## December 2009



# Emission Estimation Protocol for Petroleum Refineries

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Submitted to: Office of Air Quality Planning and Standards U.S. Environmental Protection Agency Research Triangle Park, NC 27711

Submitted by: RTI International 3040 Cornwallis Road Research Triangle Park, NC 27709-2194

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## Table of Contents 1. Introduction ......................................................................................................................................... 1-1 1.1 Completeness ............................................................................................................................ 1-1 1.2 Data Quality .............................................................................................................................. 1-9 1.3 Calculations and Significant Digits ........................................................................................ 1-10 2. Equipment Leaks ................................................................................................................................. 2-1 2.1 Methodology Rank 1 for Equipment Leaks.............................................................................. 2-2 2.2 Methodology Ranks 2 and 3 for Equipment Leaks .................................................................. 2-3 2.2.1 Speciating Equipment Leak Emissions ....................................................................... 2-7 2.2.2 Calculating Annual Equipment Leak Emissions......................................................... 2-8 2.3 Methodology Ranks 4 and 5 for Equipment Leaks ................................................................ 2-10 3. Storage Tanks ...................................................................................................................................... 3-1 3.1 Methodology Rank 1 for Storage Tanks ................................................................................... 3-1 3.2 Methodology Rank 2 for Storage Tanks ................................................................................... 3-2 3.3 Methodology Rank 3 for Storage Tanks ................................................................................... 3-3 4. Stationary Combustion Sources .......................................................................................................... 4-1 4.1 Methodology Rank 1 for Stationary Combustion Sources ....................................................... 4-2 4.2 Methodology Rank 2 for Stationary Combustion Sources ....................................................... 4-4 4.3 Methodology Rank 3A for Stationary Combustion Sources .................................................... 4-8 4.4 Methodology Rank 3B for Stationary Combustion Sources .................................................. 4-10 4.5 Methodology Rank 4 for Stationary Combustion Sources ..................................................... 4-11 4.5.1 Default Emissions Factors for Process Heaters ........................................................ 4-13 4.5.2 Default Emissions Factors for Boilers ...................................................................... 4-18 4.5.3 Default Emissions Factor for Internal Combustion Engines ..................................... 4-23 4.5.4 Default Emissions Factor for Turbines ..................................................................... 4-30 5. Process Vents ...................................................................................................................................... 5-1 5.1 Catalytic Cracking Units .......................................................................................................... 5-1 5.1.1 Methodology Ranks 1 and 2 for Catalytic Cracking Units ......................................... 5-2 5.1.2 Methodology Ranks 3 and 4 for Catalytic Cracking Units ......................................... 5-2 5.1.4 Methodology Rank 5B for Catalytic Cracking Units .................................................. 5-9 5.2 Fluid Coking Units ................................................................................................................. 5-11 5.2.1 Methodology Ranks 1 and 2 for Fluid Coking Units ................................................ 5-12 5.2.2 Methodology Ranks 3 and 4 for Fluid Coking Units ................................................ 5-12 5.2.3 Methodology Rank 5 for Fluid Coking Units ........................................................... 5-12 5.3 Delayed Coking Units ............................................................................................................ 5-12 5.3.1 Methodology Ranks 1 and 2 for Delayed Coking Units ........................................... 5-13 5.3.2 Methodology Ranks 3 and 4 for Delayed Coking Units ........................................... 5-13 5.3.3 Methodology Rank 5 for Delayed Coking Units ...................................................... 5-13 5.4 Catalytic Reforming Units ...................................................................................................... 5-14 5.4.1 Emissions Estimation Methodology for Catalytic Reforming Units ........................ 5-15 5.5 Sulfur Recovery Plants ........................................................................................................... 5-16 5.5.1 Methodology Ranks 1 and 2 for Sulfur Recovery Plants .......................................... 5-17 5.5.2 Methodology Ranks 3 and 4 for Sulfur Recovery Plants .......................................... 5-17 5.5.3 Methodology Rank 5 for Sulfur Recovery Plants ..................................................... 5-18 5.6 Other Miscellaneous Process Vents ....................................................................................... 5-18 5.6.1 Hydrogen Plant Vents ............................................................................................... 5-18 5.6.2 Asphalt Plant Vents ................................................................................................... 5-18

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iii 5.6.3 Coke Calcining.......................................................................................................... 5-21 5.6.4 Blowdown Systems ................................................................................................... 5-23 5.6.5 Vacuum Producing Systems ..................................................................................... 5-24 6. Flares ................................................................................................................................................... 6-1 6.1 Methodology Rank 1 for Flares ................................................................................................ 6-2 6.2 Methodology Rank 2 for Flares ................................................................................................ 6-3 6.3 Methodology Rank 3 for Flares ................................................................................................ 6-4 6.4 Methodology Rank 4 for Flares ................................................................................................ 6-6 6.5 Methodology Ranks 5 and 6 for Flares .................................................................................... 6-7 7. Wastewater Collection and Treatment Systems .................................................................................. 7-1 7.1 Methodology Rank 1 for Covered and Vented Units ............................................................... 7-2 7.2 Methodology Rank 2 for Uncovered Units .............................................................................. 7-2 7.2.1 Primary Weirs ............................................................................................................. 7-4 7.2.2 Junction Boxes and Lift Stations ................................................................................ 7-4 7.2.3 Oil-Water Separators .................................................................................................. 7-5 7.2.4 Dissolved Air Flotation Units ..................................................................................... 7-5 7.2.5 Equalization Tanks ...................................................................................................... 7-6 7.2.6 Biological Treatment Units ......................................................................................... 7-6 7.2.7 Polishing Ponds ........................................................................................................... 7-7 7.2.8 Site-Specific Factors ................................................................................................... 7-8 7.2.9 Model Validation ........................................................................................................ 7-8 7.3 Methodology Rank 3 for Uncovered Units .............................................................................. 7-8 7.3.1 Engineering Estimates Based on Wastewater Treatment Plant Load ......................... 7-8 7.3.2 Engineering Estimates Based on Process Capacities .................................................. 7-9 8. Cooling Towers ................................................................................................................................... 8-1 8.1 Methodology Ranks 1 and 2 for Cooling Towers .................................................................... 8-2 8.2 Methodology Rank 3 for Cooling Towers ................................................................................ 8-6 8.3 Methodology Rank 4 for Cooling Towers ................................................................................ 8-8 8.4 Methodology Rank 5 for Cooling Towers .............................................................................. 8-10 8.4.1 VOC and Organic HAP ............................................................................................ 8-10 8.4.2 Particulate Matter Emissions .................................................................................... 8-12 8.4.3 Chlorine Emissions ................................................................................................... 8-14 9. Product Loading Operations ................................................................................................................ 9-1 9.1 Data Available on Product Composition and Properties .......................................................... 9-2 9.2 Methodology Rank 1 for Product Loading Operations ............................................................ 9-2 9.3 Methodology Ranks 2 and 3 for Product Loading Operations ................................................. 9-2 9.4 Methodology Rank 4 for Product Loading Operations ............................................................ 9-4 9.4.1 AP

- 42 Emissions Factors for ―Product‖ or ―Total Hydrocarbon‖ Emissions ............. 9-4 9.4.2 Estimate Controlled or Uncontrolled Emissions and Speciate ................................... 9-5 9.4.3 Capture Efficiency ...................................................................................................... 9-6 9.4.4 Control Efficiency ....................................................................................................... 9-7 10. Fugitive Dust Sources ....................................................................................................................... 10-1 11. Startup and Shutdown ....................................................................................................................... 11-1 11.1 Gaseous Process Vessel Depressurization and Purging ......................................................... 11-1 11.2 Liquid Process Vessel Depressurization and Purging ............................................................ 11-2

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iv 12. Malfunctions ...................................................................................................................................... 12-1 12.1 Control Device Malfunctions ................................................................................................. 12-1 12.2 Vessel Overpressurization ...................................................................................................... 12-2 12.3 Spills ....................................................................................................................................... 12-3 13. References ......................................................................................................................................... 13-1 Appendix A

— Average Stream Compositions .......................................................................................... A-1 Appendix B

—

Wastewater Treatment System Equations ......................................................................... B-1 Appendix C

— Primer for TANKS Model Users ....................................................................................... C-1 Appendix D

— Emission Factors from Air Toxic Emission Factors for Combustion Sources Using Petroleum Based Fuels

– Final Report, Volume 2

– Development of Emission Factors Using CARB Approach ................................................................................................................................. D-1

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## List of Figures 7-1 Typical refinery wastewater treatment system. ............................................................................. 7-1 7-2 Simplified drawing of a constituent mass balance in a biological treatment unit. ........................ 7-3



## List of Tables 1-1 Summary of Pollutants and Emissions Sources Inclusion in a Petroleum Refinery’s Emissions Inventory...................................................................................................................... 1-2 2-1 Summary of Equipment Leak Emissions Estimates ..................................................................... 2-2 2-2 Equipment Leak Rate for Refinery Equipment Components ....................................................... 2-4 2-3 Refinery Screening Ranges Emission Factors a 

### ............................................................................. 2-5 2-4 Median Equipment Leak Component Counts for Small Model Processes ................................. 2-12 2-5 Median Equipment Leak Component Counts for Large Model Processes ................................. 2-13 2-6 Refinery Average Component Emissions Factors ...................................................................... 2-14 2-7 Concentration of Benzene in Refinery Process Unit Streams ..................................................... 2-14 3-1 Summary of Typical Hierarchy of Storage Tank Emissions Estimates ........................................ 3-1 3-2 Default Emissions Factors for Petroleum Refinery Storage Tanks .............................................. 3-3 4-1 Summary of Typical Hierarchy of Stationary Combustion Source Emissions Estimates ............ 4-2 4-2 Molar Exhaust Volumes and Molar Heat Content of Refinery Fuel Gas Constituents ................ 4-5 4-3 Summary of Emissions Factors for Process Heaters Firing Various Fuels ................................ 4-13 4-4 Summary of Emissions Factors for Boilers Firing Various Fuels .............................................. 4-18 4-5 Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuels ........... 4-24 4-6 Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuels ........... 4-26 4-7 Summary of Emissions Factors for Turbines Firing Various Fuels ............................................ 4-30 4-8 Summary of Emissions Factors for Turbines Firing Various Fuels ............................................ 4-33 5-1 Summary of Typical Hierarchy of Process Vent Emissions Estimates ........................................ 5-1 5-2 Default Size Distribution for Filterable PM from CCU ................................................................ 5-5 5-3 Default Ratio of Metal HAP Composition of CCU Fines ............................................................ 5-8 5-4 Organic HAP Emissions Factors for CCU Catalyst Regenerator Vent ...................................... 5-10 5-5 Average Vent Concentrations and Emissions Factors for Delayed Coking Unit Vents ............. 5-13 5-6 Emissions Factors for CRU Catalyst Regeneration Vent ........................................................... 5-16 5-7 Emissions Factors for Sulfur Recovery Plants ............................................................................ 5-18 5-8 Emission Factors for Asphalt Blowing (U.S. EPA, 1995a) ........................................................ 5-19 5-9 Asphalt Blowing

– Nonmethane Volatile Organic Compounds Speciation ............................... 5-20 5-10 Summary of Emissions Factors for Controlled Asphalt Blowing ............................................... 5-20 5-11 Summary of Emissions Factors for Controlled Coke Calcining ................................................. 5-21 5-12 Default Emissions Factors for Blowdown Systems .................................................................... 5-24 5-13 Default Emissions Factor for Vacuum Producing Systems ........................................................ 5-24 6-1 Summary of Flare Emissions Estimate Methodologies ................................................................ 6-2 6-2 Flare Energy Consumption-Based Emissions Factors .................................................................. 6-5 6-3 TCEQ Energy Consumption-Based Emissions Factors for Flares ............................................... 6-5 6-4 Emissions Factors for Soot from Flares ........................................................................................ 6-7 6-5 Flare General Emissions Factors .................................................................................................. 6-8 7-1 Summary of Wastewater Treatment Emissions Estimates............................................................ 7-2 7-2 Critical Inputs, Variables, and Chemical Properties Specific to Primary Weir Air Emissions Calculations ................................................................................................................. 7-4 7-3 Critical Inputs, Variables, and Chemical Properties Specific to Junction Box and Lift Station Air Emissions Calculations .............................................................................................. 7-4

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vi 7-4 Critical Inputs, Variables, and Chemical Properties Specific to Oil-Water Separators Air Emissions Calculations ................................................................................................................. 7-5 7-5 Critical Inputs, Variables, and Chemical Properties Specific to DAF Air Emissions Calculations .................................................................................................................................. 7-5 7-6 Critical Inputs, Variables, and Chemical Properties Specific to Equalization Tank Air Emissions Calculations ................................................................................................................. 7-6 7-7 Critical Inputs, Variables, and Chemical Properties Specific to Biological Treatment Unit Air Emissions Calculations ........................................................................................................... 7-7 7-8 Model Process Unit Characteristics for Petroleum Refinery Wastewater .................................... 7-9 7-9 Refinery Wastewater Contaminant Concentrations as a Ratio to Benzene ................................ 7-10 7-10 Default Mass Emissions Factors for Refinery Wastewater Collection and Treatment Systems ....................................................................................................................................... 7-10 8-1 Summary of Cooling Tower Emissions Estimation Methodologies ............................................. 8-1 8-2 Data Requirements for VOC or Speciated VOC Emissions, Methodology Ranks 1 and 2 .......... 8-3 8-3 Data Requirements for Speciated Compound Emissions, Methodology Rank 3 .......................... 8-7 8-4 Data Requirements for Speciated Compound Emissions, Methodology Rank 4 .......................... 8-9 8-5 Data Requirements for VOC or Speciated VOC Emissions, Methodology Rank 5 ................... 8-11 9-1 Summary of Product Loading Operations Emissions Estimates................................................... 9-1 9-2 Data Requirements for VOC or Speciated Emissions, Methodology Rank 1 or 2 ....................... 9-3 9-3 Saturation Factors ......................................................................................................................... 9-5 9-4 VOC Emissions Factors for Marine Vessel Loading of Gasoline at Marine Terminals ............... 9-5 9-5 Capture Efficiencies for Vapor Collection Systems ..................................................................... 9-6 9-6 Sample Calculation Methodology Rank 4

— Summary of Emissions (When Property Data Are Not Available) ...................................................................................................................... 9-10 10-1 Default Values for Fugitive Dust Emission Estimates ................................................................ 10-1 12-1 Control Device Efficiency and Multiplier Factors for Control Device Malfunctions ................ 12-2

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## List of Acronyms and Abbreviations μg/L micrograms per liter acfm actual cubic feet per minute API American Petroleum Institute atm atmosphere atm/in. of Hg atmospheres per inch of mercury bbl/cd bbl/sd barrels per calendar day barrels per stream day bbl/hr barrel s per hour BID Background Information Document BOX test aerated reactor test Btu/mol British thermal units per mole Btu/scf British thermal units per standard cubic feet BWON Benzene Waste Operations NESHAP CARB California Air Resources Board CCU catalytic cracking unit CEMS continuous emission monitoring system CERMS continuous emission rate monitoring system CFR Code of Federal Regulations CH 4 

### methane Cl 2 

### chlorine CO carbon monoxide COS carbonyl sulfide Cr +6 

### hexavalent chromium CR U crude distillation unit CS 2 

### carbon disulfide DAF dissolved air flotation DIAL Differential Absorption Light Detection and Ranging DNF dissolved nitrogen flotation dscf/MMBtu dry standard cubic feet per million British thermal unit dscf/mol dry s tandard cubic feet per mole dscfm dry standard cubic feet per minute E

- cat equilibrium catalyst EPA U.S. Environmental Protection Agency

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viii ESP electrostatic precipitators FCCU fluid catalytic cracking unit FCU fluid coking unit FID flame ionization detection g/hr grams per hour g/mol grams per mole gal/bbl gallons of wastewater per barrel of capacity at a given process unit GC gas chromatograph GC/MS gas chromatography/mass spectrometry GHG greenhouse gases H 2 

### S hydrogen sulfide HAP hazardo us air pollutants HCl hydrogen chloride hepta

- CDD heptachloro

- dibenzo

- p - dioxin Hg mercury hr/yr hours per year IAF induced air flotation in. inches kg TOC/hr kilograms of TOC per hour kg/hr kilograms per hour kg/hr/source kilograms per hour per source kg/kg

- mol kilogram per kilogram mole kg/yr kilograms per year kPa kilopascals lb/dscf pounds per standard cubic foot lb/lb

- mol pounds per pound mole lb/lton pounds per long ton lb/Mgal pounds per thousand gallons lb/MMbbl pounds per million barrels lb/MMBtu pounds per million British thermal unit lb/MMcf pounds per million cubic feet lb/ton pounds per ton lb/ton coke pounds per ton of petroleum coke LDAR leak detection and repair

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ix LIDAR Light Detection and Ranging

m 3 

### /day cu bic meters per day

m 3 

### /min cubic meters per minute MACT Maximum Achievable Control Technology mg/kg milligrams per kilogram min/hr minutes per hour mL/min milliliters per minute mL

- atm/mol

- K milliliters

- atmospheres per mole

- Kelvin MMBtu/scf mi llion British thermal units per standard cubic foot MW molecular weight Ni nickel NMOC nonmethane organic compounds NMVOC nonmethane volatile organic compounds NO nitric oxide NO 2 

### nitrogen dioxide NO x 

### nitrogen oxides NSPS new source performance standards O 2 

### oxygen OCDD octachloro

- dibenzo

- p - dioxin OCDF octachloro

- dibenzo

- furan OVA organic vapor analyzer PAH polycyclic aromatic hydrocarbons PCB polychlorinated biphenyls PM particulate matter PM 10 

### PM emissions that are 10 μm in diameter or less PM 10 

### - FIL filterable (or front

- half catch) portion of the PM emissions that are 10 μm in diameter or less PM 10 

### - PRI ―primary‖ PM emissions that are 10 μm in diameter or less PM 2.5 

### PM emissions that are 2.5 μm in diameter or less PM 2.5 

### - FIL filtera ble (or front

- half catch) portion of the PM emissions that are 2.5 μm in diameter or less PM 2.5 

### - PRI ―primary‖ PM emissions that are 2.5 μm in diameter or less PM

- CON condensable PM (or back

- half catch) POM polycyclic organic matter POTW publicly owned treatment works

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x ppmv parts per million by volume ppmw parts per million by weight psi pounds per square inch psia pounds per square inch absolute psig pounds per square inch gauge QA quality assurance QC quality control scf/kg

- mol standard cubic feet per kilogram mole scf/lb

- mol standard cubic feet per pound mole SCR selective catalytic reduction SNCR selective non

- catalytic reduction SO 2 

### sulfur dioxide SRU sulfur recovery unit SSM startup, shutdown, or malfunction SV screening value TCCU thermal catalytic cracking unit TCDD tetrachlorodibenzo

- p - dioxin TDS total dissolved solids TEQ toxic equivalents THC total hydrocarbon TOC total organic compound tons/hr tons per hour tons/kg tons per kilogram tons/yr tons per year VOC vol% volatile organic compounds volume percent WebFIRE Internet version of the Factor Information Retrieval (FIRE) data system WF weight fraction WSPA Western States Petroleum Association wt% weight percent

° C degrees Celsius

° F

° R degrees Fahrenh eit degrees Rankine

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1-1 

# 1. Introduction This Refinery Emissions Protocol document is intended to provide guidance and instructions to petroleum refinery owners and operators and to federal, state, and local agencies for the purpose of improving emissions inventories for the petroleum refining industry. This document presents a hierarchy of emissions measurement or estimation methods for various petroleum refinery emissions sources and provides a listing of pollutants for which emissions are anticipated for each source type. For each emission source, the various emissions measurement of estimation methods specific to that source are ranked in order of preference, with ―Methodology Rank 1‖ being the preferred method, followed by ―Methodology Rank 2,‖ and so on. Refinery owners and operators and other inventory developers are requested to use the highest ranked method (with Methodology Rank 1 being the highest) for which data are available. Methodology Rank 1 or 2 generally rely on continuous emissionsmeasurements. When continuous measurement data are not available, engineering calculations or sitespecific emissions factors (Methodology Ranks 3 and 4) are specified; these methods generally need periodic, site-specific measurements. When site-specific measurement or test data are not available, default emissions factors (Methodology Rank 5) are provided. In the development of this Refinery Emissions Protocol document, the U.S. Environmental Protection Agency ( EPA ) reviewed available source test data to verify or refine existing emissions factors and develop new emissions factors for sources that currently do not have default emissions factors. EPA also provided guidance on characterizing and quantifying emissions associated with startup, shutdown, and malfunction events. While many of the emission factors presented in this document have not undergone full review for the incorporation of these emission factors into AP-42 (U.S. EPA, 1995a) or WebFIRE (the internet version of the Factor Information Retrieval (FIRE) data system), the emission factors provided in this Refinery Emissions Protocol document should be used for refinery emissions sources. Efforts are on-going to update the AP-42 emission factors for petroleum refineries. As these emission factors are updated, it is EPA’s intent to revise this document to include the updated AP -42 emission factors. As such, the EPA website (http://www.epa.gov/ttn/chief/efpac/esttools.html ) should be checked prior to preparing the emissions inventory to ensure the most recent Refinery Emissions Protocol document is used. 

## 1.1 Completeness Emission estimates should be provided for each emission source at the refinery. While this Refinery Emissions Protocol document attempts to identify and provide methodologies for each emissions source , th ere are sources included in this Refinery Emissions Protocol document for which no emissions data are available to provide default (Rank 5) methods. Additionally, there may be certain sources at the refinery that have not been included in this version of the Refinery Emissions Protocol document. Emission estimates should be provided for EVERY emission source at the refinery, even for emissions sources that have not yet been included in this Refinery Emissions Protocol document or for which default methodologies are not currently provided. Similarly, emissions should be provided for each pollutant [except for greenhouse gases (GHG), which are required to be reported under the Mandatory Greenhouse Gas Emissions Reporting Rule (Final Rule, 74 Federal Register [FR] 56260)] emitted from each emission source. Table 1-1 provides a listing of the pollutants expected to be emitted by various sources described in this protocol document. Filled circles indicate compound/emission source pairings for which emission estimates should be developed. Hollow circles indicate pairings for which data may be reported (if the chemical is present or if data are available to speciate to that extent), but the inventory can be deemed complete without these estimates. In general, speciation of volatile organic compound (VOC) emissions is preferred to overall VOC emission measurement methods via EPA Methods 25, 25A-E, or 305.

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1-2 Table 1-1. Summary of Pollutants and Emissions Sources Inclusion

in a Petroleum Refinery’s Emissions Inventory

CA S Number or Pollutant Code SubstanceEquipment LeaksStorage TanksStationary Combustion Process VentsFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctionsCatalytic CrackingUnitFluid Coking UnitDelayed CokingUnitCatalyticReforming UnitSulfur RecoveryPlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdownSystemsVacuum Systems

Criteria Pollutants 630

- 08

- 0 Carbon monoxide ● ● ● ● ● ● ○ ○ 7439

- 92

- 1 Lead ● ● ● ● ○ ○
PM10

- PRI Particulate matter (PM) ≤

10 micrometers (μm) ● ● ● ● ● ● ● ● ● ○ ○
PM10

- FIL Filterable PM ≤ 10 μm ● ● ● ● ● ● ● ● ● ○ ○ PM25

- PRI PM ≤ 2.5 μm ● ● ● ● ● ● ● ● ● ○ ○ PM25

- FIL Filterable PM ≤ 2.5 μm ● ● ● ● ● ● ● ● ● ○ ○ PM

- CON Condensable PM ● ● ● ● ● ● ● ● ○ ○ ○ 10102

- 44

- 0 Nitrogen dioxide ● ● ● ● ● ● ○ ○ NOX Nitrogen oxides ● ● ● ● ● ● ○ ○ 7449

- 09

- 5 Sulfur dioxide ● ● ● ● ● ● ● ●
VOC Volatile organic

compounds ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● Specific VOC Constituents (Compounds listed below plus those listed under “Volatile Organic HAP”)
74

- 85

- 1 Ethylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 74

- 86

- 2 Acetylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 74

- 98

- 9 Propane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 115

- 07

- 1 Propylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 463

- 49

- 0 Propadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 106

- 97

- 8 n - Butane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 75

- 28

- 5 Isobutane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 160

- 98

- 9 1

- Butene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 107

- 07

- 7 2

- Butene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 115

- 11

- 7 Isobutene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 590

- 19

- 2 1,2

- Butadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 109

- 66

- 0 n - pentane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 78

- 8

- 4 2

- Methylbutane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ (continued)

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1-3 Table 1 - 1. Summary of Pollutants and Emissions Sou rces Inclusion in a Petroleum Refinery’s Emissions Inventory (continued)

CAS Number or Pollutant Code SubstanceEquipment LeaksStorage TanksStationary Combustion Process VentsFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctionsCatalytic CrackingUnitFluid Coking UnitDelayed CokingUnitCatalyticReforming UnitSulfur RecoveryPlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdownSystemsVacuum Systems

287

- 92

- 3 Cyclopentane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 591

- 95

- 7 1,2

- Pentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 1574

- 41

- 0 1

- cis

- 3

- Pentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 2004

- 70

- 8 1

- trans
- 3

- Pentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 591

- 93

- 5 1,4

- Pen tadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 591

- 96

- 8 2,3

- Pentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 598

- 25

- 4 3

- Methyl

- 1,2

- butadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 78

- 79

- 5 2

- Methyl

- 1,3

- butadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 542

- 9 2

- 7 Cyclopentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 110

- 82

- 7 Cyclohexane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 108

- 87

- 2 Methylcylcohexane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
142

- 82

- 5 Heptane (and isomers) ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
1 11

- 65

- 9 Octane (and isomers) ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 78

- 93

- 3 Methyl ethyl ketone ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 251

- 13

- 7 Trimethylbenzene(s) ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ Hazardous Air Pollutants (HAP) Volatile Organic HAP
75

- 07

- 0 Acetaldehyde ○ ○ ● ● ● ● ● ○ ● ● ● ○ ○ ● ○ ○ ○ ○ ○ 107

- 02

- 8 Acrolein ○ ○ ● ● ● ● ● ○ ○ ○ ● ○ ○ ● ○ ○ ○ ○ ○ 62

- 53

- 3 Analine ○ ○ ● ● ● ● ● ○ ○ ○ ● ○ ○ ● ○ ○ ○ ○ ○ 71

- 43

- 2 Benzene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 74

- 83

- 9 Bromomethane ○ ○ ○ 106

- 99

- 0 1,3

- Butadiene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 75

- 00

- 3 Chloroethane ○ ○ ○ ○ 67

- 66

- 3 Chloroform ○ ○ ● ○ 74

- 87

- 3 Chloromethane ○ ○ ○ ○ 98

- 82

- 8 Cumene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● (continued)

### Version 1.0 Section 1

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1-4 Table 1 - 1. Summary of Pollutants and Emissions Sou rces Inclusion in a Petroleum Refinery’s Emissions Inventory (continued)

CAS Number or Pollutant Code SubstanceEquipment LeaksStorage TanksStationary Combustion Process VentsFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctionsCatalytic CrackingUnitFluid Coking UnitDelayed CokingUnitCatalyticReforming UnitSulfur RecoveryPlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdownSystemsVacuum Systems

106

- 93

- 4 1,2

- Dibromoethane ○ ○ ○ ○ 106

- 46

- 7 1,4

- Dichlorobenzene ○ ○ ○ ○ ○ 75

- 34

- 3 1,1

- Dichloroethane ○ ○ ○ ○ 107

- 06

- 2 1,2

- Dichloroethane ○ ○ ○ ○ 75

- 35

- 4 1,1

- D ichloroethylene ○ ○ ● ○ 78

- 87

- 5 1,2

- Dichloropropane ○ ○ ○ ○ 542

- 75

- 6 1,3

- Dichloropropene ○ ○ ○ ○ 111

- 42

- 2 Diethanolamine ● ● ● ○ ○ ○ 100

- 41

- 4 Ethylbenzene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 50

- 00

- 0 Formaldehyde ○ ○ ● ● ● ● ● ● ● ● ○ ○ ● ○ ○ ○ ● ● 67

- 72

- 1 Hexachloroethane ○ ○ ○ ○ 110

- 54

- 3 Hexane ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 67

- 56

- 1 Methanol ● ● ○ 108

- 10

- 1 Methyl isobutyl ketone ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 1634

- 04

- 4 Methyl tert

- butyl ether ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 100

- 42

- 5 Styrene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 79

- 34

- 5 1,1,2,2

- Tetrachloroethane ○ ○ ● ○ 127

- 18

- 4 Tetrachloroethylene ○ ○ ● ○ 108

- 88

- 3 Toluene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 79

- 00

- 5 1,1,2

- Trichloroethane ○ ○ ● ○ 79

- 01

- 6 Trichloroethylene ○ ○ ● ○ 121

- 44

- 8 Triethylamine ● ● ● ○ ○ ○ 540

- 84

- 1 2,2,4

- Trimethylpentane ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 593

- 60

- 2 Vinyl bromide ○ ○ ○ ○ 75

- 01

- 4 Vinyl chloride ○ ○ ● ○ 95

- 47

- 6 o - Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● (continued)

### Version 1.0 Section 1

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1-5 Table 1 - 1. Summary of Pollutants and Emissions Sou rces Inclusion in a Petroleum Refinery’s Emissions Inventory (continued)

CAS Number or Pollutant Code SubstanceEquipment LeaksStorage TanksStationary Combustion Process VentsFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctionsCatalytic CrackingUnitFluid Coking UnitDelayed CokingUnitCatalyticReforming UnitSulfur RecoveryPlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdownSystemsVacuum Systems

108

- 38

- 3 m - Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 106

- 42

- 3 p - Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 1330

- 20

- 7 Xylene s (total) ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● Semi - Volatile and Non - Volatile Organic HAP (except dioxins, furans, and polychlorinated biphenyls [PCB]) 83

- 32

- 9 Acenaphthene P OM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 208

- 96

- 8 Acenaphthylene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 120

- 12

- 7 Anthracene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 56

- 55

- 3 Benzo(a)anthracene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 50

- 32

- 8 Benzo(a)pyrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 205

- 99

- 2 Benzo(b) fluoranthene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 192

- 97

- 2 Benzo(e)pyrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 191

- 24

- 2 Benzo(g,h,i)perylene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 207

- 08

- 9 Benzo(k)fluoranthene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 92

- 52

- 4 Biphenyl POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●
117

- 81

- 7 Bis(2

- ethyl hexyl)

phthalate ○ ● ● ○
91

- 58

- 7 2

- Chloronaphthalene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 108

- 39

- 4 m - Cresol ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ● ● 95

- 48

- 7 o - Cresol ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ● ● 106

- 44

- 5 p - Cresol ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ● ● 1319

- 77

- 3 Cresols (total) ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ● ● 218

- 01

- 9 Chrysene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 53

- 70

- 3 Dibenz(a,h)anthracene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 84

- 74

- 2 di

- n - Butyl phthalate ○ ● ● ○ 84

- 66

- 2 Diethyl

- phthalate ○ ● ● ○
57

- 97

- 6 7,12

- Dimethylbenz(a)

anthracene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● (continued)

### Version 1.0 Section 1

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1-6 Table 1 - 1. Summary of Pollutants and Emissions Sou rces Inclusion in a Petroleum Refinery’s Emissions Inventory (continued)

CAS Number or Pollutant Code SubstanceEquipment LeaksStorage TanksStationary Combustion Process VentsFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctionsCatalytic CrackingUnitFluid Coking UnitDelayed CokingUnitCatalyticReforming UnitSulfur RecoveryPlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdownSystemsVacuum Systems

206

- 44

- 0 Fluoranthene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 86

- 73

- 7 Fluorene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●
193

- 39

- 5 Indeno(1, 2,3

- cd)

pyrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●
56

- 49

- 5 3

- Methylchloranthrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 91

- 57

- 6 2

- Methylnaphthalene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 218

- 01

- 9 Chrysene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 91

- 20

- 3 Naphthalene POM ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ○ ● ● 198

- 55

- 0 Perylene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 85

- 01

- 8 Phenanthrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● 108

- 95

- 2 Phenol ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ● ● 129

- 00

- 0 Pyrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ● Dioxin/Furans/PCB 1746

- 01

- 6 Dioxin: 4D 2378 j ● ● ● ● ● ○ ○ ○ 40321

- 76

- 4 Dioxin: 5D 12378 j ○ ○ ○ ○ ○ ○ ○ ○ 39227

- 28

- 6 Dioxin: 6D 123478 j ○ ○ ○ ○ ○ ○ ○ ○ 57653

- 85

- 7 Dioxin: 6D 123678 j ○ ○ ○ ○ ○ ○ ○ ○ 19408

- 74

- 3 Dioxin: 6D 123789 j ○ ○ ○ ○ ○ ○ ○ ○ 35822

- 46

- 9 Dioxin: 7D 1234678 j ○ ○ ○ ○ ○ ○ ○ ○ 3268

- 87

- 9 Dioxin: 8D j ○ ○ ○ ○ ○ ○ ○ ○ 132

- 64

- 9 Dibenzofuran s ● ● ● ● ● ○ ○ ○ 51207

- 31

- 9 Furan: 4F 2378 k ○ ○ ○ ○ ○ ○ ○ ○ 57117

- 41

- 6 Furan: 5F 12378 k ○ ○ ○ ○ ○ ○ ○ ○ 57117

- 31

- 4 Furan: 5F 23478 k ○ ○ ○ ○ ○ ○ ○ ○ 70648

- 26

- 9 Furan: 6F 123478 k ○ ○ ○ ○ ○ ○ ○ ○ 57117

- 44

- 9 Furan: 6F 123678 k ○ ○ ○ ○ ○ ○ ○ ○ 72918

- 21

- 9 Furan: 6F 123789 k ○ ○ ○ ○ ○ ○ ○ ○ (continued)

### Version 1.0 Section 1

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1-7 Table 1 - 1. Summary of Pollutants and Emissions Sou rces Inclusion in a Petroleum Refinery’s Emissions Inventory (continued)

CAS Number or Pollutant Code SubstanceEquipment LeaksStorage TanksStationary Combustion Process VentsFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctionsCatalytic CrackingUnitFluid Coking UnitDelayed CokingUnitCatalyticReforming UnitSulfur RecoveryPlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdownSystemsVacuum Systems

60851

- 34

- 5 Furan: 6F 234678 k ○ ○ ○ ○ ○ ○ ○ ○ 67562

- 39

- 4 Furan: 7F 1234678 k ○ ○ ○ ○ ○ ○ ○ ○ 55673

- 8 9

- 7 Furan: 7F 1234789 k ○ ○ ○ ○ ○ ○ ○ ○ 39001

- 02

- 0 Furan: 8F k ○ ○ ○ ○ ○ ○ ○ ○
1336

- 36

- 3 Polychlorinated biphenyls

(total) ● ● ● ● ● ○ ○ ○
Metal HAP 7440

- 36

- 0 Antimony ● ● ● ○ 7440

- 38

- 2 Arsenic ● ● ● ○ 7440

- 41

- 7 Beryllium ● ● ● ○ 7440

- 43

- 9 Cadmium ● ● ● ○ 18540

- 29

- 9 Chromium (hexavalent) ● ● ● ○ 7440

- 47

- 3 Chromium (total) ● ● ● ○ 7440

- 48

- 4 Cobalt ● ● ● ○ 7439

- 92

- 1 Lead ● ● ● ○ 7439

- 96

- 5 Manganese ● ● ● ○ 7439

- 97

- 6 Mercury ● ● ● ○ 7440

- 02

- 0 Nickel ● ● ● ○ 7782

- 49

- 2 Selenium ● ● ● ○ Other Inorganic HAP
75

- 15

- 0 Carbo n disulfide ○ ○ ○ ○ ● ○ ○ ○ ○ ○ ○ ○ ○ ○ 463

- 58

- 1 Carbonyl sulfide ○ ○ ○ ○ ● ○ ○ ○ ○ ○ ○ ○ ○ ○ 7782

- 50

- 5 Chlorin e ● ● 7 647

- 0 1

- 0 Hydrogen chlor ide ○ ○ ○ ○ ● ○ ○ ○ ○ ○ ○ ○ ○ ○
74

- 90

- 8 Hydrogen cyanide (&

cyanide compou nds) ● ● ● ● ○ ○ ● ● ● ○ ○ ● ○ ○ ○ ● ●
7664

- 39

- 3 Hydrogen f luoride ○ ○ ○ 7723

- 14

- 0 Phosphorus ○ ○ ○ (continued)

### Version 1.0 Section 1

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1-8 Table 1 - 1. Summary of Pollutants and Emissions Sou rces Inclusion in a Petroleum Refinery’s Emissions Inventory (continued)

CAS Number or Pollutant Code SubstanceEquipment LeaksStorage TanksStationary Combustion Process VentsFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctionsCatalytic CrackingUnitFluid Coking UnitDelayed CokingUnitCatalyticReforming UnitSulfur RecoveryPlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdownSystemsVacuum Systems

Other Compounds of Interest
75

- 07

- 0 Ammonia ○ ○ ○ ● ● ○ ○ ○ 75

- 07

- 0 Ethane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ 7783

- 06

- 4 Hydrogen sulfide ● ○ ○ ○ ○ ● ● ○ ○ ○ ● ○ ○ ○ 7440

- 39

- 3 Barium ○ ○ ○ ○ 7440

- 50

- 8 Copper ○ ○ ○ ○ 7439

- 98

- 7 Molybdenum ○ ○ ○ ○ 7440

- 62

- 2 Vanadium ○ ● ● ○ 7440

- 66

- 6 Zinc ○ ○ ○ ○

● Designates compound/source pairings for which emissions estimates should be developed.

○ Designates compound/source pairings for which emissions estimates may be developed depending on the available data. POM Des ignates compounds t that meet the HAP definition of polycyclic organic matter (POM)

. j The listed HAP is 2,3,7,8

- Tetrachlorodibenzo

- p - dioxin (2378

- TCDD); other dioxin isomers are listed as they can be used to calculate a 2378 TCDD toxicity equivalence. Ab breviations used in the table are as follows: 4D 2378 = 2,3,7,8

- Tetrachlorodibenzo

- p - dioxin; 5D 12378 = 1,2,3,7,8

- Pentachlorodibenzo

- p - dioxin; 6D 123478 = 1,2,3,4,7,8

- Hexachlorodibenzo

p - dioxin; 6D 123678 = 1,2,3,6,7,8

- Hexachlorodibenzo

- p - dioxin; 6D 123789 = 1,2,3,7,8,9

- Hexachlorodibenzo

- p - dioxin; 7D 1234678 = 1,2,3,4,6,7,8

- Heptachlorodibenzo

- p - dioxin; 8D = Octachlorodibenzo

- p - dioxin. k The listed HAP is dibenzofurans. Abbreviations used in the table are as follows: 4F 2378 = 2,3,7,8

- Tetrachlorodibenzofura n; 5F 12378 = 1,2,3,7,8

- Pentachlorodibenzofuran; 5F 23478 = 2,3,4,7,8

- Pentachlorodibenzofuran; 6F 123478 = 1,2,3,4,7,8

- Hexachlorodibenzofuran; 6F 123678 = 1,2,3,6,7,8

- Hexachlorodibenzofuran; 6F 123789 = 1,2,3,7,8,9

- Hexachlorodibenzofuran; 6F 234678 = 2,3,4 ,6,7,8

- Hexachlorodibenzofuran; 7F 1234678 = 1,2,3,4,6,7,8

- Heptachlorodibenzofuran; 7F 1234789 = 1,2,3,4,7,8,9

- Heptachlorodibenzofuran; 8F = Octachlorodibenzofuran 

### Carbon dioxide, methane, and nitrous oxide are GHG expected to be emitted from petroleum refineries, but are not listed in this table. The Mandatory Greenhouse Gas Emissions Reporting Rule (74 FR 56260) requires detailed GHG emissions reporting from a variety of industry sectors and emission sources, including petroleum refineries and stationary combustion sources (40 Code of Federal Regulations (CFR) Part 98, Subparts Y and C, respectively). Consequently, this Refinery Emissions Protocol document focuses primarily on criteria and toxic air pollutants (i.e., the pollutants listed in Table 1-1 ). Emission estimates for GHG should be calculated and reported according to the methodologies and requirements in the GHG reporting rule. Note that the ―tiers‖ used in 40 CFR Part 98 Subpart C are listed in opposite order from the ―ranks‖ used in this Refinery Emissions Protocol document. That is, the Tier 4 method for stationary combustion sources is equivalent to Methodology Rank 1 for combustion sources in this protocol document; Tier 3 method is equivalent to Methodology Rank 2, and so on. Some criteria pollutants such as PM 10 

### or PM 2.5 

### have special reporting nomenclatures to indicate the fraction of the PM emissions that are filterable or condensable (see PM Emissions Inventory Nomenclature text box). Other criteria pollutants, such as nitrogen dioxide (NO 2 

### ), are often determined or

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1-9 regulated as a combination of chemicals. For example, nitrogen oxides (NO X 

### ), is the sum of NO 2 

### and nitric oxide (NO) emissions. The inclusion of these additional nomenclatures or groupings in Table 1-1 is not intended to suggest t hat these compounds are criteria pollutants, but these ―pollutants‖ should be included in the refinery emissions inventory.

While Table 1-1 is intended to provide a comprehensive list of pollutants for each emission source for which emissions estimates should be provided, there may be pollutants released from some sources for which we have little or no information. I f there is credible information that emissions of other pollutants are released from a given emissions source, than emissions estimates for these additional pollutants should also be provided. 

## 1.2 Data Quality The consistent use of standardized methods and procedures is essential in the compilation of reliable emissions inventories. Quality assurance (QA) and quality control (QC) of an emissions inventory are accomplished through a set of procedures that ensure the quality and reliability of data collection and analysis. These procedures include the use of appropriate emissions estimation techniques, applicable and reasonable assumptions, accuracy/logic checks of computer models, and checks of calculations and data reliability. Depending upon the technical approach used to estimate emissions, a checklist with all of the particular data needs should be prepared to verify that each piece of information is used accurately and appropriately. Appropriate metadata (data about the data) should be maintained and reported to assist data users with assessing the accuracy of the reported emissions. For example, the methodology (or Methodology Rank) used to estimate the emissions should be reported. If the emissions estimates rely on activity data (e.g., process throughput for emission factors based on process throughput), the activity data should also be reported. QA/QC and other metadata records should also be maintained to allow verification of the reported emissions. For measured emissions, these metadata include manufacturer’s design specifications for accuracy, initial calibrations, periodic calibration checks, and other QA/QC procedures used to ensure the accuracy of the measurement device(s). For source tests used to develop site-specific emissions factors, the metadata include results of field and laboratory blanks, duplicate analyses, method detection limits, isokinetic and cyclonic flow checks (if applicable), and key process operating data (e.g., throughput, temperature, material processed, etc.). For some pollutants, there may be different methods by which the emissions can be determined. For example, VOC emissions may be determined using a ―total organics‖ method (e.g., using EPA Method 25, 25A through 25E, or 305) or by speciating individual VOC and summing the emissions of these compounds to determine the overall VOC emissions. When reporting VOC emissions, therefore, it should be clearly indicated if the emissions are determined ―as methane‖ (or ―as‖ whatever compound was used to calibrate the total organic analyzer) or if the emissions are determined by summing emissions of individual VOC constituents. These metadata assist users of the inventory data and help to ensure that the inventory data are correctly and consistently used when performing subsequent analyses. PM Emissions Inventory Nomenclature PM emissions inventories have their own nomenclature and structure. A complete PM emissions inventory includes the following components:

 PM 10 - PRI: ―Primary‖ PM emissions that are 10 μm in diameter or less. PM 10 - PRI = PM 10 - FIL + PM

- CON.

 PM 10 - FIL: Filterable (or front

- half catch) portion of the PM emissions that are 10 μm in diameter or less.

 PM

- CON: Condensable PM (or back

- half catch). All condensable PM is assume d to be less than 2.5 microns ( μm ) in diameter (PM 2.5 ).

 PM 2

. 5 - PRI: ―Primary‖ PM emissions that are 2.5 μm in diameter or less. PM 2.5 - PRI = PM 25 - FIL + PM

- CON.

 PM 2

. 5 - FIL: Filterable (or front

- half catch) portion of the PM emissions that are 2.5 μm in diamete r or less.

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1-10 

## 1.3 Calculations and Significant Digits The methodology ranking presented in this Refinery Emission Protocol document is designed to highlight and promote those methods that are expected to yield the most accurate emissions data. We recognize that the Rank 5 methodologies may only provide emission estimates that are within a factor of 2 or 3 from the actual emissions rate. Nonetheless, the emission factors presented in this document are generally presented with 2 significant digits. The two significant digits should not be construed as an expectation that these emission factors are more accurate. The emission factors are provided with two significant digits because it is recommended that all calculations be performed carrying at least one additional significant digit to minimize round-off errors. The emissions calculated using a default emission factors may be rounded to one significant digit when reporting the emissions, but you should carry at least two significant digits in the calculations. For Methodology Rank 1 or other methods that may have uncertainties in the range of ±10 percent, at least 3 significant digits should be carried when performing the calculations, even though the final emission estimate may only warrant 2 significant digits.

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2-1 

# 2. Equipment Leaks Equipment leaks are small emission sources that occur throughout the process area of the refinery from various equipment components and connections that develop leaks that allow process fluids to escape into the atmosphere. Leaks are typically identified using EPA Method 21 (via an organic vapor analyzer or ―OVA‖) or using optical leak imaging techniqu es; other remote sensing techniques can also be used to identify leaks. Although direct measurement methods provide the most accurate means of quantifying equipment leak emissions, few, if any, refineries have or will implement direct measurement of equipment leak emissions. Instead, mass emissions for several types of equipment can be estimated using correlation equations that relate mass emissions to leak concentrations that are obtained using an OVA. In the absence of concentration measurements, mass emissions can also be estimated using the number of equipment components and emission factors. Typically, these procedures estimate either total organic compound (TOC) or non-methane organic compound mass emissions. To estimate either total VOC or constituent-specific emissions, the process streams being monitored must be characterized. The most common optical leak imaging technique illuminates a scene with infrared laser light of a wavelength that is strongly absorbed by the gas of interest, and the backscattered infrared light is converted to a real-time video image of the emissions plume. Although this technology is very useful for quickly and easily identifying the presence of leaks, particularly large leaks, it has not yet developed to the point of being able to quantify emissions. Therefore, it must be combined with other techniques as described below to quantify emissions. Other remote sensing techniques include Differential Absorption Light Detection and Ranging (LIDAR) and Solar Occultation Flux. These techniques measure either the volumetric or mass concentrations of a compound or mixture of compounds in a vertical cut through a plume downwind of its source. Combining these data with wind speed can be used to estimate mass flux. However, these remote sensing techniques are not yet approved by EPA as a method of quantifying emissions from equipment leaks or any other sources. Furthermore, because the measurement is conducted some distance downwind from a source, the techniques alone are not practical for identifying specific leaking equipment components. When appropriate, we will update this document to include methodologies for any optical leak imaging or other remote sensing techniques that develop to the point of being able to quantify equipment leak emissions. It is generally assumed that all leaks, even liquid leaks, will eventually evaporate so that 100% of the leak will be emitted into the atmosphere, so direct stream composition is used to estimate equipment leak emissions. For heavy liquids (such as residual fuel oils or bitumen), the assumption of 100% emissions may overstate actual emissions, especially if the liquid is cleaned up using oil socks or other similar techniques. These heavy liquids may contain significant amounts of polycyclic aromatic hydrocarbons ( PAH). As such, using the 100% emissions assumption, equipment leaks of heavy liquids can be a significant source of PAH emissions. Currently, there is no method for correcting emissions estimates for liquid component leaks that contain hea vy organic material (e.g., hydrocarbon compounds with 15 or more carbon atom, i.e., C15 hydrocarbons). However, if the liquid material is cleaned up so that it is not available for subsequent emissions, it may be assumed that only 10% of the C15 or heavier organics are emitted due to the leak. Table 2-1 summarizes the hierarchy of equipment leak emissions estimation techniques. The methods are ranked in terms of anticipated accuracy. Within a given measurement method (or rank), there may be alternative methods for determining the constituent-specific emissions; these compositional analysis methods are also provided in order of accuracy. It is anticipated that each refinery will use a mixture of different methods. For example, Methodology Rank 2 for equipment leaks may be used for components that are monitored using Method 21, but Methodology Ranks 4 or 5 for equipment leaks may be used to estimate emissions from other components that are not routinely monitored. The remainder of this section provides additional details and guidance regarding the ways to implement these methods. Most of the methods outlined in this section are based on the revised equipment leak protocol developed specifically

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2-2 for the petroleum refinery industry. For more information regarding the way in which the correlations were developed, please refer to EPA’s document, Protocol for Equipment Leak Emission Estimates (U.S. EPA, 1995b). Table 2-1. Summary of Equipment Leak Emissions Estimates

Rank Measurement Method Correlation Equations or Emissions Factor Compositional Analysis Data a 1 Direct measurement (high

- volume sampler or bagging) Not necessary Speciation of collected gas samples

2 EPA Method 21 Correlation equation a) Process

- specific, equipment

specific concentrations b) Process

- s pecific average concentrations c) Refinery average stream concentrations 3 EPA Method 21 Default screening ranges factors

4 No monitoring; facility

- specific component counts Default average emissions factors a) Process

- specific, service

- specific concent rations b) Process

- specific average concentrations c) Refinery average stream concentrations d) Default process compositions 5 No monitoring; default model process component counts Default average emissions factors

a The letters represent ranking suble vels. For example, rank 2a consists of using the correlation equation to estimate total VOC emissions and using process

- specific and equipment

- specific process fluid concentration data to estimate speciated emissions. 

## 2.1 Methodology Rank 1 for Equipment Leaks There are two primary quantitative leak measurement methods: the bagging method and high-volume sampling. Typically, EPA Method 21 would be used to initially screen and identify leaking components, and then one of these methods would be used to quantify the mass emissions rate of the leak. Direct leak rate measurement, using either of these techniques, is accurate within ±15% (U.S. EPA, 2003). In the bagging method, t he leaking component or leak opening is enclosed in a ―bag‖ or tent. An inert carrier gas (e.g., nitrogen) is conveyed through the bag at a known flow rate. Once the carrier gas attains equilibrium, a gas sample is collected from the bag, and the TOC concentration of the sample is measured. That collected gas can also be analyzed for individual compound concentrations. The mass emissions rate is calculated from the measured concentrations of the bag sample and the flow rate of the carrier gas. Although bagging techniques are useful for the direct measurement of larger leaks, bagging may not be possible for equipment components that are inaccessible, unusually shaped, or very large, and it is a relatively slow process (i.e., only two or three samples per hour). Hi gh -volume samplers are essentially vacuums that capture all of the emissions from a leaking component to accurately quantify leak emissions rates. Leak emissions and a large-volume sample of theair around the leaking component are pulled into the instrument through a vacuum sampling hose. Highvolume samplers are equipped with dual hydrocarbon detectors, which measure the concentration of hydrocarbon gas in the captured sample and the concentration of ambient hydrocarbon gas. Sample measurements are corrected for the ambient hydrocarbon concentration, and a mass leak rate is calculated by multiplying the flow rate of the measured sample by the difference between the ambient gas concentration and the gas concentration in the measured sample. Chemical speciation of the leak, using vacuum canisters or similar methods, can be used to ap portion the TOC emissions rate to individual constituents. High-volume samplers measure leak rates up to 0.23 cubic meters per minute (m 3 

### /min),

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2-3 which is a rate equivalent to 330 cubic meters per day (m 3 

### /day), and can be used to quantify 10 to 20 sources per hour. Leak rates greater than 0.23 m 3 

### /min must be measured using bagging techniques (U.S. EPA, 2003). 

## 2.2 Methodology Ranks 2 and 3 for Equipment Leaks Most leak detection and repair (LDAR) programs require periodic monitoring using EPA Method 21 to identify leaking components. The preferred methodology for estimating equipment leak emissions rates directly from EPA Method 21 data (Methodology Rank 2 for equipment leaks) is to use the screening value correlations in the right column of Table 2-2 (U.S. EPA, 1995b) for each individual component as screened via EPA Method 21. When a screening value of 0 is registered, the default zero value in the second column in Table 2-2 is used to estimate TOC emissions. If the monitoring instrument measures concentrations only up to 10,000 ppmv or 100,000 ppmv, then the applicable values for pegged emissions rates in Table 2-2 are used to estimate emissions. Many refineries or monitoring specialists use software programs that directly record the TOC reading (or screening value) for each component. Many of these software programs will directly calculate the TOC emissions for each component using the screening value correlations and will even calculate component-specific emissions rates when composition data are entered for the components. The TOC rates calculated by the correlation equation (and the default zero and pegged emission rate values) include non-VOC organic compounds, primarily methane and ethane. To calculate VOC emissions, the TOC emissions must be multiplied by the ratio of the weight percent of VOC to weight percent of TOC (i.e., (wt% TOC-wt% methane and ethane)/wt% TOC). The uncertainty of the correlations for any single measurement may be as much as a factor of 3 higher or a factor of 10 lower than the actual emissions for that component, but when summed over thousands of components, the uncertainty in the cumulative total emissions is expected to be approximately ±30%. In some older LDAR programs, the only information that is recorded is whether a leak was found. For these LDAR programs, leaks were defined as screening value readings greater than 10,000 parts per million by volume (ppmv). In these cases, generally the available data are the number of components of each type at the plant and the number of components of each type found with TOC readings less than 10,000 ppmv and the number of components of each type with TOC readings greater than or equal to 10,000 ppmv. Methodology Rank 3 for equipment leaks estimates the emissions rate using these data and the screening ranges emission factors in Table 2-3 (U.S. EPA, 1995b). If the number of components and the number of leakers are recorded by process, then this provides a more accurate method for using process-specific compositional data to estimate constituent-specific emissions rates (Methodology ranks 2a and 2b). Alternatively, the average percentage of leakers facility-wide can be used, and these data can be coupled with process-specific component counts to estimate emissions by process (Methodology rank 2c). The uncertainty of the default leak rates for any single measurement may be as much as a factor of 3 higher or a factor of 10 or more lower, but when summed over thousands of components, the uncertainty in the cumulative total emissions is expected to b e approximately ± 40%. To apply the screening ranges emission factor approach, use Equation 2-1 to calculate the total annual TOC emissions per type of equipment for which Methodology Rank 3 is used, and then use Equation 2-2 to calculate the VOC emissions. Note that Equation 2-1 adjusts the emission factors for methane because when the factors were developed, methane was subtracted out of the organic total. Therefore, apply the equation separately to groups of equipment in streams with significantly different methane weight fractions. E T OC 

### = {[F G 

### × (WF TOC 

### /(WF TOC 

### – WF m 

### )) × N G 

### ] + [F L 

### × (WF TOC 

### /(WF TOC 

### – WF m 

### )) × N L 

### ]} × H 

### (Eq. 2-1) where: E T OC 

### = Emissions rate of T OC for a specific type of equipment (kilograms per year [kg/yr])

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2-4 F G 

### = Applicable emission factor for specific type of equipment type with screening values

greater than or equal to 10,000 ppmv (kg/hr/source) F L 

### = Applicable emission factor for specific type of equipment with screening values less

than 10,000 ppmv (kg/hr/source) WF TOC 

### = Average weight fraction of TOC in the stream WF m 

### = Average weight fraction of methane in the stream N G 

### = Equipment count (specific equipment type) for sources with screening values greater

than or equal to 10,000 ppmv N L 

### = Equipment count (specific equipment type) for sources with screening values less than

10,000 ppmv H = Operating hours per year
E VOC 

### = E T OC 

### × (WF VOC 

### /

WF T OC 

### ) (Eq. 2-2) where: E VOC 

### = Emissions rate of VOC for a specific type of equipment (kg/yr) WF V OC 

### = Average weight fraction of VOC in the stream (typically TOC minus methane and

ethane) When an optical gas imaging camera is used to identify leaks, the emissions can be quantified under Methodology Rank 2 only if both of the following conditions are met: (1) the equipment is monitored in accordance with the procedures in §63.11(e) and (2) all leaks identified by the camera are monitored before repair using Method 21. For equipment found to be leaking when monitoring with the camera, use the subsequent Method 21 screening values in the applicable correlation equation to estimate the emissions. For all equipment not found to be leaking when monitoring with the camera, estimate emissions using the screening values obtained when conducting the annual Method 21 monitoring required by §63.11(e) in the applicable correlation equations. For any other situation when an optical gas imaging camera is used to identify leaks, quantify emissions using Methodology Rank 4 or Methodology Rank 5.
Table 2- 2. Equipment Leak Rate for Refinery Equipment Components a

Equipme nt Type (All Services) Default Zero

Emission s Rate (kg/hr/source) Pegged Emission s Rates (kg/hr/source) Correlation Equation b (kg/hr/source) 10,000 ppmv 100,000 ppmv Valve 7.8E

- 06 0.064 0.140 2.29E

- 06×SV 0.746 Pump 2.4E

- 05 0.074 0.160 5.03E

- 05×SV 0.610 Other c 4.0E

- 06 0.073 0.110 1.36E

- 05×SV 0.589 Connector 7.5E

- 06 0.028 0.030 1.53E

- 06×SV 0.735 Flange 3.1E

- 07 0.085 0.084 4.61E

- 06×SV 0.703 Open

- ended line 2.0E

- 06 0.030 0.079 2.20E

- 06×SV 0.704 Note: kg/hr/source = kilograms per hour per source
a Data repo rted in U.S. EPA, 1995b. b SV is the screening value (SV, ppmv) measured by the monitoring device.
c The ―other‖ equipment type was developed from instruments, loading arms, pressure relief devices, stuffing boxes, vents, compressors, dump lever arms, diap hragms, drains, hatches, meters, and polished rods. This ―other‖ equipment type should be applied to any equipment other than connectors, flanges, open

- ended lines, pumps, or valves.

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2-5 Table 2- 3. Refinery Screening Ranges Emission Factors a
Equipment type S ervice ≥10,000 ppmv emission factor (kg/hr/source) b <10,000 ppmv emission factor (kg/hr/source) b Valves Gas 0.2626 0.0006 Light liquid 0.0852 0.0017 Heavy liquid 0.00023 0.00023 Pump and agitator seals Light liquid 0.437 0.0120 Heavy liquid 0.3885 0.0135 Compressor seals All 1.608 0.0894 Pressure relief valves All 1.691 0.0447 Connectors All 0.0375 0.00006 Open

- ended lines All 0.01195 0.00150

a Data reported in U.S. EPA, 1995b. b These factors are for non

- methane organic compound emissions.

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2-6 Example 2 - 1: Calculation for Methodology Rank 2 for Equipment Leaks A refinery reforming unit operating 8,000 hours per year (hr/yr) has 600 valves. To keep the example simple, assume Method 21 monitoring registers the screening value readings in the following table, and assume the average weight percents of methane and et hane in each stream are known or estimated to be equal to 3 percent and 1 percent of the TOC, respectively. Also assume the TOC content of each stream is 100 percent. Using Methodology Rank 2 for equipment leaks (correlation approach), what is the cumulati ve hourly VOC emissions rate from the valves in this process unit at the time the monitoring is conducted? What is the annual emissions rate? To calculate the emissions, the default zero value for valves on Table 2
- 2 (7.8E

- 06) is used to estimate the TOC e missions from the 580 valves with a screening value of 0 ppmv. The pegged emission rate for valves in Table 2
- 2 (0.140) is used to estimate the TOC emission rate for the 2 valves with pegged readings. The correlation equation for valves in Table 2
- 2 (2.29E

- 06 x SV^0.746) is used to estimate the emissions for each of the valves with a measured screening value. In each case, the calculated TOC emissions are multiplied by (100

- 4)/100 to calculate the VOC emissions. The annual emissions are 2,300 kg/yr (0.29 kg /hr x 8,000 hr/yr).

Number of V alves Method 21 S c reening V alue, ppmv Emissions, kg/hr TOC VOC 580 0 0.00452 0.00434 5 200 0.00012 0.00011 5 400 0.00020 0.00019 2 1,500 0.00054 0.00051 2 7,000 0.00169 0.00162 2 20,000 0.00370 0.00355 2 50,000 0.00 733 0.00704 2 P egged at 100,000 0.28000 0.26880 0.29

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2-7 2.2.1 Speciating Equipment Leak Emissions Table 1-1 lists the specific organic compounds that should be included in an inventory of equipment leak emissions. The following equation (Equation 2

- 3 ) i s used to speciate emissions from a single equipment piece: E i 

### = E V OC 

### × (WF i 

### / WF V OC 

### ) (Eq. 2-3) where: E i 

### = Mass emissions of organic chemical ―i‖ from the equipment (kilograms per hour

[kg/hr]) E V OC 

### = VOC mass emissions from the equipment (kg/hr) WF i 

### = Concentration of organic chemical ―i‖ in the equipment in (weight fraction) WP V OC 

### = VOC concentration in the equipment in (weight fraction) Example 2 - 2: Calculation for Methodology Rank 3 for Equipment Leaks For the valves in the same reforming unit described in Example 2

- 1, what is the cumulative hourly VOC emissions rate when Methodology Rank 3 is used? What are the annual VOC emissions? Assume the distribution of valves in gas, light liquid, and heavy liquid service is as shown in the table below. To calculate hourly TOC emissions for valves in gas service with screening values less than 10,000 ppmv, use the second half of Equation 2

- 1.

E T OC 

### = [F L 

### × (WF TOC 

### /(WF TOC 

### – WF m 

### )) × N L 

### ] 

### = [0.0006 × (100/(100

- 3)) × 236] = 0.146 kg TOC/hr Use the same procedure to calculate emissions for valves in light liquid service and heavy liquid service of 0.514 kilogram s of TOC per hour (kg TOC/hr) and 0.015 kg TOC/hr, respectively. Thus, the total TOC emissions for all valves with screening values less than 10,000 ppmv are 0.675 kg/hr. Use equation 2

- 2 to calculate the VOC emissions from these valves. E VOC 

### = E T OC 

### × (WF VOC 

### / WF T OC 

### ) = 0.675 × (100

- 4)/100 = 0.648 kg VOC/hr Use the same procedure with the first half of equation 2

- 1 to estimate TOC emissions of 1.076 kg/hr from the valves with screening values equal to or greater than 10,000 ppmv, and apply equation 2

- 2 to calculate VOC emissions of 1.033 kg/hr. Total annual emissions are calculated to be 13,400 kg VOC/yr (1.68 kg/hr x 8,000 hr/yr).

Screening V alue, ppmv Number of Valves by Type

of S ervice Emission F actors, kg/hr/source TOC E missions, kg/hr VOC

E missions , kg /hr Gas Light Liquid Heavy

Liquid Gas Light

Liquid Heavy

Liquid <10,000 236 293 65 0.0006 0.0017 0.00023 0.675 0.648 ≥10,000 3 3 0 0.2626 0.0852 0.00023 1.076 1.033 1.68

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2-8 To the extent that compositional data are available for individual process streams, each equipment component associated with that process stream should be tagged with the average composition of that process stream (Methodology Rank 2a or 3a for equipment leaks). Although an ideal situation would be if chemical speciation data were available for each equipment component (i.e., each process stream associated with each equipment component), in many cases, this level of detail may not be available. Alternatively, average compositional data may be determined for a specific process unit, such as at the crude distillation unit or the CRU, and all equipment components associated with that process unit would be tagged with that concentration profile (Methodology Rank 2b or 3b for equipment leaks). As a last resort, a single, overall average process stream composition can be estimated for a refinery (Methodology Rank 2c or 3c for equipment leaks). Methodology Rank 2c or 3c of equipment leak emissions is very easy to implement in that the VOC emissions can be aggregated for all components first, and then the chemical-specific emissions can be calculated from the cumulative VOC emissions. However, this method greatly reduces the accuracy of the chemical-specific emissions rates. With the automated software programs that are now available for logging equipment leak readings and calculating equipment leak emissions, most refineries should be able to implement Methodology Rank 2a or 2b for equipment leaks.

2.2.2 Calculating Annual Equipment Leak Emissions The emissions estimated based on EPA Method 21 measurement data (i.e., Methodology Rank 2 or 3 for equipment leaks) represent the emissions rate at the time when the measurements were made. The first time an LDAR program is implemented, the emissions estimates from the component screening measurements should be used as the emissions rate for the facility (or an individual component or set of components) for all periods prior to the screening measurements (i.e., the portions of the inventory year Example 2 - 3: Calculation for Speciating Equipment Leak Emissions For Example 2

- 1 the measured composition of the process stream associated with one of the valves (Methodology Rank 2a) for which a screening value of 7,000 ppmv was obtained is: Hexane 10 wt% Toluene 8 wt% Benzene 2 wt% Other volatile organic compounds (VOC) 60 wt% Methane and ethane 4 wt% Nitrogen 10 wt% Water 5 wt% Hydrogen 1 wt% The TOC weight fraction is calculated as the sum of all of the organic compounds. The VOC weight fraction is the sum of all of the organ ic compounds, minus methane and ethane, as shown in the following equation: WF V OC 

### = %Hexane + %Toluene + %Benzene +% Other VOC)/100% = (10 + 8 + 2 + 60)/100 = 0.80 From Example 2

- 1, the valve’s VOC emissions rate was 0.81 grams per hour (g/hr). Equation 2

- 3 is used to attribute these emissions to individual components as follows: E Hexane 

### = 0.81 × (0.1/0.8) = 0.10 g/hr E Toluene 

### = 0.81 × (0.08/0.8) = 0.08 g/hr E Benzene 

### = 0.81 × (0.02/0.8) = 0.02 g/hr E Other VOC 

### = 0.81 × (0.60/0.8) = 0.61 g/hr

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2-9 prior to the screening measurements). However, most equipment components at a refinery are expected to be monitored for leaks on a routine basis (i.e., monthly, quarterly, or semiannually) as part of an ongoing LDAR program. Leaks greater than a certain threshold are required to be repaired within certain time frames (although many LDAR programs allow some repairs to be delayed). After repairs are made, the repaired components should be re-screened to verify that the leak has been repaired and to provide a new starting emissions rate for that component. During the next routine monitoring period, new screening values will be determined for each component, providing new instantaneous emissions rate estimates for each component. For the purposes of developing an average emissions rate, it can be assumed that the initial reading represents the emissions rate for the first half of the period between monitoring events and that the subsequent reading represents the emissions rate for the second half of the period between monitoring events. For leaks that are repaired, the ―leak‖ monitor reading is used from the time the leak is detected to the time it is repaired (i.e., re-screened).

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2-10 

## 2.3 Methodology Ranks 4 and 5 for Equipment Leaks Methodology Ranks 4 and 5 for equipment leaks should be used only for components that are not being routinely monitored for leaks. For refineries, this might be processes that have low HAP and low VOC content, or it might be specific types of components that are either classified as unsafe to monitor (e.g., certain pumps and valves) or are not subject to the monitoring requirements (e.g., connectors) in the new source performance standards (NSPS) or Petroleum Refinery Maximum Achievable Control Technology (MACT) I rules. Facility- or process-specific component counts (Methodology Rank 4 for equipment leaks) are preferred over default component counts (Methodology Rank 5 for equipment leaks), but the emissions estimation procedure is similar in both cases. When using Methodology Ranks 4 and 5, speciated emissions are calculated using the same procedures described in section 2.2.1 of this document. Example 2 - 4: Calculation for Annual Emiss ions The following monitoring data for a pump were recorded (Columns 1 and 2). The correlation equation from Table 2

- 2 for pumps is used (i.e., 5.03E

- 05×SV 0.610 

### ) to calculate the emissions rate in Column 3 when the OVA reading is greater than 0, and the de fault zero rate is used when the OVA reading is 0. The hours between intervals were calculated; half of the hours were assigned to the first reading and half were assigned to the second reading, except for periods before repair, which were assigned the ―le ak‖ emissions rate.

1 Date and Time 2 OVA Reading (ppm) 3

TOC Emissions Rate (kg/hr) 4

Hours a 5

TOC Emissions (kg/period) January 2, 8:00 a.m. 200 1.27E

- 3 3 2 +372 0.51 February 2, 8:00 a.m. 300 1.63E

- 3 372+336 1.15 March 2, 8:00 a.m. 280 1.56E

- 3 336+372 1.10 April 2, 8:00 a.m. 22,000 2.24E

- 2 372+74 9.99 April 5, 10:00 a.m

. b 150 1.07E

- 3 323 0.35 May 2, 8:00 a.m. 140 1.02E

- 3 323+372 0.71 June 2, 8:00 a.m. 200 1.27E

- 3 372+360 0.93 July 2, 8:00 a.m. 180 1.19E

- 3 360+372 0.87 August 2, 8:00 a.m. 500 2.2 3E

- 3 372+372 1.66 September 2, 8:00 a.m. 45,000 3.47E

- 2 372+241 21.27 September 12, 9:00 a.m

. b 0 2.4E

- 5 239.5 0.006 October 2, 8:00 a.m. 0 2.4E

- 5 239.5+372 0.015 November 2, 8:00 a.m. 0 2.4E

- 5 372+360 0.018 December 2, 8:00 a.m. 200 1.27E

- 3 360+372 0. 93 January 2, 8:00 a.m. 250 1.46E

- 3 372

- 3 2 0.50 Annual Totals 8,760 4 0

. 0 kg/yr

a Each emissions rate applies over half of the hours since the previous screening and over half of the hours until the next screening. For example, the results from the Jul y 2 measurement apply to half of the hours since the June 2 measurement and to half of the hours before the next measurement on August 2. The July 2 measurements occur 30 days (720 hours) after the June 2 measurement and 31 days (744 hours) before the Augu st 2 measurements. Therefore, the July 2 results apply to 732 hours during the year (720/2 + 744/2 = 732). b Indicates special Method 21 measurement reading to verify repair.

