&EPA
AP V2tf ££>£
UnitedSta.es Office of Air Quality AP-42VolumeI
Environmental Protection Planning and Standards Supplement E
Agency Research Triangle Park. NC 27711 October 1992
Air S : ~
SUPPLEMENT E
TO
COMPILATION
OF
AIR POLLUTANT
EMISSION FACTORS
VOLUME I:
STATIONARY POINT
AND AREA SOURCES
-------
This report has been reviewed by the Office Of Air Quality Planning And Standards, U. S. Environmental
Protection Agency, and has been approved for publication. Any mention of trade names or commercial
products is not intended to constitute endorsement or recommendation for use.
AP-42
Volume I
Supplement E
11
-------
INSTRUCTIONS FOR INSERTING
SUPPLEMENT E OF VOLUME I
INTO AP-42
Pp. iii and iv replace same. New Publications In Series.
Pp. v through viii replace same. New Contents.
Pp. ix through xvi replace same. New Key Word Index.
Pp. 1.2-1 through 10 (blank) replace 1.2-1 through 8. Major Revision.
Pp. 1.4-1 through 8 (blank) replace 1.4-1 through 6. Major Revision.
Pp. 1.5-1 through 4 replace same. Major Revision.
Pp. 1.6-1 through 18 (blank) replace 1.6-1 through 10. Major Revision.
Pp. 1.8-1 through 6 (blank) replace 1.8-1 and 2. Major Revision.
Pp. 1.9-1 through 6 (blank) replace 1.9-1 through 4. Major Revision.
Pp. 1.10-1 through 12 replace 1.10-1 through 6. Major Revision.
Pp. 1.11-1 through 8 (blank) replace same. Major Revision.
Pp. 2.2-1 and 2 replace same. Major Revision.
Pp. 2.3-1 through 4 (blank) replace same. Major Revision.
Pp. 2.4-1 through 20 (blank) replace 2.4-1 through 6. Major Revision.
Pp. 3.1-1 through 10 replace 3.1-1 through 4. Major Revision.
Pp. 3.2-1 through 10 (blank) replace 3.2-1 and 2. Major Revision.
Pp. 3.3-1 through 8 (blank) replace 3.3-1 and 2. Major Revision.
Pp. 3.4-1 through 10 (blank) replace 3.4-1 and 2. Major Revision.
Delete Section 4.3, "Storage Of Organic Liquids". Replaced by new Chapter 12.
Pp. 5.15-3 and 4 replace same. Editorial change.
Add pp. 12-1 through 124. New Chapter.
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PUBLICATIONS IN SERIES
Issue
COMPILATION OF AIR POLLUTANT EMISSION FACTORS, FOURTH EDITION
SUPPLEMENT A
Introduction
Section 1.1
1.2
1.3
1.4
1.6
1.7
5.16
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.10
7.11
8.1
8.3 '
8.6
8.10
8.13
8.15
8.19.2
8.22
8.24
10.1
11.2.6
Appendix C.I
Appendix C.2
SUPPLEMENT B
Section 1.1
1.2
1.10
1.11
2.1
2.5
4.2
4.12
5.15
6.4
8.15
8.19.2
11.1
11.2.1
11.2.3
11.2.6
11.2.7
Appendix C.3
Date
9/85
10/86
Bituminous And Subbituminous Coal Combustion
Anthracite Coal Combustion
Fuel Oil Combustion
Natural Gas Combustion
Wood Waste Combustion In Boilers
Lignite Combustion
Sodium Carbonate
Primary Aluminum Production
Coke Production
Primary Copper Smelting
Ferroalloy Production
Iron And Steel Production
Primary Lead Smelting
Zinc Smelting
Secondary Aluminum Operations
Gray Iron Foundries
Secondary Lead Processing
Asphaltic Concrete Plants
Bricks And Related Clay Products
Portland Cement Manufacturing
Concrete Batching
Glass Manufacturing
Lime Manufacturing
Crushed Stone Processing
Taconite Ore Processing
Western Surface Coal Mining
Chemical Wood Pulping
Industrial Paved Roads
Particle Size Distribution Data And Sized Emission Factors
For Selected Sources
Generalized Particle Size Distributions
Bituminous And Subbituminous Coal Combustion
Anthracite Coal Combustion
Residential Wood Stoves
Waste Oil Combustion
Refuse Combustion
Sewage Sludge Incineration
Surface Coating
Polyester Resin Plastics Product Fabrication
Soap And Detergents
Grain Elevators And Processing Plants
Lime Manufacturing
Crushed Stone Processing
Wildfires And Prescribed Burning
Unpaved Roads
Aggregate Handling And Storage Piles
Industrial Paved Roads
Industrial Wind Erosion
Silt Analysis Procedures
9/88
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PUBLICATIONS IN SERIES (Cont.)
Issue
SUPPLEMENT C
Section 1.10
2.1
2.5
4.2.2.13
4.2.2.14
5.19
7.6
7.10
10.1
11.1
11.2.6
11.2.7
11.3
Appendix C.2
Appendix D
Appendix E
Residential Wood Stoves
Refuse Combustion
Sewage Sludge Incineration
Magnetic Tape Manufacturing Industry
Surface Coating Of Plastic Parts For Business Machines
Synthetic Fiber Manufacturing
Primary Lead Smelting
Gray Iron Foundries
Chemical Wood Pulping
Wildfires And Prescribed Burning
Industrial Paved Roads
Industrial Wind Erosion
Explosives Detonation
Generalized Particle Size Distributions
Procedures For Sampling Surface/Bulk Dust Loading
Procedures For Laboratory Analysis Of Surface/Bulk Dust Loading Samples
Date
9/90
SUPPLEMENT D
Section 1.4
1.9
1.10
2.1
4.2.1
4.13
5.13.1
5.13.2
5.13.3
6.10.3
8.6
8.19.1
8.24
11.1
11.4
11.5
9/91
Natural Gas Combustion
Residential Fireplaces
Residential Wood Stoves
Refuse Combustion
Nonindustrial Surface Coating
Waste Water Collection, Treatment And Storage
Polyvinyl Chloride And Polypropylene
Poly(ethylene terephthalate)
Polystyrene
Ammonium Phosphates
Portland Cement Manufacturing
Sand And Gravel Processing
Western Surface Coal Mining
Wildfires And Prescribed Burning
Wet Cooling Towers
Industrial Flares
SUPPLEMENT E
Section 1.2
1.4
1.5
1.6
1.8
1.9
1.10
1.11
2.2
2.3
2.4
3.1
3.2
3.3
3.4
5.15
Chapter 12
Anthracite Coal Combustion
Natural Gas Combustion
Liquified Petroleum Gas Combustion
Wood Waste Combustion In Boilers
Bagasse Combustion In Sugar Mills
Residential Fireplaces
Residential Wood Stoves
Waste Oil Combustion
Automobile Body Incineration
Conical Burners
Open Burning
Stationary Gas Turbines For Electricity Generation
Heavy Duty Natural Gas Fired Pipeline Compressor Engines
Gasoline And Diesel Industrial Engines
Large Stationary Diesel And All Stationary Dual Fuel Engines
Soap And Detergents
Storage Of Organic Liquids
10/92
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CONTENTS
Page
INTRODUCTION 1
1. EXTERNAL COMBUSTION SOURCES 1-1
1.1 Bituminous Coal Combustion 1.1-1
1.2 Anthracite Coal Combustion 1.2-1
1.3 Fuel Oil Combustion 1.3-1
1.4 Natural Gas Combustion 1.4-1
1.5 Liquified Petroleum Gas Combustion 1.5-1
1.6 Wood Waste Combustion In Boilers 1.6-1
1.7 Lignite Combustion 1.7-1
1.8 Bagasse Combustion In Sugar Mills 1.8-1
1.9 Residential Fireplaces 1.9-1
1.10 Residential Wood Stoves 1.10-1
1.11 Waste Oil Combustion 1.11-1
2. SOLID WASTE DISPOSAL 2.0-1
2.1 Refuse Combustion .2!l-l
2.2 Automobile Body Incineration 2.2-1
2.3 Conical Burners 2.3-1
2.4 Open Burning 2.4-1
2.5 Sewage Sludge Incineration 2.5-1
3. STATIONARY INTERNAL COMBUSTION SOURCES 3.0-1
Glossary Of Terms Vol. II
Highway Vehicles Vol. II
Off-highway Mobile Sources Vol. II
3.1 Stationary Gas Turbines For Electricity Generation 3.1-1
3.2 Heavy Duty Natural Gas Fired Pipeline Compressor Engines 3.2-1
3.3 Gasoline And Diesel Industrial Engines 3.3-1
3.4 Large Stationary Diesel And All Stationary Dual Fuel Engines 3.4-1
4. EVAPORATION LOSS SOURCES 4.1-1
4.1 Dry Cleaning 4.1_1
4.2 Surface Coating 4.2-1
4.2.1 Nonindustrial Surface Coating 4.2.1-1
4.2.2 Industrial Surface Coating 4.2.2.1-1
4.2.2.1 General Industrial Surface Coating 4.2.2.1-1
4.2.2.2 Can Coating 7.'.'.".".'.""'.A\2\2.2-l
4.2.2.3 Magnet Wire Coating 4.2.2.3-1
4.2.2.4 Other Metal Coating 4.2.2i4-l
4.2.2.5 Flat Wood Interior Panel Coating 4.2.2.5-1
4.2.2.6 Paper Coating 4226-1
4.2.2.7 Fabric Coating I!""!!!"""""!"!!!!""!!!! 4.2.2.7-1
4.2.2.8 Automobile And Light Duty Track Surface Coating Operations 4.2.2.8-1
4.2.2.9 Pressure Sensitive Tapes And Labels 4.2.2.9-1
4.2.2.10 Metal Coil Surface Coating 4.2.2.10-1
4.2.2.11 Large Appliance Surface Coating 4.2.2.11-1
4.2.2.12 Metal Furniture Surface Coating 4.2.2.12-1
4.2.2.13 Magnetic Tape Manufacturing.; 4.2.2.13-1
4.2.2.14 Surface Coating Of Plastic Parts For Business Machines 4.2.2.14-1
4.3 [Reserved]
4.4 Transportation And Marketing Of Petroleum Liquids 4.4-1
4.5 Cutback Asphalt, Emulsified Asphalt And Asphalt Cement 4.5-1
-------
5.
6.
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
Solvent Degreasing
Waste Solvent Reclamation
Tank And Drum Cleaning
Graphic Arts •
Commercial/Consumer Solvent Use
Textile Fabric Printing
Polyester Resin Plastics Product Fabrication
Waste Water Collection, Treatment And Storage
CHEMICAL PROCESS INDUSTRY.
5.1
5.2
5.3
5.4
5.5
5.6
5.7
5.8
5.9
5.10
5.11
5.12
5.13.1
5.13.2
5.13.3
5.14
5.15
5.16
5.17
5.18
5.19
5.20
5.21
5.22
5.23
5.24
FOOD
6.1
6.2
6.3
6.4
6.5
6.6
6.7
6.8
6.9
6.10
6.11
6.12
6.13
6.14
6.15
6.16
6.17
Adipic Acid
Synthetic Ammonia
Carbon Black
Charcoal
Chlor-Alkali
Explosives
Hydrochloric Acid
Hydrofluoric Acid
Nitric Acid
Paint And Varnish
Phosphoric Acid
Phthalic Anhydride
Polyvinyl Chloride And Polypropylene
Poly(ethylene terephthalate)
Polystyrene
Printing Ink
Soap And Detergents
Sodium Carbonate
Sulfuric Acid
Sulfur Recovery
Synthetic Fibers
Synthetic Rubber
Terephthalic Acid
Lead Alkyl
Pharmaceuticals Production
Maleic Anhydride
AND AGRICULTURAL INDUSTRY.
Alfalfa Dehydrating
Coffee Roasting
Cotton Ginning
Grain Elevators And Processing Plants
Fermentation
Fish Processing
Meat Smokehouses
Ammonium Nitrate Fertilizers
Orchard Heaters
Phosphate Fertilizers
Starch Manufacturing :
Sugar Cane Processing
Bread Baking
Urea
Beef Cattle Feedlots
Defoliation And Harvesting Of Cotton
Harvesting Of Grain
4.6-1
4.7-1
4.8-1
4.9-1
4.10-1
4.11-1
4.12-1
4.13-1
5.1-1
5.1-1
5.2-1
5.3-1
5.4-1
5.5-1
5.6-1
5.7-1
5.8-1
5.9-1
5.10-1
5.11-1
5.12-1
5.13.1-1
5.13.2-1
5.13.3-1
5.14-1
5.15-1
5.16-1
5.17-1
5.18-1
5.19-1
5.20-1
5.21-1
5.22-1
5.23-1
5.24-1
6.1-1
6.1-1
6.2-1
6.3-1
6.4-1
6.5-1
6.6-1
6.7-1
6.8-1
6.9-1
6.10-1
6.11-1
6.12-1
6.13-1
6.14-1
6.15-1
6.16-1
6.17-1
-------
6.18 Ammonium Sulfate 6.18-1
7. METALLURGICAL INDUSTRY
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.9
7.10
7.11
7.12
7.13
7.14
7.15
7.16
7.17
7.18
Primary Aluminum Production
Coke Production
Primary Copper Smelting
Ferroalloy Production
Iron And Steel Production
Primary Lead Smelting
Zinc Smelting
Secondary Aluminum Operations
Secondary Copper Smelting And Alloying
Gray Iron Foundries
Secondary Lead Processing
Secondary Magnesium Smelting
Steel Foundries
Secondary Zinc Processing
Storage Battery Production
Lead Oxide And Pigment Production
Miscellaneous Lead Products
Leadbearing Ore Crushing And Grinding
8. MINERAL PRODUCTS INDUSTRY
8.1
8.2
8.3
8.4
8.5
8.6
8.7
8.8
8.9
8.10
8.11
8.12
8.13
8.14
8.15
8.16
8.17
8.18
8.19
8.20
8.21
8.22
8.23
8.24
Asphaltic Concrete Plants
Asphalt Roofing
Bricks And Related Clay Products
Calcium Carbide Manufacturing
Castable Refractories
Portland Cement Manufacturing
Ceramic Clay Manufacturing
Clay And Fly Ash Sintering
Coal Cleaning
Concrete Batching
Glass Fiber Manufacturing
Frit Manufacturing
Glass Manufacturing
Gypsum Manufacturing
Lime Manufacturing
Mineral Wool Manufacturing
Perlite Manufacturing
Phosphate Rock Processing
Construction Aggregate Processing
[Reserved]
Coal Conversion
Taconite Ore Processing
Metallic Minerals Processing
Western Surface Coal Mining
9. PETROLEUM INDUSTRY.
9.1
9.2
10.WOOD
10.1
10.2
10.3
Petroleum Refining
Natural Gas Processing
PRODUCTS INDUSTRY
Chemical Wood Pulping
Pulpboard '.
Plywood Veneer And Layout Operations
7.1-1
7.1-1
7.2-1
7.3-1
7.4-1
7.5-1
7.6-1
7.7-1
7.8-1
7.9-1
7.10-1
7.11-1
7.12-1
7.13-1
7.14-1
7.15-1
7.16-1
7.17-1
7.18-1
8.1-1
8.1-1
8.2-1
8.3-1
8.4-1
8.5-1
8.6-1
8.7-1
8.8-1
8.9-1
8.10-1
8.11-1
8.12-1
8.13-1
8.14-1
8.15-1
8.16-1
8.17-1
8.18-1
8.19-1
8.21-1
8.22-1
8.23-1
8.24-1
9.1-1
9.1-1
9.2-1
10.1-1
10.1-1
10.2-1
10.3-1
Vll
-------
10.4 Woodworking Waste Collection Operations 10.4-1
11. MISCELLANEOUS SOURCES 11.1-1
11.1 Wildfires And Prescribed Burning 11.1-1
11.2 Fugitive Dust Sources 11.2-1
11.3 Explosives Detonation 11.3-1
11.4 Wet Cooling Towers 11.4-1
11.5 Industrial Flares 11.5-1
12. STORAGE OF ORGANIC LIQUIDS 12-1
APPENDIX A
Miscellaneous Data And Conversion Factors A-l
APPENDIX B
(Reserved For Future Use)
APPENDIX C.1
Particle Size Distribution Data And Sized Emission Factors For Selected Sources C.l-1
APPENDIX C.2
Generalized Particle Size Distributions C.2-1
APPENDIX C.3
Silt Analysis Procedures C.3-1
APPENDIX D
Procedures For Sampling Surface/Bulk Dust Loading D-l
APPENDIX E
Procedures For Laboratory Analysis Of Surface/Bulk Dust Loading Samples E-l
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KEY WORD INDEX
CHAPTER/SECTION
Acid
Adipic 5.1
Hydrochloric 5.7
Hydrofluoric 5.8
Phosphoric 5.11
Sulfuric 5.17
Terephthalic 5.21
Adipic Acid 5.1
Aggregate, Construction 8.19
Aggregate Storage Piles
Fugitive Dust 11.2
Agricultural Tilling
Fugitive Dust 11.2
Alfalfa Dehydrating 6.1
Alkali, Chlor- ....5.5
Alloys
Ferroalloy Production 7.4
Secondary Copper Smelting And Alloying 7.9
Aluminum
Primary Production 7.1
Secondary Operations 7.8
Ammonia, Synthetic 5.2
Ammonium Nitrate Fertilizers 6.8
Anhydride, Phthalic 5.12
Anthracite Coal Combustion 1.2
Appliance Surface Coating 4.2.2.11
Ash
Fly Ash Sintering 8.8
Asphalt
Cutback Asphalt, Emulsified Asphalt And Asphalt Cement 4.5
Roofing ?. 8.2
Asphaltic Concrete Plants 8.1
Automobile Body Incineration ; 2.2
Automobile Surface Coating 4.2.2.8-1
Bagasse Combustion In Sugar Mills 1.8
Baking, Bread 6.13
Bark
Wood Waste Combustion In Boilers 1.6
Batching, Concrete 8.10
Battery
Storage Battery Production 7.15
Beer Production
Fermentation 6.5
Bituminous Coal Combustion 1.1
Bread Baking 6.13
Bricks And Related Clay Products 8.3
Burners, Conical (Teepee) 2.3
Burning, Open 2.4
IX
-------
Business Machines, Plastic Parts Coating 4.2.2.14
Calcium Carbide Manufacturing 8.4
Can Coating 4.2.2.2
Cane
Sugar Cane Processing 6.12
Carbon Black 5.3
Carbonate
Sodium Carbonate Manufacturing 5.16
Castable Refractories 8.5
Cattle
Beef Cattle Feedlots 6.15
Cement
Asphalt 4.5
Portland Cement Manufacturing 8.6
Ceramic day Manufacturing 8.7
Charcoal 5.4
Chemical Wood Pulping 10.1
Chlor-Alkali 5.5
Clay
Bricks And Related Clay Products 8.3
Ceramic Clay Manufacturing 8.7
Clay And Hy Ash Sintering 8.8
Cleaning
Coal 8.9
Dry Cleaning - 4.1
Tank And Drum 4.8
Coal
Anthracite Coal Combustion 1.2
Bituminous Coal Combustion 1.1
Cleaning 8.9
Conversion 8.21
Coating, Surface 4.2
Appliance, Large 4.2.2.11
Automobile And Light Duty Truck 4.2.2.8
Can 4.2.2.2
Fabric 4.2.2.7
Flat Wood Interior Panel '. 4.2.2.5
Metal, General 4.2.2.4
Magnet Wire 4.2.2.3
Magnetic Tape 4.2.2.13
Metal Coil Surface 4.2.2.10
Metal Furniture 4.2.2.12
Paper 4.2.2.6
Plastic Parts For Business Machines 4.2.2.14
Tapes And Label, Pressure Sensitive 4.2.2.9
Coffee Roasting 6.2
Coke Manufacturing 7.2
Combustion
Anthracite Coal 1.2
Bagasse, In Sugar Mill 1.8
Bituminous Coal 1.1
Fuel Oil 1.3
Internal, Mobile Vol.11
Internal, Stationary 3.0
-------
Lignite 1.7
Liquified Petroleum Gas 1.5
Natural Gas 1.4
Orchard Heater 6.9
Residential Fireplace 1.9
Waste Oil 1.11
Wood Stove 1.10
Concrete
Asphaltic Concrete Plants 8.1
Concrete Batching 8.10
Conical (Teepee) Burners 2.3
Construction Aggregate 8.19
Construction Operations
Fugitive Dust Sources 11.2
Conversion, Coal 8.21
Copper
Primary Smelting 7.3
Secondary Smelting And Alloying : 7.9
Cotton
Defoliation And Harvesting 6.16
Ginning 6.3
Dacron
Synthetic Fibers 5.19
Defoliation, Cotton 6.16
Degreasing Solvent 4.6
Dehydrating, Alfalfa 6.1
Diesel Engines, Stationary 3.4
Detergents
Soap And Detergents 5.15
Detonation, Explosives 11.3
Drum
Tank And Drum Cleaning 4.8
Dry Cleaning 4.1
Dual Fuel Engines, Stationary 3.4
Dust
Fugitive Sources 11.2
Dust Loading Sampling Procedures App. D
Dust Loading Analysis App. E
Electric Utility Power Plants, Gas 3.1
Electricity Generators, Stationary Gas Turbine 3.1
Elevators, Feed And Grain Mills 6.4
Explosives 5.6
Explosives Detonation 11.3
Fabric Coating 4.2.2.7
Feed
Beef Cattle Feedlots 6.15
Feed And Grain Mills And Elevators 6.4
Fermentation 6.5
Fertilizers
Ammonium Nitrate 6.8
Phosphate 6.10
Ferroalloy Production 7.4
XI
-------
Fiber
Glass Fiber Manufacturing 8.11
Fiber, Synthetic 5.19
Fires
Forest Wildfires And Prescribed Burning 11.1
Fireplaces, Residential 1.9
Fish Processing 6.6
Flat Wood Interior Panel Coating 4.2.2.5
Fly Ash
Clay And Fly Ash Sintering 8.8
Foundries
Gray Iron Foundries 7.10
Steel Foundries 7.13
Frit Manufacturing 8.12
Fuel Oil Combustion 1.3
Fugitive Dust Sources 11.2
Furniture Surface Coating, Metal 4.2.2.12
Gas Combustion, Liquified Petroleum 1.5
Gas, Natural
Natural Gas Combustion 1.4
Natural Gas Processing 9.2
Turbines, Electricity-generating 3.1
Gasoline/Diesel Engines 3.3
Ginning, Cotton 6.3
Glass Manufacturing 8.13
Glass Fiber Manufacturing 8.11
Grain
Feed And Grain Mills And Elevators 6.4
Harvesting Of Grain 6.17
Gravel
Sand And Gravel Processing 8.19
Gray Iron Foundries 7.10
Gypsum Manufacturing 8.14
Harvesting
Cotton 6.16
Grain 6.17
Heaters, Orchard 6.9
Hydrochloric Acid 5.7
Hydrofluoric Acid 5.8
Highway Vehicles Vol. II
Incineration
Automobile Body 2.2
Conical (Teepee) 2.3
Refuse 2.1
Sewage Sludge 2.5
Industrial Engines, Gasoline And Diesel 3.3
Industrial Flares 11.5
Industrial Surface Coating 4.2.2
Ink, Printing 5.14
Internal Combustion Engines
Highway Vehicle Vol. II
Off-highway Mobile Vol.11
-------
Off-highway Stationary 3.0
Iron
Ferroalloy Production 7.4
Gray Iron Foundries 7.10
Iron And Steel Mills 7.5
Taconite Ore Processing 8.22
Label Coating, Pressure Sensitive 4.2.2.9
Large Bore Engines 3.4
Lead
Ore Crushing And Grinding 7.18
Miscellaneous Products 7.17
Primary Lead Smelting 7.6
Secondary Smelting 7.11
LeadAlkyl 5.22
Lead Oxide And Pigment Production 7.16
Leadbearing Ore Crushing And Grinding 7.18
Lignite Combustion 1.7
Lime Manufacturing 8.15
Liquified Petroleum Gas Combustion 1.5
Magnesium
Secondary Smelting 7.12
Magnet Wire Coating 4.2.2.3
Magnetic Tape Manufacturing/Surface Coating 4.2.2.13
Maleic Anhydride 5.24
Meat Smokehouses 6.7
Metal Coil Surface Coating 4.2.2.10
Metal Furniture Surface Coating 4.2.2.12
Mineral Wool Manufacturing 8.16
Mobile Sources
Highway Vol.11
Off-highway Vol.11
Natural Gas Combustion 1.4
Natural Gas Fired Pipeline Compressors 3.2
Natural Gas Processing 9.2
Nitric Acid Manufacturing 5.9
Nonindustrial Surface Coating 4.2.1
Off-highway Mobile Sources Vol. II
Off-highway Stationary Sources 3.0
Oil
Fuel Oil Combustion 1.3
Waste Oil Combustion 1.11
Open Burning 2.4
Orchard Heaters 6.9
Ore Processing
Leadbearing Ore Crushing And Grinding 7.18
Taconite 8.22
Organic Liquid Storage 12.0
Paint And Varnish Manufacturing 5.10
Panel Coating, Wood, Interior 4.2.2.5-1
Paper Coating 4.2.2.6-1
Paved Roads
Xlll
-------
Fugitive Dust 11.2
Perlite Manufacturing 8.17
Petroleum
Liquified Petroleum Gas Combustion 1.5
Refining 9.1
Storage Of Organic Liquids 12.0
Transportation And Marketing Of Petroleum Liquids 4.4
Pharmaceutical Production 5.23
Phosphate Fertilizers 6.10
Phosphate Rock Processing 8.18
Phosphoric Acid 5.11
Phthalic Anhydride 5.12
Pigment
Lead Oxide And Pigment Production 7.16
Pipeline Compressors, Natural Gas Fired 3.2
Plastic Part Surface Coating, Business Machine 4.2.2.14
Plastics 5.13
Plywood Veneer And Layout Operations 10.3
Polyethylene terephthalate) 5.13.2
Polyester Resin Plastics Product Fabrication 4.12
Polypropylene 5.13.1
Polystyrene 5.13.3
Polyvinyl Chloride 5.13.1
Portland Cement Manufacturing '. 8.6
Prescribed Burning 11.1
Printing Ink 5.14
Pulpboard 10.2
Pulping Chemical Wood 10.1
Reclamation, Waste Solvent 4.7
Recovery, Sulfur 5.18
Refractories, Castable 8.5
Residential Fireplaces 1.9
Roads, Paved
Fugitive Dust 11.2
Roads, Unpaved
Fugitive Dust 11.2
Roasting Coffee 6.2
Rock
Phosphate Rock Processing 8.18
Roofing, Asphalt 8.2
Rubber, Synthetic 5.20
Sand And Gravel Processing 8.19
Sewage Sludge Incineration 2.5
Sintering, Clay And Fly Ash 8.8
Smelting
Primary Copper Smelting 7.3
Primary Lead Smelting 7.6
Secondary Copper Smelting And Alloying 7.9
Secondary Lead Smelting 7.11
Secondary Magnesium Smelting 7.12
Zinc Smelting 7.7
Smokehouses, Meat 6.7
Soap And Detergent Manufacturing 5.15
-------
Sodium Carbonate Manufacturing 5.16
Solvent
Commercial/Consumer Use 4.10
Degreasing 4.6
Waste Reclamation 4.7
Starch Manufacturing 6.11
Stationary Gas Turbines 3.1
Stationary Sources, Off-highway 3.0
Steel
Iron And Steel Mills 7.5
Foundries 7.13
Storage Battery Production 7.15
Storage Of Organic Liquids 12.0
Sugar Cane Processing 6.12
Sugar Mills, Bagasse Combustion In 1.8
Sulfur Recovery 5.18
SulfuricAcid 5.17
Surface Coating 4.2
Synthetic Ammonia 5.2
Synthetic Fiber 5.19
Synthetic Rubber 5.20
Taconite Ore Processing 8.22
Tank And Drum Cleaning 4.8
Tape, Magnetic, Manufacturing 4.2.2.13
Tape Coating, Pressure Sensitive 4.2.2.9
Teepee (Conical) Burners 2.3
Terephthalic Acid 5.21
Tilling, Agricultural
Fugitive Dust H-2
Transportation And Marketing Of Petroleum Liquids 4.4
Truck Surface Coating, Light Duty 4.2.2.8
Turbines, Natural Gas Fired 3.1
Unpaved Roads
Fugitive Dust 11-2
Urea 6.14
Varnish
Paint And Varnish Manufacturing 5.10
Vehicles, Highway And Off-highway Vol. II
Waste Solvent Reclamation 4.7
Waste Oil Combustion 1.11
Waste Water Collection, Treatment and Storage 4.13
Wet Cooling Towers 11.4
Whiskey Production
Fermentation 6.5
Wildfires, Forest . 11.1
Wine Making
Fermentation 6.5
Wire Coating, Magnet 4.2.2.3
Wood
Pulping, Chemical 10.1
Stoves 1-10
Waste Combustion In Boilers 1.6
XV
-------
Interior Panel Coating 4 .2.2.5
Woodworking Waste Collection Operations 10.4
Zinc
Secondary Processing 7.14
Smelting 7.7
XVI
-------
1.2 ANTHRACITE COAL COMBUSTION
1.2.1 General1'4
Anthracite coal is a high-rank coal with more fixed carbon and less volatile matter than either
bituminous coal or lignite; anthracite also has higher ignition and ash fusion temperatures. In the
United States, nearly all anthracite is mined in northeastern Pennsylvania and consumed in
Pennsylvania and its surrounding states. The largest use of anthracite is for space heating. Lesser
amounts are employed for steam/electric production; coke manufacturing, sintering and pelletizing; and
other industrial uses. Anthracite currently is only a small fraction of the total quantity of coal
combusted in the United States.
Another form of anthracite coal burned in boilers is anthracite refuse, commonly known as
culm. Culm was produced as breaker reject material from the mining/sizing of anthracite coal and was
typically dumped by miners on the ground near operating mines. It is estimated that there are over 15
million Mg (16 million tons) of culm scattered in piles throughout northeastern Pennsylvania. The
heating value of culm is typically in the 1,400 to 2,800 kcal/kg (2,500 to 5,000 Btu/lb) range,
compared to 6,700 to 7,800 kcal/kg (12,000 to 14,000 Btu/lb) for anthracite coal.
1.2.2 Firing Practices5"7
Due to its low volatile matter content, and non-clinkering characteristics, anthracite coal is
largely used in medium-sized industrial and institutional stoker boilers equipped with stationary or
traveling grates. Anthracite coal is not used in spreader stokers because of its low volatile matter
content and relatively high ignition temperature. This fuel may also be burned in pulverized coal-fired
(PC-fired) units, but due to ignition difficulties, this practice is limited to only a few plants in eastern
Pennsylvania. Anthracite coal has also been widely used in hand-fired furnaces. Culm has been
combusted primarily in fluidized bed combustion (FBC) boilers because of its high ash content and
low heating value.
Combustion of anthracite coal on a traveling grate is characterized by a coal bed of 8 to 13 cm
(3 to 5 inches) 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
screw. Feed coal is pushed through the retort and upward towards the tuyere blocks. Air is supplied
through the tuyere blocks on each side of the retort and through openings in the side grates. Overfire
air is commonly used with underfeed stokers to provide combustion air and turbulence in the flame
zone directly above the active fuel bed.
In PC-fired boilers, the fuel is pulverized to the consistency of powder and pneumatically
injected through burners into the furnace. Injected coal particles burn in suspension within the furnace
region of the boiler. Hot flue gases rise from the furnace and provide heat exchange with boiler tubes
in the walls and upper regions of the boiler. In general, PC-fired boilers operate either in a wet-
bottom or dry bottom mode; because of its high ash fusion temperature, anthracite coal is burned in
10/92 External Combustion Sources 1.2-1
-------
dry-bottom furnaces.
For anthracite culm, combustion in conventional boiler systems is difficult due to the fuel's
high ash content, high moisture content, and low heating value. However, the burning of culm in a
fluidized bed system was demonstrated at a steam generation plant in Pennsylvania. A fluidized bed
consists of inert particles (e.g., rock and ash) through which air is blown so that the bed behaves as a
fluid. Anthracite coal enters in the space above the bed and burns in the bed. Fluidized beds can
handle fuels with moisture contents up to near 70 percent (total basis) because of the large thermal
mass represented by the hot inert bed particles. Fluidized beds can also handle fuels with ash contents
as high as 75 percent. Heat released by combustion is transferred to in-bed steam-generating tubes.
Limestone may be added to the bed to capture sulfur dioxide formed by combustion of fuel sulfur.
1.2.3 Emissions And Controls
Particulate matter (PM) emissions from anthracite coal combustion are a function of furnace
firing configuration, firing practices (boiler load, quantity and location of underfire air, soot blowing,
flyash reinjection, etc.), and the ash content of the coal. Pulverized coal-fired boilers emit the highest
quantity of PM per unit of fuel because they fire the anthracite in suspension, which results in a high
percentage of ash carryover into exhaust gases. Traveling grate stokers and hand fired units produce
less PM per unit of fuel fired, and coarser particulates, because combustion takes place in a quiescent
fuel bed without significant ash carryover into the exhaust gases. In general, PM emissions from
traveling grate stokers will increase during soot blowing and flyash reinjection and with higher fuel
bed underfeed air flowrates. Smoke production during combustion is rarely a problem, because of
anthracite's low volatile matter content.
Limited data are available on the emission of gaseous pollutants from anthracite combustion.
It is assumed, based on bituminous coal combustion data, that a large fraction of the fuel sulfur is
emitted as sulfur oxides. Also, because combustion equipment, excess air rates, combustion
temperatures, etc., are similar between anthracite and bituminous coal combustion, nitrogen oxide
emissions are also assumed to be similar. Nitrogen oxide emissions from FBC units burning culm are
typically lower than from other anthracite coal-burning boilers due to the lower operating temperatures
which characterize FBC beds.
Carbon monoxide and total organic compound emissions are dependent on combustion
efficiency. Generally their emission rates, defined as mass of emissions per unit of heat input,
decrease with increasing boiler size. Organic compound emissions are expected to be lower for
pulverized coal units and higher for underfeed and overfeed stokers due to relative combustion
efficiency levels.
Controls on anthracite emissions mainly have been applied to PM. The most efficient
paniculate controls, fabric filters, scrubbers, and electrostatic precipitators, have been installed on large
pulverized anthracite-fired boilers. Fabric filters can achieve collection efficiencies exceeding 99
percent. Electrostatic precipitators typically are only 90 to 97 percent efficient, because of the
characteristic high resistivity of low sulfur anthracite fly ash. It is reported that higher efficiencies can
be achieved using larger precipitators and flue gas conditioning. Mechanical collectors are frequently
employed upstream from these devices for large particle removal.
Older traveling grate stokers are often uncontrolled. Indeed, particulate control has often been
considered unnecessary, because of anthracite's low smoking tendencies and the fact that a significant
fraction of large size flyash from stokers is readily collected in flyash hoppers as well as in the
breeching and base of the stack. Cyclone collectors have been employed on traveling grate stokers,
1.2-2 EMISSION FACTORS 10/92
-------
and limited information suggests these devices may be up to 75 percent efficient on particulate.
Flyash reinjection, frequently used in traveling grate stokers to enhance fuel use efficiency, tends to
increase PM emissions per unit of fuel combusted. High-energy venturi scrubbers can generally
achieve PM collection efficiencies of 90 percent or greater.
Emission factors and ratings for pollutants from anthracite coal combustion and anthracite
culm combustion are given in Tables 1.2-1 through 1.2-7. Cumulative size distribution data and size
specific emission factors and ratings for particulate emissions are summarized in Table 1.2-8.
Uncontrolled and controlled size specific emission factors are presented in Figure 1.2-1. Particle size
distribution data for bituminous coal combustion may be used for uncontrolled emissions from
pulverized anthracite-fired furnaces, and data for anthracite-fired traveling grate stokers may be used
for hand fired units.
REFERENCES FOR SECTION 1.2
1. Minerals Yearbook, 1978-79, Bureau of Mines, U.S. Department of the Interior, Washington,
D.C., 1981.
2. Air Pollutant Emission Factors, APTD-0923, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, April 1970.
3. "Operating Experience at the Shamokin Culm Burning Steam Generation Plant", P. Bender, D.
Samela, W. Smith, G. Tsoumpas, Stone & Webster Engineering Group, New York, New York,
J. Laukaitis, Shamokin Area Industrial Corporation, Shamokin, Pennsylvania, Presented at the
76th Annual Meeting of the Air Pollution Control Association, Atlanta, Georgia, June 1983.
4. Chemical Engineers' Handbook. Fourth Edition. J. Perry, Editor, McGraw-Hill Book
Company, New York, New York, 1963.
5. Background Information Document For Industrial Boilers, EPA 450/3-82-006a, U. S.
Environmental Protection Agency, Research Triangle Park, North Carolina, March 1982.
6. Steam: Its Generation and Use, Thirty-Seventh Edition. The Babcock & Wilcox Company,
New York, New York, 1963.
7. Draft report. Emission Factor Documentation for AP-42 Section 1.2—Anthracite Coal
Combustion, Technical Support Division, Office of Air Quality Planning and Standards, U. S.
Environmental Protection Agency, Research Triangle Park, North Carolina, October 1992.
8. Inhalable Particulate Source Category Report for External Combustion Sources, EPA Contract
No. 68-02-3156, Acurex Corporation, Mountain View, California, January 1985.
10/92 External Combustion Sources 1.2-3
-------
TABLE 1.2-1. EMISSION FACTORS FOR SPECIATED METALS FROM ANTHRACITE COAL
COMBUSTION IN STOKER FIRED BOILERS7
(Emission Factor Rating: E)
Pollutant
Mercury
Arsenic
Antimony
Beryllium
Cadmium
Chromium
Manganese
Nickel
Selenium
Emission factor
range
Ib/ton
8.7E-05
BDL-
- 1.3E-04
2.4E-04
Emission factor Average emission
range factor
kg/Mg Ib/ton
4.4E-05
BDL-
- 6.5E-05
1.2E-04
BDL
3.0E-05
4.5E-05
5.9E-03
9.8E-04
7.8E-03
4.7E-04
- 5.4E-04
- 1.1E-04
- 4.9E-02
- 5.3E-03
- 3.5E-02
- 2.1E-03
1.5E-05
2.3E-05
3.0E-03
4.9E-04
3.9E-03
2.4E-04
- 2.7E-04
- 5.5E-05
- 2.5E-02
- 2.7E-03
- 1.8E-02
- 1.1E-03
1.29E-04
. 1.85E-04
BDL
3.07E-04
7.10E-05
2.76E-02
3.56E-03
2.56E-02
1.26E-03
Average emission
factor
kg/mg
6.45E-05
9.25E-05
BDL
1.54E-04
3.55E-05
1.38E-02
1.78E-03
1.28E-02
6.30E-04
BDL = Below detection limit.
TABLE 1.2-2. EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS (TOC) AND
METHANE (CH4) FROM ANTHRACITE COAL COMBUSTORS1
Source category
TOC
Average
emission
factor
Ib/ton
Average
emission
factor Rating
kg/Mg
CH4
Average
emission
factor
Ib/ton
Average
emission
factor Rating
kg/Mg
Stoker fired boilers
0.20
0.10
NA
NA
Residential space
heaters
NA
NA
E
NA = Data not available.
1.2-4
EMISSION FACTORS
10/92
-------
TABLE 1.2-3. (ENGLISH UNITS) EMISSION FACTORS FOR SPECIATED ORGANIC
COMPOUNDS FROM ANTHRACITE COAL COMBUSTORS7
(Emission Factor Rating: E)
Pollutant
Biphenyl
Phenanthrene
Naphthalene
Acenaphthene
Acenaphthalene
Fluorene
Anthracene
Fluoranthrene
Pyrene
Benzo(a)anthracene
Chrysene
Benzo(k)fluoranthrene
Benzo(e)pyrene
Benzo(a)pyrene
Perylene
Indeno(123-cd) perylene
Benzo(g,h,i,) perylene
Anthanthrene
Coronene
Stoker fired boilers
Emission factor
Ib/ton
2.5E-02
6.8E-03
1.3E-01
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Residential space heaters
Emission factor
range
Ib/ton
-
9.1E-02- 0.43E-01
9.0E-03- 0.0482
1.4E-02- 6.75E-01
1.4E-02- 3.04E-01
9.0E-03- 5.78E-02
9.0E-03- 4.5E-02
9.6E-02- 3.3E-01
5.4E-02- 2.4E-01
1.4E-02 - 2.0E-01
2.3E-02 - 2.2E-01
1.4E-02- 6.27E-02
4.5E-03- 1.45E-02
3.8E-03 - 9.0E-03
7.6E-04- 2.3E-03
4.5E-03- 1.4E-02
4.34E-03- 1.2E-02
1.9E-04- 1.1E-03
1.1E-03- 8.0E-03
Average emission
factor
Ib/ton
-
3.63
3.27
0.43
1.46
0.38
0.38
4.86
1.83
1.15
2.62
0.37
0.09
0.06
1.4E-02
0.10
0.08
6.2E-03
0.06
NA = Data not available.
10/92
External Combustion Sources
1.2-5
-------
TABLE 1.2-4 (METRIC UNITS) EMISSION FACTORS FOR SPECIATED ORGANIC
COMPOUNDS FROM ANTHRACITE COAL COMBUSTORS7
(Emission Factor Rating: E)
Pollutant
Biphenyl
Phenanthrene
Naphthalene
Acenaphthene
Acenaphthalene
Fluorene
Anthracene
Fluoranthrene
Pyrene
Benzo(a)anthracene
Chrysene
Benzo(k)fluoranthrene
Benzo(e)pyrene
Benzo(a)pyrene
Perylene
Indeno(123-cd) perylene
Benzo(g,h,i,) perylene
Anthanthrene
Coronene
Stoker fired
boilers
Emission factor
kg/Mg
1.25E-02
3.4E-03
0.65E-01
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
Residential space heaters
Emission factor
range
kg/Mg
-
4.6E-02- 2.1E-02
4.5E-03 - 0.0241
7.0E-03- 3.38E-01
7.0E-03- 1.98E-02
4.5E-03- 2.89E-02
4.5E-03- 2.3E-02
4.8E-02- 1.7E-01
2.7E-02- 1.2E-01
7.0E-03 - l.OE-01
1.2E-02 - 1.1E-01
7.0E-03- 3.14E-02
2.3E-03- 7.25E-03
1.9E-03 - 4.5E-03
3.8E-04- 1.2E-03
2.3E-03- 7.0E-03
2.17E-03- 6.0E-03
9.5E-05- 5.5E-04
5.5E-04- 4.0E-03
Average emission
factor
kg/Mg
-
3.63
3.27
0.43
1.46
0.38
0.38
4.86
1.83
1.15
2.62
0.37
0.09
0.06
1.4E-02
0.10
0.08
6.2E-03
0.06
NA = Data not available.