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2-11 The median equipment component counts for small refineries (those less than 50,000 barrels per calendar day [bbl/cd]) 1 

### and large refineries (greater than 50,000 bbl/cd) as presented in EPA’s document, Locating and Estimating Air Emissions from Sources of Benzene (U.S. EPA, 1998a), are presented in Tables 2-4 and 2-5 , respectively. The default emissions factor per component for uncontrolled or unmonitored co mponents is provided in EPA’s document, Protocol for Equipment Leak Emission Estimates (U.S. EPA, 1995b). These emissions factors are summarized in Table 2-6

. EPA’s document, Locating and Estimating Air Emissions from Sources of Benzene , also presents average process stream benzene concentrations based on the stream type or ―service‖ (i.e., if the process stream is a gas, a light liquid, or a heavy liquid). These data are presented in Table 2-7

. Preferably, facility- or process-specific compositional analyses would be available to develop constituent-specific emissions estimates.

1 

### Barrels per calendar day is the amount of crude that a refinery can process under usual operating conditions and is expressed in terms of actual capacity during a 24-hour period (i.e., actual annual capacity divided by 365 days). The other typical capacity measure, barrels per stream day (bbls/sd), is the maximum number of barrels of crude that a refinery can process within a 24-hour period when running at full capacity.

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2-12

Table 2-4. Median Equipment Leak Component Counts for Small Model Processes a

Process Unit Valves Pumps
Compressors Pressure Relief Valves Flanges Open Ended Lines Sampling Connect ions Gas Light Liquid Heavy

Liquid Light Liquid Heavy Liquid Gas Light Liquid Heavy

Liquid Gas Light

Liquid Heavy Liquid Crude distillation 75 251 216 8 8 2 6 6 5 164 555 454 39 10 Alkylation (sulfuric acid) 278 582 34 18 10 1 12 15 4 705 1,296 7 85 20 16 Alkylation (HF) 102 402 62 13 3 2 12 13 0 300 1,200 468 26 8 Catalytic reforming 138 234 293 8 5 3 5 3 3 345 566 732 27 6 Hydrocracking 300 375 306 12 9 2 9 4 4 1,038 892 623 25 10 Hydrotreating/hydrorefining 100 208 218 5 5 2 5 3 5 290 456 53 8 20 6 Catalytic cracking 186 375 450 13 14 2 8 8 7 490 943 938 8 8 Thermal cracking (visbreaking) 206 197 0 7 0 0 4 0 0 515 405 0 0 4 Thermal cracking (coking) 148 174 277 9 8 2 7 16 13 260 322 459 13 8 Hydrogen plant 168 41 0 3 0 2 4 2 0 304 78 0 8 4 Asphalt plant 120 334 250 5 8 2 5 10 9 187 476 900 16 6 Product blending 67 205 202 6 11 1 10 6 22 230 398 341 33 14 Sulfur plant 58 96 127 6 6 3 3 88 15 165 240 345 50 3 Vacuum distillation 54 26 84 6 6 2 2 5 2 105 121 230 16 4 Full

- range distillati on 157 313 118 7 4 2 5 4 6 171 481 210 20 6 Isomerization 270 352 64 9 2 2 7 10 1 432 971 243 7 8 Polymerization 224 563 15 12 0 1 10 5 3 150 450 27 5 7 MEK dewaxing 145 1,208 200 35 39 3 10 14 4 452 1,486 2,645 19 17 Other lube oil processes 153 242 2 01 7 5 2 5 5 5 167 307 249 60 6

a Process component counts as presented in EPA’s document, Locating and Estimating Air Emissions from Sources of Benzene (U.S. EPA, 1998a), for refineries with crude capacities less than 50,000 bbl/cd.

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Table 2-5. Median Equipment Leak Component Counts for Large Model Processes a

Process Unit Valves Pumps
Compressors Pressure Relief Valves Flanges Open Ended Lines Sampling Connections Gas Light Liquid Heavy

Liquid Light Liquid Heavy Liquid Gas Light Liquid Heavy Liqui d Gas Light

Liquid Heavy Liquid Crude distillation 204 440 498 15 14 2 7 5 12 549 982 1,046 75 9 Alkylation (sulfuric acid) 192 597 0 21 0 2 13 4 0 491 1,328 600 35 6 Alkylation (HF) 104 624 128 13 8 1 9 11 1 330 1,300 180 40 14 Catalytic reforming 310 383 84 12 2 3 8 11 0 653 842 132 48 9 Hydrocracking 290 651 308 22 12 2 10 12 0 418 1,361 507 329 28 Hydrotreating/hydrorefining 224 253 200 7 6 2 9 4 8 439 581 481 49 8 Catalytic cracking 277 282 445 12 12 2 11 9 13 593 747 890 59 15 Thermal crack ing (visbreaking) 110 246 130 7 6 1 6 3 15 277 563 468 30 7 Thermal cracking (coking) 190 309 250 12 11 1 8 5 10 627 748 791 100 10 Hydrogen plant 301 58 0 7 360 3 4 139 0 162 148 0 59 21 Asphalt plant 76 43 0 4 0 0 3 7 0 90 90 0 24 24 Product blending 75 419 186 10 10 2 9 16 6 227 664 473 24 8 Sulfur plant 100 125 110 8 3 1 4 4 4 280 460 179 22 7 Vacuum distillation 229 108 447 2 12 1 5 1 4 473 136 1,072 0 7 Full

- range distillation 160 561 73 14 2 2 7 8 2 562 1,386 288 54 6 Isomerization 164 300 78 9 5 2 15 5 2 300 540 265 36 7 Polymerization 129 351 82 6 2 0 7 12 28 404 575 170 17 9 MEK dewaxing 419 1,075 130 29 10 4 33 6 18 1,676 3,870 468 0 7 Other lube oil processes 109 188 375 5 16 3 8 6 20 180 187 1,260 18 9

a Process component counts as presented in EPA’s document, Locating and Estimating Air Emissions from Sources of Benzene (U.S. EPA, 1998a), for refineries with crude capacities greater than 50,000 bbl/cd.

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2-14 Table 2-6. Refinery Average Component Emissions Factors a
Equipment T ype Service Emission s F actor (kg/hr/source) b Valves Gas 0.0268 Light liquid 0.0109 Heavy liquid 0.00023 Pump seals c Light liquid 0.114 Heavy liquid 0.021 Compressor seals Gas 0.636 Pressure relief valves Gas 0.16 Connectors All 0.00025 Open

- ended lines Al l 0.0023 Sampling connections All 0.0150 Note: kg/hr/source = kilograms per hour per source
a Source: U.S. EPA, 1995b. b These factors are for non

- CH4 organic compound emissions rates.
c The light liquid pump seal factor can be used to estimate the leak rate from agitator seals.



### Table 2-7. Concentration of Benzene in Refinery Process Unit Streams a

Process Unit Weight Percent of Benzene in Stream Type Gas Light Heavy Liquid Crude 1.3 1.21 0.67 Alkylation (sulfuric acid) 0.1 0.23 0.23 Catalytic reforming 2.93 2.87 1.67 Hydrocracking 0.78 1.09 0.1 Hydrotreating/hydrorefining 1.34 1.38 0.37 Catalytic cracking 0.39 0.71 0.2 Thermal cracking (visbreaking) 0.77 1.45 1.45 Thermal cracking (coking) 0.24 0.85 0.18 Product blending 1 .2 1.43 2.15 Full

- range distillation 0.83 1.33 1.08 Vacuum distillation 0.72 0.15 0.22 Isomerization 2.49 2.49 0.62 Polymerization 0.1 0.1 0.1 MEK dewaxing 0.36 Not reported Not reported Other lube oil processing 1.2 1.2 0.1

a Source: U.S. EPA, 199 8a. 

### To apply the average emissions factors, use Equation 2-4 to estimate VOC mass emissions from all of the equipment in a stream of a given equipment type. Note that the emission factors in Table 2-6 were developed to estimate emissions of non-methane organic compounds. Therefore, to estimate VOC emissions, the emission factor must be multiplied by the ratio of the V OC

- to -NMOC weight fractions. Also note that the emission factors apply to streams that are 100 percent TOC. To calculate VOC emissions from equipment in contact with a stream that contains both organic compounds and other

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2-15 compounds like nitrogen or water vapor, the emission factor must be multiplied by the TOC weight fraction in the stream. As a result, TOC, methane, and ethane weight fractions must be known or estimated in order to calculate the VOC emissions: E V OC 

### = FA × (WF TOC 

### - WF ethane - 

### WF methane 

### )/(WF TOC 

### - WF methane 

### ) × WF TOC 

### × N × H 

### (Eq. 2-4) where: E V OC 

### = Emissions rate of VOC from all equipment in the stream of a given equipment type

(kg/y r) FA = Applicable average non-methane organic compounds emissions factor for the equipment type (kg/hr/source) WF TOC 

### = Average weight fraction of TOC in the stream WF ethane 

### = Average weight fraction of ethane in the stream WF methane 

### = Average weight fraction of methane in the stream N = Number of pieces of equipment of the applicable equipment type in the stream H = Hours per year in component service If a process stream contains no ethane, the non-methane organic fraction is equal to the VOC fraction, which means the emission factor can be used without the correction ratios noted above, and the equation simplifies to Equation 2-5: E V OC 

### = FA × WF TOC 

### × N × H (Eq. 2-5) Two guidelines when correcting the ― FA ‖ term when applied to refineries are as follows:



## – The correction should only be applied to equipment containing a mixture of organics and CH 4 

### .



## – The maximum correction for the CH 4 

### weight fraction should not be greater than 0.10, even if the equipment contains greater than 10 weight percent of CH 4 

### . (This reflects that the equipment for which the average emissions factors in Table 2-6 were developed typically contained 10 weight percent or less of CH 4 

### ).
Example 2 - 5 : Calculation of Equipment Leak Emissions Using Refinery Average

Emissions Factors At a refinery, if there a re 100 gas valves in a stream that, on average, contain s 80 weight percent non - CH 4 

### organic compounds , 10 weight percent water vapor, 10 weight percent CH 4 

### , and no ethane (thus, the TOC weight percent would be 90) . If the process operates 8,000 hours per year, what ar e the cumulative VOC emissions from the 100 gas valves? Because the process stream contains no ethane, the VOC emissions can be calculated using the applicable emission factor from Table 2
- 5 and Equation 2

- 5. E V OC 

### = FA × WF TOC 

### × N × H

= 0.0268 kg NMOC/ hr/gas valve × 0.9 × 100 gas valves × 8,000 hr/yr

= 19,300 kg/y r of VOC from gas valves in the stream

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3-1 

# 3. Storage Tanks Storage tanks (also known as storage vessels) are used in refineries for storing and dispensing various liquids used in the refining process. These various liquids are typically organic liquids, also known as petroleum liquids, which are a mixture of hydrocarbons, such as gasoline and crude oil. Depending on the specific design and construction of the tank and the characteristics of the petroleum liquids, storage tanks may emit significant levels of VOC and HAP during typical operation, venting, and tank filling or dispensing. The basic designs for storage tanks include horizontal and vertical fixed roof tanks, external floating roof tanks, internal floating roof tanks, and domed external floating roof tanks. Chapter 7.1 (Organic Liquid Sto rage Tanks) of EPA’s Compilation of Air Pollutant Emission Factors (AP-42) provides detailed descriptions of the characteristics specific to each tank type (U.S. EPA, 1995a [some sections were updated in 2006]). The emissions estimation methods for storage tanks are presented in Table 3-1 . These methods are ranked according to anticipated accuracy. There are three primary estimation methods: (1) direct measurement, (2) tank-specific modeling, and (3) default tank emissions factors. Direct measurements can only be taken from process units that are covered and vented to a control device. Tank-specific modeling can be accomplished with emissions equations, such as those presented in AP-42 or by computer-based models designed to implement these equations (e.g., TANKS v4.09D; U.S. EPA, 2006). Most refinery owners and operators will have sufficient data to use the tank-specific modeling approach and this method should be used for most refinery storage vessels. In rare cases when tank-specific data are not available, engineering estimates can be made using actual or estimated production quantities and default emissions factors. Table 3-1. Summary of Typical Hierarchy of Storage Tank Emissions Estimates

Rank Methodology

Description Application Data Requirements 1 D irect measurement Covered and vented storage tanks Constituent concentration and flow rate

2 Tank

- specific modeling All petroleum liquid storage tanks Tank type, tank dimensions, stored liquid properties and constituent concentrations, tank condition/fitt ing information, throughput 3a Default tank modeling Common petroleum liquid storage tanks Site

- specific crude throughput, specific product production rates 3b Default tank modeling Common petroleum liquid storage tanks Crude throughput and production c apacities (from the U.S. Energy Information Administration or other similar source) 

## 3.1 Methodology Rank 1 for Storage Tanks Emissions from fixed roof storage tanks may be purged (e.g., tanks under a nitrogen blanket) and vented to a control device; these emissions can be directly measured at the outlet of the control device using the direct measurement methods for process vents or combustion sources as described in Sections 4, Stationary Combustion Sources , and 5, Process Vents , of this Refinery Emissions Protocol document. It is likely that the control device will serve a group of tanks; it is acceptable to report the cumulative emissions from the group of storage tanks if this is the case. For some control devices, such as flares, it may be possible to measure the concentration of the gas upstream of the control device and estimate the emissions using an assumed control device efficiency (for

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3-2 more details on these types of methods, see Section 4, Stationary Combustion Sources , and/or Section 6, Flares ). This method is also recommended as a means to estimate storage tank emissions when the emissions from the storage tank(s) are routed to a control device that also serves other refinery emission sources. In this case, the concentration and flow rate of the storage tank off-gas can be measured prior to combining the stream with other non-storage tank emissions. The resulting constituent mass flow rates can be corrected for the control device efficiency using the methods described in Chapter 6 ( Flares ) to estimate the emissions associated with the storage tank(s) that are released to the atmosphere. There are other direct measurement methods that have been used to measure emissions from storage tanks even when the emissions from the tank are not vented (i.e., DIAL [Differential Absorption Light Detection and Ranging (LIDAR )] techniques); however, these methods do not provide continuous monitoring and have additional limitations (requiring consistent wind direction, etc.). Therefore, at the present time they are not recommended as primary techniques for emissions estimation. However, they can be used to verify and assess the accuracy and uncertainties associated with tank-specific modeling. If direct measurement methods are used, emissions from the tank during degassing, cleaning, or drained idle periods may or may not be included, depending on how these gases are vented. If these gases are routed to the same control device as used during normal operations, the measured emissions will account for these periods. If these emissions are not controlled in the same manner as normal operations, the emissions should be estimated separately for these periods using the methods provided in Section 7.1.3.2.2 of the 2006 update of Section 7.1. 

## 3.2 Methodology Rank 2 for Storage Tanks Except for the limited number of storage tanks whose emissions are collected and controlled external to the storage tank, EPA recommends that the emissions estimation procedures detailed in Chapter 7.1 of AP -42 (U.S. EPA, 1995a) be used to calculate air pollutant emissions from organic liquid storage tanks. There are many tools available, such as TANKS v4.09D emissions estimation software that can be used to perform the necessary calculations. TANKS v4.09D software can be downloaded for free at: http://www.epa.gov/ttnchie1/software/tanks/index.html under the How to Get TANKS 4.09D link. Because TANKS v4.09D is widely used, Appendix C of this Refinery Emissions Protocol document provides tips and insights on using the TANKS program. Key things to consider when estimating emissions from storage tanks (whether using the AP-42 equations directly or when using TANKS v4.09D or other software packages) include: 1. Each tank should be modeled individually using site-specific conditions. There may be instance s in which a set of tanks have identical properties and materials and very similar throughputs so that the emissions from a single storage tank can be modeled and used as the emissions for each tank in the set. However, this approach should be limited to situations where the tanks, contents, and throughputs are effectively identical. In all other cases, it is recommended that individual tank data be entered into the TANKS program (or other similar software), and the emissions results for individual tanks be reported. 2. For the internal floating roof tank, the external floating roof tank, and the domed external floating roof tank, the tank fittings should be selected to represent the specific characteristics of each individual storage tank. You should not us e the ―default‖ fitting settings when using TANKS v4.09D, unless these settings exactly match (by number and type) the fittings actually present on the individual storage tank being modeled. 3. The storage tanks should be modeled using monthly parameters, including average monthly measured tank liquid temperatures, when available. In TANKS, selecting the city will set the meteorological data that will be used in the calculations. Even if you select the monthly calculation option, the liquid temperature remains at the annual average. As such, the TANKS

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3-3 program will not adequately account for the monthly variations in emissions. Also, for intermediate process tanks with floating roofs that store liquids that are generally warmer than ambient temperature, TANKS will underestimate the emissions. 2 

### Therefore, for storage tanks with throughputs that vary significantly with the seasons and floating roof tanks that store warm process fluids, the equations in Chapter 7.1 of AP-42 should be used directly to more accurately estimate the annual emissions. 4. Special calculations should be performed to account for tank roof landings, tank degassing, and tank cleaning, and these estimates should be included in the final annual emissions reported for each tank. The TANKS model does not currently contain algorithms for estimating emissions from tank roof landings. These emissions should be estimated separately for each landing event using the methods provided in Section 7.1.3.2.2 of the 2006 update of Section 7.1. 5. Emission estimates should be calculated and reported for individual pollutants. The TANKS program typically provides total hydrocarbon emissions estimates, but can also provide estimates for individual pollutants. 

## 3.3 Methodology Rank 3 for Storage Tanks Refinery owners and operators are expected to have tank-specific information and should use Methodology Rank 2 for storage tanks; however, state and local agency staff may not have access to this information. When tank-specific information is not available, default emissions factors can be used. The emissions factors presented in this section are primarily based on model external floating roof tanks for various petroleum refinery liquids (e.g., crude oil, gasoline, jet fuel). These default emissions factors required assumptions regarding the typical fitting controls and the average composition of crude oil, gasoline, and other products at the refinery. The heavy distillate and aromatics emissions factors were developed based on the permit applications, which were generally based on TANKS modeling. The reported emissions, which were normalized by production capacity, were then averaged across a limited number of storage tanks to develop the default emissions factors that are provided in Table 3-2

. Additional details regarding the assumptions used to develop these emissions factors are found in two publications (i.e., RTI, 2002; Lucas, 2007). These emission factors typically provide emission estimates within a factor of 2 of tank-specific modeling approach, but will be less accurate if most of the tanks are internal floating roof tanks and/or external floating roof tanks with domed covers.

Table 3-2. Default Emissions Factors for Petroleum Refinery Storage Tanks

CAS Number Chem ical Name Emissions Factors for Petroleum Li quid Storage Tanks (lb/MMbbl)

Crude Oil Gasoline

and Other Light Distillates Diesel Fuel

and Other Middle Distillates Asphalt,

Lube Oils, and H eavy Distillates Aromatics 71432 Benzene 10. 70. 54 40 a 108883 Toluene 7.5 180 10 0 29 a 1330207 Xylene 6. 2 140 70 26 a 100414 E thylbenzene 1.6 31 18 5. 3 100425 Styrene 0 66 0 98828 C umene 0. 5 15 10 0.4 95636 1,2,4

- T rimethyl benzene 0. 7 0 0 5. 9 (continued)

2 

### The TANKS program includes an algorithm for calculating emissions from heated tanks, but it is only applicable to tanks with horizontal or vertical fixed roofs.

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3-4 Table 3 - 2
. Default Emission s Factors for Petroleum Refinery Storage Tanks (continued)

CAS N umber Chem ical Name Emissions Factors for Petroleum Liquid Storage Tanks (lb/MMbbl)

Crude Oil Gasoline

and Other Light Distillates Diesel Fuel

and Other Middle Distillates Asphalt,

Lube Oils, and H eavy Distillates Aromatics 1634044 Methyl tert iary

- buty l ether 0 3 10 0 0 106990 1,3 B utadiene 0 1.8 0 0 110543 Hexane 84 42 0 48 0 1 3 540841 2,2,4

- T rimethylpentane 3. 4 14 0 22 0 78933 M ethyl ethyl ketone 0.3 0.33 0 108101 M ethyl isobutyl ketone 320 320 0 67561 Methanol 3. 8 3. 8 0 108952 P henol 0.9 0.9 0.67 0 1319773 Cresol 0.6 13 0.19 0 91203 Naphthalene 0.6 7. 6 4 5.77 91576 2

- M ethyl naphthalene 3. 5 3. 5 0 92524 Biphenyl 0. 2 0.17 0 0. 7 POM Polycyclic organic matter/

polynuclear aromatics/PAH 0 0 17
120127 Anthracene 0.24 0.24 0 218019 Chrysene 0.21 0.21 0 86737 Fluorene 0.36 0.36 0 85018 Phenanthrene 1. 5 1. 5 0 129000 Pyrene 0.39 0.39 0

Sum VOC 1,350 8, 800 5, 30 0 1 20 15 ,000 Note: lb/M Mbbl = pounds per million barrels
a Use ―Sum VOC‖ emissions factor and apply it to the production of each aromatic produced. 

### When facility-specific production data are available, these data should be used with the default emissions factors to estimate emissions. When these data are not available, crude distillation capacity and production capacities, as presented in the Refinery Capacity Report 2009 (EIA, 2009), can be used to estimate these production rates as follows:

 The crude oil processing rate can be assumed to be the atmospheric crude oil distillation capacity. If a refinery does not have atmospheric crude distillation columns, then the sum of the vacuum distillation and coking capacities can be used as the crude oil processing rate.

 The aromatics production capacity is provided in the Refinery Capacity Report 2009 (EIA, 2009); however, the specific aromatics produced cannot be determined. As a default assumption, equal production of benzene, toluene, and xylenes can be assumed.

 Heavy distillate production can be estimated as the sum of lube oil production, asphalt production, and coke production.

 Light distillate production can be estimated as 60% of the difference of the crude oil processing rate minus the aromatics and heavy distillate production (0.6 × [Crude − Aromatics − Heavy]).

 Middle distillate production can be estimated as 40% of the difference of the crude oil processing rate minus the aromatics and heavy distillate production (0.4 × [Crude − Aromatics − Heavy]).

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4-1 

# 4. Stationary Combustion Sources Petroleum refineries include numerous stationary combustion sources, the most common of which are: process heaters, boilers, internal combustion engines (including turbines), and coke gasification units. These combustion sources are vent (point) sources that occur throughout the process area of the refinery. The size of the vent stack varies with the size of the source (typically measured in terms of the rate that fuel is burned). Process heaters are used to indirectly preheat feedstock or process fluids fo r a given process or to heat distillation columns (the latter are often termed ― reboilers ‖ ). These emissions sources are typically localized at or near the process requiring the heater (or reboiler). Boilers are used to generate steam for various refinery operations and to raise the temperature of feedstocks and process streams. Nearly all petroleum refinery process heaters and boilers combust refinery fuel gas, which is a mixture of uncondensable overhead gases from distillation columns (also referred to a s ―still gas‖) and natural gas, as the primary fuel, but other fuels (e.g., natural gas only, fuel oil, or residual oil) can also be used. Internal combustion engines have a variety of uses, including cogeneration, powering fire suppression systems, and supplying emergency back-up power. Internal combustion engines generally combust natural gas, gasoline, or diesel fuel oil. In addition to refinery fuel gas, some petroleum refineries also produce petroleum coke. The petroleum coke produced by a coking unit is generally referred to as green petroleum coke. Some refineries may use green petroleum coke (also referred to as fuel grade coke) as fuel in boilers to produce steam or electricity. Green petroleum coke is expected to contain relatively high concentrations of sulfur and metals when compared with other fuels used at a refinery. Green petroleum coke may be purified in a calcining unit for use in industrial applications, most often as anode material in the manufacture of aluminum. Consequently, calcined petroleum coke is often referred to as anode grade coke. Emissions from coke calcining are described in more detail in Section 5.6.3, Coke Calcining , of this Refinery Emissions Protocol document. Alternatively, green petroleum coke may be gasified with steam and either air or oxygen (O 2 

### ) to form a low (using air) to medium (using O 2 

### ) heating value synthesis gas (or syngas) for subsequent use as a fuel gas. There are no direct emissions from the coke gasification process; emissions from the combustion of syngas can be estimated using the methods provided in this section. Table 4-1 summarizes the hierarchy of emissions estimation methods for stationary combustion sources. Each refinery may use a combination of different methods, such as Methodology Rank 1 for criteria pollutants such as sulfur dioxide (SO 2 

### ) and NO x 

### , and Methodology Rank 2 or 3 to estimate emissions of organic or metal compounds. It is also important to note that the selection of Methodology Rank 3A or Methodology Rank 3B will depend on factors such as whether the pollutant being estimated has a reduced form (e.g., reduced sulfur compounds form SO 2 

### when oxidized) that can be continuously monitored, the variability of the combustion source, and the date of the most recent stack test. The remainder of this section provides additional detail and guidance regarding the implementation of these methods. A complete inventory for combustion sources will include emissions estimates for PM, SO 2 

### , NO x 

### , VOC, 3 

### carbon monoxide (CO), and CO 2 

### . Depending on the fuel combusted, a complete inventory will also include emissions estimates for hydrogen sulfide; metals, including but not limited to arsenic, chromium, mercury, lead, and selenium; organic compounds, including but not limited to benzene, formaldehyde, 1,3-butadiene, and naphthalene and other polycyclic organic matter; and dioxins and furans. It is important to note that this list is not exhaustive; if there is evidence that a combustion source at a refinery emits a pollutant, an emissions estimate should be included in a complete inventory, even if that pollutant is not specifically identified in this document.

3 

### Total hydrocarbon [THC] may be estimated as a surrogate for VOC.

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4-2 Table 4-1. Summary of Typical Hierarchy of Stationary Combustion Source Emissions Estimates Rank Measurement Method Additional Data Needed 1 Direct meas urement (continuous emission monitoring systems [CEMS] ) for both flow rate and gas composition 

##  Pressure, temperature, and moisture content (depending on the monitoring system)
2 Direct measurement ( CEMS ) for gas composition Use of F factors 

##  Fuel usage



##  Hea t content of fuel (depending on units of source - specific emissions factors) 3A F uel analysis/ m ass balance 

##  F uel usage



##  Assumed destruction efficiency 3 B Source

- specific stack testing to calculate s ource specific emission s correlations or factors 

##  Fuel usage



##  Heat content of fuel (depending on units of source - specific emissions factors) 4 Default emission s factors 

##  Fuel use records 

### There are many sources that describe emissions methodologies for combustion sources, particularly boilers and internal combustion sources, including Chapter 2 in the Emission Inventory Improvement Program Technical Report Series (ERG, 2001), 2008 Emissions Inventory Guidelines (TCEQ, 2009), and A Customized Approach for Quantifying Emissions for the Electric Power Generation Sector in Mexico (The United States

– Mexico Foundation for Science, 2008). These documents include many examples and sample calculations for liquid and solid fuels and should be consulted for more information if needed. 

## 4.1 Methodology Rank 1 for Stationary Combustion Sources Many stationary combustion sources will have a continuous emission monitoring system (CEMS) for NO x 

### and/or SO 2 

### . A CEMS is a comprehensive unit that continually determin es gas or PM concentrations or emissions rates using pollutant analyzer measurements and a conversion equation, graph, or computer program to produce results in the desired units. A CEMS that includes a flow rate monitor, which is needed to determine mass emissions rates, such as those needed for an emissions inventory, is also referred to as a continuous emission rate monitoring system (CERMS). The CEMS or CERMS continually determines the flow rate of the exhaust gas, analyzes the composition or specific pollutant concentration in the exhaust gas, and records the results. There are two main types of CEMS: in-situ and extractive. An in-situ CEMS measures and analyzes the emissions directly in a stack. There is less sample loss associated with the in-situ CEMS compared to the extractive CEMS because the sample lines of an extractive system can leak, freeze, or clog, or pollutants can be lost because of adsorption, scrubbing effects, or condensation. In an extractive CEMS, the sample gas is extracted from the gas stream and transported to a gas analyzer for the measurement of the contaminant concentration. Because an extractive CEMS is located outside the stack, the sampling instruments are not affected by stack conditions, maintenance and replacement are generally simpler, and the cost is lower than with an in-situ CEMS, although extra costs are incurred for the sampling and conditioning system for an extractive CEMS (Levelton Consultants, 2005 ). The pollutant concentration recorded by a CEMS is generally on a concentration basis, such as parts per million. The CEMS may also include a diluent monitor (e.g., O 2 

### ) for correcting the concentrations to a fixed excess air concentration. For in -situ CEMS, these measurements are made at stack conditions so that the concentrations would be determined on a ―wet basis.‖ That is, the concentratio ns are based on the total amount of gas, including water vapor. For extractive CEMS, the gas is often conditioned to remove water vapor before analysis, so the concentrations are commonly determined on a ―dry basis.‖ Gas flow measurements are made at stack conditions, so the flow rate will be in terms of actual gas volume on a wet basis. If the gas composition is determined on a dry basis, then a moisture content measurement is

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4-3 needed to convert the flow rate to a dry basis (or convert the composition to a wet basis) so that both measurements are on the same basis, and many gas flow monitors contain temperature and pressure monitors to allow conversion of the flow to standard conditions for this purpose. It is important to note that care must be taken to ensure that the gas and flow measurements are made on the same basis and in the same terms as the permitted limits, if applicable, or that appropriate ancillary measurements are made to perform the necessary unit conversions. The following general equation (Equation 4-1) is used for determining a mass emissions rate from CEMS: (Eq. 4-1)

where: E i 

### = Emissions rate of pollutant ― i ‖ (tons per year [tons/yr] ). N = Number of measurement periods per year (e.g., for hourly measurements, N = 8,760 ). n = Index for measurement period. (Q) n



### = Volumetric flow rate for measurement period ― n ‖ (actual cubic feet per minute [acfm] ). If the flow rate meter automatically corrects for temperature and pressure, then replace

― T o 

### ÷ T n 

### × P n 

### ÷ P o 

### ‖ with ―1

. ‖ If the pollutant concentration is determined on a dry basis and the flow rate meter automatically corrects for moisture content, replace the term [1

- (f H20 

### ) n 

### ] with 1. (f H2O 

### ) n 

### = Moisture content of exhaust gas during measurement period ― n, ‖ volumetric basis (cubic feet water per cubic feet exhaust gas). (C i 

### ) n 

### = Concentration of pollutant ― i ‖ in the exhaust gas for measurement period ― n ‖ (volume %, dry basis). If the pollutant concentration is determined on a wet basis, then replace the term [1

− (f

H20 

### ) n 

### ] with 1. MW i 

### = Molecular weight of pollutant ― i ‖ (kilogram per kilogram mole [kg/kg -mol]). MVC = Molar volume conversion factor = 849.5 standard cubic feet per kilogram mole

(scf/kg-mol) at 68°F (528 °R ) and 1 atmosphere (atm). T o 

### = Temperatur e at ―standard conditions‖ (528 °R ). T n



### = Temperature at which flow is measured during measurement period ― n ‖ (°R). P n 

### = Average pressure at which flow is measured during measurement period ― n ‖ (atm). P o 

### = Average pressure at ―standard conditions‖ (1 atm). M N 

### = Minutes per measurement period (minutes per measurement period ― n ‖). This term can

be calculated by dividing 525,600 minutes per year (min/yr) by the number of measurement periods per year (―N‖). K = Conversion factor = 2.2046/2,000 (tons per kilogram [tons/kg] = 0.0011023 tons/kg. A CEMS records multiple measurements per hour; the frequency depends on the pollutant being measured and the type of CEMS. For example, a CEMS monitoring benzene concentration using gas chromatography may only sample and record a measurement every 15 minutes, while a CEMS monitoring SO 2 

### concentration may record a measurement every minute. These individual measurements can be used to calculate annual emissions in two ways. The most common method is for the CEMS to average the measurements within each hour and develop 8,760 hourly average concentrations and flow rates that can be summed. Example 4-1 demonstrates the calculation of NO x 

### emissions for 1 hour for a combustion unit firing refinery fuel gas based on an hourly average concentration and flow rate. This method is best suited for measurements that are fairly consistent and stable over the course of an hour. The other method is to determine the emissions rate for each recorded measurement based on the concentration and flow rate for that measurement. In other words, if the CEMS records measurements every minute, then the emissions rate is determined per minute and hourly emissions are determined by summing the 60 applicable emissions rates; if the CEMS records measurements every 5 minutes, then the

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4-4 emissions rate is determined for each 5-minute interval and hourly emissions are determined by summing the 12 applicable emissions rates. This method may be more accurate than hourly averages if the combustion source’s flow rate varies significantly within an hour.



## 4.2 Methodology Rank 2 for Stationary Combustion Sources Because the emissions standards for stationary combustion sources are often provided on a concentration basis or on a mass per heating

– value basis, many stationary combustion sources will have a CEMS for pollutant concentrations, but may not directly measure exhaust gas flow. In these cases, fairly accurate exhaust gas flow rates can be calculated from the refinery fuel gas composition and fuel flow measurements. This method is commonly referred to as the ―F factor‖ method, and procedures for conducting a fuel analysis and calculating estimated emissions are described in EPA Method 19 (40 CFR Part 60, Appendix A-7). EPA Method 19 includes many equations that can be used to calculate emissions depending on moisture measurements and whether pollutant concentrations and O 2 

### or CO 2 

### content are measured on a wet or dry basis, and each equation uses one of three different types of F factors. The calculation of the different F factors is described in Section 12.3.2 of Method 19. In lieu of this calculation, Table 19-2 of EPA Method Example 4 - 1 : Calculation of NO x 

### Emissions Using a CEMS T he following example shows the calculation for 1 hour (60 minutes) ; the total emissions during any period (i.e., day, month, quarter, or year ) may be calculated as the sum of the hourly emissions determined by the CEMS. In terms of Equation 4

- 1, ― i ‖ is NO x 

### and the index for the period in this example is 1, so the result ― E ‖ is in tons per hour. Calc ulate hourly NO X 

### emissions f or a 150 million British thermal units per hour ( MMBtu /hr) unit burning refinery fuel gas g iven that the following data have been collected:



## – The hourly average NO x 

### concentration calculated by the CEMS for this hour is 6 0 parts p er million ( ppm ) , wet basis



## – The hourly average flow rate calculated by the CEMS for this hour is 5 00,000 acfm , wet basis



## – The unit operated at standard conditions for the full hour

. Equation 4

- 1 should be used to c alculate the hourly emissions:

= 5 00,000 × 1 × (60 ÷ 1,000,000) × 46.01 ÷ 849.5 × 1 × 1 × 60 × 0.0011023

= 0.1075 tons per hour (tons /hr ). Rounded to two significant figures, the hourly emissions are 0.11 tons/hr. If the combustion source did not operate the entire hour , multiply the hourly emissions by the fraction of the hour that the unit operated (e.g., if the unit operated for 30 minutes, then emissions for this hour would be 0.1075 tons/hr × 0.5 = 0.054 tons/hr). If the combustion source operated steadily and conti nuously for an entire year and the emissions rate remained perfectly constant over that year, annual emissions would be 0.1075 tons/hr × 8,760 hours per year (hr/yr) = 94 0 tons/yr.

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4-5 19 includes default F factors for some fuel common types that could be used; however, F factors for refinery fuel gas are not included in Table 19-2. Refinery fuel gas generally includes many different components; therefore, one equation that can be used to calculate the F factor in this situation is an adapted version of Equation 19-16 in EPA Method 19 for multiple fuels. In Equation 4-2, the dry F factor, F d 

### , is calculated assuming both the pollutant concentration and the O 2 

### content are measured on a dry basis:

(Eq. 4-2)

where: F d 

### = Volume of combustion components per unit of heat content (dry standard cubic feet

per million British thermal unit [d scf/MMBtu]) K = Conversion factor, 10 6 

### (Btu/MMBtu) n = Number of fuels or fuel components

i = Index for fuels or fuel components X i 

### = Mole or volume fraction of each component in the refinery fuel gas MEV i 

### = Molar exhaust volume (dry standard cubic feet per mole [dscf/mol]) MHC i 

### = Molar heat content (British thermal units per mole [Btu/mol]) Table 4-2 includes values for the molar exhaust volume and molar heat content for common constituent s of refinery fuel gas. It is important to note that these calculations are based on the higher heating value of the fuel gas (referred to as gross calorific value in EPA Method 19).
Table 4-2
. Molar Exhaust Volumes and Molar Heat Content of Refinery Fuel Gas Constituents

Constituent MEV a ( dscf/mol ) MHC b ( Btu/mol ) Methane (CH 4 ) 7.28 842 Ethane (C 2 H 6 ) 12.94 1,475 Hydrogen (H 2 ) 1.61 269 Ethene (C 2 H 4 ) 11.34 1,335 Propane (C 3 H 8 ) 18.61 2,100 Propene (C 3 H 6 ) 17.01 1,947 Butane (C 4 H 10 ) 24.28 2,717 Butene (C 4 H 8 ) 22.67 2,558 Inerts 0.85 0

a MEV = molar exhaust volume ( dry standard cubic feet per mole [ dscf/mol ] ) b MHC = molar heat content ( Btu per mole [ Btu/mol ] ) ; higher heating value basis 

### The F factor can be used to calculate emissions in one of two ways. In the first option, the F factor, the amount of fuel combusted, and the heat content of the fuel can be used to calculate the volumetric flow rate of the exhaust gas, (Q) n 

### , using the following equation.

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4-6 (Eq. 4-3)

where: Q n 

### = Volumetric flow rate for measurement period ― n ‖ (dry standard cubic feet per minute

[dscfm]) F d 

### = Volume of combustion components per unit of heat content (dscf/MMBtu) Q f



### = Volumetric flow rate of fuel ( ds cf m) HHV = Higher heating value of fuel (million British thermal units per standard cubic f oo t [MMBtu/scf]) %O 2d 

### = Concentration of O 2 

### on a dry basis (percent) Once the volumetric flow rate is known, emissions can be calculated using Equation 4-1 as in Methodology Rank 1 for stationary combustion sources. It is important to note that when using the F factor method as indicated here, the exhaust gas flow rate will be in units of dry standard cubic feet per minute, so the temperature and pressure correction terms are not needed. A moisture correction term is not needed when the concentration measurement is also made on a dry basis. If the concentration measurements are made on a wet basis, then they must be corrected to a dry basis by dividing by the [1

− (f H20 

### ) n 

### ] term. In the second option, the F factor can be used to calculate an emissions factor (Equation 4-4) that can then be multiplied by the higher heating value of the fuel to estimate emissions (Equation 4-5).
(Eq. 4-4)

where: EF i 

### = Emissions rate of pollutant (pounds per million British thermal unit [lb/MMBtu]) C d 

### = Pollutant concentration, dry basis (pounds per standard cubic foo t [lb/dscf]) F d 

### = Volume of combustion components per unit of heat content (dscf/MMBtu) %O 2d 

### = Concentration of O 2 

### on a dry basis (percent) (Eq. 4-5) where: E i 

### = Emissions of pollutant ―i‖ (pounds per hour [lb/hr])

EF i 

### = Emissions rate of pollutant (lb/MMBtu) Q f



### = Volumetric flow rate of fuel (dscfm) 60 = Conversion factor, minutes per hour HHV = Higher heating value of fuel (MMBtu/scf)
Ex ample 4-2 demonstrates the calculation of an F factor based on a fuel analysis for refinery fuel gas. Examples 4-3 and 4-4 demonstrate the first and second options, respectively, to estimate emissions using the F factor. As previously mentioned, if the result of a calculation is an hourly emissions estimate, then the calculation process should be repeated for each hour in the year, or 8,760 times. For example, the hourly pollutant and O 2 

### concentrations from the CEMS should be used in Equation 4-4 to calculate an emissions factor for each hour in the year. That emissions factor and the hourly measurements of the fuel flow rate should then be used in Equation 4-5 to determine the hourly emissions for each hour in the year. The sum of all of those hourly emissions estimates is the annual emissions estimate.

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4-7 Example 4 - 3 : Calculation of Exhaust Flow Rate from F Factor From Example 4

- 2, the F factor is 8,809 dscf/MMBtu. The measured SO 2 

### concentration is 20 ppmv (dry basi s), the measured O 2 

### concentration is 6% (dry basis), the higher heating value is 1,300 Btu/scf, and the fuel flow rate is 500 dscfm. Equation 4

- 3 should be used to calculate the exhaust flow rate from F factor as follows:

Q n 

### = (8, 809) × (500) × (1,300 ÷ 10 6 

### [Btu/MMBtu]) × (20.9 ÷ (20.9

– 6)) Q n 

### = 8,031 dscfm Use this value of Q n 

### in Equation 4

- 1 without the temperature, pressure, and moisture correction terms to estimate hourly emissions as follows:

E SO 2 

### = 8 ,0 31 × 1 × (20 ÷ 1,000,000) × 64.06 ÷ 849.5 × 60 × 2.2046 = 1.6 lb/hr Example 4 - 2 : Calculation of F uel - S pecific F F actor The CEMS measures S O 2 

### and O 2 

### content on a dry basis, so i n lieu of using a default F factor, the facility can use fuel analysis results and E quation 4

- 2 to calculate an F d 

### factor (scf/MMBtu)

. The F d 

### factor is calculated at standard conditions of 20°C (68°F) and 29.92 inches of mercury. The fuel analysis revealed the following mole fractions: Methane 0.44 Propene 0.03 Ethane 0.04 Butane 0.17 Hydrogen 0.06 Butene 0.01 Ethene 0.01 Inerts 0.04 Propane 0.2 Equation 4

- 2 is used t o calculate F d 

### as follows:

F d 

### = 10 6 

### × [(0.44 × 7.28) + (0.04 × 12.94) + (0.06 × 1.61) + (0.01 × 11.34) + (0.2 × 18.61) + (0.03 × 17.01) + (0.17 × 24.28) + (0.01 × 22.67) + (0.04 × 0.85)] ÷ [(0.44 × 842) + (0.04 × 1475) + (0.06 × 269) + (0.01 × 1335) + (0.2 × 2100) + (0.03 × 194 7) + (0.17 × 2717) + (0.01 × 2558) + (0.04 × 0)]

= 10 6 

### × 12.55 ÷ 1425
= 8,809 dscf/MMBtu

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4-8 

## 4.3 Methodology Rank 3A for Stationary Combustion Sources Fuel analysis can be used to predict emissions of pollutants such as SO 2 

### by examining the compounds in the fuel being combusted. Given a known concentration of a compound, either a pollutant or pollutant precursor (e.g., hydrogen sulfide [H 2 

### S] or other reduced sulfur compounds for purposes of estimating SO 2 

### emissions), emissions of the pollutant can be calculated by assuming that all of th at compound is emitted (e.g., all of the reduced sulfur is oxidized to SO 2 

### ). Alternatively, if some of the compound is not combusted (i.e., is in a different physical or chemical state such as ash or unburned hydrocarbons), then based on the laws of mass conservation, less than 100% of the pollutant is emitted as air emissions (ERG, 2001). In this case, it may be possible to determine the emissions actually resulting from combustion by considering the uncombusted compounds in a mass balance analysis. As mentioned in the introduction to Section 4, Methodology Rank 3A for stationary combustion sources is considered a more accurate method of emissions estimation than Methodology Rank 3B for stationary combustion sources for certain pollutants, namely SO 2 

### , particularly if the concentration of the compound of interest in the fuel and the fuel flow rate are continuously measured. This may also be the case if the availab le source tests are not recent or if the combustion unit’s operation varies significantly enough that there are concerns about the accuracy of applying an emissions factor developed at one set of operating conditions. For example, a test of NO x 

### emissions from a process heater performed at high capacity may Example 4 - 4 : Calculation of Emissions Factor from F F actor Given the same measurements as Example 4

- 3, calculate hourly SO 2 

### emissions. First, the following equation should be used to co nvert the concentration to the correct units (from Table 19

- 1 of EPA Method 19, multiply the SO 2 

### concentration in ppm by 1.660 × 10 - 7 

### to convert to lb/scf [see also Equation 4

- 7 of this section]): C d 

### = 20 ppm × ( 1.660 × 10 - 7 

### ) lb/scf/ppm C d 

### = 3.322 × 10 - 6 

### lb/scf Second, Equation 4

- 4 should be used to calculate the emissions factor :

EF SO 2 

### = (3.322 × 10 - 6 

### ) × (8,809) × (20.9 ÷ (20.9

– 6))

EF SO 2 

### = 0.041 lb/MMBtu Finally, Equation 4

- 5 should be used to calculate the hourly emissions ( the fuel flow rate is 500 dscfm, or 30,000 dscf/hr [500 dscfm × 60 minutes per hour (min/hr)])

E SO 2 

### = (0.041) × (30,000) × (1,300 ÷ 10 6 

### [Btu/MMBtu])

E SO 2 

### = 1.6 lb/hr If the combustion source operated steadily and continuously for an entire year and the emissions rate remained perfectly constant over that year, then the annual emissions would be 1.6 lb/hr × 8,760 hr/yr ÷ 2,000 lb/ton = 7.0 tons/yr.

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4-9 not apply when the process heater is firing at a lower rate. As the heater firing rate decreases, the operator increases the oxygen content to ensure stable operation, and this increase in oxygen content leads to higher concentrations of NO x 

### . Equation 4-6 is a general equation used to determine a mass emissions estimate from fuel analysis data for gaseous fuels (for fuel analysis of liquid and solid fuels, see the documents referenced in the introduction to Section 4).
(Eq. 4-6)
where (assuming gaseous fuel): E i 

### = Emissions estimate of pollutant ―i‖ (lb/hr) Q f



### = Fuel flow rate (scf/hr) C f



### = Content of pollutant in fuel (lb/scf) MW i 

### = Molecular weight of pollutant emitted (pounds per pound mole [lb/lb-mol]) MW f 

### = Molecular weight of pollutant in the fuel (lb/lb-mol) As previously explained, to calculate yearly emissions, this type of calculation must be repeated for each hour in the year, or 8,760 times. Also, as described in Example 4-1, if the combustion source did not operate for part of an hour, then the emissions estimates for that hour should be multiplied by the fraction of the hour that it did operate. If the compound concentration is measured in parts per million or as a percentage rather than pounds per cubic feet, then Equation 4-7 will be needed. Equation 4-7 provides a methodology for calculating compound-specific conversion factors such as the values shown in Table 19-1 of EPA Method 19 for NO x 

### and SO 2 

### . (Eq. 4-7) where: C f



### = Content of pollutant in fuel (lb/scf) C c 

### = Volumetric concentration of pollutant in fuel (ppm or percentage) MW i 

### = Molecular weight of pollutant ―i‖ emitted (lb/lb -mole) K = Conversion constant: 10 6 

### if units of C c 

### are ppm; 10 2 

### if units of C c 

### are a percentage 385.3 = Conversion constant for ideal gases (standard cubic feet per pound mole [scf/lb-mol])

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4-10 

## 4.4 Methodology Rank 3B for Stationary Combustion Sources Source testing can provide useful data for developing site-specific emissions correlations or emissions factors. Source testing provides a measurement of the emissions at a particular point in time, and most tests are performed at conditions representative of normal operation, in which case the emissions measurement can provide an estimate of emissions at similar operating conditions. Emissions factors are developed by dividing the emissions rate by a process parameter such as fuel usage. It is important to note that this methodology will be less reliable when the unit is operating at conditions other than those tested. Generally, one source test consisting of three runs is performed at a specific set of conditions, and the results for each run can be averaged to determine an emissions factor that is assumed to apply at all heat input rates. Example 4-5 demonstrates a sample emissions factor calculation based on one test with three test runs. Section 5.1.2 of this document, Methodology Ranks 3 and 4 for Catalytic Cracking Units , also provides details on calculating one emissions factor based on three test runs. That section also includes a detailed description of the ways in which source tests and analyses for PM may need to be handled differently than other pollutants. Example 4 - 5: Fuel Analysis Calculate hourly emissions from a combustion source burning refinery fuel gas given:



## – Fuel flow rate = 500 dscfm, or 30,000 dscf/hr (500 dscfm × 60 min/hr)



## – Sulfur content of the fuel = 160 ppm



## – Molec ular weight of sulfur = 32 lb/lb

- mole; molecular weight of SO 2 

### = 64 lb/lb

- mole Convert the concentration of sulfur in the fuel to the correct units using Equation 4

- 7:

C f 

### = (160) × ( 32) ÷ (10 6 

### ) ÷ (385.3) C f 

### = 1.33 × 10 - 5 

### lb/scf T hen, use Equation 4

- 6 to calculate the hourly mass emissions:

E SO 2 

### = (30,000) × (1.33 × 10 - 5 

### ) × (64) ÷ (32)

E SO 2 

### = 0.80 lbs SO 2 

### /hr If the combustion source operated steadily and continuously for an entire year and the emissions r ate remained perfectly constant over that year, then the annual emissions would be 0.80 lbs/hr × 8,760 hr/yr ÷ 2,000 pounds per ton (lb/ton) = 3.5 tons/yr.

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4-11 A more complex methodology for developing a correlation rather than one emissions factor is provided in Section 2.1.2 of A Customized Approach for Quantifying Emissions for the Electric Power Generation Sector in Mexico (The United States

– Mexico Foundation for Science, 2008). Section 2.1.2 provides a detailed explanation of a methodology for developing a correlation between NO x 

### emissions and heat input to the source (fuel use multiplied by heat content of fuel) that is based on EPA ’s Optional NO x 

### Emissions Estimation Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units (40 CFR Part 75, Appendix E). This methodology allows the operator to account for lower mass emissions per heat input for lower operating loads. The methodology calls for stack measurements at three load levels, ideally 50%, 75%, and 100% firing rates. The test results at each firing rate are used to calculate an emissions factor in units of mass per heat input (or mass per amount of fuel combusted, assuming a constant heat content of fuel). Following the development of this correlation, hourly emissions can be calculated based on hourly measurements of fuel combusted and calculations of the heat content of the fuel (or constant heating value of the fuel). Section 2.1.2 also includes a detailed set of sample calculations in Exhibit 2.1-3 to demonstrate this procedure. 

## 4.5 Methodology Rank 4 for Stationary Combustion Sources When direct emissions monitoring or site-specific emissions factors are not available, then default emissions factors may be the only way to estimate emissions. The EPA has developed emissions factors for various types of combustion sources, which are compiled in AP -42. Emissions factors for process heaters, boilers, and other types of external combustion sources are included Chapter 1 of the Compilation of Air Pollutant Emission Factors

. Volume 1: Stationary Point and Area Sources , and emissions factors for internal combustion sources are presented in Chapter 3 of this same document (U.S. EPA, 1995a). It is important to note that AP -42 does not include emissions factors for all fuels (notably refinery fuel gas and coke). The emissions factors in AP -42 are the recommended default emission factors, and AP-42 should be consulted to obtain the appropriate emissions factors for criteria pollutants such as SO 2 

### , NO x 

### , PM, and CO. In addition, the American Petroleum Institute (API), in conjunction with the Western States Petroleum Association (WSPA), has conducted emissions source tests of combustion sources and has compiled emissions factors that may be used for refinery combustion sources if AP-42 does not include an applicable emissions factor (Hansell and England, 1998). Separate emissions factors were developed for different combustion sources based on the type of source and fuel used. Appendix D presents the full data Example 4 - 6: Site - S pecific Emission s Factor During the most recent source test, thr ee test runs were conducted to determine the NO x 

### emission rate for a 50 MMBtu/hr process heater. The NO x 

### emissions rate measured during the source tests were 1.92, 1.51, and 1.76 lbs/hr for tests 1, 2, and 3, respectively. The process heater was firing at 95% capacity during all three test runs. First, calculate the appropriate emissions factor for each individual run, and then average the emissions factors with the following calculations:



## – Run 1: Emissions/throughput = 1.92 [lbs/hr] ÷ (50 × 0.95) [MMBtu/hr] = 0.040 lbs NO x 

### /MMBtu



## – Run 2: Emissions/throughput = 1.51 [lbs/hr] ÷ (50 × 0.95) [MMBtu/hr] = 0.032 lbs NO x 

### /MMBtu



## – Run 3: Emissions/throughput = 1.76 [lbs/hr] ÷ (50 × 0.95) [MMBtu/hr] = 0.037 lbs NO x 

### /MMBtu



## – Average: Emissions/throughput = (0.040 + 0.032 + 0. 037) ÷ 3 = 0.036 lbs NO x 

### /MMBtu

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4-12 analysis summary for combustion sources of interest as presented in Hansell and England ’s Appendices A and B (1998), including the California Air Resources Board (CARB) emissions factor rating; the mean, median, maximum, and minimum emission factors; number of tests analyzed; standard deviation; uncertainty; and percent of test run results at or above the detection limit. The following tables present the recommended emissions factors for a variety of metals and organic compounds. The emissions factors in these tables are either the applicable emissions factors as presented in AP-42 or the mean emissions factors compiled by Hansell and England (1998). (Additional details on the rating and quality of these emissions factors are located in the original document for AP-42 emissions factors and in Appendix D for the emissions factors compiled by Hansell and England (1998).) Emissions factors for process heaters using various fuels are presented in Table 4-3 . Emissions factors for boilers using fuel oil and refinery fuel gas are presented in Table 4-4 . Emissions factors for reciprocating internal combustion engines using a variety of fuels are presented in Tables 4-5 and 4-6 . Emissions factors for turbines using a variety of gaseous fuels are presented in Tables 4-7 and 4-8

. To use any of these emissions factors appropriately, the refinery must monitor or keep records of the amount of fuel combusted (for the emissions factors with volumetric flow rates in the denominator) or the heat input (for emissions factors with heating values in the denominator). It is important to note that the bold italic emissions factor values in Tables 4-3 through 4-8 from Hansell and England (1998) are based on method detection limits and are likely biased high. For example, the hexavalent chromium (Cr +6 

### ) emissions factor for process heaters combusting refinery fuel gas, which is based on non-detect values, is higher than the emissions factor for total chromium. Therefore, additional data are needed to develop accurate emissions factors for the compounds that were below the detection limits for this particular test (RTI, 2002). The footnotes to Tables 4-3 through 4-6 explain any differences if a recommended emissions factor is derived from another emissions factor. It is also important to note that this document does not include emissions factors for refinery combustion sources combusting either green or calcined petroleum coke. In addition, while emissions from the combustion of synga s (gas produced by coke gasification) can be estimated using the methods provided in this section, this document does not include emissions factors for syngas as a fuel. Emissions factors for these fuels will need to be developed from future emissions testing and analysis.

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4-13 4.5.1 Default Emissions Factors for Process Heaters Table 4-3. Summary of Emissions Factors for Process Heaters Firing Various Fuels

CAS Number Substance Emission s Factor for Fuel Type a ,b

Natural Gas (lb/MMcf) Natural Gas

(lb/MM Btu ) Natural Gas

and Refinery Fuel Gas (lb/MMcf) Natural Gas

and Refinery Fuel Gas (lb/MM Btu ) Oil

(lb/Mgal) Oil

(lb/MMBtu) Refinery

Fuel Gas (lb/MMcf) c Refinery

Fuel Gas (lb/MMBtu) c
83

- 32

- 9 Acenaphthene 1. 4 E

- 06 1. 4 E

- 09 7.5E

- 06 4. 1 E

- 09 1. 8 E

- 06 1.2E

- 08 2.3E

- 06 2. 4 E

- 09 208

- 96

- 8 Acenaphthylene 1.2E

- 05 1. 2 E

- 08 5. 9 E

- 05 3. 2 E

- 08 8.0E

- 08 5.6E

- 10 1.5E

- 06 1. 6 E

- 09 75

- 07

- 0 Acetaldehyde 4.6E

- 03 4.5E

- 06 1. 5 E

- 02 7.0E

- 06 5.4E - 04 3.8E

- 06 2.0 E

- 02 1.5E

- 05 107

- 02

- 8 Acrolein 4.5E - 03 4.4E

- 06 2. 3 E

- 03 1. 1 E

- 06 6.0 E

- 04 4.2E

- 06

-- - - 120

- 12

- 7 Anthracene 1.6E

- 06 1. 6 E

- 09 1.0E

- 05 5. 6 E

- 09 6.6E

- 08 4.6E

- 10 2.8E

- 06 2. 9 E

- 09 7440

- 36

- 0 Antimony

-- -- -- -- -- -- 5.8E

- 04 5. 2 E

- 07 7440

- 38

- 2 Arsenic

-- -- -- -- 8.3E - 04 5.8E

- 06 9.5E

- 04 8.5E

- 07 7440

- 39

- 3 Barium

-- -- -- -- -- -- 6. 5 E - 03 5.8E

- 06 71

- 43

- 2 Benzene 2.3E

- 03 2. 3 E

- 06 2.1E - 02 1.0E

- 05 8. 5 E

- 03 5.9E

- 05 8.4E

- 02 6. 5 E

- 05 56

- 55

- 3 Benzo(a)anthracene 1.4E

- 06 1. 4 E

- 09 9. 6 E

- 06 5. 2 E

- 09 3.8E

- 06 2.7E

- 08 3.7E

- 05 3.2E

- 08 50

- 32

- 8 Benzo(a)pyrene 1.1E - 06 1.1E

- 09 6. 1 E

- 06 3.2E

- 09 9.8E

- 08 6.8E

- 10 9. 9 E

- 05 9

. 0 E

- 08 205

- 99

- 2 Benzo(b)fluoranthene 1.1E - 06 1.1E

- 09 2.6E

- 06 1.4E

- 09 8.0 E

- 07 5.6E

- 09 4.6E

- 05 4.0E

- 08 192

- 97

- 2 Benzo(e)pyrene

-- -- -- -- 5.5E

- 07 3.9E

- 09

-- -- 191

- 24

- 2 Benzo(g,h,i)perylene 1. 3 E

- 06 1.2E

- 09 4.1E

- 07 2.2E

- 10 2.1E

- 06 1.5E

- 08 1. 2 E - 06 1. 2 E

- 09 207

- 08

- 9 Benzo(k)fluoranthene 1.1E - 06 1.1E

- 09 1. 5 E

- 06 7.6E

- 10 3. 4 E

- 08 2.4E

- 10 2.7E

- 05 2.4E

- 08 7440

- 41

- 7 Beryllium

-- -- -- -- 7. 8 E - 05 5.4E

- 07 2. 9 E

- 04 2. 6 E

- 07 (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-14 T able 4 - 3
. Summary of Emission s Factors for Process Heaters Firing Vario us Fuels (continued)

CAS Number Substance Emission s Factor for Fuel Type a ,b

Natural Gas (lb/MMcf) Natural Gas

(lb/MM Btu ) Natural Gas

and Refinery Fuel Gas (lb/MMcf) Natural Gas

and Refinery Fuel Gas (lb/MM Btu ) Oil

(lb/Mgal) Oil

(lb/MMBtu) Refinery

Fuel Gas (lb/MMcf) c Refinery

Fuel Gas (lb/MMBtu) c
106

- 99

- 0 1,3

- Butadiene

-- -- -- -- 2.0 E - 02 1.4E

- 04

-- -- 7440

- 43

- 9 Cadmium

-- -- -- -- 8.2E

- 04 5.7E

- 06 1.1E

- 03 9. 9 E

- 07 67

- 66

- 3 Chloroform

-- -- -- -- 8.6E - 03 6.0E

- 05

-- -- 91

- 58

- 7 2

- Chloronaphthalene

-- -- -- -- 1. 2 E

- 05 8.2E

- 08

-- -- 18540

- 29

- 9 Chromium (hex avalent )

-- -- -- -- 2. 9 E - 04 2.0E

- 06 2.4E

- 04 d 2.2E

- 07 d
7440

- 47

- 3 Chromium (total)

-- -- -- -- 2.5E

- 03 1.8E

- 05 1.2E

- 03 1. 1 E

- 06 218

- 01

- 9 Chrysene 1. 4 E

- 06 1.4E

- 09 7.9E

- 07 4

. 3 E

- 1 0 1.1E

- 05 7.8E

- 08 1. 7 E

- 06 1.6E

- 09 7440

- 50

- 8 Copper

-- -- -- -- 2.6E

- 03 1.8E

- 05 4.7E

- 03 4.2E

- 06 53

- 70

- 3 Dibenz(a,h)anthracene 1.1E - 06 1.1E

- 09 1. 4 E

- 07 7

. 5 E - 1 0 1. 8 E

- 06 1.2E

- 08 1. 1 E - 05 1.0E

- 08 1746

- 01

- 6 Dioxin: 4D 2378 e

-- -- -- -- 5.0 E - 10 3.5E

- 12

-- -- 40321

- 76

- 4 Dioxin: 5D 1 2378 e

-- -- -- -- 2. 5 E - 09 1.7E

- 11

-- -- 39227

- 28

- 6 Dioxin: 6D 123478 e

-- -- -- -- 2. 2 E - 09 1.5E

- 11

-- -- 57653

- 85

- 7 Dioxin: 6D 123678 e

-- -- -- -- 3.0 E

- 09 2.1E

- 11

-- -- 19408

- 74

- 3 Dioxin: 6D 123789 e

-- -- -- -- 4.8E

- 09 3.3E

- 11

-- -- 35822

- 46

- 9 Dioxin: 7 D 1234678 e

-- -- -- -- 1.3E

- 08 9.3E

- 11

-- -- 3268

- 87

- 9 Dioxin: 8D e

-- -- -- -- 4. 7 E

- 08 3.3E

- 10

-- -- (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-15 T able 4 - 3
. Summary of Emission s Factors for Process Heaters Firing Vario us Fuels (continued)

CAS Number Substance Emission s Factor for Fuel Type a ,b

Natural Gas (lb/MMcf) Natural Gas

(lb/MM Btu ) Natural Gas

and Refinery Fuel Gas (lb/MMcf) Natural Gas

and Refinery Fuel Gas (lb/MM Btu ) Oil

(lb/Mgal) Oil

(lb/MMBtu) Refinery

Fuel Gas (lb/MMcf) c Refinery

Fuel Gas (lb/MMBtu) c
100

- 41

- 4 Ethylbenzene 2. 3 E - 03 2. 2 E

- 0 6

-- -- -- -- 3.0E

- 02 3.0E

- 05 206

- 44

- 0 Fluoranthene 1. 2 E

- 05 1.2E

- 08 1.8 E

- 05 9.7E

- 09 2.0 E

- 06 1.4E

- 08 3

. 1 E

- 06 3. 1 E

- 09 86

- 73

- 7 Fluorene 4. 6 E

- 06 4.5E

- 09 6.5E

- 04 3. 5 E

- 07 7. 5 E

- 05 5.2E

- 07 1. 1 E

- 05 1. 1 E

- 08 50

- 00

- 0 Formaldehyde 4. 8 E

- 03 4.6E

- 06 4.3E

- 02 2. 2 E

- 05 3.8E - 03 2.7E

- 05 1.5E

- 01 1.1E

- 04 51207

- 31

- 9 Furan: 4F 2378 f

-- -- -- -- 8.9E

- 08 6.2E

- 10

-- -- 57117

- 41

- 6 Furan: 5F 12378 f

-- -- -- -- 8. 6 E - 09 6.0E

- 11

-- -- 57117

- 31

- 4 Furan: 5F 23478 f

-- -- -- -- 1.5E - 08 1.1E

- 10

-- -- 70648

- 26

- 9 Furan: 6F 123478 f

-- -- -- -- 1.9E

- 08 1.3E

- 10

-- -- 57117

- 44

- 9 Furan: 6F 123678 f

-- -- -- -- 6.1 E

- 09 4.3E

- 11

-- -- 72918

- 21

- 9 Furan: 6F 123789 f

-- -- -- -- 5.0 E - 10 3.5E

- 12

-- -- 60851

- 34

- 5 Furan: 6F 234678 f

-- -- -- -- 8. 8 E

- 09 6.1E

- 11

-- -- 67562

- 39

- 4 Furan: 7F 1234678 f

-- -- -- -- 2.0 E

- 08 1.4E

- 10

-- -- 55673

- 89

- 7 Furan: 7F 1234789 f

-- -- -- -- 1. 2 E - 09 8.3E

- 12

-- -- 39001

- 02

- 0 Furan: 8F f

-- -- -- -- 1.0E

- 08 7.29E

- 11

-- -- 7783

- 06

- 4 Hydrogen sulfide

-- -- -- -- -- -- 4. 1 E - 01 2.9E

- 04 193

- 39

- 5 Indeno(1,2,3

- cd) pyrene 1.1E - 06 1.1E

- 0 9 4.6E

- 07 2.5E

- 10 1.8E

- 06 1.3E

- 08 1. 2 E

- 04 1.0E

- 07 (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-16 T able 4 - 3
. Summary of Emission s Factors for Process Heaters Firing Vario us Fuels (continued)

CAS Number Substance Emission s Factor for Fuel Type a ,b

Natural Gas (lb/MMcf) Natural Gas

(lb/MM Btu ) Natural Gas

and Refinery Fuel Gas (lb/MMcf) Natural Gas

and Refinery Fuel Gas (lb/MM Btu ) Oil

(lb/Mgal) Oil

(lb/MMBtu) Refinery

Fuel Gas (lb/MMcf) c Refinery

Fuel Gas (lb/MMBtu) c
7439

- 92

- 1 Lead

-- -- -- -- 3.0 E

- 04 2.1E

- 06 5. 5 E

- 03 4.9E

- 06 7439

- 96

- 5 Manganese

-- -- -- -- 1. 9E

- 03 1.3E

- 05 7. 7 E

- 03 6.8E

- 06 7439

- 97

- 6 Mercury

-- -- -- -- 1.7E - 05 1.2E

- 07 2.0E

- 04 1.8 E

- 07 91

- 57

- 6 2

- Methylnaphthalene

-- -- -- -- 3.6E

- 05 2.5E

- 07

-- -- 91

- 20

- 3 Naphthalene 2. 4 E

- 04 2. 3 E

- 0 7 2.3 E

- 03 1.2E

- 06 8.5 E

- 04 5.9E

- 06 3.0 E

- 04 3.1 E

- 07 7440

- 02

- 0 Nickel

-- -- -- -- 3. 5 E

- 01 2.4E

- 03 1. 1 E

- 02 9.4E

- 06 198

- 55

- 0 Perylene

-- -- -- -- 7.4 E

- 08 5.2E

- 10

-- -- 85

- 01

- 8 Phenanthrene 3. 4 E

- 05 3. 3 E

- 0 8 2. 1 E

- 04 1.1E

- 07 2. 5 E

- 05 1.7E

- 07 1.4E

- 05 1. 5 E

- 08 1 08

- 95

- 2 Phenol

-- -- 1.7 E

- 03 9.2E

- 07

-- -- 7.0 E

- 03 5.6E

- 06 7723

- 14

- 0 Phosphorus

-- -- -- -- -- -- 7.2E - 04 6.4E

- 07 115

- 07

- 1 Propylene 4.6E

- 01 4. 5 E

- 0 4 1.2E - 02 5.8E

- 06 1.5E

- 02 1.1E

- 04 2. 1 E

- 03 2. 2 E

- 06 129

- 00

- 0 Pyrene 5.6E

- 06 5. 5 E

- 0 9 1. 3 E

- 05 4.1E

- 09 1.3 E

- 05 9.2E

- 09 2.8E

- 06 2.8E

- 09 7782

- 49

- 2 Selenium

-- -- -- -- 4.6E - 03 3.2E

- 05 2.2E

- 05 2.0 E

- 08 7440

- 22

- 4 Silver

-- -- -- -- -- -- 1.8E

- 03 1.6E

- 06 7440

- 28

- 0 Thallium

-- -- -- -- -- -- 6. 5 E - 03 5. 8 E

- 06 (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-17 T able 4 - 3
. Summary of Emission s Factors for Process Heaters Firing Vario us Fuels (continued)

CAS Number Substance Emission s Factor for Fuel Type a ,b

Natural Gas (lb/MMcf) Natural Gas

(lb/MM Btu ) Natural Gas

and Refinery Fuel Gas (lb/MMcf) Natural Gas

and Refinery Fuel Gas (lb/MM Btu ) Oil

(lb/Mgal) Oil

(lb/MMBtu) Refinery

Fuel Gas (lb/MMcf) c Refinery

Fuel Gas (lb/MMBtu) c
108

- 88

- 3 Toluene 3.2E

- 02 3.2E

- 0 5 2.6E - 02 1 .3E

- 05 1.0 E

- 0 2 7.0E

- 05 1. 4 E

- 01 1. 1 E

- 04 1330

- 20

- 7 Xylene (total) 1. 9 E

- 02 1. 8 E

- 0 5 3.0E - 02 1.5E

- 05 1.9E

- 02 1.3E

- 04 3.7E

- 02 3.7E

- 05 7440

- 66

- 6 Zinc

-- -- -- -- 8.9E

- 03 6.2E

- 05 2.3E

- 02 2. 1 E

- 05 Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds pe r million cubic feet, lb/MMBtu = pounds per million British thermal units
a Bold italic values indicate that all test runs were below detection limit; underlined values indicate that more than 75% of t he test runs were below the detection limit. b Source : Hansell and England, 1998.
c The same mean emissions factors were provided specifically for heaters with no control device, heaters with selective catalyt ic reduction, and heaters with selective non

- catalytic reduction. d Hexavalent chromium was not de tected. The Hansell and England emissions factor based on the detection limits was approximately twice the emissions factor for total chromium; therefore, the reported emissions factor for hexavalent chromium was not included in this table. Instead, t wenty percent of the total chromium emissions factor is assumed for the hexavalent chromium emissions factor. (The hexavalent chromium emissions factors for turbines is between 10 and 15 percent of the total chromium emissions factor, and the hexavalent chromiu m emissions factor for boilers firing fuel oil is about 30 percent of the total chromium emissions factor, so 20 percent is a conservative approximation for hexavalent chromium emissions from refinery fuel gas.)
e 4D 2378 = 2,3,7,8

- Tetrachlorodibenzo

- p - di oxin; 5D 12378 = 1,2,3,7,8

- Pentachlorodibenzo

- p - dioxin; 6D 123478 = 1,2,3,4,7,8

- Hexachlorodibenzo

- p - dioxin; 6D 123678 = 1,2,3,6,7,8

- Hexachlorodibenzo

- p - dioxin; 6D 123789 = 1,2,3,7,8,9

- Hexachlorodibenzo

- p - dioxin; 7D 1234678 = 1,2,3,4, 6, 7,8

- Heptachlorodibenz o - p dioxin; 8D = Octachlorodibenzo

- p - dioxin. f 4F 2378 = 2,3,7,8

- Tetrachlorodibenzofuran; 5F 12378 = 1,2,3,7,8

- Pentachlorodibenzofuran; 5F 23478 = 2,3,4,7,8

- Pentachlorodibenzofuran; 6F 123478 = 1,2,3,4,7,8

- Hexachlorodibenzofuran; 6F 123678 = 1,2,3,6,7,8

- H exachlorodibenzofuran; 6F 123789 = 1,2,3,7,8,9

- Hexachlorodibenzofuran; 6F 234678 = 2,3,4,6,7,8

- Hexachlorodibenzofuran; 7F 1234678 = 1,2,3,4,6,7,8

- Heptachlorodibenzofuran; 7F 1234789 = 1,2,3,4,7,8,9

- Heptachlorodibenzofuran; 8F = Octachlorodibenzofuran.