1.2-6
EMISSION FACTORS
10/92
-------
1
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10/92
External Combustion Sources
1.2-7
-------
TABLE 1.2-7. EMISSION FACTORS FOR CARBON MONOXIDE (CO) AND
CARBON DIOXIDE (CO2) FROM ANTHRACITE COAL COMBUSTORS7
Source category
CO
Emission Factor
Ib/ton kg/Mg Rating
co2
Emission Factor
Ib/ton kg/Mg Rating
Stoker fired boilers 0.6 0.3 B 5680 2840 C
FBCboilersa 0.3 0.15 E NA NA -
NA = Data Not Available
a. FBC = Fluidized bed combustion; FBC boilers burning culm fuel; all other sources burning
anthracite coal.
TABLE 1.2-8. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR DRY BOTTOM BOILERS BURNING PULVERIZED ANTHRACITE COAL8
(Emission Factor Rating: D)
Particle
sizec
(pm)
Cumulative mass % < stated size
Uncontrolled
Controlled15
Multiple
cyclone
Baghouse
Cumulative emission factor3
kg/Mg (Ib/ton) coal, as fired
Uncontrolled
Controlled15
Multiple
cyclone
Baghouse
15
10
6
2.5
1.25
1.00
0.625
TOTAL
32
23
17
6
2
2
1
100
63
55
46
24
13
10
7
100
79
67
51
32
21
18
100
1.6A (3.2A)
1.2A (2.3A)
0.9A (1.7A)
0.3A (0.6A)
0.1A (0.2A)
0.1A (0.2A)
0.05A (0.1A)
5A (10A)
0.63A (1.26A)
0.55A (1.10A)
0.46A (0.92A)
0.24A (0.48A)
0.13 A (0.26A)
0.10A (0.20 A)
0.07 A (0.14 A)
1A (2A)
0.0079A
(0.016A)
0.0067A
(0.013A)
0.0051A
(0.010A)
0.0032A
(0.006A)
0.0021A
(0.004A)
0.0018A
(0.004A)
d
0.01A (0.02A)
a. A = coal ash weight %, as fired.
b. Estimated control efficiency for multiple cyclone, 80%; baghouse, 99.8%.
c. Expressed as aerodynamic equivalent diameter.
d. Insufficient data.
1.2-8
EMISSION FACTORS
10/92
-------
2.0A
1.8A
1.6A
? 1.4A
! 1.2A
IQ
•— 1 OA
~ I.UH
S
.g, 0.8A
I 0.6A
0.4A
0.2A
0
.1
Baghouse
Multiple
cyclone
Uncontrolled
.4 .6 1 2 4 6 10
Particle diameter (pm)
l.OA
0.9A
0.8A
0.7A
0.6A
0.5A
0.4A
0.3A
0.2A
0.1A
o"
i^"
c ia
o o
°°
i-
irt -•-
0.006A "i""
0.005A Si _•
0.004A i "
c 01
0.003A ^S1
0.002A I
en
0.001 A •"
Figure 1.2-1. Cumulative size specific emission factors for dry bottom
boilers burning pulverized anthracite coal.
10/92
External Combustion Sources
1.2-9
-------
-------
1.4 NATURAL GAS COMBUSTION
1.4.1 General1"2
Natural gas is one of the major fuels used throughout the country. It is used mainly for
industrial process steam and heat production; for residential and commercial space heating; and for
electric power generation. Natural gas consists of a high percentage of methane (generally above 80
percent) and varying amounts of ethane, propane, butane, and inerts (typically nitrogen, carbon
dioxide, and helium). Gas processing plants are required for the recovery of liquefiable constituents
and removal of hydrogen sulfide before the gas is used (see Natural Gas Processing, Section 9.2). The
average gross heating value of natural gas is approximately 8900 kilocalories per standard cubic meter
(1000 British thermal units per standard cubic foot), usually varying from 8000 to 9800 kcal/scm (900
to HOOBtu/scf).
1.4.2 Emissions and Controls^
Even though natural gas is considered to be a relatively clean-burning fuel, some emissions
can result from combustioa For example, improper operating conditions, including poor air/fuel
mixing, insufficient air, etc., may cause large amounts of smoke, carbon monoxide (CO), and organic
compound emissions. Moreover, because a sulfur-containing mercaptan is added to natural gas to
permit leak detection, small amounts of sulfur oxides will be produced in the combustion process.
Nitrogen oxides (NOX) are the major pollutants of concern when burning natural gas.
Nitrogen oxide emissions depend primarily on the peak temperature within the combustion chamber as
well as the furnace-zone oxygen concentration, nitrogen concentration, and time of exposure at peak
temperatures. Emission levels vary considerably with the type and size of combustor and with
operating conditions (particularly combustion air temperature, load, and excess air level in boilers).
Currently, the two most prevalent NOX control techniques being applied to natural gas-fired
boilers (which result in characteristic changes in emission rates) are low NOX burners and flue gas
recirculation. Low NOX burners reduce NOX by accomplishing the combustion process in stages.
Staging partially delays the combustion process, resulting in a cooler flame which suppresses NOX
formation. The three most common types of low NOX burners being applied to natural gas-fired
boilers are staged air burners, staged fuel burners, and radiant fiber burners. Nitrogen oxide emission
reductions of 40 to 85 percent (relative to uncontrolled emission levels) have been observed with low
NOX burners. Other combustion staging techniques which have been applied to natural gas-fired
boilers include low excess air, reduced air preheat, and staged combustion (e.g., burners-out-of-service
and overfire air). The degree of staging is a key operating parameter influencing NOX emission rates
for these systems.
In a flue gas recirculation (FOR) system, a portion of the flue gas is recycled from the stack to
the burner windbox. Upon entering the windbox, the gas is mixed with combustion air prior to being
fed to the burner. The FOR system reduces NOX emissions by two mechanisms. The recycled flue
gas in made up of combustion products which act as inerts during combustion of the fuel/air mixture.
This additional mass is heated 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
10/92 External Combustion Sources 1.4-1
-------
normally used in combination with low NOX burners. When used in combination, these techniques are
capable of reducing uncontrolled NOX emissions by 60 to 90 percent.
Two post-combustion technologies that may be applied to natural gas-fired boilers to reduce
NOX emissions by further amounts are selective noncatalytic reduction and selective catalytic
reduction. These systems inject ammonia (or urea) into combustion flue gases to reduce inlet NOX
emission rates by 40 to 70 percent.
Although not measured, all paniculate matter (PM) from natural gas combustion has been
estimated to be less than 1 micrometer in size. Particulate matter is composed of filterable and
condensible fractions, based on the EPA sampling method. Filterable and condensible emission rates
are of the same order of magnitude for boilers; for residential furnaces, most of the PM is in the form
of condensible material.
The rates of CO and trace organic emissions from boilers and furnaces depend on the
efficiency of natural gas combustion. These emissions are minimized by combustion practices that
promote high combustion temperatures, long residence times at those temperatures, and turbulent
mixing of fuel and combustion air. In some cases, the addition of NOX control systems such as FOR
and low NCL burners reduces combustion efficiency (due to lower combustion temperatures), resulting
in higher CO and organic emissions relative to uncontrolled boilers.
Emission factors for natural gas combustion in boilers and furnaces are presented in Tables
1.4-1 through 1.4-3. For the purposes of developing emission factors, natural gas combustors have
been organized into four general categories: utility/large industrial boilers, small industrial boilers,
commercial boilers, and residential furnaces. Boilers and furnaces within these categories share the
same general design and operating characteristics and hence have similar emission characteristics when
combusting natural gas. The primary factor used to demarcate the individual combustor categories is
heat input.
1.4-2 EMISSION FACTORS 10/92
-------
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10/92
External Combustion Sources
1.4-3
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10/92
-------
References for Section 1.4
1. Exhaust Gases From Combustion and Industrial Processes, EPA Contract No. EHSD 71-36,
Engineering Science, Inc., Washington, D.C., October 1971.
2. Chemical Engineers' Handbook, Fourth Edition. J. H. Perry, Editor, McGraw-Hill Book
Company, New York, New York, 1963.
3. Background Information Document For Industrial Boilers, EPA-450/3-82-006a, U. S.
Environmental Protection Agency, Research Triangle Park, North Carolina, March 1982.
4. Background Information Document For Small Steam Generating Units, EPA-450/3-87-000, U.
S. Environmental Protection Agency, Research Triangle Park, North Carolina, 1987.
5. Fine Particulate Emissions From Stationary and Miscellaneous Sources in the South Coast Air
Basin, California Air Resources Board Contract No. A6-191-30, KVB, Inc., Tustin, California,
February 1979.
6. Draft report. Emission Factor Documentation for AP-42 Section 1.4-Natural Gas Combustion,
Technical Support Division, Office of Air Quality Planning and Standards, U. S.
Environmental Protection Agency, Research Triangle Park, North Carolina, September 1992.
7. Systematic Field Study of NOX Emission Control Methods For Utility Boilers. APTD-1163. U.
S. Environmental Protection Agency, Research Triangle Park, North Carolina, December 1971.
8. Compilation of Air Pollutant Emission Factors, Fourth Edition, AP-42, U. S. Environmental
Protection Agency, Research Triangle Park, North Carolina, September 1985.
10/92 External Combustion Sources 1.4-7
-------
-------
1.5 LIQUIFIED PETROLEUM GAS COMBUSTION
1.5.1 General1
Liquified petroleum gas (LPG) consists of butane, propane, or a mixture of the two, and of
trace amounts of propylene and butylene. This gas, obtained from oil or gas wells as a gasoline
refining byproduct, is sold as a liquid in metal cylinders under pressure and, therefore, is often called
bottled gas. Liquified petroleum gas is graded according to maximum vapor pressure, with Grade A
being mostly butane, Grade F mostly propane, and Grades B through E being varying mixtures of
butane and propane. The heating value of LPG ranges from 6,480 kcal/liter (102,000 Btu/gallon) for
Grade A to 6,030 kcal/liter (91,000 Btu/gallon) for Grade F. The largest market for LPG is the
domestic/commercial market, followed by the chemical industry and internal combustion engines.
1.5.2 Emissions and Controls1"4
Liquified petroleum gas is considered a "clean" fuel because it does not produce visible
emissions. However, gaseous pollutants such as carbon monoxide (CO), organic compounds, and
nitrogen oxides (NOX) do occur. The most significant factors affecting these emissions are burner
design, burner adjustment, and flue gas venting. Improper design, blocking and clogging of the flue
vent, and insufficient combustion air result in improper combustion and the emissions of aldehydes,
CO, hydrocarbons, and other organics. Nitrogen oxide emissions are a function of a number of
variables, including temperature, excess air, fuel/air mixing, and residence time in the combustion
zone. The amount of sulfur dioxide (SO2) emitted is directly proportional to the amount of sulfur hi
the fuel. Emission factors for LPG combustion are presented in Tables 1.5-1 and 1.5-2.
Nitrogen oxides are the only pollutant for which emission controls have been developed.
Propane and butane are being used in Southern California as backup fuel to natural gas, replacing
distillate oil in this role pursuant to the phaseout of fuel oil in that region. Emission control for NOX
have been developed for firetube and watertube boilers firing propane or butane. Vendors are now
warranting retrofit systems to levels as low as 30 to 40 ppm (based on 3 percent oxygen). These low-
NOX systems use a combination of low NOX burners and flue gas recirculation. Some burner vendors
use water or steam injection into the flame zone for NOX reduction. This is a trimming technique
which may be necessary during backup fuel periods because LPG typically has a higher NOx-forming
potential than natural gas; conventional natural gas emission control systems may not be sufficient to
reduce LPG emissions to mandated levels. Also, LPG burners are more prone to sooting under the
modified combustion conditions required for low NOX emissions. The extent of allowable combustion
modifications for LPG may be more limited than for natural gas.
One NO% control system that has been demonstrated on small commercial boilers is flue gas
recirculation (FGR). Nitrogen oxide emissions from propane combustion can be reduced by as much
as 50 percent by recirculating 16 percent of the flue gas. Nitrogen oxide emission reductions of over
60 percent have been achieved with FGR and low NOX burners used in combination.
10/92 External Combustion Sources 1.5-1
-------
TABLE 1.5-1. (ENGLISH UNITS) EMISSION FACTORS FOR LPG COMBUSTIONa'b
(Emission Factor Rating: E)
Pollutant
Butane Emission Factor
lb/1000 gal
Industrial
Boilers0
Filterable particulate matter6 0.6
Sulfur oxidesf 0.09s
Nitrogen oxides^ 21
Carbon dioxide 14,700
Carbon monoxide 3.6
Total organic compounds 0.6
Commercial
Boilersd
Propane Emission Factor
lb/1000 gal
Industrial
Boilers0
0.5 0.6
0.09s 0.10s
15 19
14,700 12,500
2.1 3.2
0.6 0.5
Commercial
Boilersd
0.4
0.10s
14
12,500
1.9
0.5
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.
b. SCC Codes 102101001, and 10301001 for industrial and commercial/institutional butane
combustion. SCC Codes 10201002, and 10301002 for industrial and commercial/institutional
propane combustion. SCC Codes 10500110, and 10500210 for industrial and
cornmercialyinstitutional LPG combustion.
c. Heat input capacities generally between 10 and 100 million Btu/hour.
d. Heat input capacities generally between 0.3 and 10 million Btu/hour.
e. Filterable particulate matter (PM) is that PM collected on or prior to the filter of an EPA
Method 5 (or equivalent) sampling train.
f. Expressed as SO2. S equals the sulfur content expressed on gr/100 ft3 gas vapor. For
example, if the butane sulfur content is 0.18 gr/100 ft3 emission factor would be (0.09 x
0.18=) 0.016 Ib of SO2/1000 gal butane burned.
g. Expressed as NO2.
1.5-2
EMISSION FACTORS
10/92
-------
TABLE 1.5-2. (METRIC UNITS) EMISSION FACTORS FOR LPG COMBUSTIONa'b
(Emission Factor Rating: E)
Pollutant
Butane Emission Factor
kg/1000 liters
Industrial
Boilers0
Filterable paniculate matter6 0.07
Sulfur oxidesf 0.011s
Nitrogen oxides^ 2.5
Carbon dioxide 1,760
Carbon monoxide 0.4
Total organic compounds 0.07
Commercial
Boilersd
Propane Emission Factor
kg/1000 liters
Industrial
Boilers0
0.06 0.07
0.011s 0.012s
1.8 2.3
1,760 1,500
0.3 0.4
0.07 0.06
Commercial
Boilersd
0.05
0.012s
1.7
1,500
0.2
0.06
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.
b. SCC Codes 102101001, and 10301001 for industrial and commercial/institutional butane
combustion. SCC Codes 10201002, and 10301002 for industrial and commercial/institutional
propane combustion. SCC Codes 10500110, and 10500210 for industrial and
commercial/institutional LPG combustion.
c. Heat input capacities generally between 3 and 29 MW.
d. Heat input capacities generally between 0.1 and 3 MW.
e. Filterable particulate matter (PM) is that PM collected on or prior to the filter of an EPA
Method 5 (or equivalent) sampling train.
f. Expressed as SO2- S equals the sulfur content expressed on gr/100 ft gas vapor. For
example, if the butane sulfur content is 0.18 gr/100 ft emission factor would be (0.011 x
0.18) = 0.0020 kg of SO2/1000 liters butane burned.
g. Expressed as
10/92
External Combustion Sources
1.5-3
-------
References for Section 1.5
1. Air Pollutant Emission Factors, Final Report, Contract No. CPA-22-69-119, Resources
Research, Inc., Reston, VA, Durham, NC, April 1970.
2. E. A. Clifford, A Practical Guide to Liquified Petroleum Gas Utilization. New York, Moore
Publishing Co., 1962.
3. Nitrous Oxide Reduction with the Weishaupt Flue Gas Recirculation System, Weishaupt
Research and Development Institute, January. 1987.
4. Phone communication memorandum dated May 14, 1992. Conversation between B. Lusher of
Acurex Environmental and D. Childress of Suburban/Petrolane, Durham, NC.
1.5-4
EMISSION FACTORS
10/92
-------
1.6 WOOD WASTE COMBUSTION IN BOILERS
1.6.1 General1"5
The burning of wood waste in boilers is mostly confined to those industries where it is
available as a byproduct. It is burned both to obtain heat energy and to alleviate possible solid waste
disposal problems. In boilers, wood waste is normally burned in the form of hogged wood, sawdust,
shavings, chips, sanderdust, or wood trim. Heating values for this waste range from about 2,200 to
2,700 kcal/kg (4,000 to 5,000 Btu/lb) of fuel on a wet, as-fired basis. The moisture content of as-fired
wood is typically near 50, weight percent but may vary from 5 to 75 weight percent depending on the
waste type and storage operations.
Generally, bark is the major type of waste burned in pulp mills; either a mixture of wood and
bark waste or wood waste alone is burned most frequently in the lumber, furniture, and plywood
industries. As of 1980, there were approximately 1,600 wood-fired boilers operating in the U. S., with
a total capacity of over 30 GW (1.0 x 1011 Btu/hr).
1.6.2 Firing Practices5"7
Various boiler firing configurations are used for burning wood waste. One common type of
boiler used in smaller operations is the Dutch oven. This unit is widely used because it can burn fuels
with very high moisture content. Fuel is fed into the oven through an opening in the top of a
refractory-lined furnace. The fuel accumulates in a cone-shaped pile on a flat or sloping grate.
Combustion is accomplished in two stages: (1) drying and gasification, and (2) combustion of gaseous
products. The first stage takes place in the primary furnace, which is separated from the secondary
furnace chamber by a bridge wall. Combustion is completed in the secondary chamber before gases
enter the boiler section. The large mass of refractory helps to stabilize combustion rates but also
causes a slow response to fluctuating steam demand.
In another boiler type, the fuel cell oven, fuel is dropped onto suspended fixed grates and is
fired in a pile. Unlike the Dutch oven, the refractory-lined fuel cell also uses combustion air
preheating and positioning of secondary and tertiary air injection ports to improve boiler efficiency.
Because of their overall design and operating similarities, however, fuel cell and Dutch oven boilers
have comparable emission characteristics.
The most common firing method employed for wood-fired boilers larger than 45,000 kg/hr
(100,000 Ib/hr) steam generation rate is the spreader stoker. With this boiler, wood enters the furnace
through a fuel chute and is spread either pneumatically or mechanically across the furnace, where
small pieces of the fuel burn while in suspension. Simultaneously, larger pieces of fuel are spread in a
thin, even bed on a stationary or moving grate. The burning is accomplished in three stages in a
single chamber: (1) moisture evaporation; (2) distillation and burning of volatile matter, and (3)
burning of fixed carbon. This type of operation has a fast response to load changes, has improved
combustion control, and can be operated with multiple fuels. Natural gas or oil is often fired in
spreader stoker boilers as auxiliary fuel. This is done to maintain constant steam when the wood
waste supply fluctuates and/or to provide more steam than can be generated from the waste supply
alone. Although spreader stokers are the most common stokers among larger wood-fired boilers,
overfeed and underfeed stokers are also utilized for smaller units.
Another boiler type sometimes used for wood combustion is the suspension-firing boiler. This
boiler differs from a spreader stoker in that small-sized fuel (normally less than 2 mm) is blown into
the boiler and combusted by supporting it in air rather than on fixed grates. Rapid changes in
10/92 External Combustion Sources 1.6-1
-------
combustion rate and, therefore, steam generation rate are possible because the finely divided fuel
particles bum very quickly.
A recent development in wood firing is the fluidized bed combustion (FBC) boiler. A
fluidized bed consists of inert particles through which air is blown so that the bed behaves as a fluid.
Wood waste enters in the space above the bed and burns both in suspension and in the bed. Because
of the large thermal mass represented by the hot inert bed particles, fluidized beds can handle fuels
with moisture contents up to near 70 percent (total basis). Fluidized beds can also handle dirty fuels
(up to 30 percent inert material). Wood fuel is pyrolyzed faster in a fluidized bed than on a gate due
to its immediate contact with hot bed material. As a result, combustion is rapid and results in nearly
complete combustion of the organic matter, thereby minimizing emission of unburned organic
compounds.
1.6.3 Emissions And Controls6"11
The major emission of concern from wood boilers is particulate matter (PM), although other
pollutants, particularly carbon monoxide (CO) and organic compounds, may be emitted in significant
quantities under poor operating conditions. These emissions depend on a number of variables,
including (1) the composition of the waste fuel burned, (2) the degree of flyash reinjection employed
and (3) furnace design and operating conditions.
The composition of wood waste depends largely on the industry from which it originates.
Pulping operations, for example, produce great quantities of bark that may contain more than 70
weight percent moisture, sand, and other non-combustibles. As a result, bark boilers in pulp mills may
emit considerable amounts of particulate matter to the atmosphere unless they are well controlled. On
the other hand, some operations, such as furniture manufacturing, generate a clean, dry wood waste
(e.g., 2 to 20 weight percent moisture) which produces relatively low particulate emission levels when
properly burned. Still other operations, such as sawmills, burn a varying mixture of bark and wood
waste that results in PM emissions somewhere between these two extremes.
Furnace design and operating conditions are particularly important when firing wood waste.
For example, because of the high moisture content that may be present in wood waste, a larger than
usual area of refractory surface is often necessary to dry the fuel before combustion. In addition,
sufficient secondary air must be supplied over the fuel bed to burn the volatiles that account for most
of the combustible material in the waste. When proper drying conditions do not exist, or when
secondary combustion is incomplete, the combustion temperature is lowered, and increased PM, CO,
and organic compound emissions may result. Short term emissions can fluctuate with significant
variations in fuel moisture content
Flyash reinjection, which is commonly used with larger boilers to improve fuel efficiency, has
a considerable effect on PM emissions. Because a fraction of the collected flyash is reinjected into the
boiler, the dust loading from the furnace and, consequently, from the collection device increase
significantly per unit of wood waste burned. More recent boiler installations typically separate the
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.
Currently, the four most common control devices used to reduce PM emissions from wood-
fired boilers are mechanical collectors, wet scrubbers, electrostatic precipitators (ESPs), and fabric
filters. The use of multitube cyclone (or multiclone) mechanical collectors provides particulate control
for many hogged boilers. Often, two multiclones are used in series, allowing the first collector to
1.6-2 EMISSION FACTORS 10/92
-------
remove the bulk of the dust and the second to remove smaller particles. The efficiency of this
arrangement is from 65 to 95 percent. The most widely used wet scrubbers for wood-fired boilers are
venturi scrubbers. With gas-side pressure drops exceeding 4 kPa (15 inches of water), paniculate
collection efficiencies of 90 percent or greater have been reported for venturi scrubbers operating on
wood-fired boilers.
Fabric filters (i.e., baghouses) and ESPs are employed when collection efficiencies above 95
percent are required. When applied to wood-fired boilers, ESPs are often used downstream of
mechanical collector precleaners which remove larger-sized particles. Collection efficiencies of 93 to
99.8 percent for PM have been observed for ESPs operating on wood-fired boilers.
A variation of the ESP is the electrostatic gravel bed filter. In this device, PM in flue gases is
removed by impaction with gravel media inside a packed bed; collection is augmented by an
electrically charged grid within the bed. Particulate collection efficiencies are typically near 95
percent.
Fabric filters have had limited applications to wood-fired boilers. The principal drawback to
fabric filtration, as perceived by potential users, is a fire danger arising from the collection of
combustible carbonaceous fly ash. Steps can be taken to reduce this hazard, including the installation
of a mechanical collector upstream of the fabric filter to remove large burning particles of fly ash (i.e.,
"sparklers"). Despite complications, fabric filters are generally preferred for boilers firing salt-laden
wood. This fuel produces fine particulates with a high salt content. Fabric filters are capable of high
fine particle collection efficiencies; in addition, the salt content of the particles has a quenching effect,
thereby reducing fire hazards. In two tests of fabric filters operating on salt-laden wood-fired boilers,
particulate collection efficiencies were above 98 percent.
Emissions of nitrogen oxides (NOX) from wood-fired boilers are lower than those from coal-
fired boilers due to the lower nitrogen content of wood and the lower combustion temperatures which
characterize wood-fired boilers. In those areas of the U.S. where NOX emissions must be reduced to
their lowest levels, the application of selective non-catalytic reduction (SNCR) and selective catalytic
reduction (SCR) to waste wood-fired boilers has either been accomplished (SNCR) or is being
contemplated (SCR). Both systems are post-combustion NOX reduction techniques in which ammonia
(or urea) is injected into the flue gas to selectively reduce NOX to nitrogen and water. In one
application of SNCR to an industrial wood-fired boiler, NOX reduction efficiencies varied between 35
and 75 percent as the ammonia:NOx ratio increased from 0.4 to 3.2.
Emission factors and emission factor ratings for wood waste boilers are summarized in Tables
1.6-1 through 1.6-9. Cumulative particle size distribution data and associated emission factors are
presented in Tables 1.6-10 and 1.6-11. Uncontrolled and controlled size-specific emission factors are
plotted in Figures 1.6-1 and 1.6-2. All emission factors presented are based on the feed rate of wet,
as-fired wood.
10/92 External Combustion Sources 1.6-3
-------
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1.6-4
EMISSION FACTORS
10/92
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1.6-8
EMISSION FACTORS
10/92
-------
TABLE 1.6-4. (ENGLISH UNITS) EMISSION FACTORS FOR SPECIATED ORGANIC
COMPOUNDS FROM WOOD WASTE COMBUSTION1'a
Organic Compound
Phenols
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benzo(a)anthracene
Benzo(b+k)fluoranthene
Benzo(a)pyrene
B enzo(g,h,i)perylene
Chrysene
Indeno( 1 ,2,3,c,d)pyrene
Polychlorinated dibenzo-p-dioxins
Polychlorinated dibenzo-p-furans
Acenaphthylene
Pyrene
Methyl anthracene
Acrolein
Solicyladehyde
Benzaldehyde
Emission Factor
Range
Ib/ton
6.4E-05-1.2E-04
8.6E-08-4.3E-06
1.7E-07-2.8E-05
2.0E-06-1.8E-04
8.6E-08-3.5E-04
8.6E-08-8.6E-04
4.3E-07-5.9E-05
8.6E-08-6.4E-06
3.4E-07-1.9E-04
8.6E-08-3.0E-07
8.6E-08-3.5E-06
8.6E-08-3.0E-04
8.6E-08-6.0E-07
3.0E-09-3.3E-08
4.6E-09-7.2E-08
6.0E-07-6.8E-05
Average
Emission Factor
Ib/ton
3.9E-04
3.4E-06
9.6E-06
5.7E-05
3.8E-05
9.0E-05
1.7E-05
1.8E-06
2.9E-05
1.9E-07
1.2E-06
4.3E-05
3.4E-07
1.2E-08b'c
2.9E-08b)d
4.4E-05
9.0E-066
1.4E-046
4.0E-066
2.3E-056
1.2E-05e
Emission
Factor
Rating
C
C
C
C
C
C
C
C
C
D
C
C
D
C
C
C
D
D
D
D
D
a. Based on wet, as-fired wood waste with average properties of 50 weight percent moisture and
4500 Btu/lb higher heating value. Data measured after PM control device.
b. Emission factors are for total dioxins and furans, not toxic equivalents.
c. Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor is
1.3E-06 Ib/ton with a D rating.
d. Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor is
5.5E-07 Ib/ton with a D rating.
e. Based on data from one source test.
10/92
External Combustion Sources
1.6-9
-------
TABLE 1.6-5. (METRIC UNITS) EMISSION FACTORS FOR SPECIATED ORGANIC
COMPOUNDS FROM WOOD WASTE COMBUSTION1'31
Organic Compound
Phenols
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benzo(a)anthracene
Benzo(b+k)fluoranthene
Benzo(a)pyrene
Benzo(g,h,i)perylene
Chrysene
Indeno(l ,2,3,c,d)pyrene
Polychlorinated dibenzo-p-dioxins
Polychlorinated dibenzo-p-furans
Acenaphthylene
Pyrene
Methyl anthracene
Acrolein
Solicyladehyde
Benzaldehyde
Emission Factor
Range
kg/Mg
3.2E-05-6.0E-05
4.3E-08-2.1E-06
8.5E-08-1.4E-05
1.0E-06-9.0E-05
4.3E-08-1.7E-04
4.3E-08-4.3E-04
2.1E-07-2.9E-05
4.3E-08-3.2E-06
1.7E-07-9.5E-05
4.3E-08-1.5E-07
4.3E-08-1.7E-06
4.3E-08-1.5E-04
4.3E-08-3.0E-07
1.5E-09-1.7E-08
2.3E-09-3.6E-08
3.0E-07-3.4E-05
Average Emission
Factor
kg/Mg
1.9E-04
1.7E-06
4.8E-06
2.8E-05
1.9E-05
4.5E-05
8.5E-06
9.0E-07
1.9E-05
9.5E-08
6.0E-07
2.1E-05
1.7E-07
6.0E-09b'c
1.5E-08b'd
2.2E-05
4.5E-066
7.0E-056
2.0E-066
LIE-OS6
6.0E-066
Emission
Factor
Rating
C
C
C
C
C
C
C
C
C
D
C
C
D
C
C
C
D
D
D
D
D
a. Based on wet, as-fired wood waste with average properties of 50 weight percent moisture
and 2500 kcal/kg higher heating value. Data measured after PM control device.
b. Emission factors are for total dioxins and furans, not toxic equivalents.
c. Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor
is 6.5E-07 kg/Mg with a D rating.
d. Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor
is 2.8E-07 kg/Mg with a D rating.
e. Based on data from one source test.
1.6-10
EMISSION FACTORS
10/92
-------
TABLE 1.6-6. (ENGLISH UNITS) EMISSION FACTORS FOR TRACE ELEMENTS FROM
WOOD WASTE COMBUSTION1'*1
Emission Factor
Trace Element Range
Ib/ton
Chromium (VI) 3.1E-05-5.9E-05
Copper 1.4E-05-1.2E-03
Zinc 9.9E-05-2.3E-02
Barium
Potassium
Sodium
Iron 8.6E-04-8.7E-02
Lithium
Boron
Chlorine
Vanadium
Cobalt
Thorium
Tungsten
Dysprosium
Samarium
Neodymium
Praeseodymium
Iodine
Tin
Molybdenum
Niobium
Zirconium
Yttrium
Rubidium
Bromine
Germanium
a. Based on wet, as-fired wood waste with average properties of
Btu/lb higher heating value. Data measured after PM control
b. Based on data from one source test.
Average Emission
Factor
Ib/ton
4.6E-05
1.9E-04
4.4E-03
4.4E-03b
7.8E-01b
1.8E-02b
4.4E-02
7.0E-05b
8.0E-04b
7.8E-03b
1.2E-04b
1.3E-04b
1.7E-05b
l.lE-05b
1.3E-05b
2.0E-05b
2.6E-05b
3.0E-05b
1.8E-05b
3.1E-05b
1.9E-04b
3.5E-05b
3.5E-04b
5.6E-05b
1.2E-03b
3.9E-04b
2.5E-06b
Emission
Factor
Rating
D
C
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
50 weight percent moisture and 4500
device.
10/92
External Combustion Sources
1.6-11
-------
TABLE 1.6-7. (METRIC UNITS) EMISSION FACTORS FOR TRACE ELEMENTS FROM
WOOD WASTE COMBUSTION1'21
Emission Factor
Trace Element Range
kg/Mg
Chromium (VI) 1.5E-05-2.9E-05
Copper 7.0E-06-6.0E-04
Zinc 4.9E-05-1.1E-02
Barium
Potassium
Sodium
Iron 4.3E-04-3.3E-02
Lithium
Boron
Chlorine
Vanadium
Cobaltb
Thorium
Tungsten
Dysprosium
Samarium
Neodymium
Praeseodymium
Iodine
Tin
Molybdenum
Niobium
Zirconium
Yttrium
Rubidium
Bromine
Germanium
a. Based on wet, as-fired wood waste with average properties of
kcal/kg higher heating value. Data measured after PM control
b. Based on data from one source test.
1.6-12 EMISSION FACTORS
Average Emission
Factor
kg/Mg
2.3E-05
9.5E-05
2.2E-03
2.2E-03b
3.9E-01b
9.0E-03b
2.2E-02
3.5E-05b
4.0E-04b
3.9E-03b
6.0E-05b
6.5E-05b
8.5E-06b
5.5E-06b
6.5E-06b
1.0E-05b
1.3E-05b
1.5E-05b
8.0E-06b
1.5E-05b
9.5E-05b
1.7E-05b
1.7E-04b
2.8E-05b
6.0E-04b
1.8E-04b
1.7E-06b
Emission
Factor
Rating
D
C
C
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
50 weight percent moisture and 2500
device.
10/92
-------
TABLE 1.6-8 (ENGLISH UNITS) EMISSION FACTORS FOR HAZARDOUS AIR
POLLUTANTS (HAPs) FROM WOOD WASTE COMBUSTION1^
Hazardous Air Pollutant
Arsenic
Cadmium
Chromium
Manganese
Mercury
Nickel
Selenium
Formaldehyde
Acetaldehyde
Benzene
Naphthalene
2,3,7,8-Tetrachlorodibenzo-p-dioxin
Emission Factor
Range
Ib/ton
1.4E-06-2.4E-04
2.7E-06-5.4E-04
6.0E-06-4.6E-04
3.0E-04-5.2E-02
2.6E-06-2.1E-05
3.4E-05-5.8E-03
1.7E-05-1.8E-05
2.3E-04-3.3E-02
6.1E-05-2.4E-02
8.6E-05-1.4E-02
5.0E-05-5.8E-03
2. 12E-01 1-5.1 IE-Oil
Average Emission
Factor
Ib/ton
8.8E-05
1.7E-05
1.3E-04
8.9E-03
6.5E-06
5.6E-04
1.8E-05
6.6E-03
3.0E-03
3.6E-03
2.3E-03
3.6E-011
Emission
Factor
Rating
C
C
C
C
C
C
D
C
C
C
C
D
a. Based on wet, as-fired wood waste with average properties of 50 weight percent moisture
and 4500 Btu/lb higher heating value. Data measured after PM control device.
10/92
External Combustion Sources
1.6-13
-------
TABLE 1.6-9 (METRIC UNITS) EMISSION FACTORS FOR HAZARDOUS AIR
POLLUTANTS (HAPs) FROM WOOD WASTE COMBUSTION1'3-
Hazardous Air Pollutant
Arsenic
Cadmium
Chromium
Manganese
Mercury
Nickel
Selenium
Formaldehyde
Acetaldehyde
Benzene
Naphthalene
2,3,7,8-Tetrachlorodibenzo-p-dioxin
Emission Factor Average Emission
Range Factor
kg/Mg kg/Mg
7.0E-07-1.2E-04
1.3E-06-2.7E-04
3.0E-06-2.3E-04
1.5E-04-2.6E-02
1.3E-06-1.0E-05
1.7E-05-2.9E-03
8.5E-06-9.0E-06
1.2E-04-1.6E-02
3.0E-05-1.2E-02
4.3E-05-7.0E-03
2.5E-05-2.9E-03
1.1E-011-2.6E-011
4.4E-05
8.5E-06
6.5E-05
4.4E-03
3.7E-06
2.8E-04
8.8E-06
3.3E-03
1.5E-03
1.8E-03
1.1E-03
1.8E-011
Emission
Factor
Rating
C
C
C
C
C ,
C
D
C
C
C
C
D
a. Based on wet, as-fired wood waste with average properties of 50 weight percent moisture
and 2400 kcal/kg higher heating value. Data measured after PM control device.
1.6-14
EMISSION FACTORS
10/92
-------
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REFERENCES FOR SECTION 1.6
1. Draft report. 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, October
1992.
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 BurnhiR Boilers, C-E Industrial Boiler Operations, Combustion Engineering,
Inc., Windsor, CT, 1973.
5. Nonfossil Fuel Fired Industrial Boilers - Background Information, EPA-450/3-82-007, U.
S. Environmental Protection Agency, Research Triangle Park, NC, March 1982.
6. Control of Paniculate Emissions From Wood-Fired Boilers, EPA 340/1-77-026, U. S.
Environmental Protection Agency, Washington, D.C., 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. "Emission Control Technologies For Wood-Fired Boilers", E. Aul, Jr., and K. Barnett,
Radian Corporation, Presented at the Wood Energy Conference, Raleigh, NC, October
1984.
9. "Noncatalytic Ammonia Injection For NOX Reduction on a Waste Wood Fired Boiler", G.
Moilanen, Sierra Environmental Engineers, Inc., Costa Mesa, California, and K. Price, C.
Smith, and A. Turchina, Proctor & Gamble Company, Cincinnati, Ohio, Presented at the
80th Annual Meeting of the Air Pollution Control Association, New York, NY, June 1987.
10. "Information on the Sulfur Content of Bark and Its Contribution to SO2 Emissions When
Burned as a Fuel", H. Oglesby and R. Blosser, Journal of the Air Pollution Control
Agency, 30(7):769-772, July 1980.
11. Inhalable Paniculate Source Category Report for External Combustion Sources, EPA
Contract No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985.
10/92 External Combustion Sources 1.6-17
-------
-------
1.8 BAGASSE COMBUSTION IN SUGAR MILLS
1.8.1 Process Description
Bagasse is the matted cellulose fiber residue from sugar cane that has been processed in a
sugar mill. Previously, bagasse was burned as means of solid waste disposal. However, as the cost of
fuel oil, natural gas, and electricity have increased, the definition of bagasse has changed from refuse
to a fuel.
The U.S. sugar cane industry is located in the tropical and subtropical regions of Florida,
Texas, Louisiana, Hawaii, and Puerto Rico. Except for Hawaii, where sugar cane production takes
place year round, sugar mills operate seasonally from 2 to 5 months per year.
Sugar cane is a large grass with a bamboo-like stalk that grows 8 to 15 feet tall. Only the
stalk contains sufficient sucrose for processing into sugar. All other parts of the sugar cane (i.e.,
leaves, top growth and roots) are termed "trash." The objective of harvesting is to deliver the sugar
cane to the mill with a minimum of trash or other extraneous material. The cane is normally burned
in the field to remove a major portion of the trash and to control insects and rodents. The three most
common methods of harvesting are hand cutting, machine cutting, and mechanical raking. The cane
that is delivered to a particular sugar mill will vary in trash and dirt content depending on the
harvesting method and weather conditions. Inside the mill, cane preparation for extraction usually
involves washing the cane to remove trash and dirt, chopping, and then crushing. Juice is extracted in
the milling portion of the plant by passing the chopped and crushed cane through a series of grooved
rolls. The cane remaining after milling is bagasse.
Bagasse is a fuel of varying composition, consistency, and heating value. These characteristics
depend on the climate, type of soil upon which the cane is grown, variety of cane, harvesting method,
amount of cane washing, and the efficiency of the milling plant In general, bagasse has a heating
value between 1,700 and 2,200 kcal/kg (3,000 and 4,000 Btu/lb) on a wet, as-fired basis. Most
bagasse has a moisture content between 45 and 55 percent by weight.
Fuel cells, horseshoe boilers, and spreader stoker boilers are used to combust 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 up on a refractory hearth. Primary and overfire combustion air
flows through ports in the furnace walls; burning begins on the surface pile. Many of these units have
dumping hearths that permit ash removal while the unit is operating.
In more-recently built sugar mills, bagasse is burned in spreader stoker boilers. Bagasse feed
to these boilers enters the furnace through a fuel chute and is spread pneumatically or mechanically
across the furnace, where part of the fuel burns while in suspension. Simultaneously, large pieces of
fuel are spread 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).
1.8.2 Emissions and Controls1"3
The most significant pollutant emitted by bagasse-fired boilers is paniculate matter, caused by
the turbulent movement of combustion gases with respect to the burning bagasse and resultant ash.
Emissions of SO2 and NOX are lower than conventional fossil fuels due to the characteristically low
levels of sulfur and nitrogen associated with bagasse.
10/92 External Combustion Sources 1.8-1
-------
Auxiliary fuels (typically fuel oil or natural gas) may be used during startup of the boiler or
when the moisture content of the bagasse is too high to support combustion. If fuel oil is used during
these periods, SO2 and NOX emissions will increase. Soil characteristics such as particle size can
affect the magnitude of PM emissions from the boiler. Mill operations can also influence the bagasse
ash content by not properly washing and preparing the cane. Upsets in combustion conditions can
cause increased emissions of carbon monoxide (CO) and unburned organics, typically measured as
volatile organic compounds (VOCs) and total organic compounds (TOCs).
Mechanical collectors and wet scrubbers are commonly used to control particulate emissions
from bagasse-fired boilers. Mechanical collectors may be installed in single cyclone, double cyclone,
or multiple cyclone (i.e., multiclone) arrangements. The reported PM collection efficiency for
mechanical collectors is 20 to 60 percent Due to the abrasive nature of bagasse fly ash, mechanical
collector performance may deteriorate over time due to erosion if the system is not well maintained.
The most widely used wet scrubbers for bagasse-fired boilers are impingement and venturi
scrubbers. Impingement scrubbers normally operate at gas-side pressure drops of 5 to 15 inches of
water; typical pressure drops for venturi scrubbers are over 15 inches of water. Impingement
scrubbers are in greater use due to lower energy requirements and fewer operating and maintenance
problems. Reported PM collection efficiencies for both scrubber types are 90 percent or greater.
Gaseous emissions (e.g., SO2, NOX, CO, and organics) may also be absorbed to a significant
extent in a wet scrubber. Alkali compounds are sometimes utilized in the scrubber to prevent low pH
conditions. If COo-generating compounds (such as sodium carbonate or calcium carbonate) are used,
CO2 emissions will increase.
Fabric filters and electrostatic precipitators have not been used to a significant extent for
controlling PM from bagasse-fired boilers due to potential fire hazards (fabric filters) and relatively
higher costs (both devices).
Emission factors and emission factor ratings for bagasse-fired boilers are shown in Table 1.8-1
(English units) and Table 1.8-2 (metric units).