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-18 4. 5.2 Default Emissions Factors for Boilers Table 4-4. Summary of Emissions Factors for Boilers Firing Various Fuels

CAS Number Substance Emissions Factor for Fuel Type a

Natural Gas (lb/MMcf) b,c Natural Gas

(lb/MMBtu) b,c Natural Gas

and Casing Vapor Reco very Gas (lb/MMcf) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMBtu) b,c Fuel Oil

(lb/Mgal) b Fuel Oil

(lb/MMBtu) b Distillate

Oil (lb/MMBtu) g Refinery

Fuel Gas (lb/MMcf) b,d Refinery

Fuel Gas (lb/MMBtu) b,d
83

- 32

- 9 Acenaphthene < 1.8E

- 06 e

-- 1.0E

- 06 1. 1E

- 09 2.1E

- 05 f 6.0E

- 09

-- 5.9E

- 06 4.9E

- 09 208

- 96

- 8 Acenaphthylene < 1.8E

- 06 e

-- 2.7E

- 06 2.7E

- 09 2.5E

- 07 f 2.1E - 09

-- 2.6E - 06 2.1E

- 09 75

- 07

- 0 Acetaldehyde 1.6E

- 02 1.7E

- 05 1.1E

- 02 1.9E

- 05 1.0E

- 03 7.0E

- 06

-- 4.0E

- 03 3.0E

- 06 107

- 02

- 8 Acrolein 1.8E

- 02 2.0E

- 05 1.1E

- 02 1.7E

- 05 2.2E - 03 1.5E

- 05

-- -- -- 120

- 12

- 7 Anthracene < 2.4E

- 06 e

-- 2.1E

- 06 2.2E

- 09 1.2E

- 06 f 2.1E

- 09

-- 2.3E

- 05 1.9E

- 08 7440

- 36

- 0 Antimony

-- -- -- -- 5.3E

- 03 f

-- -- -- -- 7440

- 38

- 2 Arsenic 2.0E

- 04 e

-- -- -- 1.3E

- 03 f 9.8E

- 06 4E

- 06 7.0E

- 04 5. 9E

- 07 7440

- 39

- 3 Barium 4.4E

- 03 e

-- -- -- 2.6E

- 06 f

-- -- -- -- 71

- 43

- 2 Benzene 2.1E

- 03 e 3.9E - 06 3.3E

- 03 4.5E

- 06 2.1E

- 04f 3.2E - 05

-- 2.1E

- 01 1.7E

- 04 56

- 55

- 3 Benzo(a)anthracene < 1.8E

- 06 e

-- 1.2E

- 06 1.3E

- 09 4.0E

- 06 f 1.3E - 09

-- 1.8E

- 05 1.5E

- 08 50

- 32

- 8 Be nzo(a)pyrene < 1.2E

- 06 e

-- 6.9E

- 07 7.1E

- 10 2.1E - 07 1.4E

- 09

-- 3.4E

- 06 2.9E

- 09 205

- 99

- 2 Benzo(b)fluoranthene < 1.8E

- 06 e

-- 2.0E

- 06 2.0E

- 09 1.5E

- 06 f,h 8.1E

- 09

-- 6.8E

- 06 5.7E

- 09 192

- 97

- 2 Benzo(e)pyrene

-- -- -- -- 8.5E - 07 5.8E

- 09

-- -- -- 191

- 24

- 2 Benzo (g,h,i)perylene < 1.2E

- 06 e

-- 9.8E

- 07 1.0E

- 09 2.3E

- 06 f 6.7E - 09

-- 3.9E

- 06 3.2E

- 09 207

- 08

- 9 Benzo(k)fluoranthene < 1.8E

- 06 e

-- 8.2E

- 07 8.4E

- 10 f,h 1.3E - 09

-- 2.7E - 06 2.1E

- 09 7440

- 41

- 7 Beryllium < 1.2E

- 05 e

-- -- -- 2.8E

- 05 f 4.3E

- 07 3E

- 06 1.6E

- 04 1.3E

- 07 106

- 99

- 0 1,3

- Butadiene

-- -- -- -- 6.2E - 03 4.2E

- 05

-- -- -- (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-19

Table 4 - 4
. Summary of Emission s Factors for Boilers Firing Various Fuels (continued)

CAS Number Substance Emissions Factor for Fuel Type a

Natural Gas (lb/MMcf) b,c Natural Gas

(lb/MMBtu) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMcf) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMBtu) b,c Fuel Oil

(lb/Mgal) b Fuel Oil

(lb/MMBtu) b Distillate

Oil (lb/MMBtu) g Refinery

Fuel Gas (lb/MMcf) b,d Refinery

Fuel Gas (lb/MMBtu) b,d
106

- 97

- 8 Butane 2.1E+00 e

-- -- -- -- -- -- -- -- 7440

- 43

- 9 Cadmium 1.1E

- 03 e

-- -- -- 4.0E

- 04 f 5.8E

- 06 3E

- 06 2.4E

- 03 2.0E

- 06 16887

- 00

- 6 Chloride

-- -- -- -- 3.5E

- 01 f

-- -- -- -- 67

- 66

- 3 Chloroform

-- -- -- -- 4.7E - 03 3.4E

- 05

-- -- -- 91

- 58

- 7 2

- Chlorona phthalene

-- -- -- -- 2.3E - 08 1.5E

- 10

-- -- -- 18540

- 29

- 9 Chromium (hexavalent)

-- -- -- -- 2.5E

- 04 f 7.8E - 06

-- 2.6 E

- 03 i 2.0 E

- 06 i
7440

- 47

- 3 Chromium (total) 1.4E

- 03 e

-- -- -- 8.5E

- 04 f 3.3E

- 05 3E

- 06 1.3E

- 02 1.0E

- 05 218

- 01

- 9 Chrysene < 1.8E

- 06 e

-- 1.6E

- 06 1.6E

- 09 2.4E

- 06 f 2.6E

- 08

-- 3.4E

- 06 2.9E

- 09 7440

- 48

- 4 Cobalt 8.4E

- 05 e

-- -- -- 6.0E

- 03 f

-- -- -- -- 7440

- 50

- 8 Copper 8.5E

- 04 e

-- -- -- 1.8E

- 03 f 2.6E

- 05 6E

- 06 6.3E

- 03 5.3E

- 06 53

- 70

- 3 Dibenz(a,h)anthracene < 1.2E

- 06 e

-- 5.3E - 07 5.5E

- 10 1.7E

- 06 f 4.7E

- 09

-- 2.6E - 06 2.1E

- 09 25321

- 22

- 6 Dichlorobenzene 1.2E

- 03 e

-- -- -- -- -- -- -- --
57

- 97

- 6 7,12

- Dimethylbenz(a)

anthracene < 1.6E

- 05 e

-- -- -- -- -- -- -- --
1746

- 01

- 6 Dioxin: 4D 2378 j

-- -- -- -- 6.3E - 10 4.3E

- 12

-- -- -- 40321

- 76

- 4 Dioxin: 5D 12378 j

- - -- -- -- 3.7E - 10 2.5E

- 12

-- -- -- 39227

- 28

- 6 Dioxin: 6D 123478 j

-- -- -- -- 3.7E - 10 2.5E

- 12

-- -- -- 57653

- 85

- 7 Dioxin: 6D 123678 j

-- -- -- -- 3.7E

- 10 2.5E

- 12

-- -- -- 19408

- 74

- 3 Dioxin: 6D 123789 j

-- -- -- -- 3.7E

- 10 2.5E

- 12

-- -- -- (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-20

Table 4 - 4
. Summary of Emission s Factors for Boilers Firing Various Fuels (continued)

CAS Number Substance Emissions Factor for Fuel Type a

Natural Gas (lb/MMcf) b,c Natural Gas

(lb/MMBtu) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMcf) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMBtu) b,c Fuel Oil

(lb/Mgal) b Fuel Oil

(lb/MMBtu) b Distillate

Oil (lb/MMBtu) g Refinery

Fuel Gas (lb/MMcf) b,d Refinery

Fuel Gas (lb/MMBtu) b,d
35 822

- 46

- 9 Dioxin: 7D 1234678 j

-- -- -- -- 3.1E

- 09 2.1E

- 11

-- -- -- 3268

- 87

- 9 Dioxin: 8D j

-- -- -- -- 3.1E

- 09 f 5.1E

- 10

-- -- -- 74

- 84

- 0 Ethane 3.1E+00 e

-- -- -- -- -- -- -- -- 100

- 41

- 4 Ethylbenzene

-- -- 9.2E

- 03 9.6E

- 06 6.4E

- 05 f

-- -- -- -- 206

- 44

- 0 Fluo ranthene 3.0E

- 06 e

-- 3.7E

- 06 3.7E

- 09 4.8E

- 06 f 5.3E

- 08

-- 4.3E

- 05 3.6E

- 08 86

- 73

- 7 Fluorene 2.8E

- 06 e

-- 5.6E

- 06 5.7E

- 09 4.5E

- 06 f 3.1E

- 08

-- 9.8E

- 06 8.2E

- 09 16984

- 48

- 8 Fluoride

-- -- -- -- 3.7E

- 02 f

-- -- -- -- 50

- 00

- 0 Formaldehyde 7.5E

- 02 e 3.1E

- 05 1.6E

- 02 2.5E

- 05 3.3E

- 02 f 4.5E

- 05

-- 1.6E

- 02 1.3E

- 05 51207

- 31

- 9 Furan: 4F 2378 k

-- -- -- -- 8.2E

- 10 5.5E

- 12

-- -- -- 57117

- 41

- 6 Furan: 5F 12378 k

-- -- -- -- 4.6E - 10 3.1E

- 12

-- -- -- 57117

- 31

- 4 Furan: 5F 23478 k

-- -- -- -- 4.6E - 10 3.1E

- 12

-- -- -- 70648

- 26

- 9 Furan: 6F 123478 k

-- -- -- -- 3.6E

- 10 2.5E

- 12

-- -- -- 57117

- 44

- 9 Furan: 6F 123678 k

-- -- -- -- 2.7E

- 10 1.9E

- 12

-- -- -- 72918

- 21

- 9 Furan: 6F 123789 k

-- -- -- -- 3.7E - 10 2.5E

- 12

-- -- -- 60851

- 34

- 5 Furan: 6F 234678 k

-- -- -- -- 5.5E

- 10 3.7E

- 12

-- -- -- 67562

- 39

- 4 Furan: 7F 1234678 k

-- -- -- -- 1.4E

- 09 9.8E

- 12

-- -- -- 55673

- 89

- 7 Furan: 7F 1234789 k

-- -- -- -- 4.6E - 10 3.2E

- 12

-- -- -- 39001

- 02

- 0 Furan: 8F k

-- -- -- -- 7.2E

- 09 4.9E

- 11

-- -- -- 110

- 54

- 3 Hexane 1.8E+00 e

-- -- -- -- -- -- -- -- (continue d)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-21

Table 4 - 4
. Summary of Emission s Factors for Boilers Firing Various Fuels (continued)

CAS Number Substance Emissions Factor for Fuel Type a

Natural Gas (lb/MMcf) b,c Natural Gas

(lb/MMBtu) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMcf) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMBtu) b,c Fuel Oil

(lb/Mgal) b Fuel Oil

(lb/MMBtu) b Distillate

Oil (lb/MMBtu) g Refinery

Fuel Gas (lb/MMcf) b,d Refinery

Fuel Gas (lb/MMBtu) b,d
7783

- 06

- 4 Hydrogen sulfide

-- -- 1.5E

- 01 1.6E

- 04

-- -- -- 2.7E - 01 2.2E

- 04 193

- 39

- 5 Indeno(1,2,3

- cd)pyrene < 1.8E

- 06 e

-- 1.2E

- 06 1.2E

- 09 2.1E

- 06 f 3.1E - 09

-- 2.6E - 06 2.1E

- 09 7439

- 92

- 1 Lead

-- -- -- -- 1.5E

- 03 f 1.1E

- 05 9E

- 06 2.4E

- 03 2.1E

- 06 7439

- 96

- 5 Manganese 3.8E

- 04 e

-- -- -- 3.0E

- 03 f 4.0E

- 05 6E

- 06 2.4E

- 03 2.0E

- 06 7439

- 97

- 6 Mercury 2.6E

- 04 e

-- -- -- 1.1E - 04 f 7.0E

- 08 3E

- 06 3.23E - 04 2.7E

- 07 56

- 49

- 5 3

- Methylchloranthrene < 1.8E

- 06 e

-- -- -- -- -- -- -- -- 91

- 57

- 6 2

- Methylnaphthalene 2.4E

- 05 e

-- -- -- 1.1E

- 05 7.4E

- 08

-- -- -- 7439

- 98

- 7 Molybdenum 1.1E

- 03 e

-- -- -- 7.9E

- 04 f

-- -- -- -- 91

- 20

- 3 Naphthalene 6.1E

- 04 e

-- 2.9E

- 04 2.9E

- 07 1.1E

- 02 f 4.0E

- 07

-- 2.1E

- 04 1.7E

- 07 7440

- 02

- 0 Nickel 2.1E

- 03 e

-- -- -- 8.5E

- 02 f 2.3E

- 03 3E

- 06 5.6E

- 03 4.7E

- 06 10 9

- 66

- 0 Pentane 2.6E

- 00 e

-- -- -- -- -- -- -- -- 198

- 55

- 0 Perylene

-- -- -- -- 1.1E - 07 7.4E

- 10

-- -- -- 85

- 01

- 8 Phenanthrene 1.7E

- 05 e

-- 1.6E

- 05 1.7E

- 08 1.1E

- 05 f 7.4E

- 08

-- 5.6E

- 05 4.7E

- 08 108

- 95

- 2 Phenol

-- -- -- -- -- -- -- 2.2E

- 03 1.8E

- 06 7723

- 14

- 0 Phosphorus

-- -- -- -- 9.5E

- 03 f

-- -- -- -- 74

- 98

- 6 Propane 1.6E+00 e

-- -- -- -- -- -- -- -- 115

- 07

- 1 Propylene 1.1E - 01 1.2E

- 04 1.8E

- 01 2.3E

- 04 2.2E - 02 1.5E

- 04

-- -- -- 129

- 00

- 0 Pyrene 5.0E

- 06 e

-- 6.0E

- 06 6.0E

- 09 4.3E

- 06 f 2.7E

- 08

-- 6.0E

- 05 5.0E

- 08
7 782

- 49

- 2 Selenium < 2.4E

- 05 e

-- -- -- 6.8E

- 04 f 2.0E

- 05 1.5E

- 05 2.1E

- 03 1.7E

- 06 (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

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4-22

Table 4 - 4
. Summary of Emission s Factors for Boilers Firing Various Fuels (continued)

CAS Number Substance Emissions Factor for Fuel Type a

Natural Gas (lb/MMcf) b,c Natural Gas

(lb/MMBtu) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMcf) b,c Natural Gas

and Casing Vapor Recovery Gas (lb/MMBtu) b,c Fuel Oil

(lb/Mgal) b Fuel Oil

(lb/MMBtu) b Distillate

Oil (lb/MMBtu) g Refinery

Fuel Gas (lb/MMcf) b,d Refinery

Fuel Gas (lb/MMBtu) b,d
71

- 55

- 6 1,1,1

- Trichloroethane

-- -- -- -- 2.4E

- 04 f

-- -- -- -- 108

- 88

- 3 Toluene 3.4E

- 03 e 1.2E - 05 1.4E

- 02 1.7E

- 05 6.2E

- 03 f 3.9E - 05

-- 8.4E

- 01 7.2E

- 04 7440

- 62

- 2 Vanadium 2.3E

- 03 e

-- -- -- 3.2E

- 02 f

-- -- -- -- 95

- 47

- 6 Xylene (o)

-- -- -- -- 1.1E

- 04 f

-- -- -- -- 1330

- 20

- 7 Xylene (total) 2.8E - 02 2.8E

- 05 1.9E

- 02 2.7E

- 05 1.1E - 02 7.5E

- 05

-- -- -- 7440

- 66

- 6 Zinc 2.9E

- 02 e

-- -- -- 2.9E

- 02 f 1.1E

- 04 4E

- 06 3.4E+00 2.8E

- 0 3 Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds per million cubic feet, lb/MMBtu = pounds per million British t hermal units
a Bold italic values indicate that all test runs were below detection limit; underlined values indicate that 75% or more of the test runs were below the detection limit. b Source: Hansell and England, 1998, unless otherwise specified.
c The emissions factors were provided specifically for steam generators firing natural gas. d The same emissions factors were provi ded specifically for boilers with no control device and boilers with selective catalytic reduction.
e Source: U.S. EPA, 1995a , Table 1.4

- 3 and Table 1.4

- 4. Emissions factors were provided for natural gas combustion sources. Emissions factors preceded with a less than symbol are based on method detection limits. f Source: U.S. EPA, 1995a , Table 1.3

- 9 and Table 1.3

- 11. Emissions factors were provided specifically for residual oil (mostly No. 6) fired boilers. For boilers firing other fuel oils, the emission s factors presented in Appendix D may be applicable. g Source: U.S. EPA, 1995a , Table 1.3

- 10. Emissions factors were provided specifically for distillate oil

- fired boilers. h Emission factor includes both benzo(b)fluoranthene and benzo(k)fluoranthene. i Hexavalent chromium was not detected. The reported emissions factors based on detection limits are expected to overstate hexa valent chromium emissions. Twenty percent of the total chromium emissions factor is assumed for the hexavalent chromium emissions factor. (The hexavalent chromium emissions factors for turbines is between 10 and 15 percent of the total chromium emissions factor , and the hexavalent chromium emissions factor for boilers firing fuel oil is about 30 percent of the total chromium emission s factor , so 20 percent is a conservative approximation for hexavalent chromium emissions from refinery fuel gas.) j 4D 2378 = 2,3,7,8

- Tetrachlorodibenzo

- p - dioxin; 5D 12378 = 1,2,3,7,8

- Pentachlorodibenzo

- p - dioxin; 6D 123478 = 1,2,3,4,7,8

- Hexachlorodibenzo

- p - dioxin; 6D 123678 = 1,2,3,6,7,8

- Hexachlorodibenzo

- p - dioxin; 6D 123789 = 1,2,3,7,8,9

- Hexachlorodibenzo

- p - dioxin; 7D 1234678 = 1,2,3,4,6,7,8

- Heptachlorodibenzo

- p - dioxin; 8D = Octachlorodibenzo

- p - dioxin. k 4F 2378 = 2,3,7,8

- Tetrachlorodibenzofuran; 5F 123 78 = 1,2,3,7,8

- Pentachlorodibenzofuran; 5F 23478 = 2,3,4,7,8

- Pentachlorodibenzofuran; 6F 123478 = 1,2,3,4,7,8

- Hexachlorodibenzofuran; 6F 123678 = 1,2,3,6,7,8

- Hexachlorodibenzofuran; 6F 123789 = 1,2,3,7,8,9

- Hexachlorodibenzofuran; 6F 234678 = 2,3,4,6,7,8

- He xachlorodibenzofuran; 7F 1234678 = 1,2,3,4,6,7,8

- Heptachlorodibenzofuran; 7F 1234789 = 1,2,3,4,7,8,9

- Heptachlorodibenzofuran; 8F = Octachlorodibenzofuran

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

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4-23 4.5.3 Default Emissions Factor for Internal Combustion Engines The emissions from reciprocating in ternal combustion engines were dependent on: (1) the type of fuel used (diesel fuel, field gas [associated gases at production fields; use field gas factors for refinery fuelgas], or natural gas), (2) the type of engine used (two-stroke versus four-stroke engines), and (3) the fuelto -air ratio. As shown in Tables 4-5 and 4-6 , high air rates (or lean fuel mixtures) tend to have higher emissions of acetaldehyde and formaldehyde, whereas lean gas mixtures tend to have higher emissions of benzene, toluene, and xylenes. Tables 4-7 and 4-8 present emission factors for turbines.

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-24 Table 4-5. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuels a

CAS Number Substance Emission s Factor for Engine and Fuel Type b

Diesel, O 2 < 13% (lb/Mga l) Diesel,

O 2 > 13% (lb/Mgal) Field Gas,

Lean (2 - S troke) (lb/MMcf) Field Gas,

Lean ( 4 - S troke) (lb/MMcf) Field Gas,

Rich ( 4 - S troke) (lb/MMcf) Natural Gas,

Lean ( 4 - S troke) (lb/MMcf) Natural Gas,

Rich ( 4 - S troke) (lb/MMcf) 83

- 32

- 9 Acenaphthene 6.4E

- 04 2

. 0 E

- 0 4 7.4E - 04

-- -- 7. 2 E

- 04

-- 208

- 96

- 8 Acenaphthylene 1. 3 E

- 03 7.0E

- 04 1.1E

- 02

-- -- 7. 6 E

- 03

-- 75

- 07

- 0 Acetaldehyde 3. 5 E

- 03 1. 1 E

- 01 8. 8 E+00

-- -- 4

. 0 E+00 1.7E+00 107

- 02

- 8 Acrolein 1. 1 E

- 03 1.3E

- 02 2.0E+00

-- -- 1.6E+00 5.4E

- 01 120

- 12

- 7 Anthracene 1.7E

- 0 4 2.6E

- 04 4.5E

- 03

-- -- 2.6E

- 04

-- 100

- 52

- 7 Benzaldehyde

-- 1. 3 E

- 02

-- -- -- -- -- 71

- 43

- 2 Benzene 1.0E

- 01 1.2E

- 01 7. 7 E+00 1.7E+00 1.1E+01 1.2E+00 9. 9 E+00 56

- 55

- 3 Benzo(a)anthracene 8.7E

- 05 2.3E

- 04 9

. 0 E

- 04

-- -- 7.8E

- 05

-- 50

- 32

- 8 Benzo(a)pyrene 3.5 E

- 05 2.6E - 05 8. 8 E

- 04

-- -- 3. 6 E

- 05

-- 205

- 99

- 2 Benzo(b)fluoranthene 1.5E

- 04 2. 6 E

- 05 1. 5 E - 04

-- -- 3. 3 E

- 04

-- 191

- 24

- 2 Benzo(g,h,i)perylene 7. 7 E

- 05 6.8E

- 05 9.4E - 05

-- -- 1.0E

- 04

-- 207

- 08

- 9 Benzo(k)fluoranthene 3.0E

- 05 4.1E

- 05 4. 6 E

- 03

-- -- 5.3E

- 04

-- 106

- 99

- 0 1,3

- Butadiene

-- 5.4E - 03

-- -- -- -- -- 218

- 01

- 9 Chrysene 2.1E

- 04 4.9E

- 05 1. 7 E

- 03

-- -- 9.6E

- 05

-- 53

- 70

- 3 Dibenz(a,h)anthracene 4. 8 E - 05 8.1E

- 05 7.7E - 05

-- -- 1. 1 E

- 05

-- 206

- 44

- 0 Fluoranthene 5.6E

- 04 1. 1 E

- 03 1. 7 E - 04

-- -- 2.5E

- 04

-- 86

- 73

- 7 Fluorene 1. 8 E

- 03 4. 1 E

- 03 2.4E - 03

-- -- 4.6E - 04

-- 50

- 00

- 0 Formaldehyde 1. 1 E

- 02 1. 7 E

- 01 5. 1 E+01 4. 2 E+01 5. 1 E+00 2. 9 E+01 5.3E+00 (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-25 Table 4 - 5
. Summary of Emission s Factors for Internal Combustion Engines Firing Various Fuels a 

### (continued)

CAS Number Substance Emission s Factor for Engine and Fuel Type b

Diesel, O 2 < 13% (lb/Mgal) Diesel,

O 2 > 13% (lb/Mgal) Field Gas,

Lean (2 - S troke) (lb/MMcf) Field Gas,

Lean ( 4 - S troke) (lb/MMcf) Field Gas,

Rich ( 4 - S troke) (lb/MMcf) Natural Gas,

Lean ( 4 - S tr oke) (lb/MMcf) Natural Gas,

Rich ( 4 - S troke) (lb/MMcf) 193

- 39

- 5 Indeno(1 ,2,3

- cd) pyrene 5. 7 E

- 05 6.4E

- 05 1. 4 E - 04

-- -- 1.2E

- 04

-- 91

- 20

- 3 Naphthalene 1.8E

- 02 1. 2 E

- 02 2. 2 E

- 01

-- -- 1.2E

- 01

-- 85

- 01

- 8 Phenanthrene 5.6E

- 03 4. 1 E

- 03 4.9E

- 03

-- -- 8.9E

- 04

-- 115

- 07

- 1 Propylene 3. 9 E

- 01 3. 6 E

- 01 2. 5 E+01 1. 6 E+01 3.0E+00 1. 9 E+01 4

. 0 E+01 129

- 00

- 0 Pyrene 5.1E

- 04 6. 7 E

- 04 2. 4 E

- 04

-- -- 1.2E

- 04

-- 108

- 88

- 3 Toluene 3.7E

- 02 5.5E

- 02 2. 9 E+00 7. 7 E

- 01 3.4E+00 4.1E

- 01 2.5E+00 108

- 38

- 3 , 106

- 42

- 3 Xylene (m,p)

-- 2. 2 E

- 02 6 .0E

- 01 3.0E

- 01 5. 4 E

- 01 8.6E

- 02 4.4E

- 01

95

- 47

- 6 Xylene (o)

-- 2. 1 E - 02 2. 9 E

- 01 9

. 0 E

- 02 2. 7 E

- 01 4.9E

- 02 2. 2 E

- 01 1330

- 20

- 7 Xylene (total) 2. 7 E

- 02 3. 6 E

- 02

-- -- -- -- -- Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds per million cubic feet
a Source: Hansell and England , 1998. b Bold italic v alues indicate that all test runs were below detection limit

.

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-26 Table 4-6. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuels a

CAS Number Substance Emissions Factor for En gine and Fuel Type b

Diesel, O 2 < 13% (lb/MMBtu) Diesel,

O 2 > 13% (lb/MMBtu) Diesel,

O 2 not specified (lb/MMBtu) c Field Gas,

Lean (2 - Stroke) (lb/MMBtu) Natural

Gas, Lean (2 - Stroke) (lb/MMBtu) d Field Gas,

Lean (4 - Stroke) (lb/MMBtu) Field Gas,

Rich (4 - Stro ke) (lb/MMBtu) Natural

Gas, Lean (4 - Stroke) (lb/MMBtu) e Natural

Gas, Rich (4 - Stroke) (lb/MMBtu)
83

- 32

- 9 Acenaphthene 4.5E

- 06 1.4E

- 06 < 1.4E

- 06 f 7.1E - 07 1.3E

- 06 g

-- -- 1.3E

- 06 h i
208

- 96

- 8 Acenaphthylene 9.0E

- 06 5.1E

- 06 < 5.1E

- 06 f 1.1E

- 05 3.2E

- 06 g

-- -- 5.5E

- 06 h i
75

- 07

- 0 Acetaldehyde 2.4E

- 05 7.6E

- 04 7.7E

- 04 8.4E

- 03 7.8E

- 03

-- -- 8.4E

- 03 2.8E

- 03 j
107

- 02

- 8 Acrolein 7.6E

- 06 9.4E

- 05 < 9.3E

- 05 1.9E

- 03 7.8E

- 03

-- -- 5.1E

- 03 2.6E

- 03 j
120

- 12

- 7 Anthracene 1.2E

- 06 1.9E

- 06 1.9E

- 06 f 4.3E

- 06 7.2E

- 07 g

-- -- 2.4E

- 07 a, h i
100

- 52

- 7 Benzaldehyde

-- 9.0E

- 05

-- -- -- -- -- -- -- 71

- 43

- 2 Benzene 7.1E

- 04 8.8E

- 04 9.3E

- 04 7.5E

- 03 1.9E

- 03 1.64E

- 03 1.05E

- 02 4.4E

- 04 1.6E

- 03 j
56

- 55

- 3 Benzo(a)anthracene 6.1E

- 07 1.7E

- 06 1.7E

- 06 f 8.5E

- 07 3.4E

- 07 g

-- -- 7.4E

- 08 a, h i
50

- 32

- 8 B enzo(a)pyrene 2.5E

- 07 1.9E - 07 < 1.9E

- 07 f 8.3E - 07 5.7E

- 09 g

-- -- 3.4E

- 08 a, h i
205

- 99

- 2 Benzo(b)fluoranthene 1.1E

- 06 1.9E

- 07 < 9.9E

- 08 f 1.4E - 07 8.5E

- 09 g

-- -- 1.7E

- 07 h i
192

- 97

- 2 Benzo(e)pyrene

-- -- -- -- 2.3E

- 08 g

-- -- 4.2E

- 07 h i
191

- 24

- 2 Benzo(g,h,i) perylene 5.4E

- 07 4.9E

- 07 < 4

. 9 E

- 07 f 9.0E - 08 2.5E

- 08 g

-- -- 4.1E

- 07 h i
207

- 08

- 9 Benzo(k)fluoranthene 2.1E

- 07 3.0E

- 07 < 1.6E

- 07 f 4.4E

- 06 4.3E

- 09 g

-- -- 5.0E

- 07 a, h i
92

- 52

- 4 Biphenyl

-- -- -- -- 4.0E

- 06

-- -- 2.1E

- 04

-- 106

- 99

- 0 1,3

- Butadiene

-- 3.9E - 05 < 3.9E

- 05

-- 8.2E

- 04

-- -- 2.7E

- 04 6.6E

- 04 j
106

- 97

- 8 Butane

-- -- -- -- 4.8E

- 03

-- -- 5.4E

- 04

--

Butyr/Isobutyraldehyde

-- -- -- -- 4.8E

- 04

-- -- 1.0E

- 04 4.9E

- 05 j
56

- 23

- 5 Carbon tetrachloride

-- -- -- -- 6.1E

- 05

-- -- < 3.7E

- 05 < 1.8E

- 05 j
108

- 90

- 7 Ch lorobenzene

-- -- -- -- 4.4E

- 05

-- -- < 3.0E

- 05 < 1.3E

- 05 j (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-27 Table 4 - 6
. Summary of Emission s Factors for Internal Combustion Engines Firing Various Fuels a 

### (continued)

CAS Number Substance Emissions Factor for Engine and Fuel Type b

Diesel, O 2 < 13% (lb/MMBtu) Diesel,

O 2 > 13% (lb/MMBtu) Diesel,

O 2 not specified (lb/MMBtu) c Field Gas,

Lean (2 - Stroke) (lb/MMBtu) Natural

Gas, Lean (2 - Stroke) (lb/MMBtu) d Field Gas,

Lean (4 - Stroke) (lb/MMBtu) Field Gas,

Rich (4 - Stroke) (lb/MMBtu) Natural

Gas, Le an (4 - Stroke) (lb/MMBtu) e Natural

Gas, Rich (4 - Stroke) (lb/MMBtu)
75

- 00

- 3 Chloroethane

-- -- -- -- -- -- -- 1.9E

- 06

-- 67

- 66

- 3 Chloroform

-- -- -- -- 4.7E

- 05

-- -- < 2.9E

- 05 < 1.4E

- 05 j
218

- 01

- 9 Chrysene 1.5E

- 06 3.5E

- 07 3.5E

- 07 f 1.6E

- 06 6.7E

- 07 g

-- -- 6 .9E

- 07 h i
110

- 82

- 7 Cyclohexane

-- -- -- -- 3.1E

- 04

-- -- -- -- 287

- 92

- 3 Cyclopentane

-- -- -- -- 9.5E

- 05

-- -- 2.3E

- 04

-- 53

- 70

- 3 Dibenz(a,h)anthracene 3.5E - 07 5.8E

- 07 < 5 .8E

- 07 f 7.3E - 08 g

-- -- 1.0E

- 08 a, h i
75

- 34

- 3 1,1

- Dichloroethane

-- -- -- -- 3.9E

- 05

-- -- < 2.4E

- 05 < 1.1E

- 05 j
107

- 06

- 2 1,2

- Dichloroethane

-- -- -- -- 4.2E

- 05

-- -- < 2.4E

- 05 < 1.1E

- 05 j
78

- 87

- 5 1,2

- Dichloropropane

-- -- -- -- 4.5E

- 05

-- -- -- < 1.3E

- 05 j
542

- 75

- 6 1,3

- Dichloropropene

-- -- -- -- 4.4E

- 05

-- -- < 2.6E

- 05 < 1.3E

- 05 j
74

- 84

- 0 Ethane

-- -- -- -- 7.1E

- 02

-- -- 1.1E

- 01 7.0E

- 02 j
100

- 41

- 4 Ethylbenzene

-- -- -- -- 1.1E

- 04

-- -- 4.0E

- 05 < 2.5E

- 05 j
106

- 93

- 4 Ethylene dibromide

-- -- -- -- 7.3E

- 05

-- -- < 4.4E

- 05 < 2.1E

- 05 j
206

- 44

- 0 Fluoranthene 3.9E

- 06 7.6E

- 06 7.6E

- 06 f 1.6E - 07 3.6E

- 07 g

-- -- 1.1E

- 06 h i
86

- 73

- 7 Fluorene 1.3E

- 05 2.9E

- 05 2.9E

- 05 f 2.3E - 06 4.7E

- 06 g

-- -- 5.7E

- 06 h i
50

- 00

- 0 Formaldehyde 7.7E

- 05 1.2E

- 03 1.2E

- 03 4.9E

- 02 5.5E

- 02 3.95E

- 02 4.81E

- 03 5.3E

- 02 2.1E

- 02 j
110

- 54

- 3 n - Hexane

-- -- -- -- 4.5E

- 04

-- -- 1.1E

- 03

-- 193

- 39

- 5 Indeno(1,2,3

- cd)pyrene 4.0E

- 07 4.6E

- 07 < 3.8E

- 07 f 1.3E - 07 9.9E

- 09 g

-- -- 1.1E

- 07 a, h i
75

- 28

- 5 Isobutane

-- -- -- -- 3.8E

- 03

-- -- -- -- (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

Review Draft

–

Do not cite or quote

4-28 Table 4 - 6
. Summary of Emission s Factors for Internal Combustion Engines Firing Various Fuels a 

### (continued)

CAS Number Substance Emissions Factor for Engine and Fuel Type b

Diesel, O 2 < 13% (lb/MMBtu) Diesel,

O 2 > 13% (lb/MMBtu) Diesel,

O 2 not specified (lb/MMBtu) c Field Gas,

Lean (2 - Stroke) (lb/MMBtu) Natural

Gas, Lean (2 - Stroke) (lb/MMBtu) d Field Gas,

Lean (4 - Stroke) (lb/MMBtu) Field Gas,

Rich (4 - Stroke) (lb/MMBtu) Natural

Gas, Le an (4 - Stroke) (lb/MMBtu) e Natural

Gas, Rich (4 - Stroke) (lb/MMBtu)
67

- 56

- 1 Methanol

-- -- -- -- 2.5E

- 03

-- -- 2.5E

- 03 3.1E

- 03 j
108

- 87

- 2 Methylcyclohexane

-- -- -- -- 3.4E

- 04

-- -- 1.2E

- 03

-- 75

- 09

- 2 Methylene chloride

-- -- -- -- 1.5E

- 04

-- -- 2.0E

- 05 4.1E

- 05 j
91

- 57

- 6 2

- Methylnaphthalene

-- -- -- -- 2.1E

- 05 g

-- -- 3.3E

- 05 h i
91

- 20

- 3 Naphthalene 1.3E

- 04 8.5E

- 05 8.5E

- 05 f 2.1E

- 04 9.6E

- 05 g

-- -- 7.4E

- 05 h < 9.7 E

- 05 I,j
111

- 84

- 2 n - Nonane

-- -- -- -- 3.1E

- 05

-- -- 1.1E

- 04

-- 111

- 65

- 9 n - Octane

-- -- -- -- 7.4E

- 05

-- -- 3.5E

- 04

-- 109

- 66

- 0 n - Pentane

-- -- -- -- 1.5E

- 03

-- -- 2.6E

- 03

-- 198

- 55

- 0 Perylene

-- -- -- -- 5.0E

- 09 g

-- -- h i
85

- 01

- 8 Phenanthrene 4.0E

- 0 5 2.9E

- 05 2.9E

- 05 f 4.7E

- 06 3.5E

- 06 g

-- -- 1.0E

- 05 h i
108

- 95

- 2 Phenol

-- -- -- -- 4.2E

- 05

-- -- 2.4E

- 05

-- 74

- 98

- 6 Propane

-- -- -- -- 2.9E

- 02

-- -- 4.2E

- 02

-- 115

- 07

- 1 Propylene 2.7E

- 03 2.6E

- 03 2.6E

- 03 2.4E

- 02

-- 1.5E

- 02 2.9E - 03 1.8E

- 02 a 3.8E

- 02 129

- 0 0

- 0 Pyrene 3.6E

- 06 4.8E

- 06 4.8E

- 06 f 2.3E

- 07 5.8E

- 07 g

-- -- 1.4E

- 06 h i
100

- 42

- 5 Styrene

-- -- -- -- 5.5E

- 05

-- -- < 2.4E

- 05 < 1.2E

- 05 j
79

- 34

- 5 1,1,2,2

- Tetrachloroethane

-- -- -- -- 6.6E

- 05

-- -- < 4.0E

- 05 2.5E

- 05 j
108

- 88

- 3 Toluene 2.6E

- 04 4.0E

- 04 4.1E

- 04 2.7E

- 03 9.6E

- 04 7.3E

- 04 3.3E

- 03 4.1E

- 04 5.6E

- 04 j
79

- 00

- 5 1,1,2

- Trichloroethane

-- -- -- -- 5.3E

- 05

-- -- < 3.2E

- 05 < 1.5E

- 05 j
526

- 73

- 8 1,2,3

- Trimethylbenzene

-- -- -- -- 3.5E

- 05

-- -- 2.3E

- 05 (continued)

### Version 1.0 Section 4

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4-29 Table 4 - 6
. Summary of Emission s Factors for Internal Combustion Engines Firing Various Fuels a 

### (continued)

CAS Number Substance Emissions Factor for Engine and Fuel Type b

Diesel, O 2 < 13% (lb/MMBtu) Diesel,

O 2 > 13% (lb/MMBtu) Diesel,

O 2 not specified (lb/MMBtu) c Field Gas,

Lean (2 - Stroke) (lb/MMBtu) Natural

Gas, Lean (2 - Stroke) (lb/MMBtu) d Field Gas,

Lean (4 - Stroke) (lb/MMBtu) Field Gas,

Rich (4 - Stroke) (lb/MMBtu) Natural

Gas, Le an (4 - Stroke) (lb/MMBtu) e Natural

Gas, Rich (4 - Stroke) (lb/MMBtu)
95

- 63

- 6 1,2,4

- Trimethylbenzene

-- -- -- -- 1.1E

- 04

-- -- 1.4E

- 05

-- 108

- 67

- 8 1,3,5

- Trimethylbenzene

-- -- -- -- 1.8E

- 05

-- -- 3.4E

- 05

-- 540

- 84

- 1 2,2,4

- Trimethylpentane

-- -- -- -- 8.5E

- 04

-- -- 2.5E

- 04

-- 75

- 01

- 4 Vinyl chloride

-- -- -- -- 2.5E

- 05

-- -- 1.5E

- 05 < 7.2E

- 06 j
108

- 38

- 3 , 106

- 42

- 3 Xy lene (m,p)

-- 1.5E

- 04

-- 5.8E

- 04

-- 2.9E

- 04 5.1E

- 04 8.2E

- 05 a 4.2E

- 04

95

- 47

- 6 Xylene (o)

-- 1.5E - 04

-- 2.7E

- 04

-- 8.6E

- 05 2.6E

- 04 4.7E

- 05 a 2.1E

- 04 1330

- 20

- 7 Xylene (total) 1.9E

- 04 2.6E

- 04 2.9E

- 04

-- 2.7E

- 04

-- -- 1.8E

- 04 2.0E

- 04 j Note: lb/MMBtu = pounds per million British thermal units
a Source: Hansell and England, 1998, unless otherwise specified. b Bold italic values indicate that all test runs were below detection limit.
c Source: U.S. EPA, 1995a , Table 3.3

- 2. Emissions factors are for uncontroll ed sources. Emissions factors preceded with a less than symbol are based on method detection limits. d Source: U.S. EPA, 1995a , Table 3.2

- 1. Emissions factors are for uncontrolled sources.
e Source: U.S. EPA, 1995a , Table 3.2

- 2. Emissions factors are for uncontrolled sources. Emissions factors preceded with a less than symbol are based on method detection limits. f The emissions factor for total polycyclic aromatic hydrocarbons (PAH) in U.S. EPA, 1995a , Table 3.3

- 2 is 1.7E

- 04 lb/MMBtu. g The emissions f actor for total PAH in U.S. EPA, 1995a , Table 3.2

- 1 is 1.3E

- 04 lb/MMBtu. h The emissions factor for total PAH in U.S. EPA, 1995a , Table 3.2

- 2 is 2.7E

- 05 lb/MMBtu. i The emissions factor for total PAH in U.S. EPA, 1995a , Table 3.2

- 3 is 1.4E

- 04 lb/MMBtu. j Source: U.S. EPA, 1995a , Table 3.2

- 3. Emissions factors are for uncontrolled sources. Emissions factors preceded with a less than symbol are based on method detection limits

.

### Version 1.0 Section 4

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4-30 4.5.4 Default Emissions Factor for Turbines Table 4-7. Summary of Emissions Factors for Turbines Firing Various Fuels a

CAS Number Substance Emission s Factor for Turbine and Fuel Type b

Natural Gas, No Duct Burners (lb/MMcf) c Natural Gas, Duct

Burners (lb/MM cf ) d Natural Gas and Refinery Fuel Gas , Duct Burners (lb/MM cf ) e Natural Gas,

Refinery Fuel Gas, and Liquefied Petroleum Gas ; Duct Burners (lb/MMcf) e Refinery Fuel Gas,

No Duct Burners (lb/ MMcf) f
83

- 32

- 9 Acenaphthene 3. 4 E

- 06

-- 2. 4 E

- 05

-- -- 208

- 96

- 8 Acenaphthylene 3.0E

- 06

-- 1. 2 E

- 05

-- -- 75

- 07

- 0 Acetaldehyde 4.0 E

- 02

- - 4.5E

- 03

-- 2. 2 E

- 02 107

- 02

- 8 Acrolein 1.8E - 02

-- -- -- -- 120

- 12

- 7 Anthracene 3.5E

- 05

-- 2. 7 E

- 05

-- -- 7440

- 38

- 2 Arsenic

-- -- -- 1.7E - 02 4.1E - 03 71

- 43

- 2 Benzene 1.2E - 02

-- 1.7E - 01

-- 1.5E - 01 56

- 55

- 3 Benzo(a)anthracene 2. 9E

- 06

-- 1.6E

- 05

-- -- 50

- 32

- 8 Benzo(a)pyrene 2.1E - 06

-- 1.0E - 05

-- -- 205

- 99

- 2 Benzo(b)fluoranthene 3.4 E

- 06

-- 2. 7 E

- 05

-- -- 191

- 24

- 2 Benzo(g,h,i)perylene 2.5E

- 06

-- 2.1E - 05

-- -- 207

- 08

- 9 Benzo(k)fluoranthene 2. 7E

- 06

-- 1.3E - 05

-- -- 7440

- 41

- 7 Beryllium

-- -- -- 3.4E - 03 2.1E - 03 7440

- 43

- 9 Cadmium

-- -- 2. 1 E

- 03 7.4E

- 03 7.4E

- 03 18540

- 29

- 9 Chromium (hex avalent )

-- -- 7.5E - 03

-- 2.0E - 03 (continued)

### Version 1.0 Section 4

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4-31

Table 4 - 7
. Summary of Emission s Factors for Turbines Firing Various Fuels a 

### (continued)

CAS Number Substance Emission s Fact or for Turbine and Fuel Type b

Natural Gas, No Duct Burners (lb/MMcf) c Natural Gas, Duct

Burners (lb/MM cf ) d Natural Gas and Refinery Fuel Gas , Duct Burners (lb/MM cf ) e Natural Gas,

Refinery Fuel Gas, and Liquefied Petroleum Gas ; Duct Burners (lb/MMcf) e Re finery Fuel Gas,

No Duct Burners (lb/ MMcf) f
7440

- 47

- 3 Chromium (total)

-- -- 5. 4 E

- 02

-- 1.8E

- 02 218

- 01

- 9 Chrysene 5. 1 E

- 06

-- 1. 2 E

- 04

-- -- 7440

- 50

- 8 Copper

-- -- 1.9E

- 03 4.1E

- 02 5. 8E

- 02 53

- 70

- 3 Dibenz(a,h)anthracene 2.1E - 06

-- 7.1E - 06

-- -- 100

- 41

- 4 Ethylbenzene 1.5E - 02

-- -- -- -- 206

- 44

- 0 Fluoranthene 1.2 E

- 05

-- 1. 1 E

- 04

-- -- 86

- 73

- 7 Fluorene 1. 6 E

- 05

-- 1.9E

- 04

-- -- 50

- 00

- 0 Formaldehyde 2. 1 E

- 02 6.2E+00 1.7E

- 01

-- 8.4E

- 01 7783

- 06

- 4 Hydrogen s ulfid e -- -- 1.7E - 01

-- 1.6E - 01 193

- 39

- 5 Indeno (1,2,3

- cd)pyrene 2.4E

- 06

-- 9.8E - 06

-- -- 7439

- 92

- 1 Lead

-- -- -- 6.8E - 02 4

. 0 E

- 02 7439

- 96

- 5 Manganese

-- -- 3. 5 E

- 03 1.8E

- 01 1.8E

- 01 7439

- 97

- 6 Mercury

-- -- 4.6E

- 03

-- 2. 2 E

- 02 91

- 20

- 3 Naphthalene 7.5E

- 04

-- 4.0E

- 02

-- -- 7440

- 02

- 0 Nickel

-- -- 8. 2 E

- 03 2.8E

- 01 2.3 E

- 01 85

- 01

- 8 Phenanthrene 6.7 E

- 05

-- 6. 9 E

- 04

-- -- 108

- 95

- 2 Phenol

-- -- 1.5E - 02 5.8E

- 02 9.4 E

- 03 (continued)

### Version 1.0 Section 4

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4-32

Table 4 - 7
. Summary of Emission s Factors for Turbines Firing Various Fuels a 

### (continued)

CAS Number Substance Emission s Fact or for Turbine and Fuel Type b

Natural Gas, No Duct Burners (lb/MMcf) c Natural Gas, Duct

Burners (lb/MM cf ) d Natural Gas and Refinery Fuel Gas , Duct Burners (lb/MM cf ) e Natural Gas,

Refinery Fuel Gas, and Liquefied Petroleum Gas ; Duct Burners (lb/MMcf) e Re finery Fuel Gas,

No Duct Burners (lb/ MMcf) f
115

- 07

- 1 Propylene 1.7 E+00

-- -- -- -- 129

- 00

- 0 Pyrene 2.3E

- 05

-- 1. 3 E

- 04

-- -- 7782

- 49

- 2 Selenium

-- -- -- 1.7E - 02 5.4E - 03 108

- 88

- 3 Toluene 7. 2 E

- 02

-- 1.8E - 01

-- 1. 1 E+00 1330

- 20

- 7 Xylene (total) 3.6E

- 02

-- 4.1E - 01

-- 3.1E+00 7440

- 66

- 6 Zinc

-- -- 1. 7 E

- 02 4.1E

- 01 7

. 0 E+00 Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds per million cubic feet
a Source: Hanse ll and England , 1998. b Bold italic v alues indicate that all test runs were below detection limit

. c The same emissions factors were provided specifically for turbines with no control device and turbines with selective catalyt ic reduction and c arbon m ono xide o xidation c atalyst

. d The emissions factors were provided specifically for turbines with selective catalytic reduction

. e The emissions factors were provided specifically for turbines with selective catalytic reduction and c arbon m onoxide o xidation c atalyst

. f The emissions factors were provided specifically for turbines with c arbon m onoxide o xidation c atalyst

.

### Version 1.0 Section 4

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4-33

Table 4-8. Summary of Emissions Factors for Turbines Firing Various Fuels a

CAS Number Substance Emissions Factor for Turbine and Fuel Typ e a

Distillate Oil (lb/MM Btu ) c Natural Gas,

No Duct Burners (lb/MM Btu ) d Natural Gas,

Duct Burners (lb/MM Btu ) e Natural Gas,

Type not specified (lb/MM Btu ) f Natural Gas

and Refinery Fuel Gas , Duct Burners (lb/MM Btu ) g Natural Gas,

Refinery Fuel Gas, and Liqu efied Petroleum Gas ; Duct Burners (lb/MM Btu ) g Refinery Fuel

Gas, No Duct Burners (lb/MM Btu ) h
83

- 32

- 9 Acenaphthene i 3. 3 E

- 09

-- j 2.2E

- 08

-- -- 208

- 96

- 8 Acenaphthylene i 2.9 E

- 09

-- j 1. 1 E

- 08

-- -- 75

- 07

- 0 Acetaldehyde

-- 3. 8E

- 05

-- 4.0E

- 05 4.1E

- 06

-- 1.6E

- 05 107

- 02

- 8 Acrolein

-- 1.7E - 05

-- 6.4E

- 06

-- -- -- 120

- 12

- 7 Anthracene i 3.4E

- 08

-- j 2. 5 E

- 08

-- -- 7440

- 38

- 2 Arsenic < 1.1E

- 05

-- -- -- -- 9.0E - 06 2.9E

- 06 71

- 43

- 2 Benzene 5.5E

- 05 1.2E - 05

-- 1.2E

- 05 1.5E - 04

-- 1.1E - 04 56

- 55

- 3 Benzo(a)anthracen e i 2.8E

- 09

-- j 1. 5 E

- 08

-- -- 50

- 32

- 8 Benzo(a)pyrene i 2.1E - 09

-- j 9.5E - 09

-- -- 205

- 99

- 2 Benzo(b)fluoranthene i 3.3E

- 09

-- j 2.5E

- 08

-- -- 191

- 24

- 2 Benzo(g,h,i)perylene i 2.4E

- 09

-- j 1.9E - 08

-- -- 207

- 08

- 9 Benzo(k)fluoranthene i 2. 6 E

- 09

-- j 1 .3E - 08

-- -- 7440

- 41

- 7 Beryllium < 3.1E

- 07

-- -- -- -- 1.8E - 06 1.5E

- 06 106

- 99

- 0 1,3

- Butadiene < 1.6E

- 05

-- -- < 4.3E

- 07

-- -- -- 7440

- 43

- 9 Cadmium 4.8E

- 06

-- -- -- 1.9E

- 06 3.9E

- 06 5. 3 E

- 06 18540

- 29

- 9 Chromium (hex avalent )

-- -- -- -- 7.0E - 06

-- 1.5E - 06 (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

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4-34

Table 4 - 8
. Summary of Emission s Factors for Turbines Firing Various Fuels a 

### (continued)

CAS Number Substance Emissions Factor for Turbine and Fuel Type a

Distillate Oil (lb/MM Btu ) c Natural Gas,

No Duct Burners (lb/MM Btu ) d Natural Gas,

Du ct Burners (lb/MM Btu ) e Natural Gas,

Type not specified (lb/MM Btu ) f Natural Gas

and Refinery Fuel Gas , Duct Burners (lb/MM Btu ) g Natural Gas,

Refinery Fuel Gas, and Liquefied Petroleum Gas ; Duct Burners (lb/MM Btu ) g Refinery Fuel

Gas, No Duct Burners (lb/MM Bt u ) h
7440

- 47

- 3 Chromium (total) 1.1E

- 05

-- -- -- 5.0 E

- 05

-- 1.3E

- 05 218

- 01

- 9 Chrysene i 4.9E

- 09

-- j 1. 1 E

- 07

-- -- 7440

- 50

- 8 Copper

-- -- -- -- 1. 8 E

- 06 2.1E

- 05 4.1E

- 05 53

- 70

- 3 Dibenz(a,h)anthracene i 2.1E - 09

-- j 6.6E - 09

-- -- 100

- 41

- 4 Ethylbenzene

-- 1.5E - 05

-- 3.2E

- 05

-- -- -- 206

- 44

- 0 Fluoranthene i 1. 2 E

- 08

-- j 9.9 E

- 08

-- -- 86

- 73

- 7 Fluorene i 1. 5 E

- 08

-- j 1. 8 E

- 07

-- -- 50

- 00

- 0 Formaldehyde 2.8E

- 04 2

. 0 E

- 05 6.0E

- 03 7.1E

- 04 1.5E

- 04

-- 6

. 0 E

- 04 7783

- 06

- 4 Hydrogen s ulfid e -- -- -- -- 1.5E - 04

-- 1.2E - 04 193

- 39

- 5 Indeno(1,2,3

- cd)pyrene i 2.3E

- 09

-- j 9.1E - 09

-- -- 7439

- 92

- 1 Lead 1.4E

- 05

-- -- -- -- 3.6E - 05 2.8E

- 05 7439

- 96

- 5 Manganese 7.9E

- 04

-- -- -- 3. 3 E

- 06 9.2E

- 05 1. 3 E

- 04 7439

- 97

- 6 Mercury 1.2E

- 06

-- -- -- 4. 4 E

- 06

-- 1.5 E

- 05 91

- 20

- 3 Naph thalene 3.5E

- 05 j 7. 3 E

- 07

-- 1.3E

- 06 j 3.7E

- 05

-- -- 7440

- 02

- 0 Nickel < 4.6E

- 06

-- -- -- 7.6E

- 06 1. 5 E

- 04 1. 7 E

- 04 85

- 01

- 8 Phenanthrene i 6. 5 E

- 08

-- j 6. 4 E

- 07

-- -- (continued)

### Version 1.0 Section 4

— Stationary Combustion Sources

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4-35

Table 4 - 8
. Summary of Emission s Factors for Turbines Firing Various Fuels a 

### (continued)

CAS Number Substance Emissions Factor for Turbine and Fuel Type a

Distillate Oil (lb/MM Btu ) c Natural Gas,

No Duct Burners (lb/MM Btu ) d Natural Gas,

Du ct Burners (lb/MM Btu ) e Natural Gas,

Type not specified (lb/MM Btu ) f Natural Gas

and Refinery Fuel Gas , Duct Burners (lb/MM Btu ) g Natural Gas,

Refinery Fuel Gas, and Liquefied Petroleum Gas ; Duct Burners (lb/MM Btu ) g Refinery Fuel

Gas, No Duct Burners (lb/MM Bt u ) h
108

- 95

- 2 Phenol

-- -- -- -- 1.4E - 05 3. 1 E

- 05 6.7E

- 06 115

- 07

- 1 Propylene

-- 1 .6E

- 03

-- -- -- -- -- 129

- 00

- 0 Pyrene i 2. 3 E

- 08

-- j 1. 2 E

- 07

-- -- 7782

- 49

- 2 Selenium < 2.5E

- 05

-- -- -- -- 9.0E - 06 3.7E

- 06 108

- 88

- 3 Toluene

-- 7.0E

- 05

-- 1.3E

- 04 1.6E - 04

-- 7. 8 E

- 04 1330

- 20

- 7 Xylene (total)

-- 3.5E

- 05

-- 6.4E

- 05 3.7E - 04

-- 2.2E

- 03 7440

- 66

- 6 Zinc

-- -- -- -- 1.5E

- 05 2. 2 E

- 04 5

. 0 E

- 03 Note: lb/MMBtu = pounds per million British thermal units
a Source: Hansell and England, 1998 unless otherwise specified

. b Bold italic values indicate that all test runs were below detection limit.
c Source: U.S. EPA, 1995 a , Table 3.1

- 4 and Table 3.1

- 5

. Emissions factors are based on an average distillate oil heating value (HHV) of 139 MMBtu/Mgal. d The same emissions factors were provided specifically for turbines with no control device and turbines with selective catalytic reduction and c arbon m onoxide o xidation c atalyst

. e The emissions factors were provided specifically for turbines with selective catalytic reduction

. f Source: U.S. EPA, 1995 a , Table 3.1

- 3

. Emissions factors based on an average n atural gas heating value (HHV) of 1020 Btu/scf at 60°F

. g The emissions factors were provided specifically for turbines with selective catalytic reduction and c arbon m onoxide o xidation c atalyst

. h The emissions factors were provided specifically for turb ines with c arbon m onoxide o xidation c atalyst

. i The emissions factor for total polycyclic aromatic hydrocarbon s (PAH) is 4.0E

- 05 lb/MMBtu. j The emissions factor for total PAH is 2.2E

- 06 lb/MMBtu.

### Version 1.0 Section 4

— Stationary Combustion Sources

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4-36

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### Version 1.0 Section 5

— Process Vents Review Draft

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5-1 

# 5. Process Vents There are a variety of processes and equipment at petroleum refineries that may release pollutants directly into the atmosphere through process vents. Many of these process vents may be controlled using a flare, thermal incinerator, or other air pollution control techniques. This section describes the key process vents and emissions estimation procedures considering controls. At some facilities, the process gases may be routed to the refinery’s fuel gas system rather than directly to a control de vice to the atmosphere. These gases would then be combusted with the fuel gas in either a stationary combustion unit (process heater or boiler) or in a flare. As such, emissions from these gases are expected to be included in the emissions estimated for stationary combustion sources (see Section 4) or for flares (see Section 6). The methods in this section should be used for process vent gases other than those recovered into the refinery’s fuel gas system. Particularly, this section provides methods for estimating the emissions associated with catalytic cracking units (CCUs), coking units, CRUs, sulfur recovery plants, and other process vents (e.g., from hydrogen (H 2 

### ) plants, asphalt blowing stills, coke calcining units, blowdown system, and vacuum generating units ). Table 5-1 summarizes the general hierarchy of process vent emissions measurement or estimation methods, which are ranked in terms of anticipated accuracy. Within a given measurement method (or rank), there may be alternative methods for determining the constituent-specific emissions. Methodology Ranks 1 and 2 for process vents (i.e., the use of CEMS) have been previously described in Section 4, Stationary Combustion Sources . Although Section 5 will note these methods, where applicable, for individual process vents, Section 4 should be reviewed for sample calculations and other important considerations when using CEMS to determine mass emissions rates.

Table 5-1. Summary of Typical Hierarchy of Process Vent Emissions Estimates Rank Flow Estimate Me thod Compositional Analysis Data 1 Continuous flow meter Continuous gas composition analyzer 2 Engineering estimates (e.g., F factor) Continuous gas composition analyzer 3 Engineering estimates Occasional grab samples 4 Measured process rates Site

- spec ific emissions factor based on source test 5 Measured process rates Default emissions factors 

## 5.1 Catalytic Cracking Units The CCU catalyst regenerator vent is often the single largest emissions vent at the refinery. The CCU is a catalytic process used to upgrade (crack) heavy distillates to form lighter, more useful distillates such as heating oils or gasoline. The CCU system consists of a reactor, a catalyst regenerator (commonly referred to as the ―regenerator‖) , vent gas process equipment for energy recovery and emissions control, and an exhaust stack. Nearly all refinery CCU systems operate as fluidized-bed reactors and use air or oil gas flow to transport the very small catalyst particles between the CCU reactor and regenerator. These fluidized CCU systems are commonly referred to as fluid catalytic cracking units (FCCU). There are two or three refineries that use larger catalyst pellets in moving bed-type reactor system, which is commonly referred to as a thermal catalytic cracking unit (TCCU). Nearly all of the available emissions data are specific to FCCU. Consequently, the emissions inventory methods presented in this section are based primarily on FCCU operation and emissions data. Although most of these methods presented in this section were not developed for TCCU systems, apply these emissions inventory methods for TCCU systems unless direct emissions data are available. The CCU catalyst regenerator vent releases a wide variety of pollutants, including PM, SO 2 

### , NO x 

### , carbon monoxide (CO), VOC, metal HAP, organic HAP, and ammonia. As a by-product of the cracking

### Version 1.0 Section 5

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5-2 reactions, coke is deposited on the catalyst particles. The coke reduces the activity of the catalyst, and the spent catalyst that is returned from the CCU reactor is regenerated continuously by burning off coke in the CCU catalyst regenerator. There are two basic types of CCU regenerators: complete combustion regenerators and partial combustion regenerators. In a complete combustion regenerator, the regenerator is typically operated at approximately 1,200°F to 1,400°F with excess O 2 

### and low levels (< 500 ppmv) of CO in the exhaust flue gas. In a partial (or incomplete) combustion regenerator, the regenerator is typically operated at approximately 1,000°F to 1,200°F under O 2 

### -limited conditions and relatively high levels (1% to 5%) of CO. Prior to exiting the regenerator, catalyst particles entrained with the flue gases are initially removed by internal cyclone separators and returned to the regenerator catalyst bed for recirculation to the reactor. On a routine basis, a small portion of the circulating catalyst, commonly referred to as equilibrium catalyst (E-cat), is removed from the system and fresh catalyst is added to maintain catalyst activity and replace catalyst lost or removed from the system. Various other additives may also be included with the catalyst additions to reduce NO x 

### or SO 2 

### emissions or promote complete combustion (thereby reducing CO emissions). Although the CCU vent is the primary emissions source associated with the CCU, fugitive dust emissions associated with handling the fresh catalyst or spent E-cat should also be calculated and included in the emissions inventory for CCU systems. After the flue gas exits the CCU regenerator, a variety of energy recovery or emissions control systems may be used to reduce pollutant releases. For complete combustion CCU, a waste heat boiler is often used to recover the latent heat of the flue gas. The energy recovery system also serves to cool the flue gas prior to PM or other add-on control systems. The most common control systems for CCU are electrostatic precipitators (ESP) or wet scrubbers. For partial combustion CCU, the first control system is typically a CO boiler used to combust the remaining CO in the flue gas to CO 2 

### and recover the heat of combustion and latent heat of the flue gas (typically by producing steam). 5.1.1 Methodology Ranks 1 and 2 for Catalytic Cracking Units For SO 2 

### , NO x 

### , CO, and CO 2 

### , it is anticipated that most CCUs will have CEMS for measuring the composition of the exhaust gas. Gas flow rate may be directly monitored, but in many cases, the exhaust flow rate will be calculated based on air blast rates and composition monitors (similar to F factors based on coke burn-off rates). Equations in 40 CFR Part 63 Subpart UUU can be used to estimate flow rates based on gas composition analyzers that are typically used to monitor the regenerator combustion parameters. When CEMS or direct-flow monitors are present, these data should be used to calculate annual pollutant emissions. The GHG Mandatory Reporting Rule (40 CFR Part 98, Subpart Y) presents appropriate Methodology Ranks 1 or 2 for CCU to calculate CO 2 

### emissions from the CCU during coke burn-off. 5.1.2 Methodology Ranks 3 and 4 for Catalytic Cracking Units For VOC, PM, and specific HAP, it is anticipated that many refineries will have performed source tests of their CCUs. Generally, testing will be conducted infrequently so the testing results represent an emissions rate at a given point in time and production level. Rather than assuming that the mass emissions rate measured during the test occurs continuously for all process operating hours, the resulting source test data are most appropriately used for developing a site-specific emissions factor. This type of emissions factor is the measured emissions rate (lb/hr) divided by the processing rate (throughput per hr). Generally, the emissions from the CCU catalyst regenerator vent are best correlated with coke burn-off rates; however, if CCU feed and operating conditions do not vary significantly, then throughput-based emissions factorsmay be used. Generally, the most recently performed source test should be used to develop the sitespecific emissions factor.

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5-3 Although site-specific emissions factors can be developed for PM, VOC, organic HAP species, or metal HAP species using source test data, there are some unique nomenclature and reporting practices for PM emissions that deserve additional guidance. Additionally, a quasi Methodology Rank 4 for CCU metal HAP emissions estimates based on a site-specific PM emissions rate has been developed and requires additional explanation. The following subsections discuss additional guidance on providing a complete PM emissions estimate and on estimating metal HAP emissions from PM source test information. 5.1.2.1 PM Emissions Inventory and Test Method Considerations PM emissions inventories have their own nomenclature and structure. To correctly report PM emissions, an understanding of the reporting nomenclature and the PM testing methods is needed. This subsection provides guidance and background information regarding PM emissions, with a focus on the PM test methods, particularly those methods commonly used when testing the CCU vent. Example 5 - 1: Development of Site - Specific Emissions Factor A source test was performed to determin e the PM emissions rate from a CCU. Three test runs were conducted; the PM emissions rates measured during the three test runs were 20.2, 25.1, and 17.6 lb/hr for tests 1, 2, and 3, respectively. The processing rates during the three runs were 1,600; 1,700 ; and 1,500 barrels per hour (bbl/hr) and the coke burn

- off rates were 25,000; 29,000; and 23, 000 lb/hr for tests 1, 2, and 3, respectively. An appropriate emissions factor for the CCU can be developed to project annual emissions. First, the emissions fac tor for each individual run should be calculated, and then the emissions factors should be averaged. Emissions factors can be assessed using different normalizing factors, such as throughput and coke burn

- off rates, as follows:



## – Run 1: Emissions/throughput = 20.2 (lb/hr) ÷ 1,600 (bbls/hr) = 0.0126 lb/bbl = 12.6 pounds per thousands of barrels (lb/Mbbl ) Emissions/coke burn

- off = 20.2 ( lb/hr ) ÷ 25 ( 1,000 lb/hr ) = 0.808 lb/1,000 lbs coke burn

- off



## – Run 2: Emissions/throughput = 25.1 (lb/hr) ÷ 1.7 (Mbbl/hr) = 14.8 lb/Mbbl Emissions/coke burn

- off = 25.1 (lb/hr) ÷ 29 (1,000 lb/hr) = 0.866 lb/1,000 lbs coke burn

- off



## – Run 3: Emissions/throughput = 17.6 (lb/hr) ÷ 1.5 (Mbbl/hr) = 11.7 lb/Mbbl Emissions/coke burn

- off = 17.6 (lb/hr) ÷ 23 (1,000 lb/hr) = 0.765 lb/1,000 lbs c oke burn

- off



## – Average: Emissions/throughput = (12.6 + 14.8 + 11.7) ÷ 3 = 13.0 lb/Mbbl Emissions/coke burn

- off = (0.808 + 0.866 + 0.765) ÷ 3 = 0.813 lb/1,000 lb coke burn

- off There are a variety of ways to determine which emissions factor is most appropriate . One method is to compare the range of the test runs compared to the three

- run average. For the throughput

- based emissions factors, the highest single

- run emissions factor is 14% (100% × [14.8

− 13] ÷ 13) higher than the average, and the lowest single

- run emissions factor is 10% lower than the average. For the coke burn

- off rate emissions factors, the highest single

- run emissions factor is 6.5% (100% × [0.866 − 0.813] ÷ 0.813) higher than the av erage, and the lowest single

- run emissions factor is 5.9% lower than the average. The smaller range for the coke burn

- off emissions factors (as a percentage of the average) suggests that normalizing the emissions by coke burn

- off accounts for more of the d ifferences in the observed emissions than does throughput. Consequently, the average coke burn

- off emissions factor would be preferred to the throughput

- based emissions factor in this example.

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5-4 EPA Methods 5, 5B, and 5F are the most commonly used test methods for measuring PM emissions from CCUs . A typical Method 5 sampling train consists of a sampling probe, a heated line and filter, and a series of impingers that are kept in an ice bath. Method 5, 5B, or 5F sampling measures PM that is contained in the sampling probe and filter, which is often referred to as the ―front

- half‖ or ―filterable‖ PM catch. PM that condenses in the impinger section of the sampling train is often referred to as the ―back half‖ catch or the ―condensable‖ PM. One of the main differences between EPA Method 5, 5B, and 5F is that the sampling line and filter are maintained at 250°F for Method 5 compared to 325°F for Methods 5B and 5F. Although generally not used for the CCU, there are other EPA test methods for PM. EPA Method 17 is similar to Method 5, except that the filter in the Method 17 sampling probe is within the stack so that the ―filterable‖ PM content is measured at the stack temperature. EPA Methods 201 and 201A are similar to Method 17, except that there is also a cyclone or other sizing device to remove particles greater than 10 μm in diameter prior to the filter so that Methods 201 and 201A determine PM 10 

### -FIL directly. Any of the Method 5, 17, or 201 variant methods describe only the procedures to determine the front-half or filterable PM catch. EPA Method 202 specifies the procedures to determine the mass of PM that condenses in the impingers (i.e., PM-CON). Although Method 202 generally references the use of Method 17 (or 201 or 201A) sampling trains, it may also be used in conjunction with EPA Methods 5, 5B, or 5F. As the filter temperature in Method 5 is different from Methods 5B or 5F and also likely different from the filter temperature when using Method 17, the fraction of PM that is filterable versus condensable, which is a function of the sampling temperature, will also vary depending on the PM sampling method used. Because most of the data available for CCU were collected using EPA Methods 5B or 5F, the condensable PM default emissions factor is most suitable to filterable data collected using Methods 5B or 5F, but may also be used in conjunction with Method 5 sampling data. If Method 202 is used, then the back-half catch can be considered PM-CON for the purposes of inventory reporting, regardless of the PM sampling method (i.e., sampling temperature) used. To summarize, Method 5 (including 5B or 5F) provides a measure of PM-FIL and Method 202 provides a measure of PM-CON. One important caveat to this is that, in Method 5F, ammonia sulfate particulates are determined and subtracted from the total PM catch to determine the non-sulfate PM emissions. Although the non-sulfate PM value may be used for compliance purposes (for the Petroleum Refinery NSPS or for Refinery MACT II), emissions reported for the inventory should include the total filterable PM catch.That is, the total PM catch before subtracting the sulfate PM emissions should be used to determine PMFIL for the purposes of reporting for the emissions inventory. The sulfate particulate PM should be considered to be 100% PM fine (i.e., PM 2.5 

### , which it PM that is 2.5 μm in diameter or less). Additional guidance on typical CCU particle size distributions is provided in the following subsection. 5.1.2.2 PM Size Distribution Estimates for Catalytic Cracking Units AP -42 does not contain PM size distribution data for uncontrolled CCU PM emissions, but it does contain typical control device default control efficiencies for different types of PM emissions control devices. A PM Emissions Inventory Nomenclature A complete PM emissions in ventory includes the following components:

 PM 10 - PRI: ―Primary‖ PM emissions that are 10 μm in diameter or less. PM 10 - PRI = PM 10 - FIL + PM

- CON.