1.8-2 EMISSION FACTORS 10/92
-------
TABLE 1.8-1. EMISSION FACTORS FOR BAGASSE-FIRED BOILERSa
(ENGLISH UNITS)
Pollutant
Particulate matter
Uncontrolled
Controlled
Mechanical collector
Wet scrubber
PM-10d
Controlled
Wet scrubber
Carbon dioxide
Uncontrolled6
Nitrogen oxides
Uncontrolled
Polvcvclic organic matter
f
Uncontrolled
Emission
lb/1,000 Ib steamb
3.9
2.1
0.4
0.34
390
0.3
2.5E-4
factor
Ib/ton bagasse0
15.6
8.4
1.6
1.36
1,560
1.2
l.OE-3
Rating
C
D
B
D
A
C
D
a. Reference 5.
b. Based on 2 pounds of steam produced per pound of wet bagasse fired.
c. Based on wet, as-fired bagasse containing approximately 50 percent moisture, by weight
d. Includes only filterable PM (i.e., that paniculate collected on or prior to the filter of an EPA
Method 5 (or equivalent) sampling train.
e. CO2 emissions will increase following a wet scrubber in which CO2-generating reagents (such as
sodium carbonate or calcium carbonate) are used.
f. Based on measurements collected downstream of PM control devices which may have provided
some removal of POM condensed on PM.
10/92 External Combustion Sources 1.8-3
-------
TABLE 1.8-2. EMISSION FACTORS FOR BAGASSE-FIRED BOILERSa
(METRIC UNITS)
Emission factor,
Pollutant
g/kg steam"
kg/Mg bagasse
Rating
Particulate matter"
Uncontrolled
Controlled
Mechanical collector
Wet scrubber
PM-10d
Controlled
3.9
2.1
0.4
7.8
4.2
0.8
D
B
Wet scrubber
Carbon dioxide
Uncontrolled6
Nitrogen oxides
Uncontrolled
Polvcyclic organic matter
Uncontrolled
0.34
390
0.3
2.5E-4
0.68
780
0.6
5.0E-4
D
A
C
D
a. Reference 5.
b. Based on 2 kg of steam produced per kg of wet bagasse fired.
c. Based on wet, as-fired bagasse containing approximately 50 percent moisture, by weight.
d. Includes only filterable PM (i.e., that particulate collected on or prior to the filter of an EPA
Method 5 (or equivalent) sampling train.
e. CO2 emissions will increase following a wet scrubber in which CO2-generating reagents (such as
sodium carbonate or calcium carbonate) are used.
f. Based on measurements collected downstream of PM control devices which may have provided ,
some removal of POM condensed on PM.
1.8-4
EMISSION FACTORS
10/92
-------
REFERENCES FOR SECTION 1.8
1. Potential Control Strategies for Bagasse Fired Boilers, EPA Contract No. 68-02-0627,
Engineering-Science, Inc., Arcadia, California, May 1978.
2. Background Document: Bagasse Combustion in Sugar Mills. EPA-450/3-77-077, U. S.
Environmental Protection Agency, Research Triangle Park, North Carolina, January 1977.
3. Nonfossil Fuel Fired Industrial Boilers - Background Information, EPA-450/3-82-007, U.
S. Environmental Protection Agency, Research Triangle Park, North Carolina, 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, Illinois, December 1981.
5. Draft report. 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, North Carolina,
September 1992.n factor,
10/92 External Combustion Sources 1.8-5
-------
-------
1.9 RESIDENTIAL FIREPLACES
1.9.1 General1'2
Fireplaces are used primarily for aesthetic effects and secondarily as a supplemental heating source
in houses and other dwellings. Wood is the most common fuel for fireplaces, but coal and densified wood
"logs" may also be burned. The user intermittently adds fuel to the fire by hand.
Fireplaces can be divided into two broad categories, 1) masonry (generally brick and/or stone,
assembled on site, and integral to a structure) and 2) prefabricated (usually metal, installed on site as a
package with appropriate duct work).
Masonry fireplaces typically have large fixed openings to the fire bed and have dampers above
the combustion area in the chimney to limit room air and heat losses when the fireplace is not being used.
Some masonry fireplaces are designed or retrofitted with doors and louvers to reduce the intake of
combustion air during use.
Prefabricated fireplaces are commonly equipped with louvers and glass doors to reduce the intake
of combustion air, and some are surrounded by ducts through which floor level air is drawn by natural
convection, heated and returned to the room. Many varieties of prefabricated fireplaces are now available
on the market. One general class is the freestanding fireplace, the most common of which consists of an
inverted sheet metal funnel and stovepipe directly above the fire bed. Another class is the "zero clearance"
fireplace, an iron or heavy gauge steel firebox lined inside with firebrick and surrounded by multiple steel
walls with spaces for air circulation. Some zero clearance fireplaces can be inserted into existing masonry
fireplace openings, and thus are sometimes called "inserts." Some of these units are equipped with close
fitting doors and have operating and combustion characteristics similar to wood stoves. (See Section 1.10,
Residential Wood Stoves.)
Masonry fireplaces usually heat a room by radiation, with a significant fraction of the combustion
heat lost in the exhaust gases and through fireplace walls. Moreover, some of the radiant heat entering
the room goes toward warming the air that is pulled into the residence to make up for that drawn up the
chimney. The net effect is that masonry fireplaces 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 Emissions1"13
The major pollutants of concern from fireplaces are unburnt combustibles, including carbon
monoxide, gaseous organics and paniculate matter (i. e., smoke). Significant quantities of unburnt
combustibles are produced because fireplaces are inefficient combustion devices, with high uncontrolled
excess air rates and without any sort of secondary combustion. The latter is especially important in wood
burning because of its high volatile matter content, typically 80 percent by dry weight. In addition to
10/92 External Combustion Sources 1.9-1
-------
unburnt combustibles, lesser amounts of nitrogen oxides and sulfur oxides are emitted.
Hazardous Air Pollutants (HAPs) are a minor, but potentially important component of wood
smoke. A group of HAPs known as polycyclic organic matter (POM) includes potential carcinogens such
as benzo(a)pyrene (BaP). POM results from the combination of free radical species formed in the flame
zone, primarily as a consequence of incomplete combustion. Under reducing conditions, radical chain
propagation is enhanced, allowing the buildup of complex organic material such as POM. The POM is
generally found in or on smoke particles, although some sublimation into the vapor phase is probable.
Another important constituent of wood smoke is creosote. This tar-like substance will burn if the
fire is hot enough, but at insufficient temperatures, it may deposit on surfaces in the exhaust system.
Creosote deposits are a fire hazard in the flue, but they can be reduced if the chimney is insulated to
prevent creosote condensation or if the chimney is cleaned regularly to remove any buildup.
Fireplace emissions are highly variable and are a function of many wood characteristics and
operating practices. In general, conditions which promote a fast burn rate and a higher flame intensity
enhance secondary combustion and thereby lower emissions. Conversely, higher emissions will result
from a slow burn rate and a lower flame intensity. Such generalizations apply particularly to the earlier
stages of the burning cycle, when significant quantities of combustible volatile matter are being driven out
of the wood. Later in the burning cycle, when all volatile matter has been driven out of the wood, the
charcoal that remains burns with relatively few emissions.
Emission factors and their ratings for wood combustion in residential fireplaces are given in Tables
1.9-1. and 1.9-2.
1.9_2 EMISSION FACTORS 10/92
-------
Table 1.9-1. (ENGLISH UNITS) EMISSION FACTORS FOR WOOD COMBUSTION IN
RESIDENTIAL FIREPLACES
Device
Pollutant
Emission Factor3
Ib/ton
Rating
Fireplace
PM-10b
Carbon Monoxide0
Sulfur Oxidesd
Nitrogen oxides6
Carbon Dioxide
TOG (Total Organic Compounds)
Non-methane^
POM1
Aldehydesk
Hydrocarbons
34.6
252.6
0.4
2.6
3398.8
26.0
1.6E-3
2.4
175.4
B
B
A
C
C
^
EJ
EJ
1~
Dh
a. Units are in Ib/ton (Ibs. of pollutant/ton of dry wood burned).
b. References 2, 5, 7, 13; contains filterable and condensable paniculate matter (PM); PM
emissions are considered to be 100% PM-10 (i.e., PM with an aerodynamic diameter of
10pm or less).
c. References 2, 4, 5, 9, 13.
d. References 1, 8.
e. References 4, 9; expressed as NO2.
f. References 5, 13
g. References 1, 7.
h. Data used to calculate ihe average emission factor were collected by various methods.
While the emission factor may be representative of the source population in general, it
should not be used to estimate emissions from a specific source.
i. Reference 2.
j. Data used to calculate the average emission factor were collected from a single fireplace
and are not representative of the general source population.
k. Reference 11.
1. References 2, 4, 5.
10/92
External Combustion Sources
1.9-3
-------
Table 1.9-2. (METRIC UNITS) EMISSION FACTORS FOR WOOD COMBUSTION IN
RESIDENTIAL FIREPLACES
Device Pollutant Emission Factora Rating
Fireplace
PM-10b
Carbon Monoxide0
Sulfur Oxidesd
Nitrogen oxides6
Carbon Dioxide
TOC (Total Organic Compounds)
Non-methane^
POM1
Aldehydesk
Hydrocarbons
17.3
126.3
0.2
1.3
1699.4
13
0.8E-3
1.2
87.7
B
B
A
C
C
v.
EJ
^
a. Units are in g/kg (grams of pollutant/kg of dry wood burned).
b. References 2, 5, 7, 13; contains filterable and condensable paniculate matter (PM); PM
emissions are considered to be 100% PM-10 (i.e., PM with an aerodynamic diameter of
10pm or less).
c. References 2, 4, 5, 9, 13.
d. References 1, 8.
e. References 4, 9; expressed as NO2-
f. References 5, 13
g. References 1, 7.
h. 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, it
should not be used to estimate emissions from a specific source.
i. Reference 2.
j. Data used to calculate the average emission factor were collected from a single fireplace
and are not representative of the general source population.
k. Reference 11.
1. References 2, 4, 5.
1.9.4 EMISSION FACTORS 10/92
-------
References for Section 1.9
1. DeAngelis, D. G., et al., Source Assessment: Residential Combustion Of Wood, EPA-600/2-
80-0425, U. S. Environmental Protection Agency, Cincinnati, OH, March 1980.
2. Snowden, W. D., et al., Source Sampling Residential Fireplaces For Emission Factor
Development, EPA-450/3-76-010, U. S. Environmental Protection Agency, Research Triangle
Park, NC, November 1975.
3. Shelton, J. W., and L. Gay, Colorado Fireplace Report, Colorado Air Pollution Control
Division, Denver, CO, March 1987.
4. Dasch, J. M., "Particulate And Gaseous Emissions From Wood-burning Fireplaces,"
Environmental Science And Technology, 16(10):643-67, October 1982.
5. Source Testing For Fireplaces, Stoves, And Restaurant Grills In Vail, Colorado, EPA
Contract No. 68-01-1999, Pedco Environmental, Inc., Cincinnati, OH, December 1977.
6. Written communication from Robert C. McCrillis, U. S. Environmental Protection Agency,
Research Triangle Park, NC, to Neil Jacquay, U. S. Environmental Protection Agency, San
Francisco, CA, November 19, 1985.
7. Development Of AP-42 Emission Factors For Residential Fireplaces, EPA Contract No. 68-
D9-0155, Advanced Systems Technology, Inc., Atlanta, GA, January 11, 1990.
8. DeAngelis, D. G., et al., Preliminary Characterization Of Emissions From Wood Fired
Residential Combustion Equipment, EPA-600/7-80-040, U. S. Environmental Protection
Agency, Cincinnati, OH, March 1980.
9. Kosel, P., et al., Emissions From Residential Fireplaces, CARB Report C-80-027, California
Air Resources Board, Sacramento, CA, April 1980.
10. Clayton, L., et al., Emissions From Residential Type Fireplaces, Source Tests 24C67, 26C,
29C67, 40C67, 41C67, 65C67 and 66C67, Bay Area Air Pollution Control District, San
Francisco, CA, January 31, 1968.
11. Lipari, F., et al., Aldehyde Emissions From Wood-Burning Fireplaces, Publication GMR-
4377R, General Motors Research Laboratories, Warren, MI, March 1984.
12. Hayden, A. C. S., and R. W. Braaten, "Performance Of Domestic Wood Fired Appliances,"
Presented at the 73rd Annual Meeting of the Air Pollution Control Association, Montreal,
Quebec, Canada, June 1980.
13. Barnett, S.G., In-Home Evaluation of Emissions From Masonry Fireplaces and Heaters,
OMNI Environmental Services, Inc., Beaverton, OR, September 1991.
10/92 External Combustion Sources 1.9-5
-------
-------
1.10 RESIDENTIAL WOOD STOVES
1.10.1 General1"3
Wood stoves are commonly used in residences as space heaters. They are used both as the
primary source of residential heat and to supplement conventional heating systems.
Five different categories should be considered when estimating emissions from wood burning
devices due to differences in both the magnitude and the composition of the emissions:
the conventional wood stove,
the noncatalytic wood stove,
the catalytic wood stove,
the pellet stove, and
the masonry heater.
Among these categories, there are many variations in device design and operation characteristics.
The conventional stove category comprises all stoves without catalytic combustors not included
in the other noncatalytic categories (i. e., noncatalytic and pellet). Conventional stoves do not have
any emission reduction technology or design features and, in most cases, were manufactured before
July 1, 1986. Stoves of many different airflow designs may be in this category, such as updraft,
downdraft, crossdraft and S-flow.
Noncatalytic wood stoves are those units that do not employ catalysts but do have emission
reducing technology or features. Typical noncatalytic design includes baffles and secondary
combustion chambers.
Catalytic stoves are equipped with a ceramic or metal honeycomb device, called a combustor
or converter, that is coated with a noble metal such as platinum or palladium. The catalyst material
reduces the ignition temperature of the unburned volatile organic compounds (VOC) and carbon
monoxide (CO) in the exhaust gases, thus augmenting their ignition and combustion at normal stove
operating temperatures. As these components of the gases burn, the temperature inside the catalyst
increases to a point at which the ignition of the gases is essentially self sustaining.
Pellet stoves are those fueled with pellets of sawdust, wood products, and other biomass
materials pressed into manageable shapes and sizes. These stoves have active air flow systems and
unique grate design to accommodate this type of fuel. Some pellet stove models are subject to the
1988 New Source Performance Standards (NSPS), while others are exempt due to a high air-to-fuel
ratio (i.e., greater than 35-to-l).
Masonry heaters are large, enclosed chambers made of masonry products or a combination of
masonry products and ceramic materials. These devices are exempt from the 1988 NSPS due to their
weight (i.e., greater than 800 kg). Masonry heaters are gaining popularity as a cleaner burning and
10/92 External Combustion Sources
1.10-1
-------
TABLE 1.10-1. (ENGLISH UNITS) EMISSION FACTORS FOR RESIDENTIAL
WOOD COMBUSTIONa
Pollutant/
EPA Certification13
Emission
Factor
Rating
Wood Stove Typec
Conv.
Ib/ton
Non-Cat
Ib/ton
Cat
Ib/ton
Pellet Stove Typed
Certified
Ib/ton
Exempt
Ib/ton
Masonry
Heater
Exempt6
Ib/ton
PM-10f'g
Pre-Phase I
Phase I
Phase n
All
Carbon Monoxide
Pre-Phase I
Phase I
Phase II
All
Nitrogen Oxides
Sulfur Oxidesf
Carbon Dioxide^
Total Organic
Compounds1*-
Methane
Non-Methane
B
B
B
B
B
B
B
B
B
C
E
E
30.6
30.6
230.8
25.8
20.0
14.6
19.6
24.2
19.6
16.2
20.4
4.2
4.2
5.6
230.8
2.8h
0.4
140.8
140.8
0.4
104.4
107.0
104.8
2.01
0.4
39.4
39.4
13.81
0.4
2,951.6
52.2
149.0
3,671.2 3,849.4
64.0
28.0
26.0
17.2
a. Units are in (Ibs. of pollutant/ton of dry wood burned).
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.
c. Conv = Conventional; Non-Cat = Noncatalytic; Cat = Catalytic.
d. Certified = Certified pursuant to 1988 NSPS; Exempt = Exempt from 1988 NSPS (i.e., ainfuel
ratio >35:1).
e. Exempt = Exempt from 1988 NSPS (i.e., weight >800 kg).
f. References 5-13, 22-26, 28.
g. Defined as equivalent to total catch by EPA method 5H train.
h. Rating = C.
i. Rating = E.
j. References 12, 22-26, 28.
k. References 14, 15, 18. The data used to develop the emission factors showed a high degree of
variability within the source population. The use of these emission factors on specific sources
may not be appropriate.
1.10-4
EMISSION FACTORS
10/92
-------
TABLE 1.10-2. (METRIC UNITS) EMISSION FACTORS FOR RESIDENTIAL
WOOD COMBUSTIONa
Pollutant/
EPA Certification13
Emission
Factor
Rating
Wood Stove Typec
Conv.
g/kg
Non-Cat
g/kg
Cat
g/kg
Pellet Stove Typed
Certified
g/kg
Exempt
g/kg
Masonry
Heater
Exempt6
g/kg
PM-10f'g
Pre-Phasel B 15.3 12.9 12.1
Phase I B 10.0 9.8
Phase II B 7.3 8.1
All B 15.3 9.8 10.2
f
Carbon Monoxide
2.1
2.1
4.4
20
.o
Pre-Phase I
Phase I
Phase II
All
Nitrogen Oxides
Sulfur Oxides*
Carbon DioxideJ
Total Organic
Compounds**1
Methane
Non-Methane
a. Units are in
b. Pre-Phase I
B
B
B
B
B
C
E
E
115.4
115.4
1.4h
0.2
32.0
14.0
(grams of pollutant/kg
= not certified to 1988
52.2
70.4 53.5 19.7
70.4 52.4 19.7 26.1
1.0* 6.91
0.2 0.2 0.2
1,475.8 1,835.6
13.0
8.6
of dry wood burned).
EPA emission standards; Phase I = certified to
74.5
1,924.7
1988 EPA
c.
d.
e.
f.
g-
h.
i.
j-
k.
emission standards; Phase II = certified to 1990 EPA emission standards; All = average of
emission factors for all devices.
Conv = Conventional; Non-Cat = Noncatalytic; Cat = Catalytic.
Certified = Certified pursuant to 1988 NSPS; Exempt = Exempt from 1988 NSPS (i.e., ainfuel
ratio >35:1).
Exempt = Exempt from 1988 NSPS (i.e., weight >800 kg).
References 5-13, 22-26, 28.
Defined as equivalent to total catch by EPA method 5H train.
Rating = C.
Rating = E.
References 12, 22-26, 28.
References 14, 15, 18. The data used to develop the emission factors showed a high degree of
variability within the source population. The use of these emission factors on specific sources
may not be appropriate.
10/92
External Combustion Sources
1.10-5
-------
TABLE 1.10-3. (ENGLISH AND METRIC UNITS) ORGANIC COMPOUND EMISSION
FACTORS FOR RESIDENTIAL WOOD COMBUSTION18
(Emission Factor Rating: E)a
Compounds
Ethane
Ethylene
Acetylene
Propane
Propene
i-Butane
n-Butane
Butenesc
Pentenes^
Benzene
Toluene
Furan
Methyl Ethyl Ketone
2-Methyl Furan
2,5-Dimethyl Furan
Furfural
O-Xylene
WOOD STOVE TYPEb
Conventional
Ib/ton g/kg
1.470 0.735
4.490 2.245
1.124 0.562
0.358 0.179
1.244 0.622
0.028 0.014
0.056 0.028
1.192 0.596
0.616 0.308
1.938 0.969
0.730 0.365
0.342 0.171
0.290 0.145
0.656 0.328
0.162 0.081
0.486 0.243
0.202 0.101
Catalytic
Ib/ton g/kg
1.376 0.688
3.482 1.741
0.564 0.282
0.158 0.079
0.734 0.367
0.010 0.005
0.014 0.007
0.714 0.357
0.150 0.075
1.464 0.732
0.520 0.260
0.124 0.062
0.062 0.031
0.084 0.042
0.002 0.011
0.146 0.073
0.186 0.093
a. The data used to develop the emission factors showed a high degree of variability within
the source population. The use of these emission factors on specific sources may not be
appropriate.
b. Units are in Ib/ton (Ibs. of pollutant/ton of dry wood burned).
c. 1-butene, i-butene, t-2-butene, c-2-butene, 2-me-l-butene, 2-me-butene are reported as
butenes.
d. 1-pentene, t-2-pentene, and c-2-pentene are reported as pentenes.
1.10-6
EMISSION FACTORS
10/92
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TABLE 1.10-4. (ENGLISH UNITS) POLYCYCLIC AROMATIC HYDROCARBON (PAH)
EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTIONa
(Emission Factor Rating: E)
Pollutant
STOVE TYPE
Conventional0
Ib/ton
Noncatalyticd
Ib/ton
Catalytic6
Ib/ton
Exempt Pelletf
Ib/ton
PAH
Acenaphthene 0.010
Acenaphthylene 0.212
Anthracene 0.014
Benzo(a)Anthracene 0.020
Benzo(b)Fluoranthene 0.006
Benzo(g,h,i)Fluoranthene
Benzo(k)Fluoranthene 0.002
Benzo(g,h,i)Perylene 0.004
Benzo(a)Pyrene 0.004
Benzo(e)Pyrene 0.012
Biphenyl
Chrysene 0.012
Dibenzo(a,h)Anthracene 0.000
7,12-Dimethylbenz(a) Anthracene
Fluoranthene 0.020
Fluorene 0.024
Indeno(l,2,3,cd)Pyrene 0.000
9-Methylanthracene
12-Methylbenz(a)Anthracene
3-Methylchlolanthrene
1 -Methylphenanthrene
Naphthalene 0.288
Nitronaphthalene
Perylene
Phenanthrene 0.078
Phenanthrol
Phenol
Pyrene 0.024
PAH Total 0.730
0.010
0.032
0.009
<0.001
0.004
0.028
<0.001
0.020
0.006
0.002
0.022
0.010
0.004
0.004
0.008
0.014
0.020
0.004
0.002
<0.001
0.030
0.144
0.000
0.002
0.118
0.000
<0.001
0.008
0.500
0.006
0.068
0.008
0.024
0.004
0.006
0.002
0.002
0.004
0.004
0.010
0.002
0.012
0.014
0.004
0.186
0.489
0.010
0.414
2.60E-05
7.52E-05
5.48E-05
3.32E-05
4.84E-05
a. Units are in Ib/ton (Ibs. of pollutant/ton of dry wood burned).
b. The data used to develop these emission factors showed a high degree of variability within the
source population and/or came from a small number of sources. The use of these emission factors
on specific sources may not be appropriate.
c. Reference 18.
d. References 16,19-21.
e. References 15-19.
f. Reference 28. Exempt = Exempt from 1988 NSPS (i.e., airfuel ratio >35:1).
10/92
External Combustion Sources
1.10-7
-------
TABLE 1.10-5. (METRIC UNITS) POLYCYCLIC AROMATIC HYDROCARBON (PAH)
EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION51
(Emission Factor Rating: E)
Pollutant
STOVE TYPE
Conventional0
g/kg
Noncatalylic
g/kg
Catalytic6
g/kg
Exempt Pelletf
g/kg
PAH
Acenaphthene 0.005
Acenaphthylene 0.106
Anthracene 0.007
Benzo(a) Anthracene 0.010
Benzo(b)Fluoranthene 0.003
Benzo(g,h,i)Fluoranthene
Benzo(k)Fluoranthene 0.001
Benzo(g,h,i)Perylene 0.002
Benzo(a)Pyrene 0.002
Benzo(e)Pyrene 0.006
Biphenyl
Chrysene 0.006
Dibenzo(a,h)Anthracene 0.000
7,12-Dimethylbenz(a)Anthracene
Fluoranthene 0.010
Fluorene 0.012
Indeno(l,2,3,cd)Pyrene 0.000
9-Methylanthracene
12-Methylbenz(a)Anthracene
3-Methylchlolanthrene
1-Methylphenanthrene
Naphthalene 0.144
Nitronaphthalene
Perylene
Phenanthrene 0.039
Phenanthrol
Phenol
Pyrene 0.012
PAH Total 0.365
0.005
0.016
0.004
<0.001
0.002
0.014
<0.001
0.010
0.003
0.001
0.011
0.005
0.002
0.002
0.004
0.007
0.010
0.002
0.001
<0.001
0.015
0.072
0.000
0.001
0.059
0.000
<0.001
0.004
0.250
0.003
0.034
0.004
0.012
0.002
0.003
0.001
0.001
0.002
0.002
0.005
0.001
0.006
0.007
0.002
0.093
0.024
0.005
0.207
1.30E-05
3.76E-05
2.74E-05
1.66E-05
2.42E-05
a. Units are in g/kg (grams of pollutant/kg of dry wood burned).
b. The data used to develop these emission factors showed a high degree of variability within the
source population and/or came from a small number of sources. The use of these emission factors
on specific sources may not be appropriate.
c. Reference 18.
d. References 16,19-21.
e. References 15-19.
f. Reference 28. Exempt = Exempt from 1988 NSPS (i.e., ainfuel ratio >35:1).
1.10-8
EMISSION FACTORS
10/92
-------
TABLE 1.10-6. (ENGLISH AND METRIC UNITS) TRACE ELEMENT EMISSION FACTORS
FOR RESIDENTIAL WOOD COMBUSTIONa
(Emission Factor Rating: E)b
Element
WOOD STOVE TYPE
Conventional
Ib/ton g/kg
Noncatalytic
Ib/ton g/kg
Catalytic
Ib/ton g/kg
Cadmium (Cd) 2.2E-05 LIE-OS 2.0E-05 l.OE-05 4.6E-05 2.3E-05
Chromium (Cr) <1.0E-06 <1.0E-06 <1.0E-06 <1.0E-05 <1.0E-06 <1.0-E06
Manganese (Mn) 1.7E-04 8.7E-05 1.4E-04 7.0E-05 2.2E-04 1.1E-04
Nickel (Ni) 1.4E-05 7.0E-06 2.0E-05 l.OE-05 2.2E-06 l.OE-06
a. Units are in Ib/ton (Ibs. of pollutant/ton of dry wood burned) and g/kg (grams of pollutant/kg
of dry wood burned). Emission factors are based on data from References 15 and 18.
b. The data used to develop these emission factors showed a high degree of variability within the
source population. The use of these emission factors on a specific source may not be
appropriate.
TABLE 1.10-7. SUMMARY OF WOOD HEATER NET EFFICIENCIES51
Wood Heater Type
Wood Stoves,
Conventional
Non-Catalytic
Catalytic
Pellet Stovesb
Certified
Exempt
Masonry Heaters
All
Net Efficiency (%)
54
68
68
68
56
58
Reference
27
10, 13, 27
7,27
12
28
29
a. 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.
b. Certified = Certified pursuant to 1988 NSPS.
Exempt = Exempt from 1988 NSPS (i.e., ainfuel ratio >35:1).
10/92
External Combustion Sources
1.10-9
-------
References for Section 1.10
1. Standards Of Performance For New Stationary Sources: New Residential Wood Heaters. 53 FR
5573, February 26, 1988.
2. Weant, G. E., Emission Factor Documentation For AP-42 Section 1.10: Residential Wood Stoves,
EPA-450/4-89-007, U. S. Environmental Protection Agency, Research Triangle Park, NC, May
1989.
3. Gay, R., and J. Shah, Technical Support Document For Residential Wood Combustion, EPA-
450/4-85-012, U. S. Environmental Protection Agency, Research Triangle Park, NC, February
1986.
4. Rau, J. A., and J. J. Huntzicker, Composition And Size Distribution Of Residential Wood Smoke
Aerosols. Presented at the 21st Annual Meeting of the Air and Waste Management Association,
Pacific Northwest International Section, Portland, OR, November 1984.
5. Simons, C. A., et al., Whitehorse Efficient Woodheat Demonstration, The City of Whitehorse,
Whitehorse, Yukon, Canada, September 1987.
6. Simons, C. A., et al., Woodstove Emission Sampling Methods Comparability Analysis And In-situ
Evaluation Of New Technology Woodstoves. EPA-600/7-89-002, U. S. Environmental Protection
Agency, Cincinnati, OH, January 1989.
7. Bamett, S. G., Field Performance Of Advanced Technology Woodstoves In Glens Falls. N.Y.
1988-1989., Vol. 1, New York State Energy Research And Development Authority, Albany, NY,
October 1989.
8. Burnet, P. G., The Northeast Cooperative Woodstove Study, Volume 1, EPA-600/7-87-026a, U. S.
Environmental Protection Agency, Cincinnati, OH, November 1987.
9. Jaasma, D. R., 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.
10. Dembach, S., Woodstove Field Performance In Klamath Falls, OR. Wood Heating Alliance,
Washington, D. C., April 1990.
11. Simons, C. A., and S. K. Jones, Performance Evaluation Of The Best Existing Stove Technology
(BEST) Hybrid Woodstove And Catalytic Retrofit Device. Oregon Department Of Environmental
Quality, Portland, OR, July 1989.
12. Barnett, S. G., and R. B. Roholt, In-home Performance Of Certified Pellet Stoves In Medford And
Klamath Falls, OR, U. S. Department Of Energy Report No. PS407-02, July 1990.
13. Barnelt, S. G., In-Home Evaluation of Emission Characteristics of EPA-Certified High-Tech Non-
Catalytic Woodstoves in Klamath Falls, OR, 1990, prepared for the Canada Center for Mineral
and Energy Technology, Energy, Mines and Resources, Canada, DSS File No. 145Q, 23440-9-
9230, June 1, 1990.
1.10-10 EMISSION FACTORS 10/92
-------
References for Section 1.10 (continued)
14. McCrillis, R. C., and R. G. Merrill, Emission Control Effectiveness Of A Woodstove Catalyst
And Emission Measurement Methods Comparison. Presented at the 78th Annual Meeting of the
Air And Waste Management Association, Detroit, MI, 1985.
15 Leese, K. E., and S. M. Harkins, Effects Of Burn Rate. Wood Species. Moisture Content And
' Weight Of Wood Loaded On Woodstove Emissions, EPA 600/2-89-025, U. S. Environmental
Protection Agency, Cincinnati, OH, May 1989.
16. Allen, J. M., and W. M. Cooke, Control Of Emissions From Residential Wood Burning By
' Combustion' Modification, EPA-600/7-81-091, U. S. Environmental Protection Agency, Cincinnati,
OH, May 1981.
17 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.
18 Burnet, P. G., et al., Effects of Appliance Type and Operating Variables on Woodstove Emissions,
Vol. I.'Report and Appendices 6-C, EPA-600/2-90-001a, U.S. Environmental Protection Agency,
Research Triangle Park, NC, January 1990.
19. Cottone, L. E., and E. Mesner, Test Method Evaluations and Emissions Testing for Rating Wood
Stoves, EPA-600/2-86-100, U.S. Environmental Protection Agency, Research Triangle Park, NC,
October 1986.
20. Residential Wood Heater Test Report. Phase II Testing, Vol. 1, TVA, Division of Energy,
Construction and Rates, Chattanooga, TN, August 1983.
21. Truesdale, R. S. and J. G. Cleland, Residential Stove Emissions from Coal and Other Alternative
Fuels Combustion, in papers at the Specialty Conference on Residential Wood and Coal
Combustion, Louisville, KY, March 1982.
22. Barnett, S. G., In-Home Evaluation of Emissions From Masonry Fireplaces and Heaters, OMNI
Environmental Services, Inc., Beaverton, OR, September 1991.
23. Barnett, S. G., In-Home Evaluation of Emissions From a Grundofen Masonry Heater, OMNI
Environmental Services, Inc., Beaverton, OR, January 1992.
24. Barnett, S. G., In-Home Evaluation of Emissions From a Tulikivi KTU 2100 Masonry Heater,
OMNI Environmental Services, Inc., Beaverton, OR, March 1992.
25. Barnett, S. G., In-Home Evaluation of Emissions From a Roval Crown 2000 Masonry Heater,
OMNI Environmental Services, Inc., Beaverton, OR, March 1992.
26. Barnett, S. G., In-Home Evaluation of Emissions From a Biofire 4x3 Masonry Heater, OMNI
Environmental Services, Inc., Beaverton, OR, March 1992.
10/92 External Combustion Sources 1.10-11
-------
References for Section 1.10 (concluded)
27. Barnett, S. G. and R. D. Bighouse, In-Home Demonstrations of the Reduction of Woodstove
Emissions from the use of Densified Logs. Oregon Department of Energy and U.S. Environmental
Protection Agency, July 1992.
28. Barnett, S. G. 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.
29. Barnett, S. G., Summary Report of the In-Home Emissions and Efficiency Performance of Five
Commercially Available Masonry Heaters, the Masonry Heater Association, May 1992.
30. Guidance Document for Residential Wood Combustion Emission Control Measures. EPA-450/2-
89-015 Errata Sheet, Office of Air Quality Planning and Standards, U. S. Environmental
Protection Agency, Research Triangle Park, NC, 27711, June 1991.
1.10-12 EMISSION FACTORS 10/92
-------
1.11 WASTE OIL COMBUSTION
1.11.1 General1
Waste, or used oil can be burned in a variety of combustion systems including industrial
boilers; commercial/institutional boilers; space heaters; asphalt plants; cement and lime kilns; other
types of dryers and calciners; and steel production blast furnaces. Boilers and space heaters consume
the bulk of the waste oil burned. Space heaters are small combustion units [generally less than 0.1
GW (250,000 Btu/hr input)] that are common in automobile service stations and automotive repair
shops where supplies of waste crankcase oil are available.
Boilers designed to burn No. 6 (residual) fuel oils or one of the distillate fuel oils can be used
to burn waste oil, with or without modifications for optimizing combustion. As an alternative to boiler
modification, the properties of waste oil can be modified by blending it with fuel oil, to the extent
required to achieve a clean-burning fuel mixture.
1.11.2 Emissions and Controls
Waste oil includes used crankcase oils from automobiles and trucks, used industrial lubricating
oils (such as metal working oils), and other used industrial oils (such as heat transfer fluids). When
discarded, these oils become waste oils due to a breakdown of physical properties and to
contamination by the materials they come in contact with. The different types of waste oils may be
burned as mixtures or as single fuels where supplies allow; for example, some space heaters in
automotive service stations burn waste crankcase oils.
Contamination of the virgin oils with a variety of materials leads to an air pollution potential
when these oils are burned. Potential pollutants include particulate matter (PM), small particles below
10 micrometers in size (PM-10), toxic metals, organic compounds, carbon monoxide (CO), sulfur
oxides (SOY), nitrogen oxides (NOY), hydrogen chloride, and global warming gases (CO2, methane).
A. «
Ash levels in waste oils are normally much higher than ash levels in either distillate oils or
residual oils. Waste oils have substantially higher concentrations of most of the trace elements
reported relative to those concentrations found in virgin fuel oils. However, because of the shift to
unleaded gasoline, the concentration of lead in waste crankcase oils has continued to decrease in recent
years. Without air pollution controls, higher concentrations of ash and trace metals in the waste fuel
translate to higher emission levels of PM and trace metals than is the case for virgin fuel oils.
Low efficiency pretreatment steps, such as large particle removal with screens or coarse filters,
are common prefeed procedures at oil-fired boilers. Reductions in total PM emissions can be expected
from these techniques but little or no effects have been noticed on the levels of (PM-10) emissions.
Constituent chlorine in waste oils typically exceeds the concentration of chlorine in virgin
distillate and residual oils. High levels of halogenated solvents are often found in waste oil as a result
of inadvertent or deliberate additions of the contaminant solvents to the waste oils. Many efficient
combustors can destroy more than 99.99 percent of the chlorinated solvents present in the fuel.
However, given the wide array of combustor types which burn waste oils, the presence of these
compounds in the emission stream cannot be ruled out.
The flue gases from waste oil combustion often contain organic compounds other than
chlorinated solvents. At ppmw levels, several hazardous organic compounds have been found in waste
oils. Benzene, toluene, polychlorinated biphenyls (PCBs) and polychlorinated dibenzo-d-dioxins are a
9/92 External Combustion Sources 1.11-1
-------
few of the hazardous compounds that have been detected in waste oil samples. Additionally, these
hazardous compounds may be formed in the combustion process as products of incomplete
combustion.
Emission factors and emission factor ratings for waste oil combustion are shown in Tables
1.11-1 through 1.11-5. Emission factors have been determined for emissions from uncontrolled small
boilers and space heaters combusting waste oil. The use of both blended and unblended fuels is
included in the mix of combustion operations. Emission factors have also been developed for
emissions from a batch asphalt plant that was controlled for paniculate matter and speciated metals but
uncontrolled for other pollutants.
1.11-2
EMISSION FACTORS
9/92
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EMISSION FACTORS
9/92
-------
REFERENCES TO SECTION 1.11
1. Draft report. Emission Factor Documentation for AP-42 Section 1.11, Waste Oil Combustion,
Technical Support Division, Office of Air Quality Planning and Standards, U. S.
Environmental Protection Agency, Research Triangle Park, NC. September 1992.
2. Environmental Characterization of Disposal of Waste Oils in Small Combustors,
EPA-600/2-84-150, GCA Technology Division for Environmental Protection Agency,
Cincinnati, OH, September 1984.
3. Waste Oil Combustion at a Batch Asphalt Plant: Trial Burn Sampling and Analysis, Arthur D.
Little, Inc, Cambridge, MA, Presented at the 76th Annual Meeting of the Air Pollution Control
Association, June 19-24, 1983.
9/92 External Combustion Sources 1.11-7
-------
-------
2.2 AUTOMOBILE BODY INCINERATION
The information presented in this section has been reviewed but not updated since it was
originally prepared because no recent data were found and it is rarely practiced today. Auto bodies
are likely to be shredded or crushed and used as scrap metal in secondary metal production
operations, which are discussed in Chapter 7.
2.2.1 Process Description
Auto incinerators consist of a single primary combustion chamber in which one or several
partially stripped cars are burned. (Tires are removed.) Approximately 30 to 40 minutes is required
to burn two bodies simultaneously.2 As many as 50 cars per day can be burned in this batch-type
operation, depending on the capacity of the incinerator. Continuous operations in which cars are
placed on a conveyor belt and passed through a tunnel-type incinerator have capacities of more than
50 cars per 8-hour day.
2.2.2 Emissions and Controls*
Both the degree of combustion as determined by the incinerator design and the amount of
combustible material left on the car greatly affect emissions. Temperatures on the order of 1200°F
(650°C) are reached during auto body incineration.2 This relatively low combustion temperature is a
result of the large incinerator volume needed to contain the bodies as compared with the small
quantity of combustible material. The use of overfire air jets in the primary combustion chamber
increases combustion efficiency by providing air and increased turbulence.
In an attempt to reduce the various air pollutants produced by this method of burning, some
auto incinerators are equipped with emission control devices. Afterburners and low-voltage
electrostatic precipators have been used to reduce paniculate emissions; the former also reduces some
of the gaseous emissions.3>4 When afterburners are used to control emissions, the temperature in the
secondary combustion chamber should be at least 1500°F (815°C). Lower temperatures result in
higher emissions. Emission factors for auto body incinerators are presented in Table 2.2-1.
Particulate matter is likely to be mostly in the PM-10 range, but no data are available to support this
hypothesis. Although no data are available, emissions of HC1 are expected due to the increased use
of clorinated plastic materials in automobiles.
10/92 Solid Waste Disposal 2.2-1
-------
Table 2.2-1. EMISSION FACTORS FOR AUTO BODY INCINERATIONa
EMISSION FACTOR RATING: D
Pollutants
Particulates0
Carbon monoxide0
TOC (as CH4)C
Nitrogen oxides (NO^
Aldehydes (HCOH)d
Organic acids (acetic)^
Uncontrolled
Ib/car
2
2.5
0.5
0.1
0.2
0.21
kg/car
0.9
1.1
0.23
0.05
0.09
0.10
With Afterburner
Ib/car
1.5
Neg
Neg
0.02
0.06
0.07
kg/car
0.68
Neg
Neg
0.01
0.03
0.03
aBased on 250 Ib (113 kg) of combustible material on stripped car
body.
^References 2 and 4.
cBased on data for open burning and References 2 and 5.
^Reference 3.
References for Section 2.2
1. Air Pollutant Emission Factors Final Report. National Air Pollution Control Administration,
Durham, NC, Contract Number CPA-22-69-119, Resources Research Inc. Reston, VA,
April 1970.
2. E. R. Kaiser, and J. Tolcias, "Smokeless Burning of Automobile Bodies," Journal of the Air
Pollution Control Association. 12:64-73, February 1962.
3. F. M. Alpiser, "Air Pollution from Disposal of Junked Autos," Air Engineering. 10:18-22,
November 1968.
4. Private Communication with D. F. Walters, U.S. DHEW, PHS, Division of Air Pollution,
Cincinnati, Ohio. July 19, 1963.
5. R. W. Gerstle, and D. A. Kemnitz, "Atmospheric Emissions from Open Burning," Journal of
the Air Pollution Control Association. 17:324-327. May 1967.
2.2-2
EMISSION FACTORS
10/92
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2.3 CONICAL BURNERS
The information presented in this section has not been updated since it was originally prepared
because no recent data were found. The use of conical burners is much less prevalent now than in
the past and they are essentially obsolete.
2.3.1 Process Description^
Conical burners are generally truncated metal cones with screened top vents. The charge is
placed on a raised grate by either conveyor or bulldozer; however, the use of a conveyor results in
more efficient burning. No supplemental fuel is used, but combustion air is often supplemented by
underfire air blown into the chamber below the grate and by overfire air introduced through
peripheral openings in the shell.
2.3.2 Emissions and Controls
The quantities and types of pollutants released from conical burners are dependent on the
composition and moisture content of the charged material, control of combustion air, type of charging
system used, and the condition in which the incinerator is maintained. The most critical of these
factors seems to be the level of maintenance on the incinerators. It is not uncommon for conical
burners to have missing doors and numerous holes in the shell, resulting in excessive combustion air,
low temperatures, and, therefore, high emission rates of combustible pollutants.2
Paniculate control systems have been adapted to conical burners with some success. These
control systems include water curtains (wet caps) and water scrubbers. Emission factors for conical
burners are shown in Table 2.3-1.
10/92 Solid Waste Disposal 2.3-1
-------
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2.3-2
EMISSION FACTORS
10/92
-------
References for Section 2.3
1. Air Pollutant Emission Factors, Final Report, CPA-22-69-119, Resources Research Inc.
Reston, VA. Prepared for National Air Pollution Control Administration, Durham, NC
April 1970.