 PM 10 - FIL: Filterable (or front

- half catch) portion of the PM emissions that are 10 μm in diameter or less.

 PM

- CON: Condensable PM (or back

- half catch). All condensable PM is assumed to be less than 2.5 microns ( μm ) in diameter (PM 2.5 ).

 PM 2

. 5 - PRI: ―Primary‖ PM emissions that are 2.5 μm in diameter or less. PM 2.5 - PRI = PM 25 - FIL + PM

- CON.

 PM 2

. 5 - FIL: Filterable (or front

- half catch) portion of the PM emissions that are 2.5 μm in diameter or less.

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5-5 limited number of particle size distribution studies were available in the docket to the Refinery MACT 2 rule (40 CFR Part 63 Subpart UUU; Docket No. A-97-36, Item No. IV-D-19, Attachments 3, 6, and 9). From these data, the mass fraction of total filterable PM (front-half catch) that is less than 2.5 and 10 μm in diameter were determined and representative values are provided in Table 5-2

. Table 5-2 also provides PM size distribution default values for controlled CCU. The default distribution factors for controlled CCU are based on the uncontrolled PM distributions and the control device default control efficiencies from AP-42. Because the projected size distribution of PM from different control devices was similar, one single set of distribution factors for controlled CCU are provided for controlled units. Control devices considered include tertiary cyclones, wet scrubbers, venturi scrubbers, ESP, and fabric filters. All PM-CON is assumed to be less than 2.5 μm . The size distribution data guidance presented here is specific to FCCU. Although catalyst size distribution for TCCU is expected to be different, use these same default factors TCCU unless site-specific size distribution data are available.

Table 5-2. Default Size Distribution for Filterable PM from CCU
Source Description Fraction PM - FIL Less Than 2.5 μm Fraction PM - FIL Less Than 10 μm CCU, no post

- regenerator PM control device 0.30 0.50 CCU, with post

- regenerator PM control device (tertiary cyclone, wet scrubber, ESP, or fabric f ilter) 0.80 0.97 PM fine versus CCU fine Fine particles that escape from the CCU regenerator are often referred to as ―fines‖ or ―FCCU fines‖ by refinery personnel. In this Refinery Emissions Pro tocol document, fine particles that escape from the CCU regenerator are referred to as ―CCU fines.‖ Please note that CCU fines are not equivalent to ―PM fines,‖ which refers to particles that have a diameter of 2.5 μm or less. Generally, we use ―PM 2.5 ‖ to denote particles that have a diameter of 2.5 μm or less. As noted in Table 5

- 2, only a fraction of the ―CCU fines‖ are ―PM fines.‖

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5-6 5.1.3 Methodology Rank 5A for CCU Metal HAP Emissions Estimates During CCU processing, metals deposit on the catalyst particles and slowly deactivate the catalyst. Also during processing, the catalyst particles may slowly break into finer particles, which can no longer be recovered by the CCU regenerator internal cyclones. To maintain the desired catalyst activity, a portion of the recirculating catalyst (i.e., E-cat) is regularly withdrawn from the process and new (fresh) catalyst is added. New catalyst particles often have irregularities (spurs) that break off during catalyst recirculation. Consequently, the CCU fines that escape from the CCU regenerator typically have a slightly higher proportion of fresh catalyst than does the E-cat. This is significant because fresh catalyst will have less metal deposits than a catalyst that has been recirculating for days or weeks. Available paired observations of E-cat and CCU fines data indicate that the metal HAP concentration on the CCU fines are consistently Example 5 - 2 : PM Emissions Inventory Calculations The following information is available for a 50,000 barrels/calendar day ( bbl/cd) CCU controlled with an ESP. On average, the CCU burned 36,000 pounds of coke per hour and operated for 8,700 hours in the reporting year. During the most recent source test using EPA Method 5F, the CCU had non

- sulfate PM emissions of 0.7 pound per 1,000 pounds of coke burn

- off and PM emissions (including sulfates) of 0.9 pound per 1,000 pounds of coke burn

off. The ―back

- half‖ catch was also analyzed and was determined to be 0.45 pounds per 1,000 pounds of coke burn

- off. PM

- FIL = 0.9 (lb/1,000 lb c oke burn

- off) × 36 (1,000 lb of coke burn

- off per hour) × 8,700 (operating hours per year) = 281,880 lb = 140.9 tons/yr PM

- CON = 0.45 (lb/1,000 lb of coke burn

- off) × 36 (1,000 lb of coke burn

- off/hr) × 8,700 (operating hours/yr)

= 140,940 lb = 70.5 tons/ yr PM

- PRI = PM

- FIL + PM

- CON = 140.9 + 70.5 = 211.4 tons/yr For Method 5F, special consideration is made for the sulfate PM, because all of this PM is expected to be less than 2.5 μ m. For Method 5 or 5B, PM 10 

### - FIL = (fraction < 10 μ m from Table 5
- 2 ) × PM

- FIL . For Method 5F, PM 10 

### - FIL = (fraction < 10 μ m from Table 5
- 2 ) × PMnon

- sulfate + PMsulfate. Similar consideration is needed for the PM 2.5 

### - FIL calculation. Because the CCU is controlled, the appropriate fractions from Table 5
- 2 are 0.97 for the PM 10 

### - FIL calc ulation and 0.80 for the PM 2.5 

### - FIL calculation. PMnon

- sulfate = 0.7 (lb/1,000 lb coke burn

- off) × 36 (1,000 lb coke burn/hr) × 8,700 (hr/yr)

= 219,240 lb = 109.6 tons/yr PMsulfate = PM

- FIL

– PMnon

- sulfates = 140.9

– 109.6 = 31.3 tons/yr PM 10 

### - FIL = fractio n < 10 μ m from Table 5
- 2 ] × PMnon

- sulfate + PMsulfate

= 0.97 × 109.6 + 31.3 = 137.6 tons/yr PM 10 

### - PRI = PM 10 

### - FIL + PM

- CON = 137.6 + 70.5 = 208.1 tons/yr PM 2.5 

### - FIL = (fraction < 2.5 μm from Table 5
- 2 ) × PMnon

- sulfate + PMsulfate

= 0.8 × 109.6 + 31.3 = 119.0 tons/y r PM 2.5 

### - PRI = PM 2.5 

### - FIL + PM

- CON = 119.0 +70.5 = 189.5 tons/yr

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5-7 lower than on the E-cat, supporting the hypothesis that the CCU fines contain a higher fraction of fresh catalyst than does the E-cat. If metal HAP emissions tests are performed, then site-specific metal HAP emissions factors should be determined (using the methods provided in Section 5.1.2, Methodology Ranks 3 and 4 for Catalytic Cracking Units ,) and used directly to assess metal HAP emissions rates as a Rank 4 method. However, few facilities are expected to have performed metal HAP speciation emissions tests for their CCU. On the other hand, nearly all facilities have their equilibrium catalyst (i.e., the catalyst within the CCU, commonly referred to as ―E

- cat‖) tested regularly for certain metal contaminants to monitor catalyst activity and replacement needs. Some facilities also have their CCU fines tested occasionally for metal HAP concentrations. If a facility has a site-specific PM emissions factor, then either CCU fines or E-cat analysis can be used as a means to calculate a site-specific HAP emissions rate using the methodology described in this section. Th is Methodology Rank 5A for CCU metal HAP emissions estimates is expected to be more representative than a default emissions factor, but not as good as a directly measured HAP-specific emissions factor. This method involves using the site-specific (non-sulfate, if available) PM emissions rate, and estimating the concentration of metal HAP on the emitted PM based on the concentration of metal HAP on the CCU fines or E-cat using to the procedures provided in this section. This method is not applicable for mercury (Hg) because it assumes the metals are associated with the catalyst particles and are not in the vapor phase. If metal HAP concentrations of CCU fines are available, then these data should be used (preferentially to E-cat data) to estimate the metal HAP concentration of the emitted PM. It is assumed that the emitted PM has the same metal HAP concentration as the CCU fines. If metal HAP concentrations for CCU fines are not available, then the metal HAP composition of the emitted PM can be estimated as 80% of the E-cat concentration. It is expected that CCU fine or E-cat concentration data will be available for nickel (Ni) and vanadium because these are the primary metals that poison CCU catalyst activity, but concentration data may be available for other metals as well. Table 5-3 lists metal HAP generally present in CCU fines. If the concentrations of these metal HAP are not determined for the CCU fines or E-cat, then they should be estimated using the measured Ni concentration and the concentration ratios for these other metal HAP as provided in Table 5-3

. Equation 5-1 is a basic equation used to calculate metal HAP emissions based on the PM emissions rate and CCU fines metal HAP concentrations. (Eq. 5-1)

where: E i 

### = Emissions rate of metal HAP ―i‖ (tons/yr) PM -FIL = Filterable PM emissions rate from site-specific PM emissions factor; if EPA Method

5F is used, then use PMnon-sulfate rather than PM-FIL (ton/yr) C i 

### = Concentration of metal HAP ―i‖ on the CCU fines (milligrams per kilogram [mg/kg])

= 0.8 × C E-cat,i 

### , if only E-cat concentration are available = C Nickel 

### × (factor from Table 5-3 ), if other metal HAP concentrations are not available Note that E i 

### = E Nickel 

### × (factor from Table 5-3 ) when other metal HAP concentration data are not available.

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5-8 Table 5-3. Default Ratio of Metal HAP Composition of CCU Fines a

Metal HAP Ratio of Metal HAP to Nickel Concentration Antimony 0.065 Arsenic 0.010 Beryllium 0.003 Cadmium 0.013 Chromium (total) b 0.25 b Cobalt 0.052 Lead 0.08 Manganese 0.13 Nickel 1.00 Selenium 0.025 c

a Concentration ratios are based on average electrostatic precipitator dust analyses across six refinerie s. b Limited d ata are available to assess the amount for hexavalent chromium that is present, if any. If site specific data are not available, it is recommended that a default value of 1 0 percent of the total chromium emissions be used to estimate the hex avalent chromium emission s associated with the CCU

. c Selenium was highly variable, being significant for some units and below the detection limit for several others. Consequently, this v alue is highly uncertain.

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5-9 Although total chromium emissions have been found above detectable concentrations in the CCU regenerator vent, very few tests have been performed to determine Cr +6 

### emissions. The few tests that have been performed have not found Cr +6 

### above detection limits, but the detection limits have been comparable to the detected total chromium emissions. Based on these limited data, it is recommended that, for the CCU vent, Cr +6 

### emissions be estimated as 10% of the total chromium emissions. Thus, in the example calculation provided, Cr +6 

### emissions would be estimated to be 0.0026 tons/yr. Emissions of Hg should be estimated for the CCU; however, Hg emissions are not expected to be correlated with the PM emissions because very little, if any, of the Hg emissions are expected to beparticulate bound. Mercury emissions are more likely correlated with the CCU throughput or coke burnoff rate. Thus, Hg emissions should be estimated independently of other HAP metals. If Hg emissions data are available based on source test data for the site, then the source test data can be used, as a Methodology Rank 4 for metal HAP emissions estimates, to develop a site-specific emissions factor. Otherwise, Hg emissions should be estimated using a default (Rank 5B) emissions factor rather than using this Rank 5A method. 5.1.4 Methodology Rank 5B for Catalytic Cracking Units For most organic HAP (e.g., formaldehyde, benzene, benzo[a]pyrene, dioxin/furans) and other pollutants such as hydrogen cyanide and Hg, default emissions factors may be all that are available. When direct Example 5 - 3: Methodology Rank 5A for Metal HAP Emissions Estimates Following the previous example, PMnon

- sulfate emissions were calculated to be 109.6 tons/yr. If only Ni concentration for E

- c at is available, what are the metal HAP emissions if the average Ni E

- cat concentration is 1,200 mg/kg? The concentration of Ni on the emitted PM is calculated based on the E

- cat concentration as follows: C Nickel 

### = 0.8 × 1,200 = 960 mg/kg The following eq uation should be used to calculate the emissions rate of Ni from the PM emissions rate on estimated Ni concentration: E Nickel 

### = 109.6 tons/yr × (960 mg/kg) ÷ (1,000,000 mg/kg) = 0.105 tons/yr The following equations should be used to estimate the emissions rate of other metal HAP from the emissions rate of Ni: E Antimony 

### = 0.105 tons/yr × 0.065 = 0.0068 tons/yr E Arsenic 

### = 0.105 tons/yr × 0.010 = 0.00105 tons/yr E Beryllium 

### = 0.105 tons/yr × 0.003 = 0.0003 tons/yr E Cadmium 

### = 0.105 tons/yr × 0.013 = 0.0014 to ns/yr E Chromium 

### = 0.105 tons/yr × 0.25 = 0.026 tons/yr E Cobalt 

### = 0.105 tons/yr × 0.052 = 0.0055 tons/yr E Lead 

### = 0.105 tons/yr × 0.08 = 0.0084 tons/yr E Manganese 

### = 0.105 tons/yr × 0.13 = 0.014 tons/yr E Selenium 

### = 0.105 tons/yr × 0.025 = 0.0026 tons/yr

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5-10 emissions monitoring or site-specific emissions factors are not available, then the default emissions factors presented in Table 5-4 should be used to calculate the emissions from the CCU regenerator vent.

Table 5-4. Organic HAP Emissions Factors for CCU Catalyst Regenerator Vent

CAS No. Compound Emission s Factor (lb/MMbbl) a 106

- 99

- 0 1,3

- Butadiene 0.025 75

- 07

- 0 Acetaldehyde 25 71

- 43

- 2 Benzene 19 57

- 12

- 5 Cyanide 32 50

- 00

- 0 Formaldehyde 4 80 74

- 90

- 8 Hydrogen cyanide 10 0 108

- 95

- 2 Phenol 21 108

- 88

- 3 Toluene 1.4 1330

- 20

- 7 Xylene 3.2 100

- 41

- 4 Ethylbenzene 0.24 67

- 64

- 1 Acetone 4.8 107

- 02

- 8 Acrolein 1.0 74

- 83

- 9 Bromo

- methane 2.1 75

- 15

- 0 Carbon d isulfide 0.56 75

- 09

- 2 Methylene c hloride 6. 7 75

- 69

- 4 Trichloro

- fluoro

- methane 2.4 57117

- 31

- 4 Polychlorinated dibenzofurans 5.5E

- 07 57117

- 44

- 9 Hexachlorodibenzofuran 1.1E

- 06 7647

- 01

- 0 H ydrogen chloride 14 0 83

- 32

- 9 Acenaphthene 0.0033 208

- 96

- 8 Acenaphthylene 0.1 3 120

- 12

- 7 Anthracene 0.10 56

- 55

- 3 Benzo(a)anthracene 0.001 1 50

- 32

- 8 Benzo(a)pyrene 0.0106 205

- 99

- 2 Benzo(b)fluoranthene 0.0035 192

- 97

- 2 Benzo(e)pyrene 0.0008 5 191

- 24

- 2 Benzo(g,h,i)perylene 0.0046 207

- 08

- 9 Benzo(k)fluoranthene 0.0027 218

- 01

- 9 Chrysene 0.0033 53

- 70

- 3 D ibe nz(a,h)anthracene 0.0042 206

- 44

- 0 Fluoranthene 0.22 86

- 73

- 7 Fluorene 0.058 193

- 39

- 5 Indeno(1,2,3

- cd)pyrene 0.004 4 91

- 20

- 3 Naphthalene 1.1 85

- 01

- 8 Phenanthrene 0.35 129

- 00

- 0 Pyrene 0.003 3 91

- 57

- 6 2

- Methylnaphthalene 0.026 (continued)

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5-11 Table 5 - 4 . Organic HAP Emission s Factors for CCU Catalyst

Re generator Vent (continued)

CAS No. Compound Emission s Factor (lb/MMbbl) a 65

- 85

- 0 Benzoic acid 79 117

- 81

- 7 Bis (2

- ethyl hexyl ) p hthalate 2.8 84

- 74

- 2 di

- n - Butyl p hthalate 2.0 84

- 66

- 2 Diethyl

- phthalate 0.28 7439

- 97

- 6 Mercury 0.25

a Emission s factors f or CCU controlled for organics in pounds per million barrels of CCU capacity. 

### Based on the lack of data for PAH and furan emissions, the emissions estimates for these compounds have high uncertainties, likely an order-of-magnitude either high or low. The California Air Resources Board ( CARB ), with EPA’s support, conduct ed an emissions source test at a complete combustion FCCU(without a post-combustion device). The only dioxin isomer detected in all runs was octachloro-dibenzop-dioxin (OCDD); octachloro-dibenzo-furan (O CDF ) and heptachloro-dibenzo-p-dioxin ( he p ta -CDD) were detected in one run. All dioxin/furan quantities that were detected were detected at levels below the method quantitation limit for the analysis. All polychlorinated biphenyls (PCBs) isomers were below detection limits. This additional source test was not included in the development of the Petroleum Refinery MACT II emissions factors, but it confirms low emissions of dioxins/furans and PCBs from the CCU catalyst regenerator vent. 

## 5.2 Fluid Coking Units Coking units use heat to thermally crack heavy hydrocarbon streams to form lighter, more useful distillates such as heating oils or gasoline. There are three basic types of coking units: traditional fluid coking units, flexicoking units, and delayed coking units. Traditional fluid coking units are one of the largest vent emissions sources at a refinery, being comparable to emissions from the CCU regenerator. However, there are only a handful of traditional fluid coking units currently in operation in the United States. Flexicoking units, which are also rare, do not have a direct atmospheric vent. Instead, these units produce a low heating value content syngas that can be subsequently used as fuel in process heaters or boilers. Emissions from the combustion of flexicoking syngas should be determined using the methods described in Section 4, Stationary Combustion Sources . Nearly all new coking units being built at refineries are delayed coking units, which are discussed further in Section 5.3. Fluid coking units have several similarities to a CCU. The coking unit contains a burner section and a reactor section. In the burner section, heat for the coking reaction is supplied by burning a portion of the coke that is produced. In the reactor, fine coke particles are produced as a result of the thermal cracking process. Prior to exiting the coking unit, coke particles entrained with the flue gases are removed by internal cyclone separators and recovered as a product, with a portion of the produced coke recycled to the burner section. The coke burner is operated with limited air

— enough to combust the diverted coke (to provide heat for the coking reaction)

— but limited enough to prevent O 2 

### from getting into the reactor section. The exhaust gas from the coking unit burner has high levels of CO, which is typically combusted in a CO boiler to recover the latent heat of the CO. The CO boiler also acts to combust any organics entrained in the flue gas. The gas may then be further processed to remove PM or SO 2 

### in the flue gas. The fluid coking unit vent releases a wide variety of pollutants, including PM, SO 2 

### , NO x 

### , CO, VOC, metal HAP, organic HAP, and ammonia. Special considerations should be taken to estimate the amount of total sulfur compounds present in fuel gas generated from the fluid coking unit. Coking units have been found to produce appreciable quantities

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5-12 of methyl mercaptans and other reduced sulfur compounds that are not efficiently removed from the sour gas as H 2 

### S. Consequently, SO 2 

### emissions from fuel gas combustion devices receiving fuel gas generated from a fluid coking unit should account for this additional sulfur that is not measured by H 2 

### S monitors (see Section 4, Stationary Combustion Sources , for further details). Note also that fluid coking units, in particular, may have significant fugitive PM emissions from the handling of the produced coke. Methodologies for these fugitive PM emissions are described in Section 11, Fugitive Dust Sources

. 5.2.1 Methodology Ranks 1 and 2 for Fluid Coking Units For SO 2 

### , NO x 

### , CO, and CO 2 

### , it is anticipated that most units will have CEMS for measuring the composition of the exhaust gas. Gas flow rate may be directly monitored, but in many cases, the exhaust flow rate will be calculated based on air blast rates and composition monitors (similar to F factors). 5.2.2 Methodology Ranks 3 and 4 for Fluid Coking Units Source tests should be available for PM (and perhaps SO 2 

### and NO x 

### , if not continuously monitored) so that site-specific emissions factors should be available. It is anticipated that the pollutant emissions will primarily be a function of the coke burn rates; however, limited data are available to assess this hypothesis. 5.2.3 Methodology Rank 5 for Fluid Coking Units We do not have data to provide default emissions factors for fluid coking units. 

## 5.3 Delayed Coking Units Coking units use heat to thermally crack heavy hydrocarbon streams to form lighter, more useful distillates such as heating oils or gasoline. Most of the coking units in operation within the United States are delayed coking units. Unlike most other refinery operations that are continuous, delayed coking units are operated in a semi-batch system. Most delayed coking units consist of a large process heater, typically two coking drums, a single product distillation column, and coke cutting equipment. The process heater heats the heavy feed oil to near cracking temperatures, and then the oil is fed to one of the coking drums. As the cracking reactions occur, coke is produced in the drum and begins to fill the drum with sponge-like solid coke material. Once filled, the feed is diverted to the second coke drum. The full coke drum is cooled by slowly adding water to the vessel, which quickly turns to steam, and the steam helps to cool and purge organics in the coke matrix. After the coke drum is sufficiently cooled, the drum is opened and the coke is removed from the vessel using high-pressure water. Once the coke is cut out of the drum, the drum is closed, and prepared to go back online. A typical coke drum cycle is typically 14 to 18 hours from start of feed to start of feed.During the reaction process, the delayed coking unit is a closed system. When the coke drum is taken offline, the initial steaming process gas is also recovered through the unit’s product distillation column. As the steaming cycle continues, the gas is sent to a blowdown system to recover the liquids. The gas is typically sent to a flare or other control device but may be released to the atmosphere. Near the end of the steaming process, a vent is opened to allow the remaining steam and vapors to be released into the atmosphere prior to opening the drum. Emissions from delayed coking units are primarily CH 4 

### and ethane, but include a variety of volatile and semi-volatile organics. Although this section primarily addresses the vent emissions from the delayed coking unit, fugitive emissions are also released from the delayed coking unit when the coke drum is opened and the coke is cut from the drum. During this cutting process, hydrocarbons that were retained in the internal coke pores will be released into the atmosphere. The cutting water will absorb some hydrocarbons, so this water will also become a source of organic emissions. PM emissions from the coke cutting operations and

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5-13 subsequent coke storage and handling facilities should be estimated using the methodologies described in Section 11, Fugitive Dust Sources . Organic emissions from impoundments or ponds used to store the cutting liquids should be estimated using the methodologies described in Section 7.2.5, Equalization Tanks

. As with fluid coking units, special considerations should be taken to estimate the amount of total sulfur compounds that are present in fuel gas generated from delayed coking units. Coking units have been found to produce appreciable quantities of methyl mercaptans and other reduced sulfur compounds that are not efficiently removed from the sour gas as H 2 

### S. Consequently, SO 2 

### emissions from fuel gas combustion devices receiving fuel gas generated from a delayed coking unit should account for this additional sulfur that is not measured by H 2 

### S monitors (for more detail, see Section 4, Stationary Combustion Sources ). 5.3.1 Methodology Ranks 1 and 2 for Delayed Coking Units Delayed coking units vent periodically and only for relatively short periods of time during depressurization of the unit after the coking cycle. As such, delayed coking units are not expected to use CEMS. If CEMS are used, Methodology Rank 1 for process vents could be used. The gas flow rate cannot be estimated using F factors, so Methodology Rank 2 for process vents is not applicable to the delayed coking unit vent. 5.3.2 Methodology Ranks 3 and 4 for Delayed Coking Units A limited number of source tests have recently been performed on delayed coking unit vents. For facilities that have performed source tests, site-specific emissions factors can be developed and used. It is anticipated that the pollutant emissions will be a function of coking vessel void volume and initial vent pressure; however, for a particular delayed coking unit, these variables are fairly constant and a per cycle emissions rate from the source test can be used. 5.3.3 Methodology Rank 5 for Delayed Coking Units Source test data are available for five delayed coking units (SCAQMD, 2004a, 2004b, 2004c, and 2004d; URS Corporation, 2008). From these data, average concentrations and emissions factors were developed (see Table 5-5 ). While the emissions are expected to be higher for units that start to depressure at higher coke drum pressures, the emissions were also dependent on the time steaming occurred prior to depressurization and the temperature of the drum (how much additional steam was generated after the steam vent was opened. Due to the complexities of the delayed coking unit steam vent and the limited test data available, correlations to account for different process variables (venting pressure, drum temperature and steaming time prior to venting) are not currently available, and the default emissions factors in Table 5-5 should be used when site-specific measurement or test data are not available.
Table 5-5
. Average Vent Concentrations and Emissions Factors for Delayed Coking Unit Vents

CAS No. Compound Vent Concentration ( ppmv, wet basis ) Emission s Factor (lb/ c ycle ) a 106

- 99

- 0 Methane 7,600 200 75

- 07

- 0 Ethane 1,800 42 VOC Nonmethane/nonethane VOC 1,600 57 71

- 43

- 2 Benzene 9.4 0.1 108

- 88

- 3 Toluene 24 5.6 100

- 41

- 4 Ethylbenzene 1.7 0.03 1330

- 20

- 7 Xylene 15 0.24 (continued)

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5-14 Table 5 - 5
. Average Vent Concentra tions and Emission s Factors for Delayed Coking Unit Vents (continued)

CAS No. Compound Vent Concentration ( ppmv, wet basis ) Emission s Factor (lb/ cycle ) a 108

- 95

- 2 Phenol 0.12 1319

- 77

- 3 Cres ol s (total) 0.23 105

- 67

- 9 2,4

- Dimethylphenol 0.086 62

- 53

- 3 A niline 0.057 POM Total all POM 0.64 83

- 32

- 9 Acenaphthene 0.070 208

- 96

- 8 Acenaphthylene 0.004 120

- 12

- 7 Anthracene 0.15 56

- 55

- 3 Benzo(a)anthracene 0.031 50

- 32

- 8 Benzo(a)pyrene 0.027 205

- 99

- 2 Benzo(b)fluoranthene 0.007 191

- 24

- 2 Benzo(g,h,i)per ylene 0.014 207

- 08

- 9 Benzo(k)fluoranthene 0.005 218

- 01

- 9 Chrysene 0.032 53

- 70

- 3 D ibenz(a,h)anthracene 0.010 206

- 44

- 0 Fluoranthene 0.024 86

- 73

- 7 Fluorene 0.18 193

- 39

- 5 Indeno(1,2,3

- cd)pyrene 0.007 91

- 20

- 3 Naphthalene 1.7 85

- 01

- 8 Phenanthrene 0.46 129

- 00

- 0 Pyrene 0.080 91

- 57

- 6 2

- Methylnaphthalene 2.9

a Emissions are in pounds per emissions event or per cycle considering a single coke drum. 

## 5.4 Catalytic Reforming Units The CRU is a series of catalytic reactors that turn naphtha into hi gh -octane gasoline. There are no direct atmospheric vents from the naphtha-reforming process, but the catalyst activity slowly diminishes with time and the catalyst must be regenerated. There are three basic types of CRU catalyst regeneration: continuous, cyclic, and semi-regenerative. Continuous CRU catalyst regenerators operate continuously with a small slip stream of catalyst being re-circulated between the CRU and the regenerator. In cyclic CRU, there is essentially an extra CRU reactor. When regeneration is needed, one reactor is cycled offline and regenerated. The regeneration of the offline reactor is a batch process. When complete, the reactor is returned to service, and the next reactor is cycled offline and regenerated. Th is process continues until all reactors are regenerated. In a cyclic CRU, regeneration may occur for 1,000 to 4,000 hours per year. The semi-regenerative CRU operates without regeneration for 8 to 18 months, then the entire unit is brought offline, and the entire unit is regenerated. The overall regeneration cycle typically takes 1 to 2 weeks. During regeneration, there are several potential atmospheric vents. Although the location of the emission points might vary depending on whether catalyst regeneration is continuous, cyclic, or semi-regenerative, there are three times or locations during the regeneration process that emissions can occur regardless of the regenerator type. For continuous regeneration, venting occurs from three distinct vents as follows: (1) the initial depressurization and purge vent; (2) the coke burn pressure control vent; and (3) the final

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5-15 catalyst purge vent. For cyclic and semi-regenerative units, the initial depressurization and purge vent is often a distinct release point, but the coke burn and final catalyst purge emissions are commonly released at different times during the regeneration cycle from a single atmospheric vent. The initial depressurization and purge cycle removes the hydrocarbons from the catalyst prior to CRU catalyst regeneration. The vent gases from this initial purge may have high levels of organic HAP such as benzene, toluene, xylene, and hexane. Th e gases generated from the initial depressurization and purge cycles are typically vented to the refinery fuel gas system or directly to a combustion device (e.g., flare or process heater). The coke burn cycle is typically the largest (in terms of gas volume) emissions source of the overall catalyst regeneration cycle. The primary HAP contained in the CRU coke burn vent are hydrogen chloride ( HCl ) and chlorine (Cl 2 

### ), which are produced when the water formed during combustion leaches chloride atoms from the CRU catalyst. The final purge and reduction cycle removes O 2 

### and any remaining chlorination agent from the system and reduces the catalyst prior to returning the CRU catalyst to the reforming process or bringing the unit back online. The vent gases from this final purge may have low levels of the chlorinating agent (usually an organic HAP such as trichloroethene of perchloroethene) and residual HCl or Cl 2 

### remaining in the system. Th e final purge gases are typically vented in to the atmosphere or to the refinery fuel gas system depending on the O 2 

### content of the purge gases (safety considerations restrict the venting of O 2 

### -containing gases to the re finery fuel gas system). 5.4.1 Emissions Estimation Methodology for Catalytic Reforming Units Few data are available to characterize the emissions from the CRU catalyst regeneration vent because venting is infrequent, the vent flow rates are slow and usually variable, and the vents have small diameters. All of these factors make traditional source testing difficult. Most of the available data are for HCl and Cl 2 

### emissions from uncontrolled coke burn (20 data points are available for HCl emissions; 10 data points are available for Cl 2 

### ). Few data were available for a limited number of organic chemicals. These data are compiled in the Background Information Document (BID) for the proposed Petroleum Refinery MACT II rule (U.S. EPA , 1998b). During the Petroleum Refinery MACT II project, CARB, with funding assistance from EPA, conducted a source test of a continuous CRU catalyst regenerator coke-burn vent for dioxins/furans, PCBs, and PAHs. The results from this source test, which were not available at the time for inclusion into the Petroleum Refinery MACT II BID, were used to develop emissions factors for these compounds. The emissions factors used for the uncontrolled coke burn emissions are presented in Table 5-6 . These emissions factors are normalized by the CRU process throughput and are assumed to apply equally for all types of CRU regenerators. The most prevalent control device used in association with the coke-burn vent is a wet scrubber. The dioxin/furan emissions source tests and the volatile organics were performed on a system controlled by a wet scrubber. Because of the limited solubilities of these chemicals and the scrubbing medium recirculation rate used for wet scrubbers on this vent stream, the scrubber is assumed to be ineffective at reducing the emissions of these chemicals. Therefore, the same emissions factor is recommended for these chemicals for both controlled and uncontrolled CRU. The wet scrubbers are expected to reduce the emissions of HCl and Cl 2 

### . The wet scrubbers used for these vents were characterized into two classes: single-stage scrubbers and multiple-stage scrubbers. Single-stage scrubbers are estimated to reduce HCl and Cl 2 

### emissions by 92%, and the multiple-stage scrubbers are estimated to reduce HCl and Cl 2 

### emissions by 97%. As most emissions from the purge cycles are vented to the refinery fuel gas system or a flare, emissions from this source were not covered separately in this section; these emissions are presumably included in the refinery fuel gas combustion sources (process heaters and boilers) or flares emissions estimates. No data are available to characterize the small portion of venting that occurs directly in to the atmosphere from these purge cycles, but these emissions should be characterized and reported in the inventory.

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5-16 Table 5-6. Emissions Factors for CRU Catalyst Regeneration Vent

CAS No. Chemical Name Emission s Factor (lb/1 , 000 bbl) a 1746

- 01

- 6 Dioxin toxic equivalents (TEQ) b 5. 7 E

- 09 1336

- 36

- 3 Total polychlorinated biphenyls c 2.6E

- 06 91

- 20

- 3 Naphthalene 3.5E

- 05 91

- 57

- 6 2

- Methylnaphthalene 1. 3 E

- 06 208

- 96

- 8 Acenaphthylene 3.0E

- 08 83

- 32

- 9 Acenaphthene 4. 3 E

- 08 86

- 73

- 7 Fluorene 2

. 0 E

- 07 85

- 01

- 8 Phenanthrene 6.1E

- 07 120

- 12

- 7 Anthracene 9.1E

- 08 206

- 44

- 0 Fluo r anthene 1.0E

- 07 129

- 00

- 0 Pyrene 1.5E

- 08 56

- 55

- 3 Benzo(a )anthracene 9

. 0 E

- 10 218

- 01

- 9 Chrysene 2. 9 E

- 09 205

- 99

- 2 Benzo(b)fluoranthene 1.5E

- 09 207

- 08

- 9 Benzo(k)fluoranthene 7. 5 E

- 10 192

- 97

- 2 Benzo(e)pyrene 2.9E

- 09 193

- 39

- 5 Indeno(1,2,3

- c,d)pyrene 1.7E

- 09 53

- 70

- 3 Dibenzo(a,h)anthracene 7. 8 E

- 10 191

- 24

- 2 Benzo( g,h,i)perylene 4.0E

- 09 71

- 43

- 2 Benzene 0.004 108

- 88

- 3 Toluene 0.0096 1330

- 20

- 7 Xylene 0.007 7647

- 01

- 0 H ydrogen chloride 4.2 d 7782

- 50

- 5 Chlorine 0.2 3 d

a Emission s factor in pounds pollutant emitted per 1,000 barrels of catalytic reforming unit proces s capacity. b Dioxin TEQ = toxic equivalen ts to 2,3,7,8

- tetrachloro

- dibenzo

- p - dioxin used for risk analysis; specific dioxin/furan isomer emissions data are available.
c Sum total of all chlorinated biphenyl emission s factors; data were available for eac h class of chlorinated biphen yls (e.g., mono

- , di

- , tri

- ..., decachlorobiphenyl). d Emission s factor for uncontrolled coke burn vent; controlled emissions should be estimated based on the efficiency of the control device for these pollutants

. 

## 5. 5 Sulfur Recovery Plants All crude oils contain some sulfur compound impurities. Sulfur compounds in crude oil are converted to H 2 

### S in the cracking and hydrotreating processes of the refinery. The H 2 

### S in the generated gas streams is removed from the process vapors using amine scrubbers. The amine scrubbing solution is subsequently heated to release the H 2 

### S to form an H 2 

### S rich ―acid gas‖ that is treated in the sulfur recovery plant to yield high-purity sulfur that is then sold as product. Most sulfur recovery plants use the Claus reaction and are commonly referred to as Claus units or Claus sulfur recovery plants. There are a couple of other types of sulfur recovery plants at smaller refineries, but all larger sulfur recovery plants employ Claus units. The exhaust gas from the sulfur recovery unit (SRU) is commonly referred to as ―tail gas.‖ The sulfur

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5-17 recovery plant consists of one or more SRU operated in parallel and may also contain one or more catalytic tail gas treatment units and/or a thermal oxidizer to combust the tail gas. The primary HAP components of the final sulfur plant vent are carbonyl sulfide (COS) and carbon disulfide (CS 2 

### ). These HAP components are by-products of the SRU and tail gas treatment unit (TGTU) reactions; COS may also be a product of incomplete combustion from a thermal oxidizer. Unreacted H 2 

### S may also be released during the process. Sulfur recovery plant vents are commonly controlled by a thermal oxider to oxidize unreacted H 2 

### S or H 2 

### S in sweep gas from the sulfur pits to SO 2 

### . When the sulfur recovery plant is in operation, the sulfur plant vent flow rate is fairly small so that the SO 2 

### emissions from the sulfur recovery plant are also relatively small. If the sulfur recovery plant must be taken offline due to an upset or malfunction, the sour gas may be temporarily directed to a flare or to the thermal oxidizer. Under these cases, the SO 2 

### emissions can be very large. As such, it is critical to include accurate accounting of SO 2 

### emissions during startup, shutdown, or malfunction (SSM) events associated with the sulfur recovery plant. The sulfur plant sour gas feed may also contain small amounts of light organics. Therefore, it is important to account for the hydrocarbons in the sulfur recovery plant feed when estimating emissions from the sulfur recovery plant, particularly from Lo-Cat ® 

### or other sulfur recovery plants that may have atmospheric vents without thermal destruction. 5.5.1 Methodology Ranks 1 and 2 for Sulfur Recovery Plants It is anticipated that most sulfur recovery plants, particularly Claus sulfur recovery plants, will have continuous SO 2 

### concentration monitors. When continuous flow monitors are also in place, mass emissions rates can be calculated using the CEMS method previously described in Section 4, Stationary Combustion Sources . Unlike combustion sources, however, there is not an F factor method to project the vent flow rate. If the flow rate and H 2 

### S concentration of the feed to the sulfur recovery plant, the air or oxygen feed rates to the sulfur plant burner (used to convert one-third of the H 2 

### S to SO 2 

### ), and the quantity of sulfur recovered are known, then calculations to determine/quantify emissions can be made, but the calculations are not trivial. As such, there is not a simple Rank 2 method that can be provided for sulfur recovery plants. Non-Claus sulfur recovery plants may monitor H 2 

### S or reduced sulfur compound concentrations instead of SO 2 

### . Again, H 2 

### S emissions estimates should be provided for sulfur recovery plants. 5.5.2 Methodology Ranks 3 and 4 for Sulfur Recovery Plants Emissions estimates can be made from inlet flow measurements and assumed recovery efficiencies. For most Claus units, especially those with tail gas treatment/recovery units, a mass balance approach for sulfur is expected to yield emissions estimates with high uncertainties (e.g., when two large numbers are subtracted so that the difference is only a few percentages of the original values, the uncertainties in the original values may be as large as the difference). A three-stage Claus unit is expected to have sulfur recovery efficiencies of 95% to 97%. Combining a three-stage Claus unit with a tail gas treatment unit, sulfur recovery efficiencies are expected to be 99.7% to 99.9%. With these types of recovery efficiencies, the mass balance approach (i.e., calculating SO 2 

### or other sulfur compound emissions from the difference of the sulfur feed rate to the SRU and the sulfur produced) will have significant uncertainty. Consequently, measurement of the mass feed rate of sulfur to the sulfur recovery plant and an assumed sulfur recovery efficiency (based on the number of Claus reactors in series and the presence or absence of a tail gas treatment unit) are likely to be more accurate than using a mass balance approach when calculating sulfur compound emissions from the sulfur recovery plant. A similar approach can be used to calculate CO 2 

### emissions from the sulfur recovery plant, particularly in systems controlled with a flare or thermal oxidizer. Because nearly all of the CO 2 

### or hydrocarbons introduced to the sulfur recovery plant will exit as CO 2 

### , measuring inlet C content and flow rate of gases to the sulfur recovery plant can be used to accurately estimate CO 2 

### emissions.

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5-18 Given the high uncertainty expected in engineering/mass-balance calculations for sulfur recovery plants, site-specific emissions factors may be as or more useful than using an engineering/mass-balance approachfor calculating emissions from sulfur recovery plants, particularly sulfur compound emissions. Sitespecific emissions factors are also recommended for reductive tail gas treatment units not followed by an incinerator and for non-Claus sulfur recovery plants. Evaluation of light hydrocarbons should be addressed in these systems. For example, Lo-Cat ® 

### systems use an oxidation tank in which H 2 

### S is chemically oxidize to SO 2 

### . Any light hydrocarbons entrained in the sour gas are expected to be released in the vent from the oxidation tank. The emissions from this oxidation tank should be characterized and reported for the sulfur recovery plant. 5.5.3 Methodology Rank 5 for Sulfur Recovery Plants The Petroleum Refinery MACT II BID (U.S. EPA, 1998b) presents a range of total sulfur HAP compounds emissions factors for SRU controlled by an incinerator. Based on the data presented and additional concentration data submitted by the National Petrochemical and Refiners Association, it was assumed that 75% of the sulfur HAP emitted was COS and 25% was CS 2 

### . The controlled emissions factors are based on summary data reported for five SRUs. Emissions of uncontrolled sulfur HAP were estimated assuming a control efficiency of 98% (so that uncontrolled emissions are 50 times higher than controlled emissions). The resulting emissions factors are presented in Table 5-7

. Table 5-7. Emissions Factors for Sulfur Recovery Plants

CAS No. Compound Name Controlled SRU Emission s Factor (lb/lton) a Uncontrolled SRU Emission s Factor (lb/lton) a 43

- 58

- 1 Carbonyl sulfide 0.1 2 5.85 b 75

- 15

- 0 Carbon disulfide 0.040 2.00 b Note: lb/lton = pounds per long ton
a Emission s factor in pounds of HAP per long

- ton of sulfur produced. b Values estimated as 50 times the controlled SRU emission s factor

. 

## 5.6 Other Miscellaneous Process Vents There are many other process vents at a refinery; however, there are limited data for these vents, so default emissions factors are not available. For these process vents, this section provides a brief description of the process, the vent source, and the primary pollutants associated with the process vent. For all of these sources, the general hierarchy of methods as presented in Table 5-1 in the introduction to this chapter is applicable. The purpose of this section is to provide default emission factors for Methodology Rank 5 for these particular process vents. 5.6.1 Hydrogen Plant Vents Steam CH 4 

### reforming is the primary means by which H 2 

### is produced at a petroleum refinery. Refinery fuel gas is typically used as the feedstock to the H 2 

### plant. The feedstock is combined with steam in a reactor at high temperatures (750 °C to 800°C) to produce a mixture of H 2 

### and CO. A water

– gas shift reaction occurs in a series of catalytic reactors to convert the CO and steam to CO 2 

### and H 2 

### . Finally, the CO 2 

### is removed from the H 2 

### product using either a liquid absorption system or pressure swing absorption. The H 2 

### plant vent contains relatively high levels of methanol and may also contain formaldehyde and other light hydrocarbons; however, no default emission factors are available at this time for the hydrogen plant vent. 5.6.2 Asphalt Plant Vents Asphalt blowing is used for polymerizing and stabilizing asphalt to improve its weathering characteristics. Air-blown asphalts are used in the production of asphalt roofing products and certain road asphalts. Air

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5-19 blowing of asphalt may be conducted at petroleum refineries, asphalt processing plants, and asphalt roofing plants. Asphalt blowing involves the oxidation of asphalt flux by bubbling air through liquid asphalt flux at 260°C (500°F) for 1 hour to 10 hours. The amount of time depends on the desired characteristics of the product, such as the softening point and the penetration rate. Shorter periods are typically used for road asphalt; longer periods are used for roofing asphalt. Asphalt blowing results in an exothermic reaction that requires cooling. The emissions from a blowing still are primarily organic particulate with a fairly high concentration of gaseous hydrocarbon and polycyclic organic matter. The blowing still gas is commonly controlled with a wet scrubber to remove sour gas, entrained oil, particulates, and condensable organics and/or a thermal oxidizer to combust the hydrocarbons and sour gas to CO 2 

### and SO 2 

### . Overall PM and TOC emissions factors for asphalt blowing are provided in Section 11.2 of AP -42 (U.S. EPA, 1995a); these emission factors are also presented here in Table 5-8

.

Table 5- 8. Emission Factors for Asphalt Blowing (U.S. EPA, 199 5a )

Operation Filterable PM a TOC b Emission Factor (Data Quality Rating) (lb/ton asphalt processed) Uncontrolled Saturant asphalt c 6.6 (E) 1.3 (E) Coating aspha lt d 24 (E) 3.4 (E) Controlled Saturant asphalt c 0.27 (D) 0.0043 (D) Coating asphalt d 0.81 (D) 0.017 (D)

a Filterable (front

- half) particulate matter catch using EPA Method 5A sampling at 108°F. b Total organic compounds measured using EPA Method 25A

. c Saturant blow of 1.5 hours. d Coating blow of 4.5 hours. 

### Tumbore (1998) provided an additional summary and evaluation of emissions from controlled asphalt blowing. Some key findings from this review were:

 The AP-42 emission factors ignore emissions of SO 2 

### , which are usually the largest emissions from the process. For gas fired control systems, H 2 

### S resulting from the asphalt blowing reaction accounted for 70 to 80 % of the SO 2 

### emissions, with the remainder attributable to entrained or condensed oil.

 The AP -42 emission factors ignore emissions of HCl, which are important when ferric chloride is used as a catalyst in the process. The Emission Inventory Guidebook 2006 (EMEP/CORINAIR, 2006) provides the following speciation profile for organic emissions from asphalt blowing (see Table 5-9 ). Although not specified, it is assumed that this speciation profile in Table 5-9 represents uncontrolled asphalt blowing emissions.

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5-20 Table 5-9. Asphalt Blowing
– Nonmethane Volatile Organic C ompounds Speciation a Compound % Weight Ethane 6.0 Propa n e 18.8 Butanes 30.5 Pentanes 17.2 Hexanes 8.4 Heptanes 9.8 Octanes 7.4 Cycloparaffins 1.9 Benzene 0.1

a As reported by EMEP/CORINAIR, 2006. 

### In addition, API and the Western States Petroleum Association (WSPA) conducted emissions source tests of petroleum refining sources and ha ve compiled emissions factors for controlled asphalt blowing (Hansell and England, 1998 ). The average emissions factors are presented in Table 5-10 . These factors are recommended for estimating speciated emissions from controlled asphalt blowing units.

Table 5- 10 . Summary of Emissions Factors for Controlled Asphalt Blowing

CAS Number Substance Mean Emissions Factor a With Blow Cycle and Thermal Oxidizer (lb/MMcf) b With Blow

Cycle and Thermal Oxidiz er (lb/MM Btu ) b Without Blow

Cycle and w ith Thermal Oxidizer (lb/MMcf) b Without Blow

Cycle and w ith Thermal Oxidizer (lb/MM Btu ) b
75

- 07

- 0 Acetaldehyde 1. 8E

- 03 1.67E

- 06 4.3E

- 03 4. 1 E

- 06 7440

- 28

- 2 Arsenic 1.3E - 02 1.2E

- 05 1. 2 E

- 02 1. 1 E

- 05 71

- 43

- 2 Benzene 3. 2 E - 01 3.0 E

- 04 2.8E

- 01 2.6E

- 04 7440

- 41

- 7 Beryllium 2.6E - 03 2. 5 E

- 06 2.3E

- 03 2. 2 E

- 06 7440

- 43

- 9 Cadmium 5. 3 E - 03 4.9E

- 06 4. 7

E - 03 4. 4 E

- 06 18540

- 29

- 9 Chromium

(hex avalent ) 3. 2 E

- 03 3.0 E

- 06 3. 3 E - 03 3. 1 E

- 06

7440

- 47

- 3 Chromium (total) 4. 2 E

- 02 3.9E

- 05 1.4E - 02 1.3E

- 05 7440

- 50

- 8 Copper 4. 8 E

- 02 4. 5 E

- 05 3. 8 E

- 02 3.6E

- 05 100

- 41

- 4 Ethylbenzene 8.6E - 01 8.1E

- 04 7.6E

- 01 7. 2 E

- 04 50

- 00

- 0 Formaldehyde 3. 6 E

- 03 3.3E

- 06 1.3E

- 02 1.2E

- 05 7647

- 01

- 0 Hydrogen chloride 2.2E

- 03 2. 1 E

- 06 8.2E

- 04 7.7E

- 07 7783

- 06

- 4 Hydrogen sulfi de 2. 1 E+00 2.0 E - 03 1.8E+00 1.7E - 03 7439

- 92

- 1 Lead 5. 3 E - 02 4.9E

- 05 4. 7

E - 02 4. 4 E

- 05 (continued)

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5-21 T able 5 - 10
. Summary of Emission s Factors for Controlled Asphalt Blowing (continued)

CAS Number Substance Mean Emissions Factor a
With Blow Cycle and Ther mal Oxidizer (lb/MMcf) b With Blow

Cycle and Thermal Oxidizer (lb/MM Btu ) b Without Blow

Cycle and w ith Thermal Oxidizer (lb/MMcf) b Without Blow

Cycle and w ith Thermal Oxidizer (lb/MM Btu ) b
7439

- 96

- 5 Manganese 1.2E

- 01 1. 2 E

- 04 2. 1 E

- 01 2.0 E

- 04 7439

- 97

- 6 Mercu ry 9. 1 E

- 03 8.5E

- 06 8.5E

- 03 8.0E

- 06 7440

- 02

- 0 Nickel 6. 7 E - 02 6. 3 E

- 05 6.0E

- 02 5. 7

E - 05 108

- 95

- 2 Phenol 7. 6 E

- 02 7.1E

- 05 4.6E

- 02 4. 4 E

- 05 7782

- 49

- 2 Selenium 1.3E - 02 1.2E

- 05 1. 2 E

- 02 1. 1 E

- 05 1330

- 20

- 7 Xylene (total) 8.6E - 01 8.1E

- 04 7.6E

- 01 7. 2 E

- 04 7440

- 6 6

- 6 Zinc 8.4E

- 01 7.9E

- 04 5. 4 E

- 01 5.0E

- 04 Note: lb/MMcf = pounds per million cubic feet asphalt fumes, lb/MMBtu = pounds per million British thermal units
a Bold italic values indicate that all test runs were below detection limit. b Source: Hansell and England , 1998. 

### 5.6.3 Coke Calcining Coke calcining is one of the processes tested by API and WSPA for which emissions factors were developed (Hansell and England, 1998). The average emissions factors for a coke calcining unit controlled with a spray dryer and fabric filter are presented in Table 5-11

.

Table 5- 11 . Summary of Emissions Factors for Controlled Coke Calcining

CAS Number Substance Mean Emissions Factor a lb/ ton coke b lb/MM Btu b 83

- 32

- 9 Acenaphthene 1. 5 E

- 08 4.4E

- 08 208

- 96

- 8 Acenaphthylene 1.8E

- 08 5. 6 E

- 08 75

- 07

- 0 Acetaldehyde 1.0E

- 03 3.1E

- 03 107

- 02

- 8 Acrolein 3. 4 E - 04 1.0E - 03 120

- 12

- 7 Anthracene 1.8E

- 08 5.4E

- 08 7440

- 36

- 0 Antimony 4.6E

- 05 1.4E

- 04 7440

- 28

- 2 Arsenic 4. 7 E - 06 1.5E - 05 7440

- 39

- 3 Barium 2.0 E

- 05 6.1E

- 05 71

- 43

- 2 Benzene 3 .2E

- 04 1.0E

- 03 56

- 55

- 3 Benzo(a)anthracene 8.7E

- 09 2.6E

- 08 50

- 32

- 8 Benzo(a)pyrene 8. 1 E - 09 2.4E - 08 205

- 99

- 2 Benzo(b)fluoranthene 8. 1 E - 09 2.4E - 08 191

- 24

- 2 Benzo(g,h,i)perylene 8. 1 E - 09 2.4E - 08 (continued)

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5-22 T able 5 - 11
. Summary of Emission s Factors fo r Controlled Coke Calcining (continued)

CAS Number Substance Mean Emissions Factor a lb/ ton coke b lb/MM Btu b 207

- 08

- 9 Benzo(k)fluoranthene 8. 1 E - 09 2.4E - 08 7440

- 41

- 7 Beryllium 1.9E

- 06 6.0E

- 06 7440

- 43

- 9 Cadmium 9.3E - 06 2.9E

- 05 18540

- 29

- 9 Chromium ( h ex avalent ) 6.3E

- 07 2.1E

- 06 7440

- 47

- 3 Chromium ( t otal) 2. 1 E

- 05 6.9E

- 05 218

- 01

- 9 Chrysene 1. 3 E

- 08 3.7E

- 08 7440

- 50

- 8 Copper 9.3E - 06 2.9E - 05 53

- 70

- 3 Dibenz(a,h)anthracene 8. 1 E - 09 2.4E - 08 1746

- 01

- 6 Dioxin:4D 2378 1.1E - 11 3. 7 E - 11 Dioxin:4D Other 1. 4E

- 10 4.4E

- 10 40321

- 76

- 4 Dioxin:5D 12378 9. 6E - 12 2.9E - 11 Dioxin:5D Other 8.5E

- 11 2.7E

- 10 39227

- 28

- 6 Dioxin:6D 123478 9.9E

- 12 3. 5E

- 11 57653

- 85

- 7 Dioxin:6D 123678 1. 4 E

- 11 4.4E

- 11 19408

- 74

- 3 Dioxin:6D 123789 1. 3 E

- 11 4.2E

- 11

Dioxin:6D Other 6. 4 E

- 11 2. 1 E

- 10 35822

- 46

- 9 Dioxin:7D 1234678 1. 4 E

- 10 4. 2 E

- 10

Dioxin:7D Other 1.3E

- 10 4. 1 E

- 10 3268

- 87

- 9 Dioxin:8D 1. 8 E

- 09 5. 3 E

- 09 206

- 44

- 0 Fluoranthene 3. 6 E

- 08 1. 1 E

- 07 86

- 73

- 7 Fluorene 5.6E

- 08 1.7E

- 07 50

- 00

- 0 Formaldehyde 3. 4 E - 04 1.0E - 03 51207

- 31

- 9 Furan:4F 2378 1.3E

- 11 4.2E

- 11

Furan:4F Other 1. 4 E

- 10 4. 4 E

- 10 57117

- 41

- 6 Furan:5F 12378 1. 4 E

- 11 4.4E

- 11 57117

- 31

- 4 Furan:5F 23478 1. 3 E

- 11 4. 1 E

- 11

Furan:5F Other 1.2E

- 10 3. 8 E

- 10 70648

- 26

- 9 Furan:6F 123478 2.4E

- 11 7. 9 E

- 11 57117

- 44

- 9 Furan:6F 12 3678 2.2E

- 11 7.1E

- 11 72918

- 21

- 9 Furan:6F 123789 9. 2 E

- 12 3.0 E

- 11 60851

- 34

- 5 Furan:6F 234678 2.0E

- 11 6.5E

- 11

Furan:6F Other 1.5E

- 10 4.8E

- 10 67562

- 39

- 4 Furan:7F 1234678 1.5E

- 10 4. 8 E

- 10 55673

- 89

- 7 Furan:7F 1234789 2.6E

- 11 8.0E

- 11

Furan:7F Other 5. 2 E

- 11 1. 8 E

- 10 39001

- 02

- 0 Furan:8F 1. 5 E

- 10 4.1E

- 10 (continued)

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5-23 T able 5 - 11
. Summary of Emission s Factors fo r Controlled Coke Calcining (continued)

CAS Number Substance Mean Emissions Factor a lb/ ton coke b lb/MM Btu b 193

- 39

- 5 Indeno(1,2,3

- cd)pyrene 8. 1 E - 09 2.4E - 08 7439

- 92

- 1 Lead 6.2E

- 05 1.9E

- 04 7439

- 96

- 5 Manganese 4. 6E

- 05 1.4E

- 04 7439

- 97

- 6 Mercury 4.6E

- 05 1. 5 E

- 04 91

- 20

- 3 Naphthalene 2.4E

- 06 7. 3 E

- 06 7440

- 02

- 0 Nickel 9. 1 E

- 05 2. 9 E

- 04 85

- 01

- 8 Phenanthrene 1. 9 E

- 07 5. 7 E

- 07 7723

- 14

- 0 Phosphorus 4. 7 E - 04 1.5E - 03 129

- 00

- 0 Pyrene 2.7E

- 08 7. 9 E

- 08 7782

- 49

- 2 Selenium 4. 7 E - 06 1.5E - 05 108

- 88

- 3 Toluene 5.3E

- 05 1.6E

- 04 1330

- 20

- 7 Xylene (m,p) 3. 1 E

- 0 5 8.9E

- 05 95

- 47

- 6 Xylene (o) 4. 5 E - 05 1.3E - 04 7440

- 66

- 6 Zinc 1. 2 E

- 04 3. 7 E

- 04 Note: lb/ton coke = pounds per ton of petroleum coke, lb/MMBtu = pounds per million British thermal units Abbreviations: 4D 2378 = 2,3,7,8

- Tetrachlorodibenzo

- p - dioxin; 5D 1237 8 = 1,2,3,7,8

- Pentachlorodibenzo

- p - dioxin; 6D 123478 = 1,2,3,4,7,8

- Hexachlorodibenzo

- p - dioxin; 6D 123678 = 1,2,3,6,7,8

- Hexachlorodibenzo

- p - dioxin; 6D 123789 = 1,2,3,7,8,9

- Hexachlorodibenzo

- p - dioxin; 7D 1234678 = 1,2,3,4,6,7,8

- Heptachlorodibenzo

- p - dioxin; 8 D = Octachlorodibenzo

- p - dioxin; 4F 2378 = 2,3,7,8

- Tetrachlorodibenzofuran; 5F 12378 = 1,2,3,7,8

- Pentachlorodibenzofuran; 5F 23478 = 2,3,4,7,8

- Pentachlorodibenzofuran; 6F 123478 = 1,2,3,4,7,8

- Hexachlorodibenzofuran; 6F 123678 = 1,2,3,6,7,8

- Hexachlorodibenzo furan; 6F 123789 = 1,2,3,7,8,9

- Hexachlorodibenzofuran; 6F 234678 = 2,3,4,6,7,8

- Hexachlorodibenzofuran; 7F 1234678 = 1,2,3,4,6,7,8

- Heptachlorodibenzofuran; 7F 1234789 = 1,2,3,4,7,8,9

- Heptachlorodibenzofuran; 8F = Octachlorodibenzofuran.
a Emissions factors provided are for coke calcining controlled with a spray dryer and fabric filter. Bold italic v alues indicate that all test runs were below detection limit ; u nderlined values indicate that more than 75 % of the test runs were below the detection limit

. b S ource : Hansell and England , 1998. 

### 5.6.4 Blowdown Systems Blowdown systems are used during depressurization processes to recover liquids entrained in a process gas stream. The remaining uncondensed gases may be compressed and recovered for use as fuel gas or they may be vented to a thermal destruction device (thermal oxidizer or flare). Either of these scenarios would be considered a ―controlled‖ blowdown system. In an ―uncontrolled‖ blowdown system, the uncondensed gases are vented directly to the atmosphere. For blowdown gases that are recovered as fuel gas, the emissions from these gases would be accounted for in the emissions projected for stationary combustion devices (see Section 4). AP -42 (U.S. EPA, 1995a) contains a default emission factors uncontrolled blowdown systems as well as blowdown systems that recover the vapors for destruction in a flare. For systems controlled by a flare, the measurement methodologies provided in Section 6, Flares , should be used preferentially over these default emission factors, but these factors may provide an estimate of the portion of the flare’s emissions originate from blowdown gases. The AP-42 default emission factors for blowdown systems are provided in Table 5-12

.

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5-24 Table 5- 12 . Default Emissions Factors for Blowdown Systems

Process Description Pollutant Emission s F actor a ( lb / 10 3 barrel of refinery

feed ) Rating Uncontrolled blowdown Total hydrocarbons b 580 C Blowdown System with vapor recovery and flaring Carbon monoxide 4.3 C Nitrogen oxides 19 C Sulfur dioxi de 27 C Total hydrocarbons b 0.8 C

a Source: U.S. EPA, 1995a

. b Total hydrocarbon may be estimated as a surrogate for VOC

. ( Overall, less than 1 weight % of total hydrocarbon emissions is methane.)


### 5.6.5 Vacuum Producing Systems Vacuum producing systems include reciprocating, rotary or centrifugal blower or compressors, or any jet ejector or device that takes suction from a pressure below atmospheric and discharges against atmospheric pressure. Depending on the vacuum producing system design, gases from the system may be released directly to the atmosphere or may be condensed, to the extent possible, using a condenser. The condensed liquid is gathered in a ―hot well‖ or ― accumulator ‖ and the uncondensed gases are discharged to a control device or directly to the atmosphere. The vacuum producing system associated with the vacuum distillation column is typically the largest vacuum producing system at a petroleum refinery; vacuum producing systems may also be used to evacuate reactor vessels or vacuum trucks. AP -42 provides a total hydrocabon emission factor for the vacuum distillation column condenser. Speciation of the gases can be estimated based on the composition in the condensed liquids and assuming the gases are saturated (in equilibrium) with the condensed liquid. If the emissions are controlled, a control device efficiency correction can be used to estimate the controlled emissions.

Table 5-13. Default Emissions Factor for Vacuum Producing Systems

Process Description Pollutant Emission s F actor a ( lb / 10 3 barrel of vacuum feed ) Rating Vacuum producing system on vacuum distillation column, u ncontrolled Total hydrocarbons b 50 C

a Source: U.S. EPA, 1995a

. b Total hydrocarbon may be estimated as a surrogate for VOC

. ( Overall, less than 1 weight % of to tal hydrocarbon emissions is methane.)

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6-1 

# 6. Flares Flares are point sources used at petroleum refineries to destroy organic compounds in excess refinery fuel gas, purged products, or waste gases released during startups, shutdowns, and malfunctions. Most flares have a natural gas pilot flame and use the fuel value of the gas routed to the flare to sustain combustion. If the heating value of the flare gas falls below certain values (for steam or air assisted flares, typically 300 British thermal units per standard cubic feet [Btu/scf]), then natural gas may be added to the flare gas to maintain the appropriate heating value for good combustion. Emissions from flares consist of a fraction of the hydrocarbons in the flare gas (e.g., CH 4 

### , CO, VOC, and specific organic HAP) that are not combusted in the flare; SO 2 

### resulting from the oxidation of sulfur compound impurities, such as H 2 

### S, in the gas stream; and CO 2 

### from the combustion process. Flares are also expected to produce NO x 

### emissions and may produce PM (soot) if combustion conditions are not adequate. A complete emissions inventory will include estimates for all these compounds (the specific organic HAP will vary based on the composition of the gas being flared). Accurate estimates of emissions from flares are difficult to obtain because they do not lend themselves to conventional emissions-testing techniques, and only a few attempts have been made to characterize flare emissions. Therefore, to date, there are limited direct emissions test data for flares. Recent developments in testing protocols, such as the DIAL technique, provide a direct emission s measurement technique for flares. However, DIAL measurements provide only a snapshot in time. Unless the flow and composition of the flare gas is highly stable, inaccuracies build as these measurements are extrapolated to annual emissions rates. Continuous monitoring of the gas stream prior to combustion in the flare is generally the most accurate means of assessing flare emissions. One difficulty with this approach is that flare gas composition and flow are highly variable, and the monitors are calibrated to detect compositions or flows within a certain range or span, so if the flow or composition is outside the instrument’s range, then inaccuracies in the measurement data result. In addition, because the monitors are evaluating the stream of gas going to the flare, assumptions must be made regarding flare efficiency to determine the emissions following combustion. Engineering calculations are another methodology that can be used to assess certain release events. For example, if a pressure relief valve on a tank opens, then the volume of gas released can be calculated based on the pressure at which the valve opens, the pressure at which the valve recloses, and the volume of the tank. Product knowledge of the material in the tank can be used to estimate the composition of the gas vented. Some emissions factors are available, but these have highuncertainty. EPA concludes that direct measurement methods are best used to develop site- or flarespecific emissions factors or to verify the combustion efficiency of a specific flare under certain conditions; however, they are not particularly useful in developing an emissions inventory for flares. Table 6-1 summarizes the hierarchy of flare emissions estimation techniques. Within a given measurement method (or rank), there may be alternative methods for determining the constituent-specific emissions; these compositional analysis methods are provided in order of accuracy. Each refinery will likely use a mixture of different methods. For example, Methodology Rank 1 for flares may be used for events that are directly monitored and are fairly routine releases, but Methodology Rank 4 for flares may have to be used to estimate emissions for unusual events. The remainder of this section provides additional detail and guidance regarding the implementation of these methods.

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6-2 Table 6-1. Summary of Flare Emissions Estimate Methodologies Rank Measurement Method Additional Data Needed 1 Contin uous composition and flow rate monitoring of the gas sent to the flare 

##  Combustion efficiency (based on results of a direct measurement test, if available, or a default assumption) 2 Continuous flow rate monitoring and periodic compositional analysis 

##  Repre sentative sample (grab or integrated)



##  Assumed combustion efficiency 3 Continuous flow rate and heating value monitoring 

##  Emissions factors based on heating value
4 Engineering calculations 

##  Process knowledge of units connected to flare (e.g., volume, compo sition of process streams)



##  Temperature and pressure monitoring data or other process operating data as needed



##  Assumed combustion efficiency 5 Emission s factors based on energy consumption 

##  Flow estimates (not continuous)



##  Heat value estimates (not continuou s) 6 Default e mission s factors based on refinery or process throughput 

##  Refinery or process throughput 

## 6.1 Methodology Rank 1 for Flares Methodology Rank 1 for flares includes continuously measuring composition and flow of gas sent to the flare. For a flare, the most likely pollutants to be estimated using Methodology Rank 1 are SO 2 

### and total hydrocarbons (or VOC). For example, a reduced sulfur or total sulfur monitor can be used to characterize the sulfur content of the gas being combusted in the flare. Similarly, monitoring of the total hydrocarbon, VOC, or specific organic HAP content in the flare gas can be used to assess the emissions of these pollutants. However, because these monitors measure the concentrations in the gas sent to the flare rather th an the gas exiting the flare, the other piece of information needed to estimate emissions from the flare is the flare efficiency (F eff



### ). For the example of sulfur content above, the portion of the sulfur that is oxidized to SO 2 

### emissions during the combustion of the flare gas will be dependent on the combustion efficiency. For emissions of compounds that are emitted as a result of incomplete combustion, such as reduced sulfur compounds and uncombusted hydrocarbons, one minus the assumed flare efficiency (1- F eff 

### ) is used to estimate the emissions rate. As noted above, direct measurement methods are available and can be used to confirm the efficiency of a flare. If efficiency information is available for a specific flare at a refinery under certain conditions, that information should be used to estimate emissions for that flare where appropriate. For other flares, Section 13.5 of Compilation of Air Pollutant Emission Factors notes that the flare combustion efficiency for properly operated flares is at least 98% (U.S. EPA, 1995a). It is important to note that only flares that operate consistent with the criteria of 40 CFR 60.18 should be assumed to be ―properly operating‖ and achieving 98% combustion efficiency. It should also be noted that recent efforts to better characterize flare emissions include efforts to determine whether this combustion efficiency continues to be appropriate for properly operated flares. At this time, sufficient data have not yet been collected and evaluated to support revising this efficiency estimate. Most gas composition monitors measure the concentration on a volume basis (and generally on a dry basis), although some will provide the concentration on a mass basis. Most flow monitors measure volumetric flow rate in actual cubic feet. Many flow monitoring systems are equipped with temperature and pressure monitors to automatically convert the flow to standard conditions. If the gas composition is determined on a dry basis, which is typical for extractive monitoring systems, then it is important to also

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6-3 correct the flow to be on a dry basis. The total volumetric flow of the pollutant can be converted to a mass emissions rate using the molecular weight of the pollutant and/or the ideal gas law, as appropriate. An emissions estimate can be calculated using Equation 6-1, which is a variation of Equation 4-1 for CEMS:
(Eq. 6-1)

where: E i 

### = Emissions rate of pollutant ― i ‖ (tons per year [tons/yr] ). N = Number of measurement periods per year (e.g., for hourly measurements, N = 8,760 ). n = Index for measurement period. K eff



### = Factor to account for the efficiency of the flare. K eff 

### is equal to the flare efficiency F eff 

### for pollutants created by combustion, such as SO 2 

### . K eff 

### is equal to one minus the flare efficiency (1

–

F eff 

### ) for pollutants in uncombusted gas, such as VOC, reduced sulfur, and specific HAP. (Q) n



### = Volumetric flow rate of gas being combusted for measurement period ― n ‖ (actual cubic feet per minute [acfm] ). If the flow rate meter automatically corrects for temperature and pressure, then replace ― (T) o 

### ÷ (T) n 

### × (P) n 

### ÷ (P) o 

### ‖ with ―1

. ‖ If the pollutant concentration is determined on a dry basis and the flow rate meter automatically corrects for moisture content, replace the term [1- (f H20 

### ) n 

### ] with 1. (f H2O 

### ) n 

### = Moisture content of exhaust gas during measurement period ― n, ‖ volumetric basis (cubic feet water per cubic feet exhaust gas). (C i 

### ) n 

### = Concentration of pollutant ― i ‖ in the exhaust gas for measurement period ― n ‖ (volume %, dry basis). If the pollutant concentration is determined on a wet basis, then replace the term [1

− (f

H20 

### ) n 

### ] with 1. MW i 

### = Molecular weight of pollutant ― i ‖ (kilogram per kilogram mole [kg/kg -mol]). MVC = Molar volume conversion factor = 849.5 standard cubic feet per kilogram mole

(scf/ kg -mol) at 60°F (520 °R ) and 1 atmosphere (atm). T o 

### = Temperature at ―standard conditions‖ (520 °R ). T n



### = Temperature at which flow is measured during measurement period ― n ‖ (°R). P n 

### = Average pressure at which flow is measured during measurement period ― n ‖ (atm). P o 

### = Average pressure at ―standard conditions‖ (1 atm). M N 

### = Minutes per measurement period (minutes per measurement period ― n ‖). This term can

be calculated by dividing 525,600 minutes per year (min/yr) by the number of measurement periods per year (―N‖). K = Conversion factor = 2.2046/2,000 (tons per kilogram [tons/kg] = 0.0011023 tons/kg. As explained in Section 4-1, a continuous monitor records multiple measurements per hour, and the individual measurements can be used to calculate annual emissions in two ways. For a flare, the selection of an hourly average approach or heavier reliance on individual measurements will depend on the duration of the flare’s operation (particularly for flares that operate only intermittently) and the proces s unit generating the gas being flared. 