2. T. E. Kreichelt, Air Pollution Aspects of Teepee Burners, U. S. DHEW, PHS, Division of
Air Pollution. Cincinnati, Ohio. PHS Publication Number 999-AP-28. September 1966.
3. P. L. Magill and R. W. Benoliel, Air Pollution in Los Angeles County: Contribution of
Industrial Products. Ind. Eng. Chem. 44:1347-1352. June 1952.
4. Private Communication with Public Health Service, Bureau of Solid Waste Management,
Cincinnati, Ohio. October 31, 1969.
5. D. M. Anderson, J. Lieben, and V. H. Sussman, Pure Air for Pennsylvania, Pennsylvania
State Department of Health, Harrisburg PA, November 1961. p.98.
6. R. W. Boubel, et al.. Wood Waste Disposal and Utilization. Engineering Experiment
Station, Oregon State University, Corvallis, OR, Bulletin Number 39. June 1958. p.57.
7. A. B. Netzley, and J. E. Williamson. Multiple Chamber Incinerators for Burning Wood
Waste, In: Air Pollution Engineering Manual, Danielson, J. A. (ed.). U. S. DHEW, PHS,
National Center for Air Pollution Control. Cincinnati, Ohio. PHS Publication Number 999-
AP-40. 1967. p.436-445.
8. H. Droege, and G. Lee, The Use of Gas Sampling and Analysis for the Evaluation of Teepee
Burners, Bureau of Air Sanitation, California Department of Public Health, (Presented at the
7th Conference on Methods in Air Pollution Studies, Los Angeles, CA, January 1965.)
9. R. W. Boubel, Paniculate Emissions from Sawmill Waste Burners, Engineering Experiment
Station, Oregon State University, Corvallis, OR, Bulletin Number 42, August 1968, p.7,8.
10/92 Solid Waste Disposal 2.3-3
-------
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2.4 OPEN BURNING
2.4.1 General1
Open burning can be done in open drums or baskets, in fields and yards, and in large open
dumps or pits. Materials commonly disposed of in this manner include municipal waste, auto body
components, landscape refuse, agricultural field refuse, wood refuse, bulky industrial refuse, and
leaves.
Current regulations prohibit open burning of hazardous waste. One exception is for open
burning and detonation of explosives, particularly waste explosives that have the potential to detonate,
and bulk military propellants which cannot safely be disposed of through other modes of treatment.
The following Source Classification Codes (SCCs) pertain to open burning:
Government
50100201 General Refuse
50100202 Vegetation Only
Commercial/Institutional
50200201 Wood
50200202 Refuse
Industrial
50300201 Wood/Vegetation/Leaves
50300202 Refuse
50300203 Auto Body Components
50300204 Coal Refuse Piles
50300205 Rocket Propellant
2.4.2 Emissions1"22
Ground-level open burning emissions are affected by many variables, including wind, ambient
temperature, composition and moisture content of the debris burned, and compactness of the pile. In
general, the relatively low temperatures associated with open burning increase emissions of particulate
matter, carbon monoxide, and hydrocarbons and suppress emissions of nitrogen oxides. Sulfur oxide
emissions are a direct function of the sulfur content of the refuse.
2.4.2.1 Municipal Refuse
Emission factors for the open burning of municipal refuse are presented in Table 2.4-1.
2.4.2.2 Automobile Components
Emission factors for the open burning of automobile components including upholstery, belts,
hoses, and tires are presented in Table 2.4-1.
Emission factors for the burning of scrap tires only are presented in Tables 2.4-2 through
2.4-4. Although it is illegal in many states to dispose of tires using open burning, fires often occur at
10/92 Solid Waste Disposal 2.4-1
-------
Table 2.4-1
Emission Factors for Open Burning of Municipal Refuse
Emission Factor Rating: D
Source
Municipal Refuse^3
kg/Mg
Ib/ton
Automobile Components0
kg/Mg
Ib/ton
Particulate
8
16
50
100
Sulfur
Oxides
0.5
1.0
Neg.
Neg.
Carbon
Monoxid
e
42
85
62
125
voca
Methane
6.5
13
5
10
Nonmeth
ane
15
30
16
32
Nitrogen
Oxides
3
6
2
4
a Data indicate that VOC emissions are approximately 25% methane, 8% other saturates, 18%
olefins, 42% others (oxygenates, acetylene, aromatics, trace formaldehyde).
b References 2 and 7.
c Reference 2. Upholstery, belts, hoses, and tires burned together.
tire stockpiles and through illegal burning activities. Of the emission factors presented here are used
to estimate emissions from an accidental tire fire, it should be kept in mind that emissions from
burning tires are generally dependent on the burn rate of the tire. A greater potential for emissions
exists at lower burn rates, such as when a tire is smoldering, rather than burning out of control. In
addition, the emission factors presented here for tire "chunks" are probably more appropriate than for
"shredded" tire for estimating emissions from an accidental tire fire because there is likely to be more
air-space between the tires in an actual fire. As discussed in Reference 21, it is difficult to estimate
emissions from a large pile of tires based on these results, but emissions can be related to a mass burn
rate. To use the information presented here, it may be helpful to use the following estimates: tires
tested in Reference 21 weighed approximately 7 kilograms and one volume of one tire is
approximately 7 ft3 (15 pounds). Table 2.4-2 presents emission factors for paniculate metals. Table
2.4-3 presents emission factors for polycyclic aromatic hydrocarbons (PAH's), and Table 2.4-4
presents emissions for other volatile hydrocarbons. For more detailed information on this subject
consult the reference cited at the end of this chapter.
2.4.2.3 Agricultural Waste
Organic Agricultural Waste. Organic refuse burning consists of burning field crops, wood,
and leaves. Emissions from organic agricultural refuse burning are dependent mainly on the moisture
content of the refuse and, in the case of the field crops, on whether the refuse is burned in a headfire
or a backfire. Headfires are started at the upwind side of a field and allowed to progress in the
direction of the wind, whereas backfires are started at the downwind edge and forced to progress in a
direction opposing the wind.
Other variables such as fuel loading (how much refuse material is burned per unit of land
area) and how the refuse is arranged (in piles, rows, or spread out) are also important in certain
instances. Emission factors for open agricultural burning are presented in Table 2.4-5 as a function
2.4-2
EMISSION FACTORS
10/92
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Solid Waste Disposal
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EMISSION FACTORS
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EMISSION FACTORS
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of refuse type and also, in certain instances, as a function of burning techniques and/or moisture
content when these variables are known to significantly affect emissions. Table 2.4-5 also presents
typical fuel loading values associated with each type of refuse. These values can be used, along with
the corresponding emission factors, to estimate emissions from certain categories of agricultural
burning when the specific fuel loadings for a given area are not known.
Emissions from leaf burning are dependent upon the moisture content, density, and ignition
location of the leaf piles. Increasing the moisture content of the leaves generally increases the amount
of carbon monoxide, hydrocarbon, and particulate emissions. Carbon monoxide emissions decreases
if moisture content is high but increases if moisture content is low. Increasing the density of the piles
increases the amount of hydrocarbon and particulate emissions, but has a variable effect on carbon
monoxide emissions.
The highest emissions from open burning of leaves occur when the base of the leaf pile is
ignited. The lowest emissions generally arise from igniting a single spot on the top of the pile.
Particulate, hydrocarbon, and carbon monoxide emissions from window ignition (piling the leaves
into a long row and igniting one end, allowing it to burn toward the other end) are intermediate
between top and bottom ignition. Emission factors for leaf burning are presented in Table 2.4-6. For
more detailed information on this subject, the reader should consult the reference cited at the end of
this section.
Agricultural Plastic Film. Agricultural plastic film that has been used for ground moisture
and weed control. Large quantities of plastic film are commonly disposed of when field crops are
burned. The plastic film may also be gathered into large piles and burned separately or burned in an
air curtain. Emissions from burning agricultural plastic are dependent on whether the film is new or
has been exposed to vegetation and possibly pesticides. Table 2.4-7 presents emission factors for
organic compounds emitted from burning new and used plastic film in piles or in piles where air has
been forced through them to simulate combustion in an air curtain. Table 2.4-8 presents emission
factors for PAH's emitted from open burning of inorganic plastic film.
2.4-14
EMISSION FACTORS
10/92
-------
Table 2.4-7
Emission Factors for Organic Compounds From Burning Plastic Film3
Emission Factor Rating: C
Pollutant
Benzene
Toluene
Ethyl benzene
1-Hexene
Units
(mg/kg plastic)
(lb/1000 tons plastic)
(mg/kg plastic)
(lb/1000 tons plastic)
(mg/kg plastic)
(lb/1000 tons plastic)
(mg/kg plastic)
(lb/1000 tons plastic)
Condition of plastic
Unused Plastic
Pileb
0.0478
0.0955
0.0046
0.0092
0.0006
0.0011
0.0010
0.0020
Forced airc
0.0288
0.0575
0.0081
0.0161
0.0029
0.0058
0.0148
0.0296
Used Plastic
Pileb
0.0123
0.0247
0.0033
0.0066
0.0012
0.0025
0.0043
0.0086
Forced airc
0.0244
0.0488
0.0124
0.0248
0.0056
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0.0220
0.0440
aReference 22
^Emission factors are for plastic gathered in a pile and burned.
cEmission factors are for plastic burned in a pile with a forced
air current.
10/92
Solid Waste Disposal
2.4-15
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References for Section 2.4
!• Air Pollutant Emission Factors. Final Report. National Air Pollution Control Administration,
Durham, NC Contract Number CPA A-22-69-119, Resources Research, Inc., Reston VA
April 1970.
2. R. W. Gerstle, and D. A. Kemnitz, "Atmospheric Emissions from Open Burning," Journal of
Air Pollution Control Association. 12: 324-327, May 1967.
3. J. O. Burkle, J. A. Dorsey, and B. T. Riley. "The Effects of Operating Variables and Refuse
Types on Emissions from a Pilot-Scale Trench Incinerator", In: Proceedings of 1968
Incinerator Conference. American Society of Mechanical Engineers. New York p 34-41
May 1968
4. M. I. Weisburd, and S. S. Griswold (eds.), Air Pollution Control Field Operations Guide:
A Guide for Inspection and Control. PHS Publication No. 937, U.S. DREW, PHS, Division
of Air Pollution, Washington, D.C., 1962.
5. Unpublished data on estimated major air contaminant emissions, State of New York
Department of Health, Albany, NY, April 1, 1968.
6. E. F. Darley, etal., "Contribution of Burning of Agricultural Wastes to Photochemical Air
Pollution," Journal of Air Pollution Control Association. 16: 685-690, December 1966.
7. M. Feldstein, etal.. "The Contribution of the Open Burning of Land Clearing Debris to Air
Pollution," Journal of Air Pollution Control Association. 13: 542-545, November 1963.
8. R. W. Boubel, E. F. Darley, and E. A. Schuck, "Emissions from Burning Grass Stubble and
Straw," Journal of Air Pollution Control Association. 19: 497-500, July 1969.
9. Waste Problems of Agriculture and Forestry, Environmental Science and Technology 2-498
July 1968.
10. G. Yamate, etal., "An Inventory of Emissions from Forest Wildfires, Forest Managed Burns,
and Agricultural Burns and Development of Emission Factors for Estimating Atmospheric
Emissions from Forest Fires," Presented at 68th Annual Meeting Air Pollution Control
Association, Boston, MA, June 1975.
11. E. F. Darley, Air Pollution Emissions from Burning Sugar Cane and Pineapple from Hawaii.
University of California, Riverside, Calif. Prepared for Environmental Protection Agency,
Research Triangle Park, N.C. as amendment of Research Grant No. R800711. August 1974.
12. E. F. Darley, etal., Air Pollution from Forest and Agricultural Burning. California Air
Resources Board Project 2-Q17-1. California Air Resources Board Project No. 2-017-1,
University of California, Davis, CA, April 1974.
13. E. F. Darley, Progress Report on Emissions from Agricultural Burning, California Air
Resources Board Project 4-011, University of California, Riverside, CA, Private
communication with permission of Air Resources Board, June 1975.
2.4-18 EMISSION FACTORS
10/92
-------
14. Private communication on estimated waste production from agricultural burning activities.
California Air Resources Board, Sacramento, Calif. September 1975.
15. L. Fritschen, et al.. Flash Fire Atmospheric Pollution. U.S. Department of Agriculture,
Washington, D.C. Service Research Paper PNW-97. 1970.
16. D. W. Sandberg, S. G. Pickford, and E. F. Darley, Emissions from Slash Burning and the
Influence of Flame Retardant Chemicals. Journal of Air Pollution Control Association.
25:278, 1975.
17. L. G. Wayne, and M. L. McQueary, Calculation of Emission Factors for Agricultural
Burning Activities. EPA-450-3-75-087, Environmental Protection Agency, Research Triangle
Park, N. C., Prepared under Contract No. 68-02-1004, Task Order No.4. by Pacific
Environmental Services, Inc., Santa Monica, CA, November 1975.
18. E. F. Darley, Emission Factor Development for Leaf Burning. University of California,
Riverside, CA, Prepared for Environmental Protection Agency, Research Triangle Park, NC,
under Purchase Order No. 5-02-6876-1. September 1976.
19. E. F. Darley, Evaluation of the Impact of Leaf Burning - Phase I: Emission Factors for
Illinois Leaves, University of California, Riverside, CA, Prepared for State of Illinois,
Institute for Environmental Quality, August 1975.
20. J. H. Southerland, and A. McBath. Emission Factors and Field Loading for Sugar Cane
Burning, MDAD, OAQPS, U.S. Environmental Protection Agency, Research Triangle Park,
NC. January 1978.
21. Characterization of Emissions from the Simulated Open Burning of Scrap Tires.
EPA-600/2-89-054, U. S. Environmental Protection Agency, Research Triangle Park,
October 1989.
22. W. P. Linak, et.al.. "Chemical and Biological Characterization of Products of Incomplete
Combustion from the Simulated Field Burning of Agricultural Plastic," Journal of Air
Pollution Control Association. Vol. 39, No. 6, EPA/600/J-89/025, U. S. Environmental
Protection Agency Control Technology Center, June 1989.
10/92 Solid Waste Disposal 2.4-19
-------
-------
3.1 STATIONARY GAS TURBINES FOR ELECTRICITY GENERATION
3.1.1 General
Stationary gas turbines are applied in electric power generators, in gas pipeline pump and
compressor drives, and in various process industries. Gas turbines (greater than 3 MW(e)) are used in
electrical generation for continuous, peaking, or standby power. The primary fuels used are natural gas
and distillate (No. 2) fuel oil, although residual fuel oil is used in a few applications.
3.1.2 Emissions
Emission control technologies for gas turbines have advanced to a point where all new and most
existing units are complying with various levels of specified emission limits. For these sources, the
emission factors become an operational specification rather than a parameter to be quantified by testing.
This section treats uncontrolled (i.e., baseline) emissions and controlled emissions with specific control
technologies.
The emission factors presented are for simple cycle gas turbines. These factors also apply to
cogeneration/combined cycle gas turbines. In general, if the heat recovery steam generator (HRSG) is not
supplementary fired, the simple cycle input specific emission factors (Ibm/MMBtu) will apply to
cogeneration/combined cycle systems. The output specific emissions (gAip-hr) will decrease according
to the ratio of simple cycle to combined cycle power output. If the HRSG is supplementary fired, the
emissions and fuel usage must be considered to estimate stack emissions. Nitrogen Oxide (NOX) emissions
from regenerative cycle turbines (which account for only a small percentage of turbines in use) are greater
than emissions from simple cycle turbines because of the increased combustion air temperature entering
the turbine. The carbon monoxide (CO) and hydrocarbon (HC) emissions may be lower with the
regenerative system for a comparable design. More power is produced from the same energy input, so
the input specific emissions factor will be affected by changes in emissions, while output specific
emissions will reflect the increased power output.
Water/steam injection is the most prevalent NOx control for cogeneration/combined cycle gas
turbines. The water or steam is injected with the air and fuel into the turbine combustion can in order to
lower the peak temperatures which, in turn, decreases the thermal NOX produced. The lower average
temperature within the combustor can may produce higher levels of CO and HC as a result of incomplete
combustion.
Selective catalytic reduction (SCR) is a post-combustion control which selectively reduces NOX
by reaction of ammonia and NO on a catalytic surface to form N2 and H2O. Although SCR systems can
be used alone, all existing applications of SCR have been used in conjunction with water/steam injection
controls. For optimum SCR operation, the flue gas must be within a temperature range of 600-800°F with
the precise limits dependant on the catalyst. Some SCR systems also utilize a CO catalyst to give
simultaneous catalytic CO/NOX control.
Advanced combustor can designs are currently being phased into production turbines. These dry
techniques decrease turbine emissions by modifying the combustion mixing, air staging, and flame
stabilization to allow operation at a much leaner air/fuel ratio relative to normal operation. Operating at
leaner conditions will lower peak temperatures within the primary flame zone of the combustor. The
lower temperatures may also increase CO and HC emissions.
10/92 Stationary Internal Combustion Sources 3.1-1
-------
With the proliferation and advancement of NOX control technologies for gas turbines during the
past 15 years, the emission factors for the installed gas turbine population are quite different than
uncontrolled turbines. However, uncontrolled turbine emissions have not changed significantly. Therefore
a careful review of specific turbine details should be performed before applying uncontrolled emission
factors. Today most gas turbines are controlled to meet local, state, and/or federal regulations.
The average gaseous emission factors for uncontrolled gas turbines (firing natural gas and fuel oil)
are presented in Tables 3.1-1 and 3.1-2. There is some variation in emissions over the population of large
uncontrolled gas turbines because of the diversity of engine designs and models. Tables 3.1-3 and 3.1-4
present emission factors for gas turbines controlled for NOX using water injection, steam injection or SCR.
Tables 3.1-5 and 3.1-6 present emission factors for large distillate oil- fired turbines controlled for NOX
using water injection.
Gas turbines firing distillate or residual oil may emit trace metals carried over from the metals
content of the fuel. If the fuel analysis is known, the metals content of the fuel should be used for flue
gas emission factors assuming all metals pass through the turbine. If the fuel analysis is not known, Table
3.1-7 provides order of magnitude levels for turbines fired with distillate oil.
3.1-2
EMISSION FACTORS
10/92
-------
TABLE 3.1-1. (ENGLISH UNITS)
EMISSION FACTORS FOR LARGE UNCONTROLLED GAS TURBINES1-8
Pollutant
NOX
CO
CO2C
TOC (as methane)
SOx (as SOa)
PM (solids)
PM (condensables)
PM Sizing %
< .05 microns
< .10 microns
< .15 microns
< .20 microns
< .25 microns
< 1 micron
Emission
Factor
Rating3
C
D
B
D
B
E
E
D
D
D
D
D
D
Natural Gas (SCC-2-01-002-01)
[grams/hr-hp]b [Ib/MMBtu]
(power output) (fuel input)
1.6 .44
.39 .11
407 112
.087 .024
d d
.070 .0193
.082 .0226
15%
40%
63%
78%
89%
100%
Fuel Oil (i.e. Distillate)
(SCC-2-01-001-01)
[grams/hp-hr]b [Ib/MMBtu]
(power output) (fuel input)
2.54 .698
.174 .048
596 164
.062 .017
d d
.138 .038
.084 .023
16%
48%
72%
85%
93%
100%
a.
b.
c.
d.
"D" and "E" rated emission factors are due to limited data and/or a lack of documentation of test
results. "D" and "E" rated emission factors may not be suitable for specific facilities or populations
and should be used with care.
Calculated from Ib/MMBtu assuming an average heat rate of 8,000 Btu/hp-hr (x 3.632).
Based on 100 percent conversion of the fuel carbon to CO2. CO2[lb/MMBtu] = 3.67*C/E, where
C = carbon content of fuel by weight, .7, and E = energy content of fuel, .0023 MMBtu/lb.
The uncontrolled CO2 emission factors are also applicable to controlled gas turbines.
All sulfur in the fuel is converted to SO2.
10/92
Stationary Internal Combustion Sources
3.1-3
-------
TABLE 3.1-2. (METRIC UNITS)
EMISSION FACTORS FOR LARGE UNCONTROLLED GAS TURBINES1'8
Uncontrolled
Emission Factors
NO,
CO
CO2C
TOC (as methane)
SOx (as SOz)
PM (solids)
PM (condensables)
PM Sizing %
< .05 microns
< .10 microns
< .15 microns
< .20 microns
< .25 microns
< 1 micron
Emission
factor
Rating3
C
D
B
D
B
E
E
D
D
D
D
D
D
Natural Gas (SCC-2-01-002-01)
[grams/kW-hrb [ng/J]
(power output) (fuel input)
2.15 190
.52 46
546 48160
.117 10.32
d d
.094 8.30
.11 9.72
15%
40%
63%
78%
89%
100%
Fuel Oil (i.e. Distillate)
(SCC-2-01-00-01)
[grams/kW-hr]b [ng/J]
(power output) (fuel input)
3.41 300
.233 20.6
799 70520
.083 7.31
d d
.185 16.3
.113 9.89
16%
48%
72%
85%
93%
100%
a. "D" and "E" rated emission factors are due to limited data and/or a lack of documentation of test
results. "D" and "E" rated emission factors may not be suitable for specific facilities or populations
and should be used with care.
b. Calculated from ng/J assuming an average heat rate of 11,318 KJ/KW-hr.
c. Based on 100 percent conversion of the fuel carbon to CO2. CO2[lb/MMBtu] = 3.67*C/E, where
C = ratio of carbon in the fuel by weight, and E = energy content of fuel, MMBtu/lb.
The uncontrolled CO2 emission factors are also applicable to controlled gas turbines.
d. All sulfur in the fuel is assumed to be converted to SO2.
3.1-4
EMISSION FACTORS
10/92
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TABLE 3.1-3. (ENGLISH UNITS)
EMISSION FACTORS FOR LARGE GAS-FIRED CONTROLLED GAS TURBINES3'10'15
(Emission Factor Rating: C)a
Controlled
Emission Factors
Fuel: Natural Gas
Water Injection
(.8 water/fuel ratio)
[grams/hr-hp]
(power
output)
NOX .50
CO .94
TOG (as methane)
NH3
NMHC
Formaldehyde
[Ib/MMBtu]
(fuel
input)
Steam Injection
(1.2 water/fuel ratio)
[grams/hr-hp]
(power
output)
.14 .44
.28 .53
[Ib/MMBtu]
(fuel
input)
.12
.16
Selective
Catalytic
Reduction (with
water injection)
[Ib/MMBtu]
(fuel
input)
.03"
.0084
.014
.0065
.0032
.0027
a. All data are averages of a limited number of tests and may not be typical of those reductions which
can be achieved at a specific location.
b. Average of 78 percent reduction of NOX through the SCR catalyst.
10/92
Stationary Internal Combustion Sources
3.1-5
-------
TABLE 3.1-4. (METRIC UNITS)
EMISSION FACTORS FOR LARGE GAS-FIRED CONTROLLED GAS TURBINES3-10'15
(Emission Factor Rating: C)
Controlled
Emission Factors
Fuel: Natural Gas
Water Injection
(.8 water/fuel ratio)
[grams/kW-hr] [ng/J]
(power output) (fuel input)
Steam Injection
(1.2 water/fuel ratio)
[grams/kW-hr] [ng/J]
(power output) (fuel input)
NOX .66 61 .59 52
CO 1.3 120 .71 69
TOC (as methane)
NH3
NMHC
Formaldehyde
a. All data are averages of a limited number of tests and may not be typical
can be achieved at a specific location.
b. Average of 78 percent reduction of NOX through the SCR catalyst.
Selective
Catalytic
Reduction (with
water injection)
[ng/J]
(fuel input)
3.78"
3.61
6.02
2.80
1.38
1.16
of those reductions which
3.1-6
EMISSION FACTORS
10/92
-------
TABLE 3.1-5. (ENGLISH UNITS) EMISSION FACTORS FOR LARGE
DISTILLATE OIL-FIRED CONTROLLED GAS TURBINES16
Pollutant
NOX
CO
TOC (as methane)
SOx
PM
a. Calculated
c. All sulfur
Emission Factor
Rating
E
E
E
B
E
Water Injection
(.8 water/fuel ratio)
[grams/hr-hp]a
(power output)
1.05
.067
.017
b
.135
[Ib/MMBtu]
(fuel input)
.290
.0192
.0048
b
.0372
from fuel input assuming an average heat rate of 8,000 Btu/hp-hr (x 3.632).
in the fuel is assumed to be converted to SOX.
TABLE 3.1-6. (METRIC UNITS) EMISSION FACTORS FOR LARGE
DISTILLATE OIL-FIRED CONTROLLED GAS TURBINES16
Pollutant
NOX
CO
TOC (as methane)
soxb
PM
a. Calculated from
b. All sulfur in the
Emission Factor
Rating
E
E
E
B
E
Water Injection
(.8 water/fuel ratio)
[grams/kW-hr]a
(power output)
1.41
.090
.023
b
.181
fuel input assuming an average heat rate of
fuel is assumed to be converted to SOX.
[ng/J]
(fuel input)
125
8.26
2.06
b
16.00
8,000 Btu/hp-hr (x 3.632).
10/92
Stationary Internal Combustion Sources
3.1-7
-------
TABLE 3.1-7. TRACE ELEMENT EMISSION FACTORS FOR DISTILLATE OIL-FIRED GAS TURBINES1
(Emission Factor Rating: E)a
Trace Element
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Bromine
Cadmium
Calcium
Chromium
Cobalt
Cooper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silicon
Sodium
Tin
Vanadium
Zinc
pg/J
64
9.4
2.1
8.4
.14
28
1.8
1.8
330
20
3.9
578
256
25
100
145
.39
3.6
526
127
185
2.3
575
590
35
1.9
294
Ib/MMBtu
1.5 E-04
2.2 E-05
4.9 E-06
2.0 E-05
3.3 E-07
6.5 E-05
4.2 E-06
4.2 E-06
7.7 E-04
4.7 E-05
9.1 E-06
1.3 E-03
6.0 E-04
5.8 E-05
2.3 E-04
3.4 E-04
9.1 E-07
8.4 E-06
1.2 E-03
3.0 E-04
4.3 E-04
5.3 E-06
1.3 E-03
1.4 E-03
8.1 E-05
4.4 E-06
6.8 E-04
a. Emission factor ratings of "E"
and may not be representative
indicate that the data are from a limited data set
of a specific source or population of sources.
3.1-8
EMISSION FACTORS
10/92
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REFERENCES FOR SECTION 3.1
1. Shih, C.C., J.W. Hamersma, and D.G. Ackerman, R.G. Beimer, M.L. Kraft, and M.M.
Yamada, Emissions Assessment of Conventional Stationary Combustion Systems; Vol. II
Internal Combustion Sources. Industrial Environmental Research Laboratory,
EPA-600/7-79-029C, U.S. Environmental Protection Agency, Research Triangle Park, NC,
February 1979.
2. Final Report - Gas Turbine Emission Measurement Program, prepared by General Applied
Science Laboratories for Empire State Electric Energy Research Corp., August 1974, GASL
TR 787.
3. Malte, P.C, S., Bernstein, F. Bahlmann, and J. Doelman, NQV Exhaust Emissions for Gas-Fired
Turbine Engines. ASME 90-GT-392, June 1990.
4. Standards Support and Environmental Impact Statement; Volume 1: Proposed Standards of
Performance for Stationary Gas Turbines. EPA-450/2-77-017a, September 1977.
5. Hare, C.T. and K.J. Springer, Exhaust Emissions from Uncontrolled Vehicles and Related
Equipment using Internal Combustion Engines: Part - 6 Gas Turbines, Electric Utility Power
Plant, SWRI for EPA report APTD-1495, U.S. Environmental Protection Agency, Research
Triangle Park, NC, NTIS PB-235751.
6. Lieferstein, M., Summary of Emissions from Consolidated Edison Gas Turbine, prepared by
the Department of Air Resources, City of New York, November 5, 1975.
7. Hurley, J.F. and S. Hersh, Effect of Smoke and Corrosion Suppressant Additives on Particulate
and Gaseous Emissions from Utility Gas Turbine: prepared by KVB Inc. for Electric Power
Research Institute, EPRI FP-398, March 1977.
8. Crawford, A.R., E.H. Mannym M.W. Gregory and W. Bartok, The Effect of Combustion
Modification on Pollutants and Equipment Performance of Power Generation Equipment," in
Proceedings of the Stationary Source Combustion Symposium Vol. Ill - Field Testing and
Surveys, U.S. EPA-600/2-76-152c, NTIS PB-257 146, June 1976.
9. Carl, D.E., E.S. Obidinski, and C.A. Jersey, Exhaust Emissions from a 25-MW Gas Turbine
Firing Heavy and Light Distillate Fuel Oils and Natural Gas. Paper presented at the Gas
Turbine Conference and Products Show, Houston, Texas, March 2-6, 1975.
10. Shareef, G.S. and D.K. Stone, Evaluation of SCR NOV Controls for Small Natural Gas-Fueled
Prime Movers - Phase I, prepared by Radian Corp. (DCN No.: 90-209-028-11) for the Gas
Research Institute, GRI-90/0138, July 1990.
11. Pease. R.R.. SCAQMD Engineering Division Report - Status Report on SCR for Gas Turbines
South Coast Air Quality Management District, July 1984.
10/92 Stationary Internal Combustion Sources 3.1-9
-------
REFERENCES FOR SECTION 3.1 (concluded)
12. CEMS Certification and Compliance Testing at Chevron USA, Inc.'s Gaviota Gas Plant.
Report PS-89-1837/Project G569-89, Chevron USA, Inc., Goleta, CA, 93117, June 21, 1989.
13. Emission Testing at the Bonneville Pacific Cogeneration Plant. Report PS-92-2702/Project
7141-92, Bonneville Pacific Corporation, Santa Maria, CA 95434, March 1992.
14. Compliance test report on a production gas-fired 1C engine, ESA, 19770-462, Proctor and
Gamble, Sacramento, CA, December 1986.
15. Compliance test report on a cogeneration facility, CR 75600-2160, Proctor and Gamble,
Sacramento, CA, May, 1990.
16. Larkin, R. and E.B. Higginbotham, Combustion Modification Controls For Stationary Gas
Turbines Vol. II. Utility Unit Field Test. EPA 600/7-81-122, U.S. Environmental Protection
Agency, Research Triangle Park, July 1981.
3.1-10
EMISSION FACTORS
10/92
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3.2 HEAVY DUTY NATURAL GAS FIRED PIPELINE COMPRESSOR ENGINES
3.2.1 General
Engines in the natural gas industry are used primarily to power compressors used for pipeline
transportation, field gathering (collecting gas from wells), underground storage, and gas processing plant
applications, i.e. prime movers. Pipeline engines are concentrated in the major gas producing states (such
as those along the Gulf Coast) and along the major gas pipelines. Gas turbines emit considerably smaller
amounts of pollutants than do reciprocating engines; however, reciprocating engines are generally more
efficient in their use of fuel.
Reciprocating engines are separated into three design classes: 2-stroke lean burn, 4-stroke lean
burn and 4-stroke rich burn. Each of these have design differences which affect both baseline emissions
as well as the potential for emissions control. Two-stroke engines complete the power cycle in a single
engine revolution compared to two revolutions for 4-stroke engines. With the two-stroke engine, the
fuel/air charge is injected with the piston near the bottom of the power stroke. The valves are all covered
or closed and the piston moves to the top of the cylinder compressing the charge. Following ignition and
combustion, the power stroke starts with he downward movement of the piston. Exhaust ports or valves
are then uncovered to remove the combustion products, and a new fuel/air charge is ingested. Two stroke
engines may be turbocharged using an exhaust powered turbine to pressurize the charge for injection into
the cylinder. Non-turbocharged engines may be either blower scavenged or piston scavenged to improve
removal of combustion products.
Four stroke engines use a separate engine revolution for the intake/compression stroke and the
power/exhaust stroke. These engines may be either naturally aspirated, using the suction from the piston
to entrain the air charge, or turbocharged, using a turbine to pressurize the charge. Turbocharged units
produce a higher power output for a given engine displacement, whereas naturally aspirated units have
lower initial cost and maintenance. Rich burn engines operate near the fuel-air stoichiometric limit with
exhaust excess oxygen levels less than 4 percent. Lean burn engines may operate up to the lean flame
extinction limit, with exhaust oxygen levels of 12 percent or greater. Pipeline population statistics show
a nearly equal installed capacity of turbines and reciprocating engines. For reciprocating engines, two
stroke designs contribute approximately two-thirds of installed capacity.
3.2.2 Emissions and Controls
The primary pollutant of concern is NOX, which readily forms in the high temperature, pressure,
and excess air environment found in natural gas fired compressor engines. Lesser amounts of carbon
monoxide and hydrocarbons are emitted, although for each unit of natural gas burned, compressor engines
(particularly reciprocating engines) emit significantly more of these pollutants than do external combustion
boilers. Sulfur oxides emissions are proportional to the sulfur content of the fuel and will usually be quite
low because of the negligible sulfur content of most pipeline gas. This section will also discuss the major
variables affecting NOX emissions and the various control technologies that will reduce uncontrolled NOX
emissions.
The major variables affecting NOX emissions from compressor engines include the air fuel ratio,
engine load (defined as the ratio of the operating horsepower to the rated horsepower), intake (manifold)
air temperature and absolute humidity. In general, NOX emissions increase with increasing load and intake
air temperature and decrease with increasing absolute humidity and air fuel ratio, (the latter already being,
10/92 Stationary Internal Combustion Sources 3.2-1
-------
in most compressor engines, on the "lean" side of that air fuel ratio at which maximum NOX formation
occurs). Quantitative estimates of the effects of these variables are presented in Reference 10.
Because NOX is the primary pollutant of significance emitted from pipeline compressor engines,
control measures to date have been directed mainly at limiting NOX emissions. Reference 11 summarizes
control techniques and emission reduction efficiencies. For gas turbines, the early control applications
used water or steam injection. New applications of dry low NOX combustor can designs and selective
catalytic reduction are appearing. Water injection has achieved reductions of 70 to 80 percent with utility
gas turbines. Efficiency penalties of 2 to 3 percent are typical due to the added heat load of the water.
Turbine power outputs typically increase, however. Steam injection may also be used, but the resulting
NOX reductions may not be as great as with water injection, and it has the added disadvantage that a
supply of steam must be readily available. Water injection has not been applied to pipeline compressor
engines because of the lack of water availability.
The efficiency penalty and operational impacts associated with water injection have led
manufacturers to develop dry low NOX combustor can designs based on lean burn and/or staging to
suppress NOX formation. These are entering the market in the early 1990's. Stringent gas turbine NOX
limits have been achieved in California in the late 1980's with selective catalytic reduction. This is an
ammonia based post-combustion technology which can achieve in excess of 80 percent NOX reductions.
Water or steam injection is frequently used in combination with SCR to minimize ammonia costs.
For reciprocating engines, both combustion controls and post-combustion catalytic reduction have
been developed. Controlled rich bum engines have mostly been equipped with non-selective catalytic
reduction which uses unreacted hydrocarbons and CO to reduce NOX by 80 to 90 percent. Some rich-bum
engines can be equipped with prestratified charge which reduces the peak flame temperature in the NOX
forming regions. Lean burn engines have mostly met NOX reduction requirements with lean combustion
controls using torch ignition or chamber redesign to enhance flame stability. NOX reductions of 70 to 80
percent are typical for numerous engines with retrofit or new unit controls. Lean burn engines may also
be controlled with SCR, but the operational problems associated with engine control under low NOX
operation have been a deterrent.
Emission factors for natural gas fired pipeline compressor engines are presented in Tables 3.2-1
and 3.2-2 for baseline operation and in 3.2-4 through 3.2-7 for controlled operation. The factors for
controlled operation are taken from a single source test. Table 3.2-3 lists non-criteria (organic) emission
factors.
3.2-2 EMISSION FACTORS 10/92
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10/92
-------
TABLE 3.2-3. (ENGLISH AND METRIC UNITS) NON-CRITERIA EMISSION FACTORS
FOR UNCONTROLLED NATURAL GAS PRIME MOVERS3'5
(Emission Factor Rating: E)a
Pollutant
2-Cyc Lean
[grams/kw-hr]
[ng/J]
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Benzene 2.2E-3 0.17
Toluene 2.2E-3 0.17
Ethylbenzene 1.1E-3 0.086
Xylenes 3.3E-3 0.26
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10/92 Stationary Internal Combustion Sources 3.2-5
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References for Section 3.2
1. Engines, Turbines, and Compressors Directory, American Gas Association, Catalog #XF0488.
2. Martin, N.L. and R.H. Thring, Computer Database of Emissions Data for Stationary Reciprocating
Natural Gas Engines and Gas Turbines in use by the Gas Pipeline Transmission Industry Users
Manual (Electronic Database Included), prepared by South West Research Institute for the Gas
Research Institute, GRI-89/0041.
3. Air Pollution Source Testing for California AB2588 on an Oil Platform Operated by Chevron
USA, Inc. Platform Hope, California, Chevron USA, Inc., Ventura, CA, August 29, 1990.
4. Air Pollution Source Testing for California AB2588 of Engines at the Chevron USA, Inc.
Carpinteria Facility, Chevron USA, Inc., Ventura, CA, August 30, 1990.
5. Pooled Source Emission Test Report: Gas Fired 1C Engines in Santa Barbara County, ARCO,
Bakersfield, CA, July, 1990.
6. Castaldini, C, Environmental Assessment of N(X Control on a Spark-Ignited Large Bore
Reciprocating Internal Combustion Engine, U.S. Environmental Protection Agency, Research
Triangle Park, NC, April 1984.
7. Castaldini, C. and L.R. Waterland, Environmental Assessment of a Reciprocating Engine
Retrofitted with Nonselective Catalytic Reduction, EPA-600/7-84-073B, U.S. Environmental
Protection Agency, Research Triangle Park, NC, June 1984.
8. Castaldini, C. and L.R. Waterland, Environmental Assessment of a Reciprocating Engine
Retrofitted with Selective Catalytic Reduction, EPA Contract No. 68-02-3188, U.S. Environmental
Protection Agency, Research Triangle Park, NC, December 1984.
9. Fanick, R.E., H.E. Dietzmann, and C.M. Urban, Emissions Data for Stationary Reciprocating
Engines and Gas Turbines in Use by the Gas Pipeline Transmission Industry -Phase I&II, prepared
by SouthWest Research Institute for the Pipeline Research Committee of the American Gas
Association, April 1988, Project PR-15-613.
10. Standards Support and Environmental Impact Statement, Volume I: Stationary Internal
Combustion Engines, EPA-450/2-78-125a, U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Research Triangle Park, NC, July 1979.
11. Castaldini, C., NCX Reduction Technologies for Natural Gas Industry Prime Movers, prepared by
Acurex Corp. for the Gas Research Institute, GRI-90/0215, August 1990.
10/92 Stationary Internal Combustion Sources 3.2-9
-------
-------
3.3 GASOLINE AND DIESEL INDUSTRIAL ENGINES
3.3.1 General
The engine category addressed by this section covers a wide variety of industrial applications
of both gasoline and diesel internal combustion engines such as, aerial lifts, fork lifts, mobile
refrigeration units, generators, pumps, industrial sweepers/scrubbers, material handling equipment (such
as conveyors), and portable well-drilling equipment. The rated power of these engines covers a rather
substantial range; up to 186 kW (250 hp) for gasoline engines and up to 447 kW (600 hp) for diesel
engines. (Diesel engines greater than 600 hp are covered in Section 3.4: Large Stationary Diesel and
All Stationary Dual Fuel Engines). Understandably, substantial differences in engine duty cycles exist.
It was necessary, therefore, to make reasonable assumptions concerning usage in order to formulate
some of the emission factors.
3.3.2 Process Description
All reciprocating internal combustion (1C) engines operate by the same basic process. A
combustible mixture is first compressed in a small volume between the head of a piston and its
surrounding cylinder. The mixture is then ignited, and the resulting high pressure products of
combustion push the piston through the cylinder. This movement is converted from linear to rotary
motion by a crankshaft. The piston returns, pushing out exhaust gases, and the cycle is repeated.
There are two methods used for stationary reciprocating 1C engines: compression ignition (CI)
and spark ignition (SI). Section 3.3 deals with both types of reciprocating internal combustion
engines.
In compression ignition engines, combustion air is first compression heated in the cylinder,
and diesel fuel oil is then injected into the hot air. Ignition is spontaneous as the air is above the auto-
ignition temperature of the fuel. Spark ignition engines initiate combustion by the spark of an
electrical discharge. Usually the fuel is mixed with the air in a carburetor (for gasoline) or at the
intake valve (for natural gas), but occasionally the fuel is injected into the compressed air in the
cylinder. All diesel fueled engines are compression ignited and all gasoline fueled engines are spark
ignited.
CI engines usually operate at a higher compression ratio (ratio of cylinder volume when the
piston is at the bottom of its stroke to the volume when it is at the top) than SI engines because fuel is
not present during compression; hence there is no danger of premature auto-ignition. Since engine
thermal efficiency rises with increasing pressure ratio (and pressure ratio varies directly with
compression ratio), CI engines are more efficient than SI engines. This increased efficiency is gained
at the expense of poorer response to load changes and a heavier structure to withstand the higher
pressures.
3.3.3 Emissions and Controls
The best method for calculating emissions is on the basis of "brake specific" emission factors
(g/hp-hr or g/kW-hr). Emissions are calculated by taking the product of the brake specific emission
factor, the usage in hours (that is, hours per year or hours per day), the power available (rated power),
and the load factor (the power actually used divided by the power available).
10/92 Stationary Internal Combustion Sources 3.3-1
-------
Once reasonable usage and duty cycles for this category were ascertained, emission values
were aggregated to arrive at the factors presented in Tables 3.3-1 (English units) and 3.3-2 (Metric
units) for criteria and organic pollutants. Emissions data for a specific design type were weighted
according to estimated material share for industrial engines. The emission factors in this table are
most appropriately applied to a population of industrial engines rather than to an individual power
plant because of their aggregate nature. Table 3.3-3 shows unweighted speciated organic compound
and air toxic emissions factors based upon only two engines. Their inclusion in this section is
intended only for rough order of magnitude estimates.
Table 3.3-4 shows a summary of various diesel emission reduction technologies (some which
may be applicable to gasoline engines). These technologies are categorized into fuel modifications,
engine modifications, and exhaust after treatments. Current data are insufficient to quantify the results
of the modifications. Table 3.3-4 provides general information on the trends of changes on selected
parameters.
3.3-2
EMISSION FACTORS
10/92
-------
TABLE 3.3-1. (ENGLISH UNITS) EMISSION FACTORS FOR UNCONTROLLED GASOLINE
AND DIESEL INDUSTRIAL ENGINES3
Pollutant
[Rating]"
NOX [D]
CO[D]
SOX [D]
Paniculate [D]
CO2 [B]c
Aldehydes [D]
Hydrocarbons
Exhaust [D]
Evaporative [E]
Crankcase [E]
Refueling [E]
Gasoline Fuel
SCC 20200301, 20300301
[grams/hp-hr]
(power output)
5.16
199
0.268
0.327
493
0.22
6.68
0.30
2.20
0.49
[Ib/MMBtu]
(fuel input)
1.63
62.7
0.084
0.10
155
0.07
2.10
0.09
0.69
0.15
Diesel Fuel
SCC 20200102, 20300101
[grams/hp-hr]
(power output)
14.0
3.03
0.931
1.00
525
0.21
1.12
0.00
0.02
0.00
[Ib/MMBtu]
(fuel input)
4.41
0.95
0.29
0.31
165
0.07
0.35
0.00
0.01
0.00
a. Data based on uncontrolled levels for each fuel from references 1, 3 and 6. When necessary,
the average brake specific fuel consumption (BSFC) value was used to convert from gAip-hr to
Ib/MMBtu was 7000 Btu/hp-hr.
b. "D" and "E" rated emission factors are most appropriate when applied to a population of
industrial engines rather than to an individual power plant, due to the aggregate nature of the
emissions data.
c. Based on assumed 100 percent conversion of carbon in fuel to CO2 with 87 weight percent
carbon in diesel, 86 weight percent carbon in gasoline, average brake specific fuel
consumption of 7000 Btu/hp-hr, diesel heating value of 19300 Btu/lb, and gasoline heating
value of 20300 Btu/lb.
10/92
Stationary Internal Combustion Sources
3.3-3
-------
TABLE 3.3-2. (METRIC UNITS) EMISSION FACTORS FOR UNCONTROLLED GASOLINE
AND DIESEL INDUSTRIAL ENGINES3
Pollutant
[Rating]"
NOX [D]
CO[D]
SOX [D]
Participate [D]
C02 [Bf
Aldehydes [D]
Hydrocarbons
Exhaust [D]
Evaporative [E]
Crankcase [E]
Refueling [E]
Gasoline Fuel
SCC 20200301, 20300301
[grams/kW-hr]
(power output)
6.92
267
0.359
0.439
661
0.30
8.96
0.40
2.95
0.66
[n/J]
(fuel input)
699
26,947
36
44
66,787
29
905
41
298
66
Diesel Fuel
SCC 20200102, 20300101
[grams/kW-hr]
(power output)
18.8
4.06
1.25
1.34
704
0.28
1.50
0.00
0.03
0.00
[n/J]
(fuel input)
1,896
410
126
135
71,065
28
152
0.00
2.71
0.00
a. Data based on uncontrolled levels for each fuel from references 1, 3 and 6.
b. "D" and "E" rated emission factors are most appropriate when applied to a population c
industrial engines rather than to an individual power plant, due to the aggregate nature of the
emissions data.
c. Based on assumed 100 percent conversion of carbon in fuel to CO2 with 87 weight percent
carbon in diesel, 86 weight percent carbon in gasoline, average brake specific fuel
consumption of 7000 Btu/hp-hr, diesel heating value of 19300 Btu/lb, and gasoline heating
value of 20300 Btu/lb.
3.3-4
EMISSION FACTORS
10/92
-------
TABLE 3.3-3. (ENGLISH AND METRIC UNITS) SPECIATED ORGANIC COMPOUNDS AND
AIR TOXIC EMISSION FACTORS FOR UNCONTROLLED DIESEL ENGINES3
(All Emission Factors are Rated: E)b
Pollutant
Benzene
Toluene
Xylenes
Propylene
1,3 Butadiene0
Formaldehyde
Acetaldehyde
Acrolein
[Ib/MMBtu]
(fuel input)
9.33 E-04
4.09 E-04
2.85 E-04
2.58 E-03
< 3.91 E-05
1.18 E-03
7.67 E-04
< 9.25 E-05
[n/J]
(fuel input)
0.401
0.176
0.122
1.109
< 0.017
0.509
0.330
< 0.040
Polycyclic Aromatic Hydrocarbons (PAH)
a. Data are
b. "E" rated
Naphthalene
Acenaphthylene
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benz(a)anthracene
Chrysene
Benzo(b)fluoranthene
Benzo(k)fluoranthene
Benzo(a)pyrene
Indeno(l ,2,3-cd)pyrene
Dibenz(a,h)anthracene
Benzo(g,h,l)perylene
Total PAH
based on the uncontrolled
emission factors are due to
8.48 E-05
< 5.06 E-06
< 1.42 E-06
2.92 E-05
2.94 E-05
1.87 E-06
7.61 E-06
4.78 E-06
1.68 E-06
3.53 E-07
< 9.91 E-08
< 1.55 E-07
< 1.88 E-07
< 3.75 E-07
< 5.83 E-07
< 4.89 E-07
1.68 E-04
3.64 E-02
< 2.17 E-03
<6.11 E-04
1.26 E-02
1.26 E-02
8.02 OE-04
3.27 E-03
2.06 E-03
7.21 E-04
1.52 E-04
< 4.26 E-05
< 6.67 E-05
< 8.07 E-05
< 1.61 E-04
< 2.50 E-04
< 2. 10 E-04
7.22 E-02
levels of two diesel engines from references 6 and 7.
limited data sets, inherent variability
in the population and/or
c.
a lack of documentation of test results. "E" rated emission factors may not be suitable for specific
facilities or populations and should be used with care.
Data are based on one engine.
10/92
Stationary Internal Combustion Sources
3.3-5
-------
TABLE 3.3-4. DIESEL EMISSION CONTROL TECHNOLOGIES4
Technology
Affected Parameter3
Increase
Decrease
Fuel Modifications
Sulfur Content Increase
Aromatic Content Increase
Cetane Number
10 percent and 90 percent Boiling
Point
Fuel Additives
Water/Fuel Emulsions
Engine Modifications
Injection Timing
Fuel Injection Pressure
Injection Rate Control
Rapid Spill Nozzles
Electronic Timing & Metering
Injector Nozzle Geometry
Combustion Chamber Modifications
Turbocharging
Charge Cooling
Exhaust Gas Recirculation
Oil Consumption Control
Exhaust After Treatment
Particulate Traps
Selective Catalytic Reduction
Oxidation Catalysts
PM, Wear
PM, NOX
NOX) PM, BSFC,
Power
PM, NOX
PM, Power
PM, NOX
PM
PM, NOX
NOX
NO,
NOX, PM
PM
NOX, PM
PM
NOX, PM
NOX
NOV
PM, Power, Wear NOX
PM, Wear
PM
NOX
HC, CO, PM
a.
3.3-6
NOX = Nitrogen oxides; PM = Particulate matter; HC = Hydrocarbons;
CO = Carbon monoxide; BSFC = Brake specific fuel consumption.
EMISSION FACTORS
10/92
-------
References for Section 3.3
1. Hare, C. T. and K. J. Springer, Exhaust Emissions from Uncontrolled Vehicles and Related
Equipment using Internal Combustion Engines. Part 5: Farm. Construction, and Industrial
Engines, U.S. Environmental Protection Agency, Research Triangle Park, NC, Publication
APTD-1494, October 1973, pp. 96-101.
2. Lips, H. I., J. A. Gotterba, and K. J. Lim, Environmental Assessment of Combustion
Modification Controls for Stationary Internal Combustion Engines, EPA-600/7-81-127,
Industrial Environmental Research Laboratory, Office of Environmental Engineering and
Technology, Office of Air Quality Planning and Standards, U.S. Environmental Protection
Agency, Research Triangle Park, NC, July 1981.
3. Standards Support and Environmental Impact Statement. Volume I: Stationary Internal
Combustion Engines, EPA-450/2-78-125a, Emission Standards and Engineering Division,
Office of Air, Noise, and Radiation, Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, NC, July 1979.
4 Technical Feasibility of Reducing NO, and Paniculate Emissions from Heavy-Duty Engines,
Draft Report by Acurex Environmental Corporation for the California Air Resources Board,
Sacramento, CA, March 1992, CARB Contract A132-085.
5. Nonroad Engine and Vehicle Emission Study-Report, EPA-460/3-91-02, Certification Division,
Office of Mobile Sources, Office of Air & Radiation, U.S. Environmental Protection Agency,
Research Triangle Park, NC, November 1991.
6. Pooled Source Emission Test Report: Oil and Gas Production Combustion Sources, Fresno
and Ventura Counties, California, Report prepared by ENSR Consulting and Engineering for
Western States Petroleum Association (WSPA), Bakersfield, CA, December 1990, ENSR
7230-007-700.
7. Osborn, W. E., and M. D. McDannel, Emissions of Air Toxic Species: Test Conducted Under
AB2588 for the Western States Petroleum Association, Report prepared by Camot for Western
States Petroleum Association (WSPA), Glendale, California, May 1990, CR 72600-2061.
10/92 Stationary Internal Combustion Sources 3.3-7
-------
-------
3.4 LARGE STATIONARY DIESEL AND ALL STATIONARY DUAL FUEL ENGINES
3.4.1 General
The primary domestic use of large stationary diesel engines (greater than 600 hp) is in oil and
gas exploration and production. These engines, in groups of three to five, supply mechanical power to
operate drilling (rotary table), mud pumping and hoisting equipment, and may also operate pumps or
auxiliary power generators. Another frequent application of large stationary diesels is electricity
generation for both base and standby service. Smaller uses include irrigation, hoisting and nuclear
power plant emergency cooling water pump operation.
Dual fuel engines were developed to obtain compression ignition performance and the
economy of natural gas, using a minimum of 5 to 6 percent diesel fuel to ignite the natural gas. Large
dual fuel engines have been used almost exclusively for prime electric power generation. This section
includes all dual fuel engines.
3.4.2 Process Description
All reciprocating internal combustion (1C) engines operate by the same basic process. A
combustible mixture is first compressed in a small volume between the head of a piston and its
surrounding cylinder. The mixture is then ignited, and the resulting high pressure products of
combustion push the piston through the cylinder. This movement is converted from linear to rotary
motion by a crankshaft. The piston returns, pushing out exhaust gases, and the cycle is repeated.
There are two methods used for stationary reciprocating 1C engines: compression ignition (CI)
and spark ignition (SI). Section 3.4 deals only with compression ignition engines.
In compression ignition engines, combustion air is first compression heated in the cylinder,
and diesel fuel oil is then injected into the hot air. Ignition is spontaneous as the air is above the auto-
ignition temperature of the fuel. Spark ignition engines initiate combustion by the spark of an
electrical discharge. Usually the fuel is mixed with the air 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 compression ignition engine if a small amount of diesel
fuel is injected into the compressed gas/air mixture to burn any mixture ratio of gas and diesel oil
(hence the name dual fuel), from 6- to 100-percent diesel oil.
CI engines usually operate at a higher compression ratio (ratio of cylinder volume when the
piston is at the bottom of its stroke to the volume when it is at the top) than SI engines because fuel is
not present during compression; hence there is no danger of premature auto-ignition. Since engine
thermal efficiency rises with increasing pressure ratio (and pressure ratio varies directly with
compression ratio), CI engines are more efficient than SI engines. This increased efficiency is gained
at the expense of poorer response to load changes and a heavier structure to withstand the higher
pressures.
10/92 Stationary Internal Combustion Sources 3.4-1
-------
3.4.3 Emissions and Controls
Most of the pollutants from 1C engines are emitted through the exhaust. However, some
hydrocarbons escape from the crankcase as a result of blowby (gases which are vented from the oil
pan after they have escaped from the cylinder past the piston rings) and from the fuel tank and
carburetor because of evaporation. Nearly all of the hydrocarbons from diesel (CI) engines enter the
atmosphere from the exhaust. Crankcase blowby is minor because hydrocarbons are not present
during compression of the charge. Evaporative losses are insignificant in diesel engines due to the low
volatility of diesel fuels. In general, evaporative losses are also negligible in engines using gaseous
fuels because these engines receive their fuel continuously from a pipe rather than via a fuel storage
tank and fuel pump.
The primary pollutants from internal combustion engines are oxides of nitrogen (NOJ, organic
compounds (hydrocarbons), carbon monoxide (CO), and particulates, which include both visible
(smoke) and nonvisible emissions. The other pollutants are primarily the result of incomplete
combustion. Ash and metallic additives in the fuel also contribute to the paniculate content of the
exhaust. Oxides of sulfur (SOX) also appears in the exhaust from 1C engines.
The primary pollutant of concern from large stationary diesel and all stationary dual fuel
engines is NOX, which readily forms in the high temperature, pressure, nitrogen content of the fuel,
and excess air environment found in these engines. Lesser amounts of CO and hydrocarbons are
emitted. The sulfur compounds, mainly SO2, are directly related to the sulfur content of the fuel. SOX
emissions will usually be quite low because of the negligible sulfur content of diesel fuels and natural
gas.
Tables 3.4-1 (English units) and 3.4-2 (Metric units) contain gaseous emission factors.
Table 3.4-3 shows the speciated organic compound emission factors and Table 3.4-4 shows the
emission factors for polycyclic aromatic hydrocarbons (PAH). These tables do not provide a complete
speciated organic compound and PAH listing since they are based only on a single engine test; they
are to be used for rough order of magnitude comparisons.
Table 3.4-5 shows the particulate and particle sizing emission factors.
Control measures to date have been directed mainly at limiting NOX emissions because NOX is
the primary pollutant from diesel and dual fuel engines. Table 3.4-6 shows the NOX reduction and fuel
consumption penalties for diesel and dual fueled engines based on some of the available control
techniques. All of these controls are engine control techniques except for the selective catalytic
reduction (SCR) technique, which is a post-combustion control. The emission reductions shown are
those which have been demonstrated. The effectiveness of controls on an particular engine will
depend on the specific design of each engine and the effectiveness of each technique could vary
considerably. Other NOX control techniques exist but are not included in Table 3.4-6. These
techniques include internal/external exhaust gas recirculation (EGR), combustion chamber
modification, manifold air cooling, and turbocharging.
3.4-2
EMISSION FACTORS
10/92
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TABLE 3.4-3. (ENGLISH AND METRIC UNITS) SPECIATED ORGANIC COMPOUND
EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES3
(Emission Factor Rating: E)b
Pollutant
Benzene
Toluene
Xylenes
Propylene
Formaldehyde
Acetaldehyde
Acrolein
[Ib/MMBtu]
(fuel input)
7.76 E-04
2.81 E-04
1.93 E-04
2.79 E-03
7.89 E-05
2.52 E-05
7.88 E-06
[ng/J]
(fuel input)
3.34 E-01
1.21 E-01
8.30 E-02
1.20 E-00
3.39 E-02
1.08 E-02
3.39 E-03
a. Data based on the uncontrolled levels of one diesel engine from reference 5. There was
enough information to compute the input specific emission factors of Ib/MMBtu, but not
enough to calculate the output specific emission factor of g/hp-hr. There was enough
information to compute the input specific emission factors of ng/J, but not enough to calculate
the output specific emission factor of g/kW-hr.
b. "E" rating for emission factors are due to limited data sets, inherent variability in the
population and/or a lack of documentation of test results. "E" rated emission factors may not
be suitable for specific facilities or populations and should be used with care.
10/92 Stationary Internal Combustion Sources 3.4-5
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TABLE 3.4-4. (ENGLISH AND METRIC UNITS) POLYCYCLIC AROMATIC HYDROCARBON
(PAH) EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES3
(Emission Factor Rating: E)b
Pollutant
Polycyclic Aromatic Hydrocarbons (PAH)
Naphthalene
Acenaphthylene
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benz(a)anthracene
Chrysene
Benzo(b)fluoranthene
Benzo(k)fluoranthene
Benzo(a)pyrene
Indeno(l ,2,3-cd)pyrene
Dibenz(a,h)anthracene
Benzo(g,h,l)perylene
Total PAH
[Ib/MMBtu]
(fuel input)
1.30 E-04
9.23 E-06
4.68 E-06
1.28 E-05
4.08 E-05
1.23 E-06
4.03 E-06
3.71 E-06
6.22 E-07
1.53 E-06
1.11 E-06
< 2. 18 E-07
< 2.57 E-07
< 4. 14 E-07
< 3.46 E-07
< 5.56 E-07
2.12 E-04
[ng/J]
(fuel input)
5.59 E-02
3.97 E-03
2.01 E-03 ,
5.50 E-03
1.75 E-02
5.29 E-04
1.73 E-03
1.60 E-03
2.67 E-04
6.58 E-04
4.77 E-04
< 9.37 E-05
< 1.10 E-04
< 1.78 E-04
< 1.49 E-04
< 2.39 E-04
9.09 E-02
a. Data are based on the uncontrolled levels of one diesel engine from reference 5. There was
enough information to compute the input specific emission factors of Ib/MMBtu and ng/J but
not enough to calculate the output specific emission factor of g/hp-hr and g/kW-hr.
b. "E" rating for emission factors is due to limited data sets, inherent variability in the population
and/or a lack of documentation of test results. "E" rated emission factors may not be suitable
for specific facilities or populations and should be used with care.
3.4-6
EMISSION FACTORS
10/92
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TABLE 3.4-5. (ENGLISH AND METRIC UNITS) PARTICULATE AND PARTICLE SIZING
EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES3
(Emission Factor Rating: E)b
Pollutant
Paniculate Size Distribution
<1 urn
1-3 urn
3-10 um
>10 um
Total PM-10 (<10 um)
TOTAL
Paniculate Emissions
Solids
Condensables
TOTAL
Power
[grams/hp-hr]
0.1520
0.0004
0.0054
0.0394
0.1578
0.1972
0.2181
0.0245
0.2426
Output
[grams/kW-hr]
0.2038
0.0005
0.0072
0.0528
0.2116
0.2644
0.2925
0.0329
0.3253
Fuel Input
[Ib/MMBtu]
0.0478
0.0001
0.0017
0.0124
0.0496
0.0620
0.0686
0.0077
0.0763
[ng/J]
20.56
0.05
0.73
5.33
21.34
26.67
29.49
3.31
32.81
a.
Data are based on the uncontrolled levels of one diesel engine from reference 6. The data for
the paniculate emissions were collected using Method 5 and the particle size distributions were
collected using a Source Assessment Sampling System (SASS).
"E" rating for emission factors is due to limited data sets, inherent variability in the population
and/or a lack of documentation of test results. "E" rated emission factors may not be suitable
for specific facilities or populations and should be used with care.
10/92
Stationary Internal Combustion Sources
3.4-7
-------
TABLE 3.4-6. NOX REDUCTION AND FUEL CONSUMPTION PENALTIES FOR
LARGE STATIONARY DIESEL AND DUAL FUEL ENGINES3
Control Approach
Derate
Retard
Air-to-Fuel
Water Injection (H2O/fuel ratio)
Selective Catalytic Reduction (SCR)
10%
20%
25%
2°
4°
8°
3%
±10%
50%
Diesel
Percent NOX
Reduction
<20
5-23
<20
<40
28-45
7-8
25-35
80-95
ABSFC,"
Percent
4
1-5-
4
4
2-8
3
2-4
0
Dual
Percent
NOX
Reduction
<20
1-33
<20
<40
50-73
<20
25-40
80-95
Fuel
ABSFC,b
Percent
4
1-7
3
1
3-5
0
1-3
0
a.
Data are based on references 1, 2, and 3. The reductions shown are typical and will
vary depending on the engine and duty cycle.
b. BSFC = Brake Specific Fuel Consumption.
3.4-8
EMISSION FACTORS
10/92
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References for Section 3.4
1. Lips, H. I., J. A. Gotterba, and K. J. Lim, Environmental Assessment of Combustion
Modification Controls for Stationary Internal Combustion Engines. EPA-600/7-81-127,
Industrial Environmental Research Laboratory, Office of Environmental Engineering and
Technology, Office of Air Quality Planning and Standards, U.S. Environmental Protection
Agency, Research Triangle Park, NC, July 1981,
2. Campbell, L. M., D. K. Stone, and G. S. Shareef, Sourcebook: NOV Control Technology Data,
Control Technology Center, EPA-600/2-91-029, Emission Standards Division, Office of Air
Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle
Park, NC, July 1991.
3. Catalysts for Air Pollution Control, brochure by the Manufacturers of Emission Controls
Association (MECA), Washington, DC, March 1992.
4. Standards Support and Environmental Impact Statement, Volume I: Stationary Internal
Combustion Engines, EPA-450/2-78-125a, Emission Standards and Engineering Division,
Office of Air, Noise, and Radiation, Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, NC, July 1979.
5. Pooled Source Emission Test Report: Oil and Gas Production Combustion Sources, Fresno
and Ventura Counties, California, Report prepared by ENSR Consulting and Engineering for
Western States Petroleum Association (WSPA), Bakersfield, CA, December 1990, ENSR #
7230-007-700.
6. Castaldini, C, Environmental Assessment of NO. Control on a Compression Ignition Large
Bore Reciprocating Internal Combustion Engine, Volume I: Technical Results, EPA-600/7-
86/OOla, Combustion Research Branch of the Energy Assessment and Control Division,
Industrial Environmental Research Laboratory, Office of Research and Development, U.S.
Environmental Protection Agency, Washington, D.C., April 1984.
10/92 Stationary Internal Combustion Sources 3.4-9
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Emissions And Controls2'3 - In the bathing and mixing of fine dry ingredients to form slurry, dust
emissions are generated at scale hoppers, mixers and crushers. Fabric filters are used, not only to reduce or
to eliminate the dust emissions but also to recover raw materials. Emission factors for paniculate from
spray drying operations are shown in Table 5.15-1. Table 5.15-2 gives size specific paniculate emission
factors for operations on which information is available. There is also a minor source of volatile organics
when the product being sprayed contains organic material with low vapor pressures. In the tower exhaust
air stream, these vaporized organic materials condense into droplets or particles.
Dry cyclones and cyclonic impingement scrubbers are the primary collection equipment employed
to capture the detergent dust in the spray dryer exhaust for return to process. Dry cyclones are used, in
parallel or in series, to collect paniculate (detergent dust) and to recycle it back to the crusher. Cyclonic
impinged scrubbers are used, in parallel, to collect the paniculate from a scrubbing slurry and to recycle it to
the crushher. Secondary collection equipment is used to collect the fine paniculate that has escaped from the
primary devices. Cyclonic impingement scrubbers are often followed by mist eliminators, and dry cyclones
are followed by fabric filters or scrubber/electrostatic precipitator units. Conveying, mixing and packaging
of detergent granules can cause dust emissions. Usually, fabric filters provide the best control.
TABLE 5.15-1. EMISSION FACTORS FOR DETERGENT SPRAY DRYINGa
EMISSION FACTOR RATING: B
Control device
Uncontrolled
Cycloneb
Cyclone
w/Spray chamber
w/Packed scrubber
w/Venturi scrubber
w/Wet scrubber
w/Wet scrubber/ESP
Fabric filter
Efficiency
(%)
NA
85
92
95
97
99
99.9
99
Paniculate
Kg/Mgof
product
45
7
3.5
2.5
1.5
0.544
0.023
0.54
Ib/ton of
product
90
14
7
5
3
1.08
0.046
1.1
References 4-8. VOC emissions data have not been reported in the literature. NA = not
applicable. ESP = electrostatic precipitator.
bSome type of primary collector, such as a cyclone, is considered integral to a spray drying
system.
9/88 Chemical Process Industry 5.15-3
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9/88
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STORAGE OF ORGANIC LIQUIDS
12.1 PROCESS DESCRIPTION1'2
Storage vessels containing organic liquids can be found in many industries, including
(1) petroleum producing and refining, (2) petrochemical and chemical manufacturing,
(3) bulk storage and transfer operations, and (4) other industries consuming or producing
organic liquids. Organic liquids in the petroleum industry, usually called petroleum liquids,
generally are mixtures of hydrocarbons having dissimilar true vapor pressures (for example,
gasoline and crude oil). Organic liquids in the chemical industry, usually called volatile
organic liquids, are composed of pure chemicals or mixtures of chemicals with similar true
vapor pressures (for example, benzene or a mixture of isopropyl and butyl alcohols).
Five basic tank designs are used for organic liquid storage vessels: fixed roof
(vertical and horizontal), external floating roof, internal floating roof, variable vapor space,
and pressure (low and high). A brief description of each tank is provided below. Loss
mechanisms associated with each type of tank are provided in Section 12.2.
Fixed Roof Tanks - A typical vertical fixed roof tank is shown in Figure 12.1-1. This type
of tank consists of a cylindrical steel shell with a permanently affixed roof, which may vary
in design from cone- or dome-shaped to flat.
Fixed roof tanks are either freely vented or equipped with a pressure/vacuum vent.
The latter allows them to operate at a slight internal pressure or vacuum to prevent the
release of vapors during very small changes in temperature, pressure, or liquid level. Of
current tank designs, the fixed roof tank is the least expensive to construct and is generally
considered the minimum acceptable equipment for storing organic liquids.
Horizontal fixed roof tanks are constructed for both above-ground and underground
service and are usually constructed of steel, steel with a fiberglass overlay, or fiberglass-
reinforced polyester. Horizontal tanks are generally small storage tanks with capacities of
less than 40,000 gallons. Horizontal tanks are constructed such that the length of the tank is
not greater than six times the diameter to ensure structural integrity. Horizontal tanks are
usually equipped with pressure-vacuum vents, gauge hatches and sample wells, and manholes
to provide access to these tanks. In addition, underground tanks are cathodically protected to
prevent corrosion of the tank shell. Cathodic protection is accomplished by placing
sacrificial anodes in the tank that are connected to an impressed current system or by using
galvanic anodes in the tank.
The potential emission sources for above-ground horizontal tanks are the same as
those for vertical fixed roof tanks. Emissions from underground storage tanks are associated
mainly with changes in the liquid level in the tank. Losses due to changes in temperature or
barometric pressure are minimal for underground tanks because the surrounding earth limits
the diurnal temperature change, and changes in the barometric pressure result in only small
losses.
10/92 Storage of Organic Liquids 12-1
-------
External Floating Roof Tanks - A typical external floating roof tank consists of an open-
topped cylindrical steel shell equipped with a roof that floats on the surface of the stored
liquid. Floating roof tanks that are currently in use are constructed of welded steel plate and
are of two general types: pontoon or double-deck. Pontoon-type and double-deck-type
external floating roofs are shown in Figures 12.1-2 and 12.1-3, respectively. With all types
of external floating roof tanks, the roof rises and falls with the liquid level in the tank.
External floating roof tanks are equipped with a seal system, which is attached to the roof
perimeter and contacts the tank wall. The purpose of the floating roof and seal system is to
reduce evaporative loss of the stored liquid. Some annular space remains between the seal
system and the tank wall. The seal system slides against the tank wall as the roof is raised
and lowered. The floating roof is also equipped with roof fittings that penetrate the floating
roof and serve operational functions. The external floating roof design is such that
evaporative losses from the stored liquid are limited to losses from the seal system and roof
fittings (standing storage loss) and any exposed liquid on the tank walls (withdrawal loss).
Internal Floating Roof Tanks - An internal floating roof tank has both a permanent fixed roof
and a floating deck inside. The terms "deck" and "floating roof can be used
interchangeably in reference to the structure floating on the liquid inside the tank. There are
two basic types of internal floating roof tanks: tanks in which the fixed roof is supported by
vertical columns within the tank, and tanks with a self-supporting fixed roof and no internal
support columns. Fixed roof tanks that have been retrofitted to use a floating deck are
typically of the first type. External floating roof tanks that have been converted to internal
floating roof tanks typically have a self-supporting roof. Newly constructed internal floating
roof tanks may be of either type. The deck in internal floating roof tanks rises and falls with
the liquid level and either floats directly on the liquid surface (contact deck) or rests on
pontoons several inches above the liquid surface (noncontact deck). The majority of
aluminum internal floating roofs currently in service are noncontact decks. Typical contact
deck and noncontact deck internal floating roof tanks are shown in Figure 12.1-4.
Contact decks can be (1) aluminum sandwich panels that are bolted together, with a
honeycomb aluminum core floating in contact with the liquid; (2) pan steel decks floating in
contact with the liquid, with or without pontoons; and (3) resin-coated, fiberglass reinforced
polyester (FRP), buoyant panels floating in contact with the liquid. The majority of internal
contact floating roofs currently in service are aluminum sandwich panel-type or pan
steel-type. The FRP roofs are less common. The panels of pan steel decks are usually
welded together.
Typical noncontact decks have an aluminum deck and an aluminum grid framework
supported above the liquid surface by tubular aluminum pontoons or some other buoyant
structure. The noncontact decks usually have bolted deck seams. Installing a floating roof
or deck minimizes evaporative losses of the stored liquid. As with the external floating roof
tanks, both contact and noncontact decks incorporate rim seals and deck fittings for the same
purposes previously described for external floating roof tanks. Evaporation losses from
decks may come from deck fittings, nonwelded deck seams, and the annular space between
the deck and tank >wall. In addition, these tanks are freely vented by circulation vents at the
top of the fixed roof. The vents minimize the possibility of organic vapor accumulation in
12-2 EMISSION FACTORS 10/92
-------
concentrations approaching the flammable range. An internal floating roof tank not freely
vented is considered a pressure tank. Emission estimation methods for such tanks are not
provided in AP-42.
Variable Vapor Space Tanks - Variable vapor space tanks are equipped with expandable
vapor reservoirs to accommodate vapor volume fluctuations attributable to temperature and
barometric pressure changes. Although variable vapor space tanks are sometimes used
independently, they are normally connected to the vapor spaces of one or more fixed roof
tanks. The two most common types of variable vapor space tanks are lifter roof tanks and
flexible diaphragm tanks.
Lifter roof tanks have a telescoping roof that fits loosely around the outside of the
main tank wall. The space between the roof and the wall is closed by either a wet seal,
which is a trough filled with liquid, or a dry seal, which uses a flexible coated fabric.
Flexible diaphragm tanks use flexible membranes to provide expandable volume.
They may be either separate gasholder units or integral units mounted atop fixed roof tanks.
Variable vapor space tank losses occur during tank filling when vapor is displaced by
liquid. Loss of vapor occurs only when the tank's vapor storage capacity is exceeded.
Pressure Tanks - Two classes of pressure tanks are in general use: low pressure (2.5 to
15 psig) and high pressure (higher than 15 psig). Pressure tanks generally are used for
storing organic liquids and gases with high vapor pressures and are found in many sizes and
shapes, depending on the operating pressure of the tank. Pressure tanks are equipped with a
pressure/vacuum vent that is set to prevent venting loss from boiling and breathing loss from
daily temperature or barometric pressure changes. High-pressure storage tanks can be
10/92 Storage of Organic Liquids 12-3
-------
operated so that virtually no evaporative or working losses occur. In low-pressure tanks,
working losses can occur with atmospheric venting of the tank during filling operations. No
appropriate correlations are available to estimate vapor losses from pressure tanks.
Pressure/Vacuum V«nt
F i x«d Roo f
Float Gauge
Roof Column
I- i qu i d Lav* I
Indi cat or
Inl.t Nozzl*
Outlat Nozzl
Roo f ManhoI i
Gaugs-Ha t ch/
Samp la WeU
:—Gauger's Platform
Spiral Stairway
Cyl i ndr i cal Shol I
SholI ManhoIe
Figure 12.1-1. Typical fixed-roof tank.1
12-4
EMISSION FACTORS
10/92
-------
RIM VENT
PONTOON ACCESS HATCH
WIND GIRDER
VACUUM BREAKER
RIM SEAL
PONTOON ROOF LEG
CENTER ROOF LEG
ACCESS HATCH
GAUGER'S PLATF3RM
GAUGE-FLOAT WELL
GUIDE POLE
GAUGE-HATCH/
SAMPLE WELL
ROLLING LADDER
ROOF DRAIN
LEG FLOOR PAD
Figure 12.1-2. External floating roof tank (pontoon type).1
RIM VENT
WIND GIRDER
VACUUM BREAKER
ROOF LEG
RIM SEAL
ACCESS HATCH
EMERGENCY ROOF DRAIN
GAUGER'S PLATFORM
GAUGE-FLOAT WELL
GUIDE POLE
GAUGE-HATCH/
SAMPLE WELL
ROLLING LADDER
ROOF DRAIN
LEG FLOOR PAD
Figure 12.1-3. External floating roof tank (double-deck type).1
10/92
Storage of Organic Liquids
12-5
-------
Peripheral
Roof Vent
Primary Seal
Manhole
Center Vent
Tank Support
Column with
Column Well
a. Contact internal floating roof
Center Vent
Peripheral
Roof Vent
Primary Seal
Manhole
Rim Plate
Rim Pontoons
Tank Support
Column with
Column Well
Rim Pontoons
Pontoons
Vapor Space
b. Noncontact internal floating roof.
Figure 12.1-4. Internal floating roof tanks.2
12-6
EMISSION FACTORS
10/92
-------
12.2 EMISSION MECHANISMS AND CONTROL
Emissions from organic liquids in storage occur because of evaporative loss of the
liquid during its storage and as a result of changes in the liquid level. The emission sources
vary with tank design, as does the relative contribution of each type of emission source.
Emissions from fixed roof tanks are a result of evaporative losses during storage and are
known as breathing losses (or standing storage losses), and evaporative losses during filling
and emptying operations are known as working losses. External and internal floating roof
tanks are emission sources because of evaporative losses that occur during standing storage
and withdrawal of liquid from the tank. Standing storage losses are a result of evaporative
losses through rim seals, deck fittings, and/or deck seams. The loss mechanisms for fixed
roof and external and internal floating roof tanks are described in more detail in the
following sections. Variable vapor space tanks are also emission sources because of
evaporative losses that result during filling operations. The loss mechanism for variable
vapor space tanks is also described in this section. Emissions occur from pressure tanks, as
well. However, loss mechanisms from these sources are not described in this chapter.
12.2.1 Fixed Roof Tanks
The two significant types of emissions from fixed roof tanks are storage and working
losses. Storage loss is the expulsion of vapor from a tank through vapor expansion and
contraction, which are the results of changes in temperature and barometric pressure. This
loss occurs without any liquid level change in the tank.
The combined loss from filling and emptying is called working loss. Evaporation
during filling operations is a result of an increase in the liquid level in the tank. As the
liquid level increases, the pressure inside the tank exceeds the relief pressure and vapors are
expelled from the tank. Evaporative loss during emptying occurs when air drawn into the
tank during liquid removal becomes saturated with organic vapor and expands, thus
exceeding the capacity of the vapor space.
Fixed roof tank emissions vary as a function of vessel capacity, vapor pressure of the
stored liquid, utilization rate of the tank, and atmospheric conditions at the tank location.
Several methods are used to control emissions from fixed roof tanks. Emissions from
fixed roof tanks can be controlled by installing an internal floating roof and seals to minimize
evaporation of the product being stored. The control efficiency of this method ranges from
60 to 99 percent, depending on the type of roof and seals installed and on the type of organic
liquid stored.
Vapor balancing is another means of emission control. Vapor balancing is probably
most common in the filling of tanks at gasoline stations. As the storage tank is filled, the
vapors expelled from the storage tank are directed to the emptying gasoline tanker truck.
The truck then transports the vapors to a centralized station where a vapor recovery or
control system is used to control emissions. Vapor balancing can have control efficiencies as
high as 90 to 98 percent if the vapors are subjected to vapor recovery or control. If the
10/92 Storage of Organic Liquids 12-7
-------
truck vents the vapor to the atmosphere instead of to a recovery or control system, no control
is achieved.
Vapor recovery systems collect emissions from storage vessels and convert them to
liquid product. Several vapor recovery procedures may be used, including vapor/liquid
absorption, vapor compression, vapor cooling, vapor/solid adsorption, or a combination of
these. The overall control efficiencies of vapor recovery systems are as high as 90 to
98 percent, depending on the methods used, the design of the unit, the composition of vapors
recovered, and the mechanical condition of the system.
In a typical thermal oxidation system, the air/vapor mixture is injected through a
burner manifold into the combustion area of an incinerator. Control efficiencies for this
system can range from 96 to 99 percent.
12.2.2 External Floating Roof Tanks2-3'5
Total emissions from external floating roof tanks are the sum of withdrawal losses
and standing storage losses. Withdrawal losses occur as the liquid level, and thus the
floating roof, is lowered. Some liquid remains attached to the tank surface and is exposed to
the atmosphere. Evaporative losses will occur until the tank is filled and the exposed surface
(with the liquid) is again covered. Standing storage losses from external floating roof tanks
include rim seal and roof fitting losses. Rim seal losses can occur through many complex
mechanisms, but the majority of rim seal vapor losses have been found to be wind-induced.
Other potential standing storage loss mechanisms include breathing losses as a result of
temperature and pressure changes. Also, standing storage losses can occur through
permeation of the seal material with vapor or via a wicking effect of the liquid. Testing has
indicated that breathing, solubility, and wicking loss mechanisms are small in comparison to
the wind-induced loss. Also, permeation of the seal material generally does not occur if the
correct seal fabric is used. The rim seal loss factors incorporate all types of losses.
The roof fitting losses can be explained by the same mechanisms as the rim seal loss
mechanisms. However, the relative contribution of each is not known. The roof fitting
losses identified in this section account for the combined effect of all of the mechanisms.
A rim seal system is used to allow the floating roof to travel within the tank as the
liquid level changes. The seal system also helps to fill the annular space between the rim
and the tank shell and therefore minimize evaporative losses from this area. A rim seal
system may consist of just a primary seal or a primary seal and a secondary seal, which is
mounted above the primary seal. Examples of primary and secondary seal configurations are
shown in Figures 12.2-1 through 12.2-3. Three basic types of primary seals are used on
external floating roofs: mechanical (metallic) shoe, resilient filled (nonmetallic), and flexible
wiper. The resilient seal can be mounted to eliminate the vapor space between the seal and
liquid surface (liquid mounted) or to allow a vapor space between the seal and liquid surface
(vapor mounted). A primary seal serves as a vapor conservation device by closing the
annular space between the edge of the floating roof and the tank wall. Some primary seals
are protected by a metallic weather shield. Additional evaporative loss may be controlled by
12-8 EMISSION FACTORS 10/92
-------
a secondary seal. Secondary seals can be either flexible wiper seals or resilient filled seals.
Two configurations of secondary seals are currently available: shoe mounted and rim
mounted. Although there are other seal systems, the systems described here include the
majority in use today.
Roof fitting loss emissions from external floating roof tanks result from penetrations
in the roof by deck fittings, the most common of which are described below. Roof fittings
are also shown in Figures 12.2-4 and 12.2-5. Some of the fittings are typical of both
external and internal floating roof tanks.
1. Access hatch. An access hatch is an opening in the deck with a peripheral vertical
well that is large enough to provide passage for workers and materials through the deck for
construction or servicing. Attached to the opening is a removable cover that may be bolted
and/or gasketed to reduce evaporative loss. On internal floating roof tanks with noncontact
decks, the well should extend down into the liquid to seal off the vapor space below the
noncontact deck. A typical access hatch is shown in Figure 12.2-4a.
2. Gauge-float well. A gauge-float .is used to indicate the level of liquid within the
tank. The float rests on the liquid surface and is housed inside a well that is closed by a
cover. The cover may be bolted and/or gasketed to reduce evaporation loss. As with other
similar deck penetrations, the well extends down into the liquid on noncontact decks in
internal floating roof tanks. A typical gauge-float well is shown in Figure 12.2-4b.
3. Gauge-hatch/sample well. A gauge-hatch/sample well consists of a pipe sleeve
equipped with a self-closing gasketed cover (to reduce evaporative losses) and allows
hand-gauging or sampling of the stored liquid. The gauge-hatch/sample well is usually
located beneath the gauger's platform, which is mounted on top of the tank shell. A cord
may be attached to the self-closing gasketed cover so that the cover can be opened from the
platform. A typical gauge-hatch/sample well is shown in Figure 12.2-4c.
4. Rim vents. Rim vents are usually used only on tanks equipped with a
mechanical-shoe primary seal. A typical rim vent is shown in Figure 12.2-4d. The vent is
used to release any excess pressure or vacuum that is present in the vapor space bounded by
the primary-seal shoe and the floating roof rim and the primary seal fabric and the liquid
level. Rim vents usually consist of weighted pallets that rest on a gasketed cover.
5. Roof drains. Currently two types of roof drains are in use (closed and open roof
drains) to remove rainwater from the floating roof surface. Closed roof drains carry
rainwater from the surface of the roof though a flexible hose or some other type of piping
system that runs through the stored liquid prior to exiting the tank. The rainwater does not
come in contact with the liquid, so no evaporative losses result.
Open roof drains can be either flush or overflow drains and are used only on
double-deck external floating roofs. Both types consist of a pipe that extends below the roof
to allow the rainwater to drain into the stored liquid. The liquid from the tank enters the
pipe, so evaporative losses can result from the tank opening. Flush drains are flush with the
10/92 Storage of Organic Liquids 12-9
-------
roof surface. Overflow drains are elevated above the roof surface. A typical overflow roof
drain is shown in Figure 12.2-5a. Overflow drains are used to limit the maximum amount of
rainwater that can accumulate on the floating roof, providing emergency drainage of
rainwater if necessary. Overflow drains are usually used in conjunction with a closed drain
system to carry rainwater outside the tank.
6. Roof leg. To prevent damage to fittings underneath the deck and to allow for tank
cleaning or repair, supports are provided to hold the deck at a predetermined distance off the
tank bottom. These supports consist of adjustable or fixed legs attached to the floating deck
or hangers suspended from the fixed roof. For adjustable legs or hangers, the load-carrying
element passes through a well or sleeve into the deck. With noncontact decks, the well
should extend into the liquid. Evaporative losses may occur in the annulus between the roof
leg and its sleeve. A typical roof leg is shown in Figure 12.2.5b.
7. Unslotted guidepole wells. A guidepole well is an antirotational device that is
fixed to the top and bottom of the tank, passing through the floating roof. The guidepole is
used to prevent adverse movement of the roof and thus damage to roof fittings and the rim
seal system. A typical guidepole well is shown in Figure 12.2-5c.