## 6.2 Methodology Rank 2 for Flares Methodology Rank 2 for flares includes continuous monitoring of flare gas flow as in Methodology Rank 1 for flares and routine (daily or weekly) sampling and analysis to determine the composition of the flare gas. Methodology Rank 2 also includes determining composition by continuously monitoring a ―surrogate‖ component, and then using sampling or other data to periodically check a correlation between the surrogate and the pollutant. For a flare, the most likely pollutants to be estimated using Methodology Rank 2 for flares are SO 2 

### and specific HAP. A continuous monitor for H 2 

### S can be used to estimate SO 2

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6-4 emissions similar to the process described for Methodology Rank 1, but because H 2 

### S is only one of several sulfur compounds potentially present in the flare gas, it is important to periodically characterize the total sulfur content of the gas so as not to underestimate SO 2 

### emissions from the flare. For example, periodic sampling of the flare gas can be performed to determine the total sulfur content of the flare gas, which can be used in conjunction with the H 2 

### S monitoring data to determine an average total sulfur- to

H 2 

### S ratio of the flare gas. This average total sulfur- to -H 2 

### S ratio, expressed in SO 2 

### equivalence, can be used to adjust the H 2 

### S concentration measured by the continuous monitor to provide a more accurate and complete assessment of SO 2 

### emissions from the flare. Similarly, sampling can be used to determine the relative concentration of specific HAP present in the flare gas. These sampling data can be used in conjunction with total hydrocarbon monitoring data to estimate HAP emissions from the flare. As with the Methodology Rank 1 for flares, the generation or destruction of pollutants in the flare will depend on the flare combustion efficiency. As mentioned previously, the current default flare combustion efficiency for properly operating flares is 98% (U.S. EPA, 1995a). 

## 6.3 Methodology Rank 3 for Flares Methodology Rank 3 for flares includes continuous monitoring of flare gas flow as in Methodology Rank 1 for flares, continuous monitoring of the heating value of the fuel, and emissions factors based on the heating value. The most likely pollutants estimated using Methodology Rank 3 for flares are CO, NO x 

### , and total hydrocarbons (surrogate for VOC). A general equation for Methodology Rank 3 for flares is as follows: (Eq. 6-2)

E i 

### = Emissions rate of pollutant ― i ‖ (tons/yr ). N = Number of measurement periods per year (e.g., for hourly measurements, N = 8,760 ). n = Index for measurement period. HV n 

### = Heating value of gas being flared during measurement period ― n ‖ (MMBtu/scf). (Heating value for flares is usually determined on a lower (net) heating value (LHV) basis.) FR n 

### = Flow rate of gas being flared for measurement period ― n ‖ (scfm). M N 

### = Minutes per measurement period (minutes per measurement period ― n ‖). This term can

be calculated by dividing 525,600 min/yr by the number of measurement periods per year (―N‖). EF i 

### = Emissions factor for pollutant ―i‖ (lb/MMBtu). Values for ―EF i 

### ‖ are presented in Tables 6-2 and 6-3 below. It is important to note that both sets of emissions factors are intended for use with properly operating flares meeting the criteria of 40 CFR 60.18; therefore, the flare efficiency is already included in these emissions factors. It is also important to note that the number of components for which emissions factors are available is limited because these emissions factors are based on general combustion characteristics and limited emissions tests. For example, the emissions factors for NO x 

### are generally based on the amount of nitrogen in the air during combustion, so if there are constituents containing nitrogen in the fuel gas, such as ammonia, additional calculations are needed to account for all NO x 

### emissions (based on Methodology Rank 2 for flares, particularly if flow rate is monitored continuously.) The emissions factors in Table 6-2 are from Section 13.5 of EPA’s Compilation of Air Pollutant Emission Factors (U.S. EPA, 1995a) and have an emissions factor rating of ―B‖ ( U.S. EPA, 1995a, for details on the emissions factor rating system). These flare emissions factors are based on limited EPA tests conducted decades ago. Although AP-42 does not specify, it is common practice that the heating

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6-5 value for flares is determined on a LHV basis. As such, it is recommended that these emissions factors be used with LHV heat content measurements.

Table 6-2. Flare Energy Consumption-Based Emissions Factors

Component Emission s F actor a ( lb / 10 6 Btu ) Total hydrocarbons b 0.14 Carbon monoxide (CAS No. 630

- 08

- 0 ) 0.37 Nitrogen oxides 0.068

a Source: U.S. EPA, 1995a

. b Measured as methane equivalent

. 

### The emissions factors in Table 6-3 are from Te chnical Supplement 4 of TCEQ’s 2008 Emissions Inventory Guidelines (TCEQ, 2009). The emissions factor rating for these emissions factors is not specified. These flare emissions factors are intended to be used with LHV, or net heating value, heat content measurements.

Table 6-3. TCEQ Energy Consumption-Based Emissions Factors for Flares
Component Assist Type Waste Gas Stream Net Heating Value a Emission s F actor ( lb / MMBtu ) b

Nitrogen oxides Steam High Btu 0.049 Low Btu 0.068

Air or Unassisted High Btu 0.1 4 Low Btu 0.064

Carbon monoxide (CAS No. 630

- 08

- 0 ) Steam High Btu 0.35 Low Btu 0.35

Air or Unassisted High Btu 0.28 Low Btu 0.55

a High Btu: > 1000 Btu/scf; Low Btu: 192

– 1000 Btu/scf b Source: TCEQ, 2009.

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6-6 

## 6.4 Methodology Rank 4 for Flares Methodology Rank 4 for flares includes a variety of estimation methods based on engineering calculations. Estimates of nearly all pollutants from flares can be calculated using this rank based on process knowledge of units connected to the flare, including process unit volume, process stream compositions, temperature, and pressure. Any of this information used in conjunction with periodic sampling also constitutes Methodology Rank 4. The specific methods used will vary based on the ways in which the flare is used and the units the flare serves. Estimating emissions from flares with routine flow, such as those used for controlling blowdown from delayed coking units or other routine discharges, may rely on key process operating parameters that can be defined in advance. For process upsets or malfunctions, the estimation methods used may be very event-focused and are likely to rely on engineering judgment as much as actual monitoring data. Estimation methods may also be needed from flares with monitoring systems when an upset or malfunction causes the concentration or flow to exceed the calibrated span of the monitor. A few examples are described in this section, but many others are possible, given the complexity of refineries and differences between them. When emissions are estimated using Methodology Rank 4 for flares, a description of the methodology, assumptions, and specific pieces of data should be recorded and kept for future reference, both to document the emissions calculation methodology and to ensure consistency from one estimate to the next for a particular process. For routine or planned releases from flares not equipped with a continuous monitor, the refiner should know the quantity and composition of the gas being released. If the gas is excess fuel gas that has been amine-treated and mixed in a central drum, then the H 2 

### S concentration of the gas being flared should be the same as the concentration going to any fuel gas combustion device (e.g., process heater, boiler) at the refinery. (As noted previously, it is important to note that H 2 

### S may not be the only reduced sulfur compound contributing to SO 2 

### emissions.) Alternatively, if a fuel gas combustion device has an instrument for measuring SO 2 

### emissions, then the SO 2 

### emissions from the flare can be calculated based on Example 6 - 1: Calculation of CO Emissions from a Flare with Continuous Monitors for

Flow Rate and Heating Value Calculate hourly emissions from a refinery flare given:



## – The flaring event is from one source at the refinery and lasts several hours, so emissions can be estimated using the hourly average flow rate and heat content measurements



## – The average flow rate to the flare during a certain hour is 250 scfm



## – The higher heating value of the flow to the flare during that hour is 1200 Btu/scf, or 1.2E

- 03 MMBtu/scf (1200 Btu/scf × 1E

- 06Btu/MMBtu) Calculate hourly emissions using Equation 6

- 2:

E CO 

### = (1.2E

- 03) × ( 250) × (60) × (0.37)

E CO 

### = 6.7 lbs/hr If the flaring event lasts 3 hours, and the flow rate and heat content remain ed perfectly constant over those 3 hours, then the total emissions for that flaring event would be 6.7 lbs/hr × 3 hours = 20 lbs

. Annual emissions for the flare would be calculated as the sum of emissions estimates for all events.

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6-7 the quantities of gas being combusted in the fuel gas combustion device and the flare. If the efficiency of that fuel gas combustion device and the flare are not the same, then an efficiency correction may be needed. (This method would account for all sulfur from the flare since SO 2 

### emissions would be measured directly.) As another example, if a refiner is emptying a tank and combusting the vapors, VOC and HAP emissions can be calculated based on the composition of the tank contents and the size of the tank. For emergency flares and flares with flare gas recovery systems (or otherwise equipped with water seals intended to prevent gases from going to the flare during normal operations), an alternative method of estimating flow rate for non-routine flaring events is to monitor the pressure drop across the flare water seal drum. A limited number of flow measurements can be made at different flare gas and water seal differential pressures (or water heights) to develop a flow rate correlation with the measured pressure drop. The water seal differential pressure or water height is routinely measured to determine the flow to the flare. Alternatively, the pressure in the flare line can also be monitored using a direct pressure monitor installed at the final liquid knock-out drum prior to the water seal. Concentrations of specific compounds are estimated by sampling and analysis of the flare gases (preferred, if possible) or calculations based on the composition of the gases in the process unit(s) contributing to the flaring event. Emissions are then calculated using those concentrations, the calculated flow rate, and an assumed flare efficiency. Some refiners that use this method for flares with a flare gas recovery system also monitor the recovery system to ensure that gases are not sent to the flare during normal operation. 

## 6. 5 Methodology Ranks 5 and 6 for Flares As previously mentioned, flares are difficult to test, so only a few emissions factors have been developed for flares. Most of the available emissions factors were provided in Tables 6-2 and 6-3 for use with continuous flow and heat content monitoring. Methodology Rank 5 for flares consists of using these emissions factors Additional emissions factors for soot (PM) appear in Section 13.5 of EPA’s Compilation of Air Pollutant Emission Factors (U.S. EPA, 1995a) and are also provided here in Table 6-4 . As mentioned previously, these flare emissions factors are based on limited EPA tests conducted decades ago and have an emissions factor rating of ―B.‖ Methodology Rank 5 for flares consists of using the emissions factors in Tables 6-2 , 6-3 , or 6-4 with estimates of the energy consumption of each flare in British thermal units and constitute Methodology Rank 5 for flares. The total hydrocarbon emissions factor could be used with knowledge of the components in the flare gas to estimate HAP emissions. Table 6-4. Emissions Factors for Soot from Flares
Flare Operation Emission s F actor a ( μg/L ) Nonsmoking flares 0 Lightly smo king flares 40 Average smoking flares 177 Heavily smoking flares 274

a Source: U.S. EPA, 1995a

. Note: μg/L = micrograms per liter 

### Methodology Rank 6 for flares includes emissions factors for HAP that were developed for the Petroleum Refinery Source Characterization and Emission Model for Residual Risk Assessment (RTI, 2002) based on the State of Louisiana’s title V permit applications data. The original emissions factors presented in RTI’s document (2002) were based on arithmetic averages. However, the arithmetic average is occasionally skewed by one high estimate. The log-mean average emissions factors from the State of Louisiana’s title V permit applications data were calculated and are provided in Table 6-5 . These

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6-8 emissions factors yield a cumulative emissions estimate from all flares (not per flare) for the refinery based on the total refinery crude capacity in barrels per calendar day (bbl/cd). It is uncertain how the permit application estimates were developed and whether these estimates include SSM events, but it is likely that these factors would not include emissions released during significant SSM events. As such, these emissions factors are very general and are not recommended unless no other information is available. Refineries are expected to have more source-specific information for estimating flare emissions, but these factors may be used for the purposes of modeling or for general emissions estimates.
Table 6-5. Flare General Emissions Factors a

CAS Number Component Emission s F actor ( tons/yr / bbl/cd ) 71

- 43

- 2 Benzene 9 E

- 0 6 108

- 88

- 3 Toluene 7 E

- 0 6 1330

- 20

- 7 Xylene 6 E

- 0 6 1634

- 04

- 4 Methyl tertiary

- butyl ether 3 E

- 0 6 110

- 54

- 3 Hexane 1 E

- 0 5 50

- 00

- 0 Formaldehyde 1 E

- 0 6 100

- 41

- 4 Ethylbenzene 2 E

- 0 7 106

- 99

- 0 1,3

- Butadiene 7 E

- 0 6

a Source: Log

- mean average from State of Louisiana ’s title V permit applications data 

### The application of these emissions factors is straightforward, using Equation 6-3. (Eq. 6-3) where: E i 

### = Mass emissions per year of pollutant ―i‖ (tons/ yr) Cap = Crude capacity of refinery (bbl/cd)

EF i 

### = Emissions factor for pollutant ―i‖ (tons/yr /bbl/cd) Example 6-2 shows the calculation of emissions from flares at a refinery with a given crude capacity.

Exa mple 6 - 2: Emissions Factor Given that a refinery has a crude capacity of 100,000 bbl/cd crude capacity, the annual emissions of benzene (C 6 

### H 6 

### ) emissions can be calculated from flares at the refinery as follows:

E C6H6 

### = (100,000) × (9E

- 06) E C6H6 

### = 0.9 tons/yr

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7-1 

# 7. Wastewater Collection and Treatment Systems Industrial wastewater collection and treatment operations range from simple pre-treatment operations that discharge to publicly owned treatment works (POTW) to a full-scale treatment systems. Full-scale treatment systems include the collection of process and/or storm water that is treated to a quality that is acceptable for discharge to a receiving water body or for re-use. Wastewater collection systems differ among facilities, but they generally include drains, manholes, trenches, lift stations, sumps, junction boxes, and/or weirs. As water passes through each of these system components, emissions may occur by volatilization of organic compounds at the water/air interface. The overall objectives of wastewater treatment at refineries are to: (1) equalize flow and pollutant load by buffering flow surges in large tanks, (2) separate free and emulsified oils and solids from the wastewater by oil/water separators and flotation unit operations (e.g., dissolved air flotation [DAF], induced air flotation [IAF], dissolved nitrogen flotation [DNF]), and (3) oxidize organic molecules and remove or transform nutrients through biodegradation. Figure 7-1 shows a typical full-scale refinery wastewater treatment scheme.

Figure 7- 1. Typical refinery wastewater treatment system. 

### Tanks or treatment units upstream of any benzene removal or destruction systems (e.g., stream strippers, enhanced biodegradation units) at most petroleum refineries are regulated under BWON (Benz en e Waste Operations NESHAP) and thus should be covered and vented to appropriate control devices. Equalization tanks, oil/water separators, and flotation units typically fall into this category; however, in the event these units are not covered because they do not contain high benzene quantities, emissions estimation methods are presented in this Refinery Emissions Protocol document. Biological treatment units are typically the first uncovered process in the wastewater treatment system and thus the first air emissions source. Limited data are available to characterize emissions from unsealed process drains and other uncovered or unsealed processes in the wastewater treatment system, and emissions from these processes are not addressed at this time.

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7-2 Table 7-1 lists the emissions estimation methods for wastewater treatment systems. The methods are ranked according to anticipated reliability. There are three primary estimation methods: (1) direct measurement, (2) predictive modeling, and (3) engineering estimates. Direct measurements can only be taken from process units that are covered and vented to a control device. Predictive modeling can be accomplished with using analytical equations, such as those presented in AP-42, by computer-based fate and transport models (e.g., WATER9, TOXCHEM, BASTE) or by using the simplified refinery wastewater emissions tool presented in this Refinery Emissions Protocol document. Engineering estimates can be made using emissions factors based on crude throughput or wastewater load.

Table 7-1. Summary of Wastewater Treatment Emissions Estimates Rank Measurement Method Application Data Requirements 1 Direct measurement Covered and vented units  Constituent load and speciation of collected gas samples 2a Predictive modeling with sit e specific factors and biodegradation rates followed by validation Uncovered units  Constituent load and speciation of process wastewaters

 Site

- specific biodegradation rates

 Model validation by a direct measurement method 2b Predictive modeling with site

s pecific factors and biodegradation rates Uncovered units  Constituent load and speciation of process wastewaters

 Site

- specific biodegradation rates 2c Predictive modeling with site

specific factors Uncovered units  Constituent load and speciation of process wastewaters 3a Engineering estimates based on wastewater treatment plant load Uncovered units  Constituent load and speciation of process wastewaters 3b Engineering estimates based on crude throughput Uncovered units  Crude throughput 

## 7.1 Methodology Rank 1 for Covered and Vented Units Emissions from covered and vented process units and drainage system components can be estimated by the methods summarized in Section 5, Process Vents , of this Refinery Emissions Protocol document. Although there are direct measurement methods for uncovered units (i.e., off gas collectors and DIAL techniques), these methods do not provide continuous monitoring data. Therefore, these methods are not recommended as primary techniques for emissions estimations, but are reasonable for predictive modeling validation. 

## 7.2 Methodology Rank 2 for Uncovered Units Air emissions estimation modeling techniques use mathematical equations to predict the fate and transport of specific constituents in wastewater. Figure 7-2 is a simplified drawing illustrating the mass balance of a wastewater constituent as it passes through a biological treatment unit. With the appropriate information, such as constituent concentration and physical properties, reaction kinetics, and flow-in and flow-out of the control volume, predictive models can estimate air emissions without direct measurement. Specifically, factors that impact volatilization and thus air emissions in a biological treatment unit are: (1) gas and liquid-phase mass transfer coefficients for quiescent water surfaces, (2) gas and liquid-phase mass transfer coefficients for turbulent water surface, (3) constituent biodegradation rate, (4) the type of aeration used (diffused or mechanical), and (5) adsorption of the constituent to the biomass. The general steps in predictive modeling for each process unit are to determine: 1. The overall liquid-phase mass transfer coefficient

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7-3 2. The overall gas-phase mass transfer coefficient 3. The overall oil-phase mass transfer coefficient (for oil-water separators) 4. The overall mass transfer coefficient 5. The air emissions 6. The effluent concentration of each unit.

Figure 7-2. Simplified drawing of a constituent mass balance in a biological treatment unit. 

### Although successful use of the available predictive models has been demonstrated, reporting facilities have expressed concerns regarding complexity, user friendliness, and accuracy; therefore, a simplistic refinery wastewater emissions tool has been developed as part of this document to address these issues. This tool is designed to help the user identify critical model inputs for each process unit, recognize variables and constants that may be site-specific, and calculate air emissions and constituent effluent concentrations. Additionally, constituent effluent concentrations from a treatment unit can be used as inputs for the next downstream unit when processes are linked in a series (e.g., oil-water separator effluent data equals input data for the DAF unit). The ― Critical Inputs ‖ section of the refinery wastewater emissions tool includes data that is required to estimate air emissions from the specific process unit. The ― Variables with Default Values ‖ section includes inputs that may be site-specific or unknown to the user. Default values are taken from AP-42, but they can be changed if more accurate data are known or determined. The Chemical Properties sheet contains the best available chemical, physical, and biodegradation information on the 30 organic HAP listed in the Petroleum Refinery MACT I. However, if more accurate or site-specific data are available, then these data can be inserted in the Site-Specific Table on the Chemical Properties sheet, and the model will override the default values. Detailed instructions for use and application are provided in the refinery wastewater emissions tool. Since reliable variables to estimate emissions for all volatile organic compounds (VOC) are not available, air emission estimates for compounds not listed in the MACT I can be made using surrogate compounds. Butane is the surrogate compound used for C 2 

### – C 4 

### VOC and octane for C 4 

### – C 9 

### in the refinery wastewater emissions tool. Air emission estimates for compounds not listed and considered non-volatile (e.g., > C 9 

### and Henry’s law const ant > 10 -3 

### atm-m 3 

### /gmol) can be made using the ―Compound A, B, or C rows in the tool. The following list of chemical, physical, and biological degradation properties for each compound are required to reliably estimate air emissions:

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7-4 1. Molecular weight 2. Vapor pressure 3. Henry’s law constant 4. Diffusivity in water 5. Diffusivity in air 6. Octanol-water partitioning coefficient 7. Maximum biorate constant 8. Half saturation biorate constant [Insert link to refinery wastewater emissions tool here] The calculations used in the refinery wastewater emissions tool and variable definitions are based on those presented in AP-42 and included in the Appendix B, Wastewater Treatment System Equations , of this section and alternatively can be used to manually calculate emissions. 7.2.1 Primary Weirs Weirs can serve as open-channel dams and utilized in settling basins to discharge cleaner effluent. As previously stated, these components of the wastewater collection system are typically covered and vented; therefore, open-air emissions estimations are not required. However, if the treatment units are uncovered, then the refinery wastewater emissions tool can be used to estimate air emissions. Table 7-2 lists the critical inputs, variables with default values, and chemical properties specific to weirs.

Table 7-2. Critical Inputs, Variables, and Chemical Properties Specific

to Primary Weir Air Emissions Calculations Critical Inputs Variable s with Default Values Chemical Properties Wastewater flow rate (Q) Diffusivity of oxyg en in water (D O2 , w ) Diffusivity of constituent in water (D w ) Constituent influent concentration (C 0 ) Weir height (h) 

### 7.2.2 Junction Boxes and Lift Stations Junction boxes and lift stations collect and equalize wastewater prior to pumping to the wastewater treatment system. As previously mentioned, these treatment units are typically covered and vented; therefore, open-air emissions estimations are not required. However, if the treatment units are uncovered, then the refinery wastewater emissions tool can be used to estimate air emissions. Table 7-3 lists the critical inputs, variables with default values, and chemical properties specific to junction boxes and lift stations. Table 7-3. Critical Inputs, Variables, and Chemical Properties Specific

to Junction Box and Lift Station Air Emissions Calculations Critical Inputs Variable s with Default Values Chemical Properties Surface area (A) Density of water (ρ L ) Diffusivity of constituent in air (D a ) Temperature (T) Viscosity of water (μ L ) Diffusivity of constituent in water (D w ) (continued)

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7-5 Table 7 - 3 . Critical Inputs, Variables, and Chemical Properties Specific to Junction Box and Lift Station Air Emission s Calculations (continued) Critical Inputs Variable s with Default Values Chemical Properties Wind speed (U 10 ) Density of air (ρ air ) Henry’s law constant Wastewater flow rate (Q) Molecular weight of air (MW air ) Constituent influent concentration (C 0 ) Viscosity of air ( μ a ) Turbulent surface area (A T ) Universal gas constant (R) Total power to aerators (P tot ) Rotational speed of impeller (w) Oxygen transfer correction factor (O t ) Oxygen transfer rating to surface area (J) I mpeller diameter (d) 

### 7.2.3 Oil-Water Separators An oil-water separator is a treatment unit designed to separate oil and suspended solids from wastewater. As previously mentioned, these treatment units are typically covered and vented; therefore, open-air emissions estimations are not required. However, if the treatment units are uncovered, then the refinery wastewater emissions tool can be used to estimate air emissions. Table 7-4 lists the critical inputs, variables with default values, and chemical properties specific to oil-water separators.

Table 7-4. Critical Inputs, Variables, and Chemical Properties Specific

to Oil-Water Separators Air Emissions Calculations Critical Inputs Variable s with Default Values Chemical Properties Surface area (A) Flow of oil (Q oil ) Diffusivity of constituent in air (D a ) Oil layer thickness (O layer ) Density of oil (ρ oil ) Octanol

– water partitioning coefficient (Kow) Total pressure (P 0 ) Molecular weight of oil (MW oil ) Vapor pressure of constituent (P*) Wastewater flow rate (Q) Density of air (ρ air ) Constituent influent concentration (C 0 ) Molecular weight of air (MW air ) Wind speed (U 10 ) Viscosity of air ( μ a ) Fraction of volume that is oil (FO) 

### 7.2.4 Dissolved Air Flotation Units DAF is a wastewater treatment unit that uses bubble flotation to remove suspended oil and solids from water. As previously mentioned, these treatment units are typically covered and vented to control devices. However, if the treatment units are uncovered, then the refinery wastewater emissions tool can be used to estimate air emissions. Table 7-5 lists the critical inputs, variables with default values, and chemical properties specific to DAF units.

Table 7-5. Critical Inputs, Variables, and Chemical Properties Specific

to DAF Air Emissions Calculations Critical Inputs Variable s with Default Values Chemical Properties Surface area (A) Viscosity of water (μ L ) Diffusivity of constituent in air (D a ) Temperature (T) Density o f water (ρ L ) Diffusivity of constituent in water (D w ) Total pressure (P 0 ) Mol ecular weight of water (MW L ) Henry’s law constant (H) (continued)

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7-6 Table 7 - 5 . Critical Inputs, Variables, and Chemical Properties Specific

to DAF Air Emission s Calculations (continued) Critical Inputs Variable s with Default Values Chemical Properti es Wastewater flow rate (Q) Density of air (ρ air ) Constituent influent concentration (C 0 ) Molecular weight of air (MW air ) Diffused air flow rate (Q a ) Viscosity of air ( μ a ) Wind speed (U 10 ) 

### 7.2.5 Equalization Tanks Equalization tanks dampen variations in wastewater flow rate and pollutant load to lessen negative impacts on downstream processes. As previously mentioned, these tanks should be covered and vented; however, if the treatment units are uncovered, then the refinery wastewater emissions tool can be used to estimate air emissions. Table 7-6 lists the critical inputs, variables with default values, and chemical properties specific to equalization tanks.

Table 7-6. Critical Inputs, Variables, and Chemical Properties Specific

to Equalization Tank Air Emissions Calculations Critical Inputs Variable s with Default Values Chemical Properties Surface area (A) Density of water (ρ L ) Diffusivity of constituent in air (D a ) Temperature (T) Viscosity of water (μ L ) Diffusivity of constituent in water (D w ) Total pressure (P 0 ) Density of air (ρ air ) Henry’s law constant Wastewater flow rate (Q) Molecular weight of air (MW air ) Constituent influent concentration (C 0 ) Viscosity of air ( μ a ) Wastewater depth (D) Rotational speed of impeller (w) Total power to aerators (P tot ) Quiescent surface area (A Q ) Number of aerators (N I ) Oxygen transfer correction factor (O t ) Turbulent surface area (A T ) Oxygen transfer rating to surface area (J) Wind speed (U 10 ) Impeller diameter (d) 

### 7.2.6 Biological Treatment Units Biological treatment is an effective process to reduce, remove, or transform organic constituents and nutrients typically found in refinery wastewater to an acceptable form or concentration prior to discharge or re-use. However, biological treatment units are complex and vary greatly in design, operation, and treatment efficiency, resulting in units that are difficult to characterize. Multiple fate and transport mechanisms are often involved in the ultimate removal of a specific compound. Specifically, biodegradation, volatilization, adsorption, hydrolysis, and photo degradation are common mechanisms in wastewater treatment that may compete against each other. Additionally, biological systems are dynamic in nature, resulting in shifts in the dominant fate mechanism. Therefore, it is important to obtain and use site-specific variables when estimating emissions to obtain accurate results. The two primary classes of biological treatment units are suspended-growth and attached-growth systems. Suspended-growth systems maintain the biomass (flocs) in suspension by mechanical or aeration devices where biodegradation occurs. Examples of suspended-growth systems include activated sludge, aerated lagoons, sequencing batch reactors, and membrane bioreactors. Attached-growth systems establish

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7-7 biofilms on fixed surfaces where biochemical reactions occur. Examples of attached-growth systems include trickling filters, rotating biological contactors, and fluidized-bed reactors. Regardless of the type of biological treatment used, the biochemical reactions are generally the same, with the oxidation of organic compounds and ammonia forming new cells, CO 2 

### , and water. To maintain the health of the microorganisms and ensure adequate biologically mediated oxidation of the organic compounds and ammonia, O 2 

### must be introduced into the system. There are two basic methods for aerating wastewater: (1) introducing air or pure O 2 

### into the wastewater through diffusers or other devices, and (2) agitating the water to increase surface area and promote the gaseous exchange with the atmosphere. However, the mechanisms that increase dissolved oxygen concentration in the water also increase the emissions rate of organic constituents through increased volatilization. The volatilization rate can be affected by the wastewater surface area, turbulence, and temperature; hydraulic retention; water depth; concentration and physical properties of the organic constituents (e.g., volatility, diffusivity, inhibitory mechanisms); and atmospheric conditions. As previously mentioned, the biological treatment unit will most likely be the first uncovered process in the wastewater treatment system. Accordingly, these units will be the most likely to have air emissions that require estimation. Table 7-7 lists the critical inputs, variables with default values, and chemical properties specific to biological treatment unit air emissions calculations.

Table 7-7. Critical Inputs, Variables, and Chemical Properties Specific to Biological Treatment Unit Air Emissions Calculations Critical Inputs Va riable s with Default Values Chemical Properties Surface area (A) Density of water (ρ L ) Diffusivity of constituent in air (D a ) Temperature (T) Viscosity of water (μ L ) Diffusivity of constituent in water (D w ) Total pressure (P 0 ) Density of air (ρ air ) Henry’s law constant Wastewater flow rate (Q) Molecular weight of air (MW air ) Maximum biodegradation rate constant (K max ) Constituent influent concentration (C 0,X ) Viscosity of air ( μ a ) Half saturation biorate constant (K s ) Wastewater depth (D) Weight fraction of the total carbon in biomass (f OC ) Octanol

- water partitionin g coefficient (K ow ) Total power to aerators (P tot ) Quiescent surface area (A Q ) Number of aerators (N I ) Oxygen transfer correction factor (O t ) Mixed liquor volatile suspended solids (C MLVSS ) Oxygen transfer rating to surface area (J) Influent BOD con centration (C 0,BOD ) Impeller diameter (d) Wind speed (U 10 ) Rotational speed of impeller (w) Turbulent surface area (A T ) Biomass volatile suspended solids yield from influent biochemical oxygen demand (Y) Wasted sludge flow rate (Q w ) 

### 7.2.7 Polishing Ponds Although air emissions downstream of biological treatment should be minimal, ineffective treatment, constituent slugs, or hydraulic surges may lead to HAP contamination of tertiary treatment processes (i.e., polishing ponds). If air emissions estimates are needed for polishing ponds, then the equalization tank sheet of the refinery wastewater emissions tool can be used. Although polishing ponds may function as a

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7-8 plug-flow reactor, the assumption can be made that volatilization is the major constituent fate mechanism. If the polishing pond is aerated and has significant active biomass (> 40 milligrams per liter [mg/L] volatile suspended solids), the biological treatment sheet of the model may be used. 7.2.8 Site-Specific Factors There has been tremendous effort to compile default values for specific variables to estimate air emissions; however, site-specific data provide the most accurate results. The factors that can have the most dramatic impact on air emissions from a biological treatment unit are the ones impacting biodegradation. Compound-specific biodegradation rate constants (i.e., k 0 

### and k 1 

### ) and the half-saturation concentration (i.e., K S 

### ) can be determined by using the aerated reactor test (BOX test). The empirically derived values can then be used in a predictive model for more accurate results. Although time and cost are involved during this procedure, the facility is often awarded with lower emissions estimates. Moye and colleagues (2006) reported lower air emissions from a biological treatment unit compared to WATER9 predictions when site-specific biodegradation rates were determined and the constants were critically reviewed. The methods used to determine the fraction of organic constituent biodegraded areprovided in 40 CFR Part 63, Appendix C (also available at: http://www.epa.gov/EPAAIR/2004/June/Day-30/a14826.htm ). Although these methods have been successfully used to estimate biodegradation rates, there are concerns. Specifically, it is argued that dosing the bioreactor with only one constituent of interest yields inaccurate biodegradation rates compared to those dosed with a mixture of compounds commonly encountered by the microorganisms. Preferential biodegradation, degradation by-products, and co-metabolism are important factors to consider when determining biodegradation rates that are not addressed in the recommended methods. Yerushalmi and Guiot (1998) reported biodegradation rates of benzene and toluene that were 62.9 and 16.4 times greater, respectively, when used as the sole substrate, versus a mixture of organic compounds. It is recommended that the constituent of interest be dosed in the appropriate ratio with organic compounds found in the real-world system (as described in Appendix C). Additionally, the methods do not distinguish between biodegradation, hydrolysis, and adsorption. Rather, the results of the BOX test are a summation of the three primary fate mechanisms common to aerated bioreactors. This fact is important to consider when assessing all the fate mechanisms involved in compound degradation. 7.2.9 Model Validation To ensure that predictive model outputs are accurate, validation studies can be conducted to support the results. This task is accomplished by secondary direct or in-direct measurement techniques such as offgas collectors, DIAL, concentration-profile methods. Direct measurements are taken of a modeled process unit, and the results are compared. Favorable comparisons are indicative of accurate predictive modeling, whereas poor comparisons could be the result of incorrect assumptions or errors in the model. If corrective actions are necessary, a review of the constants and site-specific variables should be conducted. 

## 7.3 Methodology Rank 3 for Uncovered Units 7.3.1 Engineering Estimates Based on Wastewater Treatment Plant Load If a facility only has benzene wastewater concentration data, then this method can be used to estimate the unknown HAP concentrations for use in the predictive modeling methods in Section 7.2, Methodology Rank 2 for Uncovered Units . The wastewater generation rates, benzene concentrations, and total HAP concentrations presented in Table 7-8 (U.S. EPA, 1998a) were combined with the total U.S. refinery processing and production capacities reported by EIA (2009) to calculate an average wastewater mixture to determine an average benzene and total HAP concentration of refinery wastewater. These data were evaluated using the average petroleum stream composition provided in Appendix B, Wastewater Treatment System Equations , of this Refinery Emissions Protocol document and an evaluation of the log

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7-9 octanol water partition coefficient to help speciate the total HAP concentration before and after oil removal. The results of this analysis (see Table 7-9 ) are relative concentrations of key pollutants as a ratio of the benzene concentration. If the benzene concentration of the refinery wastewater is known, then the concentration of other organics in the wastewater can be estimated using the ratios in Table 7-9

. 7.3.2 Engineering Estimates Based on Pr ocess Capacities Facilities that do not have any of the required data to estimate air emissions (e.g., for proposed units) can use the factors in Table 7-8 to estimate wastewater generation rates and benzene concentrations to the wastewater treatment syste m. Either the factors in Table 7-8 can be used to estimate the total organic HAP concentration, or the factors in Table 7-9 can be used to estimate the specific HAP (and total HAP) concentrations of the wastewater. The generated data can then be used to estimate specific constituent wastewater loads (see Section 7.3.1, Engineering Estimates Based on Wastewater Treatment Plant Load ) and used in the predictive modeling methods in Section 7.2, Methodology Rank 2 for Uncovered Units . If the wastewater treatment system design is unknown, then the default emissions factors in Table 7-10 can be used to estimate the fraction of the total constituent load to the wastewater treatment system (calculated using the factors in Tables 7-8 and 7-9 ) that is expected to be released into the atmosphere. Table 7-8. Model Process Unit Characteristics for Petroleum Refinery Wastewater a

Process Unit Average Flow Factor b (gal/bbl) Average Benzene

Concentration c (ppmw) Average Organic

HAP Concentration (ppmw) Crude distillation 2.9 21 140 Alkylation unit 6 3 6.9 Catalytic reforming 1.5 106 238 Hydrocracking unit 2.6 14 72 Hydrotreating/hydrorefining 2.6 6.3 32 Catalytic cracking 2.4 13 165 Thermal cracking/coking 5.9 40 75 Thermal cracking/visbreaking 7. 1 40 75 Hydrogen plant 80 d 62 278 Asphalt plant 8.6 40 75 Product blending 2.9 24 1,810 Sulfur plant 9.7 e 0.8 3.4 Vacuum distillation 3 12 53 Full range distillation 4.5 12 65 Isomerization 1.5 33 117 Polymerization 3.5 0.01 0.04 MEK dewaxing unit s 0.011 0.1 27 Lube oil/specialty processing unit 2.5 40 75 Tank drawdown 0.02 188 840 Note: gal/bbl = gallons of wastewater per barrel of capacity at a given process unit , ppmw = parts per million by weight
a Source: U.S. EPA , 199 8

. b All flow factors were derived from Clean Air Act Section 114 questionnaire responses
c Average concentration in the wastewater d This flow factor is given in gallons per million cubic feet ( gal/MM ft 3 ) of gas production
e This flow factor is given in gal/ton of sulfur

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7-10 Table 7- 9. Refinery Wastewater Contaminant Concentrations as a Ratio to Benzene

CAS No. HAP Mass Concentration Ratio of Compounds to the Concentration of Benzene

Inlet to Oil - Water Separator or DAF Unit Inlet to Biological Treatmen t U nit ( A fter O il W ater S eparator) 540841 2,2,4

- Trimethylpentane 1.97 0.022 71432 Benzene 1.00 1.00 92524 Biphenyl 0.034 0.0005 1319773 Cresols 0.25 0.38 98828 Cumene 0.37 0.013 100414 Ethylbenzene 0.88 0.086 110543 Hexane 3.50 0.047 1634044 Methyl tertiary

- butyl ether 0.58 0.98 91203 Naphthalene 0.29 0.02 108952 Phenol 0.18 0.80 100425 Styrene 0.58 0.09 108883 Toluene 3.3 0.80 1330207 Xylene 3.6 0.33 106990 1,3

- Butadiene 0.0006 0.0027 VOC Total VOCs 81 17 

### Table 7- 10. Default Mass Emissions Factors for Refinery Wastewater Collection and Treatment Systems

CAS No. HAP Mass Fraction of Compound Emitted from Wastewater Collection and Treatment System Based

on Total Wastewater Loading Open Wastewater Collection and Treatment System BWON - Complia nt Wastewater Collection and Treatment System 540841 2,2,4

- Trimethylpentane 0.25 0.001 71432 Benzene 0.45 0.08 92524 Biphenyl 0.10 0.001 1319773 Cresols 0.05 0.001 98828 Cumene 0.15 0.005 100414 Ethylbenzene 0.15 0.01 110543 Hexane 0.25 0.002 16340 44 Methyl tertiary

- butyl ether 0.60 0.15 91203 Naphthalene 0.02 0.005 108952 Phenol 0.04 0.01 100425 Styrene 0.10 0.02 108883 Toluene 0.20 0.02 1330207 Xylene 0.15 0.01 106990 1,3

- Butadiene 1.00 0.5 VOC Total VOCs 0.25 0.05

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7-11 Example 7 - 1. Methodology Rank 3 for Wastewater A refinery has the following processing and production rates. The average annual emissions of hexane, benzene, toluene, and xylene can be estimated from the wastewater collection a nd treatment system for a BWON

- compliant refinery. Process Unit or Operation Average Throughput (bbl/cd) Atmospheric distillation 100,000 Vacuum distillation 50,000 Catalytic reforming 20,000 Catalytic cracking 40,000 Alkylation 10,000 Product blendi ng 60,000 Total crude and product tank throughput 180,000


### Use the factors in Table 7
- 6 and the density of water (ρ water 

### = 8.34 lb/gal) to estimate the total wastewater flow rate and benzene loading rate.

Process Unit or Operation (A)

Average Throughput ( bbl/cd) (B)

Wastewater Flow Factor (gal/bbl) (C) = A×B

Wastewater Flow (gal/cd) (D)

Benzene Concentration (ppmw) (E) = C×ρ×D/10 6

Benzene Mass Flow (lb/cd) Atmospheric distillation 100,000 2.9 290,000 21 50.8
Vacuum distillation 50,000 3 150,000 12 15.0 Catalytic reforming 20,000 1.5 30,000 106 26.5 Catalytic cracking 40,000 2.4 96,000 13 10.4 Alkylation 10,000 6 60,000 3 1.5 Product blending 60,000 2.9 174,000 24 34.8
Tank drawdown 180,000 0.02 3,600 188 5.6
Totals 803,600 144.7


### Use the factors in Table 7
- 7 to estimate the mass loading rate of other compounds and the BWON

- compliant emissions factors in Table 7
- 8 to estimate the annual emissions.

Compound (A)

Mass Ratio from Table 7 - 7 (B) = A×144.7

Mass Flow (lb/cd) (C) Emission Factor from Table 7 - 8 (D) = B×C×365/2000

Annual Emissions (tons/yr) Hexane 3.5 506.5 0.002 0.18 Benzene 1.0 144.7 0.08 2.1 Toluene 3.34 483.3 0.02 1.8 Xylene 3.57 516.6 0.01 0.94

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7-12

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8-1 

# 8. Cooling Towers Cooling water is used in refineries in heat exchange systems and condensers to cool or condense various product streams. The cooling water for a closed-loop recirculation system may be sent to a cooling tower, where it is cooled to near ambient temperature for reuse, and then is returned to the process or to refrigeration units for additional cooling. The cooling water for a once-through system may be cooled and se nt to a receiving waterbody. This section focuses on cooling towers because these are used predominately in the petroleum refining industry. Some refineries use once-through cooling systems (emissions estimates for once-through cooling systems can be estimated using essentially the same techniques used for cooling towers). Organic HAP and VOC are picked up by cooling water when leaks occur in heat exchangers or condensers. Product on the high-pressure side leaks through cracks in the exchanger and contaminates the water. Organic HAP, VOC, PM-10, and chlorine are subsequently emitted from the water into the atmosphere due to stripping (i.e., active air and water contact) in the cooling tower and due to drift loss. Large emissions on the order of tons per year can occur for low levels of contamination or concentration because refineries use large volumes of cooling water. Generally, CH 4 

### or other GHGs are not significant pollutants for cooling towers; however, if the cooling water is used on a high CH 4 

### process stream, then CH 4 

### emissions can be calculated using the same methods presented in this section for calculating volatile hydrocarbon emissions from cooling towers. The cooling tower emissions estimates require information on the cooling water flow rate and the composition of the process stream in the heat exchanger or in the condenser or refrigeration units. These emissions estimates are also dependent on the type of heat exchange monitoring system used. Table 8-1 summarizes the hierarchy of cooling tower emissions estimation techniques. The methods are ranked in terms of anticipated reliability. Within a given measurement method (or rank), there may be alternative methods for determining the constituent-specific emissions; these compositional analysis methods are also provided in order of reliability. The remainder of this section provides additional detail and guidance regarding the ways in which to implement these methods. In general, annual emissions from cooling towers should account for the full operating time of the cooling tower on an annual basis. Annual cooling tower emissions can be estimated using the measured concentrations for each monitoring period (whether the measured concentration constitutes a leak or not) and summing emissions over all monitoring periods or can be estimated using emission factors for the full annual operating time of the cooling tower.

Table 8-1. Summary of Cooling Tower Emissions Estimation Methodologies Rank Measurement Method or Emissions Factor Compositional Analysis Data 1 

##  Air stripping simulation using Appendix P ,

Modified El Paso m ethod a



##  Water recirculation rate 

##  Speciation of collected gas samples with EPA TO

14 or TO

- 15 methods, with EPA Method 18, or with a portable ( not handheld) gas chromatograph/flame ionization det ector 2 

##  Air stripping simulation using Appendix P,

Modified El Paso method a , using a flame ionization detection analyzer



##  Water recirculation rate 

##  Process

- specific, service

- specific concentrations



##  Process

- specific average concentrations



##  Site

- specific refi nery average stream concentrations



##  Default process compositions (continued)

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8-2 Table 8 - 1. Summary of Cooling Tower Emissions Estimation Methodologies (continued) Rank Measurement Method or Emissions Factor Compositional Analysis Data 3 

##  Direct water meas urement by EPA Method

8260B b before and after exposure to the atmosphere (e.g., at the cooling tower return line and at the outlet of cooling tower)



##  Water recirculation rate 

##  Speciation of collected water samples

4 

##  Direct water measurement by EPA Method

82 60 B b before exposure to the atmosphere (e.g., at the heat exchanger exit line, or at the cooling tower return line)



##  Water recirculation rate 

##  Speciation of collected water samples

5 

##  AP

- 42 emissions factor



##  Water recirculation rate OR



##  Material balance 

##  Proces s - specific, service

- specific concentrations



##  Process

- specific average concentrations



##  Site

- specific refinery average stream concentrations



##  Default process compositions

a Source: TCEQ , 2003. b Source: U.S. EPA, 1996. 

## 8.1 Methodology Ranks 1 and 2 for Cooling Towers The El Paso method (TCEQ, 2003) uses a flow-through system for air stripping a sample of water and analyzing the stripped gases for VOC using a flame ionization detection (FID) analyzer. This method measures the quantity of easily strippable components from the cooling water that have boiling points below 140°F. In this method, a continuous stream of cooling water is hard-piped to an air-stripping column apparatus. Air flowing countercurrent to the cooling water in the apparatus strips VOC and organic HAP from the water. Concentrations of pollutants in the stripping are measured, along with the air and water flow rates in the apparatus, to determine the concentrations of strippable VOC in the cooling water. At the apparatus air outlet, the concentrations may be measured using an on-site FID analyzer to determine the total strippable VOC (Methodology Rank 2 for cooling towers) or an on-site portable gas chromatograph (GC); (Methodology Rank 1 for cooling towers), or the concentrations may be measured by collecting samples in sample canisters for off-site laboratory analysis for speciation of air contaminants (Compendium Method TO-14A, Compendium Method TO-15, or Method 18 [which are all Rank 1 methods]).The data necessary to implement Methodology Ranks 1 and 2 for cooling towers include speciated airstripped compounds concentration, operating parameters of the air-stripping apparatus, and the cooling water flow rate. Table 8-2 summarizes the data requirements for Methodology Ranks 1 and 2.

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8-3 Table 8- 2. Data Requirements for VOC or Speciated VOC Emissions, Methodology Ranks 1 and 2 Rank D ata That M ust B e C ollected T he Way in Which D ata A re Ob tained Rank 1

— speciated VOC emissions 

##  Speciated air

- strippable VOC concentration

measured in the stripped air ( ppm v ) 

##  Periodic Appendix P testing results using an air

- stripp ing column apparatus , followed by TO

- 14A, TO

- 15, EPA M ethod 18 , or GC/FID



##  Sample water flow rate of the apparatus, stripping air flow rate of the apparatus, pressure in the air

- stripping column ap paratus chamber, and the temperature of stripping chamber 

##  Measurements during Appendix P testing



##  Cooling water flow recirculation rates (gal/min) 

##  Continuous measurements from pump flow rate curves, rotameters, or similar methods



##  Length of time of the monitoring period (hours) 

##  Assume the measured concentration has occurred for half of the time period since the last sampling date; if a leak occurs, then add the time period it takes to repair the leak Rank 2

— VOC emissions 

##  Air strippable VOC concentration measured

in the stripped air ( ppmv ) 

##  Periodic Appendix P testing results using an air stripp ing column apparatus , followed by FID



##  Sample water flow rate of the apparatus, stripping air flow rate of the apparatus , pressure in the air

- stripping column appa ratus chamber, and temperature of stripping chamber 

##  Measurements during Appendix P testing



##  Cooling water flow recirculation rates (gal/min) 

##  Continuous measurements from pump flow rate curves, rotameters, or similar methods



##  Length of time of the monit oring period (hours) 

##  Assume the measured concentration has occurred for half of the time period since the last sampling date; if a leak occurs, then add the time period it takes to repair the leak 

### For cooling towers servicing process streams with multiple components, it is best to determine speciated compounds for air-strippable compounds from the cooling water. For cooling towers servicing process streams with single components, using the FID analyzer is likely adequate. (Equation 8-1) should be used to calculate the concentration of the air-strippable components in the cooling water from the concentration detected in the stripped air outlet:
(Eq. 8-1)

where: C Water ,i 

### = Concentration of air strippable compound ―i‖ in the water ma trix (parts per million by

weight [ppmw]) C Air ,i 

### = Concentration of compound ―i‖ in the stripped air (parts per million by volume [ppmv]) MW = Molecular weight of the compound (grams per mole [g/mol]) P = Pressure in the air-stripping column apparatus chamber (inches [in.] of Hg) PC = Pressure conversion factor (0.03342 atmospheres per inch [atm/in.] of Hg) b stripairflow 

### = Stripping air flow rate of apparatus (milliliters per minute [mL/min])

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8-4 R = Universal gas constant (82.054 milliliters-atmospheres per mole-Kelvin [mL-atm/mol-K]) T = Stripping chamber temperature (°C) a samplewaterflow 

### = Sample water flow rate of apparatus (mL/min) When using the El Paso method (TCEQ, 2003), the calculated concentration of the compounds in the water matrix represents the concentration that was stripped and does not represent the total concentration of the compounds in the water matrix prior to stripping. As such, this calculated water concentration is referred to as the ―strippable pollutant concentration‖ in the coo ling water. In general, when estimating the total VOC based on the FID analyzer, use the molecular weight (MW) of the calibration gas. Typically, CH 4 

### is used for the calibration, so the MW for CH 4 

### (16 g/mol) would be used to estimate the total VOC concentr ation in the water and the emissions rate (reported ―as CH 4 

### ‖). Even when a different calibration gas is used, one may need to use the MW for CH 4 

### in the event a leak threshold is defined in units of ppmw or ppmv as CH 4 

### . In general, when the process stream is a single component, then the concentration on a CH 4 

### basis from the FID can be converted to specific compounds that are expected to be leaking by accounting for C (e.g., for benzene, C air



### × 1 mol of CH 4 

### × 1 mol of C/1 mol of CH 4 

### × 1 mol of C 6 

### H 6 

### /6 mol of C). For a multicomponent process stream, it is better to determine speciated compounds using a portable GC/FID, TO14A, TO -15, or Method 18. For portable GC results, in addition to calibration with a standard compound (CH 4 

### or propane), the response factor of the unit should be determined for typical compounds expected in the air-stripped stream. For speciated compound results from an off-site laboratory, the concentration in the water for specific compounds can be estimated using the MW for the respective compound (e.g., benzene MW is 78 g/mol). These speciated concentrations (calculated using the compound-specific MW) should be used when estimating emissions for the purposes of an emissions inventory. However, it is important to note that for specific regulatory purposes, these concentrations must be converted to a CH 4 

### basis (using the MW of CH 4 

### ) for comparison to a leak definition threshold that is on an ―as CH 4 

### ‖ basis.) The following equation (Equation 8-2) should be used to estimate emissions for air strippable total VOC from the cooling water: (Eq. 8-2)

where: E i 

### = Emissions of air strippable pollutant ―i‖ from the cooling water (tons/yr) Flow CoolingWater 

### = Flow rate of cooling water (gallons per minute [gal/min]) H Year 

### = Length of time of the monitoring period or the length of time a leak occurs (hr/yr) When C air ,i 

### is based on total VOC results from an FID analyzer (Methodology Rank 2 for cooling towers), pollutant ―i‖ is simply VOC. When C air ,i 

### is based on GC analysis results for individual species (Methodology Rank 1 for cooling towers) or based on site-specific or default species composition data (Methodology Rank 2 for cooling towers), pollutant ―i‖ will be the individual pollutant. If monitoring or sampling events occur regularly or periodically (i.e., quarterly or monthly), then concentration measurements for consecutive monitoring events can be used to estimate the average emissions rate during the intervening period by assigning each concentration measurement to half of the time period between monitoring/sampling events. If significant concentrations of organics are detected in the cooling water (i.e., a ―leak‖ is detected), then the measured concentration is also attributed to the time span from when the leak was discovered until the time when it was repaired. This method is analogous to

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8-5 the method used to annualize equipment leak emissions when periodic monitoring is used (see Example 2-4 in Section 2.2.2, Calculating Annual Average Equipment Leak Emissions , for additional details). When monitoring or sampling is not conducted regularly or periodically, any measured concentration should be used to calculate the average emissions rate from the cooling tower, assuming the concentration is constant for the entire year. In this situation, if the concentration measurement suggests a leak that is subsequently repaired, then use the initially determined ―leak‖ concentration for the entire reporting year up to the time when the leak was repaired.
Example 8 - 1: Calculation for Methodology Rank 1 for Cooling Towers Given: For hexane emissions from a cooling tower with a water recirculation rate of 32 ,000 gal/min , a hexane concentration in the stripped air of 5.0 ppmv, a pressure of 29.9 in. of Hg, strippable air flow in the apparatus of 2,500 mL/min, a temperature of 32°C, a sample water flow rate in the apparatus of 125 mL/min, sampling that occurs quarterly , and the leak repair took 45 days to complete. The foll owing equation for C Water,i 

### should be used to calculate the concentration of air strippable compound in the water :

Thus, the 5 ppmv hexane concentration in the air stream translates to 0.34 ppmw ―strippable‖ hexane in the cooling wat er. The following equation should be used to calculate the emissions of hexane for the quarterly monitoring period:

Based on a leak that occurs for 2,175 hours (i.e., one

- half of a 3

- month period [1,095 hours] plus 45 days to repa ir [1,080 hours]), the total emissions of hexane that were emitted into the atmosphere is 5.9 tons/yr.

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8-6 

## 8.2 Methodology Rank 3 for Cooling Towers Methodology Rank 3 is used to estimate emissions from cooling towers and involves using a mass balance approach based on sampling the cooling water before and after the cooling tower. Although Methodology Rank 3 has the potential to be as appropriately reliable as Methodology Ranks 1 or 2 for Example 8 - 2: Calculation for Methodology Rank 2 for Cooling Towers Given: For VOC and C 6 

### H 6 

### emissions from cooling water with a water recirculation rate of 25,000 gal/min , a VOC concentration in the stripped air of 14 ppmv (as CH 4 

### ), a pressure of 29.9 in. of Hg, strippable air flow in the apparatus of 2,500 mL/min, a temperature of 32°C , a sample water flow rate in the apparatus of 125 mL/min, sampling occurs quarterly , and the leak repair took 30 days to complete. The following equation (C Water,i 

### ) should be used to calculate the concentration of air strippable VOC compound in the water as CH 4 

### :

The following equation should be used to calculate the quarterly emissions of VOC, E i 

### :

The length of time of the leak was 1,815 hours (i.e., one

- half of a 3

- month period [1,095 hours] plus 30 days t o repair [ 720 hours]). The emissions of VOC emitted into the atmosphere are 2.0 tons/yr (based on CH 4 

### ). I f C 6 

### H 6 

### is expected to be leaking , t o estimate the leak , convert the CH 4 

### concentration to C 6 

### H 6 

### (similar to the conversion example on p. 8

- 4) and use Eq. 8

- 1 for C Water,i 

### to calculate the concentration of air strippable compound in the water :

Where: 14 ppmv of total air strippable VOC is equivalent to 2.3 ppmv of C 6 

### H 6 

### in the air stream. The 2.3 ppmv C 6 

### H 6 

### co ncentration in the air stream translates to 0.145 ppmw of ―strippable‖ C 6 

### H 6 

### in the cooling water. The following equation (Eq. 8

- 2) should be used to calculate the quarterly emissions of C 6 

### H 6 

### , E i 

### :

The total emissions of C 6 

### H 6 

### emitte d into the atmosphere is 1.6 tons/yr.

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8-7 large leakers, Rank 3 suffers from detection limit issues with water sampling techniques. Consequently, this monitoring approach will not detect the smaller leaks that could significantly contribute to VOC or HAP emissions. Cooling water typically has low concentrations of components and large volumes of flow rate, so direct water sampling typically requires analysis for low-level concentrations. A common method used for cooling water sampling is Method 8260B. In this method, the sample is introduced into a gas chromatography/mass spectrometry (GC/MS) system, the GC column is temperature programmed to separate the components, and the components are detected with MS. The results from the method are the concentrations of components in the cooling water. Typically, two cooling water samples are taken to estimate the emissions: one sample before and one sample after the cooling water has been exposed to the at mosphere. The change in the component concentration of the cooling water multiplied by the cooling water recirculation rate provides the quantity emitted into the atmosphere for the duration of the leak. The data necessary to implement Methodology Rank 3 for cooling towers include speciated compounds concentration in the cooling water and the cooling water flow rate. Table 8-3 summarizes the data requirements of Methodology Rank 3. Table 8-3. Data Requirements for Speciated Compound Emissions, Methodology Rank 3 Rank D ata That M ust B e C ollected T he Way in Which D ata A re Ob tained Rank 3

— speciated emissions 

##  Speciated compounds concentration

measured in the inlet cooling tower return line ( ppm w) 

##  Periodic sampling results using Method 8260 B, including a measure ment prior to exposure to the atmosphere



##  Speciated compounds concentration measured in the outlet cooling water ( ppm w) 

##  Periodic sampling results using Method 8260 B, including a measurement after exposure to the atmosphere



##  Cooling water flow recirculati on rates (gal/min) 

##  Continuous measurements from pump flow rate curves, rotameters, or similar methods



##  Length of time of the monitoring period (hours) 

##  Assume the measured concentration has occurred for half of the time period since the last sampling date; if a leak occurs, then add the time period it takes to repair the leak 

### The change in the component concentration in the cooling water before and after being exposed to the atmosphere is used, along with the cooling water recirculation rate, to estimate the emissions from the cooling water. The following equation (Equation 8-3) can be used to calculate the emissions of components from the cooling water. It is important to note that it is assumed that the drift loss and water make-up rates are small (in the range of 1% to 2%); therefore, flow ―in‖ is the same as flow ―out‖ and can be determined based on the water recirculation flow rate, regardless of where this measurement takes place.
(Eq. 8-3)

where: C i, In 

### = Concentration of comp onent ―i‖ in the cooling water prior to exposure to the

atmosphere (ppmw) C i, Out 

### = Concentration of component ―i‖ in the cooling water after exposure to the atmosphere

(ppmw)

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8-8 As shown in Equation 8-4, the total emissions from the cooling water are the sum of all component species emitted and can be summed specifically for VOC or organic HAP:
(Eq. 8-4)



## 8.3 Methodology Rank 4 for Cooling Towers Methodology Rank 4, similar to Methodology Rank 3, uses direct cooling water samples for analysis of VOC and HAP contained in the cooling water, and a water sample is taken and sent for laboratory analysis. Under Methodology Rank 4 for cooling towers, only one sample is taken of the cooling water prior to being exposed to the atmosphere to estimate emissions. In this method, it is assumed that 100% of the compound is emitted at the cooling tower. As such, this methodology will likely overestimate the cooling water emissions, and would be a conservative (i.e., resulting in greatest emissions) estimate. The data necessary to implement Methodology Rank 3 for cooling towers include speciated compounds concentration in the cooling water and the cooling water flow rate. Table 8-4 summarizes the data requirements of Methodology Rank 4. Example 8 - 3: Calculation for Methodology Rank 3 for Cooling Towers Given: Concentrations for C 6 

### H 6 

### in the cooling water are 0.220 ppmw before expo sure to the atmosphere and 0.080 ppmw after for a cooling tower with a cooling water recirculation rate of 55,000 gal/min, sampling occurs monthly , and the leak repair took 45 days to complete. For the following month, sampling showed C 6 

### H 6 

### concentrations o f 0.320 ppmw before and 0.100 ppmw after the cooling tower. The following equation (Eq. 8

- 3) should be used to calculate the emissions of C 6 

### H 6 

### , E i 

### for the first monitoring period (the length of time of the leak for this period is one half of 30 days [ 365 hours] ):

The following equation (Eq. 8

- 3) should be used to calculate the emissions of C 6 

### H 6 

### , E i 

### , for the second monitoring period plus remaining repair time (i.e., the length of time of the leak was 1,095 hours based on 1 month [7 30 hours] plus 15 remaining days to repair (365 hours]):

So the total C 6 

### H 6 

### emissions for this leak until repair are 4.0 tons (0.70 ton + 3.3 tons).

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8-9 Table 8-4. Data Requirements for Speciated Compound Emissions, Methodology Rank 4 Rank D ata That M ust B e C ollected T he Way in Which D ata A re Ob tained Rank 4

— speciated emissions 

##  Speciated compounds concentration measured in the inlet cooling t ower return line ( ppm w) 

##  Periodic sampling results using Method 8260 B, including a measurement prior to exposure to the atmosphere



##  Cooling water flow recirculation rates (gal/min) 

##  Continuous measurements from pump flow rate curves, rotameters, or similar methods



##  Length of time of the monitoring period (hours) 

##  Assume the measured concentration has occurred for half of the time period since the last sampling date; if a leak occurs, then add the time period it takes to repair the leak 

### The component concentration in the cooling water before being exposed to the atmosphere is used with the cooling water flow rate to estimate the emissions from the cooling water. The following equation (Equation 8-5) should be used to calculate the emissions of components from the cooling water:
(Eq. 8-5)

where: C i, In 

### = Concentration of component ―i‖ in the cooling water prior to exposure to the

atmosphere (ppmw) As shown in Equation 8-6, the total emissions from the cooling water are the sum of all component species emitted and can be summed specifically for VOC or organic HAP:
(Eq. 8-6)

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8-10 

## 8.4 Methodology Rank 5 for Cooling Towers 8.4.1 VOC and Organic HAP Methodology Rank 5 for cooling towers uses the uncontrolled VOC emissions factor given in AP-42 (U.S. EPA, 1995a; Section 5.1) of 6 pounds of total VOC per million gallons of water (MM gal)(equivalent to a concentration in the water of 0.7 ppmw). The controlled emissions factor provided in AP42 should not be used. The controlled emissions factor only applies to refineries that directly monitor for hydrocarbons (and organic HAP) and repair leaks when they occur, in which case the refineries would have monitoring data to conduct emissions estimates under Methodology Ranks 1, 2, 3, or 4 for cooling towers. To estimate HAP emissions, refineries should use site-specific information on the composition of processstreams cooled in heat exchangers and condensers if available. Process-specific concentrations, processspecific average concentrations, or site-specific refinery average stream concentrations should be used when available. If these data are not available, then a default average composition of all process streams at refineries was developed to estimate emissions for the Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC). This default average composition for the refinery industry, given in Appendix A, Average Stream Compositions , Table A-1 , may be used to speciate the VOC and generate HAP emissions estimates. The data necessary to implement the Methodology Rank 5 for cooling towers include the AP-42 uncontrolled VOC emissions factor, the cooling water flow rate, and the process stream composition. Table 8-5 summarizes the data requirements of Methodology Ranks 1 and 2. Example 8 - 4: Calculation for Methodology Rank 4 for Cooling Towers Given: Concentrations for C 6 

### H 6 

### in the cooling water are 0.220 ppmw before exposure to the atmosphe re for a cooling tower with a cooling water recirculation rate of 55,000 gal/min, sampling occurs monthly , and the leak repair took 45 days to complete. For the following month, sampling showed C 6 

### H 6 

### concentrations of 0.320 ppmw before the cooling tower. T he following equation (Eq, 8

- 5) should be used to calculate the emissions of C 6 

### H 6 

### , E i 

### , for the first monitoring period (the length of time of the leak for this period is one

- half of 30 days [365 hours]):

The following equation *Eq . 8

- 5) should be used to calculate the emissions of C 6 

### H 6 

### , E i 

### , for the second monitoring period plus remaining repair time (the length of leak for this period is 1,095 hours based on 1 month [730 hours] plus 15 remaining days to repair [ 365 hours]):

So the total C 6 

### H 6 

### emissions for this leak until repair are 5.9 tons (1.1 tons + 4.8 tons).

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8-11 Table 8-5. Data Requirements for VOC or Speciated VOC Emissions, Methodology Rank 5 Rank D ata That M ust B e C ollected T he Way in Which D ata A re Ob tained Rank 5

— estimated speciated emissions 

##  AP

- 42 uncontrolled emissions factor for c ooling towers of 6 pounds of VOC per million gallons of water 

##  Not applicable



##  Process stream composition data 

##  Measurement/sampling of process stream composition, engineering knowledge of process composition, or default average composition for the industry



##  Cooling water flow recirculation rates (gal/min) 

##  Continuous measurements from pump flow rate curves, rotameters, or similar methods



##  Length of time of the monitoring period (hours) 

##  Assume the leak occurs all year (8,760 hr/yr) 

### The following equation (Equation 8-7) should be used to estimate VOC emissions: (Eq. 8-7)

where: EF Unc 

### = Uncontrolled emissions factor for cooling towers of 6.0 pounds of VOC per 10 6



### gallons of cooling water from AP-42 (Section 5.1) The following equation (Equation 8-8) should be used to estimate the emissions for a particular species component: (Eq. 8-8)

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8-12 8.4.2 Particulate Matter Emissions Methodology Rank 5 for cooling towers uses the total liquid drift emission factor given in AP-42 (U.S. EPA, 1995a; Section 13.4) of 1.7 lb of drift per 1,000 gallons of water (lb/10 3 

### gal) for induced draft cooling towers and the total dissolved solids (TDS) weight fraction to estimate PM-10 emissions. This is a conservative PM-10 emission factor in that it assumes that all TDS are in the PM-10 size range. The site-specific TDS fraction in the cooling water should be used when available, the site-specific TDS fraction can be estimated from the TDS of the makeup water and the cycles of concentration ratio (ratio of the measured parameter for the cooling tower water such as conductivity, calcium, chlorides, or phosphate, to the measured parameter for the makeup water), or if these data are not available, then use Example 8 - 5: Calculation for Methodology Rank 5 for Cooling Towers Given: For VOC and HAP emissions from a cooling tower with a water recir culation rate of 25,000 gal/min that is servicing a heat exchanger cooling a gasoline stream. Using the default average composition for the industry for gasoline ( in liquid phase ), the following equation (Eq. 8

- 7) should be used to c alculate the annual emi ssions of VOC, E VOC 

### :

The following equation (Eq. 8

- 8) should be used to estimate the emissions for each HAP component in the gasoline stream. For example, to c alculate the annual emissions of C 6 

### H 6 

### , E i 

### , the liquid composition of 1. 61% of C 6 

### H 6 

### in the default average gasoline composition (see Appendix A, Average Stream Compositions ) should be used:

To estimate the default gasoline composition in liquid:

 1,3

- Butadiene of 0.0037% by weight; emissions are 0.0015 ton/yr

 T rimethylpentane of 4.72 % by weight; emissions are 1.9 ton s /yr

 Benzene of 1.61 % by weight; emissions are 0. 63 ton/yr

 Biphenyl of 0.01 % by weight; emissions are 0.0039 ton/yr

 Cresols of 0.789 % by weight; emissions are 0.31 ton/yr .



###  Cumene of 0.849 % b y weight; 0. 33 ton/yr

 Ethylbenzene of 1.605 % by weight; emissions are 0.6 3 ton/yr

 Hexane of 7.1 % by weight; emissions are 2.8 ton s /yr

 Methyl tert iary

- butyl ether of 3. 54 % by weight; emissions are 1.4 ton s /yr

 Naphthalene of 0.444 % by weight; emissions are 0 .18 ton/yr

 Phenol of 0.0 551 % by weight; emissions are 0.022 ton/yr

 Styrene of 3.5 % by weight; emissions are 1.4 ton s /yr

 Toluene of 7.21 % by weight; emissions are 2.8 ton s /yr

 Xylene of 7.17 % by weight; emissions are 2.8 ton s /yr

 Total HAP emission s are 1 5

. 2 tons/yr. The total HAP emissions for this cooling tower are 15.2 ton total HAP per year.

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8-13 the default average TDS fraction from AP-42, Table 13.4-2 of 20,600 ppmw. Other default average TDS fractions are provided for counter flow and cross flow cooling tower designs in AP-42 (U.S. EPA, 1995a; Section 13.4). (Eq. 8-9)

Example 8 - 7: Calculation for Annual Emissions from Cooling Towers Given: For PM

- 10 emissions from a cooling tower with a water recirculation rate of 25,000 gal/min and that is sampled monthly for TDS

. Using the site

- specific TDS fraction and the operating hours between measurements, equation (Eq. 8

- 9) should be used to c alculate the annual emissions of PM

- 10 , E PM10 

### .

1 Date 2

TDS C oncentration (ppmw) 3 Hours 4 Emissions (ton/month) Jan 10 (startup Jan 1) 360 96 0.044 February 4 520 600 0.398 March 4 780 672 0.668 April 4 1,100 720 1.01 May 4 1,260 720 1.16 June 4 2,300 744 2.18 July 4 3,500 720 3.21 August 4 5,500 744 5.22 September 4 4,600 744 4.36 October 4 1,700 720 1.56 November 4 2,100 744 1.99 December (shutdown Dec 1

- not operating in December) (2,100

- Use value from previous month) (648) 1.73
Total 7,872 24 ton/yr 

### Example 8 - 6: Calculation for Methodology Rank 5 for Cooling Towers Given: For PM

- 10 emis sions from a cooling tower with a water recirculation rate of 25,000 gal/min , that is servicing a heat exchanger cooling a gasoline stream , and that is in service all year
. Using the default average TDS weight fraction of 0.0206 (or 20,600 ppmw), the follo wing equation (Eq. 8

- 9) should be used to c alculate the annual emissions of PM

- 10 , E PM10 

### :

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8-14 8.4.3 Chlorine Emissions Site-specific material balance may be one method of estimating chlorine emissions. Otherwise, limited information is available regarding chlorine emissions factors for cooling towers. EPA is currently reviewing available data to develop guidance for estimating chlorine emissions from cooling towers. To aid indeveloping that guidance, EPA is seeking additional data and suggestions for emissions estimation methologies.