8. plotted guidepole/sample wells. The function of the slotted guidepole/sample well
is similar to the unslotted guidepole well but also has additional features. A typical slotted
guidepole well is shown in Figure 12.2-5d. As shown in this figure, the guide pole is slotted
to allow stored liquid to enter. The liquid entering the guidepole is well mixed, having the
same composition as the remainder of the stored liquid, and is at the same liquid level as the
liquid in the tank. Representative samples can therefore be collected from the slotted
guidepole. The opening at the top of the guidepole and along the exposed sides is typically
the emission source. However, evaporative loss from the top of the guidepole can be
reduced by placing a float inside the guidepole.
9. Vacuum breaker. A vacuum breaker equalizes the pressure of the vapor space
across the deck as the deck is either being landed on or floated off its legs. A typical
vacuum breaker is shown in Figure 12.2-5e. As depicted in this figure, the vacuum breaker
consists of a well with a cover. Attached to the underside of the cover is a guided leg long
enough to contact the tank bottom as the floating deck approaches. When in contact with the
tank bottom, the guided leg mechanically opens the breaker by lifting the cover off the well;
otherwise, the cover closes the well. The closure may be gasketed or ungasketed. Because
the purpose of the vacuum breaker is to allow the free exchange of air and/or vapor, the well
does not extend appreciably below the deck.
12-10 EMISSION FACTORS 10/92
-------
Tank Wall
•ff
Metallic
Weather Sheild
Floating Roof
Scuff Band
Liquid Riled
Tub*
a. Liquid-filled seal with
weather shield.
r— Tank Watt
\ /ft /—Metallic
\ P^C Weathtr Sh*iw
^*H
I iJ.
•Floating Roof
b- Seal Fabric
c. Vapor-mounted resilient
foam-filled seal with
weather shield.
Tank Wall
Envelope
Shoe
Floating Roof
b. Metallic shoe seal.
Metallic
Weather Sheild
Floating Roof
Seal Fabric
d. Liquid-mounted resilient
foam-filled seal with
weather shield.
Figure 12.2-1. Primary seals.'
10/92
Storage of Organic Liquids
12-11
-------
•Tank Wall
Rim-Mountod
Secondary Seal
Floating Roof
Shoo
a. Shoe seal with rim-mounted
secondary seal.
•TankWaM
Rim-Mounted
Secondary Seal
Floating Roof
>-Seal Fabric
RetiRtm
Foam Log
Vapor Space
c. Resilient foam seal (vapor-
mounted) with rim-mounted
secondary seal.
•Tank Wall
Rim-Mounted
Secondary Seal
Floating Roof
V Scuff Band
Liquid-Filled
Tub*
b. Liquid-filled seal with rim-
mounted secondary seal.
r—Tank Wai
\ H* y—Rim-Mounted
\ ^jf Secondary Seal
Floating Roof
>— Seal Fabric
Resident
Foam Log
d.
Resilient foam seal (liquid
mounted) with rim-mounted
secondary seal.
Figure 12.2-2. Rim-mounted secondary seals
on external floating roofs.
12-12
EMISSION FACTORS
10/92
-------
•Tank Wall
Secondary Saal
(Wiper Type)
Envelope
Shoe
Floating Roof
Vapor Space
Jii
Figure 12.2-3. Metallic shoe seal with shoe-mounted secondary seal.
10/92
Storage of Organic Liquids
12-13
-------
/—
(Fv
Handfc
a. Access hatch
Cord
Gasket
FSpesleere a
Gtaiut
Liquid leva*
y-Wett
/- Floating roof
-Floating
roof
Liquid terel
c. Gauge-hatch/sample well
b. Gauge-float well
Tankahell
Primary-seal
fabric
Primary-seal
shoe
Floating roof
rim
Rim vapor
tpae*
Liquid level
d. Rim vent
Cabto
Slidjog cover
roof
FkMt
Rim Teot
12-14
Figure 12.2-4. Roof fittings for external floating roof tanks.3
EMISSION FACTORS
10/92
-------
Screened
coyer
Overflow
roof drain '
a. Overflow drain
Floating roof
Liquid lerei
AJternatiTe pinbote
Adjustable leg
b. Roof leg
Floating roof
c. Unslotted guide pole well
d. Slotted guide pole/sample well
AttoflMtrre pnhole
roof
e. Vacuum breaker
Figure 12.2-5. Roof fittings for external floating roof tanks.3
10/92
Storage of Organic Liquids
12-15
-------
12.2.3 Internal Floating Roof Tanks4-5
Total emissions from internal floating roof tanks are the sum of withdrawal losses and
standing storage losses. Withdrawal losses occur in the same manner as in external floating
roof tanks: as the floating roof lowers, some liquid remains attached to the tank surface and
evaporates. Also, in internal floating roof tanks that have a column-supported fixed roof,
some liquid clings to the columns. Standing storage losses from internal floating roof tanks
include rim seal, deck fitting, and deck seam losses. The loss mechanisms described in
Section 12.2.2 for external floating roof rim seal and roof fitting losses also apply to internal
floating roofs. However, unlike external floating roof tanks in which wind is the
predominant factor affecting rim seal loss, no dominant wind loss mechanism has been
identified for internal floating roof tank rim seal losses. Deck seams in internal floating roof
tanks are a source of emissions to the extent that these seams may not be completely vapor
tight. The loss mechanisms described in Section 12.2.2 for external floating roof tank rim
seals and roof fittings can describe internal floating roof deck seam losses. As with internal
floating roof rim seal and roof fittings, the relative importance of each of the loss
mechanisms is not known. It should be noted that welded internal floating roofs do not have
deck seam losses.
Internal floating roofs typically incorporate one of two types of flexible,
product-resistant seals: resilient foam-filled seals or wiper seals. Similar to those used on
external floating roofs, each of these seals closes the annular vapor space between the edge
of the floating roof and the tank shell to reduce evaporative losses. They are designed to
compensate for small irregularities in the tank shell and allow the roof to move freely up and
down in the tank without binding.
A resilient foam-filled seal used on an internal floating roof is similar in design to that
described in Section 12.2.2 for external floating roofs. Two types of resilient foam-filled
seals for internal floating roofs are shown in Figures 12.2-6a and 12.2-6b. These seals can
be mounted either in contact with the liquid surface (liquid-mounted) or several centimeters
above the liquid surface (vapor-mounted).
Resilient foam-filled seals work because of the expansion and contraction of a resilient
material to maintain contact with the tank shell while accommodating varying annular rim
space widths. These seals consist of a core of open-cell foam encapsulated in a coated
fabric. The elasticity of the foam core pushes the fabric into contact with the tank shell.
The seals are attached to a mounting on the deck perimeter and are continuous around the
roof circumference. Poiyurethane-coated nylon fabric and polyurethane foam are commonly
used materials. For emission control, it is important that the mounting and radial seal joints
be vapor-tight and that the seal be in substantial contact with the tank shell.
Wiper seals are commonly used as primary seals for internal floating roof tanks. This
type of seal is depicted in Figure 12.2-6c. New tanks with wiper seals may have dual
wipers, one mounted above the other.
12-16 EMISSION FACTORS 10/92
-------
Wiper seals generally consist of a continuous annular blade of flexible material
fastened to a mounting bracket on the deck perimeter that spans the annular rim space and
contacts the tank shell. The mounting is such that the blade is flexed, and its elasticity
provides a sealing pressure against the tank shell. Such seals are vapor-mounted; a vapor
space exists between the liquid stock and the bottom of the seal. For emission control, it is
important that the mounting be vapor-tight, that the seal be continuous around the
circumference of the roof, and that the blade be in substantial contact with the tank shell.
Two types of materials are commonly used to make the wipers. One type consists of
a cellular, elastomeric material tapered in cross section with the thicker portion at the
mounting. Buna-N rubber is a commonly used material. All radial joints in the blade are
joined.
A second type of wiper seal construction uses a foam core wrapped with a coated
fabric. Polyurethane on nylon fabric and polyurethane foam are common materials. The
core provides the flexibility and support, while the fabric provides the vapor barrier and wear
surface.
Secondary seals may be used to provide some additional evaporative loss control over
that achieved by the primary seal. The secondary seal is mounted to an extended vertical
rim plate, above the primary seal, as shown in Figure 12.2-7. Secondary seals can be either
a resilient foam-filled seal or an elastomeric wiper seal, as previously described. For a given
roof design, using a secondary seal further limits the operating capacity of a tank due to the
need to keep the seal from interfering with the fixed-roof rafters when the tank is filled.
Numerous deck fittings penetrate or are attached to an internal floating roof. These
fittings accommodate structural support members or allow for operational functions. The
fittings can be a source of evaporative loss in that they require penetrations in the deck.
Other accessories are used that do not penetrate the deck and are not, therefore, sources of
evaporative loss. The most common fittings relevant to controlling vapor losses are
described in the following paragraphs.
The access hatches, guide-pole wells, roof legs, vacuum breakers, and automatic
gauge float wells for internal floating roofs are similar fittings to those already described for
external floating roofs. Other fittings used on internal floating roof tanks include column
wells, ladder wells, and stub drains.
1. Column wells. The most common fixed-roof designs are normally supported from
inside the tank by means of vertical columns, which necessarily penetrate an internal floating
deck. (Some fixed roofs are entirely self-supporting and, therefore, have no support
columns.) Column wells are similar to unslotted guide pole wells on external floating roofs.
Columns are made of pipe with circular cross sections or of structural shapes with irregular
cross sections (built-up). The number of columns varies with tank diameter from a minimum
of 1 to over 50 for very large tanks.
10/92 Storage of Organic Liquids 12-17
-------
The columns pass through deck openings via peripheral vertical wells. With
noncontact decks, the well should extend down into the liquid stock. Generally, a closure
device exists between the top of the well and the column. Several proprietary designs exist
for this closure, including sliding covers and fabric sleeves, which must accommodate the
movements of the deck relative to the column as the liquid level changes. A sliding cover
rests on the upper rim of the column well (which is normally fixed to the roof) and bridges
the gap or space between the column well and the column. The cover, which has a cutout,
or opening, around the column slides vertically relative to the column as the roof raises and
lowers. At the same time, the cover slides horizontally relative to the rim of the well, which
is fixed to the roof. A gasket around the rim of the well reduces emissions from this fitting.
A flexible fabric sleeve seal between the rim of the well and the column (with a cutout or
opening, to allow vertical motion of the seal relative to the columns) similarly accommodates
limited horizontal motion of the roof relative to the column. A third design combines the
advantages of the flexible fabric sleeve seal with a well that excludes all but a small portion
of the liquid surface from direct exchange with the vapor space above the floating roof.
2. Ladder wells. Some tanks are equipped with internal ladders that extend from a
manhole in the fixed roof to the tank bottom. The deck opening through which the ladder
passes is constructed with similar design details and considerations to deck openings for
column wells, as previously discussed.
3. Stub drains. Bolted internal floating roof decks are typically equipped with stub
drains to allow any stored product that may be on the deck surface to drain back to the
underside of the deck. The drains are attached so that they are flush with the upper deck.
Stub drains are approximately 1 inch in diameter and extend down into the product on
noncontact decks.
12-18
EMISSION FACTORS
10/92
-------
FLEXIBLE WIPER
/.SECONDARY SEAL
RESILIENT FILLED SEAL
S'(VAPOR-MOUNTED)
\
LIQUID LEVEL
NBUOYANT PANEL DECK
a. Resilient foam-filled seal (vapor-mounted).
RESILIENT FILLED SEAL
(LIQUID-MOUNTED)
RIM PLATE
LIQUID LEVEL
J
^PAN-TYPE DECK
-TANK SHELL
b. Resilient foam-filled seal (liquid-mounted).
7
yl-LCA
r
\IQUI
IDLE wircn OE*M.
\ z_-
; u
mf^nnm
D LEVEL \
XPONTOO
N
/
' , COVER
A WELL
r /
\ '
^DECK
c. Elastomeric wiper seal.
Figure 12.2-6. Typical floatation devices and perimeter
seals for internal floating roofs.4
10/92
Storage of Organic Liquids
12-19
-------
SceondaiyMal
Primary seal immersed in VOL
Contact-type internal floatinf roof
Figure 12.2-7. Rim-mounted secondary seal on an internal floating
12-20
EMISSION FACTORS
10/92
-------
12.3 EMISSION ESTIMATION PROCEDURES
The following section presents the emission estimation procedures for fixed roof,
external floating roof, and internal floating roof tanks. These procedures are valid for all
petroleum liquids, pure volatile organic liquids, and chemical mixtures with similar true
vapor pressures. It is important to note that in all the emission estimation procedures the
physical properties of the vapor do not include the noncondensibles (e.g., air) in the gas but
only refer to the condensible components of the stored liquid. To aid in the emission
estimation procedures, a list of variables with their corresponding definitions was developed
and is presented in Table 12.3-1.
The factors presented in AP-42 are those that are currently available and have been
reviewed and approved by the U. S. Environmental Protection Agency. As storage tank
equipment vendors design new floating decks and equipment, new emission factors may be
developed based on that equipment. If the new emission factors are reviewed and approved,
the emission factors will be added to AP-42 during the next update.
The emission estimatioa procedures outlined in this chapter have been used as the
basis for the development of a software program to estimate emissions from storage tanks.
The software program entitled "TANKS" is available through the Bulletin Board System
maintained by the U. S. Environmental Protection Agency.
12.3.1 Total Losses From Fixed Roof Tanks4'6"12
The following equations, provided to estimate standing storage and working loss
emissions, apply to tanks with vertical cylindrical shells and fixed roofs. These tanks must
be substantially liquid- and vapor-tight and must operate approximately at atmospheric
pressure. Total losses from fixed roof tanks are equal to the sum of the standing storage loss
and working loss:
LT = Ls + LW (1-1)
where:
Lj = total losses, Ib/yr
LS = standing storage losses, Ib/yr
Lw = working losses, Ib/yr
10/92
Storage of Organic Liquids 12-21
-------
Standing Storage Loss - Fixed roof tank breathing or standing storage losses can be estimated
from:
Ls = 365 VVWVKEKS (1-2)
where:
Ls = standing storage loss, Ib/yr
Vv = vapor space volume, ft3
Wv = vapor density, Ib/ft3
KE = vapor space expansion factor, dimensionless
Ks = vented vapor saturation factor, dimensionless
365 = constant, days/year
Tank Vapor Space Volume. Vv - The tank vapor space volume is calculated using the
following equation:
(1-3)
where:
Vv = vapor space volume, ft3
D = tank diameter, ft, see Note 1 for horizontal tanks
Hvo = vapor space outage, ft
The vapor space outage, Hvo is the height of a cylinder of tank diameter, D, whose
volume is equivalent to the vapor space volume of a fixed roof tank, including the volume
under the cone or dome roof. The vapor space outage, Hvo, is estimated from:
Hvo = Hs - HL + HRO (1-4)
where:
Hvo = vapor space outage, ft
Hs = tank shell height, ft
12-22 EMISSION FACTORS 10/92
-------
HL = liquid height, ft
HRO = roof outage, ft; see Note 2 for a cone roof or Note 3 for a dome roof
Notes:
1. The emission estimating equations presented above were developed for vertical fixed roof
tanks. If a user needs to estimate emissions from a horizontal fixed roof tank, some of the
tank parameters can be modified before using the vertical tank emission estimating equations.
First, by assuming that the tank is one-half filled, the surface area of the liquid in the tank is
approximately equal to the length of the tank times the diameter of the tank. Next, assume
that this area represents a circle, i.e., that the liquid is an upright cylinder. Therefore, the
effective diameter, DE, is then equal to:
(1-5)
where:
DE = effective tank diameter, ft
L = length of tank, ft
D = actual diameter of tank, ft
One-half of the actual diameter of the horizontal tank should be used as the vapor space
outage, Hvo. This method yields only a very approximate value for emissions from
horizontal storage tanks. For underground horizontal tanks, assume that no breathing or
standing storage losses occur (1^=0) because the insulating nature of the earth limits the
diurnal temperature change. No modifications to the working loss equation are necessary for
either above-ground or underground horizontal tanks.
2. For a cone roof, the roof outage, HRO, is calculated as follows:
HRO - 1/3 HR (1-6)
where:
HRO = roof outage (or shell height equivalent to the volume contained under the
roof), ft
HR = tank roof height, ft
10/92 Storage of Organic Liquids 12-23
-------
The tank roof height, HR, is equal to SR Rs
where,
SR = tank cone roof slope, if unknown, a standard value of 0.0625 ft/ft is used,
ft/ft
Rs = tank shell radius, ft
3. For a dome roof, the roof outage, HRO, is calculated as follows:
"RO ~
1/2 +1/6
(1-7)
where:
(1-8)
HRO = roof outage, ft
HR = tank roof height, ft
Rs = tank shell radius, ft
The tank roof height, HR, is calculated:
HR - RR - (RR2 - RS2)°-5
where:
HR — tank roof height, ft
RR = tank dome roof radius, ft
Rs = tank shell radius, ft
The value of RR usually ranges from 0.8D - 1.2D. If RR is unknown, the tank diameter is
used in its place. If the tank diameter is used as the value for RR, Equations 1-7 and 1-8
reduce to HR = 0.268 Rs and HRO = 0.137 Rs.
12-24
EMISSION FACTORS
10/92
-------
Density. Wv - The density of vapor is calculated using the following equation:
W „
v
where:
Wv = vapor density, Ib/ft3
Mv = vapor molecular weight, Ib/lb-mole; see Note 1
R = the ideal gas constant, 10.731 psia-ftVlb-mole^R
PVA = vapor pressure at daily average liquid surface temperature, psia; see Notes 1
and 2
TLA = daily average liquid surface temperature, °R; see Note 3
Notes:
1. The molecular weight of the vapor, Mv, can be determined from Table 12.3-2 and
Table 12.3-3 for selected petroleum liquids and volatile organic liquids, respectively, or by
analyzing vapor samples. Where mixtures of organic liquids are stored in a tank, My can be
calculated from the liquid composition. The molecular weight of the vapor, Mv, is equal to
the sum of the molecular weight, Mi5 multiplied by the vapor mole fraction, yb for each
component. The vapor mole fraction is equal to the partial pressure of component i divided
by the total vapor pressure. The partial pressure of component i is equal to the true vapor
pressure of component i (P) multiplied by the liquid mole fraction, (x-). Therefore,
Mv = S
where: PVA. total vapor pressure of the stored liquid, by Raoult's law, is:
PVA = EPXi (1-11)
For more detailed information, please refer to Section 12.4.
2. True vapor pressure is the equilibrium partial pressure exerted by a volatile organic
liquid, as defined by ASTM-D 2879 or as obtained from standard reference texts. Reid
vapor pressure is the absolute vapor pressure of volatile crude oil and volatile nonviscous
petroleum liquids, except liquified petroleum gases, as determined by ASTM-D-323. True
vapor pressures for organic liquids can be determined from Table 12.3-3. True vapor
pressure can be determined for crude oils using Figures 12.3-1A and 12.3-1B. For refined
10/92 Storage of Organic Liquids 12-25
-------
stocks (gasolines and naphthas), Table 12.3-2 or Figures 12.3-2A and 12-3-2B can be used.
In order to use Figures 12.3-1A, 12.3-1B, 12.3-2A, or 12.3-2B, the stored liquid surface
temperature, TLA, must be determined in degrees Fahrenheit. See Note 3 to determine TLA.
Alternatively, true vapor pressure for selected petroleum liquid stocks, at the stored
liquid surface temperature, can be determined using the following equation:
PVA = exp [A - (B/TLA)] (l-12a)
where:
exp = exponential function
A = constant in the vapor pressure equation, dimensionless
B = constant in the vapor pressure equation, °R
TLA = daily average liquid surface temperature, °R
PVA = true vapor pressure, psia
For selected petroleum liquid stocks, values for the constants A and B are listed in
Table 12.3-2. For refined petroleum stocks, the constants A and B can be calculated from
the equations presented in Figure 12.3-3 and the distillation slopes presented in Table 12.3-4.
For crude oil stocks, the constants A and B can be calculated from the equations presented in
Figure 12.3-4. Note that in Equation 1-12, TLA is determined in degrees Rankine instead of
degrees Fahrenheit.
The true vapor pressure of organic liquids at the stored liquid temperature can be
estimated by Antoines equation:
T j. f*
XLA *-
where:
A = constant in vapor pressure equation
B = constant in vapor pressure equation
C = constant in vapor pressure equation
TLA = average liquid surface temperature, °C
PVA = vapor pressure at average liquid surface temperature, mm Hg
12-26 EMISSION FACTORS 10/92
-------
For organic liquids, the values for the constants A, B, and C are listed in
Table 12.3-5. Note that in equation 1-125, TLA is determined in degrees Celsius instead of
degrees Rankine. Also, in equation l-12b, PVA is determined in mm of Hg rather than psia
(760 mm Hg = 14.696 psia).
3. If the daily average liquid surface temperature, TLA, is unknown, it is calculated using
the following equation:
TLA = 0.44TAA + 0.56TB + 0.0079 al (1-13)
where:
TLA = daily average liquid surface temperature, °R
TAA = daily average ambient temperature, °R; see Note 4
TB = liquid bulk temperature, °R; see Note 5
a = tank paint solar absorptance, dimensionless; see Table 12.3-7
I = daily total solar insolation factor, Btu/ft^day; see Table 12.3-6
If TLA is used to calculate PVA from Figures 12.3.1 A through 12.3.2B, TLA must be
converted from degrees Rankine to degrees Fahrenheit (°F = °R - 460). If TLA is used to
calculate PVA from Equation l-12b, TLA must be converted from degrees Rankine to degrees
Celsius (°C = (°R - 492)/1.8). Equation 1-13 should not be used to estimate emissions
from insulated tanks. In the case of insulated tanks, the average liquid surface temperature
should be based on liquid surface temperature measurements from the tank.
4. The daily average ambient temperature, T^, is calculated using the following equation:
TAA = (TAX + TAN)^ (
where:
TAA = daily average ambient temperature, °R
T^ = daily maximum ambient temperature, °R
TAN = daily minimum ambient temperature, °R
Table 12.3-6 gives values of T^ and T^ for select U.S. cities.
10/92 Storage of Organic Liquids 12-27
-------
5. The liquid bulk temperature, TB, is calculated using the following equation:
TB = TAA + 6a - 1 (1-15)
where:
TB = liquid bulk temperature, °R
TAA = daity average ambient temperature, °R, as calculated in Note 4
a = tank paint solar absorptance, dimensionless; see Table 12.3-7.
Vapor Space Expansion Factor, KE - The vapor space expansion factor, KE, is calculated
using the following equation:
^V.
E T P -P
AIA rA rVA
where:
ATV = daily vapor temperature range, °R; see Note 1
APV = daily vapor pressure range, psi; see Note 2
APB = breather vent pressure setting range, psi; see Note 3
PA = atmospheric pressure, 14.7 psia
PVA = vapor pressure at daily average liquid surface temperature, psia; see Notes 1
and 2 for Equation 1-9
TLA = daily average liquid surface temperature, °R; see Note 3 for Equation 1-9
Notes:
1. The daily vapor temperature range ATV, is calculated using the following equation:
ATV = 0.72 ATA + 0.028 al (1-17)
where:
ATV = daily vapor temperature range, °R
ATA = daily ambient temperature range, °R; see Note 4
12-28 EMISSION FACTORS 10/92
-------
a - tank paint solar absorptance, dimensionless; see Table 12.3-7
I = daily total solar insolation factor, Btu/ft^day; see Table 12.3-6
2. The daily vapor pressure range, APV, can be calculated using the following equation:
APV = PVX - PVN (1-18)
where:
APV = daily vapor pressure range, psia
PVX = vapor pressure at the daily maximum liquid surface temperature, psia; see Note
5
PVN = vapor pressure at the daily minimum liquid surface temperature, psia; see Note
5
The following method can be used as an alternate means of calculating APV for
petroleum liquids:
. 0.50BPVAATV
v T 2
*LA
where:
APV = daily vapor pressure range, psia
B = constant in the vapor pressure equation, °R; see Note 2 to Equation 1-9
PVA = vapor pressure at the daily average liquid surface temperature, psia; see
Notes 1 and 2 to Equation 1-9
TLA = daily average liquid surface temperature, °R; see Note 3 to Equation 1-9
ATV = daily vapor temperature range, °R; see Note 1
3. The breather vent pressure setting range, APB, is calculated using the following equation:
APB = PBP - PBV (1-20)
where:
APB = breather vent pressure setting range, psig
10/92 Storage of Organic Liquids 12-29
-------
PBP = breather vent pressure setting, psig
PBV = breather vent vacuum setting, psig
If specific information on the breather vent pressure setting and vacuum setting is not:
available, assume 0.03 psig for PBP and -0.03 psig for PBV as typical values. If the fixed
roof tank is of bolted or riveted construction in which the roof or shell plates are not vapor
tight, assume that APB = 0, even if a breather vent is used. The estimating equations for
fixed roof tanks do not apply to either low or high pressure tanks. If the breather vent
pressure or vacuum setting exceeds 1.0 psig, the standing storage losses could potentially be
negative.
4. The daily ambient temperature range, ATA, is calculated using the following equation:
ATA=TAX-TAN (1-21)
where:
ATA = daily ambient temperature range, °R
TAX = daily maximum ambient temperature, °R
TAN = daily minimum ambient temperature, °R
Table 12.3-6 gives values of T^ and T^ for select cities in the United States.11
5. The vapor pressures associated with daily maximum and minimum liquid surface
temperature, Pyx ^d PVN, respectively are calculated by substituting the corresponding
temperatures, TLX and TLN into the pressure function discussed in Notes 1 and 2 to
Equation 1-9. If TLX and TLN are unknown, Figure 12.3-5 can be used to calculate their
values.
Vented Vapor Saturation Factor. K5 - The vented vapor saturation factor, Ks, is calculated
using the following equation:
1 (1-22)
0.053 PVAHVO
where:
Ks = vented vapor saturation factor, dimensionless
= vapor pressure at daily average liquid surface temperature, psia; see Notes 1
and 2 to Equation 1-9
12-30
vapor space outage, ft, as calculated in Equation 1-4
EMISSION FACTORS
10/92
-------
Working Loss - The working loss, LW, can be estimated from:
Lw = 0.0010 MVPVAQKNKP, (1-23)
where:
LW = working losses, Ib/yr
Mv = vapor molecular weight, Ib/lb-mole; see Note 1 to Equation 1-9
PVA = vapor pressure at daily average liquid surface temperature, psia; see Notes 1
and 2 to Equation 1-9
Q = annual net throughput, bbl/yr
KN = turnover factor, dimensionless; see Figure 12.3-6
for turnovers > 36, KN = (180 + N)/6N
for turnovers < 36, KN = 1
N = number of turnovers per year, dimensionless
N = -
where:
N = number of turnovers per year, dimensionless
Q = annual net throughput, bbl/yr
VLX = tank maximum liquid volume, ft3
VLX = — D2H,Y (1-25)
4
where:
D = diameter, ft
HLX = maximum liquid height, ft
Kp = working loss product factor, dimensionless, 0.75 for crude oils. For all other
organic liquids, Kp = 1
10/92 Storage of Organic Liquids 12-31
-------
F
o.s
i-
0.
>
S
w
• 10
11
12
13
14
IS
20
E
I
H-10
1—15
Figure 12.3-1A. True vapor pressure of crude oils with a
Reid vapor pressure of 2 to 15 pounds per square inch.4
140
130
120
110
100
90
80
70
60
50
40
30
20 —=
10
0 —B
I
1
12-32
EMISSION FACTORS
10/92
-------
• 0.20
— 0.30
— 0.40
0.50
• 0.60
0.70
0.80
0.90
1.00
— 1.50
2.00
J7- 2.50
E- 3.oo
E- 3.50
=- 4.00
ELA02-
5- 6.00
— 7.00
8.00
9.00
— 10.0
•11.0
-12.0
•13.0
•14.0
•15.0
•16.0
•17.0
•18.0
•19.0
•20.0
-21.0
• 22.0
•23.0
-240
Notes:
1.5- slope of the ASTM distillation curve at 10 percent evaporated, in degrees
Fahrenheit per percent
- [(°F at 15 percent) - (°F at 5 percem)]/(10 percent).
In the absence of distillation data, the following average values of 5 may be used:
Motor gasoline—3.0.
Aviation gasoline—2.0.
Light naphtha {RVP of 9-14 pounds per square inch)—3.5.
Naphtha (RVP of 2-8 pounds per square inch)—2.5.
2. The broken line illustrates a sample problem for a gasoline stock (5 - 3.0) with a
Reid vapor pressure of 10 pounds per square inch and a stock temperature of 62.5°F.
120-
110 —
100-
90 —
80—
70 —
60 —
50-
40 —
30—
20-
10 —
0-3
Figure 12.3-2A. True vapor pressure of refined petroleum stocks with a Reid
vapor pressure of 1 to 20 pounds per square inch.4
10/92
Storage of Organic Liquids
12-33
-------
p "
Where:
- 2-227
- (rib) + 12-82)
P = stock true vapor pressure, in pounds per square inch absolute.
7 = stock temperature, in degrees Fahrenheit.
RVP = Reid vapor pressure, in pounds per square inch.
Note: This equation wa* derived from a regression analysis of point* read off Figure 12.3-1 A over the full range of Reid vapor
pressure slopes of the ASTM distillation curve at 10 percent evaporated, and stock temperatures. In general, the equation yields
P values that are within +0.05 pound per square inch absolute of the values obtained directly from the nomograph.
Figure 12.3-IB. Equation for true vapor pressure of crude oils
with a Reid vapor pressure of 2 to 15 pounds per square inch.4
rO.3
Where:
P = stock true vapor pressure, in pounds per square inch absolute.
T = stock temperature, in degrees Fahrenheit.
RVP = Reid vapor pressure, in pounds per square inch.
S = slope of the ASTM distillation curve at 10 percent, evaporated, in
degrees Fahrenheit per percent.
Note: This equation was derived from a regression analysis of points read off Figure 12.3-2A over the full range of Reid vapor
pressure slopes of the ASTM distillation curve at 10 percent evaporated, and stock temperatures. In general, the equation yields
P value* that are within +0.05 pound per square inch absolute of the value* obtained directly from the nomograph.
Figure 12.3-2B. Equation for true vapor pressure of refined
petroleum stocks with a Reid vapor pressure of
1 to 20 pounds per square inch.4
A = 15.64 - 1.854 S0-5 - (0.8742-0.3280 S°-5)ln(RVP)
B = 8,742 - 1,042 S0-3 - (1,049-179.4 S°-3)ln(RVF)
where:
RVP = stock Reid vapor pressure, psi
In = natural logarithm function
S = stock ASTM-D86 distillation slope at 10 volume percent
evaporation (°F/vol %)
Figure 12.3-3. Equations to determine vapor pressure constants A and B for refined
petroleum stocks.6
12-34
EMISSION FACTORS
10/92
-------
A = 12.82 - 0.9672 In (RVP)
B = 7,261 - 1,216 In (RVP)
where:
RVP = stock Reid vapor pressure, psi
In = natural logarithm function
Figure 12.3-4. Equations to determine vapor pressure Constants A and B
for crude oils stocks.6
Daily Maximum and Minimum Liquid Surface Temperature, (°R)
TLX = TLA + 0.25 ATV
TLN = TLA - 0.25 ATV
where:
TLX = daily maximum liquid surface temperature, °R
TLA is as defined in Note 3 to Equation 1-9
ATV is as defined in Note 1 to Equation 1-16
TLN = daily minimum liquid surface temperature, °R
Figure 12.3-5. Equations for the daily maximum and minimum liquid surface temperatures/
10/92 Storage of Organic Liquids 12-35
-------
1.0
0.8
OS
1 "•'
fc 0.4
0.2
0
100
200
300
400
TURNOVER PER YEAR = ANNUAL THROUGHPUT
TANK CAPACITY
Note: For 36 turnovers per year or less, K* = 1.0
Figure 12.3-6. Turnover factor (KN) for fixed roof tanks/
12-36
EMISSION FACTORS
10/92
-------
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10/92
Storage of Organic Liquids
12-37
-------
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EMISSION FACTORS
10/92
-------
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-------
TABLE 12.3-4 ASTM DISTILLATION SLOPE FOR SELECTED REFINED PETROLEUM
STOCKS8
Refined petroleum stock
Aviation gasoline
Naptha
Motor gasoline
Light naptha
Reid vapor pressure, RVP
(psi)
~
2-8
—
9-14
ASTM-D86 distillation
slope at 10 volume percent
evaporated, (°F/vol%)
2.0
2.5
3.0
3.5
Reference 6.
12-42
EMISSION FACTORS
10/92
-------
TABLE 12.3-5. VAPOR PRESSURE EQUATION CONSTANTS
FOR ORGANIC LIQUIDS*
Name
Acetaldehyde
Acetic acid
Acetic anhydride
Acetone
Acetonitrile
Acrylamide
Acrylic acid
Acrylonitrile
Aniline
Benzene
Butanol (iso)
Butanol-(l)
Carbon disulfide
Carbon tetrachloride
Chlorobenzene
Chloroform
Chloroprene
Cresol(-M)
Cresol(-O)
Cresol(-P)
Cumene (isopropylbenzene)
Cyclohexane
Cyclohexanol
Cyclohexanone
Dichloroethane(l,2)
Dichloroethy lene( 1 , 2)
Diethyl (N,N) anilin
Dimethyl formamide
Dimethyl hydrazine (1,1)
Dimethyl phthalate
Dinitrobenzene
Dioxane(l,4)
Epichlorohydrin
Ethanol
Ethanolamine(mono-)
Ethyl acrylate
Ethyl chloride
Ethylacetate
Ethylbenzene
Vapor pressure equation constants
A
(dimensioless)
8.005
7.387
7.149
7.117
7.119
11.2932
5.652
7.038
7.32
6.905
7.4743
7.4768
6.942
6.934
6.978
6.493
6.161
7.508
6.911
7.035
6.963
6.841
6.255
7.8492
7.025
6.965
7.466
6.928
7.408
4.522
4.337
7.431
8.2294
8.321
7.456
7.9645
6.986
7.101
6.975
B
(°C)
1600.017
1533.313
1444.718
1210.595
1314.4
3939.877
648.629
1232.53
1731.515
1211.033
1314.19
1362.39
1169.11
1242.43
1431.05
929.44
783.45
1856.36
1435.5
1511.08
1460.793
1201.53
912.87
2137.192
1272.3
1141.9
1993.57
1400.87
1305.91
700.31
229.2
1554.68
2086.816
1718.21
1577.67
1897.011
1030.01
1244.95
1424.255
C
CO
291.809
222.309
199.817
229.664
230
273.16
154.683
222.47
206.049
220.79
186.55
178.77
241.59
230
217.55
196.03
179.7
199.07
165.16
161.85
207.78
222.65
109.13
273.16
222.9
231.9
218.5
196.43
225.53
51.42
-137
240.34
273.16
237.52
173.37
273.16
238.61
217.88
213.21
10/92
Storage of Organic Liquids
12-43
-------
TABLE 12.3-5. (Continued)
IJ Name
Ethylether
|| Formic acid
jjFuran
|] Furfural
||Heptane(iso)
Hexane(-N)
||Hexanol(-l)
|| Hydrocyanic acid
|J Methanol
|| Methyl acetate
1 Methyl ethyl ketone
|j Methyl isobutyl ketone
1 Methyl metharcrylate
| Methyl styrene (alpha)
||Methylene chloride
I Morpholine
| Naphthalene
| Nitrobenzene
|| Pentachloroethane
Phenol
Picoline(-2)
Propanol (iso)
Propylene glycol
Propylene oxide
Pyridine
Resorcinol
Styrene
Tetrachloroethane(l, 1,1,2)
Tetrachloroethane(l, 1,2,2)
Tetrachloroethylene
JTetrahydrofuran
| Toluene
| Trichloro(l, 1 ,2)trifluoroethane
Trichloroethane(l, 1, 1)
| Trichloroethane( 1 , 1 , 2)
1 Trichloroethylene
| Trichlorofluoromethane
| Trichloropropane(l,2,3)
Vinyl acetate
Vapor pressure equation constants
A
(dimensioless)
6.92
7.581
6.975
6.575
6.8994
6.876
7.86
7.528
7.897
7.065
6.9742
6.672
8.409
6.923
7.409
7.7181
7.01
7.115
6.74
7.133
7.032
8.117
8.2082
8.2768
7.041
6.9243
7.14
6.898
6.631
6.98
6.995
6.954
6.88
8.643
6.951
6.518
6.884
6.903
7.21
B
(°Q
1064.07
1699.2
1060.87
1198.7
1331.53
1171.17
1761.26
1329.5
1474.08
1157.63
1209.6
1168.4
2050.5
1486.88
1325.9
1745.8
1733.71
1746.6
1378
1516.79
1415.73
1580.92
2085.9
1656.884
1373.8
1884.547
1574.51
1365.88
1228.1
1386.92
1202.29
1344.8
1099.9
2136.6
1314.41
1018.6
1043.004
788.2
12%. 13
C
(°Q
228.8
260.7
227.74
162.8
212.41
224.41
196.66
260.4
229.13
219.73
216
191.9
274.4
202.4
252.6
235
201.86
201.8
197
174.95
211.63
219.61
203.5396
273.16
214.98
186.0596
224.09
209.74
179.9
217.53
226.25
219.48
227.5
302.8
209.2
192.7
236.88
243.23
226.66
12-44
EMISSION FACTORS
10/92
-------
TABLE 12.3-5. (Continued)
Name
Vinylidene chloride
Xylene(-M)
Xylene<-0)
Vapor pressure equation constants
A
(dimensioless)
6.972
7.009
6.998
B
(°Q
1099.4
1426.266
1474.679
C
(°Q
237.2
215.11
213.69
Reference 10.
10/92
Storage of Organic Liquids
12-45
-------
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12-46
EMISSION FACTORS
10/92
-------
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10/92
Storage of Organic Liquids
12-47
-------
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12-48
EMISSION FACTORS
10/92
-------
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10/92
Storage of Organic Liquids
12-49
-------
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12-50
EMISSION FACTORS
10/92
-------
13
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10/92
Storage of Organic Liquids
12-51
-------
TABLE 12.3-7. PAINT SOLAR ABSORPTANCE FOR FIXED ROOF TANKSa'b-c
Paint color
Aluminum
Aluminum
Gray
Gray
Red
White
Paint shade or type
Specular
Diffuse
Light
Medium
Primer
—
Paint factors (a)
Paint condition
Good
0.39
0.60
0.54
0.68
0.89
0.17
Poor
0.49
0.68
0.63
0.74
0.91
0.34
Reference 6.
blf specific information is not available, a white shell and roof, with the paint in good
condition, can be assumed to represent the most common or typical tank paint in use.
clf the tank roof and shell are painted a different color, a is determined from
a = (C*R + as)/2; where «R is the tank roof paint solar absorptance and as is the tank
shell paint solar absorptance.
12-52
EMISSION FACTORS
10/92
-------
12.3.2 Total Losses From External Floating Roof Tanks3'4-11
Total external floating roof tank emissions are the sum of rim seal, withdrawal, and
roof fitting losses. The equations presented in this subsection apply only to external floating
roof tanks. The equations are not intended to be used in the following applications:
1. To estimate losses from unstable or boiling stocks or from mixtures of
hydrocarbons or petrochemicals for which the vapor pressure is not known or cannot readily
be predicted; or
2. To estimate losses from tanks in which the materials used in the rim seal and/or
roof fitting are either deteriorated or significantly permeated by the stored liquid.
Total losses from external floating roof tanks may be written as:
LT = LR + LWD + LF (2-1)
where:
Lj = total loss, Ib/yr
LR = rim seal loss, Ib/yr; see Equation 2-2
LWQ = withdrawal loss, Ib/yr; see Equation 2-4
LF = roof fitting loss, Ib/yr; see Equation 2-5
Rim Seal Loss - Rim seal loss from floating roof tanks can be estimated using the following
equation:
LR = KRvnP*DMvKc (2-2)
where:
LR = rim seal loss, Ib/yr
KR = seal factor, lb-mole/(mph)nft»yr; see Table 12.3-8 or Note 3
v = average wind speed at tank site, mph; see Note 1 and Note 3
n = seal-related wind speed exponent, dimensionless; see Table 12.3-8 or Note 3
P* = vapor pressure function, dimensionless; see Note 2
10/92 Storage of Organic Liquids 12-53
-------
P* = •
[1 + (1 -
(2-3)
where:
PVA - vapor pressure at daily average liquid surface temperature, psia;
See Notes 1 and 2 to Equation 1-9
PA = atmospheric pressure, 14.7 psia
D = tank diameter, ft
Mv = average vapor molecular weight, Ib/lb-mole; see Note 1 to Equation 1-9,
KC = product factor, Kc = 0.4 for crude oils; KC = 1 for all other organic liquids.
Notes:
1. If the wind speed at the tank site is not available, use wind speed data from the
nearest local weather station or values from Table 12.3-9.
2. P* can be calculated or read directly from Figure 12.3-7.
3. The rim seal loss factor, FR = KRvn, can also be read directly from
Figures 12.3-8 through 12.3-11. Figures 12.3-8 through 12.3-11 present FR for both average
and tight fitting seals. However, it is recommended that only the values for average fitting
seals be used in estimating rim seal losses because of the difficulty in ensuring the seals are
tight fitting at all liquid heights in the tank.
Withdrawal Loss - The withdrawal loss from floating roof storage tanks can be estimated
using Equation 2-4.
_ (0.943)QCWL
- _
(2-4)
where:
c =
= withdrawal loss, Ib/yr
= annual throughput, bbl/yr, (tank capacity [bbl] times annual turnover rate)
shell clingage factor, bbl/1,000 ft2; see Table 12.3-10
= average organic liquid density, Ib/gal; see Note
12-54
EMISSION FACTORS
10/92
-------
D = tank diameter, ft
0.943 = constant, 1,000 ft3 x gal/bbl2
Note: A listing of the average organic liquid density for select petrochemicals is provided in
Tables 12.3-2 and 12.3-3. If WL is not known for gasoline, an average value of
6. 1 Ib/gal can be assumed.
Roof Fitting Loss - The roof fitting loss from external floating roof tanks can be estimated by
the following equation:
LF = FF P*MvKc (2-5)
where:
LF = the roof fitting loss, Ib/yr
^F = total roof fitting loss factor, Ib-mole/yr; see Figures 12.3-12 and 12.3-13
=[(NF1 KF1) +
-------
The roof fitting loss factor, KF. for a particular type of fitting, can be estimated by
the following equation: l
KF = KF + KF vmi (2-7)
where: * ^ D1
Kj = loss factor for a particular type of roof fitting, Ib-moles/yr
KFa. = loss factor for a particular type of roof fitting, Ib-moles/yr
KFb. = loss factor for a particular type of roof fitting, lb-mole/(mph)m«yr
mi = loss factor for a particular type of roof fitting, dimensionless
i= 1, 2, ..., n, dimensionless
v = average wind speed, mph
Loss factors Kp&, Kp, , and m are provided in Table 12.3-11 for the most common
roof fittings used on external floating roof tanks. These factors apply only to typical roof
fitting conditions and when the average wind speed is between 2 and 15 miles per hour.
Typical number of fittings are presented in Tables 12.3-11, 12.3-12, and 12.3-13. Where
tank-specific data for the number and kind of deck fittings are unavailable, FF can be
approximated according to tank diameter. Figures 12.3-12 and 12.3-13 present FF plotted
against tank diameter for pontoon and double-deck external floating roofs, respectively.
12-56 EMISSION FACTORS 10/92
-------
I.W
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
001
-
-
-
-
-
-
;
-
—
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=
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-
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
2 3 4 5 6 7 8 9 10 11 12 13 14 15
Stock true vapor prassurc. P (pounds our squar* inch ateotut*)
Notes:
1. Broken line illustrates sample problem for P = 5.4 pounds per square inch absolute.
2. Curve is for atmospheric pressure, P,, equal to 14.7 pounds per square inch absolute.
Figure 12.3-7. Vapor pressure function.4
10/92
Storage of Organic Liquids
12-57
-------
•B
100
50
5-
1 -
0.5-
0,1-
/
//
t^'
/>
/
/
T
/
/
'/
/
'/
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j/_
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//
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/ |
,
^X
F
r
1
Primary only
Primary and shoe-
mounted secondary
Primary and rim-
mounted secondary
20 30
5 10
Wind speed, V (milea per hour)
Note: Solid line indicates average-fitting seal; broken line indicates tight-fitting seal: F, - K,V.
Figure 12.3-8. Rim-seal loss factor for a welded tank with a
mechanical-shoe primary seal.3
12-58
EMISSION FACTORS
10/92
-------
1
500-
100-
1-
/
/ f
1 f
1 f
' f /
/ /
/
! /
1
//
/
7
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t //*
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//
* "
f
*
/
*
f
weather shield
mounted secondary
weather shield
mounted secondary
5 10 20 30
Wind speed, V (me* per hour)
Note: Solid line indicates average-fitting seal; broken line indicates tight-fining seal; F, » K,V".
Figure 12.3-9. Rim-seal loss factor for a welded tank with a
vapor-mounted, resilient-filled primary seal.3
10/92
Storage of Organic Liquids
12-59
-------
50
Is 10
SL
8
t
S 5
1
uT
S"
3
To
? 1-
0.5-
0.1-
.
^
/,
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^
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s
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^
XI
-L — y^t I
^/ ^
X /
/
^ \ •
1
— Primary only
Primary and
weather shield
Primary and rim-
mounted secondary
1 5 10 20 30
VMnd speed, V (mite per hour)
Note: Solid line indicates average-fitting seal; broken line indicates tight-fitting seal; F, =- K,V".
Figure 12.3-10. Rim-seal loss factor for a welded tank with
a liquid-mounted, resilient-filled primary seal.3
12-60
EMISSION FACTORS
10/92
-------
100
50
10
0.5
0.1
Primary only
Primary and shoe-
mounted secondary
Primary and rim-
mounted secondary
5 10
Wind spMd, V (miles p«r hour)
20 30
Note: Solid line indicates average-fitting seal: F, » K,V.
Figure 12.3-11. Rim-seal loss factor for a riveted tank with a
mechanical-shoe primary seal.3
10/92
Storage of Organic Liquids
12-61
-------
3500
3000
I
I
2500
2000
1500
1000
500
Fi - 1000 + 1.400
I I i i I i i i i I i i i i I i i i
50
100 150 200
Tank diameter, 0 (fMt)
250 300
Figure 12.3-12. Total roof-fitting loss factor for typical
fittings on pontoon floating roofs.3
12-62
EMISSION FACTORS
10/92
-------
3500
3000
2500
2000
1500
1000
500
iii iii
Tank diameter, D (tatt)
Figure 12.3-13. Total roof-fitting loss factor for typical
fittings on double-deck floating roofs.3
10/92
Storage of Organic Liquids
12-63
-------
TABLE 12.3-8. RIM-SEAL LOSS FACTORS, KR and n,
FOR EXTERNAL FLOATING ROOF TANKSa
Tank construction and
rim-seal system
Average-fitting seals
KR
pb-mole/(mph)n-ft-yr]
n
(dimensionless)
Welded tanks
Mechanical-shoe seal
Primary only
Shoe-mounted secondary
Rim-mounted secondary
Liquid-mounted resilient-filled seal
Primary only
Weather shield
Rim-mounted secondary
Vapor-mounted resilient-filled seal
Primary only
Weather shield
Rim-mounted secondary
1.2b
0.8
0.2
1.1
0.8
0.7
1.2
0.9
0.2
1.5b
1.2
1.0
1.0
0.9
0.4
2.3
2.2
2.6
Riveted tanks
Mechanical-shoe seal
Primary only
Shoe-mounted secondary
'Rim-mounted secondary
1.3
1.4
0.2
1.5
1.2
1.6
Reference 3.
b
If no specific information is available, a welded tank with an average-fitting
mechanical-shoe primary seal can be used to represent the most common or typical
construction and rim-seal system in use.
12-64
EMISSION FACTORS
10/92
-------
TABLE 12.3-9. AVERAGE ANNUAL WIND SPEED (v) FOR
FOR SELECTED U.S. LOCATIONS*
Location
Alabama
Birmingham
Huntsville
Mobile
Montgomery
Alaska
Anchorage
Annette
Barrow
Barter Island
Bethel
Settles
Big Delta
Cold Bay
Fairbanks
Gulkana
Homer
Juneau
King Salmon
Kodiak
Kotzebue
McGrath
Nome
St. Paul Island
Talkeetna
Valdez
Yakutat
Arizona
Flagstaff
Phoenix
Tucson
Winslow
Yuma
Arkansas
Fort Smith
Little Rock
California
Bakersfield
Blue Canyon
Wind Speed
(mph)
7.2
8.2
9.0
6.6
6.9
10.6
11.8
13.2
12.8
6.7
8.2
17.0
5.4
6.8
7.6
8.3
10.8
10.8
13.0
5.1
10.7
17.7
4.8
6.0
7.4
6.8
6.3
8.3
8.9
7.8
7.6
7.8
6.4
6.8
Wind
Location
California (continued)
Eureka
Fresno
Long Beach
Los Angeles (City)
Los Angeles International
Airport
Mount Shasta
Sacramento
San Diego
San Francisco (City)
San Francisco
Airport
Santa Maria
Stockton
Colorado
Colorado Springs
Denver
Grand Junction
Pueblo
Connecticut
Bridgeport
Hartford
Delaware
Wilmington
District of Columbia
Dulles Airport
National Airport
Florida
Apalacbicola
Daytona Beach
Fort Myers
Jacksonville
Key West
Miami
Orlando
Speed
(mph)
6.8
6.3
6.4
6.2
7.5
5.1
7.9
6.9
8.7
10.6
7.0
7.5
10.1
8.7
8.1
8.7
12.0
8.5
9.1
7.4
9.4
7.8
8.7
8.1
8.0
11.2
9.3
8.5
Location
Florida (continued)
Pensacola
Tallahassee
Tampa
West Palm Beach
Georgia
Athens
Atlanta
Augusta
Columbus
Macon
Savannah
Hawaii
Hilo
Honolulu
Kahului
Lihue
Idaho
Bosie
Pocatello
Illinois
Cairo
Chicago
Moline
Peoria
Rockford
Springfield
Indiana
Evansville
Fort Wayne
Indianapolis
South Bend
Iowa
DCS Moines
Wind Speed
(mph)
8.4
6.3
8.4
9.6
7.4
9.1
6.5
6.7
7.6
7.9
7.2
11.4
12.8
12.2
8.8
10.2
8.5
10.3
10.0
10.0
10.0
11.2
8.1
10.0
9.6
10.3
10.9
10/92
Storage of Organic Liquids
12-65
-------
TABLE 12.3-9. (Continued)
Wind
Location
Iowa (continued)
Sioux City
Waterloo
Kansas
Concordia
Dodge City
Goodland
Topeka
Wichita
Kentucky
Cincinnati Airport
Jackson
Lexington
Louisville
Louisiana
Baton Rouge
Lake Charles
New Orleans
Shreveport
Maine
Caribou
Portland
Maryland
Baltimore
Massachusetts
Blue Hill Observatory
Boston
Worcester
Michigan
Alpena
Detroit
Flint
Grand Rapids
Speed
(mph)
11.0
10.7
12.3
14.0
12.6
10.2
12.3
9.1
7.2
9.3
8.4
7.6
8.7
8.2
8.4
11.2
8.8
9.2
15.4
12.4
10.2
8.1
10.2
10.2
9.8
Wind
Location
Michigan (continued)
Houghton Lake
Lansing
Muskegon
Sault Sainte Marie
Minnesota
Duluth
International Falls
Minneapolis-Saint Paul
Rochester
Saint Cloud
Mississippi
Jackson
Meridian
Missouri
Columbia
Kansas City
Saint Louis
Springfield
Montana
Billings
Glasgow
Great Falls
Helena
Kalispell
Missoula
Nebraska
Grand Island
Lincoln
Norfolk
North Platte
Omaha
Scotts Bluff
Valentine
Speed
(mph)
8.9
10.0
10.7
9.3
11.1
8.9
10.6
13.1
8.0
7.4
6.1
9.9
10.8
9.7
10.7
11.2
10.8
12.8
7.8
6.6
6.2
11.9
10.4
11.7
10.2
10.6
10.6
9.7
Wind
Location
Nevada
Elko
Ely
Las Vegas
Reno
Winnemucca
New Hampshire
Concord
Mount Washington
New Jersey
Atlantic City
Newark
New Mexico
Albuquerque
Roswell
New York
Albany
Binghamton
Buffalo
New York (Central Park)
New York (JFK Airport)
New York (La Guardia
Airport)
Rochester
Syracuse
North Carolina
Asheville
Cape Hatteras
Charlotte
Greensboro-
High Point
Raleigh
Wilmington
North Dakota
Bismark
Speed
(mph)
6.0
10.3
9.3
6.6
8.0
6.7
35.3
10. 1
10.2
9.1
8.6
8.9
10.3
12.0
9.4
12.0
12.2
9.7
9.5
7.6
11.1
7.5
7.5
7.8
8.8
10.2
12-66
EMISSION FACTORS
10/92
-------
TABLE 12.3-9. (Continued)
Wind
Location
North Dakota (continued)
Fargo
Williston
Ohio
Akron
Cleveland
Columbus
Dayton
Mansfield
Toledo
Youngstown
Oklahoma
Oklahoma City
Tulsa
Oregon
Astoria
Eugene
Medford
Pendleton
Portland
Salem
Sexton Summit
Pennsylvania
Allentown
Avoca
Erie
Harrisburg
Philadelphia
Pittsburgh Int'l. Airport
Williamsport
Puerto Rico
San Juan
Rhode Island
Providence
South Carolina
Charleston
Columbia
Greenville-Spartanburg
"Reference 11.
10/92
Speed
(mph)
12.3
10.1
9.8
10.6
8.5
9.9
11.0
9.4
9.9
12.4
10.3
8.6
7.6
4.8
8.7
7.9
7.1
11.8
9.2
8.3
11.3
7.6
9.5
9.1
7.8
8.4
10.6
8.6
6.9
6.9
Location
South Dakota
Aberdeen
Huron
Rapid City
Sioux Falls
Tennessee
Bristol-Johnson City
Chattanooga
Knoxville
Memphis
Nashville
Oak Ridge
Texas
Abilene
Amarillo
Austin
Brownsville
Corpus Christi
Dalls-Fort Worth
Del Rio
El Paso
Galveston
Houston
Lubbock
Midland-Odessa
Port Arthur
San Angelo
San Antonio
Victoria
Waco
Wichita Falls
Utah
Salt Lake City
Vermont
Burlington
Virginia
Lynchburg
Norfolk
Richmond
Roanoke
Wind Speed
(mph)
11.2
11.5
11.3
11.1
5.5
6.1
7.0
8.9
8.0
4.4
12.0
13.6
9.2
11.5
12.0
10.8
9.9
8.9
11.0
7.9
12.4
11.1
9.8
10.4
9.3
10.1
11.3
11.7
8.9
8.9
7.7
10.7
7.7
8.1
Location
Washington
Olympia
Quillayute
Seattle Int'l.
Spokane
Walls Walls
Yakima
West Virginia
Beckley
Charleston
Elkins
Huntington
Wisconsin
Green Bay
La Crosse
Madison
Milwaukee
Wyoming
Casper
Cheyenne
Lander
Sheridan
Storage of Organic Liquids
Wind Speed
(mph)
6.7
6.1
Airport 9.0
8.9
5.3
7.1
9.1
6.4
6.2
6.6
10.0
8.8
9.9
11.6
12.9
13.0
6.8
8.0
12-6
-------
TABLE 12.3-10. AVERAGE CLINGAGE FACTORS, C
(Barrels per 1,000 square feet)a
Product stored
Gasoline
Single-component stocks
Crude oil
Shell condition
Light
rust
0.0015
0.0015
0.0060
Dense
rust
0.0075
0.0075
0.030
Gunite
lining
0.15
0.15
0.60
Reference 3.
Note: If no specific information is available, the values in this table can be assumed to
represent the most common or typical condition of tanks currently in use.
12-68
EMISSION FACTORS
10/92
-------
TABLE 12.3-11. EXTERNAL FLOATING ROOF-FITTING LOSS FACTORS,
KFa, Kpt,, AND m, AND TYPICAL NUMBER OF ROOF FITTINGS, NF*
Fining type and
construction details 1
Access hatch (24-inch diameter well)
Bolted cover, gasketed
Unbolted cover, ungasketed
Unbolted cover, gasketed
Unslotted guide-pole well (8-inch
diameter unslotted pole, 21-inch
diameter well)
Ungasketed sliding cover
Gasketed sliding cover
Slotted guide-pole/sample well (8 inch
diameter slotted pole, 21 -inch
diameter wall)
Ungasketed sliding cover,
without float
Ungasketed sliding cover, with float
Gasketed sliding cover,
without float
Gasketed sliding cover, with float
Gauge-float well (20-inch diameter)
Unbolted cover, ungasketed
Unbolted cover, gasketed
Bolted cover, gasketed
Gauge-hatch/ sample well (8-inch
diameter)
Weighted mechanical actuation,
gasketed
Weighted mechanical actuation,
ungasketed
Vacuum breaker (10-inch diameter well)
Weighted mechanical actuation,
gasketed
Weighted mechanical actuation,
ungasketed
Roof drain (3-inch diameter)
Open
90% closed
Roof leg (3-inch diameter)
Adjustable, pontoon are*
Adjustable, center are*
Adjustable, double-deck roofs
Fixed
Roof leg (2-1/2 inch diameter)
Adjustable, pontoon are*
Adjustable, center are*
Adjustable, double-deck roofs
Fixed
-------
TABLE 12.3-11. (Continued)
Loss Factor*
Fining type and
construction details
(Ib-mole/yr)
, [Ib-mole/Cmphy-yr]
Typical
number
m (dimensionless) fittings, I
Rim vent (6-inch diameter)
Weighted mechanical actuation,
gasketed
Weighted mechanical actuation,
ungasketed
0.71
0.68
0.10
1.8
1.0b
1.0
Note: The roof-fitting loss factors, KFa, K^,, and m, may only be used for wind speeds
from 2 to 15 miles per hour.
*Reference 3.
kff no specific information is available, this value can be assumed to represent the most
common or typical roof fitting currently in use.
CA slotted guide-pole/sample well is an optional fitting and is not typically used.
dRoof drains that drain excess rainwater into the product are not used on pontoon floating
roofs. They are, however, used on double-deck floating roofs and are typically left open.
eThe most common roof leg diameter is 3 inches. The loss factors for 2-1/2 inch diameter
roof legs are provided for use if this smaller size roof leg is used on a particular floating
roof.
fRim vents are used only with mechanical-shoe primary seals.
12-70
EMISSION FACTORS
10/92
-------
TABLE 12.3-12. EXTERNAL FLOATING ROOF TANKS: TYPICAL NUMBER OF
VACUUM BREAKERS, NF6, AND ROOF DRAINS,
Tank
diameter
D (feet)b
50
100
150
200
250
300
350
400
Number of vacuum breakers, NF6
Pontoon roof
1
1
2
3
4
5
6
7
Double-deck roof
1
1
2
2
3
3
4
4
Number of roof drains,
NFT
(double-deck roof)0
1
1
2
3
5
7
. «
Note: This table was derived from a survey of users and manufacturers. The actual
number of vacuum breakers may vary greatly depending on throughput and
manufacturing prerogatives. The actual number of roof drains may also vary
greatly depending on the design rainfall and manufacturing prerogatives. For tanks
more than 300 feet in diameter, actual tank data or the manufacturer's
recommendations may be needed for the number of roof drains. This table should
not supersede information based on actual tank data.
Reference 3.
blf the actual diameter is between the diameters listed, the closest diameter listed should be
used. If the actual diameter is midway between the diameters listed, the next larger
diameter should be used.
cRoof drains that drain excess rainwater into the product are not used on pontoon floating
roofs. They are, however, used on double-deck floating roofs and are typically left open.
10/92
Storage of Organic Liquids
12-71
-------
TABLE 12.3-13.
EXTERNAL FLOATING ROOF TANKS:
ROOF LEGS, NF8*
TYPICAL NUMBER OF
Tank
diameter, D
(feet)b
30
40
50
60
70
80
90
100
110
120
130
140
150
160
170
180
190
200
210
220
230
240
250
260
270
280
290
300
310
320
330
340
350
Pontoon roof
Number of
pontoon
legs
4
4
6
9
13
15
16
17
18
19
20
21
23
26
27
28
29
30
31
32
33
34
35
36
36
37
38
38
39
39
40
41
42
Number of
center legs
2
4
6
7
9
10
12
16
20
24
28
33
38
42
49
56
62
69
77
83
92
101
109
118
128
138
148
156
168
179
190
202
213
Number of
legs on
double-
deck roof
6
7
8
10
13
16
20
25
29
34
40
46
52
58
66
74
82
90
98
107
115
127
138
149
162
173
186
200
213
226
240
255
270
12-72
EMISSION FACTORS
10/92
-------
TABLE 12.3-13. (Continued)
Tank
diameter, D
(feet)b
360
370
380
390
400
Pontoon roof
Number of
pontoon
legs
44
45
46
47
48
Number of
center legs
226
238
252
266
281
Number of
legs on
double-
deck roof
285
300
315
330
345
Note: This table was derived from a survey of users and manufacturers. The actual number
of roof legs may vary greatly depending on age, style of floating roof, loading
specifications, and manufacturing prerogatives. This table should not supersede
information based on actual tank data.
•Reference 3.
ktf the actual diameter is between the diameters listed, the closest diameter listed should be
used. If the actual diameter is midway between the diameters listed, the next larger
diameter should be used.
10/92
Storage of Organic Liquids
12-73
-------
12.3.3 Total Losses From Internal Floating Roof Tanks4
Total internal floating roof tank emissions are the sum of rim seal, withdrawal, deck
fitting, and deck seam losses.
The equations provided in this section apply only to freely vented internal floating
roof tanks. These equations are not intended to estimate losses from closed internal floating
roof tanks (tanks vented only through a pressure/vacuum vent).
Emissions from internal floating roof tanks may be estimated as:
(3-D
where:
LT = total loss, Ib/yr
LR = rim seal loss, Ib/yr; see Equation 3-2
= withdrawal loss, Ib/yr; see Equation 3-4
LF = deck fitting loss, Ib/yr; see Equation 3-5
LD = deck seam loss, Ib/yr, see Equation 3-6
Rim Seal Loss - Rim seal losses from floating roof tanks can be estimated by the following
equation:
LR = KRP*DMvKc
(3-2)
where:
LR = rim seal loss, Ib/yr
KR = seal factor, lb-mole/(ft-yr); see Table 12.3-14
P* = vapor pressure function, dimensionless; see Note 2 to Equation 2-2
p* =
[1 + (1 - [PVA/PA])05]2
where: PA and PVA are as defined for Equation 2-3
D = tank diameter, ft
12-74 EMISSION FACTORS
(3-3)
10/92
-------
Mv = average vapor molecular weight, Ib/lb-mole; see Note 1 to Equation 1-9
Kc = product factor; KC = 0.4 for crude oils, KC = 1.0 for all other organic liquids
Withdrawal Loss - The withdrawal loss from internal floating roof storage tanks can be
estimated using Equation 3-4:
(3.4)
where:
\
Nc = number of columns, dimensionless; see Note 1
Fc = effective column diameter, ft (column perimeter [ft])/*-); see Note 2
0.943 = constant, 1,000 ft3 x gal/bbl2
LWJ,, Q, C, WL, and D are as defined for Equation 2-4
Notes:
1. For a self-supporting fixed roof or an external floating roof tank:
Nc = 0.
For a column-supported fixed roof:
Nc = use tank-specific information or see Table 12.3-15.
2. Use tank-specific effective column diameter or
Fc = 1.1 for 9-inch by 7-inch built-up columns, 0.7 for 8-inch-diameter pipe
columns, and 1.0 if column construction details are not known
Deck Fitting Losses - Fitting losses from internal floating roof tanks can be estimated by the
following equation:
LF = FFP*MvKc (3-5)
where:
FF = total deck fitting loss factor, Ib-mol/yr
10/92 Storage of Organic Liquids 12-75
-------
= [(NF1KF1)+(NF2KF2)...+(NFnFKFnF)]
where:
Np. = number of deck fittings of a particular type (i = 0, 1, 2, ..., nf),
dimensionless; see Table 12.3-164
Kp. = deck fitting loss factor for a particular type fitting (i = 0, 1, 2, ..., nf)
Ib-mol/yr; see Table 12.3-164
nf = total number of different types of fittings
P*, Mv, and KC are as defined in Equations 2-2 and 2-5.
The value of FF may be calculated by using actual tank-specific data for the number
of each fitting type (NF) and then multiplying by the fitting loss factor for each fitting (KF).
Values of fitting loss factors and typical number of fittings are presented in Table 12.3-16.
Where tank-specific data for the number and kind of deck fittings are unavailable, then FF
can be approximated according to tank diameter. Figures 12.3-14 and 12.3-15 present FF
plotted against tank diameter for column-supported fixed roofs and self-supported fixed roofs,
respectively.
Deck Seam Loss - Welded internal floating roof tanks do not have deck seam losses. Tanks
with bolted decks may have deck seam losses. Deck seam loss can be estimated by the
following equation:
LD = KDSDD2P*MvKc (3-6)
where:
KD = deck seam loss per unit seam length factor, Ib-mol/ft-yr
= 0.0 for welded deck
= 0.34 for bolted deck; see Note
SD = deck seam length factor, ft/ft2
where:
Lscam = total length of deck seams, ft
12-76 EMISSION FACTORS 10/92
-------
Adeck = a1"6* of deck> ft2 = T D2/4
D, P*, Mv, and KC are as defined for Equation 2.2
If the total length of the deck seam is not known, Table 12.3-17 can be used to
determine SD. For a deck constructed from continuous metal sheets with a 7-ft spacing
between the seams, a value of 0.14 ft/ft2 can be used. A value of 0.33 ft/ft2 can be used for
SD when a deck is constructed from rectangular panels 5 ft by 7.5 ft. Where tank-specific
data concerning width of deck sheets or size of deck panels are unavailable, a default value
for SD can be assigned. A value of 0.20 ft/ft2 can be assumed to represent the most common
bolted decks currently in use.
Note: Recently vendors of bolted decks have been using various techniques in an effort to
reduce deck seam losses. However, emission factors are not currently available in
AP-42 that represent the emission reduction achieved by these techniques. Some
vendors have developed specific factors for their deck designs; however, use of these
factors is not recommended until approval has been obtained from the governing
regulatory agency or permitting authority.
10/92 Storage of Organic Liquids 12-77
-------
8500
8000
7500
7000
MOO
6000
5500
5000
4500
4000
3500
3000
2900
1500
1000
•coo
:
j
1
•
1
1
;
'.
|
1111
&
^-(O.C
***
1 I I 1
XTEDOE
>481)£>2 -
Ss
^
1 I 1 1
•CK(S««I>
t- (1.392)
/
//
1 1 1 1
lota)
D + 134.
/
A
/
v /
//
/
/
/
//
1 /
/
/
/
/
//
/
/
r / WELDED DECK
/Ff= (0.0385)D2 -1- (1.392JD + i:
1 1 1 1
J4.2
50 100 150 200 250 300
TANK DIAMETER, D (feet)
360
400
Basis: Fittings include: (1) access hatch with ungasketed, unbolted cover, (2) built-up column wells with ungasketed
unbolted cover, (3) adjustable deck legs; (4) gauge float well with ungasketed, unbolted cover, (5) ladder well
with ungasketed sliding cover; (6) sample well with slit fabric seal (1056 open are*); (7) 1-inch-diameter stub
drains (only on bolted deck); and (8) vacuum breaker with gasketed weighted mechanical actuation. This basis
was derived from * survey of users and manufacturers. Other fittings may be typically used within particular
companies or organizations to reflect standards and/or specifications of that group. This figure should not
supersede information based on actual tank data.
NOTE: If no specification information is available, assume bolted decks are the most common/typical type currently in
use in tanks with column-supported fixed roofs.
Figure 12.3-14. Approximated total deck fitting loss factors (Ff) for typical
fittings in tanks with column-supported fixed roofs and either a bolted deck or
a welded deck. This figure is to be used only when tank-specific data on the
number and kind of deck fittings are unavailable.4
12-78
EMISSION FACTORS
10/92
-------
4500
4000
3500
3000
2500
2000
1500
1000
500
•
-
i
-
-
-
Ff=
•
»
(0.0228)
^
DCTEDDt
ID2 + (0
/
S ^^
ECK
.79)D +
/
A
105.2
y
/
/
/,
/
/
/
WELD
> (0.013'
/
/
/
/
ED DECK
2)D2 + (
/
/
/
(SMNott
0.79)0 H
»
1- 105.2
till
SO 100 ISO 200 2SO 300 350 400
TANK DIAMETER, D (feet)
Basis: Fittings include: (1) access hatch with unguketed, unbolted cover, (2) adjustable deck legs; (3) gauge float well
with ungtsketed, unbolted cover, (4) sample well with slit fabric seal (10% open area); (5) 1-inch-diameter stub
drains (only on bolted deck); and (6) vacuum breaker with gasketed weighted mechanical actuation. This basis
was derived from a survey of users and manufacturers. Other fittings may be typically used within particular
companies or organizations to reflect standards and/or specifications of that group. This figure should not
supersede information based on actual tank data.
NOTE: If no specification information is available, assume bolted decks are the most common/typical type currently in
use in tanks with column-supported fixed roofs.
Figure 12.3-15. Approximated total deck fitting loss factors (Ff) for typical
fittings in tanks with self-supporting fixed roofs and either a
bolted deck or a welded deck. This figure is to be used
only when tank-specific data on the number and kind of deck
fittings are unavailable.4
10/92
Storage of Organic Liquids
12-79
-------
TABLE 12.3-14. INTERNAL FLOATING ROOF RIM SEAL LOSS FACTORS (Kp)a
Rim seal system description
Vapor-mounted primary seal only
Liquid-mounted primary seal only
Vapor-mounted primary seal plus secondary seal
Liquid-mounted primary seal plus secondary seal
KR (lb-mole/ft«yr)
Average
6.7b
3.0
2.5
1.6
"Reference 4.
blf no specific information is available, this value can be assumed to represent the most
common/typical rim seal system currently in use.
12-80
EMISSION FACTORS
10/92
-------
TABLE 12.3-15. TYPICAL NUMBER OF COLUMNS AS A FUNCTION OF TANK
DIAMETER FOR INTERNAL FLOATING ROOF TANKS WITH COLUMN-
SUPPORTED FIXED ROOFSa
Tank diameter range D, (ft)
0 < D < 85
85 < D < 100
100 < D < 120
120 < D <> 135
135 < D ^ 150
150 < D < 170
170 < D <, 190
190 < D < 220
220 < D < 235
235 < D < 270
270 < D < 275
275 < D <, 29(J
290 < D < 330
330 < D < 360
360 < D < 400
Typical number
of columns, NC
1
6
7
8
9
16
19
22
31
37
43
49
61
71
81
Reference 4. This table was derived from a survey of users and manufacturers. The actual
number of columns in a particular tank may vary greatly with age, fixed roof style, loading
specifications, and manufacturing prerogatives. Data in this table should not supersede
information on actual tanks.
10/92
Storage of Organic Liquids
12-81
-------
TABLE 12.3-16. SUMMARY OF INTERNAL FLOATING DECK FITTING LOSS
FACTORS (KF) AND TYPICAL NUMBER OF FITTINGS (NB)*
Deck fitting type
Access hatch (24-inch diameter)
Bolted cover, gasketed
Unbolted cover, gasketed
Unbolted cover, ungasketed
Automatic gauge float well
Bolted cover, gasketed
Unbolted cover, gasketed
Unbolted cover, ungasketed
Column well (24-inch diameter)0
Builtup column-sliding covet, gasketed
Builtup column-sliding cover, ungasketed
Pipe column-flexible fabric sleeve seal
Pipe column-sliding cover, gasketed
Pipe column-sliding cover, ungasketed
Ladder well (36-inch diameter)6
Sliding cover, gasketed
Sliding cover, ungasketed
Roof leg or hanger well
Adjustable
Fixed
Sample pipe or well (24-inch diameter)
Slotted pipe-sliding cover, gasketed
Slotted pipe-sliding cover, ungasketed
Sample well-slit fabric seal 10% open area
Stub drain (1-inch diameter)6
Deck fitting
loss factor,
KF(lb-
mole/yr)
1.6
11
25b
5.1
15
28b
33
47b
10
19
32
56
76b
7.9b
0
44
57
12b
1.2
Typical
number of
fittings, Np
1
1
(see Table 12.3-15)
lf
r5+D + D2
+ 10 + 600
1
D2
~125
12-82
EMISSION FACTORS
10/92
-------
TABLE 12.3-16. (Continued)
Deck fitting type
Vacuum breaker (10-inch diameter)
Weighted mechanical actuation, gasketed
Weighted mechanical actuation, ungasketed
Deck fitting
loss factor,
KF (Ib-
mole/yr)
0.7b
0.9
Typical
number of
fittings, Np
"Reference 4.
''If no specific information is available, this value can be assumed to represent the most
common/typical deck fittings currently used.
cColumn wells and ladder wells are not typically used with self-supported roofs.
dD = tank diameter, (ft).
"Not used on welded contact internal floating decks.
typically used on tanks with self-supporting fixed roofs.
10/92
Storage of Organic Liquids
12-83
-------
TABLE 12.3-17. DECK SEAM LENGTH FACTORS (SD) FOR TYPICAL DECK
CONSTRUCTIONS FOR INTERNAL FLOATING ROOF TANKS*
Deck construction
Continuous sheet construction15
5 ft wide
6 ft wide
7 ft wide
Panel construction*1
5 x 7.5 ft rectangular
5 x 12 ft rectangular
Typical deck seam ;
length factor,
sD (ft/ft2)
0.20°
0.17
0.14
0.33
0.28
Reference 4. Deck seam loss applies to bolted decks only.
bSD = 1/W, where W = sheet width (ft).
clf no specific information is available, this factor can be assumed to represent the most
common bolted decks currently in use.
dSD = (L+W)/LW, where W = panel width (ft) and L = panel length (ft).
12-84
EMISSION FACTORS
10/92
-------
12.3.4 Variable Vapor Space Tanks13
Variable vapor space filling losses result when vapor is displaced by liquid during
filling operations. Since the variable vapor space tank has an expandable vapor storage
capacity, this loss is not as large as the filling loss associated with fixed roof tanks. Loss of
vapor occurs only when the tank's vapor storage capacity is exceeded.
Variable vapor space system filling losses can be estimated from:
Lv=(2.40 x ID'2) MyPvA/Vi [(V^ - (0.25V2NJ] (4-1)
where:
Lv = variable vapor space filling loss, lb/ 1,000 gal throughput
Mv = molecular weight of vapor in storage tank, Ib/lb-mole; see Note 1 to
Equation 1-9
PVA = true vapor pressure at the daily average liquid surface temperature, psia; see
Notes 1 and 2 to Equation 1-9
Vl — volume of liquid pumped into system, throughput, bbl/yr
V2 = volume expansion capacity of system, bbl; see Note 1
N2 = number of transfers into system, dimensionless; see Note 2
Notes:
1. V2 is the volume expansion capacity of the variable vapor space achieved by roof lifting
or diaphragm flexing.
2. N2 is the number of transfers into the system during the time period that corresponds to a
throughput of VA.
The accuracy of Equation 4-1 is not documented. Special tank operating conditions
may result in actual losses significantly different from the estimates provided by
Equation 4-1. It should also be noted that, although not developed for use with heavier
petroleum liquids such as kerosenes and fuel oils, the equation is recommended for use with
heavier petroleum liquids in the absence of better data.
12.3.5 Pressure Tanks
Losses occur during withdrawal and filling operations in low-pressure (2.5 to 15 psig)
tanks when atmospheric venting occurs. High-pressure tanks are considered closed systems,
with virtually no emissions. Vapor recovery systems are often found on low-pressure tanks.
Fugitive losses are also associated with pressure tanks and their equipment, but with proper
10/92 Storage of Organic Liquids 12-85
-------
system maintenance, these losses are considered insignificant. No appropriate correlations
are available to estimate vapor losses from pressure tanks.
12.3.6 Variations of Emission Estimation Procedures
All of the emission estimation procedures presented in Section 12.3 can be used to
estimate emissions for shorter time periods by manipulating the inputs to the equations for
the time period in question. For all of the emission estimation procedures, the daily average
liquid surface temperature should be based on the appropriate temperature and solar
insolation data for the time period over which the estimate is to be evaluated. The
subsequent calculation of the vapor pressure should be based on the corrected daily liquid
surface temperature. For example, emission calculations for the month of June would be
based only on the meteorological data for June. It is important to note that a 1-month time
frame is recommended as the shortest time period of which emissions should be estimated.
In addition to the temperature and vapor pressure corrections, the constant in the
standing storage loss equation for fixed roof tanks would need to be revised based on the
actual time frame used. The constant, 365, is based on the number of days in a year. To
change the equation for a different time period, the constant should be changed to the
appropriate number of days in the time period for which emissions are being estimated. The
only change that would need to be made to the working loss equation for fixed roof tanks
would be to change the throughput per year to the throughput during the time period for
which emissions are being estimated.
Other than changing the meteorological data and the vapor pressure data, the only
changes needed for the floating roof rim seal, fitting, and deck seam losses would be to
modify the time frame by dividing the individual losses by the appropriate number of days or
months. The only change to the withdrawal losses would be to change the throughput to the
throughput for the time period for which emissions are being estimated.
Another variation that is frequently made to the emission estimation procedures is an
adjustment in the working or withdrawal loss equations if the tank is operated as a surge tank
or constant level tank. For constant level tanks or surge tanks where the throughput and
turnovers are high but the liquid level in the tank remains relatively constant, the actual
throughput or turnovers should not be used in the working loss or withdrawal loss equations.
For these tanks, the turnovers should be estimated by determining the average change in the
liquid height. The average change in height should then be divided by the total shell height.
This estimated turnover value should then be multiplied by the tank volume to obtain the net
throughput for the loss equations. Alternatively, a default turnover rate of four could be
used based on data from these type tanks.
12-86 EMISSION FACTORS 10/92
-------
12.4 HAZARDOUS AIR POLLUTANTS (HAP) SPECIATION METHODOLOGY
In some cases it may be important to know the annual emission rate for a component
(e.g., HAP) of a stored liquid mixture. There are two basic approaches that can be used to
estimate emissions for a single component of a stored liquid mixture. One approach involves
calculating the total losses based upon the known physical properties of the mixture (i.e. ,
gasoline) and then determining the individual component losses by multiplying the total loss
by the weight fraction of the desired component. The second approach is similar to the first
approach except that the mixture properties are unknown; therefore, the mixture properties
are first determined based on the composition of the liquid mixture.
Case 1— If the physical properties of the mixture are known (PVA> Mv> ML ^d WL)»
the total losses from the tank should be estimated using the procedures described previously
for the particular tank type. The component losses are then determined from either
Equation 5-1 or 5-2. For fixed roof tanks, the emission rate for each individual component
can be estimated by:
LT-. = (ZiiV)(Lr) (5-1)
where:
LI-. = emission rate of component i, Ib/yr
Z4 v = weight fraction of component i in the vapor. Ib/lb
LT = total losses, Ib/yr
For floating roof tanks, the emission rate for each individual component can be
estimated by:
L™ = (Zi>v) (LR + LF + LD) + (Zi)L) (L^,) (5-2)
where:
Lj i = emission rate of component i, Ib/yr
Zj v = weight fraction of component i in the vapor, Ib/lb
LR = rim seal losses, Ib/yr
LF = roof fitting losses, Ib/yr
LD = deck seam losses, Ib/yr
Zj L = weight fraction of component i in the liquid, Ib/lb
= withdrawal losses, Ib/yr
10/92 Storage of Organic Liquids 12-87
-------
If Equation 5-1 is used in place of Equation 5-2 for floating roof tanks, the value obtained
will be approximately the same value as that achieved with Equation 5-2 because withdrawal
losses are typically minimal for floating roof tanks.
In order to use Equations 5-1 and 5-2, the weight fraction of the desired component in
the liquid and vapor phase is needed. The liquid weight fraction of the desired component is
typically known or can be readily calculated for most mixtures. In order to calculate the
weight fraction in the vapor phase, Raoult's Law must first be used to determine the partial
pressure of the component. The partial pressure of the component can then be divided by the
total vapor pressure of the mixture to determine the mole fraction of the component in the
vapor phase. Raoult's Law states that the mole fraction of the component in the liquid (xj)
multiplied by the vapor pressure of the pure component (at the daily average liquid surface
temperature) (P) is equal to the partial pressure (P^ of that component:
PI = (P)(Xi) (5-3)
where:
Pi = partial pressure of component i, psia
P = vapor pressure of pure component i at the daily average liquid surface
temperature, psia
Xj = liquid mole fraction, Ib-mole/lb-mole
The vapor pressure of each component can be calculated from Antoine's equation or
found in standard references, as shown in Section 12.3.1. In order to use Equation 5-3, the
liquid mole fraction must be determined from the liquid weight fraction by:
Xj = (Zi(L) (MJ / (Mj) (5-4)
where:
Xj = liquid mole fraction of component i, Ib-mole/lb-mole
Z| L = weight fraction of component i, Ib/lb
ML = molecular weight of liquid stock, Ib/lb-mole
Mj = molecular weight of component i, Ib/lb-mole
If the molecular weight of the liquid is not known, the liquid mole fraction can be
determined by assuming a total weight of the liquid mixture (see Example 1 in Section 12.5).
12-88 EMISSION FACTORS 10/92
-------
The liquid mole fraction and the vapor pressure of the component at the daily average liquid
surface temperature can then be substituted into Equation 5-3 to obtain the partial pressure of
the component. The vapor mole fraction of the component can be determined from the
following equation:
y'= & (5"5>
where:
yj = vapor mole fraction of component i, Ib-mole/lb-mole
Pj = partial pressure of component i, psia
PVA = total vapor pressure of liquid mixture, psia
The weight fractions in the vapor phase are calculated from the mole fractions in the vapor
phase.
Z,v - (5-6)
^ Mv
where:
Z- v = vapor weight fraction of component i, Ib/lb
yj = vapor mole fraction of component i, Ib/lb-mole
Mj = molecular weight of component i, Ib/lb-mole
Mv = molecular weight of vapor stock, Ib/lb-mole
The liquid and vapor weight fractions of each desired component and the total losses can be
substituted into either Equation 5-1 or 5-2 to estimate the individual component losses.
Case 2—For cases where the mixture properties are unknown but the composition of
the liquid is known (i.e., nonpetroleum organic mixtures), the equations presented above can
be used to obtain a reasonable estimate of the physical properties of the mixture. For
nonaqueous organic mixtures, Equation 5-3 can be used to determine the partial pressure of
each component. If Equation 5-4 is used to determine the liquid mole fractions, the
molecular weight of the liquid stock must be known. If the molecular weight of the liquid
stock is unknown, then the liquid mole fractions can be determined by assuming a weight
basis and calculating the number of moles (see Example 1 in Section 12.5). The partial
pressure of each component can then be determined from Equation 5-3.
10/92 Storage of Organic Liquids 12-89
-------
For special cases, such as wastewater, where the liquid mixture is a dilute aqueous
solution, Henry's Law should be used instead of Raoult's Law in calculating total losses.
Henry's Law states that the mole fraction of the component in the liquid phase (jq) multiplied
by the Henry's Law constant for the component in the mixture is equal to the partial pressure
(Pi) for that component. For wastewater, Henry's Law constants are typically provided in
the form of atm»m3/g-mole. Therefore, the appropriate from of Henry's Law equation is:
Pi = (HA) (Q) (5-7)
where:
P5 = partial pressure of component i, atm
HA = Henry's Law constant for component i, atm«m3/g-mole
Ci = concentration of component i in the wastewater, g-mole/m3; see Note
Section 4.13 of AP-42 presents Henry's Law constants for selected organic liquids. The
partial pressure calculated from Equation 5-7 will need to be converted from atmospheres to
psia (1 atm = 14.696 psia).
Note: Typically wastewater concentrations are given in mg/liter, which is equivalent to
g/m3. To convert the concentrations to g-mole/m3 divide the concentration by the
molecular weight of the component.
The total vapor pressure of the mixture can be calculated from the sum of the partial
pressures:
PVA = S Pi (5-8)
where:
PVA = vapor pressure at daily average liquid surface temperature, psia
Pi = partial pressure of component i, psia
This procedure can be used to determine the vapor pressure at any temperature.