Example 8 - 8: Regulatory Note for Example Calculation for Methodology Rank 1 for

Cooling Towers
— How to Compare Speciated Concentration Results with Leak Definitions That Are Defined as Methane In the case in which a facility conducts monitoring that provides speciated results, for regulatory purposes these concentrations must be converted to a CH 4 

### basis for comparison to a leak definition that is on a CH 4 

### basis. Given: For hexane emissions from a cooling tower with a water recirculation rate of 3 2 ,000 gal/min , hexane concentration in the stripped air of 5 ppmv, a pressure of 29.9 in. of Hg, strippable air flow in the apparatus of 2,500 mL/min, a temperature of 32°C, a sample water flow rate in the apparatus of 125 mL/min, sampling that occurs quar terly , and a leak repair that took 45 days to complete. In this example, hexane concentration in the stripped air was given as 5 ppmv. The following equation should be used to convert this concentration to CH 4 

### basis:

If the leak de finition is 6.2 ppmv as CH 4 

### , then a leak has been detected because the hexane concentration is equivalent to 30 ppmv as CH 4 

### .

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9-1 

# 9. Product Loading Operations Product or commodity loading emissions occur when vapor is displaced by the liquid product when it is loaded into tank trucks, rail cars, and marine vessels (which include both ships and barges). The vapor may contain constituents from the material previously transported and from the product currently being loaded. HAP, VOC, and GHG are emitted from loading operations. Loading emissions estimates require information on the quantity of product loaded annually, the component composition of the product, vapor pressures of the components, the loading procedure, the type of vessel being loaded, and the effectiveness of the capture system and the controls used. Emissions from gasoline loading racks are regulated under the Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC) and are limited to 10 milligrams of TOCs per liter of gasoline (Subpart CC references Subpart R, which references some requirements for 40 CFR Part 60, Subpart XX). Emissions from marine vessel loading

– operations for crude, gasoline, and other products are also regulated under the Petroleum Refinery MACT I (Subpart CC references the Marine Vessel Loading MACT in 40 CFR Part 63, Subpart Y) and are subject to a 97% emissions-reduction requirement for existing sources and 98% emissions-reduction requirement for new sources. Product loading emissions may be reduced by using submerged loading or bottom loading. Product loading emissions may be captured and controlled using a vapor collection system and an add-on air pollution control device. If an add-on air pollution control device or a vapor balance system is used to capture and control emissions, then capture and control efficiencies should be included in the emissions estimate. Control devices used for product loading operations typically include thermal or catalytic incinerators, adsorption systems, scrubbers, and flares

. Vapor balancing systems are allowed as an option or an alternative for marine vessel loading operations under Subpart CC of the Petroleum Refinery MACT I. For loading racks subject to gasoline loading requirements, typically an EPA Method 25A or 25B performance test is conducted on the control device to collect outlet TOC concentration data and determine an outlet emissions factor based on the volume of gasoline loaded (i.e., meet the less than 10 milligrams of total hydrocarbon per liter gasoline loaded [mg/L]). For marine vessel loading subject to requirements under Subpart CC MACT I, typically, a Method 25 performance test is conducted on the control devices to collect inlet and outlet TOC concentration data and determine a control efficiency. Table 9-1 summarizes the hierarchy of product loading operation emissions estimation techniques. Within a given measurement method (or rank), there may be alternative methods for determining the constituent-specific emissions; these compositional analysis methods are also provided in order of accuracy. The remainder of this section provides additional details and guidance regarding the ways in which to implement these methods.

Table 9- 1. Summary of Product Loading Operations Emissions Estimates Rank Measurement Method or Emissions Factor Compositional Analysis Data 1 Direct measurement ( CEMS ) for both flow rate and gas composit ion  Pressure, temperature, and moisture content (depending on the monitoring system) 2 Direct measurement by EPA Method 18 (site

specific emissions factor) and loading rate  N ot applicable
3 Direct measurement by EPA Method 25, Method 25A , or Method 25B ( site

- specific emissions factor) and loading rates  Process

- specific, service

- specific concentrations

 Process

- specific average concentrations

 Site

- specific refinery average stream concentrations

 Default process compositions (continued)

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9-2 Table 9 - 1. Summary of Product Loading Operations Emission s Estimates (continued) Rank Measurement Method or Emissions Factor Compositional Analysis Data 4 AP

- 42 e missions f actor (default emissions factor) and loading rates  Process

- specific, service

- specific concentrations

 Process

- specific average concentrations

 Site

- specific refinery average stream concentrations

 Default process compositions 

## 9.1 Data Available on Product Composition and Properties To speciate the emissions into VOC or HAP, facilities should use site-specific information on the composition of product loaded if available (for more information, see Section 9.3.2, Estimate Controlled or Uncontrolled Emissions and Speciate). Data are often available on the product or commodity composition, sometimes for both the liquid and vapor phases and sometimes only for the liquid phase. Product-specific concentration, product-specific average concentration, or site-specific product concentrations should be used when available. If product-specific or site-specific data are not available, then a default average composition for products at refineries was developed to estimate emissions for the Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC). This default average composition for refineries may be used to speciate and generate VOC and HAP emissions factors, as shown in Table B-1 of Appendix B, Wastewater Treatment System Equations

. Other properties such as the MW of the liquid, the MW of the vapor, and the vapor pressure of a multicomponent product or commodity are also often available. When these data are not readily available at the refinery, data from various references can be used or can be calculated using basic principles. For instance, property data are available in AP-42, Section 7.1 ( Organic Liquid Storage Tanks ), in Table 7.1-2 for various petroleum fuels and in Table 7.1-3 for various petrochemicals (U.S. EPA, 1995a). If the weight composition of a commodity is available but other property data are not, estimates can be made. Appendix A presents equations that may be used for calculating estimates of the liquid vapor pressure, the molecular weight of the vapor, and the weight fraction of the vapor given a known liquid component composition. 

## 9.2 Methodology Rank 1 for Product Loading Operations For pollutants such as THC, it is anticipated that some loading operations may have CEMS for measuring the composition and the gas flow rate of the emissions from loading operations. If such monitors are present, the methods in Section 4.1, Methodology Rank 1 for Stationary Combustion Sources , should be used to calculate emissions. 

## 9.3 Methodology Ranks 2 and 3 for Product Loading Operations Performance testing conducted at the refinery may be used to develop site-specific emissions factors with emissions data correlated to throughput. These site-specific emissions factors may be used with throughput data to estimate the annual loading emissions. For gasoline loading activities regulated under Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC and Subpart R), refineries have conducted periodic EPA Method 18, Method 25A, or Method 25B testing for speciated hydrocarbons or for outlet nonmethane organic compounds (NMOC); determined the flow rate based on EPA Method 2A or 2B testing; and measured and recorded the gasoline loading throughput during the testing. The outlet test results on a mass basis are correlated with the gasoline throughput during the test to demonstrate that the refinery is meeting the 10 mg/L gasoline emissions limitation. The test data could also be used to estimate the speciated hydrocarbons, total hydrocarbon, CH 4 

### , NMOC, or VOC loading emissions into the atmosphere based on the mass emissions per volume loaded factor developed during the performance test and the annual quantity of that product loaded. It is important to

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9-3 note that when NMOC is used, a CH 4 

### emissions factor may also be developed. Additional information about speciation of the gasoline or product either as site-specific information or as defaults may be used to estimate individual species component emissions. For marine vessel loading regulated under the Marine Vessel Loading MACT (40 CFR Part 63, Subpart CC and Subpart Y), refineries have conducted EPA Method 2, 2A, 2C, or 2D flow rate testing and have conducted EPA Method 25 or 25A testing on the inlet and outlet streams of the control device to determine control device efficiency. The Marine Vessel Loading MACT requires initial performance testing of the control device, but it does not require ongoing or periodic testing. The outlet test data, along with the recorded product throughput during the testing, could also be used to estimate the total hydrocarbon, CH 4 

### , NMOC, or VOC loading emissions per volume loaded factor. This factor and the annual loading data of the product can be used to estimate emissions. It is important to note that when NMOC is used, a CH 4 

### emissions factor may also be developed. Additional information on speciation of the gasoline or product either as site-specific information or as defaults may be used to estimate individual species component emissions. The data necessary to implement Methodology Ranks 1 and 2 for product loading operations include the emissions rate or emissions factor (either speciated by component or as total hydrocarbon, CH 4 

### , NMOC, or VOC) and throughput data of the products loaded. Table 9-2 summarizes the data requirements of Methodology Ranks 1 and 2. Table 9-2. Data Requirements for VOC or Speciated Emissions, Methodology Rank 1 or 2 Rank D ata That M ust B e C ollected T he Way in Which D ata A re Ob tained R ank 2

— speciated emissions 

##  Speciated component emission s factor

for a product ( m illigrams per liter [mg/L] or lb/gal ) 

##  Periodic EPA Method 18 testing results



##  Throughput data by product over the time period of interest ( gal lons or liters ) 

##  Volume flow rate m easurements determined by flow meter or pump rates , gal lons, or liters Rank 3

— VOC or total hydrocarbon emissions 

##  Total hydrocarbon or VOC emission s

factor for a product ( mg/liter or lb/gal ) 

##  Periodic EPA Method 25 or 25A testing results



##  Throughput data b y product over the time period of interest ( gal lons or liters ) 

##  Volume flow rate measurements determined by flow meter or pump rates , gal lons, or liters 

### Equation 9-1 should be used to estimate the emissions of each product using emissions rates or emission s factors developed from testing. (Eq. 9-1)

where: E Li 

### = Emissions of component species ―i‖ (tons) ER Li 

### = Emissions rate of component species ―i‖ (lb/gal) Thruput = Throughput of product (gallons) When ER Li 

### is based on tota l hydrocarbon, NMOC, or VOC, pollutant ―i‖ is simply the total hydrocarbon, NMOC, or VOC. When ER Li 

### is based on single pollutant, pollutant ―i‖ will be the individual pollutant. When ER Li 

### is based on total hydrocarbon, NMOC, or VOC (i.e., Method 25, 25A, or 25B testing), additional calculations are necessary to estimate individual pollutant emissions. To estimate the emissions

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9-4 of each pollutant, multiply Equation 9-1 for E Li 

### by the vapor weight fraction of the component ―i‖, as shown in Equation 9-2. (Eq. 9-2)
where: E LSpecies 

### = Emissions of component species ―i‖ (tons) Wtfrac Species 

### = Vapor weight fraction of component species ―i‖ (fraction by weight) 

## 9.4 Methodology Rank 4 for Product Loading Operations The emissions estimating methodology for loading operations is given in AP-42 (U.S. EPA, 1995a). In section 5.2 of AP-42, commodities are categorized into crude loading, gasoline loading, and what is termed ―other products‖ (i.e., not crude or gasoline). In the AP -42 methodology, there is one equation that is used for tanker trucks and rail cars for crude, gasoline, and other commodity products and for marine vessels for other commodity products (but not for crude or gasoline). In addition, Table 5.2-2 in AP-42 presents other emissions factors that are used for marine vessels for gasoline. These equations provide the emissions for the ―product‖ or ―total hydrocarbon,‖ whether that product has multiple component species (e.g., gasoline) or whether that product is a single species (e.g., toluene ). Depending on the commodity being loaded, the emissions factor ( EF L 

### ) could be used for gasoline emissions, crude emissions, or other product emissions. The AP-42 methodology for gasoline and other products is summarized in the following sections. It is not expected that refineries will be loading crude for transport, but if so, the refiner should consult AP-42 for the emissions estimation methodology. 9.4.1 AP -42 Emissions Factors for ―Product‖ or ―Total Hydrocarbon‖ Emissions 9.4.1.1 Tanker Trucks (Any Commodity) and Marine Vessels (Products Other than

Gasoline) Equation 9-3 should be used to estimate the emissions factor or the emissions rate for the product loaded, in terms of total hydrocarbon or the product: (Eq. 9-3)
where: ER L



### = Loading emissions factor or emissions rate for the product (or total hydrocarbon) loaded (in lb per 10 3 

### gallons of liquid loaded) S = Saturation factor (see Table 9-3 ) P = True vapor pressure of liquid loaded (pounds per square inch absolute [psia]) 4 

### MW Vap 

### = Molecular weight of vapors (lb/mol) T = Temperature of bulk liquid loaded (°R; °F + 460)

4 

### True vapor pressure is defined as the equilibrium partial pressure exerted by a volatile organic liquid as a function of temperature. It differs from the Reid vapor pressure, which is defined as the absolute vapor pressure exerted by a liquid at 100 ° F and is a common measure of the volatility of petroleum liquids. For a pure component at 100 ° F, the true vapor pressure is equivalent to the Reid vapor pressure.

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9-5

Table 9-3. Saturation Factors a Type of T anker L oaded Loading S cenario Saturation F actor



##  Tank trucks


##  Rail cars


##  Any commodity 

##  Submerged l oading


##  Dedicated normal service 0.60



##  Submerged loading



##  Dedicated vapor balance service 1.00



##  Splash loading



##  Dedicated normal service 1.45



##  Splash loading



##  Dedicated vapor balance service 1.00



##  Marine vessels



##  Other products (only) 

##  Submerged loading



##  Ships 0.2



##  Submerged loading



##  Barges 0.5

a Source: U.S. EPA, 1995. 

### 9.4.1.2 Marine Vessels (Gasoline) Section 5.2, Table 5.2-2, of AP-42 provides VOC emissions factors for marine vessels loading gasoline at marine terminals based on measurements of gasoline loading losses from ships and barges. Those emissions factors are presented in Table 9-4 . (Table 5.2-2 of AP-42 also includes emissions factors in units of mg/L.) AP-42 does not provide ratings for these emissions factors. Table 9-4. VOC Emissions Factors fo r Marine Vessel Loading of Gasoline at Marine Terminals a

Vessel Tank Condition Previous Cargo Ships and Ocean Barges (lb/10 3 gal) Barges (lb/10 3 gal) Uncleaned Volatile c 2.6 3.9 Ballasted Volatile 1.7 Not applicable Cleaned Volatile 1.5 No data Gas

- fre ed Volatile 0.7 No data Any condition Nonvolatile 0.7 No data Gas

- freed Any cargo No data 2.0 Typical overall situation d Any cargo 1.8 3.4

a Source: U.S. EPA, 1995a. The emissions factors for VOC (which excludes methane and ethane) may be used to estim ate total organic emissions (i.e., including methane and ethane) because methane and ethane constitute a negligible fraction of the components in gasoline. b Ocean barges (tank compartment depth about 40 ft) exhibit emission levels similar to tank ships. S hallow draft barges (compartment depth 10 to 12 ft) exhibit higher emission levels.
c Volatile cargoes are those with a true vapor pressure greater than 10 kilopascals (kPa) (1.5 psia). d Based on observation that 41% of tested ship compartments were uncle aned, 11% ballasted, 24% cleaned, and 24% gas

- freed. For barges, 76% were uncleaned. 

### 9.4.2 Estimate Controlled or Uncontrolled Emissions and Speciate Using the emissions factor developed or identified from the methods previously discussed, the emissions can be estimated based on Equation 9-4: (Eq. 9-4)

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9-6 where: E L



### = Uncontrolled emissions (lb) of commodity ER L 

### = Loading emissions rate (lb/10 3 

### gal of liquid loaded) Thruput = Throughput of commodity (gallons) As previously discussed, depending on the commodity being loaded, the emissions rate ER L 

### could be for gasoline, crude, or other product. Also as previously discussed, to speciate the emissions for specific components, the composition or concentration data available (i.e., product-specific, product-specific average, site-specific product, or default averages) can be used as shown in Equation 9-5. (Eq. 9-5) where: E LSpecies 

### = Emissions (lb) of the component species ―i‖ Wtfrac Species 

### = Weight fractio n of component species ―i‖ in the vapor (fraction) 9.4.3 Capture Efficiency If an add-on air pollution control device or vapor balance system is used to capture and control emissions, then capture and control efficiencies should be included in the emissions estimate. The capture efficiency is the portion of the total emissions that is captured by the vapor collection system. The effectiveness of the vapor collection system, or capture system, is dependent on the leak tightness of the truck tank, rail car, or marine vessel; the condition of the connection from the tanker or vessel collection header equipment to the vapor collection system; the leak tightness of the terminal’s vapor collection system; and the control device. For gasoline loading racks subject to Subpart CC, refineries are required to confirm and document the vapor tightness of the vehicles being loaded. For loading racks subject to gasoline loading requirements, an annual pressure and vacuum certification is required on the tanker truck (e.g., using EPA Method 27 in 40 CFR Part 60), a leak test using EPA Method 21 from 40 CFR Part 60 may be performed on the tanker truck, and a leak check using EPA Method 21 may be conducted on the terminal’s vapor collection system. In addition, the type of loading conducted (i.e., atmospheric, pressurized) and type of connection from the tank headspace to the vapor collection system and to the control device are factors. Typical capture efficiencies assumed for vapor collection procedures and systems are shown in Table 9-5 . Capture efficiency for the vapor collection system can be applied based on the leak check conducted for the tanker truck, rail car, and marine vessel.

Table 9-5. Capture Efficiencies for Vapor Collection Systems a Loading Characteristics and Le ak Check Frequency for Tankers Capture E fficiencies

 No leak check on tanker 65%

 No leak check on tanker

 Maintain minimum positive pressure below +3 to +5 in ches of water 85%

 Annual leak check on tanker per 40 CFR Part 60, Subpart XX (nongasoline) 95%

 S emi

- annual leak check on tanker per 40 CFR Part 60, Subpart XX (nongasoline) 97.5%

 Annual leak check on tanker per 40 CFR Part 60, Subpart XX (gasoline) 98.7%

 Vacuum loading , maintaining vacuum less than
− 1.5 in ches of water

 Hard

- piped bolted, flanged co nnection from tanker to the vapor collection system 100%

 Pressure tank that is U.S. Department of Transportation certified

 Hard

- piped bolted, flanged connection from tanker to the vapor collection system 100%
Note: Use latest available version if update s to this document have occurred since the cited version.
a Source: TCEQ, 2000.

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9-7 9.4.4 Control Efficiency The control efficiency represents the portion of the total captured emissions that are removed from the emissions stream by the add-on air pollution control device. The control efficiency determined for the control device should be applied based on performance testing, if available, or based on design efficiency and operating parameters. To estimate controlled emissions from loading, use Equations 9-6 and 9-7 to apply the capture efficiency and the control efficiency to the uncontrolled emissions: (9 -6) (9 -7) where: Capture = Capture efficiency of the vapor collection system (fraction) CE = Control efficiency of the add-on air pollution control device (fraction)

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9-8 Example 9 - 1: Calculation for Rank 4
— When Property Data Are Not Available Calculate the VOC and HAP emissions for submerged loading of gasoline into dedicated

service gasoline transport tank trucks (each with a volume of 8,000 gallons) based on the following information: The refinery loads 210 tank trucks per year, with 100 tank trucks loading gasoline at a bulk temperature of 90 ° F, 55 loading at a bulk temperature of 77 ° F, and 55 loading at a bulk temperature of 40 ° F. P roperty data are available for liquid composition of the gasoline only ; the properties are identical to those provided for gasoline in Example A

- 1 in Appendix A

. First, the vapor pressure of gasoline and MW VAP 

### must be calculated. In this example, the weight fraction of the vapor is estimated separately for each loading temperature following the calculation methodology presented in Appendix A (see Example A

- 1 and Table A
- 2 ). The vap or pressure for each constituent is determined at the three loading temperatures using Antoine’s equation and Antoine’s coefficients, such as those provided in Table 7.1

- 5 of AP

- 42 (U.S. EPA, 1995a). From Example A

- 1 in Appendix A, at 90 ° F, the total syste m vapor pressure is 5.641 psia and the MW of the vapor, MW GasolineVAP 

### , is 65.98 lb/lb

- mol. Similar calculations for loading gasoline with bulk temperatures of 77 ° F and 40 ° F reveal the following (see Appendix A for further details) :

Temperature Vapor Pressu re MW GasolineVAP 77 ° F 4.40 psia 65.46 lb/lb

- mol 40 ° F 2.03 psia 63.99 lb/lb

- mol 

### The emissions rates at each temperature are calculated using Equation 9

- 3 :

The emissions at each t emperature are th en calculated using Equation 9

- 4 :

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9-9 Example 9 - 1 (continued): Calculation for Rank 4
— When Property Data Are Not Available The individual VOC or HAP species at each bulk temperature can b e estimated using the calculated gasoline vapor weight fraction for each species in Equation 9

- 5:

See Table 9
- 6 for the emissions estimate summary for individual HAP species. Finally, total emissions are estimated by summing the em issions estimates for each of the three bulk temperatures. Total gasoline emissions (VOC) are 6,700 lb (4,047 lb + 1,765 lb + 853 lb), or 3.3 tons (6,700 lb ÷ 2,000 lb/ton). Similarly, total emissions of each of the individual HAP species are estimated by summing the emissions estimates for each of the three bulk temperatures. The results are presented in Table 9
- 6

.

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9-10 Table 9-6. Sample Calculation Methodology Rank 4
— Summary of Emissions (When Property Data Are Not Available)

CAS Number Component ― i‖ At 90 ° F Gasoline, Vapor, wt% At 90 ° F

E Gasoline = 4,047 lb E L Species ―i‖ (lb) At 77 ° F

Gasoline, Vapor, wt% At 77 ° F

E Gasoline = 1,765 lb E L Species ―i‖ (lb) At 40 ° F

Gasoline, Vapor, wt% At 40 ° F

E Gasoline = 853 lb E L Species ―i‖ (lb) Sum Total

Annual Emissio ns (lb) 106

- 99

- 0 1,3

- butadiene 4.5 6 E

- 02 1.8 4.74E

- 02 0.84 5.30E

- 02 0.45 3.1 1634

- 04

- 4 Methyl tertiary butyl ether 3.16E+00 1 30 2.9 9 E+00 5 3 2.4 4 E+00 2 1 20 0 110

- 54

- 3 Hexane 6.9 1 E+00 2 80 6.58E+00 1 20 5.5 2 E+00 47 44 0 540

- 84

- 1 2,2,4

- trimethylpentane 1.5 4 E+0 0 62 1.4 2 E+00 25 1.07E+00 9. 2 96 71

- 43

- 2 Benzene 9.98E

- 01 40 9.3 3 E

- 01 16 7.3 6 E

- 01 6. 3 63 108

- 88

- 3 Toluene 1.39E+00 56 1.2 5 E+00 22 8.67E

- 01 7.4 8 6 1330

- 20

- 7 Xylene 4.44E

- 01 1 8 3.82E

- 01 6.7 2.3 1 E

- 01 2.0 2 7 100

- 41

- 4 Ethylbenzene 1.0 8 E

- 01 4. 4 9.29E

- 02 1.6 5.62E

- 02 0.48 6. 5 100

- 42

- 5 Styrene 1.65E

- 01 6. 7 1.4 2 E

- 01 2.5 8. 50 E

- 02 0.72 9.9 98

- 82

- 8 Cumene 2.83E

- 02 1.1 2.3 7 E

- 02 0.4 2 1. 30 E

- 02 0.11 1. 7 91

- 20

- 3 Naphthalene 9.2 6 E

- 04 0.037 7.1 2 E

- 04 0.013 3.0 2 E

- 04 0.0026 0.053 92

- 52

- 4 Biphenyl 2.58E

- 06 0.00010 1.79E

- 0 6 0.00003 2 5.3 6 E

- 07 0.000004 6 0.00014 108

- 95

- 2 Phenol 1.68E

- 04 0.0068 1.18E

- 04 0.002 1 3.55E

- 05 0.00030 0.009 2 1319

- 77

- 3 Cresols 1.6 2 E

- 03 0.06 6 1.1 1 E

- 03 0.0 20 2.99E

- 04 0.002 6 0.088

Total HAP 600 240 95 940

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## 10

- 1 

# 10 . Fugitive Dust Sources There are three main sources of fugitive dust (or PM) at a petroleum refinery: roads (paved and unpaved); fluid catalytic cracking catalyst handling; and petroleum coke storage and handling. Petroleum refineries may also operate a landfill or land application unit, which would also be a source of fugitive PM emissions. There are no direct emissions measurement methodologies commonly employed for fugitive dust sources. Fugitive dust sources are described in Chapter 13 of AP-42 (U.S. EPA, 1995a). Unfortunately, none of the default factors for the fugitive dust emissions correlations are specific to petroleum refineries. Table 10-1 provides recommended default values for the correlations based on a review of the available data. The methodologies are detailed in Chapter 13 of AP- 42 and basic guidance for applying the methodologies are provided below.

 For paved roads, Equation 1 of Section 13.2.1.3 of AP-42 (U.S. EPA, 1995a) should be used with the silt loading recommended in Table 10-1 ; values for all other equation variables are provided in Section 13.2.1.3.

 For unpaved roads, Equation 1a and 1b of Section 13.2.2.2 of AP-42 (U.S. EPA, 1995a) should be used with the silt content recommended in Table 10-1 ; values for all other equation variables are provided in Section 13.2.2.2.

 For handling of FCCU catalyst or petroleum coke, use Equation 1 of Section 13.2.4.3 of AP-42 (U.S. EPA, 1995a) with the moisture content recommended in Table 10-1 ; values for all other equation variables are provided in Section 13.2.4.3.

Table 10-1. Default Values for Fugitive Dust Emission Estimates
Source/Variable Description Potential Range Value Recommended Value Paved road : silt loading, g/m 2 0.4 a

– 120 b 10 Unpaved road : silt content % 1.8

– 25.2 c 7 FCCU catalyst ―drops‖: silt content % 50 d FCCU ca talyst ―drops‖: moisture content % 8 e FCU or calcined coke ―drops‖: silt content % 5 e FCU coke or calcined ―drops‖: moisture content % 8 e Delayed coking unit coke ―drops‖: silt content % 5 e Delayed coking unit coke ―drops‖: moisture content % 30 f Flexicoking or petroleum coke ash: silt content % 13 g Flexicoking or petroleum coke ash: moisture content % 7 g

a Based on low average daily traffic (ADT) public road factor in Table 13.2.1

- 3 in AP

- 42. b Based in asphalt batching industrial facility f actor in Table 13.2.1

- 4 in AP

- 42.
c Based on range for industrial sites in Table 13.2.2

- 3 in AP

- 42. d Assumed based on median particle size of FCCU catalyst and equilibrium catalyst (E

- cat) of 65 μ m. e Values for coke breeze assumed to apply. f Assumed v alue based on wet coke cutting techniques. g Values for flue dust assumed to apply. 

### The methodologies outlined in Chapter 13 provide means of estimating PM 10 

### and PM 2.5 

### emissions. These emission are all filterable PM so that PM10-PRI = PM10-FIL and PM25-PRI = PM25-FIL. For FCCU catalyst handling emissions and for petroleum coke handling activities, emission estimates should also be provided metal HAP emissions. Concentrations of specific metal HAP are commonly determined for the FCCU equilibrium catalyst; these concentrations can be used time the PM 10 

### emissions rate to determine

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## 10

- 2 the metal HAP emissions rate from FCCU catalyst and E-cat handling (external from the FCCU). Table 5-3 provides concentration ratios of various metal HAP to nickel on CCU fines. The se concentration ratios can be used to augment the FCCU catalyst and E-cat metal HAP emissions estimates when only nickel concentrations are routinely determined. Compositional analysis of petroleum coke material or ash should also be determined so that the metal HAP emissions from petroleum coke or ash handling can be reported.

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## 11

- 1 

# 11 . Startup and Shutdown Except for the CEMS-based measurements (i.e., Methodology Rank 1), most of the emissions estimation methods provided in this Refinery Emissions Protocol document characterize the emissions during normal operating conditions. However, during startup and shutdown, the process operations are not normal. During startup, the reactor temperatures may not be sufficient for the necessary reactions to occur or the process flow rate may be well below typical operating conditions. Under these conditions, processes that do not typically have atmospheric emissions may have significant emissions. While most control devices will operate well at lower vent rates, some control devices, such as venturi scrubbers, require a minimum flow for effective operation. During startup and shutdown, the emissions characteristics of the processes may be significantly different than those during normal operations. When the emission estimation methodology relies on normal operating conditions (e.g., most site-specific and default emission factors), it is important to specifically estimate the emissions during startup and shutdown and include these emissions in the facility’s annual emissions to tals. During shutdown, the process vessels need to be degassed and purged. Process unit startup and shutdown of one process unit may also affect the emission characteristics of other units, particularly with respect to the fuel gas system. When a hydrotreater or hydrocracking unit is shutdown, this often leads to excess hydrogen being added to the fuel gas. This leads to higher NO X 

### emissions from process heaters. When certain energy intensive units, such as catalytic reforming units, are shutdown, the refinery may have excess fuel gas, which is subsequently flared. Depending on the methods used to estimate emissions from combustion sources and flares, these fuel gas fluctuations may already be fully accounted within the inventories for combustion sources and flares. However, if default estimates (or site-specific estimates based on source tests conducted under typical operating conditions) are used, then emissions during these significant fuel gas fluctuation events should be estimated and the emissions included in the annual emission values. It is beyond the scope of this protocol document to provide methods of estimating emissions during all startup or shutdown events. However, the primary emissions event during startup or shutdown is expected to be vessel depressurization and purging (or degassing). Methods are provided in this section to account for these events are described in this section. 

## 11 .1 Gaseous Process Vessel Depressurization and Purging Process vessel depressurization for gaseous process can be estimated using Equation 11-1 . This equation assumes ideal gas law; for gases that do not follow ideal gas law, compressibility factors can be included. The equation includes a void fraction term to account for inert material, such as packing material, distillation trays, and certain catalyst particles, that reduce the gaseous space. This equation may underestimate the emissions if the solid material in the vessel may adsorb certain gas constituents (e.g., petroleum coke or activated carbon), that can desorb at lower pressures and temperatures.
(Eq. 11-1)

where: E i 

### = Emissions of pollutant ―i‖ during depressurization event (lbs /event ). P V 

### = Gauge pressure of the vessel when depressurization gases are first routed to the

atmosphere (pounds per square inch gauge, psig). 14.7 = Assumed atmospheric pressure (pounds per square inch, psi). T V 

### = Absolute temperature of the vessel when depressurization gases are first routed to the

atmosphere (degrees Rankine, °R ).

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## 1 1

- 2 528 = ―Standard‖ t emperature used in the calculation ( °R ). V V 

### = Volume of the vessel (cubic feet, ft 3 

### ). f

void 

### = Volumetric void fraction of vessel. Use 1 unless packing material or trays are present in the vessel. MW i 

### = Molecular weight of pollutant ―i‖ ( lb / lb -mole). M VC = Molar volume conversion factor (385.3 scf/ lb -mole). MF i 

### = Volume fraction of pollutant ―i‖ in vessel gas (scf pollutant i/scf of gas). Typically, depressurization and purging occurs initially to a flare. Depending on the methodology used to estimate the emissions from the flare, these gas flows may be included in the flare emission estimates (e.g., when measuring flare gas volumes and composition). If the flare emissions methodology does not account for these flows (e.g., default factors), Equation 11-1 can be used to estimate the mass of gas sent to the flare (using initial depressurization temperatures and pressures) and these mass rates can be adjusted by the flare destruction efficiency to estimate the emissions during the flare venting period. Th e use of Equation 11-1 is illustrated in Example 11-1 , G aseous Depressurization Calculation

. 

## 11.2 Liquid Process Vessel Depressurization and Purging For vessels that contain liquids, depressurization and purging emissions can be estimated based on the ―heel‖ or fraction of the liquid that remains in the vessel prior to purging. This method assumes that the mass of liquid remaining in the tank will overwhelm the quantity of contaminants in the headspace. For systems operating with very volatile material (such as butane in gasoline), it may be necessary to consider the initial gaseous emissions for the most volatile components (using Equation 11-1) as well as the liquid heel. A heel fraction may be between 0.1 and 1 percent, depending on the viscosity of the liquid, the surface area of internals within the vessel, and the location of the drainage port or pump line (higher viscosities, higher internal surface areas, and higher drainage port locations will increase the heel fraction). Using the heel method, it is assumed all of the liquid heel is eventually volatilized. Knowledge of the process steam can be used to speciate the emissions. Again, some of the heel may be purged to a flare and a control efficiency for this portion is warranted, but some fraction will also be purged directly to the atmosphere. Example 11-2 , Liquid Heel Emissions Calculation , illustrates this methodology.

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## 11

- 3 Example 11 - 1: Gaseous Depressurization Calculation A catalytic reforming unit is depressurized and purged to a flare. After the purge sequence, no liquid materials are assumed to be present. The reactor is then depressurized and purged to the atmosphere. The total volume of the reactor vessels are 20,000 ft 3 

### and the catalyst occupies 40% of the total reactor volume. The temperature and pressure of the vessel when first purged to the atmosphere are 250 ° C and 10 psig, respectively. The composition of the gas is in the reactor vessel after the flare purge is: Benzene = 1.2 vol% Hexane = 0.5 vol% Toluene = 1.4 vol% Xylenes = 0.8 vol% Other VOC = 2.1 vol% Nitrogen = 94 vol% For use in Equation 10

- 1 , the reactor vessel temperature must be converted to ° R: 250 ° C = 250 × 9/5 + 32 = 482 ° F = 482+460 = 942 ° R. The void fraction is the volume fraction not occupied by catalyst particles: 1

- 0.4 = 0.6. The molecular weight of the constituents listed range from 78 to 106 lb/lb

- mol. It is assumed the ―other VOC‖ has similar molecular weight so a molecular weight for this unspecified material is estimated from, the weighted average molecular weight of the known organic constituents: MolWt ―other VOC‖ = (1.2 × 78+0.5 × 86+1.4 × 92+0.8 × 106)/4.9 = 90 lb/lb

- mol. Using benzene as the example, substituting into Equation 11

- 1 yields:

Similarly, the emissions of other organic constituents are estimated to be: Benzene = 27.5 lbs/event Hexane = 12.6 lbs/e vent Toluene = 37.8 lbs/event Xylenes = 24.9 lbs/event Other VOC = 55.4 lbs/event The total VOC is the sum of these emissions, which is 158 lbs/event or 0.079 tons/event. If this event occurred twice during the year, the annual emission would be 0.16 to ns VOC/yr.

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## 11

- 4 Example 11 - 2: L iquid Heel Emissions Calculation Problem : Using the same catalytic reforming unit as in Example 11

- 1, estimate the emissions from depressurizing and purging the reactor vessels using the ―heel‖ approach. Assume 90 percent of the heel is purged to the flare

. Solution : As there is high internal surface area, the heel is assumed to be 0.5% of the liquid volume. The maximum liquid volume is 20,000 ft 3 

### × (1

- 0.4) = 12,000 ft 3 

### , so the volume of liquid in the reactor is estimated to be 60 ft 3 

### (12,000 × 0.005). Appe ndix A contains average composition of various process fluids. Reformate composition is given as: Benzene = 4.6 wt% Hexane = 3.9 wt% Toluene = 14.5 wt% Xylenes = 13.8 wt% Other VOC = 63.2 wt% To calculate the potential mass emissions, a mass of liquid remaining must be calculated. Using a specific gravity of 0.8 for reformate, the mass of liquid remaining is estimated to be: 60 ft 3 

### × 0.8 × 62.4 lb/ft 3 

### (density of water) = 3,000 lbs. Given 90 percent of the heel liquid is removed while purging to the fla re, then 2,700 lbs of material is sent to the flare and 300 lbs are purged directly to the atmosphere. Assuming a 98 percent destruction efficiency for the flare, the uncombusted emissions from the flare are estimated to be 54 lbs [2700 × (1

- 0.98)]. Therefo re, a total of 354 lbs of organic material (VOC) is estimated to be emitted considering emissions from both the flare and atmospheric purging. Emissions of specific constituents are calculated based on the mass composition in the liquid: Benzene = 354 × 0.046 = 16 lbs/event Hexane = 354 × 0.039 = 14 lbs/event Toluene = 354 × 0.145 = 51 lbs/event Xylenes = 354 × 0.138 = 49 lbs/event Other VOC = 354 × 0.632 = 224 lbs/event.

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## 12

- 1 

# 12 . Malfunctions Malfunctions may occur either within the process unit or to a control device used to reduce a source’s emissions. During malfunction events, emissions may be significantly higher than the emissions that occur under normal operating conditions. Except for the CEMS-based measurements (i.e., Methodology Rank 1), most of the emissions estimation methods provided in this Refinery Emissions Protocol document characterize the emissions during normal operating conditions. As such, malfunction events must be accounted for separately for malfunction events and these malfunction emissions must be added to the normal process emissions to accurately estimate annual emissions. Because of the myriad of potential malfunction events that could occur, it is impossible to provide specific guidance for all possible malfunction scenarios. However, because malfunction events are important to both annual and short-term emissions, the duration and emissions associated with each malfunction event should be recorded, and these emissions should be included in the emissions inventory. The following list provides specific events for which malfunction emissions estimates should be made to accurately account for these emissions. Again, this is not intended to be an exhaustive list, but rather representative examples. In some malfunction events, such as pressure relief valve opening to a flare during a system over-pressurization event, the emissions during the malfunction event may be adequately accounted for by the flare emissions methodology (i.e., when using continuous monitoring of gases is sent to a flare), but in other cases it may not (i.e., when using default factors). As such, emissions inventory developers will need to evaluate the malfunction events in light of their inventory methods to determine if it is appropriate to use special malfunction emissions calculations. Emissions estimates should be provided for the following malfunction events: 1. Any instance when a control device is bypassed or is not functioning properly. 2. Any instance when the amine scrubbing system and/or sulfur recovery plant is offline or not operating at normal efficiencies (generally affecting SO 2 

### emissions estimates from combustion sources, flares, and/or sulfur recovery plants). 3. Instances during startup or shutdown when units are vented directly into the atmosphere or when they are vented to a flare and the flare methodology does not account for these gases. 4. Tank roof landings (for more information, see Section 3, Storage Tanks , of this Refinery Emissions Protocol document). 5. Instances of over-steaming a flare. When gas is being sent to a flare, but no flame is visible, then it is likely the result of over-steaming. Fifty percent flare destruction efficiencies should be used during periods of over-steaming. 6. Any instance when a spill or similar emergency release occurs. There are three types of malfunction events considered in this section: control device malfunctions; process vessel overpressurization; and spills. 

## 12 .1 Control Device Malfunctions When a control device is used to reduce the emissions from a particular source, the site-specific emissions factors or other methodologies provided in this Refinery Emissions Protocol document account for these controls when the equipment is operating normally. However, when control systems are not operating normally or or bypassed the emissions may be orders of magnitude more than when these emissions are controlled. If a control device that normally achieves 99% control efficiency is offline for 3 days, then the emissions during these 3 days would equal the annual emissions projected for the controlled emissions source.

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## 12

- 2 When there is a malfunction with a control device, the emissions from the source can be estimated based on the uncontrolled emission factor or by adjusting the controlled emissions base on the control device’s efficiency. It is important to note that the control device efficiency is often different for different pollutants. A wet scrubber on an FCCU may be 95% efficient at reducing SO 2 

### emissions, 90% efficient for PM and metal HAPs, but has no real impact on VOC or NO X 

### emissions. Similarly, oversteaming a flare that causes poor combustion efficiency will increase VOC and reduced sulfur emissions but reduce NO X 

### and SO 2 

### emissions. Table 12-1 provides default control efficiencies and correction factors for certain control device malfunctions. Table 12-1. Control Device Efficiency and Multiplier Factors for Control Device Malfunctions

Source/Control Device Description a Pollutant Class b Control Device Efficiency

c (%) Controlled

Emissions Multiplie r d FCCU or FCU/wet scrubber PM, metal HAP 92 12.5 SO 2 95 20 FCCU or FCU/ESP PM, Metal HAP 92 12.5 SO 2 , NO X , VOC, organic HAP, CO 0 1 FCCU or FCU/cyclone PM, Metal HAP 85 6.7 FCCU or FCU/CO boiler CO, VOC, most organic HAP 98% 1 NO X , PAH, Formald ehyde

- 100% 0.5 FCCU or FCU/SCR NO X 92 12.5 FCCU or FCU/SNCR NO X 60% 1.7 Sulfur plant malfunction with sour gas sent to flare SO 2 96

– 99.8% 25

- 500
H 2 S 0

– 98% 1

– 50 Tail gas treatment malfunction with tail gas sent to flare SO 2 95% 20
H 2 S 0

– 95 % 1

– 20

a Abbreviations: FCCU = fluid catalytic cracking unit FCU = fluid coking unit ESP = electrostatic precipitator CO boiler = carbon monoxide boiler SCR = selective catalytic reduction SNCR = selective non

- catalytic reduction b Pollutant class. Only pollutants affected by the control device are listed. For other pollutants, assume the control device efficiency is 0% and the controlled emissions multiplier is 1.
c Control device efficiency. A negative number indicates a control device that may increa se the emissions of a particular pollutant. d Controlled emissions multiplier. Factor used to escalate the controlled emission factor to account for periods of control device malfunction = 1/(1

- control device efficiency). 

## 12.2 Vessel Overpressurization Process malfunctions often result in temperature or pressure excursions that must be released from the vessel to prevent a catastrophic failure. Generally, these emergency releases will be sent to a flare. Depending on the methodology used to estimate the emissions from the flare, these gas flows may be included in the flare emission estimates (e.g., when measuring flare gas volumes and composition). If the flare emissions methodology does not account for these flows (e.g., default factors), Equation 11-1 (presented in Section 11.1) can be used to estimate the mass of gas sent to the flare (using initial

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## 12

- 3 depressurization temperatures and pressures); the calculated mass release rates must then be adjusted by the flare destruction efficiency to estimate the emissions during the emergency release event. 

## 12.3 Spills Generally, it can be assumed that 100% of the compounds spilled are emitted into the atmosphere. For heavier liquids, the mass transfer correlations for an oil layer (K oil 

### ) as provided in Appendix B, Wastewater Treatment System Equations , Section B.2.1, Oil Water Separators , of Section 7, Wastewater , can be used. Equation 12-1 can be used to estimate the emissions based on the quantity of material spilled, the area of the spill, and the time period from when the initial spill occurred to the final clean up: (Eq. 12-1) where: E i 

### = Emissions estimate of pollutant ―i‖ (kilograms per spill event)

ρ = Density of spilled liquid (kilograms per cubic meter) V = Volume of spilled material (cubic meters) C i,o 

### = Concentration of pollutant ―i‖ in spilled fluid prior to the spill event (mass fraction;

kilogram per kilogram) K oil 

### = Mass transfer coefficient for an oil (organic) liquid (meters per second)

t = Duration of the spill (seconds) A = Area covered by the spill (square meters)

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13-1 

# 13 . References Coburn, J. and M. Icenhour. 2008. Memorandum from J. Coburn and M. Icenhour, RTI, to Brenda Shine, EPA/SPPD. Preliminary Analysis of Short-term Variability in Storage Vessels Emissions

. December 29. EIA (U.S. Energy Information Administration). 2009. Refinery Capacity Report 2009. Prepared by the Energy Information Administration, Washington, DC. June 25. EMEP/CORINAIR (European Monitoring and Evaluation Programme/COoRdination of Information on AIR emissions). 2006. Atmospheric Emission Inventory Guidebook 2006 . Technical Report No. 11/2006. Available at: http://www.eea.europa.eu/publications/EMEPCORINAIR4. ERG (Eastern Research Group, Inc). 2001. Emission Inventory Improvement Program Technical Report Series . Volume II, Chapter 2: ―Preferred and Alternative Methods for Estimating Air Emissio ns from Boilers.‖ Prepared for Point Sources Committee Emission Inventory Improvement Program. January. Hansell, D., and G. England. 1998. Air Toxic Emission Factors for Combustion Sources Using Petroleum Based Fuels, Volume 2: Development of Emission Factors Using CARB Approach . Prepared by EER for S. Folwarkow, Western States Petroleum Association, Concord, CA, and K. Ritter, American Petroleum Institute, Washington, DC. Levelton Consultants Ltd. 2005. Emission Monitoring and Reporting Strategy

– Summary and Background . Prepared for Canadian Council of Ministers of the Environment and NFPRER Monitoring and Reporting Team.Lucas, B. 2007. Memorandum from B. Lucas, EPA/SPPD, to Project Docket File (EPA Docket No. EPAHQ

- OAR -2003-0146). Storage Vessels: Control Options and Impact Estimates . August 3, 2007. Docket Item No. EPA- HQ

- OAR -2003-0146-0014. Moye, D., V. Boero, and G. Everett. 2006. The whole plant approach to air emission modeling for NESHAP compliance. WEFTEC ® 

### .06 :6685

− 6694. NYSERDA (New York State Energy Research and Development Authority). 2005. Hydrogen Fact Sheet. Hydrogen Production

– Steam Methane Reforming (SMR). Available at: http://www.getenergysmart.org/Files/HydrogenEducation/6HydrogenProductionSteamMethaneR eforming.pdf. RTI (Research Triangle Institute). 2002. Petroleum Refinery Source Characterization and Emission Model for Residual Risk Assessment . Prepared for U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. EPA Contract No. 68- D6

- 0014. July. SCAQMD (South Coast Air Quality Management District). 2004a. Source Test Report 03-194 Conducted at Chevron/Texaco Refinery, El Segundo, California

— Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent

. May 14. SCAQMD (South Coast Air Quality Management District). 2004b. Source Test Report 03-197 Conducted at Conoco-Phillips Refinery, Carson, California

— Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent . July 23.

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13-2 SCAQMD (South Coast Air Quality Management District). 2004c. Source Test Report 03-198 Conducted at Exxon Mobil Refinery, Torrance, California

— Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent

. March 4. SCAQMD (South Coast Air Quality Management District). 2004d. Source Test Report 03-200 Conducted at Shell Oil Refinery, Wilmington, California

— Vo latile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent . July 1. TCEQ (Texas Commission on Environmental Quality). 2000. Air Permit Technical Guidance for Chemical Sources: Loading Operations. TCEQ (Texas Commission on Environmental Quality). 2003. Source Sampling Procedures Manual, Appendix P, Cooling Tower Monitoring, Air Stripping Method (Modified El Paso Method) for Determination of Volatile Organic Compound Emissions from Water Sources. January 31. TCEQ (Texas Commission on Environmental Quality). Air Quality Division. 2009. 2008 Emissions Inventory Guidelines . RG-360A/08. January. The United States

–

Mexico Foundation for Science. 2008. A Customized Approach for Quantifying Emissions for the Electric Power Generation Sector in Mexico . Prepared for: SEMARNAT and CFE. Revision 2, Revised by RTI International for U.S. Environmental Protection Agency Clean Air Markets Division and Climate Change Division. December. Tumbore, DC. 1998. The magnitude and source of air emissions from asphalt blowing operations. Environmental Progress 17 (1):53

– 59. U.S. EPA (Environmental Protection Agency). 1995a. Compilation of Air Pollutant Emission Factors

. Volume 1: Stationary Point and Area Sources. AP -42, Fifth Edition. Office of Air Quality Planning and Standards, Research Triangle Park, NC. U.S. EPA (Environmental Protection Agency). 1995b

. Protocol for Equipment Leak Emission Estimates

. EPA -453/R-95-017. Office of Air Quality Planning and Standards, Research Triangle Park, NC. U.S. EPA (Environmental Protection Agency). 1996. Method 8260B, Volatile Organic Compounds by Gas Chromatography/Mass Spectrometry . Revision 2, December. SW-846. U.S. EPA (Environmental Protection Agency). 1998a. Locating and Estimating Air Emissions from Sources of Benzene . EPA-454/R-98-011. Office of Air Quality Planning and Standards, Research Triangle Park, NC. U.S. EPA (Environmental Protection Agency). 1998b. Petroleum Refineries

— Background Information for Proposed Standards, Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Recovery Units . EPA-453/R-98-003. Washington, DC: Government Printing Office. U.S. EPA (Environmental Protection Agency). 2006. TANKS Emissions Estimation Software, Version 4.09D . Office of Air Quality Planning and Standards, Technology Transfer Network, Clearinghouse for Inventories and Emissions Factors, Available at http://www.epa.gov/ttnchie1/software/tanks/index.html

. U.S. EPA (Environmental Protection Agency). 2009. Mandatory Reporting of Greenhouse Gases (Final Rule). Federal Register : 74 FR 56260. October 30.

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13-3 URS Corporation. 2008. Source Test Report of the Coker Steam Vent . Prepared for Hovensa, LLC, St. Croix, U.S. Virgin Islands. September 8. Yerushalmi, L., and S.R. Guiot. 1998. Kinetics of biodegradation of gasoline and its hydrocarbon constituents. Appl Microbiol Biotechnol 49 :475

− 481.

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# Appendix A Average Stream Compositions

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Table A- 1. Refinery Average Stream Hazardous Air Pollutant Compositions
— Default Values

CAS Number HAP Component Gasoline Alkylate Crude Oil Reformate Naphtha Avg. Conc. (wt%) Wt d Avg. Conc. (wt%) Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor 106

- 99

- 0 1,3

- Butadiene 0.0037 0.0037 540

- 84

- 1 2,2,4

- Trimethylpentane 4.72 0.953 35.4 9.4 0.263 0.247 0.799 0.355 8.51 2.29 2.27 0.679 71

- 43

- 2 Benzene 1.61 0.626 0.118 0.061 0.446 0.807 4.61 3.32 1.244 1.06 1.61 1.17 1.1546 1.028 92

- 52

- 4 Biphenyl 0.01 0 0 0 0.061 0.00002 0.025 0 0 0 0.02 0.000004 0.0396 1.15E

- 05 1319

- 77

- 3 Cresols 0.789 0.00065 0 0 0.218 0.0008 0.141 0.0002 0.019 1 0.00003 0.23 0.0003 0.2905 0.0006074 98

- 82

- 8 Cumene 0.849 0.01565 0.004 0.0001 0.126 0.0108 0.968 0.033 0.91 0.0368 0.57 0.02 0.4258 0.01638 100

- 41

- 4 Ethylbenzene 1.605 0.0631 0.011 0.0006 0.346 0.0633 3.73 0.272 1.366 0.118 1.41 0.1 1.018 0.08803 110

- 54

- 3 Hexane 7.138 4.428 3.22 2.63 2.46 7.11 3.9 4.48 7.53 10.27 4.85 5.78 4.045 6.551 1634

- 04

- 4 Methyl tertiary

- butyl

ether 3.54 3.62 0 0 0 0 0 0 0 0 0.71 0.72 0.6669 0.68198 91

- 20

- 3 Naphthalene 0.444 0.0006 0.012 0.00002 0.219 0.00125 0.798 0.0018 0.39 9 0.0011 0.37 0.001 0.3322 0.001131 108

- 95

- 2 Phenol 0.0551 0.0001 0 0 0.323 0.0031 0.0276 0.0001 0.066 0.0003 0.09 0.0007 0.2066 0.001850 100

- 42

- 5 Styrene 3.528 0.0882 0 0 0 0 0.0907 0.0042 0 0 0.72 0.02 0.6737 0.01703 108

- 88

- 3 Toluene 7.21 0.842 0.503 0.077 0.878 0.477 14.54 3.14 5.05 1.295 5.64 1.17 3.862 0.8860 1330

- 20

- 7 Xylene 7.17 0.235 0.0212 0.0009 1.42 0.216 13.79 0.8367 5.49 0.395 5.58 0.34 4.125 0.2941

Sum of listed HAP 38.7 10.9 39.3 12.2 6.76 8.94 44.0 12.6 22.9 13.5 30.3 11.6 19.1 10.2

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# Property Calculations If the weight composition of a commodity is available but other property data are not, estimates can be made. For example, if the liquid component mixture and the weight fraction for gasoline are known, then the vapor pressure of the liquid, the MW of vapor, and the weight fraction of the vapor can be estimated. The following steps and equations may be used for calculating these estimates: 1. From the weight fraction values in the gasoline (liquid), Equation A-1 should be used to estimate the number of moles of component ―i.‖ (Eq. A-1)

2. From moles of component ―i‖ (liquid), Equation A -2 should be used to estimate the mole fraction of component ―i‖ (liquid). (Eq. A-2) 3. Equation A-3 sh ould be used to calculate the partial pressure of each component ―i‖ in liquid. (Eq. A-3) where: P(i) = Partial pressure of component ―i‖ (psia) P = Vapor pressure of pure component ―i‖ at the liquid temperature (psia) x i 

### = Liquid mole fraction 4. To estimate the total pressure of the liquid, Equation A-4 should be used to estimate the average vapor pressure for the gasoline mixture by summing the partial pressure of each component ―i‖ (liquid). (Eq. A-4)
5. From mole fraction of component ―i‖ (liquid), Equation A -5 should be used to estimate the mole fraction of component ―i‖ in the vapor using Raoult’s law. (Eq. A-5) 6. Equation A-6 should be used to estimate the MW of the gasoline vapor, MW VAP 

### , using the mole fraction of vapor (yi) and the MW of the pure component ―i‖(MW i 

### ). (Eq. A-6)
where: MW VAP 

### = Molecular weight of the vapor (lb/mol) MW i 

### = Molecular weight of component ―i‖ (lb/mol)

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A-5 7. Equation A-7 should be used to estimate the gasoline vapor weight fractions using the gasoline vapor mole fractions and the MW VAP 

### . (Eq. A-7)

Example A - 1: Calculation of Vapor Pressure and Molecular Weight for Gasoline

Loading Example Calculate the vapor pressure of gasoline and MW VAP 

### for submerged loading of gasoline into dedicated

- service gasoline transport tank trucks (each with a volume of 8,000 gallons) based on the following information: The refinery loads 1 0 0 tank trucks per year at a bulk temperature of 90 ° F . P roperty data are available for liquid composition of the gasoline only and are provided in Table A
- 2

. First, the vapor pressure for each constituent is determined at the loading temperature using Antoine’s e quation and Antoine’s coefficients, such as those provided in Table 7.1

- 5 of AP

- 42 (U.S. EPA, 1995a). Using Steps 1 through 7 from this Appendix A , the gasoline liquid mole fraction can be calculated from the weight fraction or weight percent component com position, the partial pressure of each component in liquid, and the gasoline vapor mole fraction using Raoult’s law (see each calculation ―step‖ in the columns in Table A
- 2 ).

 Step 1.

 Step 2.

 Step 3.

 Step 4.

 Step 5.

 Step 6.

 Step 7.

See Table A
- 2 for the calculations of thee variables. At 90°F, the total system vapor pressure is 5.641 psia and the MW of the vapor, MW GasolineVAP 

### , is 65.984 lb/lb

- mol.

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A-6

Table A-2. Sample Calculation of Average Molecular Weight and Vapor Weight Fraction Step 1 Step 2 Step 3 Step 4 Step 5 Step 6 Step 7

A B C D=C/A E=D/(ΣD) F=E*B G=F/(ΣF) H=G*A G=H/(ΣH)* 100%

CAS Number Compound MolWt Pvap at 90°F (psia) Gasoline

Liquid (wt%) Gasoline

Liquid (moles/ 100 g) Gasoline

Liquid (mole fraction) Gasoline

Partial Pressure (psia) Gasoline

Vapor (mole fraction) MolWt

Contribut ion Gasoline Vapor (g/mol) Gasoline

Vapor (wt%) 106

- 99

- 0 1,3

- butadiene 54.09 50. 53 0.0037 6.840E

- 07 6.206E

- 05 3.136E

- 03 5.559E

- 04 3.007E

- 02 0. 045 6 1634

- 04

- 4 Methyl tertiary butyl ether 88.15 3.666 3.54 4.016E

- 04 3.643E

- 02 1.336E

- 01 2.368E

- 02 2. 087E+00 3. 16 110

- 54

- 3 Hexane 86.18 3.9 70 7.138 8.283E

- 04 7.514E

- 02 2.983E

- 01 5.288E

- 02 4. 557E+00 6.9 1 540

- 84

- 1 2,2,4

- Trimethylpentane 114.2 1.336 4.72 4.132E

- 04 3.749E

- 02 5.008E

- 02 8.878E

- 03 1. 014E+00 1.5 4 71

- 43

- 2 Benzene 78.11 2. 544 1.61 2.061E

- 04 1.870E

- 02 4.75 8E

- 02 8.434E

- 03 6.588E

- 01 0.998 108

- 88

- 3 Toluene 92.14 0. 7911 7.21 7.825E

- 04 7.099E

- 02 5.615E

- 02 9.955E

- 03 9.172E

- 01 1.39 1330

- 20

- 7 Xylene 106.1 0.254 2 7.17 6.755E

- 04 6.128E

- 02 1.558E

- 02 2.762E

- 03 2.931E

- 01 0. 444 100

- 41

- 4 Ethylbenzene 106. 2 0. 2758 1.605 1.512E

- 04 1.371E

- 02 3.782E

- 03 6.704E

- 04 7.118E

- 02 0. 108 100

- 42

- 5 Styrene 104. 2 0.192 1 3.528 3.387E

- 04 3.073E

- 02 5.904E

- 03 1.047E

- 03 1.090E

- 01 0. 165 98

- 82

- 8 Cumene 120. 2 0. 1369 0.849 7.064E

- 05 6.408E

- 03 8.77 4 E

- 04 1. 555E

- 04 1.869E

- 02 0. 0283 91

- 20

- 3 Napht halene 128. 2 0. 008555 0.444 3.464 2 E

- 05 3.143E

- 03 2.6 8 9E

- 05 4. 766E

- 06 6. 109E

- 04 9

. 2 6E

- 04 92

- 52

- 4 Biphenyl 154.2 0.001 059 0.01 6.485E

- 07 5.883E

- 05 6.23 1 E

- 08 1.10 5 E

- 08 1.70 3 E

- 06 2.58E

- 06 108

- 95

- 2 Phenol 94.11 0.01 25 3 0.0551 5.855E

- 06 5.311E

- 04 6.6 5 6E

- 06 1.1 8 0 E

- 06 1.11 0 E

- 04 1

. 68 E

- 04 1319

- 77

- 3 Cresols 108.1 0. 008422 0.789 7.296E

- 05 6.619E

- 03 5.574E

- 05 9.881E

- 06 1.069E

- 03 0.00162 74

- 98

- 6 P ropane 44.1 162. 5 0.001 2.268E

- 07 2.057E

- 05 3.342E

- 03 5.924E

- 04 2.613E

- 02 0. 039 6 106

- 97

- 8 n - B utane 58.12 43. 79 4.7 8.087E

- 04 7.336E

- 02 3. 213E+00 5.695E

- 01 3.310E+01 50. 2 75

- 28

- 5 I sobutane 58.12 17. 0 4 1.7 2.925E

- 04 2.654E

- 02 4.521E

- 01 8.015E

- 02 4. 658E+00 7.0 6 109

- 66

- 0 n - P entane 72.15 13. 32 3.9 5.405E

- 04 4.904E

- 02 6.533E

- 01 1.158E

- 01 8. 356E+00 12. 7 78

- 78

- 4 Is opentane 72.15 4.920 7.9 1.095E

- 03 9.933E

- 02 4.888E

- 01 8.664E

- 02 6. 251E+00 9.47

Other VOC 100.2 0.553 1 43.13 4.304E

- 03 3.904E

- 01 2.159E

- 01 3.828E

- 02 3. 836E+00 5.81
n T P totalVP MW vap Totals 100.0 1.102 1.000 5.641 1.000 65.98 100.0

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# Appendix B Wastewater Treatment System Equations

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# B. Wastewater Treatment System Equations This appendix provides a brief presentation of the key equations needed to calculate air emissions from typical wastewater treatment units. The purpose of this appendix is to document the equations used in the simplified refinery wastewater emissions tool and to correct errors found in the presentation of some of these equations as provided in Chapter 4.3 of AP-42 (EPA, 1995). 

## B .1 Ma ss Transfer Rate Equations The overall mass transfer coefficient that determines the rate of volatilization is determined based on a two-resistance module: a liquid phase mass transfer resistance and a gas phase mass transfer resistance. The liquid and gas phase mass transfer resistances are very different for turbulent surfaces compared to quiescent (laminar flow) surfaces. Therefore, the overall mass transfer coefficient is a composite of the overall mass transfer coefficient for the turbulent surface area and the overall mass transfer coefficient for the quiescent surface area based on an area weighted average as follows:
(Eq. B-1)
where: K OL 

### = Overall mass transfer coefficient (m/s) K OL,t 

### = Overall mass transfer coefficient for turbulent surface areas (m/s) A t



### = Turbulent surface area = f aer 

### A, m 2 

### f

aer 

### = Fraction of total surface area affected by aeration K OL,q 

### = Overall mass transfer coefficient for quiescent surface areas (m/s) A q 

### = Quiescent surface area = (1-f aer 

### ) A, m 2 

### (Note: A t



### + A q 

### must equal A) A = Total surface area (m 2 

### ) The overall mass transfer coefficient for turbulent surface areas based on the two resistance module is:
(Eq. B-2)

where: k l,t 

### = liquid phase mass transfer coefficient for turbulent surface areas (m/s)

H' = dimensionless Henry's law constant = H/RT H 

### H = Henry's law constant (atm-m 3 

### /mol) R = ideal gas law constant = 0.00008205 (atm-m 3 

### /mol- K) T H 

### = temperature at which Henry's law constant was evaluated = 298 K. k g,t 

### = gas phase mass transfer coefficient for turbulent surface areas (m/s) Similarly, the overall mass transfer coefficient for quiescent surface areas is
(Eq. B-3)

where: k l,q 

### = Liquid phase mass transfer coefficient for quiescent surface areas (m/s) k g,q 

### = Gas phase mass transfer coefficient for quiescent surface areas (m/s).

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B-4 The mass transfer correlations used in this module to estimate the individual mass transfer coefficients are the same as those used in the WATER9 emissions model developed by EPA. The documentation of these mass transfer correlations can be accessed from EPA’s Web site at http://www.epa.gov/ttnchie1/software/ water. Only the basic equations are provided here. For a more detailed discussion of these mass transfer correlations, the reader is referred to Chapter 5 of the Air Emissions Models for Waste and Wastewater report (U.S. EPA, 1994). B.1.1 Liquid Phase Mass Transfer Coefficient for Turbulent Surfaces The liquid phase, turbulent surface mass transfer coefficient is calculated as follows:
(Eq. B-4)

where: J = Oxygen transfer factor (lb/h/hp) P tot 

### = Total power to the impellers (hp) T = Water temperature in ( 

##  C) O cf



### = Oxygen correction factor MW l 

### = Molecular weight of liquid (water) (g/mol) ρ l 

### = Density of liquid (water) (g/cm 3 

### = Mg/m 3 

### ) D i,l 

### = Diffusivity in liquid (water) (cm 2 

### /s) D O2,l 

### = Diffusivity of oxygen in liquid (water) (cm 2 

### /s) B.1.2 Gas Phase Mass Transfer Coefficient for Turbulent Surfaces The gas phase, turbulent surface mass transfer coefficient is calculated as follows: (Eq. B-5) where: Re g 

### = Gas phase Reynolds number = (d imp 2 

### w ρ g 

### )/μ g



### ρ g 

### = Density of gas (air) (g/cm 3 

### ) μ g 

### = Viscosity of gas (air) (g/cm- s) p = Power number = 0.85 (550 P tot 

### /N aer 

### ) g c,2 

### / [(62.428ρ l 

### )w 3 

### (d imp 

### /30.48) 5 

### ] g c,2 

### = Gravitational constant = 32.17 lb m 

### - ft/s 2



### - lb f 

### = 0.03283 g c 

### N aer



### = Number of aerators w = Rotational speed (rad/s)

Sc g 

### = Gas phase Schmidt number = μ g 

### /(ρ g 

### D i,a 

### ) Fr = Froud number = [w 2 

### (d imp 

### /30.48) ]/ g c,2 

### D i,a 

### = Diffusivity of constituent in air (cm 2 

### /s) MW a 

### = Molecular weight of air (g/mol) d imp 

### = Impeller diameter (cm) g c 

### = Gravitational constant = 980 cm/s 2 

### B.1.3 Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces The appropriate correlation to use to estimate the liquid phase mass transfer coefficient is dependent on the wind speed and the fetch- to -depth ratio of the impoundment. The fetch is the linear distance across the treatment unit, and it is calculated from the unit’s surface area, assumin g a circular shape. That is,

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B-5 (Eq. B-6)
where: F = Fetch (m) For wind speeds less than 3.25 m/s, the following correlation is used regardless of the fetch- to -depth ratio (F/d liq 

### ):
(Eq. B-7)

where: k l,q 

### = Liquid phase, quiescent surface mass transfer coefficient (m/s) D i,l 

### = Diffusivity of constituent in liquid (water) (cm 2 

### /s) D ether 

### = Diffusivity of ether in water = 8.5 × 10 -6 

### cm 2 

### /s For windspeeds greater than or equal to 3.25 m/s, the appropriate correlation is dependent on the fetch- to

depth ratio as follows: (Eq. B-8)

where: a = Equation constant, a = 34.1 for U* > 0.3 m/s; a = 144 for U* < 0.3 m/s U * 

### = Friction velocity, m/s = 0.01U (6.1 + 0.63U) 0.5 

### U = Wind speed at 10 m above the liquid surface b = Equation constant, b = 1 for U* > 0.3 m/s; b = 2.2 for U* < 0.3 m/s Sc liq 

### = Liquid phase Schmidt number = μ l 

### /(ρ l 

### D i,l 

### ) μ l 

### = Viscosity of water (g/cm- s) ρ l 

### = Density of water (g/cm 3 

### )

(Eq. B-9)

(Eq. B-10)

B.1.4 Gas Phase Mass Transfer Coefficient for Quiescent Surfaces The gas phase mass transfer coefficient for quiescent surface areas is estimated as follows: (Eq. B-11)

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B-6 

## B .2 Collection Systems and Process Units B.2.1 Weirs Weirs are typically used in wastewater collection and treatment units as dams, allowing solids to settle in the quiescent areas. The first step in calculating air emissions is to calculate the volatilization-reaeration theory mass transfer coefficient ( K D 

### ), using equation B-12. Air emissions ( N ) for each pollutant are calculated using equation B-13.
(Eq. B-12)
(Eq. B-13) where: Q = Volumetric flow rate (m 3 

### /s)

Co = Initial constituent concentration (g/m 3 

### ) H = Weir height (ft) B.2.2 Junction Boxes and Lift Stations Junction boxes and lift stations collect and equalize wastewater prior to pumping to the wastewater treatment system. As previously mentioned, these components should be covered the vented; however, if uncovered, the following procedure can be used to estimate air emissions:

 Step 1: Calculate the liquid phase mass transfer coefficient for turbulent surfaces (k l,t 

### ) with Equation B-4. Alternatively, a simplified version specifically for junction boxes and lift stations that is based on default values presented in AP-42 yields: (Eq. B-14)

where: V = Unit volume (m 3 

### ) Default values:

J = 3 (lb/h/hp) O cf



### = 0.83 MW l 

### = 18 (g/mol) ρ l 

### = 1 (g/m 3 

### ) P tot 

### = 0.0264 (hp/m 3 

### ) ×V D O2,l 

### = 2.4×10 -5 

### (cm 2 

### /s)

 Step 2: Calculate the gas phase mass transfer coefficient for quiescent surfaces (k g,q 

### ) as described in Section B.1.4, Gas Phase Mass Transfer Coefficient for Quiescent Surfaces

.
 Step 3: Calculate the overall mass transfer coefficient (K) with the following equation: (Eq. B-15)

### Version 1.0 Ap pendix B

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B-7  Step 4: Calculate the tank effluent concentration (C L 

### ) with the following equation: (Eq. B-16)

 Step 5: Calculate the air emissions (N) with the following equation: (Eq. B-17) B.2.3 Sumps Sumps typically collect and equalize wastewater from various collection systems prior to treatment. As previously mentioned, these components should be covered the vented; however, if uncovered, the following procedure can be used to estimate air emissions:

 Step 1: Calculate the liquid phase mass transfer coefficient for quiescent surfaces (k l,q 

### ) as described in Section B.1.3, Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces

.
 Step 2: Calculate the gas phase mass transfer coefficient for quiescent surfaces (k g,q 

### ) as described in Section B.1.4, Gas Phase Mass Transfer Coefficient for Quiescent Surfaces

.
 Step 3: Calculate the overall mass transfer coefficient (K) with the following equation: (Eq. B-18)

 Step 8: Calculate the tank effluent concentration (C L 

### ) with the following equation: (Eq. B-19)

 Step 9: Calculate the air emissions (N) with the following equation: (Eq. B-20) B.2.4 Oil-Water Separators (API) An oil-water separator is a treatment unit designed to separate oil and suspended solids from wastewater. As previously mentioned, these units are typically covered and vented and thus open-air emissions estimations are not required. However, if the treatment units are uncovered, then the following procedure can be used to estimate air emissions. First, calculate the gas phase mass transfer coefficient for quiescent surfaces (k g,q 

### ) with Equation B-11. Next, calculate the overall mass transfer coefficient for oil (K oil 

### ) with the following equations: (Eq. B-21) where: (Eq. B-22) Air emissions are determined from the following equations: (Eq. B-23)

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B-8 where: (Eq. B-24) If the oil layer is > 1cm, then use this equation: (Eq. B-25) If the oil layer is < 1cm, then use this equation: (Eq. B-26)
(Eq. B-27) where: P* = Constituent vapor pressure (mm Hg) MW oil 

### = Molecular weight of oil (g/mol) ρ oil 

### = Density of oil (g/m 3 

### ) P 0 

### = Total pressure (atm) Q oil 

### = Volumetric flow rate of oil (m 3 

### /s) Co oil 

### = Initial concentration of constituent in oil phase (g/m 3 

### ) K ow 

### = Octanol-water partition coefficient f

oil 

### = Fraction of volume that is oil B.2.5 Dissolved Air Flotation DAF is a wastewater treatment unit that clarifies water by removing suspended oil and solids by bubble flotation. As previously mentioned, these treatment units are typically covered and vented to control devices. However, if the treatment units are uncovered, then the following procedure can be followed to estimate air emissions. First, the liquid phase mass transfer coefficient for quiescent surfaces (k l,q 

### ) can be determined by the method described in Section B.1.3, Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces

. Second, the gas phase mass transfer coefficient for quiescent surface (k g,q 

### ) can be calculated by the method described in Section B.1.4. Third, the overall mass transfer coefficient (K OL 

### ) can be determined by Equation B-1. Finally, the air emissions (N) can be calculated with the following equations: (Eq. B-28) where: (Eq. B-29)
B.2.6 Equalization Tanks (Mixed Tank with N o Biodegradation) Equalization tanks dampen variations in wastewater flow rate and pollutant load to lessen negative impacts on downstream processes. As previously mentioned, these tanks should be covered the vented; however, if these tanks are uncovered, then the following procedure can be used to estimate air emissions:

### Version 1.0 Ap pendix B

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B-9  Step 1: Calculate the liquid phase mass transfer coefficient for turbulent surfaces (k l,t 

### ) with Equation B-4.

 Step 2: Calculate the gas phase mass transfer coefficient for turbulent surfaces (k g,t 

### ) with Equation B-5.

 Step 3: Calculate the liquid phase mass transfer coefficient for quiescent surfaces (k l,q 

### ) as described in Section B.1.3, Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces

.
 Step 4: Calculate the gas phase mass transfer coefficient for quiescent surfaces (k g,q 

### ) as described in Section B.1.4, Gas Phase Mass Transfer Coefficient for Quiescent Surfaces

.
 Step 5: Calculate the overall mass transfer coefficient for turbulent surfaces (K OL,t 

### ) with Equation B-2.

 Step 6: Calculate the overall mass transfer coefficient for quiescent surfaces (K OL,q 

### ) with Equation B-3.

 Step 7: Calculate the overall mass transfer coefficient (K OL 

### ) with Equation B-1.

 Step 8: Calculate the tank effluent concentration (C L 

### ) with the following equation: (Eq. B-30)

 St ep 9: Calculate the air emissions (N) with the following equation: (Eq. B-31) B.2.7 Biological Treatment Unit (with a Known Wasting Rate) The determination of air emissions from biological treatment units is similar to equalization tanks with the addition of a biodegradation factor. Additionally, whereas turbulent and quiescent surface areas impact air emissions for mechanically aerated systems, the air volumetric flow rate impacts diffused aeration systems. Consequently, two slightly different methods are used to estimate air emissions. For mechanically aerated systems, follow Steps 1 through 7 of Section B.2.6 to determine the overall mass transfer coefficient (K OL 

### ). For diffused aeration systems, first calculate the average diffused air flow rate Q a,avg 

### (m 3 

### /s):

(Eq. B-32)
where: P g 

### = Blow gauge pressure (lb/in 2 

### ) P 0 

### = Atmospheric pressure (atm) × 14.696 (lb/in 2 

### atm)=(lb/in 2 

### ) Monteith et al . (1996) reported the effect of turbulence, induced by diffused bubble aeration, on mass transfer at the water surface. Correlations between the mass transfer of ammonia and VOCs were established and used to determine K L[NH4] 

### a, k l,t 

### a and k g,t 

### a with the following equations:
(Eq. B-33)

### Version 1.0 Ap pendix B

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B-10 where: K L[NH4] 

### a = Ammonium volumetric mass transfer coefficient (h -1 

### ) Note: make sure the units used are consistent (e.g., Q=m 3 

### /hr and A=m 2 

### )
(Eq. B-34)

where: D l,NH4 

### = Diffusivity of Ammonium in water (6.93×10 -5 

### cm 2 

### /s) k l,t 

### a = Volumetric liquid phase mass transfer coefficient (hr -1 

### ) The k l,t 

### values must then be calculated from the k l,t 

### a value with the following equation: (Eq. B-35)
where: k l,t 

### = Liquid phase mass transfer coefficient (m/s) a = Specific interfacial area based on liquid volume (m -1 

### ) = A/V V = Aeration basin volume (m 3 

### )
Note: k l,t 

### (m/hr) divided by 3600 (s/hr) = (m/s) Hsieh et al . (1992) reported the ratio of k g 

### /k l 

### ranged from 2.2 to 3.6 for diffused aeration systems. Therefore, k g 

### can be approximated by the following equation: (Eq. B-36) where: k g,t 

### = Gas phase mass transfer coefficient (m/s) The K OL,t 

### , K OL,q 

### , and K OL



### are then calculated by using steps by using equations B-2, B-3, and B-1. Next, calculate the tank effluent concentration (C L 

### ) and the emissions rate (N) with the following equations. For mechanically aerated systems: (Eq. B-37) For diffused aeration systems: (Eq. B-38) where: (Eq. B-39)

### Version 1.0 Ap pendix B

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B-11 For mechanically aerated systems: (Eq. B-40)

(Eq. B-41)
For diffused aerated systems: (Eq. B-42)

(Eq. B-43)
(Eq. B-44) where: Q w 

### = Wasted activated sludge flow rate (m 3 

### /s)

Q e 

### = Effluent flow rate (m 3 

### /s) Q i 

### = Influent flow rate (m 3 

### /s) K S 

### = Half saturation biorate constant (g/m 3 

### ) V

max 

### = Maximum biorate constant (g/s-g biomass) C

MLVSS 

### = Mixed-liquor volatile suspended solids (g /m 3 

### ) C WAS,VSS 

### = Wasted sludge volatile suspended solids (g/m 3 

### ) k

abs 

### = Partition coefficient for organic contaminant (m 3 

### /g) where: (Eq. B-45) f

OC 

### = Weight fraction of carbon in biomass (g C/g) (default value 0.33) K OC 

### = Organic carbon partition coefficient (g/ M gC/ ( g / m - 3 

### ) 1×10 - 6 

### = unit conversion (megagrams per gram, Mg/g) where: (Eq. B-46) B.2.8 Biological Treatment Unit (with an Unknown Wasting Rate) Air emissions estimate calculations from aerated lagoons are very similar to those for activated sludge units. The difference is sludge is not wasted from the lagoon, rather it settles and accumulates on the lagoon bottom until dredging. The assumptions made in this document are: (1) at steady-state conditions the amount of sludge that settles and thus removed from the unit is equal to the biomass production rate, and (2) once the sludge and associated contaminants settle, they are considered removed from the system. Follow the procedure in Section B.2.7 to determine the overall mass transfer coefficient (K OL 

### ), the unit effluent concentration (C L 

### ), and the emissions rate (N). However, variables a, b, and c are determined by the following equations

### Version 1.0 Ap pendix B

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B-12 For mechanically aerated systems: (Eq. B-47)

(Eq. B-48)
For diffused aerated system: (Eq. B-49)

(Eq. B-50)
(Eq. B-51) 

## B.3 References Hsieh, C., R. Babcock, and M. Stenstrom. 1992. Estimating semi-volatile organic compound emission rates and oxygen transfer coefficients in diffused aeration . Presented at the 65 th 

### Water Environment Federation Conference, New Orleans, LA, September 20

– 24. Monteith, H., W. Parker, and H. Melcer. 1996. Impact of bubble-induced surface turbulence on gas-liquid mass transfer in diffused aeration systems . Presented at the Water Environment Federation’s Annual Technical Exhibition and Conference, Dallas, TX, October 5

– 9. U.S. EPA (Environmental Protection Agency). 1994. Air Emissions Models for Waste and Wastewater

. EPA -453/R-94-080A. Office of Air Quality Planning and Standards, Research Triangle Park, NC. U.S. EPA (Environmental Protection Agency). 1995. Compilation of Air Pollutant Emission Factors

. Volume 1: Stationary Point and Area Sources. AP -42, Fifth Edition. Office of Air Quality Planning and Standards, Research Triangle Park, NC.