After computing the total vapor pressure, the mole fractions in the vapor phase are calculated
using Equation 5-5. The vapor mole fractions are used to calculate the molecular weight of
the vapor, Mv. The molecular weight of the vapor can be calculated by:
Mv = E Miyi (5-9)
where:
Mv = molecular weight of the vapor, Ib/lb-mole
Mi = molecular weight of component i, Ib/lb-mole
12-90 EMISSION FACTORS 10/92
-------
yj = vapor mole fraction of component i, Ib-mole/lb-mole
Another variable that may need to be calculated before estimating the total losses if it
is not available in a standard reference is the density of the liquid, WL. If the density of the
liquid is unknown, it can be estimated based on the liquid weight fractions of each
component (see Section 12.5, Example 3).
All of the mixture properties are now known (PVA» Mv> an^ WL)> therefore, these
values can be inputted into the emission estimation procedures outlined in Section 12.3 to
estimate total losses. After calculating the total losses, the component losses can be
calculated by using either Equation 5-1 or 5-2. Prior to calculating component losses,
Equation 5-6 must be used to determine the vapor weight fractions of each component.
10/92 Storage of Organic Liquids 12-91
-------
12-92
EMISSION FACTORS
10/92
-------
12.5 SAMPLE CALCULATIONS14
Example 1 - Chemical Mixture in a Fixed Roof Tank
Determine the yearly emission rate of the total product mixture and each component for a
chemical mixture stored in a vertical cone roof tank in Denver, Colorado. The chemical
mixture contains (for every 3,171 Ib of mixture) 2,812 Ib of benzene, 258 Ib of toluene, and
101 Ib of cyclohexane. The tank is 6 ft in diameter, 12 ft high, usually holds about 8 ft of
product, and is painted white. The tank working volume is 1,690 gallons. The number of
turnovers per year for the tank is five (i.e., the throughput of the tank is 8,450 gal/yr).
Solution
1. Determine tank type. The tank is a fixed-cone roof, vertical tank.
2. Determine estimating methodology. The product is made up of three organic liquids,
all of which are miscible in each other, which makes a homogenous mixture if the
material is well mixed. The tank emission rate will be based upon the properties of
the mixture. Raoult's law (as discussed in the HAP Speciation Section) is assumed to
apply to the mixture and will be used to determine the properties of the mixture.
3. Select equations to be used. For a vertical, fixed roof storage tank, the following
equations apply:
= 365 WVVVKEKS (1-2)
= 0.0010 MVPVAQKNKP (1~23)
where:
LT = total loss, Ib/yr
Ls = standing storage loss, Ib/yr
Lw = working loss, Ib/yr
Vv = tank vapor space volume, ft3
Vv = r/4 D2 Hvo (1-3)
10/92 Storage of Organic Liquids 12-93
-------
Wv = vapor density, Ib/ft3
(1-9)
LA
KE = vapor space expansion factor, dimensionless
APy - APB
PA ~ PVA
Ks = vented vapor space saturation factor, dimensionless
K = 1
s " 1 + 0.053 PVAHVO
D = diameter, ft
Hvo= vapor space outage, ft
Mv = molecular weight of vapor, Ib/lb-mole
PVA = vapor pressure at the daily average liquid surface temperature, psia
TLA ~ daily average liquid surface temperature, °R
ATV = daily vapor temperature range, °R
APV = daily vapor pressure range, psia
APB = breather vent pressure setting range, psi
PA = atmospheric pressure, psia
Q = annual net throughput, bbl/yr
KN = working loss turnover factor, dimensionless
KP = working loss product factor, dimensionless
(1-16)
(1-22)
12-94
EMISSION FACTORS
10/92
-------
4. Calculate each component of the standing storage loss and working loss functions.
a. Tank vapor space volume, Vv.
Vv = T/4 D2 HVQ (1-3)
D = 6 ft (given)
For a cone roof, the vapor space outage, Hvo is calculated by:
HVQ = Hs - HL + HRO (1-4)
Hs = tank shell height, 12 ft (given)
HL = stock liquid height, 8 ft (given)
HRO = roof outage, 1/3 HR = 1/3(SR)(RS) (1-6)
SR = tank cone roof slope, 0.0625 ft/ft (given) (see Note 1 to Equation 1-4)
Rs = tank shell radius = 1/2 D = 1/2 (6) = 3
Substituting values in Equation 1-6 yields,
HRO = 1 (0.0625)(3) = 0.0625 ft
Then use Equation 1-4 to calculate HVQ>
Hvo = 12 - 8 + 0.0625 = 4.0625 ft
Therefore,
Vv = i (6)2 (4.0625) = 114.86 ft3
4
b. Vapor density, Wv
R = ideal gas constant = 10.731 psia • ft3
Ib-mole • °R
10/92 Storage of Organic Liquids 12-95
-------
Mv = stock vapor molecular weight, Ib/lb-mole
PVA = stock vapor pressure at the daily average liquid surface temperature,
psia
TLA = daily average liquid surface temperature, °R
First calculate TLA using Equation 1-13.
TLA =°-44 TAA + 0-56 TB + 0.0079 a I (1-13)
where:
TAA = daily average ambient temperature, °R
TB = liquid bulk temperature, °R
I = daily total solar absorptance, Btu/ft-day = 1,568 (see Table 12.3-6)
a = tank paint solar absorptance = 0.17 (see Table 12.3-7)
TAA and TB must be calculated from Equations 1-14 and 1-15.
AN
(1-14)
from Table 12.3-6, for Denver, Colorado:
TAX = daity maximum ambient temperature = 64.3°F
TAN = daily minimum ambient temperature = 36.2°F
Converting to °R:
TAX = 64-3 + 460 = 524.3°R
TAN » 36-2 + 460 = 496.2°R
Therefore,
TAA = (524-3 + 496.2)72 = 510.25 °R
TB = liquid bulk temperature = TAA + 6a - 1
TAA SBt 510.25 °R from previous calculation
12-96 EMISSION FACTORS
(1-15)
10/92
-------
a = paint solar absorptance = 0.17 (see Table 12.3-7)
I = daily total solar insolation on a horizontal surface = 1,568 Btu/ft^day (see
Table 12.3-6)
Substituting values in Equation 1-15
TB = 510.25 + 6 (0.17) - 1 = 510.27 °R
Using Equation 1-13,
TLA = (0-44) (510.25°R) + 0.56 (510.27°R) + 0.0079 (0.17) (1,568) = 512.36°R
Second, calculate PVA using Raoult's Law.
According to Raoult's Law, the partial pressure of a component is the product of its pure
vapor pressure and its liquid mole fraction. The sum of the partial pressures are equal to the
total vapor pressure of the component mixture stock.
The pure vapor pressure for benzene, toluene, and cyclohexane can be calculated from
Antoine's equation. For benzene, Table 12.3-5 provides the Antoines coefficients which are
A = 6.905, B = 1,211.033, and C = 220.79. For toluene, A = 6.954, B = 1,344.8, and
C = 219.48. For cyclohexane, A = 6.841, B = 1,201.53, and C = 222.65. Therefore:
log P - A - -JL-
For benzene,
log P = 6.905 -
(U°C + 220.79)
P = 47.90 mmHg = 0.926 psia
Similarly for toluene and cyclohexane,
P = 0.255 psia for toluene
P = 0.966 psia for cyclohexane
In order to calculate the mixture vapor pressure, the partial pressures need to be calculated
for each component. The partial pressure is the product of the pure vapor pressure of each
component (calculated above) and the mole fractions of each component in the liquid.
10/92 Storage of Organic Liquids 12-97
-------
The mole fractions of each component are calculated as follows:
Benzene
Toluene
Cyclohexane
Total
Amount, Ib
2,812
258
101
+ Mi
78.1
92.1
84.2
Moles
36.0
2.80
1.20
40.0
xi
0.90
0.07
0.03
1.00
where:
Mj = molecular weight of component
Xi = liquid mole fraction
The partial pressures of the components can then be calculated by multiplying the pure vapor
pressure by the liquid mole fraction as follows:
Benzene
Toluene
Cyclohexane
Total
Pat52°F
0.926
0.255
0.966
Xi
0.90
0.07
0.03
1.0
p
•"•partial
0.833
0.018
0.029
0.880
The vapor pressure of the mixture is then 0.880 psia.
Third, calculate the molecular weight of the vapor, Mv. Molecular weight of the vapor
depends upon the mole fractions of the components in the vapor.
where:
Mv = EM^
Mj = molecular weight of the component
yj = vapor mole fraction
The vapor mole fractions, yi} are equal to the partial pressure of the component divided by
the total vapor pressure of the mixture.
12-98
EMISSION FACTORS
10/92
-------
Therefore,
Vbenzene = Ppartial/Ptotal = 0.833/0.880 = 0.947
Similarly, for toluene and cyclohexane,
Ytoluene = Ppartial/Ptotal = 0.020
Ycyclohexane = "partial'"total = 0.033
The mole fractions of the vapor components sum to 1.0.
The molecular weight of the vapor can be calculated as follows:
'
Benzene
Toluene
Cyclohexane
Total
M5
78.1
92.1
84.2
Yi
0.947
0.020
0.033
Mv
74.0
1.84
2.78
78.6
Since all variables have now been solved, the stock density, Wv, can be calculated:
W.. =
RT,
LA
(78.6) (0.880)
(10.731) (512.36)
_2 Jb
ft*
c. KE, vapor space expansion factor can be calculated using the following equation:
ATV
APV-APB
LLA
-P
r
VA
where:
AT, =
AR, =
APn =
PA =
daily vapor temperature range, °R
daily vapor pressure range, °R
breather vent pressure setting range, psia
atmospheric pressure, 14.7 psia (given)
(1-16)
10/92
Storage of Organic Liquids
12-99
-------
PVA = vapor pressure at daily average liquid surface temperature, psia = 0.881 psia
(from Step 4b)
TLA = daily average liquid surface temperature, °R = 512.36°R (from Step 4b)
First, calculate the daily vapor temperature range from Equation 1-17,
ATV = 0.72 A TA + 0.028al (1-17)
where:
ATV = daily vapor temperature range, °R
ATA = daily ambient temperature range = TAX " TAN
a = tank paint solar absorptance, 0.17 (given)
I = daily total solar insolation, 1,568 Btu/ft^day (given)
from Table 12.3-6, for Denver, Colorado:
TAX= 64.3°F
TAN - 36.2°F
Converting to °R,
TAX = 64-3 + 460 = 524.3°R
TAN = 36-2 + 460 = 496.2°R
From equation 1-17,
ATA = 524.3 - 496.2 = 28.1°R
Therefore,
ATV = 0.72 (28.1) + (0.028)(0.17)(1568) = 27.7°R
Second, calculate the daily vapor pressure range using Equation 1-18,
APV = Pyx - PVN (M8>
12-100 EMISSION FACTORS 10/92
-------
PVX/VN = vapor pressure at the daily maximum/minimum liquid temperature can be
calculated in a manner similar to the PVA calculation shown earlier.
TLX = maximum liquid temperature, TLA + 0.25 ATV (from Figure 12.3-5)
TLN = minimum liquid temperature, TLA - 0.25 ATV (from Figure 12.3-5)
TLA = 512.36 (from Step 4b)
ATV = 27.7°R
TLX = 512.36 + (0.25) (27.7) = 519.3°R or 59°F
TLN = 512.36 - (0.25) (27.7) = 505.4°R or 45°F
Using Antoine's equation, the pure vapor pressures of each component at the minimum liquid
surface temperature are:
Pbenzene = 0.758
Ptoluene = 0.203
Pcyclohexane = 0-794 psia
The partial pressures for each component at TLN can then be calculated as follows:
Benzene
Toluene
Cyclohexane
Total
P at 45 °F
0.758
0.203
0.794
xi
0.90
0.07
0.03
1.0
p
r partial
0.68
0.01
0.02
0.71
Using Antoines equation, the pure vapor pressure of each component at the maximum
liquid surface temperature are:
benzene
toluene
= 0.32
cyclohexane
10/92
Storage of Organic Liquids
12-101
-------
The partial pressures for each component at TLX can then be calculated as follows:
Benzene
Toluene
Cyclohexane
Total
P
1.14
0.32
1.18
*i
0.90
0.07
0.03
1.0
p
r partial
1.03
0.02
0.04
1.09
Therefore, the vapor pressure range, APV = PLX - PLN = 1.09 - 0.710 = 0.38 psia.
Next, calculate the breather vent pressure, APB, from equation 1-20
AP —
where:
PBP = breather vent pressure setting = 0.03 psia (given) (see Note 3 to
Equation 1-16)
PBV = breather vent vacuum setting = -0.03 psig (given) (see Note 3 to
Equation 1-16)
APB = 0.03 - (-0.03) = 0.06 psig
Finally, KE, can be calculated by substituting values into Equation 1-16.
VB
(27.7) + 0.38 - 0.06 psia
(512.36) 14.7 psia - 0.880 psia
(1-20)
d. The vented vapor space saturation factor, Ks, can be calculated from Equation 1-22.
1
1 + 0.053 PVAHVO
(1-22)
where:
PVA = 0-880 psia (from Step 4b)
Hvo = 4.0625 ft (from Step 4a)
12-102
EMISSION FACTORS
10/92
-------
1 = 0.841
1 + 0.053(0.880)(4.0625)
5. Calculate standing storage losses.
LS = 365 WVVVKEKS
Using the values calculated above:
Wv = 1.26 x 10'2 jb (from Step 4b)
ft3
Vv = 114.86 ft3 (from Step 4a)
KE = 0.077 (from Step 4c)
Ks = 0.841 (from Step 4d)
LS = 365 (1.26xlO-2)(114.86)(0.077)(0.841) = 34.2 Ib/yr
6. Calculate working losses.
The amount of VOC's emitted as a result of filling operations can be calculated from
the following equation:
Lw = (0.0010) (MV)(PVA)(Q)(KN)(KP) (1-23)
From Step 4:
Mv = 78.6 (from Step 4b)
PVA = 0.880 psia (from Step 4b)
Q = 8,450 gal/yr x 2.381 bbl/100 gal = 201 bbl/yr (given)
Kp = product factor, dimensionless = 1 for volatile organic liquids, 0.75 for crude
oils
KN = 1 for turnovers _<.36 (given)
N = turnovers per year = 5 (given)
= (0.0010)(78.6)(0.880)(201)(1)(1) = 13.9 Ib/yr
10/92 Storage of Organic Liquids 12-103
-------
7. Calculate total losses. Lr-
LT = LS "^" MV
where:
Ls = 34.2 Ib/yr
LW = 13.9 Ib/yr
Lj. = 34.7 + 13.9 = 48.1 Ib/yr
8. Calculate the amount of each component emitted from the tank.
The amount of each component emitted is equal to the weight fraction of the
component in the vapor times the amount of total VOC emitted. Assuming 100 moles of
vapor are present, the number of moles of each component will be equal to the mole fraction
multiplied by 100. This assumption is valid regardless of the actual number of moles
present. Therefore,
Component
Benzene
Toluene
Cyclohexane
Total
No. of moles x Mj = Pounds;
94.7
2.0
3.3
100
78.1
92.1
84.3
7,396
184
278
7,858
Weight
fraction
0.94
0.02
0.04
1.0
Weight fraction =
pounds^
total pounds
12-104
EMISSION FACTORS
10/92
-------
Amount of each component emitted is then calculated by:
Component
Benzene
Toluene
Cyclohexane
Total
Weight Total VOC
fraction x emitted =
0.94
0.02
0.04
48.1
48.1
48.1
Poundsj emitted
45.2
0.96
1.92
48.1
Example 2 - Chemical Mixture in a Horizontal Tank - Assuming that the tank mentioned in
Example 1 is now horizontal, calculate emissions. (Tank diameter - 6 ft and length - 12ft.)
Solution
Emissions from horizontal tanks can be calculated by adjusting parameters in the fixed roof
equations. Specifically, an effective diameter, DE, is used in place of the tank diameter, D.
The vapor space height, Hvo, is assumed to be half the actual tank diameter.
1. Horizontal tank adjustments. Make adjustments to horizontal tank values so that fixed
roof tank equations can be used. The effective diameter, DE, is calculated as follows:
PL
0.785
0.785
- 9.577 ft.
The vapor space height, Hvo is calculated as follows:
Hvo = 1/2 D = 1/2 (6) = 3 ft
2. Given the above adjustments the standing storage loss. Lg. can be calculated.
Calculate values for each effected variable on the standing loss equation.
LS = 365 (Vv) (Wv) (Ke) (Ks)
Vv and Ks depend on the effective tank diameter, DE, and vapor space height, Hvo.
10/92
Storage of Organic Liquids
12-105
-------
These variables can be calculated using the values derived in Step 1:
Vv = - (9.57T)2 (3) = 216.10 ft3
4
* 1 + (0.053) (PVA) (Hvo)
Ks = = 0.877
s 1 + (0.053) (0.880) (3)
3. Calculate standing storage loss using the values calculated in Step 2.
LS = 365 (VV)(WV)(KE)(KS)
Vv - 216.10 ft3 (from Step 2)
Wv = 1.26 x 10'2 Ib/ft3 (from Step 4b)
KE » 0.077 (from Step 4c)
Ks = 0.877 (from Step 2)
LS = (365)(1.26 x 10-2)(216.10)(0.077)(0.877)
LS - 67.1 Ib/yr
4. Calculate working loss. Since the parameters for working loss do not depend on
diameter or vapor space height, the working loss for a horizontal tank of the same capacity
as the tank in Example 1 will emit the same amount as working loss.
= 13.9 Ib/yr
5. Calculate total emissions.
LT = LS + Lw
LT = 67.1 + 13.9 = 81 Ib/yr
12-106 EMISSION FACTORS 10/92
-------
Example 3 - Chemical Mixture in an External Floating Roof Tank - Determine the yearly
emission rate of a mixture that is 75 percent benzene, 15 percent toluene, and 10 percent
cyclohexane, by weight, from a 100,000-gallon external floating roof tank with a pontoon
roof. The tank is 20 feet in diameter. The tank has 10 turnovers per year. The tank has a
mechanical shoe seal (primary seal) and a shoe-mounted secondary seal. The tank is made of
welded steel and has a light rust covering the inside surface of the shell. The tank shell is
painted white, and the tank is located in Newark, New Jersey. The floating roof is equipped
with the following fittings: (1) an ungasketed access hatch with an unbolted cover, (2) an
unspecified number of ungasketed vacuum breakers with weighted mechanical actuation, and
(3) ungasketed gauge hatch/sample wells with weighted mechanical actuation.
Solution:
1. Determine tank type. The tank is an external floating roof storage tank.
2. Determine estimating methodology. The product consists of three organic liquids, all of
which are miscible in each other, which make a homogenous mixture if the material is well
mixed. The tank emission rate will be based upon the properties of the mixture. Because
the components have similar structures and molecular weights, Raoult's Law is assumed to
apply to the mixture.
3. Select equations to be used. For an external floating roof tank,
LT ~ LWD ~^" LR + Lp (2-1)
LWD = (0.943) QCWL/D (2-4)
LR = KRvnP*DMvKc (2-2)
LF = FFP*MVKC (2-5)
where:
LT = total loss, Ib/yr
LWD = withdrawal loss, Ib/yr
LR = rim seal loss from external floating roof tanks, Ib/yr
LF = roof fitting loss, Ib/yr
Q = product average throughput, bbl/yr
C = product withdrawal shell clingage factor, bbl/1,000 ft2; see Table 12.3-10
WL = density of product, Ib/gal
10/92 Storage of Organic Liquids 12-107
-------
D = tank diameter, ft
KR - seal factor, lb-mole/[ft(mphyi'ft'yr)]
v = average windspeed for the tank site, mph
n = seal windspeed exponent, dimensionless
P* = the vapor pressure function, dimensionless
P* - (PVA/PA)/(! + [1-OWPA)]0-5)2
where:
PVA = the true vapor pressure of the materials stored, psia
PA = atmospheric pressure, psia = 14.7
Mv =» molecular weight of product vapor, Ib/lb-mol
KC = product factor, dimensionless
FF = the total deck fitting loss factor, Ib-mol/yr
nf
S = l(NFiKFi)=[(NF1KFl)
i
where:
Np. = number of fittings of a particular type, dimensionless. Np. is determined
1 for the specific tank or estimated from Tables 12.3-11, 12.3-12, or
12.3-13
KF- - roof fitting loss factor for a particular type of fitting, Ib-mol/yr. Kpi is
1 determined for each fitting type from Table 12.3-11.
nf = number of different types of fittings, dimensionless = 3
4. Identify parameters to be calculated/determined from tables. In this example, the
following parameters are not specified: WL, FF, C, KR, v, n, PVA, P*» Mv> ^d KC- Some
typical assumptions that can be made are as follows:
v = average windspeed for the tank site = 10.2 mph (see Table 12.3-9)
Kc — 1.0 for volatile organic liquids
12-108 EMISSION FACTORS 10/92
-------
C = 0.0015 bbl/ 1,000 ft2 for tanks with light rust (from Table 12.3-10)
KR = 0.8 (from Table 12.3-8)
n = 1.2 (from Table 12.3-8)
FF, WL, PVA> P*> and Mv stiu need to be calculated.
FF is estimated by calculating the individual Kp. and Np. for each of the three types
of roof fittings used in this example. For the ungasketed access1hatches with unbolted
covers, the Kf value can be calculated using information in Table 12.3-11. For this fitting,
Kfa = 2.7, Kflj =7.1, and m = 1. There is normally one access hatch. So,
f . , , = Kfa+ Kfo
facess hatch Id 10
= 2.7 + (7.1K10.2)1
= 75.1 Ib-mol/yr
Kf u * u = 75.11b-mol/yr
'access batch
N =1
faccess hatch
The number of vacuum breakers can be taken from Table 12.3-12. For tanks with a
diameter of 20 feet and a pontoon roof, the number of vacuum breakers is one.
Table 12.3-11 provides fitting factors for weighted mechanical action, ungasketed vacuum
breakers when the average windspeed is 10.2 mph. Based on this table, Kfa =1.1, Kft, =
3.0, and m =1. So,
KFvacuum breaker = KFA + Kra (vm)
KFvacuum breaker = 1.1 + 3.0 (10.2)1
Kpvacuum breaker = 31.7 Ib-mol/yr
N
Fvacuum breaker = 1
For the ungasketed gauge hatch/sample wells with weighted mechanical actuation,
Table 12.3-11 indicates that tanks normally have only one. This table also indicates that
Kfa = 0.91, Kfe = 2.4, and m = 1. Therefore,
Kpgauge hatch/sample well = KFA + Kra (vm)
10/92 Storage of Organic Liquids 12-109
-------
KF = 0.91 + 2.4 (10.2)1
V-
Fgauge hatch/sample well = 25.4 Ib-mol/yr
Fgauge hatch/sample well = 1
FF can be calculated from Equation 2-6:
3
- E (KF.)(NF.)
- 132.2 Ib-mol/yr
5. Calculate mole fractions in the liquid. The mole fractions of components in the liquid
must be calculated in order to estimate the vapor pressure of the liquid using Raoult's Law.
For this example, the weight fractions (given as 75 percent benzene, 15 percent toluene, and
10 percent cyclohexane) of the mixture must be converted to mole fractions. First, assume
that there are 1,000 Ib of liquid mixture. Using this assumption, the mole fractions
calculated will be valid no matter how many pounds of liquid actually are present. The
amount (pounds) of each component is equal to the weight fraction times 1,000:
Component
Benzene
Toluene
Cyclohexane
Total
Weight
fraction
x 1,000 Ib
0.75
0.15
0.10
1.00
= Pounds.;
750
150
100
1,000
Mj. Ib/
-r lb-moles
78.1
92.1
84.2
Moles
9.603
1.629
1.188
12.420
Mole
fraction
0.773
0.131
0.096
1.000
For example, the mole fraction of benzene in the liquid is 9.603/12.420 = 0.773.
6. Determine the daily average liquid surface temperature. The daily average liquid surface
temperature is equal to:
TLA = 0.44
TAA=
TR - T
+ 0.56 T + 0.0079 a I
LB
AA
6a -
12-110
EMISSION FACTORS
10/92
-------
For Newark, New Jersey (see Table 12.3-6):
TAX = 62.5°F = 522.2°R
TAN = 45.9°F = 505.6°R
I = 1,165 Btu/ft2«d
From Table 12.3-7, a = 0.17
Therefore;
TAA = (522-2 + 505.6)/2 = 513.9°R
TB = 513.9°R + 6 (0.17) - 1 = 513.92°R
TLA = O-44 (513.9) + 0.56 (513.92) + 0.0079 (0.17)(1,165)
TLA = 226-12 + 287-8 + L56 = 515.5°R
TLA = 55.8°F = 56°F
7. Calculate partial pressures and total vapor pressure of the liquid. The vapor pressure of
each component at 56°F can be determined using Antoines equation. Since Raoult's Law is
assumed to apply in this example, the partial pressure of each component is the liquid mole
fraction (x;) times the vapor pressure of the component (P).
Component
Benzene
Toluene
Cyclohexane
Totals
P at 56°F
1.04
0.29
1.08
Xi
0.773
0.131
0.096
1.00
p
•"•partial
0.80
0.038
0.104
0.942
The vapor pressure of the mixture is estimated to be 0.942 psia.
8. Calculate mole fractions in the vapor. The mole fractions of the vapor phase are based
upon the partial pressure that each component exerts (calculated in Step 7).
The total vapor pressure of the mixture is 0.942 psia. So for benzene:
Ybcnzene = Ppartial/Ptotal = 0.80/0.942 = 0.85
where:
Xbcnzene = mo*e fraction of benzene in the vapor
Ppartiai = partial pressure of benzene in the vapor, psia
10/92
Storage of Organic Liquids
12-111
-------
Ptotal = total vapor pressure of the mixture, psia
Similarly,
Ytoluene = 0.038/0.942 = 0.040
Ycyclohcxanc = 0.104/0.942 = 0.110
The vapor phase mole fractions sum to 1.0.
9. Calculate molecular weight of the vapor. The molecular weight of the vapor depends
upon the mole fractions of the components in the vapor.
M =
where:
= molecular weight of the vapor
I = molecular weight of the component
j = mole fraction of component in the vapor
Component
Benzene
Toluene
Cyclohexane
Total
^
78.1
92.1
84.2
Yi
0.85
0.040
0.110
1.00
Mv = E(Mi)
-------
(0.110X84.2) = cyciohexane
"•v 79.3
11. Calculate total VOC emitted from the tank. The total VOC emitted from the tank is
calculated using the equations identified in Step 3 and the parameters calculated in Steps 4
through 9.
LR + Lp
= 0.943 QCWL/D
where:
Q = 100,000 gal x 10 turnovers/yr (given)
= 1,000,000 gal x 2.381 bbl/100 gal = 23,810 bbl/yr
C = 0.0015 bbl/103 ft2 (from Table 12.3-10)
WL = 1/[E (wt fraction in liquid)/(liquid density from Table 12.3-3)]
Weight fractions
Benzene = 0.75 (given)
Toluene = 0.15 (given)
Cyciohexane = 0. 10 (given)
Liquid densities
Benzene = 7.4 (see Table 12.3-3)
Toluene = 7.3 (see Table 12.3-3)
Cyciohexane = 6.5 (see Table 12.3-3)
WL = l/[(0.75/7.4) + (0.15/7.3) + (0.10/6.5)]
= 1/(0.101 + 0.0205 + 0.0154)
= 1/0.1369
= 7.3 Ib/gal
D = 20 ft (given)
= 0.943 QCWL/D
= [0.943(23,810)(0.0015)(7.3)/20]
= 12.3 Ib of VOC/yr
10/92 Storage of Organic Liquids 12-113
-------
where:
KR
v
n
PVA
P*
P*
Mv
LR
KRvnP*DMvKc
0.8 (from Step 4)
10.2 mph (from Step 4)
1.2 (from Step 4)
0.942 psia (from Step 7)
(0.942/14.7)7(1+[1-(0.942/14.7)]°-5)2 (formula from Step 3)
0.017
79.3 Ib/lb-mol (from Step 9)
(0.8)(10.2)1-2(0.017)(20)(79.3)(1.0)
350 Ib of VOC/yr
LF = FFP*MvKc
where:
FF = 132.2 Ib-mol/yr (from Step 4)
P* = 0.017
Mv - 79.3 Ib/lb-mol
KC = 1.0 (from Step 4)
LF - (132.2)(0.017)(79.3)(1.0)
= 178 Ib/yr of VOC emitted
LR + LF
- 12.3 + 350 + 178
= 540 Ib/yr of VOC emitted from tank
12. Calculate amount of each component emitted from the tank. For an external floating
roof tank, the individual component losses are equal to:
J = (ZUv)(LR + LF) +
Therefore,
= (0.84)(528) + (0.75)(12.3) = 453 Ib/yr benzene
= (0.040)(528) + (0.15)(12.3) = 23 Ib/yr toluene
12-114
EMISSION FACTORS
10/92
-------
= (0.12)(528) + (0.10)(12.3) = 65 Ib/yr cyclohexane
Example 4 - Gasoline in an Internal Floating Roof Tank - Determine emissions of product
from a 1 million gallon, internal floating roof tank containing gasoline (RVP 13). The tank
is painted white and is located in Tulsa, Oklahoma. The annual number of turnovers for the
tank is 50. The tank is 70 ft in diameter and 35 ft high and is equipped with a
liquid-mounted primary seal plus a secondary seal. The tank has a column-supported fixed
roof. The tank's deck is welded and equipped with the following: (1) two access hatches
with an unbolted, ungasketed cover; (2) an automatic gauge float well with an unbolted,
ungasketed cover; (3) a pipe column well with a flexible fabric sleeve seal; (4) a sliding
cover, gasketed ladder well; (5) fixed roof legs; (6) a slotted sample pipe well with a
gasketed sliding cover; and (7) a weighted, gasketed vacuum breaker.
Solution:
1. Determine tank type. The following information must be known about the tank in order
to use the internal floating roof equations:
--the number of columns
—the effective column diameter
-the system seal description (vapor- or liquid-mounted, primary or secondary seal)
—the deck fitting types and the deck seam length
Some of this information depends on specific construction details, which may not be
known. In these instances, approximate values are provided for use.
2. Determine estimating methodology. Gasoline consists of many organic compounds, all of
which are miscible in each other, which form a homogenous mixture. The tank emission
rate will be based on the properties of RVP 13 gasoline. Since vapor pressure data have
already been compiled, Raoult's Law will not be used. The molecular weight of gasoline
also will be taken from a table and will not be calculated. Weight fractions of components
will be assumed to be available from SPECIATE database.
3. Select equations to be used.
+ LR + LF + LD (3-1)
(0.943) QCWLfl+( NCR
D D
LR = KRP*DMVKC (3-2)
LF = FFP*MvKc (3-5)
LD = KDSDD2P*MvKc (3-6)
10/92 Storage of Organic Liquids 12-115
-------
where:
IT = total loss, Ib/yr
LWD = withdrawal loss, Ib/yr
LR = rim seal loss, Ib/yr
LF = deck fitting loss, Ib/yr
LD = deck seam loss, Ib/yr
For this example:
Q = product average throughput, bbl/yr [tank capacity (bbl/turnover) X
turnovers/yr]
C = product withdrawal shell clingage factor, bbl/ 1,000 ft2
WL = density of liquid, Ib/gal
D = tank diameter, ft
Nc = number of columns, dimensionless
Fc = effective column diameter, ft
KR = seal factor, Ib-mole/ft-yr
Mv = the average molecular weight of the product vapor, Ib/lb-mol
KC = the product factor, dimensionless
P* = the vapor pressure function, dimensionless
where:
PVA = the vapor pressure of the material stored, psia
PA = average atmospheric pressure at tank location, psia
FF — the total deck fitting loss factor, Ib-mol/yr
= EJNFiKF.) = [(NFlKFl) + (NF2KF2) + ... + (NFn
where:
j = number of fittings of a particular type, dimensionless. NFj is
determined for the specific tank or estimated from Table 12.3-16
12-116 EMISSION FACTORS 10/92
-------
Kp. = deck fitting loss factor for a particular type of fitting, Ib-mol/yr.
1 Kp. is determined for each fitting type from Table 12.3-16
nf = number different types of fittings, dimensionless
KD = the deck seam loss factor, lb-mol/ft»yr
= 0.34 for nonwelded roofs
= 0 for welded decks
= deck seam length factor, ft/ft2
where:
Lseam = total length of deck seams, ft
Adeck = area of deck, ft2 = rD2/4
4. Identify parameters to be calculated or determined from tables. In this example, the
following parameters are not specified: Nc, Fc, P, Mv, Ks, P*, KC, FF, KD, and SD. The
density of the liquid (WL) and the vapor pressure of the liquid (P) can be read from tables
and do not need to be calculated. Also, the weight fractions of components in the vapor can
be obtained from speciation manuals. Therefore, several steps required in preceding
examples will not be required in this example. In each case, if a step is not required, the
reason is presented.
The following parameters can be obtained from tables or assumptions:
Kc = 1.0 (for volatile organic liquids)
Nc = 1 (from Table 12.3-15)
Fc = 1.0 (assumed)
KR = 1.6 (from Table 12.3-14)
Mv = 62 Ib/lb-mol (from Table 12.3-2)
WL = 4.9 Ib/gal (from Table 12.3-2)
C = 0.0015 bbl/1,000 ft2 (from Table 12.3-10)
KD = 0 (for welded roofs)
10/92 Storage of Organic Liquids 12-117
-------
SD = 0.2 ft/ft2 (from Table 12.3-17)
F = values taken from Table 12.3-18
= (25)(2) + (28)(1) + (10)(1) + (56)(1) + 0 [5 + (70/10) -I- (702/600)] +
= 188.7 Ib-mol/yr
5. Calculate mole fractions in the liquid. This step is not required because liquid mole
fractions are only used to calculate liquid vapor pressure, which is given in this example.
6. Calculate the daily average liquid surface temperature. The daily average liquid surface
temperature is equal to:
TLA = O-44 TAA + 0-56 TB + 0.0079 a I
TAA = (TAX + TAN)^
TB = TAA + 6« - 1
For Tulsa, Oklahoma (see Table 12.3-6):
TAX = 71.3°F = 530.97°R
TAN = 49.2°F = 508.87°R
I = 1,373 Btu/ft2«day
From Table 12.3-7, a = 0.17
Therefore,
LAA
(530.97 + 508.87)72 = 519.92°R
TB = 519.92 + 6(0.17) - 1 = 519.94°R
TLA = O-44 (519.92) + 0.56 (519.94) + 0.0079(0.17)(1,373)
TLA = 228.76 + 291.17+1.84
TLA = 521.77 or 62°F
7. Calculate partial pressures and total vapor pressure of the liquid. The vapor pressure of
gasoline RVP 13 can be interpolated from Table 12.3-2. The interpolated vapor pressure at
62°F is equal to 7.18 psia. Therefore,
P* = (7.18/14.7)/[1 + (l-(7.18/14.7)f5]2
P* = 0.166
12-118
EMISSION FACTORS
10/92
-------
8. Calculate mole fractions in the vapor. This step is not required because vapor mole
fractions are needed to calculate the weight fractions and the molecular weight of the vapor,
which are already specified.
9. Calculate molecular weight of the vapor. This step is not required because the molecular
weight of gasoline vapor is already specified.
10. Calculate weight fractions of the vapor. The weight fractions of gasoline vapor can be
obtained from a VOC speciation manual.
11. Calculate total VOC emitted from the tank. The total VOC emitted from the tank is
calculated using the equations identified in Step 3 and the parameters specified in Step 4.
LR + Lp + LD
= [(0.943)QCWL]/D X [1 + (NCFC)/D]
where:
Q = (1,000,000 gal) X (50 turnovers/yr)
= (50,000,000 gal) X (2.381 bbl/lOOgal) = 1, 190,500 bbtfyr
C = 0.0015 bbl/ 1,000 ft2
WL = 4.9 Ib/gal
D = 70ft
Nc= 1
Fc= 1
= [(0.943)(1,190,500)(0.0015)(4.9)]/70X [1 + (1)(1)/70J = 119.6 Ib/yr
LR = KRDP*MvKc
where:
KR = 1.61b-mole/ft-yr
P* = 0.166
D = 70 ft
Mv = 62 Ib/lb-mol
KC= 1.0
LR = (1.6)(0.166)(70)(62)(1.0) =1,153 Ib/yr of VOC emitted
10/92 Storage of Organic Liquids 12-119
-------
Lp = FFP*MvKc
where:
F
P
Mv
F
*
188.7 Ib-mol/yr
0.166
62 Ib/lb-mol
LF = (188.7)(0.166)(62)(1.0) = 1,942 Ib/yrof VOC emitted
L =
where:
KD
SD
D
P*
Mv
LD =
0
0.2
70 ft
0.166
62 Ib/lb-mol
1.0
(0.0)(0.2)(70)2(0.166)(62)(1.0) = 0 Ib/yr of VOC
= 119.6 + 1,153 + 1,942 + 0 = 3,215 Ib/yr of VOC emitted from the tank
12. Calculate amount of each component emitted from the tank. The individual component
losses are equal to:
LT; = (Zi>v)(LR + LF + LD) + (Zi>L)(LwD)
Since the liquid weight fractions are unknown, the individual component losses are calculated
based on the vapor weight fraction and the total losses. This procedure should yield
approximately the same values as the above equation because withdrawal losses are typically
low for floating roof tanks. The amount of each component emitted is the weight fraction of
that component in the vapor (obtained from a VOC species data manual and shown in
Table 12.5-1) times the total amount of VOC emitted from the tank. Table 12.5-1 shows the
amount emitted for each component in this example.
12-120
EMISSION FACTORS
10/92
-------
TABLE 12.5-1. EMISSIONS FOR EXAMPLE 4
Constituent
Air toxics
Benzene
Toluene
Ethylbenzene
O-xylene
Nontoxics
Isomers of pentane
N-butane
Iso-butane
N-pentane
Isomers of hexane
3-methyl pentane
Hexane
Others
Total
Weight percent in vapor x 3,215 Ib/yr
0.77
0.66
0.04
0.05
26.78
22.95
9.83
8.56
4.78
2.34
1.84
21.40
100
= Pounds emitted/yr
24.8
21.2
1.29
1.61
861
738
316
275
154
75.2
59.2
688
3,215
10/92
Storage of Organic Liquids
12-121
-------
12-122
EMISSION FACTORS
10/92
-------
References for Chapter 12
1. Royce J., Laverman, Emission Reduction Options for Floating Roof Tanks. Chicago
Bridge and Iron Technical Services Company, Presented at the Second International
Symposium on Aboveground Storage Tanks, Houston, Texas, January 1992.
2. VOC Emissions From Volatile Organic Liquid Storage Tanks-Background Information
for Proposed Standards. EPA-450/3-81-003a, U. S. Environmental Protection Agency,
Research Triangle Park, NC, July 1984.
3. Evaporative Loss From External Floating Roof Tanks. Third Edition, Bulletin
No. 2517, American Petroleum Institute, Washington, D.C., 1989.
4. Evaporation Loss From Internal Floating Roof Tanks. Third Edition, Bulletin
No. 2519, American Petroleum Institute, Washington, D.C., 1982.
5. Benzene Emissions From Benzene Storage Tanks-Background Information for Proposed
Standards. EPA-450/3-80-034a, U. S. Environmental Protection Agency, Research
Triangle Park, NC, December 1980.
6. Evaporative Loss From Fixed Roof Tanks. Second Edition, Bulletin No. 2518,
American Petroleum Institute, Washington, D.C., October 1991.
7. Estimating Air Toxics Emissions From Organic Liquid Storage Tanks.
EPA-450/4-88-004, U. S. Environmental Protection Agency, Research Triangle Park,
NC, October 1988.
8. Henry C. Barnett, et al., Properties of Aircraft Fuels. NACA-TN 3276, Lewis Flight
Propulsion Laboratory, Cleveland, OH, August 1956.
9. Petrochemical Evaporation Loss from Storage Tanks. First Edition, Bulletin No. 2523,
American Petroleum Institute, Washington, D.C., 1969.
10. SIMMS Data Base Management System. U. S. Environmental Protection Agency,
Research Triangle Park, NC.
11. Comparative Climatic Data Through 1990. National Oceanic and Atmospheric
Administration, Asheville, NC, 1990.
12. Input for Solar Systems. Prepared by U. S. Department of Commerce, National
Oceanic and Atmospheric Administration, Environmental and Information Service,
National Climatic Center, Asheville, NC. Prepared for the U. S. Department of
Energy, Division of Solar Technology, November 1987 (revised August 1979).
13. Use of Variable Vapor Space Systems to Reduce Evaporation Loss. Bulletin No. 2520,
American Petroleum Institute, New York, NY, 1964.
10/92 Storage of Organic Liquids 12-123
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14. SPECIATE Data Base Management System. Emission Inventory Branch, U. S.
Environmental Protection Agency, Research Triangle Park, NC, 1990.
12-124
EMISSION FACTORS
10/92
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TECHNICAL REPORT DATA
(I'leasc read Instructions on the reverse before completing)
REPORT NO.
AP-42
2.
Volume I, Supplement E
3. RECIPIENT'S ACCESSION NO.
TITLE AND SUBTITLE
Supplement E To Compilation Of Air Pollutant Emission
Factors, Volume I
5. REPORT DATE
October 1992
6. PERFORMING ORGANIZATION CODE
AUTHOR<3)
8. PERFORMING ORGANIZATION REPORT NO.
. PERFORMING ORGANIZATION NAME AND ADDRESS
U. S. Environmental Protection Agency
Office Of Air Quality Planning And Standards
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
2. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
5. SUPPLEMENTARY NOTES
6. ABSTRACT
In this Supplement to the Fourth Edition of AP-42 Volume I, new or
revised emissions data are presented for Anthracite Coal Combustion; Natural
Gas Combustion; Liquified Petroleum Gas Combustion; Wood Waste Combustion In
Boilers; Bagasse Combustion In Sugar Mills; Residential Fireplaces; Resident-
ial Wood Stoves; Waste Oil Combustion; Automobile Body Incineration; Conical
Burners; Open Burning; Stationary Gas Turbines For Electricity Generation;
Heavy Duty Natural Gas Fired Pipeline Compressor Engines; Gasoline And
Diesel Industrial Engines; Large Stationary Diesel And All Stationary Dual
Fuel Engines; Soap And Detergents; and Storage Of Organic Liquids.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATl Field/Group
Stationary Sources
Point Sources
Area Sources
Emissions
Emission Factors
Air Pollutants
18. DISTRIBUTION STATEMENT
19. SECURITY CLASS (Tins Report)
2O. SECURITY CLASS (Tills page)
282.
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
•U.S. Government Printing Office: 1992— 728-090/67002
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