### Version 1.0 Appendix C

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# Appendix C Primer for TANKS Model Users

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C-3 

# C. Primer for TANKS Model Users In general, EPA recommends that the emissions estimation procedures detailed in Chapter 7.1 of AP-42 (U.S. EPA, 1995a) be used to calculate air pollutant emissions from organic liquid storage vessels. There are many tools available, such as TANKS v4.09D emissions estimation software that can be used to perform the necessary calculations detailed in Chapter 7.1 of AP-42 (U.S. EPA, 1995a). TANKS v4.09D software can be downloaded for free at: http://www.epa.gov/ttnchie1/software/tanks/index.html (under the How to Get TANKS 4.09D link). Because TANKS v4.09D is widely used, this appendix is included to provide tips and insights on using the TANKS program. This appendix will also highlight some potential enhancements to the modeling of storage tank emissions that may be implemented when using the AP-42 equations directly (or potentially other software packages) that are not currently afforded by TANKS v4.09D. The calculations in the TANKS program are specific to the type of tank, and the results will be highl y dependent on the type of liquid stored. Each individual storage tank should be modeled separately. There may be instances in which a set of tanks have identical properties and materials and very similar throughputs so that the emissions from a single storage tank can be modeled and used as the emissions for each tank in the set. However, this type of ―model tank‖ analysis should be used and generally be limited to situations in which limited data are available (i.e., if throughput is only measured by product and not by individual tank, then modeling a group of identical tanks used to store that product may be necessary). For inventories developed by the petroleum refinery or storage tank operators, it is recommended that individual tank data be entered into the TANKS program (or other similar software), and the emissions results for individual tanks be reported in the emissions inventory. For some uses of the emissions inventory data, specific emissions location and source characteristics data are needed. These data become lost or less accurate when emissions from a group of tanks (e.g., those that would be assigned to the same source classification code [SCC]) are aggregated when reporting to the emissions inventory. To enter a new tank, first select the tank type from the drop- down menu labeled ―Create a New Tank Record.‖ There are five basic tank types: horizontal fixed roof tanks; vertical fixed roof tanks; external floating roof tanks; internal floating roof tanks; and domed external floating roof tanks. Next, fill out the information in the Identification, Physical Characteristics, Site Selection, Tank Contents, and Monthly Calculations tabs with the appropriate information. Tables C-1 and C-2 show the required input by tank orientation. These inputs may either be from a drop-down list based on the TANKS database for location, tank color, and other tank-specific information or taken directly from process data. In TANKS, selecting the city will set the meteorological data that will be used in the calculations. After entering all of the requested data, the tank information can be saved by pressing the Save button at the bottom of the gray window.

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C-4 Table C-1. TANKS Inputs by Tank Configuration-Tank Dimensions and Characteristics

Horizontal Tank Vertical

Fi x ed - Roof Tank Internal

Floating Roof E x ternal

Floating Roof Domed

E x ternal Floating Roof Identification n umber      Description      State      City      Company      Dimensions a nd Characteristics Shell h eight ( feet [ ft ] )   Diameter (s hell diameter, ft )    Volume   Ma x imum l iquid h eight   Average l iquid h eight   Working v olume (gal lons )   Turnovers p er y ear     Net t hroughput (gal lons per year [gal /yr ] )    Is t ank h eated ?   Is t ank u nderground ?  Self

- s upporting r oof  Number of c olumns  Effective c olumn d iameter  Roof t ype   Roof f itting c ategory   Tank c onstruction  

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C-5 Table C-2. TANKS Inputs by Tank Configuration-Specific Attributes, Site Selection, and Contents

Horizontal Tank Vertical

Fi x ed - Roof Tank Internal

Floating Roof E x ternal

Floating Roof Domed

E x ternal Floating Roof Tank/Shell/Roof Characteristics (External) s hell /paint c olor/ s hade      (External) s hell /paint s hel l c ondition      Internal s hell c ondition  Rim Seal Primary s eal    Secondary s eal    Deck Characteristics Deck t ype  Deck f itting c ategory  Breather Vent Settings Vacuum s etting (psig)   Pressure s etting (psig )   Roof Characteristics Color/ s hade   Condition  Type  Height (ft)  Roof p aint c ondition  Site Selection Nearest m ajor c ity      Daily a verage a mbient t emp erature      Annual a verage m a x imum t emp erature      Annual a verage m inimum t emp erature      Average w ind s peed      Annual a verage s olar i nsulation f actor (B tu /(ft × ft × day)      Atmospheric p ressure ( pounds of force per square inch absolute [ psia ] )      Tank Contents Chem ical c ategory of l iquid      Single or m ulti

- c omponent l iquid      Mi x ture p roperties, if applicable      Throughput b y m onth     

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C-6 For the internal floating roof tank, the external floating roof tank, and the domed external floating roof tank, it is possible to define the fitting type to represent specific characteristics of the tanks at your facility. Using facility-specific tank information will ensure that the calculated emissions estimates are as accurate as possible. The fittings information can be entered under the Physical Characteristics tab by selecting the View/Add Fittings button and providing the fitting type and status. Table C-3 contains a list of the different fitting types and status options. Using the information provided in Tables C-1 through C-3 , the tanks program estimates the anticipated emissions specifically for the particular location, tank type, and process characteristics. Once a tank is entered, you can use or import that tank as a starting point for adding new tanks. To copy data from an existing tank to a new tank, select DATA, then TANKS, and then New Record from the TANKS 4.0 main menu or by selecting the appropriate acronym from the toolbar on the main screen. Click on the Copy button at the bottom of the tank pop-up screen. Then click on the tank that you want to copy from a dropdown menu, and then select whether you want to copy just the Tank Data, just the Liquid Data, or both (―All Data‖). Simply opening an existing tank and changing the name does n ot create a new tank record, it only renames and replaces the old record. Because TANKS uses preloaded meteorological data, year- to -year variations in emissions will only result from differing throughput or tank service (storing different material than in previous years). If accommodated in other software packages, meteorological data that are specific to the reporting year should be used because this information will provide more accurate emissions values. Studies have indicated that emissions may vary by up to 25% from year to year depending on the meteorological conditions for that year (Coburn and Icenhour, 2008). Also, if accommodated in other software packages, directly measured liquid temperatures or monthly average ambient temperatures should be used for the bulk liquid temperatures, and these values should be used to calculate monthly average emissions rates. In TANKS, even when using the monthly calculations option, unfortunately the annual average liquid temperature is still used. As such, unless there are extreme differences in throughputs by month, the monthly calculation procedures used in TANKS are unlikely to significantly alter the annual emissions estimates. Based on limited model analyses, monthly variations in liquid temperature may be significant and may influence the annual average emissions if monthly emissions are estimated more rigorously (i.e., by accounting for variations in bulk liquid temperature) (Coburn and Icenhour, 2008 ). The TANKS program typically provides total hydrocarbon emissions estimates. TANKS is also designed to calculate the individual component emissions from known mixtures and to estimate emissions from typical refined petroleum products. More than 100 organic liquids are included in the TANKS chemical database, but it is also designed to analyze other substances based on their chemical properties and the parameters shown in Table C-4 . If you store a component or mixture in the storage tanks and have available property data (i.e. chemical database inputs), then these can be added to the TANKS program. In addition to the analysis of individual chemicals, the TANKS program also has the capability to calculate the characteristics of defined mixtures. When the ―Multiple‖ option is selected for the ―Single or Multi-Compon ent Liquid‖ option, and ―Full Speciation‖ is selected for the ―Speciation‖ option, then the full chemical profile can be created using the ―View/Add Components‖ button. Any defined chemical, including those defined using the criteria in Table C-4 , can be included in the mixture as a component as long as the percentage of total liquid weight or relative weight is known. With the chemical components and their relative percentages and/or weights entered, the menu can be closed, and the mixture properties can b e calculated by clicking on the Calculate Mixture Properties button.

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C-7 Table C-3. Fitting Type and Status Option Inputs for TANKS Program Fitting Type Status

Access hatch (24 i n ches in d iam eter ) Bolted c over, g asketed Unbolted c over, g asketed Unbolte d c over, u ngasketed
Automatic g auge f loat w ell Bolted c over, g asketed Unbolted c over, g asketed Unbolted c over, u ngasketed

Column well (24 in ches in d iam eter ) Built

- u p c ol umn, s liding c over, g ask eted Built

- u p c ol umn, s liding c over, u ngask eted Pipe c ol umn, f lex ible f abric s leeve s eal Pipe c ol umn, s liding c over, g ask eted Pipe c ol umn, s liding c over, u ngask eted Gauge

- h atch/ s ample w ell (8 in ches in d iam eter ) Weighted m ech anical a ctuation, g ask eted Weighted mechanical actuation, ungasketed Ladder w ell (36 in ches in d iam eter ) Sliding cover, gasketed Sliding cover, ungasketed Rim v ent (6 in ches In d iameter) Weighted mechanical actuation, gasketed Weighted mechanical actuation, ungasketed Roof d rain (3 in ches in d iameter) Open 90% c losed

Roo f l eg (3 in ches In d iameter) Adjustable, p ontoon a rea, u ngasketed Adjustable, c enter a rea, u ngasketed Adjustable, d ouble

- d eck r oofs Fixed Adjustable, p ontoon a rea, g asketed Adjustable, p ontoon a rea, s ock Adjustable, c enter a rea, g asketed Adju stable, c enter a rea, s ock Roof l eg or h anger w ell Adjustable Fixed Sample p ipe or w ell (24 in ches In d iam eter ) Slotted p ipe , s liding c over, g ask eted Slotted p ipe , s liding c over, u ngask eted Slit f abric s eal 10% o pen

Slotted g uide

- p ole/ s ample w ell S liding c over, without f loat , u ngask eted Sliding c over, w ith f loat , u ngask eted Sliding c over, without f loat , g ask eted Sliding c over, w ith f loat, g ask eted Sliding c over, w ith p ole w iper, g ask eted Sliding c over, w ith p ole s leeve , g ask eted Sliding c over, w ith f loat, w iper, g ask eted Sliding c over, w ith f loat, s leeve, w iper, g ask eted Sliding c over, w ith p ole s leeve, w iper, g ask eted Stub d rain (1 in ch in d iameter) N one listed

Unslotted guide

- p ole w ell Sliding c over , u ngasketed Sliding c over , g a sketed Sliding c over , w ith s leeve u ngasketed Sliding c over , w ith s leeve, g ask eted Sliding c over , w ith w iper, g ask eted Vacuum breaker (10 in ches in d iam eter ) Weighted mechanical actuation , g ask eted Weighted mechanical actuation , ung ask eted

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C-8

Table C-4. Chemical Database Inputs for TANKS Chemical n ame CAS n umber (Chemical Abstracts Service number) Category Liq uid m ol ecular w eight Liq uid d ensity (lb/gal ; ~60 ° F) Vapor m olecular w eight Vapor p ressure at 40 ° F, 50 ° F, 60 ° F, 70 ° F, 80 ° F, 90 ° F, 100 ° F C onstants for Antoine's e quation using ° C (A, B , and C) Constants for Antoine's equation using °K (A and B) Reid vapor pressure (psia): Distillates and crude oil ASTM s lope: d istillates o nly

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D-1



# Appendix D Emission Factors from Air Toxic Emission Factors for Combustion Sources Using Petroleum Based Fuels
– Final Report, Volume 2
– Development of Emission Factors Using CARB Approach

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## D. Emission Factors from Air Toxic Emission Factors for Combustion Sources Using Petroleum Based Fuels
– Final Report, Volume 2
– Development of Emission Factors Using CARB Approach

 Detect Ratio: Ratio of detected values to the sum of detected and nondetected values.

 RSD: 100 times the standard deviation divided by the arithmetic average.

 Uncertainty: 100 times the 95% confidence interval divided by the arithmetic average. 

## Dioxin Acronyms 4D 2378 2,3,7,8

- Tetrachlorodibenzo

- p - dioxin. 4D Other Tetrachlorodibenzo

- p - dioxin other. 4D Total Tetrachlorodibenzo

- p - dioxin total. 5D 123 78 1,2,3,7,8

- Pentachlorodibenzo

- p - dioxin. 5D Other Pentachlorodibenzo

- p - dioxin other. 5D Total Pentachlorodibenzo

- p - dioxin total. 6D 123478 1,2,3,4,7,8

- Hexachlorodibenzo

- p - dioxin. 6D 123678 1,2,3,6,7,8

- Hexachlorodibenzo

- p - dioxin. 6D 123789 1,2,3 ,7,8,9

- Hexachlorodibenzo

- p - dioxin. 6D Other Hexachlorodibenzo

- p - dioxin other. 6D Total Hexachlorodibenzo

- p - dioxin. 7D 1234678 1,2,3,4,7,8

- Heptachlorodibenzo

- p - dioxin. 7D Other Heptachlorodibenzo

- p - dioxin other. 7D Total Heptachlorodibenzo

- p - dioxin tot al. 8D Octachlorodibenzo

- p - dioxin. 

## Furan Acronyms 4F 2378 2,3,7,8

- Tetrachlorodibenzofuran. 4F Other Tetrachlorodibenzofuran other. 4F Total Tetrachlorodibenzofuran total. 5F 12378 1,2,3,7,8

- Pentachlorodibenzofuran. 5F 23478 2,3,4,7,8

- Pentachlorodiben zofuran. 5F Other Pentachlorodibenzofuran other. 5F Total Pentachlorodibenzofuran total. 6F 123478 1,2,3,4,7,8

- Hexachlorodibenzofuran. 6F 123678 1,2,3,6,7,8

- Hexachlorodibenzofuran. 6F 123789 1,2,3,7,8,9

- Hexachlorodibenzofuran. 6F 234678 2,3,4,6,7,8

- H exachlorodibenzofuran. 6F Other Hexachlorodibenzofuran other. 6F Total Hexachlorodibenzofuran total. 7F 1234678 1,2,3,4,6,7,8

- Heptachlorodibenzofuran. 7F 1234789 1,2,3,4,7,8,9

- Heptachlorodibenzofuran. 7F Other Heptachlorodibenzofuran other. 7F Total Heptachlorodibenzofuran total. 8F Octachlorodibenzofuran.

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D-4 Table D- 1a. Summary of Data for Emission Factor Development
– Asphalt Blowing with Blow Cycle and a Thermal Oxidizer

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % D etect Ratio Mean Median Maximum Minimum Acetaldehyde C3

- v - 1.78E

- 03 1.78E

- 03 1.78E

- 03 1.78E

- 03 1 0.00 0.00 1.00 Arsenic D3

- v - 1.31E

- 02 1

. 31 E

- 0 2 1

. 31 E

- 0 2 1

. 31 E

- 0 2 1 0.00 0.00 0.00 Benzene E3

- v - 3.16E

- 01 3.16E

- 01 3.16E

- 01 3.16E

- 01 1 0.00 0.00 0. 00 Beryllium D3

- v - 2.63E

- 03 2

. 63 E

- 0 3 2

. 63 E

- 0 3 2

. 63 E

- 0 3 1 0.00 0.00 0.00 Cadmium D3

- v - 5.25E

- 03 5

. 25 E

- 0 3 5

. 25 E

- 0 3 5

. 25 E

- 0 3 1 0.00 0.00 0.00 Chromium (Hex) C3

- v - 3.17E

- 03 3

. 17 E

- 0 3 3

. 17 E

- 0 3 3

. 17 E

- 0 3 1 0.00 0.00 1.00 Chromium (Total) C3

- v - 4.18E

- 02 4.1 8E

- 02 4.18E

- 02 4.18E

- 02 1 0.00 0.00 1.00 Copper D3

- v - 4.75E

- 02 4.75E

- 02 4.75E

- 02 4.75E

- 02 1 0.00 0.00 1.00 Ethylbenzene E3

- v - 8.61E

- 01 8.61E

- 01 8.61E

- 01 8.61E

- 01 1 0.00 0.00 0.00 Formaldehyde C3

- v - 3.55E

- 03 3.55E

- 03 3.55E

- 03 3.55E

- 03 1 0.00 0.00 1.00 HCl C3

- v - 2.21E

- 03 2.21E

- 03 2.21E

- 03 2.21E

- 03 1 0.00 0.00 1.00 Hydrogen Sulfide A3

- v - 2.07E+00 2.07E+00 2.07E+00 2.07E+00 1 0.00 0.00 0.00 Lead D3

- v - 5.25E

- 02 5.25E

- 02 5.25E

- 02 5.25E

- 02 1 0.00 0.00 0.00 Manganese D3

- v - 1.23E

- 01 1.23E

- 01 1.23E

- 01 1 .23E

- 01 1 0.00 0.00 1.00 Mercury A3

- v - 9.07E

- 03 9.07E

- 03 9.07E

- 03 9.07E

- 03 1 0.00 0.00 1.00 Nickel D3

- v - 6.65E

- 02 6.65E

- 02 6.65E

- 02 6.65E

- 02 1 0.00 0.00 0.00 Phenol C3

- v - 7.57E

- 02 7.57E

- 02 7.57E

- 02 7.57E

- 02 1 0.00 0.00 1.00 Selenium D3

- v - 1.31E

- 02 1.31E

- 02 1.31E

- 02 1.31E

- 02 1 0.00 0.00 0.00 Xylene (Total) E3

- v - 8.61E

- 01 8.61E

- 01 8.61E

- 01 8.61E

- 01 1 0.00 0.00 0.00 Zinc D3

- v - 8.41E

- 01 8.41E

- 01 8.41E

- 01 8.41E

- 01 1 0.00 0.00 1.00

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D-5 Table D-1b. Summary of Data for Emission Factor Development
– Asphalt Blowing with Blow Cycle and a Thermal Oxidizer

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde C3

- v - 1.67E

- 06 1.67E

- 06 1.67E

- 06 1.67E

- 06 1 0.00 0.00 1.00 Arsen ic D3

- v - 1.23E

- 05 1.23E

- 05 1.23E

- 05 1.23E

- 05 1 0.00 0.00 0.00 Benzene E3

- v - 2.98E

- 04 2.98E

- 04 2.98E

- 04 2.98E

- 04 1 0.00 0.00 0.00 Beryllium D3

- v - 2.47E

- 06 2.47E

- 06 2.47E

- 06 2.47E

- 06 1 0.00 0.00 0.00 Cadmium D3

- v - 4.94E

- 06 4.94E

- 06 4.94E

- 06 4.94E

- 06 1 0.00 0.00 0.00 Chromium (Hex) C3

- v - 2.99E

- 06 2.99E

- 06 2.99E

- 06 2.99E

- 06 1 0.00 0.00 1.00 Chromium (Total) C3

- v - 3.94E

- 05 3.94E

- 05 3.94E

- 05 3.94E

- 05 1 0.00 0.00 1.00 Copper D3

- v - 4.47E

- 05 4.47E

- 05 4.47E

- 05 4.47E

- 05 1 0.00 0.00 1.00 Ethylbenzene E3

- v - 8.10E

- 04 8.10E

- 04 8.10E

- 04 8.10E

- 04 1 0.00 0.00 0.00 Formaldehyde C3

- v - 3.34E

- 06 3.34E

- 06 3.34E

- 06 3.34E

- 06 1 0.00 0.00 1.00 HCl C3

- v - 2.08E

- 06 2.08E

- 06 2.08E

- 06 2.08E

- 06 1 0.00 0.00 1.00 Hydrogen Sulfide A3

- v - 1.95E

- 03 1.95E

- 03 1.95E

- 03 1.95E

- 03 1 0.00 0.00 0.00 Lead D3

- v - 4.94E

- 05 4.94E

- 05 4.94E

- 05 4.94E

- 05 1 0.00 0.00 0.00 Manganese D3

- v - 1.16E

- 04 1.16E

- 04 1.16E

- 04 1.16E

- 04 1 0.00 0.00 1.00 Mercury A3

- v - 8.53E

- 06 8.53E

- 06 8.53E

- 06 8.53E

- 06 1 0.00 0.00 1.00 Nickel D3

- v - 6.26E

- 05 6.26E

- 05 6.26E

- 05 6.26E

- 05 1 0.00 0.00 0.00 Phenol C3

- v - 7.12E

- 05 7.12E

- 05 7.12E

- 05 7.12E

- 05 1 0.00 0.00 1.00 Selenium D3

- v - 1.23E

- 05 1.23E

- 05 1.23E

- 05 1.23E

- 05 1 0.00 0.00 0.00 Xylene (Total) E3

- v - 8.10E

- 04 8.10E

- 04 8.10E

- 04 8.10E

- 04 1 0.00 0.00 0.00 Zinc D3

- v - 7.91E

- 04 7.91E

- 04 7.91E

- 04 7.91E

- 04 1 0.00 0.00 1.00

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D-6 Table D- 2a. Summary of Data for Emission Factor Development
– Asphalt Blowing with No Blow Cycle and a Thermal Oxidizer

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde C3

- v - 4.32E

- 03 4.32E

- 03 4.32E

- 03 4.32E

- 03 1 0.00 0.00 1.00 Arsenic D3

- v - 1.16E

- 02 1.16E

- 02 1.16E

- 02 1.16E

- 02 1 0.00 0.00 0.00 Benzene E3

- v - 2.80E

- 01 2.80E

- 01 2.80E

- 01 2.80E

- 01 1 0.00 0.0 0 0.00 Beryllium D3

- v - 2.33E

- 03 2.33E

- 03 2.33E

- 03 2.33E

- 03 1 0.00 0.00 0.00 Cadmium D3

- v - 4.65E

- 03 4.65E

- 03 4.65E

- 03 4.65E

- 03 1 0.00 0.00 0.00 Chromium (Hex) C3

- v - 3.28E

- 03 3.28E

- 03 3.28E

- 03 3.28E

- 03 1 0.00 0.00 0.00 Chromium (Total) C3

- v - 1.42E

- 02 1.42E

- 02 1.42E

- 02 1.42E

- 02 1 0.00 0.00 0.00 Copper D3

- v - 3.79E

- 02 3.79E

- 02 3.79E

- 02 3.79E

- 02 1 0.00 0.00 1.00 Ethylbenzene E3

- v - 7.62E

- 01 7.62E

- 01 7.62E

- 01 7.62E

- 01 1 0.00 0.00 0.00 Formaldehyde C3

- v - 1.30E

- 02 1.30E

- 02 1.30E

- 02 1.30E

- 02 1 0.00 0.00 1.00 HCl C3

- v - 8.22E

- 04 8.22E

- 04 8.22E

- 04 8.22E

- 04 1 0.00 0.00 1.00 Hydrogen Sulfide A3

- v - 1.83E+00 1.83E+00 1.83E+00 1.83E+00 1 0.00 0.00 0.00 Lead D3

- v - 4.65E

- 02 4.65E

- 02 4.65E

- 02 4.65E

- 02 1 0.00 0.00 0.00 Manganese D3

- v - 2.07E

- 01 2.07E

- 01 2.07E

- 01 2.07E

- 01 1 0.00 0.00 1.00 Mercury A3

- v - 8.53E

- 03 8.53E

- 03 8.53E

- 03 8.53E

- 03 1 0.00 0.00 1.00 Nickel D3

- v - 6.01E

- 02 6.01E

- 02 6.01E

- 02 6.01E

- 02 1 0.00 0.00 0.00 Phenol C3

- v - 4.64E

- 02 4.64E

- 02 4.64E

- 02 4.64E

- 02 1 0.00 0.00 1.00 Selenium D3

- v - 1.16E

- 02 1.16E

- 02 1.16E

- 02 1.16E

- 02 1 0.00 0.00 0.00 Xylene (Total) E3

- v - 7.62E

- 01 7.62E

- 01 7.62E

- 01 7.62E

- 01 1 0.00 0.00 0.00 Zinc D3

- v - 5.35E

- 01 5.35E

- 01 5.35E

- 01 5.35E

- 01 1 0.00 0.00 1.00

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— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-7 Table D-2b. Summary of Data for Emission Factor Development
– Asphalt Blowing with No Blow Cycle and a Thermal Oxidizer

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde C3

- v - 4.07E

- 06 4.07E

- 06 4.07E

- 06 4.07E

- 06 1 0.00 0.00 1.00 Arsenic D3

- v - 1.09E

- 05 1.09E

- 05 1.09E

- 05 1.09E

- 05 1 0.00 0.00 0.00 Benzene E3

- v - 2.64E

- 04 2.64E

- 04 2.64E

- 04 2.64E

- 04 1 0.00 0.00 0.00 Beryllium D3

- v - 2.19E

- 06 2.19E

- 06 2.19E

- 06 2.19E

- 06 1 0.00 0.00 0.00 Cadmium D3

- v - 4.37E

- 06 4.37E

- 06 4.37E

- 06 4.37E

- 06 1 0.00 0.00 0.00 Chromium (Hex) C3

- v - 3.09E

- 06 3.09E

- 06 3.09E

- 06 3.09E

- 06 1 0.00 0.00 0.00 Chromium (Total) C3

- v - 1.34E

- 05 1.34E

- 05 1.34E

- 05 1.34E

- 05 1 0.00 0.00 0.00 Copper D3

- v - 3.56E

- 05 3.56E

- 05 3.56E

- 05 3.56E

- 05 1 0.00 0.00 1.00 Ethylbenzene E3

- v - 7.17E

- 04 7.17E

- 04 7.17E

- 04 7.17E

- 04 1 0.00 0.00 0.00 Formaldehyde C3

- v - 1.22E

- 05 1.22E

- 05 1.22E

- 05 1.22E

- 05 1 0.00 0.00 1.00 HCl C3

- v - 7.74E

- 07 7.74E

- 07 7.74E

- 07 7.74E

- 07 1 0.00 0.00 1.00 Hydrogen Sulfide A3

- v - 1.73E

- 03 1.73E

- 03 1.73E

- 03 1.73E

- 03 1 0.00 0.00 0.00 Lead D3

- v - 4.38E

- 05 4.38E

- 05 4.38E

- 05 4.38E

- 05 1 0.00 0.00 0.00 Manganese D3

- v - 1.95E

- 04 1.95E

- 04 1.95E

- 04 1.95E

- 04 1 0.00 0.00 1.00 Mercury A3

- v - 8.03E

- 06 8.03E

- 06 8.03E

- 06 8.03E

- 06 1 0.00 0.00 1.00 Nickel D3

- v - 5.65E

- 05 5.65E

- 05 5.65E

- 05 5.65E

- 05 1 0.00 0.00 0.00 Phenol C3

- v - 4.37E

- 05 4.37E

- 05 4.37E

- 05 4.37E

- 05 1 0.00 0.00 1.00 Selenium D3

- v - 1.09E

- 05 1.09E

- 05 1.09E

- 05 1.09E

- 05 1 0 .00 0.00 0.00 Xylene (Total) E3

- v - 7.17E

- 04 7.17E

- 04 7.17E

- 04 7.17E

- 04 1 0.00 0.00 0.00 Zinc D3

- v - 5.04E

- 04 5.04E

- 04 5.04E

- 04 5.04E

- 04 1 0.00 0.00 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-8 Table D- 3a. Summary of Data for Emission Factor Development
– Boilers Firing Fuel Oil

S ubstance CARB

Rating Emission Factor (lb/Mgal) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene B3

- v0 8.93E

- 07 8.50E

- 07 1.56E

- 06 3.34E

- 07 2 67.31 53.86 0.87 Acenaphthylene B3

- v0 3.17E

- 07 3.28E

- 07 3.58E

- 07 2.34E

- 07 2 14.29 11.43 0.00 Acetaldehyde A3

- v1 1.04E

- 03 4.98E

- 04 3.35E

- 03 2.80E

- 04 2 116.00 92.82 0.75 Acrolein A3

- v0 2.17E

- 03 1.75E

- 03 3.35E

- 03 1.43E

- 03 1 47.31 53.53 0.00 Anthracene B3

- v1 3.22E

- 07 2.84E

- 07 7.42E

- 07 1.90E

- 08 2 98.99 79.20 0.94 Arsenic B3

- v0 1.44E

- 03 1

. 44 E

- 0 3 1.68E

- 03 1.19E

- 03 1 17.00 19.24 0.00 Benzene A3

- v0 4.63E

- 03 4.67E

- 03 4.76E

- 03 4.47E

- 03 1 3.26 3.69 0.00 Benzo(a)anthracene B3

- v1 2.04E

- 07 2.21E

- 07 3.58E

- 07 2.98E

- 08 2 78.58 62.87 0.00 Benzo(a)pyrene B 3

- v0 2.09E

- 07 2.24E

- 07 3.5 8E

- 07 4.61E

- 08 2 73.55 58.55 0.00 Benzo(b)fluoranthene B 3

- v0 1.21E

- 06 1.02E

- 06 2.36E

- 06 3.34E

- 07 2 73.99 59.20 0.40 Benzo(e)pyrene C 3

- v0 8.53E

- 07 1.03E

- 06 1.12E

- 06 4.11E

- 07 1 45.15 51.09 0.00 Benzo(g,h,i)perylene B3

- v0 9.99E

- 07 8.47E

- 07 2.20E

- 06 3.34E

- 07 2 77.58 62.08 0.00 Benzo(k)fluoranthene B3

- v1 2.08E

- 07 2.37E

- 07 3.58E

- 07 2.98E

- 08 2 76.76 61.42 0.00 Beryllium B3

- v0 6.29E

- 05 6.35E

- 05 7.03E

- 05 5.50E

- 05 1 12.22 13.83 0.00 1,3

- Butadiene B3

- v1 6.17E

- 03 5.97E

- 03 1.18E

- 02 8.95E

- 04 2 93.74 75.01 0.00 Cadmium B3

- v0 8.56E

- 04 6.58E

- 04 1.26E

- 03 6.47E

- 04 1 41.15 46.57 0.00 Chloroform A3

- v0 4.69E

- 03 5.00E

- 03 5.10E

- 03 4.78E

- 03 1 3.26 3.69 0.00 2

- Chloronaphthalene C3

- v0 2.27E

- 08 2.33E

- 08 2.86E

- 08 1.63E

- 08 1 27.13 30.70 0.00 Chromium (Hex) A3

- v0 1.15E

- 03 1. 15E

- 03 1.21E

- 03 1.09E

- 03 1 4.95 5.60 0.00 Chromium (Total) A3

- v0 4.83E

- 03 5.18E

- 03 5.85E

- 03 3.45E

- 03 1 25.70 29.08 1.00 Chrysene B3

- v0 3.88E

- 06 3.26E

- 06 8.57E

- 06 1.16E

- 06 2 78.87 63.11 1.00 Copper B3

- v0 3.86E

- 03 2.02E

- 03 8.67E

- 03 8.92E

- 04 1 108.86 12 3.19 1.00 Dibenz(a,h)anthracene B3

- v1 7.06E

- 07 3.43E

- 07 2.68E

- 06 2.07E

- 07 2 136.88 109.33 0.00 Dioxin: 4D 2378 C3

- v0 6.33E

- 10 5.71E

- 10 7.83E

- 10 5.46E

- 10 1 20.50 23.20 0.00 Dioxin: 5D 12378 C3

- v0 3.68E

- 10 2.73E

- 10 5.71E

- 10 2.61E

- 10 1 47.67 53.94 0.00 Dioxin: 6D 123478 C3

- v0 3.68E

- 10 2.73E

- 10 5.71E

- 10 2.61E

- 10 1 47.67 53.94 0.00 Dioxin: 6D 123678 C3

- v0 3.68E

- 10 2.73E

- 10 5.71E

- 10 2.61E

- 10 1 47.67 53.94 0.25 Dioxin: 6D 123789 C3

- v0 3.68E

- 10 2.73E

- 10 5.71E

- 10 2.61E

- 10 1 47.67 53.94 0.25 Dioxin: 7D 12346 78 C3

- v0 3.12E

- 09 2.86E

- 09 5.19E

- 09 1.30E

- 09 1 62.77 71.03 1.00 Dioxin: 8D C3

- v0 7.50E

- 08 8.28E

- 08 1.23E

- 07 1.93E

- 08 1 69.66 78.83 1.00 Fluoranthene B3

- v1 7.78E

- 06 6.18E

- 06 1.65E

- 05 9.31E

- 07 2 87.83 70.27 1.00 Fluorene B3

- v0 4.65E

- 06 4.60E

- 06 8.48E

- 0 6 8.93E

- 07 2 83.31 66.66 1.00 Formaldehyde A3

- v1 6.72E

- 03 7.14E

- 03 1.67E

- 02 2.83E

- 04 2 91.09 72.89 0.18 Furan: 4F 2378 C3

- v0 8.16E

- 10 7.83E

- 10 1.09E

- 09 5.71E

- 10 1 32.18 36.42 1.00 Furan: 5F 12378 C3

- v0 4.59E

- 10 5.46E

- 10 5.71E

- 10 2.61E

- 10 1 37.52 42.4 6 0.00 Furan: 5F 23478 C3

- v0 4.59E

- 10 5.46E

- 10 5.71E

- 10 2.61E

- 10 1 37.52 42.46 0.00 Furan: 6F 123478 C3

- v0 3.64E

- 10 2.86E

- 10 5.46E

- 10 2.61E

- 10 1 43.44 49.15 0.50 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-9 Table D - 3a. Summary of Data for Emission Factor Development
– Boilers Firing Fuel Oil (continued)

Substance CARB

Rating Emission Factor (lb/Mgal) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Furan: 6F 123678 C3

- v0 2.73E

- 10 2.73E

- 10 2.86E

- 10 2.61E

- 10 1 4.51 5.10 0.33 Furan: 6F 123789 C3

- v0 3.68E

- 1 0 2.73E

- 10 5.71E

- 10 2.61E

- 10 1 47.67 53.94 0.00 Furan: 6F 234678 C3

- v0 5.51E

- 10 5.71E

- 10 8.20E

- 10 2.61E

- 10 1 50.85 57.54 0.50 Furan: 7F 1234678 C3

- v0 1.44E

- 09 1.14E

- 09 2.09E

- 09 1.09E

- 09 1 38.89 44.01 1.00 Furan: 7F 1234789 C3

- v0 4.64E

- 10 2.73E

- 10 8.57E

- 10 2.61E

- 10 1 73.43 83.10 0.00 Furan: 8F C3

- v0 7.15E

- 09 7.14E

- 09 1.04E

- 08 3.91E

- 09 1 45.27 51.23 1.00 Indeno(1,2,3

- cd) pyrene B3

- v0 4.59E

- 07 3.55E

- 07 7.82E

- 07 2.90E

- 07 2 43.75 35.01 0.00 Lead B3

- v0 1.56E

- 03 8.59E

- 04 3.32E

- 03 4.89E

- 04 1 98.91 111.92 0. 00 Manganese B3

- v0 5.81E

- 03 2.82E

- 03 1.22E

- 02 2.40E

- 03 1 95.34 107.89 1.00 Mercury B3

- v0 1.03E

- 05 9.04E

- 06 1.47E

- 05 7.19E

- 06 1 38.06 43.07 0.00 2

- Methylnaphthalene C3

- v0 1.09E

- 05 1.07E

- 05 1.22E

- 05 9.76E

- 06 1 11.52 13.04 1.00 Naphthalene B3

- v0 6.07E

- 05 6.22E

- 05 8.12E

- 05 4.25E

- 05 2 25.60 20.48 1.00 Nickel B3

- v0 3.34E

- 01 3.05E

- 01 4.06E

- 01 2.90E

- 01 1 18.95 21.44 1.00 Perylene C3

- v0 1.09E

- 07 5.95E

- 08 2.20E

- 07 4.88E

- 08 1 87.56 99.09 0.00 Phenanthrene B3

- v0 1.10E

- 05 1.10E

- 05 1.99E

- 05 3.29E

- 06 2 57.8 6 46.30 1.00 Propylene A3

- v0 2.19E

- 02 2.21E

- 02 2.25E

- 02 2.11E

- 02 1 3.26 3.69 0.00 Pyrene B3

- v1 4.01E

- 06 2.35E

- 06 1.08E

- 05 3.53E

- 07 2 110.05 88.06 0.97 Selenium B3

- v0 2.88E

- 03 3.59E

- 03 3.61E

- 03 1.45E

- 03 1 43.13 48.81 0.17 Toluene A3

- v0 5.75E

- 03 5. 79E

- 03 5.91E

- 03 5.55E

- 03 1 3.26 3.69 0.00 Xylene (Total) A3

- v0 1.10E

- 02 1.11E

- 02 1.14E

- 02 1.06E

- 02 1 3.26 3.69 0.00 Zinc B3

- v0 1.60E

- 02 8.61E

- 03 3.09E

- 02 8.56E

- 03 1 80.41 90.99 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-10 Table D-3b. Summary of Data for Emission Factor Development
– Boilers Firing Fuel Oil

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene B3

- v0 6.00E

- 09 5.71E

- 09 1.06E

- 08 2.14E

- 09 2 69.26 55.42 0.87 Acenaphthylene B3

- v0 2.09E

- 09 2 .16E

- 09 2.29E

- 09 1.59E

- 09 2 12.32 9.86 0.00 Acetaldehyde A3

- v1 6.99E

- 06 3.33E

- 06 2.28E

- 05 1.79E

- 06 2 117.49 94.01 0.75 Acrolein A3

- v0 1.48E

- 05 1.19E

- 05 2.28E

- 05 9.69E

- 06 1 47.31 53.53 0.00 Anthracene B3

- v1 2.07E

- 09 1.83E

- 09 4.76E

- 09 1.29E

- 10 2 98.24 78.60 0.94 Arsenic B3

- v0 9.76E

- 06 9.76E

- 06 1.14E

- 05 8.10E

- 06 1 17.00 19.24 0.00 Benzene A3

- v0 3.15E

- 05 3.17E

- 05 3.24E

- 05 3.04E

- 05 1 3.26 3.69 0.00 Benzo(a)anthracene B3

- v1 1.32E

- 09 1.44E

- 09 2.29E

- 09 2.03E

- 10 2 77.09 61.68 0.00 Benzo(a) pyrene B3

- v0 1.36E

- 09 1.46E

- 09 2.29E

- 09 3.13E

- 10 2 71.84 57.48 0.00 Benzo(b)fluoranthene B3

- v0 8.11E

- 09 6.77E

- 09 1.60E

- 08 2.14E

- 09 2 75.81 60.66 0.40 Benzo(e)pyrene C3

- v0 5.80E

- 09 7.00E

- 09 7.60E

- 09 2.80E

- 09 1 45.15 51.09 0.00 Benzo(g,h,i)peryle ne B3

- v0 6.72E

- 09 5.69E

- 09 1.50E

- 08 2.14E

- 09 2 79.36 63.50 0.00 Benzo(k)fluoranthene B3

- v1 1.34E

- 09 1.55E

- 09 2.29E

- 09 2.03E

- 10 2 75.32 60.26 0.00 Beryllium B3

- v0 4.28E

- 07 4.32E

- 07 4.78E

- 07 3.74E

- 07 1 12.22 13.83 0.00 1,3

- Butadiene B3

- v1 4.18E

- 05 4.04E

- 05 8.00E

- 05 5.74E

- 06 2 94.58 75.68 0.00 Cadmium B3

- v0 5.82E

- 06 4.47E

- 06 8.58E

- 06 4.40E

- 06 1 41.15 46.57 0.00 Chloroform A3

- v0 3.37E

- 05 3.40E

- 05 3.47E

- 05 3.25E

- 05 1 3.26 3.69 0.00 2

- Chloronaphthalene C3

- v0 1.54E

- 10 1.58E

- 10 1.94E

- 10 1.1 1E

- 10 1 27.13 30.70 0.00 Chromium (Hex) A3

- v0 7.82E

- 06 7.85E

- 06 8.20E

- 06 7.43E

- 06 1 4.95 5.60 0.00 Chromium (Total) A3

- v0 3.28E

- 05 3.52E

- 05 3.98E

- 05 2.34E

- 05 1 25.70 29.08 1.00 Chrysene B3

- v0 2.62E

- 08 2.19E

- 08 5.83E

- 08 7.46E

- 09 2 80.59 64.48 1.00 Copper B3

- v0 2.62E

- 05 1.37E

- 05 5.89E

- 05 6.07E

- 06 1 108.86 123.19 1.00 Dibenz(a,h)anthracene B3

- v1 4.73E

- 09 2.20E

- 09 1.82E

- 08 1.41E

- 09 2 139.45 111.58 0.00 Dioxin:4D 2378 C3

- v0 4.31E

- 12 3.88E

- 12 5.32E

- 12 3.71E

- 12 1 20.50 23.20 0.00 Dioxin: 5D 12378 C3

- v0 2.50E

- 12 1.86E

- 12 3.88E

- 12 1.77E

- 12 1 47.67 53.94 0.00 Dioxin:6D 123478 C3

- v0 2.50E

- 12 1.86E

- 12 3.88E

- 12 1.77E

- 12 1 47.67 53.94 0.00 Dioxin:6D 123678 C3

- v0 2.50E

- 12 1.86E

- 12 3.88E

- 12 1.77E

- 12 1 47.67 53.94 0.25 Dioxin:6D 123789 C3

- v0 2.50E

- 12 1.86E

- 12 3.88E

- 12 1.77E

- 12 1 47.67 53.94 0.25 Dioxin:7D 1234678 C3

- v0 2.12E

- 11 1.94E

- 11 3.53E

- 11 8.87E

- 12 1 62.77 71.03 1.00 Dioxin:8D C3

- v0 5.10E

- 10 5.63E

- 10 8.36E

- 10 1.31E

- 10 1 69.66 78.83 1.00 Fluoranthene B3

- v1 5.25E

- 08 4.14E

- 08 1.12E

- 07 5.97E

- 09 2 89.14 71.33 1.00 Fluorene B3

- v1 3.14E

- 08 3.10E

- 08 5.76E

- 08 5.73E

- 09 2 84.62 67.71 1.00 Formaldehyde A3

- v1 4.52E

- 05 4.72E

- 05 1.14E

- 04 1.82E

- 06 2 92.14 73.72 0.18 Furan:4F 2378 C3

- v0 5.54E

- 12 5.32E

- 12 7.43E

- 12 3.88E

- 12 1 3 2.18 36.42 1.00 Furan:5F 12378 C3

- v0 3.12E

- 12 3.71E

- 12 3.88E

- 12 1.77E

- 12 1 37.52 42.46 0.00 Furan:5F 23478 C3

- v0 3.12E

- 12 3.71E

- 12 3.88E

- 12 1.77E

- 12 1 37.52 42.46 0.00 Furan:6F 123478 C3

- v0 2.48E

- 12 1.94E

- 12 3.71E

- 12 1.77E

- 12 1 43.44 49.15 0. 50 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-11 Table D - 3b. Summary of Data for Emission Factor Development
– Boilers Firing Fuel Oil (continued)

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Furan:6F 12 3678 C3

- v0 1.86E

- 12 1.86E

- 12 1.94E

- 12 1.77E

- 12 1 4.51 5.10 0.33 Furan:6F 123789 C3

- v0 2.50E

- 12 1.86E

- 12 3.88E

- 12 1.77E

- 12 1 47.67 53.94 0.00 Furan:6F 234678 C3

- v0 3.74E

- 12 3.88E

- 12 5.57E

- 12 1.77E

- 12 1 50.85 57.54 0.50 Furan:7F 1234678 C3

- v0 9. 79E

- 12 7.76E

- 12 1.42E

- 11 7.43E

- 12 1 38.89 44.01 1.00 Furan:7F 1234789 C3

- v0 3.15E

- 12 1.86E

- 12 5.82E

- 12 1.77E

- 12 1 73.43 83.10 0.00 Furan:8F C3

- v0 4.86E

- 11 4.85E

- 11 7.06E

- 11 2.66E

- 11 1 45.27 51.23 1.00 Indeno(1,2,3

- cd)pyrene B3

- v0 3.05E

- 09 2.28E

- 09 5.32E

- 09 1.97E

- 09 2 46.19 36.96 0.00 Lead B3

- v0 1.06E

- 05 5.84E

- 06 2.26E

- 05 3.32E

- 06 1 98.91 111.92 0.00 Manganese B3

- v0 3.95E

- 05 1.92E

- 05 8.29E

- 05 1.63E

- 05 1 95.34 107.89 1.00 Mercury B3

- v0 7.02E

- 08 6.15E

- 08 1.00E

- 07 4.89E

- 08 1 38.06 43.07 0.00 2

- Methylnaphthalene C3

- v0 7.40E

- 08 7.25E

- 08 8.32E

- 08 6.63E

- 08 1 11.52 13.04 1.00 Naphthalene B3

- v0 4.04E

- 07 4.11E

- 07 5.52E

- 07 2.73E

- 07 2 28.11 22.49 1.00 Nickel B3

- v0 2.27E

- 03 2.08E

- 03 2.76E

- 03 1.97E

- 03 1 18.95 21.44 1.00 Perylene C3

- v 0 7.44E

- 10 4.05E

- 10 1.49E

- 09 3.32E

- 10 1 87.56 99.09 0.00 Phenanthrene B3

- v0 7.39E

- 08 7.35E

- 08 1.35E

- 07 2.11E

- 08 2 60.02 48.02 1.00 Propylene A3

- v0 1.49E

- 04 1.50E

- 04 1.53E

- 04 1.44E

- 04 1 3.26 3.69 0.00 Pyrene B3

- v1 2.72E

- 08 1.58E

- 08 7.37E

- 08 2.26 E

- 09 2 110.83 88.68 0.97 Selenium B3

- v0 1.96E

- 05 2.44E

- 05 2.45E

- 05 9.83E

- 06 1 43.13 48.81 0.17 Toluene A3

- v0 3.91E

- 05 3.94E

- 05 4.02E

- 05 3.77E

- 05 1 3.26 3.69 0.00 Xylene (Total) A3

- v0 7.51E

- 05 7.56E

- 05 7.72E

- 05 7.24E

- 05 1 3.26 3.69 0.00 Zinc B3

- v0 1.09E

- 04 5.86E

- 05 2.10E

- 04 5.82E

- 05 1 80.41 90.99 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-12 Table D- 4a. Summary of Data for Emission Factor Development
–

Boilers Firing Refinery Fuel Gas

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio M ean Median Maximum Minimum Acenaphthene A3

- v0 5.88E

- 06 5.75E

- 06 6.47E

- 06 5.44E

- 06 1 8.97 10.15 0.37 Acenaphthylene A3

- v0 2.56E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Acetaldehyde C1

- v3 3.97E

- 03 2.43E

- 03 1.21E

- 02 4.92E

- 06 5 100.80 51.01 1.00 Anthracene A3

- v0 2.28E

- 05 2.50E

- 05 3.89E

- 05 4.40E

- 06 1 76.23 86.26 1.00 Arsenic D3

- v0 7.04E

- 04 7.65E

- 04 1.13E

- 03 2.11E

- 04 1 66.10 74.80 1.00 Benzene C1

- v2 2.06E

- 01 6.24E

- 02 1.40E+00 3.39E

- 03 5 180.67 88.53 0.80 Benzo(a)anthracene A3

- v0 1 .83E

- 05 1.79E

- 05 2.46E

- 05 1.25E

- 05 1 33.08 37.44 1.00 Benzo(a)pyrene A3

- v0 3.42E

- 06 3.37E

- 06 4.40E

- 06 2.50E

- 06 1 27.72 31.36 0.76 Benzo(b)fluoranthene A3

- v0 6.76E

- 06 7.24E

- 06 8.28E

- 06 4.75E

- 06 1 26.90 30.44 1.00 Benzo(g,h,i)perylene A3

- v0 3.85E

- 06 3.89E

- 06 5.17E

- 06 2.50E

- 06 1 34.64 39.20 0.78 Benzo(k)fluoranthene A3

- v0 2.56E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Beryllium D3

- v0 1.55E

- 04 1.55E

- 04 1.56E

- 04 1.53E

- 04 1 1.35 1.87 1.00 Cadmium D3

- v0 2.38E

- 03 2.05E

- 03 3.13E

- 03 1.98E

- 03 1 27.01 30.57 1.00 Chromium (Hex) C3

- v0 7.70E

- 03 7.56E

- 03 1.09E

- 02 4.67E

- 03 1 40.17 45.45 0.00 Chromium (Total) C3

- v1 1.28E

- 02 5.43E

- 03 3.08E

- 02 2.16E

- 03 1 122.51 138.63 1.00 Chrysene A3

- v0 3.42E

- 06 2.59E

- 06 5.17E

- 06 2.50E

- 06 1 44.30 50.13 0.50 Copper D3

- v0 6.30E

- 03 6.30E

- 03 7.71E

- 03 4.89E

- 03 1 31.59 43.78 1.00 Dibenz(a,h)anthracene A3

- v0 2.56E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Fluoranthene A3

- v0 4.25E

- 05 3.10E

- 05 7.24E

- 05 2.40E

- 05 1 61.63 69.74 1.00 Fluorene A3

- v0 9.78E

- 0 6 5.75E

- 06 1.82E

- 05 5.44E

- 06 1 74.23 84.00 1.00 Formaldehyde C1

- v1 1.60E

- 02 1.41E

- 02 4.14E

- 02 3.24E

- 03 5 62.29 31.52 1.00 Hydrogen Sulfide A1

- v1 2.74E

- 01 2.37E

- 01 7.15E

- 01 5.94E

- 02 5 89.81 44.00 0.00 Indeno(1,2,3

- cd)pyrene A3

- v0 2.56E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Lead D3

- v0 2.42E

- 03 2.42E

- 03 2.49E

- 03 2.36E

- 03 1 3.87 5.36 1.00 Manganese D3

- v0 2.39E

- 03 2.39E

- 03 3.14E

- 03 1.64E

- 03 1 44.52 61.70 1.00 Mercury D3

- v0 3.23E

- 04 3.18E

- 04 3.82E

- 04 2.70E

- 04 1 17.33 19.60 0.00 Nap hthalene A3

- v0 2.06E

- 04 1.94E

- 04 2.40E

- 04 1.85E

- 04 1 14.51 16.42 1.00 Nickel D3

- v0 5.59E

- 03 5.59E

- 03 7.03E

- 03 4.16E

- 03 1 36.33 50.35 1.00 Phenanthrene A3

- v0 5.64E

- 05 4.49E

- 05 8.80E

- 05 3.62E

- 05 1 49.24 55.72 1.00 Phenol C2

- v0 2.18E

- 03 8.64E

- 04 5 .66E

- 03 7.28E

- 04 4 98.89 54.25 0.85 Pyrene A3

- v0 5.98E

- 05 5.17E

- 05 8.28E

- 05 4.49E

- 05 1 33.82 38.27 1.00 Selenium D3

- v0 2.06E

- 03 2.36E

- 03 2.83E

- 03 9.79E

- 04 1 46.79 52.94 0.16 Toluene E2

- v2 8.40E

- 01 8.35E

- 02 5.00E+00 4.14E

- 02 3 189.87 124.04 0.97 Zinc D3

- v2 3.42E+00 3.82E

- 01 9.78E+00 9.27E

- 02 1 161.24 182.45 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-13 Table D-4b. Summary of Data for Emission Factor Development
–

Boilers Firing Refinery Fuel Gas

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect R atio Mean Median Maximum Minimum Acenaphthene A3

- v0 4.90E

- 09 4.65E

- 09 5.46E

- 09 4.59E

- 09 1 9.89 11.20 0.37 Acenaphthylene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Acetaldehyde C1

- v3 3.01E

- 06 2.11E

- 06 1.01E

- 05 4.10E

- 09 5 95.45 48.30 1.00 Anthracene A3

- v0 1.89E

- 08 2.02E

- 08 3.28E

- 08 3.71E

- 09 1 77.14 87.30 1.00 Arsenic D3

- v0 5.88E

- 07 6.46E

- 07 9.40E

- 07 1.78E

- 07 1 65.36 73.95 1.00 Benzene C1

- v2 1.74E

- 04 5.03E

- 05 1.22E

- 03 2.86E

- 06 5 186.11 91.19 0.80 Benzo(a)a nthracene A3

- v0 1.53E

- 08 1.51E

- 08 2.07E

- 08 1.01E

- 08 1 34.78 39.35 1.00 Benzo(a)pyrene A3

- v0 2.86E

- 09 2.84E

- 09 3.71E

- 09 2.02E

- 09 1 29.49 33.37 0.76 Benzo(b)fluoranthene A3

- v0 5.65E

- 09 6.11E

- 09 6.99E

- 09 3.84E

- 09 1 28.79 32.57 1.00 Benzo(g,h,i) perylene A3

- v0 3.22E

- 09 3.28E

- 09 4.36E

- 09 2.02E

- 09 1 36.33 41.11 0.78 Benzo(k)fluoranthene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Beryllium D3

- v0 1.31E

- 07 1.31E

- 07 1.32E

- 07 1.29E

- 07 1 1.35 1.87 1.00 Cadmium D3

- v0 2.00E

- 0 6 1.70E

- 06 2.64E

- 06 1.67E

- 06 1 27.60 31.23 1.00 Chromium (Hex) C3

- v0 6.32E

- 06 6.29E

- 06 8.78E

- 06 3.89E

- 06 1 38.70 43.79 0.00 Chromium (Total) C3

- v1 1.04E

- 05 4.51E

- 06 2.49E

- 05 1.80E

- 06 1 121.39 137.36 1.00 Chrysene A3

- v0 2.86E

- 09 2.19E

- 09 4.36 E

- 09 2.02E

- 09 1 45.70 51.71 0.50 Copper D3

- v0 5.32E

- 06 5.32E

- 06 6.51E

- 06 4.13E

- 06 1 31.59 43.78 1.00 Dibenz(a,h)anthracene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Fluoranthene A3

- v0 3.56E

- 08 2.62E

- 08 6.11E

- 08 1.94E

- 08 1 62 .95 71.23 1.00 Fluorene A3

- v0 8.19E

- 09 4.65E

- 09 1.53E

- 08 4.59E

- 09 1 75.53 85.46 1.00 Formaldehyde C1

- v1 1.32E

- 05 1.16E

- 05 3.62E

- 05 2.81E

- 06 5 66.84 33.82 1.00 Hydrogen Sulfide A1

- v1 2.21E

- 04 1.69E

- 04 5.93E

- 04 5.01E

- 05 5 92.80 45.47 0.00 Indeno(1,2,3

- cd)pyrene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Lead D3

- v0 2.05E

- 06 2.05E

- 06 2.10E

- 06 1.99E

- 06 1 3.87 5.36 1.00 Manganese D3

- v0 2.02E

- 06 2.02E

- 06 2.65E

- 06 1.38E

- 06 1 44.52 61.70 1.00 Mercury D3

- v0 2.72E

- 07 2.69E

- 07 3.22E

- 07 2.24E

- 07 1 18.19 20.58 0.00 Naphthalene A3

- v0 1.72E

- 07 1.63E

- 07 2.03E

- 07 1.49E

- 07 1 16.13 18.25 1.00 Nickel D3

- v0 4.72E

- 06 4.72E

- 06 5.94E

- 06 3.51E

- 06 1 36.33 50.35 1.00 Phenanthrene A3

- v0 4.71E

- 08 3.63E

- 08 7.43E

- 08 3.06E

- 08 1 50.50 57.15 1.00 Phenol C2

- v0 1.83E

- 06 7.04E

- 07 4.91E

- 06 5.45E

- 07 4 99.84 56.49 0.85 Pyrene A3

- v0 5.00E

- 08 4.36E

- 08 6.99E

- 08 3.63E

- 08 1 35.35 40.00 1.00 Selenium D3

- v0 1.73E

- 06 1.99E

- 06 2.39E

- 06 8.11E

- 07 1 47.44 53.68 0.16 Toluene E2

- v2 7.23E

- 04 7.25E

- 05 4.37E

- 03 3.59E

- 05 3 193.00 126.09 0.97 Zinc D3

- v2 2.83E

- 03 3.22E

- 04 8.10E

- 03 7.83E

- 05 1 161.02 182.20 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-14 Table D- 5a. Summary of Data for Emission Factor Development
– Boilers Firing Refinery

Fuel Gas Controlled with Selective Catalytic Reduction (NO x 

### )

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 5.88E

- 06 5.75E

- 06 6.47E

- 06 5.44E

- 06 1 8.97 10.15 0.37 Acenaphthylene A3

- v0 2.5 6E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Acetaldehyde C1

- v3 3.97E

- 03 2.43E

- 03 1.21E

- 02 4.92E

- 06 5 100.80 51.01 1.00 Anthracene A3

- v0 2.28E

- 05 2.50E

- 05 3.89E

- 05 4.40E

- 06 1 76.23 86.26 1.00 Arsenic D3

- v0 7.04E

- 04 7.65E

- 04 1.13E

- 03 2.11E

- 04 1 6 6.10 74.80 1.00 Benzene C1

- v2 2.06E

- 01 6.24E

- 02 1.40E+00 3.39E

- 03 5 180.67 88.53 0.80 Benzo(a)anthracene A3

- v0 1.83E

- 05 1.79E

- 05 2.46E

- 05 1.25E

- 05 1 33.08 37.44 1.00 Benzo(a)pyrene A3

- v0 3.42E

- 06 3.37E

- 06 4.40E

- 06 2.50E

- 06 1 27.72 31.36 0.76 Benzo(b )fluoranthene A3

- v0 6.76E

- 06 7.24E

- 06 8.28E

- 06 4.75E

- 06 1 26.90 30.44 1.00 Benzo(g,h,i)perylene A3

- v0 3.85E

- 06 3.89E

- 06 5.17E

- 06 2.50E

- 06 1 34.64 39.20 0.78 Benzo(k)fluoranthene A3

- v0 2.56E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Beryllium D3

- v0 1.55E

- 04 1.55E

- 04 1.56E

- 04 1.53E

- 04 1 1.35 1.87 1.00 Cadmium D3

- v0 2.38E

- 03 2.05E

- 03 3.13E

- 03 1.98E

- 03 1 27.01 30.57 1.00 Chromium (Hex) C3

- v0 7.70E

- 03 7.56E

- 03 1.09E

- 02 4.67E

- 03 1 40.17 45.45 0.00 Chromium (Total) C3

- v1 1.28E

- 02 5.43E

- 03 3.08E

- 0 2 2.16E

- 03 1 122.51 138.63 1.00 Chrysene A3

- v0 3.42E

- 06 2.59E

- 06 5.17E

- 06 2.50E

- 06 1 44.30 50.13 0.50 Copper D3

- v0 6.30E

- 03 6.30E

- 03 7.71E

- 03 4.89E

- 03 1 31.59 43.78 1.00 Dibenz(a,h)anthracene A3

- v0 2.56E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Fluoranthene A3

- v0 4.25E

- 05 3.10E

- 05 7.24E

- 05 2.40E

- 05 1 61.63 69.74 1.00 Fluorene A3

- v0 9.78E

- 06 5.75E

- 06 1.82E

- 05 5.44E

- 06 1 74.23 84.00 1.00 Formaldehyde C1

- v1 1.60E

- 02 1.41E

- 02 4.14E

- 02 3.24E

- 03 5 62.29 31.52 1.00 Hydrogen Sulfide A1

- v1 2.74E

- 01 2.37E

- 01 7.15E

- 01 5.94E

- 02 5 89.81 44.00 0.00 Indeno(1,2,3

- cd)pyrene A3

- v0 2.56E

- 06 2.59E

- 06 2.59E

- 06 2.50E

- 06 1 2.04 2.31 0.00 Lead D3

- v0 2.42E

- 03 2.42E

- 03 2.49E

- 03 2.36E

- 03 1 3.87 5.36 1.00 Manganese D3

- v0 2.39E

- 03 2.39E

- 03 3.14E

- 03 1.64E

- 03 1 4 4.52 61.70 1.00 Mercury D3

- v0 3.23E

- 04 3.18E

- 04 3.82E

- 04 2.70E

- 04 1 17.33 19.60 0.00 Naphthalene A3

- v0 2.06E

- 04 1.94E

- 04 2.40E

- 04 1.85E

- 04 1 14.51 16.42 1.00 Nickel D3

- v0 5.59E

- 03 5.59E

- 03 7.03E

- 03 4.16E

- 03 1 36.33 50.35 1.00 Phenanthrene A3

- v0 5.6 4E

- 05 4.49E

- 05 8.80E

- 05 3.62E

- 05 1 49.24 55.72 1.00 Phenol C2

- v0 2.18E

- 03 8.64E

- 04 5.66E

- 03 7.28E

- 04 4 95.89 54.25 0.85 Pyrene A3

- v0 5.98E

- 05 5.17E

- 05 8.28E

- 05 4.49E

- 05 1 33.82 38.27 1.00 Selenium D3

- v0 2.06E

- 03 2.36E

- 03 2.83E

- 03 9.79E

- 04 1 46.79 52. 94 0.16 Toluene E2

- v2 8.40E

- 01 8.35E

- 02 5.00E+00 4.14E

- 02 3 189.87 124.04 0.97 Zinc D3

- v2 3.42E+00 3.82E

- 01 9.78E+00 9.27E

- 02 1 161.24 182.45 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-15 Table D-5b. Summary of Data for Emission Factor Development
– Boilers Firing Refinery

Fuel Gas Controlled with Selective Catalytic Reduction (NO x 

### )

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 4.90E

- 09 4.65E

- 09 5.46E

- 09 4.59E

- 09 1 9.89 11.20 0.37 Acenaph thylene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Acetaldehyde C1

- v3 3.01E

- 06 2.11E

- 06 1.01E

- 05 4.10E

- 09 5 95.45 48.30 1.00 Anthracene A3

- v0 1.89E

- 08 2.02E

- 08 3.28E

- 08 3.71E

- 09 1 77.14 87.30 1.00 Arsenic D3

- v0 5.88E

- 07 6.46 E

- 07 9.40E

- 07 1.78E

- 07 1 65.36 73.95 1.00 Benzene C1

- v2 1.74E

- 04 5.03E

- 05 1.22E

- 03 2.86E

- 06 5 186.11 91.19 0.80 Benzo(a)anthracene A3

- v0 1.53E

- 08 1.51E

- 08 2.07E

- 08 1.01E

- 08 1 34.78 39.35 1.00 Benzo(a)pyrene A3

- v0 2.86E

- 09 2.84E

- 09 3.71E

- 09 2 .02E

- 09 1 29.49 33.37 0.76 Benzo(b)fluoranthene A3

- v0 5.65E

- 09 6.11E

- 09 6.99E

- 09 3.84E

- 09 1 28.79 32.57 1.00 Benzo(g,h,i)perylene A3

- v0 3.22E

- 09 3.28E

- 09 4.36E

- 09 2.02E

- 09 1 36.33 41.11 0.78 Benzo(k)fluoranthene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Beryllium D3

- v0 1.31E

- 07 1.31E

- 07 1.32E

- 07 1.29E

- 07 1 1.35 1.87 1.00 Cadmium D3

- v0 2.00E

- 06 1.70E

- 06 2.64E

- 06 1.67E

- 06 1 27.60 31.23 1.00 Chromium (Hex) C3

- v0 6.32E

- 06 6.29E

- 06 8.78E

- 06 3.89E

- 06 1 38.70 43.79 0.00 Chromium (Total) C3

- v1 1.04E

- 05 4.51E

- 06 2.49E

- 05 1.80E

- 06 1 121.39 137.36 1.00 Chrysene A3

- v0 2.86E

- 09 2.19E

- 09 4.36E

- 09 2.02E

- 09 1 45.70 51.71 0.50 Copper D3

- v0 5.32E

- 06 5.32E

- 06 6.51E

- 06 4.13E

- 06 1 31.59 43.78 1.00 Dibenz(a,h)anthr acene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Fluoranthene A3

- v0 3.56E

- 08 2.62E

- 08 6.11E

- 08 1.94E

- 08 1 62.95 71.23 1.00 Fluorene A3

- v0 8.19E

- 09 4.65E

- 09 1.53E

- 08 4.59E

- 09 1 75.53 85.46 1.00 Formaldehyde C1

- v1 1.32E

- 05 1.1 6E

- 05 3.62E

- 05 2.81E

- 06 5 66.84 33.82 1.00 Hydrogen Sulfide A1

- v1 2.21E

- 04 1.69E

- 04 5.93E

- 04 5.01E

- 05 5 92.80 45.47 0.00 Indeno(1,2,3

- cd)pyrene A3

- v0 2.13E

- 09 2.19E

- 09 2.19E

- 09 2.02E

- 09 1 4.43 5.01 0.00 Lead D3

- v0 2.05E

- 06 2.05E

- 06 2.10E

- 06 1.99E

- 06 1 3.87 5.36 1.00 Manganese D3

- v0 2.02E

- 06 2.02E

- 06 2.65E

- 06 1.38E

- 06 1 44.52 61.70 1.00 Mercury D3

- v0 2.72E

- 07 2.69E

- 07 3.22E

- 07 2.24E

- 07 1 18.19 20.58 0.00 Naphthalene A3

- v0 1.72E

- 07 1.63E

- 07 2.03E

- 07 1.49E

- 07 1 16.13 18.25 1.00 Nickel D3

- v0 4.72E

- 06 4.72E

- 06 5.94E

- 06 3.51E

- 06 1 36.33 50.35 1.00 Phenanthrene A3

- v0 4.71E

- 08 3.63E

- 08 7.43E

- 08 3.06E

- 08 1 50.50 57.15 1.00 Phenol C2

- v0 1.83E

- 06 7.04E

- 07 4.91E

- 06 5.45E

- 07 4 99.84 56.49 0.85 Pyrene A3

- v0 5.00E

- 08 4.36E

- 08 6.99E

- 08 3.63E

- 08 1 35.35 40.00 1.00 Selenium D3

- v0 1.73E

- 06 1.99E

- 06 2.39E

- 06 8.11E

- 07 1 47.44 53.68 0.16 Toluene E2

- v2 7.23E

- 04 7.25E

- 05 4.37E

- 03 3.59E

- 05 3 193.00 126.09 0.97 Zinc D3

- v2 2.83E

- 03 3.22E

- 04 8.10E

- 03 7.83E

- 05 1 161.02 182 .20 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-16 Table D- 6a. Summary of Data for Emission Factor Development
– Coke Calcining Controlled by Spray Dryer and Fabric Filter

Substance CARB

Rating Emission Factor (lb/ton coke) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minim um Acenaphthene A3

- v0 1.46E

- 08 1.38E

- 08 1.64E

- 08 1.37E

- 08 1 10.68 12.08 1.00 Acenaphthylene A3

- v0 1.83E

- 08 1.69E

- 08 2.81E

- 08 9.87E

- 09 1 50.39 57.02 1.00 Acetaldehyde A3

- v0 1.02E

- 03 1.16E

- 03 1.22E

- 03 6.77E

- 04 1 29.23 33.07 1.00 Acrolein A3

- v0 3.36E

- 04 3.41E

- 04 3.60E

- 04 3.08E

- 04 1 7.79 8.82 0.00 Anthracene A3

- v0 1.82E

- 08 1.84E

- 08 1.97E

- 08 1.64E

- 08 1 9.02 10.20 1.00 Antimony C3

- v0 4.61E

- 05 4.64E

- 05 4.79E

- 05 4.41E

- 05 1 4.04 4.57 0.34 Arsenic C3

- v0 4.66E

- 06 4.64E

- 06 4.92E

- 06 4 .41E

- 06 1 5.42 6.13 0.00 Barium C3

- v0 1.95E

- 05 1.99E

- 05 2.46E

- 05 1.39E

- 05 1 27.51 31.13 1.00 Benzene C3

- v0 3.24E

- 04 4.06E

- 04 4.50E

- 04 1.15E

- 04 1 56.20 63.60 1.00 Benzo(a)anthracene A3

- v0 8.71E

- 09 8.25E

- 09 1.02E

- 08 7.67E

- 09 1 15.15 17.15 0. 39 Benzo(a)pyrene A3

- v0 8.05E

- 09 8.22E

- 09 8.25E

- 09 7.67E

- 09 1 4.04 4.57 0.00 Benzo(b)fluoranthene A3

- v0 8.05E

- 09 8.22E

- 09 8.25E

- 09 7.67E

- 09 1 4.04 4.57 0.00 Benzo(g,h,i)perylene A3

- v0 8.05E

- 09 8.22E

- 09 8.25E

- 09 7.67E

- 09 1 4.04 4.57 0.00 Be nzo(k)fluoranthene A3

- v0 8.05E

- 09 8.22E

- 09 8.25E

- 09 7.67E

- 09 1 4.04 4.57 0.00 Beryllium C3

- v0 1.93E

- 06 1.72E

- 06 2.43E

- 06 1.63E

- 06 1 22.77 25.76 0.42 Cadmium C3

- v0 9.32E

- 06 9.27E

- 06 9.84E

- 06 8.84E

- 06 1 5.34 6.04 0.00 Chromium (Hex) C3

- v0 6.3 1E

- 07 6.30E

- 07 7.17E

- 07 5.45E

- 07 1 13.63 15.42 1.00 Chromium (Total) C3

- v0 2.05E

- 05 2.04E

- 05 2.09E

- 05 2.01E

- 05 1 1.82 2.06 1.00 Chrysene A3

- v0 1.28E

- 08 1.18E

- 08 1.84E

- 08 8.25E

- 09 1 40.02 45.28 0.79 Copper C3

- v0 9.32E

- 06 9.27E

- 06 9.84E

- 06 8.8 4E

- 06 1 5.34 6.04 0.00 Dibenz(a,h)anthracene A3

- v0 8.05E

- 09 8.22E

- 09 8.25E

- 09 7.67E

- 09 1 4.04 4.57 0.00 Dioxin:4D 2378 A3

- v0 1.14E

- 11 1.18E

- 11 1.32E

- 11 9.05E

- 12 1 18.56 21.00 0.00 Dioxin:4D Other A3

- v0 1.44E

- 10 1.01E

- 10 2.99E

- 10 3.17E

- 11 1 9 6.53 109.23 1.00 Dioxin:5D 12378 A3

- v0 9.56E

- 12 9.20E

- 12 1.35E

- 11 6.01E

- 12 1 39.05 44.19 0.00 Dioxin:5D Other A3

- v0 8.45E

- 11 8.83E

- 11 1.02E

- 10 6.34E

- 11 1 23.10 26.14 0.40 Dioxin:6D 123478 A3

- v0 9.93E

- 12 9.24E

- 12 1.57E

- 11 4.83E

- 12 1 55.10 62 .35 0.31 Dioxin:6D 123678 A3

- v0 1.38E

- 11 1.27E

- 11 2.04E

- 11 8.30E

- 12 1 44.48 50.33 0.69 Dioxin:6D 123789 A3

- v0 1.29E

- 11 1.45E

- 11 1.50E

- 11 9.20E

- 12 1 24.83 28.10 0.39 Dioxin:6D Other A3

- v0 6.36E

- 11 6.71E

- 11 8.96E

- 11 3.39E

- 11 1 44.09 49.89 0.6 5 Dioxin:7D 1234678 A3

- v0 1.38E

- 10 1.18E

- 10 2.18E

- 10 7.96E

- 11 1 51.62 58.41 1.00 Dioxin:7D Other A3

- v0 1.32E

- 10 1.09E

- 10 1.90E

- 10 9.72E

- 11 1 38.24 43.27 1.00 Dioxin:8D A3

- v0 1.77E

- 09 1.79E

- 09 2.76E

- 09 7.60E

- 10 1 56.40 63.82 1.00 Fluoranthe ne A3

- v0 3.58E

- 08 3.30E

- 08 4.30E

- 08 3.13E

- 08 1 17.64 19.96 1.00 Fluorene A3

- v0 5.64E

- 08 5.21E

- 08 6.61E

- 08 5.10E

- 08 1 14.90 16.86 1.00 Formaldehyde A3

- v0 3.36E

- 04 3.41E

- 04 3.60E

- 04 3.08E

- 04 1 7.79 8.82 0.00 Furan:4F 2378 A3

- v0 1.33E

- 11 1.19E

- 11 1.63E

- 11 1.18E

- 11 1 19.13 21.65 0.70 Furan:4F Other A3

- v0 1.39E

- 10 1.10E

- 10 2.15E

- 10 9.21E

- 11 1 47.70 53.98 1.00 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-17 Table D - 6a. Summary of Data for Emission Factor Development
– Coke Calcining Controlled by Spray Dryer and Fabric F ilter (continued)

Substance CARB

Rating Emission Factor (lb/ton coke) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Furan:5F 12378 A3

- v0 1.36E

- 11 1.43E

- 11 1.50E

- 11 1.16E

- 11 1 13.01 14.72 0.65 Furan:5F 23478 A3

- v0 1.25 E

- 11 1.38E

- 11 1.46E

- 11 9.10E

- 12 1 23.87 27.01 0.63 Furan:5F Other A3

- v0 1.20E

- 10 9.47E

- 11 1.79E

- 10 8.70E

- 11 1 42.57 48.17 0.74 Furan:6F 123478 A3

- v0 2.44E

- 11 2.49E

- 11 2.71E

- 11 2.12E

- 11 1 12.27 13.89 1.00 Furan:6F 123678 A3

- v0 2.21E

- 11 2.19E

- 11 3.13E

- 11 1.31E

- 11 1 41.02 46.42 1.00 Furan:6F 123789 A3

- v0 9.19E

- 12 8.96E

- 12 1.20E

- 11 6.64E

- 12 1 29.03 32.85 0.67 Furan:6F 234678 A3

- v0 2.01E

- 11 2.04E

- 11 2.04E

- 11 1.96E

- 11 1 2.55 2.88 1.00 Furan:6F Other A3

- v0 1.52E

- 10 1.31E

- 10 2.36E

- 10 9 .04E

- 11 1 49.18 55.66 1.00 Furan:7F 1234678 A3

- v0 1.50E

- 10 1.42E

- 10 1.76E

- 10 1.32E

- 10 1 15.51 17.55 1.00 Furan:7F 1234789 A3

- v0 2.56E

- 11 2.56E

- 11 2.99E

- 11 2.12E

- 11 1 17.09 19.33 0.72 Furan:7F Other A3

- v0 5.16E

- 11 5.16E

- 11 5.16E

- 11 5.16E

- 11 1 0.00 0.00 0.50 Furan:8F A3

- v1 1.46E

- 10 1.36E

- 10 2.86E

- 10 1.61E

- 11 1 92.60 104.78 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 8.05E

- 09 8.22E

- 09 8.25E

- 09 7.67E

- 09 1 4.04 4.57 0.00 Lead C3

- v0 6.20E

- 05 4.92E

- 05 9.27E

- 05 4.41E

- 05 1 43.08 48.75 0.50 Ma nganese C3

- v0 4.56E

- 05 4.41E

- 05 7.63E

- 05 1.63E

- 05 1 65.87 74.54 0.88 Mercury C3

- v1 4.63E

- 05 1.63E

- 05 1.12E

- 04 1.08E

- 05 1 122.58 138.71 1.00 Naphthalene A3

- v0 2.41E

- 06 2.46E

- 06 3.14E

- 06 1.64E

- 06 1 31.02 35.10 1.00 Nickel C3

- v0 9.06E

- 05 4.92E

- 05 1.76E

- 04 4.64E

- 05 1 81.90 92.67 0.65 Phenanthrene A3

- v0 1.88E

- 07 1.81E

- 07 2.15E

- 07 1.69E

- 07 1 12.67 14.34 1.00 Phosphorus C3

- v0 4.66E

- 04 4.64E

- 04 4.92E

- 04 4.41E

- 04 1 5.42 6.13 0.00 Pyrene A3

- v0 2.67E

- 08 2.64E

- 08 3.23E

- 08 2.15E

- 08 1 20.27 22.94 1.00 Selenium C3

- v0 4.66E

- 06 4.64E

- 06 4.92E

- 06 4.41E

- 06 1 5.42 6.13 0.00 Silver C3

- v0 1.63E

- 05 1.63E

- 05 1.72E

- 05 1.54E

- 05 1 5.45 6.17 0.00 Thallium C3

- v0 6.99E

- 05 6.96E

- 05 7.38E

- 05 6.64E

- 05 1 5.31 6.01 0.00 Toluene C3

- v0 5.34E

- 05 4.46E

- 05 7.17E

- 05 4.39E

- 05 1 29.73 33.64 1.00 Xylene (m,p) C3

- v0 3.09E

- 05 3.44E

- 05 3.79E

- 05 2.04E

- 05 1 29.89 33.82 0.22 Xylene (o) C3

- v0 4.49E

- 05 4.34E

- 05 4.79E

- 05 4.34E

- 05 1 5.72 6.47 0.00 Zinc C3

- v0 1.17E

- 04 1.04E

- 04 1.63E

- 04 8.37E

- 05 1 3 5.15 39.78 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-18 Table D-6b. Summary of Data for Emission Factor Development
– Coke Calcining Controlled by Spray Dryer and Fabric Filter

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 4.40E

- 08 4.06E

- 08 5.43E

- 08 3.70E

- 08 1 20.68 23.40 1.00 Acenaphthylene A3

- v0 5.59E

- 08 4.58E

- 08 9.29E

- 08 2.90E

- 08 1 59.27 67.06 1.00 Acetaldehyde A3

- v0 3.12E

- 03 3.14E

- 03 3.89E

- 03 2.33E

- 03 1 24.96 28.25 1.00 Acr olein A3

- v0 1.04E

- 03 1.06E

- 03 1.14E

- 03 9.25E

- 04 1 10.62 12.02 0.00 Anthracene A3

- v0 5.40E

- 08 5.43E

- 08 5.79E

- 08 4.98E

- 08 1 7.50 8.48 1.00 Antimony C3

- v0 1.44E

- 04 1.42E

- 04 1.52E

- 04 1.37E

- 04 1 5.19 5.87 0.34 Arsenic C3

- v0 1.45E

- 05 1.42E

- 05 1.5 6E

- 05 1.37E

- 05 1 6.73 7.62 0.00 Barium C3

- v0 6.10E

- 05 6.40E

- 05 7.79E

- 05 4.11E

- 05 1 30.51 34.52 1.00 Benzene C3

- v0 1.03E

- 03 1.39E

- 03 1.45E

- 03 2.62E

- 04 1 64.73 73.25 1.00 Benzo(a)anthracene A3

- v0 2.60E

- 08 2.72E

- 08 2.99E

- 08 2.08E

- 08 1 18.05 20 .43 0.39 Benzo(a)pyrene A3

- v0 2.41E

- 08 2.42E

- 08 2.72E

- 08 2.08E

- 08 1 13.35 15.10 0.00 Benzo(b)fluoranthene A3

- v0 2.41E

- 08 2.42E

- 08 2.72E

- 08 2.08E

- 08 1 13.35 15.10 0.00 Benzo(g,h,i)perylene A3

- v0 2.41E

- 08 2.42E

- 08 2.72E

- 08 2.08E

- 08 1 13.35 15. 10 0.00 Benzo(k)fluoranthene A3

- v0 2.41E

- 08 2.42E

- 08 2.72E

- 08 2.08E

- 08 1 13.35 15.10 0.00 Beryllium C3

- v0 6.03E

- 06 5.45E

- 06 7.83E

- 06 4.81E

- 06 1 26.41 29.88 0.42 Cadmium C3

- v0 2.90E

- 05 2.85E

- 05 3.12E

- 05 2.74E

- 05 1 6.71 7.59 0.00 Chromium ( Hex) C3

- v0 2.12E

- 06 1.93E

- 06 2.88E

- 06 1.54E

- 06 1 32.38 36.64 1.00 Chromium (Total) C3

- v0 6.90E

- 05 5.92E

- 05 9.35E

- 05 5.44E

- 05 1 30.92 34.99 1.00 Chrysene A3

- v0 3.73E

- 08 3.48E

- 08 4.98E

- 08 2.72E

- 08 1 30.84 34.90 0.79 Copper C3

- v0 2.90E

- 05 2.85 E

- 05 3.12E

- 05 2.74E

- 05 1 6.71 7.59 0.00 Dibenz(a,h)anthracene A3

- v0 2.41E

- 08 2.42E

- 08 2.72E

- 08 2.08E

- 08 1 13.35 15.10 0.00 Dioxin:4D 2378 A3

- v0 3.68E

- 11 3.66E

- 11 4.86E

- 11 2.51E

- 11 1 31.88 36.08 0.00 Dioxin:4D Other A3

- v0 4.44E

- 10 4.14E

- 10 8. 31E

- 10 8.81E

- 11 1 83.85 94.88 1.00 Dioxin:5D 12378 A3

- v0 2.92E

- 11 2.56E

- 11 3.74E

- 11 2.47E

- 11 1 24.24 27.43 0.00 Dioxin:5D Other A3

- v0 2.74E

- 10 2.83E

- 10 3.63E

- 10 1.76E

- 10 1 34.15 38.64 0.40 Dioxin:6D 123478 A3

- v0 3.45E

- 11 2.57E

- 11 6.45E

- 11 1. 34E

- 11 1 77.21 87.37 0.31 Dioxin:6D 123678 A3

- v0 4.40E

- 11 5.23E

- 11 5.68E

- 11 2.30E

- 11 1 41.59 47.07 0.69 Dioxin:6D 123789 A3

- v0 4.22E

- 11 4.16E

- 11 5.95E

- 11 2.56E

- 11 1 40.22 45.52 0.39 Dioxin:6D Other A3

- v0 2.06E

- 10 2.49E

- 10 2.76E

- 10 9.42E

- 11 1 47.47 53.72 0.65 Dioxin:7D 1234678 A3

- v0 4.19E

- 10 3.27E

- 10 6.05E

- 10 3.27E

- 10 1 38.30 43.34 1.00 Dioxin:7D Other A3

- v0 4.09E

- 10 3.99E

- 10 5.27E

- 10 3.02E

- 10 1 27.59 31.22 1.00 Dioxin:8D A3

- v0 5.25E

- 09 4.98E

- 09 7.65E

- 09 3.12E

- 09 1 43.40 49.11 1.00 Fluoranthene A3

- v0 1.06E

- 07 1.09E

- 07 1.16E

- 07 9.18E

- 08 1 11.95 13.52 1.00 Fluorene A3

- v0 1.70E

- 07 1.50E

- 07 2.18E

- 07 1.41E

- 07 1 24.78 28.04 1.00 Formaldehyde A3

- v0 1.04E

- 03 1.06E

- 03 1.14E

- 03 9.25E

- 04 1 10.62 12.02 0.00 Furan:4F 2378 A3

- v0 4.23E

- 11 4.53E

- 11 4.85E

- 11 3.31E

- 11 1 19.19 21.72 0.70 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-19 Table D - 6b. Summary of Data for Emission Factor Development
– Coke Calcining Controlled by Spray Dryer and Fabric Filter (continued)

Substance CARB

Rating Emission Factor (lb/ MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Furan:4F Other A3

- v0 4.35E

- 10 4.51E

- 10 5.97E

- 10 2.56E

- 10 1 39.34 44.51 1.00 Furan:5F 12378 A3

- v0 4.42E

- 11 4.16E

- 11 5.87E

- 11 3.23E

- 11 1 30.36 34.35 0.65 Furan:5F 23478 A3

- v0 4.09E

- 11 4.07E

- 11 5.66E

- 11 2.53E

- 11 1 38.39 43.44 0.63 Furan:5F Other A3

- v0 3.76E

- 10 3.89E

- 10 4.98E

- 10 2.42E

- 10 1 34.21 38.71 0.74 Furan:6F 123478 A3

- v0 7.88E

- 11 7.53E

- 11 1.02E

- 10 5.88E

- 11 1 27.77 31.43 1.00 Furan:6F 123678 A3

- v 0 7.11E

- 11 8.68E

- 11 9.00E

- 11 3.65E

- 11 1 42.25 47.81 1.00 Furan:6F 123789 A3

- v0 2.95E

- 11 3.32E

- 11 3.68E

- 11 1.84E

- 11 1 33.01 37.36 0.67 Furan:6F 234678 A3

- v0 6.50E

- 11 5.68E

- 11 8.39E

- 11 5.43E

- 11 1 25.28 28.60 1.00 Furan:6F Other A3

- v0 4.81E

- 10 5.38E

- 10 6.54E

- 10 2.51E

- 10 1 43.15 48.82 1.00 Furan:7F 1234678 A3

- v0 4.75E

- 10 4.90E

- 10 5.42E

- 10 3.94E

- 10 1 15.81 17.89 1.00 Furan:7F 1234789 A3

- v0 8.04E

- 11 8.31E

- 11 8.70E

- 11 7.12E

- 11 1 10.23 11.58 0.72 Furan:7F Other A3

- v0 1.77E

- 10 1.77E

- 10 2.12E

- 10 1.43E

- 10 1 27.28 37.81 0.50 Furan:8F A3

- v1 4.13E

- 10 3.77E

- 10 7.94E

- 10 6.63E

- 11 1 88.52 100.16 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 2.41E

- 08 2.42E

- 08 2.72E

- 08 2.08E

- 08 1 13.35 15.10 0.00 Lead C3

- v0 1.91E

- 04 1.56E

- 04 2.74E

- 04 1.42E

- 04 1 37.94 42.93 0.50 Manganese C3

- v0 1.44E

- 04 1.42E

- 04 2.42E

- 04 4.81E

- 05 1 67.22 76.06 0.88 Mercury C3

- v1 1.48E

- 04 4.81E

- 05 3.60E

- 04 3.43E

- 05 1 124.89 141.33 1.00 Naphthalene A3

- v0 7.29E

- 06 6.67E

- 06 1.04E

- 05 4.83E

- 06 1 38.67 43.75 1.00 Nicke l C3

- v0 2.87E

- 04 1.56E

- 04 5.68E

- 04 1.37E

- 04 1 84.93 96.10 0.65 Phenanthrene A3

- v0 5.66E

- 07 5.31E

- 07 7.09E

- 07 4.58E

- 07 1 22.80 25.80 1.00 Phosphorus C3

- v0 1.45E

- 03 1.42E

- 03 1.56E

- 03 1.37E

- 03 1 6.73 7.62 0.00 Pyrene A3

- v0 7.86E

- 08 7.75E

- 08 8. 76E

- 08 7.09E

- 08 1 10.68 12.09 1.00 Selenium C3

- v0 1.45E

- 05 1.42E

- 05 1.56E

- 05 1.37E

- 05 1 6.73 7.62 0.00 Silver C3

- v0 5.07E

- 05 4.97E

- 05 5.45E

- 05 4.81E

- 05 1 6.52 7.37 0.00 Thallium C3

- v0 2.18E

- 04 2.14E

- 04 2.34E

- 04 2.06E

- 04 1 6.65 7.53 0.00 Toluene C3

- v0 1.63E

- 04 1.44E

- 04 2.45E

- 04 9.97E

- 05 1 45.82 51.85 1.00 Xylene (m,p) C3

- v0 8.90E

- 05 8.62E

- 05 1.11E

- 04 6.99E

- 05 1 23.14 26.18 0.22 Xylene (o) C3

- v0 1.32E

- 04 1.40E

- 04 1.48E

- 04 1.09E

- 04 1 15.78 17.86 0.00 Zinc C3

- v0 3.66E

- 04 3.08E

- 04 5.25E

- 04 2.65E

- 04 1 38.08 43.10 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-20 Table D- 7a. Summary of Data for Emission Factor Development
– Heaters Firing Natural Gas

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 1.39E

- 06 1.40E

- 06 1.62E

- 06 1.15E

- 06 1 16.72 18.92 0.72 Acenaphthylene A3

- v1 1.21E

- 05 2.84E

- 06 3.23E

- 05 1.15E

- 06 1 144.82 163.88 0.97 Acetaldehyde A3

- v0 4.61E

- 03 4.61E

- 03 4.82E

- 03 4.41E

- 03 1 4.47 5.06 0.32 Acrolein A 3

- v0 4.51E

- 03 4.56E

- 03 4.64E

- 03 4.32E

- 03 1 3.66 4.14 0.00 Anthracene A3

- v0 1.61E

- 06 1.83E

- 06 1.85E

- 06 1.15E

- 06 1 24.62 27.86 0.76 Benzene A3

- v0 2.34E

- 03 1.65E

- 03 3.71E

- 03 1.65E

- 03 1 50.72 57.40 0.53 Benzo(a)anthracene A3

- v0 1.41E

- 06 1.18E

- 06 1.90E

- 06 1.15E

- 06 1 29.86 33.79 0.45 Benzo(a)pyrene A3

- v0 1.14E

- 06 1.15E

- 06 1.18E

- 06 1.08E

- 06 1 4.76 5.39 0.00 Benzo(b)fluoranthene A3

- v0 1.14E

- 06 1.15E

- 06 1.18E

- 06 1.08E

- 06 1 4.76 5.39 0.00 Benzo(g,h,i)perylene A3

- v0 1.25E

- 06 1.18E

- 06 1.42 E

- 06 1.15E

- 06 1 11.81 13.36 0.38 Benzo(k)fluoranthene A3

- v0 1.14E

- 06 1.15E

- 06 1.18E

- 06 1.08E

- 06 1 4.76 5.39 0.00 Chrysene A3

- v0 1.39E

- 06 1.18E

- 06 1.83E

- 06 1.15E

- 06 1 27.63 31.27 0.44 Dibenz(a,h)anthracene A3

- v0 1.14E

- 06 1.15E

- 06 1.18E

- 06 1.0 8E

- 06 1 4.76 5.39 0.00 Ethylbenzene A3

- v0 2.25E

- 03 2.25E

- 03 2.25E

- 03 2.25E

- 03 1 0.00 0.00 0.00 Fluoranthene A3

- v0 1.19E

- 05 1.07E

- 05 1.79E

- 05 7.15E

- 06 1 46.07 52.14 1.00 Fluorene A3

- v0 4.59E

- 06 4.50E

- 06 5.82E

- 06 3.46E

- 06 1 25.79 29.19 1.00 Formaldehyde A3

- v0 4.75E

- 03 4.61E

- 03 5.32E

- 03 4.32E

- 03 1 10.76 12.18 0.37 Indeno(1,2,3

- cd)pyrene A3

- v0 1.14E

- 06 1.15E

- 06 1.18E

- 06 1.08E

- 06 1 4.76 5.39 0.00 Naphthalene A3

- v0 2.37E

- 04 2.37E

- 04 2.80E

- 04 1.94E

- 04 1 18.28 20.69 1.00 Phenanthre ne A3

- v0 3.37E

- 05 3.31E

- 05 4.74E

- 05 2.05E

- 05 1 39.96 45.22 1.00 Propylene A3

- v0 4.63E

- 01 4.57E

- 01 6.13E

- 01 3.20E

- 01 1 31.59 35.74 1.00 Pyrene A3

- v0 5.60E

- 06 2.84E

- 06 1.16E

- 05 2.31E

- 06 1 93.70 106.03 1.00 Toluene A3

- v0 3.23E

- 02 1.38E

- 02 7.47 E

- 02 8.37E

- 03 1 114.08 129.09 1.00 Xylene (Total) A3

- v0 1.87E

- 02 2.05E

- 02 2.97E

- 02 5.71E

- 03 1 64.92 73.46 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-21 Table D-7b. Summary of Data for Emission Factor Development
– Heaters Firing Natural Gas

Substance CARB

Rating Emission Factor (lb/MMB tu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 1.36E

- 09 1.36E

- 09 1.58E

- 09 1.13E

- 09 1 16.72 18.92 0.72 Acenaphthylene A3

- v1 1.18E

- 08 2.77E

- 09 3.16E

- 08 1.13E

- 09 1 144.82 163.88 0.97 Acetaldehyde A3

- v0 4.50E

- 06 4.50E

- 06 4.71E

- 06 4.30E

- 06 1 4.47 5.06 0.32 Acrolein A3

- v0 4.40E

- 06 4.46E

- 06 4.53E

- 06 4.22E

- 06 1 3.66 4.14 0.00 Anthracene A3

- v0 1.57E

- 09 1.79E

- 09 1.80E

- 09 1.13E

- 09 1 24.62 27.86 0.76 Benzene A3

- v0 2.28E

- 06 1.61E

- 06 3.62E

- 06 1.61E

- 06 1 50.72 57.40 0.53 Benzo(a)anthracene A3

- v0 1.38E

- 09 1.16E

- 09 1.85E

- 09 1.13E

- 09 1 29.86 33.79 0.45 Benzo(a)pyrene A3

- v0 1.11E

- 09 1.13E

- 09 1.16E

- 09 1.05E

- 09 1 4.76 5.39 0.00 Benzo(b)fluoranthene A3

- v0 1.11E

- 09 1.13E

- 09 1.16E

- 09 1.05 E

- 09 1 4.76 5.39 0.00 Benzo(g,h,i)perylene A3

- v0 1.22E

- 09 1.16E

- 09 1.39E

- 09 1.13E

- 09 1 11.81 13.36 0.38 Benzo(k)fluoranthene A3

- v0 1.11E

- 09 1.13E

- 09 1.16E

- 09 1.05E

- 09 1 4.76 5.39 0.00 Chrysene A3

- v0 1.36E

- 09 1.16E

- 09 1.79E

- 09 1.13E

- 09 1 27.6 3 31.27 0.44 Dibenz(a,h)anthracene A3

- v0 1.11E

- 09 1.13E

- 09 1.16E

- 09 1.05E

- 09 1 4.76 5.39 0.00 Ethylbenzene A3

- v0 2.20E

- 06 2.20E

- 06 2.20E

- 06 2.20E

- 06 1 0.00 0.00 0.00 Fluoranthene A3

- v0 1.16E

- 08 1.04E

- 08 1.75E

- 08 6.98E

- 09 1 46.07 52.14 1.00 Fluorene A3

- v0 4.49E

- 09 4.39E

- 09 5.69E

- 09 3.38E

- 09 1 25.79 29.19 1.00 Formaldehyde A3

- v0 4.64E

- 06 4.50E

- 06 5.19E

- 06 4.22E

- 06 1 10.76 12.18 0.37 Indeno(1,2,3

- cd)pyrene A3

- v0 1.11E

- 09 1.13E

- 09 1.16E

- 09 1.05E

- 09 1 4.76 5.39 0.00 Naphthalene A3

- v0 2.31E

- 07 2.31E

- 07 2.74E

- 07 1.89E

- 07 1 18.28 20.69 1.00 Phenanthrene A3

- v0 3.29E

- 08 3.24E

- 08 4.63E

- 08 2.00E

- 08 1 39.96 45.22 1.00 Propylene A3

- v0 4.53E

- 04 4.47E

- 04 5.98E

- 04 3.13E

- 04 1 31.59 35.74 1.00 Pyrene A3

- v0 5.47E

- 09 2.77E

- 09 1.1 4E

- 08 2.25E

- 09 1 93.70 106.03 1.00 Toluene A3

- v0 3.15E

- 05 1.35E

- 05 7.29E

- 05 8.17E

- 06 1 114.08 129.09 1.00 Xylene (Total) A3

- v0 1.82E

- 05 2.01E

- 05 2.90E

- 05 5.58E

- 06 1 64.92 73.46 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-22 Table D- 8a. Summary of Data for Emission Factor Developmen t
– Heaters Firing Natural Gas and Refinery Fuel Gas

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 7.53E

- 06 2.44E

- 06 1.81E

- 05 2.05E

- 06 1 121.63 137.64 1.0 0 Acenaphthylene A3

- v1 5.88E

- 05 2.32E

- 06 1.72E

- 04 2.11E

- 06 1 166.69 188.62 1.00 Acetaldehyde C3

- v0 1.47E

- 02 1.43E

- 02 1.67E

- 02 1.30E

- 02 1 12.83 14.52 1.00 Acrolein C3

- v0 2.29E

- 03 2.10E

- 03 2.84E

- 03 1.93E

- 03 1 21.23 24.03 0.00 Anthracene A3

- v0 1.04E

- 05 8.97E

- 06 1.43E

- 05 7.89E

- 06 1 33.12 37.48 1.00 Benzene A3

- v0 2.12E

- 02 1.99E

- 02 2.44E

- 02 1.94E

- 02 1 13.02 14.73 0.00 Benzo(a)anthracene A3

- v0 9.57E

- 06 7.66E

- 06 1.67E

- 05 4.34E

- 06 1 66.91 75.72 1.00 Benzo(a)pyrene A3

- v1 6.07E

- 06 6.67 E

- 06 1.10E

- 05 5.25E

- 07 1 86.79 98.21 0.97 Benzo(b)fluoranthene A3

- v0 2.63E

- 06 1.91E

- 06 4.19E

- 06 1.79E

- 06 1 51.36 58.12 1.00 Benzo(g,h,i)perylene A3

- v0 4.13E

- 07 1.59E

- 07 9.55E

- 07 1.25E

- 07 1 113.74 128.71 0.77 Benzo(k)fluoranthene A3

- v0 1.46E

- 06 8.35E

- 07 3.18E

- 06 3.70E

- 07 1 103.06 116.62 0.92 Chrysene A3

- v0 7.91E

- 07 6.38E

- 07 1.24E

- 06 4.91E

- 07 1 50.32 56.94 0.52 Dibenz(a,h)anthracene A3

- v0 1.38E

- 07 1.07E

- 07 2.08E

- 07 1.01E

- 07 1 43.36 49.06 0.00 Fluoranthene A3

- v0 1.80E

- 05 1.03E

- 05 3.82E

- 05 5.49E

- 06 1 98.02 110.92 1.00 Fluorene A3

- v1 6.48E

- 04 1.50E

- 04 1.69E

- 03 1.01E

- 04 1 139.64 158.01 1.00 Formaldehyde C3

- v0 4.33E

- 02 2.38E

- 02 8.89E

- 02 1.73E

- 02 1 91.33 103.35 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 4.56E

- 07 4.04E

- 07 6.67E

- 07 2.96E

- 07 1 41.87 47.38 0.49 Naphthalene A3

- v1 2.31E

- 03 4.04E

- 04 6.18E

- 03 3.45E

- 04 1 145.12 164.21 1.00 Phenanthrene A3

- v0 2.06E

- 04 1.06E

- 04 4.30E

- 04 8.36E

- 05 1 93.74 106.07 1.00 Phenol A3

- v0 1.72E

- 03 1.82E

- 03 2.08E

- 03 1.26E

- 03 1 24.34 27.54 1.00 Propylene A3

- v0 1.20E

- 02 1.13E

- 02 1.38E

- 02 1.10E

- 02 1 13.02 14.73 0.00 Pyrene A3

- v0 1.25E

- 05 7.14E

- 06 2.62E

- 05 4.04E

- 06 1 96.40 109.08 1.00 Toluene A3

- v0 2.63E

- 02 2.46E

- 02 3.03E

- 02 2.41E

- 02 1 13.02 14.73 0.00 Xylene (Total) A3

- v0 3 .03E

- 02 2.84E

- 02 3.49E

- 02 2.77E

- 02 1 13.02 14.73 0.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-23 Table D-8b. Summary of Data for Emission Factor Development
– Heaters Firing Natural Gas and Refinery Fuel Gas

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 4.05E

- 09 1.38E

- 09 9.73E

- 09 1.05E

- 09 1 121.25 137.21 1.00 Acenaphthylene A3

- v1 3.16E

- 08 1.31E

- 09 9.23E

- 08 1.08E

- 09 1 166.64 188.56 1.00 Acetaldehyde C3

- v0 7.02E

- 06 6.94E

- 06 7.52E

- 06 6.5 9E

- 06 1 6.67 7.55 1.00 Acrolein C3

- v0 1.08E

- 06 1.10E

- 06 1.12E

- 06 1.03E

- 06 1 4.51 5.11 0.00 Anthracene A3

- v0 5.59E

- 09 4.60E

- 09 7.69E

- 09 4.48E

- 09 1 32.56 36.85 1.00 Benzene A3

- v0 1.01E

- 05 1.02E

- 05 1.06E

- 05 9.61E

- 06 1 4.81 5.44 0.00 Benzo(a )anthracene A3

- v0 5.18E

- 09 4.34E

- 09 8.97E

- 09 2.23E

- 09 1 66.60 75.36 1.00 Benzo(a)pyrene A3

- v1 3.24E

- 09 3.78E

- 09 5.65E

- 09 2.82E

- 10 1 84.14 95.21 0.97 Benzo(b)fluoranthene A3

- v0 1.44E

- 09 1.03E

- 09 2.38E

- 09 9.21E

- 10 1 56.34 63.75 1.00 Benzo(g,h, i)perylene A3

- v0 2.22E

- 10 8.16E

- 11 5.13E

- 10 7.08E

- 11 1 113.71 128.67 0.77 Benzo(k)fluoranthene A3

- v0 7.64E

- 10 4.49E

- 10 1.63E

- 09 2.10E

- 10 1 99.78 112.91 0.92 Chrysene A3

- v0 4.27E

- 10 3.62E

- 10 6.67E

- 10 2.52E

- 10 1 50.33 56.95 0.52 Dibenz(a,h)ant hracene A3

- v0 7.45E

- 11 5.73E

- 11 1.12E

- 10 5.48E

- 11 1 43.05 48.72 0.00 Fluoranthene A3

- v0 9.73E

- 09 5.86E

- 09 2.05E

- 08 2.82E

- 09 1 97.23 110.02 1.00 Fluorene A3

- v1 3.49E

- 07 8.52E

- 08 9.09E

- 07 5.20E

- 08 1 139.21 157.53 1.00 Formaldehyde C3

- v0 2.19E

- 05 9.37E

- 06 4.74E

- 05 9.10E

- 06 1 100.34 113.54 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 2.45E

- 10 2.08E

- 10 3.58E

- 10 1.68E

- 10 1 41.08 46.49 0.49 Naphthalene A3

- v1 1.24E

- 06 2.08E

- 07 3.32E

- 06 1.96E

- 07 1 145.06 164.15 1.00 Phenanthrene A3

- v0 1.11E

- 07 6. 02E

- 08 2.31E

- 07 4.29E

- 08 1 93.26 105.53 1.00 Phenol A3

- v0 9.22E

- 07 9.35E

- 07 1.12E

- 06 7.14E

- 07 1 21.82 24.69 1.00 Propylene A3

- v0 5.75E

- 06 5.78E

- 06 6.01E

- 06 5.46E

- 06 1 4.81 5.44 0.00 Pyrene A3

- v0 6.74E

- 09 4.05E

- 09 1.41E

- 08 2.08E

- 09 1 95.66 1 08.24 1.00 Toluene A3

- v0 1.26E

- 05 1.26E

- 05 1.31E

- 05 1.19E

- 05 1 4.81 5.44 0.00 Xylene (Total) A3

- v0 1.45E

- 05 1.46E

- 05 1.51E

- 05 1.38E

- 05 1 4.81 5.44 0.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-24 Table D- 9a. Summary of Data for Emission Factor Development
– Heaters Firing Fuel Oil

Sub stance CARB

Rating Emission Factor (lb/Mgal) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v1 1.75E

- 06 2.20E

- 06 2.99E

- 06 6.81E

- 08 1 86.27 97.62 1.00 Acenaphthylene C3

- v0 8.02E

- 08 5.33E

- 08 1.37E

- 07 5.03E

- 08 1 61.23 69.29 1.00 Acetaldehyde C3

- v0 5.43E

- 04 5.44E

- 04 5.48E

- 04 5.38E

- 04 1 0.98 1.11 0.00 Acrolein C3

- v0 5.98E

- 04 5.99E

- 04 6.03E

- 04 5.91E

- 04 1 0.95 1.07 0.00 Anthracene C3

- v0 6.62E

- 08 6.81E

- 08 7.41E

- 08 5.65E

- 08 1 13.48 15.25 1.00 Ar senic D3

- v0 8.34E

- 04 8.28E

- 04 8.62E

- 04 8.13E

- 04 1 3.01 3.41 0.00 Benzene A3

- v0 8.47E

- 03 8.49E

- 03 8.74E

- 03 8.19E

- 03 1 3.22 3.65 0.00 Benzo(a)anthracene C3

- v1 3.84E

- 06 2.05E

- 07 1.12E

- 05 1.33E

- 07 1 165.56 187.35 1.00 Benzo(a)pyrene C3

- v0 9.80E

- 08 8.63E

- 08 1.84E

- 07 2.40E

- 08 1 82.16 92.97 1.00 Benzo(b)fluoranthene C3

- v0 7.95E

- 07 6.37E

- 07 1.15E

- 06 5.98E

- 07 1 38.74 43.84 1.00 Benzo(e)pyrene C3

- v0 5.54E

- 07 5.30E

- 07 7.73E

- 07 3.60E

- 07 1 37.44 42.36 1.00 Benzo(g,h,i)perylene C3

- v1 2.12E

- 06 5.50E

- 07 5.57E

- 06 2.55E

- 07 1 140.55 159.04 1.00 Benzo(k)fluoranthene C3

- v0 3.36E

- 08 2.08E

- 08 6.81E

- 08 1.18E

- 08 1 90.02 101.86 1.00 Beryllium D3

- v0 7.78E

- 05 7.64E

- 05 8.66E

- 05 7.04E

- 05 1 10.51 11.89 0.00 1,3

- Butadiene A3

- v0 1.95E

- 02 1.96E

- 0 2 2.01E

- 02 1.89E

- 02 1 3.14 3.55 0.00 Chloroform A3

- v0 8.63E

- 03 8.65E

- 03 8.88E

- 03 8.35E

- 03 1 3.06 3.46 0.00 2

- Chloronaphthalene C3

- v2 1.17E

- 05 5.33E

- 08 3.50E

- 05 3.57E

- 08 1 172.55 195.25 1.00 Chromium (Total) A3

- v0 2.54E

- 03 2.66E

- 03 2.74E

- 03 2 .22E

- 03 1 11.14 12.60 1.00 Chrysene C3

- v1 1.12E

- 05 2.80E

- 06 2.92E

- 05 1.54E

- 06 1 139.73 158.12 1.00 Copper D3

- v0 2.62E

- 03 1.64E

- 03 4.58E

- 03 1.63E

- 03 1 64.94 73.48 1.00 Dibenz(a,h)anthracene C3

- v1 1.76E

- 06 1.18E

- 07 5.09E

- 06 6.54E

- 08 1 164.18 185.78 1.00 Dioxin:4D 2378 C3

- v0 4.96E

- 10 5.94E

- 10 5.97E

- 10 2.97E

- 10 1 34.70 39.26 0.00 Dioxin:5D 12378 C3

- v1 2.49E

- 09 5.94E

- 10 6.57E

- 09 2.97E

- 10 1 142.30 161.02 0.00 Dioxin:6D 123478 C3

- v1 2.19E

- 09 5.94E

- 10 5.68E

- 09 2.97E

- 10 1 138.10 156.28 0.00 Dioxin:6D 123678 C3

- v1 2.99E

- 09 5.94E

- 10 8.07E

- 09 2.97E

- 10 1 147.43 166.83 0.07 Dioxin:6D 123789 C3

- v1 4.78E

- 09 5.94E

- 10 1.34E

- 08 2.97E

- 10 1 157.08 177.75 0.04 Dioxin:7D 1234678 C3

- v1 1.33E

- 08 4.45E

- 09 3.29E

- 08 2.68E

- 09 1 127.05 143.76 1.00 Dioxin:8D C3

- v0 4.68E

- 08 5.64E

- 08 5.97E

- 08 2.41E

- 08 1 42.12 47.67 1.00 Fluoranthene C3

- v0 1.97E

- 06 2.28E

- 06 2.48E

- 06 1.13E

- 06 1 37.09 41.97 1.00 Fluorene C3

- v0 7.48E

- 05 3.25E

- 05 1.67E

- 04 2.52E

- 05 1 106.53 120.55 1.00 Formaldehyde C 3

- v0 3.80E

- 03 3.81E

- 03 3.84E

- 03 3.77E

- 03 1 0.95 1.08 0.00 Furan:4F 2378 C3

- v2 8.93E

- 08 1.48E

- 09 2.66E

- 07 5.95E

- 10 1 171.19 193.71 1.00 Furan:5F 12378 C3

- v1 8.56E

- 09 5.94E

- 10 2.48E

- 08 2.97E

- 10 1 164.20 185.80 0.00 Furan:5F 23478 C3

- v2 1.52E

- 0 8 5.94E

- 10 4.48E

- 08 2.97E

- 10 1 168.14 190.26 0.00 Furan:6F 123478 C3

- v2 1.92E

- 08 5.94E

- 10 5.68E

- 08 1.49E

- 10 1 169.85 192.20 0.01 Furan:6F 123678 C3

- v2 6.12E

- 09 2.97E

- 10 1.79E

- 08 1.49E

- 10 1 166.91 188.87 0.02 Furan:5F 23478 C3

- v2 1.52E

- 08 5.9 4E

- 10 4.48E

- 08 2.97E

- 10 1 168.14 190.26 0.00 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-25 Table D - 9a. Summary of Data for Emission Factor Development
– Heaters Firing Fuel Oil (continued)

Substance CARB

Rating Emission Factor (lb/Mgal) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Furan:6F 123478 C3

- v2 1.92E

- 08 5.94E

- 10 5.68E

- 08 1.49E

- 10 1 169.85 192.20 0.01 Furan:6F 123678 C3

- v2 6.12E

- 09 2.97E

- 10 1.79E

- 08 1.49E

- 10 1 166.91 188.87 0.02 Furan:6F 123789 C3

- v0 4.96E

- 10 5.94E

- 10 5.97E

- 10 2.97E

- 10 1 34.70 39.26 0.00 Furan:6F 234678 C3

- v1 8.76E

- 09 8.91E

- 10 2.48E

- 08 5.95E

- 10 1 158.52 179.38 0.03 Furan:7F 1234678 C3

- v1 1.95E

- 08 1.19E

- 09 5.68E

- 08 5.95E

- 10 1 165.30 187.05 1.00 Furan:7F 1234789 C3

- v0 1.19E

- 09 5.94E

- 10 2.69E

- 09 2.97E

- 10 1 109.22 123.59 0.00 Furan:8F C3

- v1 1.04E

- 08 4.75E

- 09 2.54E

- 08 1.19E

- 09 1 125.10 141.57 1.00 Indeno(1,2,3

- cd)pyrene C3

- v1 1.81E

- 06 1.55E

- 07 5.12E

- 06 1.48E

- 07 1 158.71 179.59 1.00 Lead D3

- v0 2.96E

- 04 1.79E

- 04 5.48E

- 04 1.62E

- 04 1 73.61 83.30 0.62 Manganese D3

- v0 1.89E

- 03 1.79E

- 03 2.22E

- 03 1.67E

- 03 1 15.12 17.11 0.39 Mercury D3

- v0 1.72E

- 05 1.29E

- 05 2.83E

- 05 1.04E

- 05 1 56.41 63.84 0.00 2

- Methylnaphthalene C3

- v1 3.60E

- 05 1.06E

- 05 9.29E

- 05 4.54E

- 06 1 137.05 155.09 1.00 Naphthalen e C3

- v0 8.46E

- 04 1.04E

- 03 1.11E

- 03 3.88E

- 04 1 47.07 53.26 1.00 Nickel D3

- v0 3.46E

- 01 3.47E

- 01 4.09E

- 01 2.81E

- 01 1 18.57 21.01 1.00 Perylene C3

- v0 7.41E

- 08 3.57E

- 08 1.66E

- 07 2.07E

- 08 1 107.75 121.93 1.00 Phenanthrene C3

- v1 2.49E

- 05 1.18E

- 05 6.02E

- 05 2.83E

- 06 1 123.75 140.04 1.00 Propylene A3

- v0 1.52E

- 02 1.52E

- 02 1.56E

- 02 1.47E

- 02 1 3.01 3.41 0.00 Pyrene C3

- v0 1.32E

- 06 1.19E

- 06 2.14E

- 06 6.28E

- 07 1 57.94 65.56 1.00 Selenium D3

- v0 4.63E

- 03 3.96E

- 03 6.59E

- 03 3.33E

- 03 1 37.32 42.23 0.00 Toluene A3

- v0 9.99E

- 03 1.00E

- 02 1.03E

- 02 9.67E

- 03 1 3.06 3.46 0.00 Xylene (Total) A3

- v0 1.92E

- 02 1.92E

- 02 1.98E

- 02 1.86E

- 02 1 3.21 3.63 0.00 Zinc D3

- v0 8.93E

- 03 8.35E

- 03 1.22E

- 02 6.27E

- 03 1 33.43 37.83 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-26 Table D-9b. Summary of Data for Emission Factor Development
– Heaters Firing Fuel Oil

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v1 1.22E

- 08 1.53E

- 08 2.09E

- 08 4.76E

- 10 1 86.27 9 7.62 1.00 Acenaphthylene C3

- v0 5.59E

- 10 3.72E

- 10 9.55E

- 10 3.51E

- 10 1 61.23 69.29 1.00 Acetaldehyde C3

- v0 3.79E

- 06 3.80E

- 06 3.83E

- 06 3.75E

- 06 1 0.98 1.11 0.00 Acrolein C3

- v0 4.17E

- 06 4.18E

- 06 4.21E

- 06 4.13E

- 06 1 0.95 1.07 0.00 Anthracene C3

- v0 4.62E

- 10 4.75E

- 10 5.17E

- 10 3.94E

- 10 1 13.48 15.25 1.00 Arsenic D3

- v0 5.82E

- 06 5.78E

- 06 6.02E

- 06 5.67E

- 06 1 3.01 3.41 0.00 Benzene A3

- v0 5.91E

- 05 5.92E

- 05 6.10E

- 05 5.72E

- 05 1 3.22 3.65 0.00 Benzo(a)anthracene C3

- v1 2.68E

- 08 1.43E

- 09 7.7 9E

- 08 9.30E

- 10 1 165.56 187.35 1.00 Benzo(a)pyrene C3

- v0 6.84E

- 10 6.02E

- 10 1.28E

- 09 1.67E

- 10 1 82.16 92.97 1.00 Benzo(b)fluoranthene C3

- v0 5.55E

- 09 4.44E

- 09 8.02E

- 09 4.17E

- 09 1 38.74 43.84 1.00 Benzo(e)pyrene C3

- v0 3.87E

- 09 3.70E

- 09 5.39E

- 09 2.51E

- 09 1 37.44 42.36 1.00 Benzo(g,h,i)perylene C3

- v1 1.48E

- 08 3.84E

- 09 3.88E

- 08 1.78E

- 09 1 140.55 159.04 1.00 Benzo(k)fluoranthene C3

- v0 2.35E

- 10 1.45E

- 10 4.76E

- 10 8.27E

- 11 1 90.02 101.86 1.00 Beryllium D3

- v0 5.43E

- 07 5.33E

- 07 6.04E

- 07 4. 92E

- 07 1 10.51 11.89 0.00 1,3

- Butadiene A3

- v0 1.36E

- 04 1.37E

- 04 1.40E

- 04 1.32E

- 04 1 3.14 3.55 0.00 Cadmium D3

- v1 5.73E

- 06 8.28E

- 06 8.60E

- 06 2.99E

- 07 1 82.13 92.94 1.00 Chloroform A3

- v0 6.02E

- 05 6.03E

- 05 6.20E

- 05 5.83E

- 05 1 3.06 3.46 0.00 2

- Chloronaphthalene C3

- v2 8.16E

- 08 3.72E

- 10 2.44E

- 07 2.49E

- 10 1 172.55 195.25 1.00 Chromium (Hex) A3

- v0 2.00E

- 06 2.14E

- 06 2.18E

- 06 1.67E

- 06 1 14.20 16.07 0.00 Chromium (Total) A3

- v0 1.77E

- 05 1.85E

- 05 1.91E

- 05 1.55E

- 05 1 11.14 12.60 1.00 Chr ysene C3

- v1 7.81E

- 08 1.95E

- 08 2.04E

- 07 1.07E

- 08 1 139.73 158.12 1.00 Copper D3

- v0 1.83E

- 05 1.15E

- 05 3.20E

- 05 1.14E

- 05 1 64.94 73.48 1.00 Dibenz(a,h)anthracene C3

- v1 1.23E

- 08 8.23E

- 10 3.55E

- 08 4.57E

- 10 1 164.18 185.78 1.00 Dioxin:4D 2378 C3

- v0 3.46E

- 12 4.15E

- 12 4.17E

- 12 2.08E

- 12 1 34.70 39.26 0.00 Dioxin:5D 12378 C3

- v1 1.74E

- 11 4.15E

- 12 4.59E

- 11 2.08E

- 12 1 142.30 161.02 0.00 Dioxin:6D 123478 C3

- v1 1.53E

- 11 4.15E

- 12 3.96E

- 11 2.08E

- 12 1 138.10 156.28 0.00 Dioxin:6D 123678 C3

- v1 2 .08E

- 11 4.15E

- 12 5.63E

- 11 2.08E

- 12 1 147.43 166.83 0.07 Dioxin:6D 123789 C3

- v1 3.33E

- 11 4.15E

- 12 9.38E

- 11 2.08E

- 12 1 157.08 177.75 0.04 Dioxin:7D 1234678 C3

- v1 9.30E

- 11 3.11E

- 11 2.29E

- 10 1.87E

- 11 1 127.05 143.76 1.00 Dioxin:8D C3

- v0 3.26E

- 10 3.94E

- 10 4.17E

- 10 1.68E

- 10 1 42.12 47.67 1.00 Fluoranthene C3

- v0 1.37E

- 08 1.59E

- 08 1.73E

- 08 7.89E

- 09 1 37.09 41.97 1.00 Fluorene C3

- v0 5.22E

- 07 2.26E

- 07 1.16E

- 06 1.76E

- 07 1 106.53 120.55 1.00 Formaldehyde C3

- v0 2.65E

- 05 2.66E

- 05 2.68E

- 05 2. 63E

- 05 1 0.95 1.08 0.00 Furan:4F 2378 C3

- v2 6.23E

- 10 1.04E

- 11 1.86E

- 09 4.15E

- 12 1 171.19 193.71 1.00 Furan:5F 12378 C3

- v1 5.97E

- 11 4.15E

- 12 1.73E

- 10 2.08E

- 12 1 164.20 185.80 0.00 Furan:5F 23478 C3

- v2 1.06E

- 10 4.15E

- 12 3.13E

- 10 2.08E

- 12 1 168 .14 190.26 0.00 Furan:6F 123478 C3

- v2 1.34E

- 10 4.15E

- 12 3.96E

- 10 1.04E

- 12 1 169.85 192.20 0.01 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-27 Table D-9b. Summary of Data for Emission Factor Development
– Heaters Firing Fuel Oil (continued)

Substance CARB

Rating Emission Factor (l b/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Furan:6F 123678 C3

- v2 4.27E

- 11 2.07E

- 12 1.25E

- 10 1.04E

- 12 1 166.91 188.87 0.02 Furan:6F 123789 C3

- v0 3.46E

- 12 4.15E

- 12 4.17E

- 12 2.08E

- 12 1 34.70 39.26 0.00 Fur an:6F 234678 C3

- v1 6.11E

- 11 6.22E

- 12 1.73E

- 10 4.15E

- 12 1 158.52 179.38 0.03 Furan:7F 1234678 C3

- v1 1.36E

- 10 8.29E

- 12 3.96E

- 10 4.15E

- 12 1 165.30 187.05 1.00 Furan:7F 1234789 C3

- v0 8.33E

- 12 4.15E

- 12 1.88E

- 11 2.08E

- 12 1 109.22 123.59 0.00 Furan :8F C3

- v1 7.29E

- 11 3.32E

- 11 1.77E

- 10 8.30E

- 12 1 125.10 141.57 1.00 Indeno(1,2,3

- cd)pyrene C3

- v1 1.26E

- 08 1.08E

- 09 3.58E

- 08 1.03E

- 09 1 158.71 179.59 1.00 Lead D3

- v0 2.07E

- 06 1.25E

- 06 3.83E

- 06 1.13E

- 06 1 73.61 83.30 0.62 Manganese D3

- v0 1.32E

- 05 1.25E

- 05 1.55E

- 05 1.17E

- 05 1 15.12 17.11 0.39 Mercury D3

- v0 1.20E

- 07 8.99E

- 08 1.98E

- 07 7.28E

- 08 1 56.41 63.84 0.00 2

- Methylnaphthalene C3

- v1 2.51E

- 07 7.40E

- 08 6.49E

- 07 3.17E

- 08 1 137.05 155.09 1.00 Naphthalene C3

- v0 5.91E

- 06 7.28E

- 06 7.7 3E

- 06 2.71E

- 06 1 47.07 53.26 1.00 Nickel D3

- v0 2.41E

- 03 2.42E

- 03 2.86E

- 03 1.96E

- 03 1 18.57 21.01 1.00 Perylene C3

- v0 5.17E

- 10 2.49E

- 10 1.16E

- 09 1.45E

- 10 1 107.75 121.93 1.00 Phenanthrene C3

- v1 1.74E

- 07 8.23E

- 08 4.20E

- 07 1.98E

- 08 1 123.75 14 0.04 1.00 Propylene A3

- v0 1.06E

- 04 1.06E

- 04 1.09E

- 04 1.03E

- 04 1 3.01 3.41 0.00 Pyrene C3

- v0 9.22E

- 09 8.32E

- 09 1.49E

- 08 4.38E

- 09 1 57.94 65.56 1.00 Selenium D3

- v0 3.23E

- 05 2.77E

- 05 4.60E

- 05 2.33E

- 05 1 37.32 42.23 0.00 Toluene A3

- v0 6.97E

- 05 6.99E

- 05 7.18E

- 05 6.75E

- 05 1 3.06 3.46 0.00 Xylene (Total) A3

- v0 1.34E

- 04 1.34E

- 04 1.38E

- 04 1.29E

- 04 1 3.21 3.63 0.00 Zinc D3

- v0 6.23E

- 05 5.83E

- 05 8.49E

- 05 4.38E

- 05 1 33.43 37.83 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-28 Table D- 10a. Summary of Data for Emission Factor Deve lo pment
– Heaters Firing Refinery

Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### )

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A2

- v0 2.33E

- 06 1. 46E

- 06 5.28E

- 06 1.11E

- 06 4 65.80 38.88 0.95 Acenaphthylene A2

- v0 1.52E

- 06 1.39E

- 06 2.64E

- 06 9.83E

- 07 4 38.62 22.82 0.51 Acetaldehyde B1

- v3 1.95E

- 02 1.08E

- 02 1.12E

- 01 1.10E

- 04 8 129.02 51.62 0.88 Anthracene A2

- v0 2.81E

- 06 2.40E

- 06 5.93E

- 06 1. 01E

- 06 4 57.37 33.90 0.92 Antimony C3

- v0 5.81E

- 04 6.56E

- 04 8.51E

- 04 2.36E

- 04 1 54.13 61.25 1.00 Arsenic C3

- v0 9.54E

- 04 1.11E

- 03 1.43E

- 03 3.19E

- 04 1 60.10 68.00 1.00 Barium C3

- v0 6.49E

- 03 6.49E

- 03 6.64E

- 03 6.33E

- 03 1 2.45 2.78 0.00 Benzen e B1

- v2 8.42E

- 02 6.76E

- 02 2.76E

- 01 2.35E

- 03 11 93.71 31.97 0.02 Benzo(a)anthracene A1

- v2 3.70E

- 05 7.11E

- 06 3.97E

- 04 1.00E

- 06 9 261.62 100.56 1.00 Benzo(a)pyrene A1

- v3 9.89E

- 05 2.20E

- 06 1.32E

- 03 9.83E

- 07 9 344.55 132.44 0.98 Benzo(b)fluoranth ene A1

- v2 4.61E

- 05 4.20E

- 06 6.04E

- 04 9.83E

- 07 9 315.76 121.37 0.99 Benzo(g,h,i)perylene A2

- v0 1.17E

- 06 1.04E

- 06 1.41E

- 06 9.83E

- 07 4 16.09 9.51 0.00 Benzo(k)fluoranthene A1

- v2 2.72E

- 05 2.66E

- 06 3.40E

- 04 9.83E

- 07 9 309.39 118.92 0.96 Beryllium C3

- v0 2.88E

- 04 2.89E

- 04 2.95E

- 04 2.81E

- 04 1 2.45 2.78 0.00 Cadmium C3

- v0 1.11E

- 03 1.08E

- 03 1.33E

- 03 9.15E

- 04 1 18.76 21.23 1.00 Chromium (Hex) C3

- v0 2.43E

- 03 2.48E

- 03 2.51E

- 03 2.30E

- 03 1 4.62 5.23 0.00 Chromium (Total) C3

- v0 1.20E

- 03 7.38E

- 04 2.16E

- 03 7.03E

- 04 1 69.39 78.52 0.60 Chrysene A2

- v0 1.66E

- 06 1.29E

- 06 5.37E

- 06 9.83E

- 07 4 76.71 45.33 0.63 Copper C3

- v0 4.73E

- 03 2.16E

- 03 1.05E

- 02 1.48E

- 03 1 106.76 120.81 1.00 Dibenz(a,h)anthracene A1

- v2 1.06E

- 05 1.95E

- 06 1.31E

- 04 6.78E

- 07 9 262.22 100.79 0.00 Ethylbenzene A2

- v1 3.04E

- 02 1.74E

- 02 9.50E

- 02 2.53E

- 03 4 100.75 57.01 0.51 Fluoranthene A2

- v0 3.06E

- 06 3.03E

- 06 5.66E

- 06 1.72E

- 06 4 37.95 22.43 1.00 Fluorene A2

- v0 1.06E

- 05 8.55E

- 06 2.64E

- 05 3.33E

- 06 4 67.66 39.98 1.00 Formaldehyde B1

- v3 1.51E

- 01 3.03E

- 02 1.76E+00 7.92E

- 04 7 254.14 108.70 1.00 Hydrogen Sulfide A1

- v1 4.05E

- 01 3.27E

- 01 1.20E+00 1.82E

- 02 7 84.49 36.13 0.00 Indeno(1,2,3

- cd)pyrene A1

- v3 1.15E

- 04 2.29E

- 06 1.55E

- 03 9.83E

- 07 9 342.12 131.50 0 .99 Lead C3

- v0 5.49E

- 03 4.43E

- 03 8.43E

- 03 3.61E

- 03 1 47.03 53.22 1.00 Manganese C3

- v0 7.65E

- 03 7.03E

- 03 1.37E

- 02 2.21E

- 03 1 75.45 85.38 1.00 Mercury C3

- v0 2.02E

- 04 1.97E

- 04 2.17E

- 04 1.92E

- 04 1 6.49 7.34 0.36 Naphthalene A2

- v0 3.02E

- 04 2.4 3E

- 04 6.96E

- 04 1.33E

- 04 4 62.74 37.08 1.00 Nickel C3

- v1 1.06E

- 02 1.48E

- 03 2.88E

- 02 1.44E

- 03 1 149.30 168.95 0.95 Phenanthrene A2

- v0 1.44E

- 05 1.49E

- 05 2.17E

- 05 7.69E

- 06 4 32.45 19.18 1.00 Phenol C1

- v1 6.96E

- 03 4.70E

- 03 2.68E

- 02 2.93E

- 04 7 103 .61 44.32 0.97 Phosphorus C3

- v0 7.21E

- 04 7.22E

- 04 7.38E

- 04 7.03E

- 04 1 2.45 2.78 0.00 Propylene A2

- v0 2.05E

- 03 2.14E

- 03 2.91E

- 03 1.00E

- 03 3 25.36 16.57 0.05 Pyrene A2

- v0 2.84E

- 06 2.63E

- 06 5.09E

- 06 1.78E

- 06 4 33.95 20.06 1.00 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-29 Table D- 10a. Summary of Data for Emission Factor Development
– Heaters Firing Refinery Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### ) (continued)

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Selenium C3

- v0 2.20E

- 05 2.28E

- 05 2.85E

- 05 1.48E

- 05 1 31.23 35.34 0.78 Silver C3

- v1 1.81E

- 03 1.48E

- 03 3.61E

- 03 3.53E

- 04 1 91.23 103.24 0.94 Thallium C3

- v0 6.49E

- 03 6.49E

- 03 6.64E

- 03 6.33E

- 03 1 2.45 2.78 0.00 Toluene D1

- v2 1.37E

- 01 7.81E

- 02 1.21E+00 3.71E

- 03 11 154.31 52.65 0.55 Xylene (Total) A2

- v1 3.74E

- 02 3.37E

- 02 9.90E

- 02 4.27E

- 03 4 95.86 54.24 0.60 Zinc C3

- v0 2.34E

- 02 2.89E

- 02 3.18E

- 02 9.52E

- 03 1 51.72 58.53 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-30 Table D-10b. Summary of Data for Emission Factor Development
– Heaters Firing Refinery

Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### )

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Ac enaphthene A2

- v0 2.36E

- 09 1.55E

- 09 5.61E

- 09 1.20E

- 09 4 69.14 40.86 0.95 Acenaphthylene A2

- v0 1.55E

- 09 1.25E

- 09 2.74E

- 09 1.02E

- 09 4 41.70 24.64 0.51 Acetaldehyde B1

- v3 1.53E

- 05 8.12E

- 06 8.55E

- 05 8.41E

- 08 8 126.30 50.53 0.88 Anthracene A2

- v0 2.87E

- 09 2.30E

- 09 6.45E

- 09 1.09E

- 09 4 61.24 36.19 0.92 Antimony C3

- v0 5.17E

- 07 5.84E

- 07 7.58E

- 07 2.10E

- 07 1 54.13 61.25 1.00 Arsenic C3

- v0 8.50E

- 07 9.90E

- 07 1.28E

- 06 2.84E

- 07 1 60.10 68.00 1.00 Barium C3

- v0 5.78E

- 06 5.78E

- 06 5.92E

- 06 5.63E

- 0 6 1 2.45 2.78 0.00 Benzene B1

- v1 6.47E

- 05 5.49E

- 05 1.85E

- 04 2.54E

- 06 11 87.67 29.91 0.02 Benzo(a)anthracene A1

- v2 3.21E

- 08 5.40E

- 09 3.39E

- 07 1.05E

- 09 9 265.30 101.97 1.00 Benzo(a)pyrene A1

- v3 8.96E

- 08 1.73E

- 09 1.38E

- 06 1.02E

- 09 9 352.36 135 .44 0.98 Benzo(b)fluoranthene A1

- v2 4.04E

- 08 3.31E

- 09 4.87E

- 07 1.02E

- 09 9 314.58 120.92 0.99 Benzo(g,h,i)perylene A2

- v0 1.17E

- 09 1.10E

- 09 1.40E

- 09 1.02E

- 09 4 11.55 6.82 0.00 Benzo(k)fluoranthene A1

- v2 2.41E

- 08 2.18E

- 09 2.96E

- 07 1.02E

- 09 9 310 .01 119.16 0.96 Beryllium C3

- v0 2.57E

- 07 2.57E

- 07 2.63E

- 07 2.50E

- 07 1 2.45 2.78 0.00 Cadmium C3

- v0 9.88E

- 07 9.65E

- 07 1.18E

- 06 8.15E

- 07 1 18.76 21.23 1.00 Chromium (Hex) C3

- v0 2.17E

- 06 2.21E

- 06 2.24E

- 06 2.05E

- 06 1 4.62 5.23 0.00 Chromium (Total) C3

- v0 1.07E

- 06 6.57E

- 07 1.93E

- 06 6.26E

- 07 1 69.39 78.52 0.60 Chrysene A2

- v0 1.63E

- 09 1.23E

- 09 4.79E

- 09 1.02E

- 09 4 66.84 39.50 0.63 Copper C3

- v0 4.21E

- 06 1.93E

- 06 9.39E

- 06 1.31E

- 06 1 106.76 120.81 1.00 Dibenz(a,h)anthracene A1

- v2 1.0 2E

- 08 1.60E

- 09 1.37E

- 07 5.93E

- 10 9 279.09 107.28 0.00 Ethylbenzene A2

- v1 3.02E

- 05 1.79E

- 05 1.03E

- 04 2.72E

- 06 4 104.65 59.21 0.51 Fluoranthene A2

- v0 3.06E

- 09 3.14E

- 09 5.04E

- 09 1.85E

- 09 4 33.80 19.97 1.00 Fluorene A2

- v0 1.08E

- 08 8.77E

- 09 2.74E

- 08 2.96E

- 09 4 70.62 41.74 1.00 Formaldehyde B1

- v3 1.11E

- 04 1.90E

- 05 1.34E

- 03 7.67E

- 07 7 262.94 112.46 1.00 Hydrogen Sulfide A1

- v1 2.92E

- 04 2.46E

- 04 8.04E

- 04 1.76E

- 05 7 75.53 32.30 0.00 Indeno(1,2,3

- cd)pyrene A1

- v3 1.03E

- 07 1.75E

- 09 1.42E

- 06 1.02E

- 09 9 343.01 131.85 0.99 Lead C3

- v0 4.89E

- 06 3.94E

- 06 7.51E

- 06 3.21E

- 06 1 47.03 53.22 1.00 Manganese C3

- v0 6.81E

- 06 6.26E

- 06 1.22E

- 05 1.97E

- 06 1 75.45 85.38 1.00 Mercury C3

- v0 1.80E

- 07 1.75E

- 07 1.93E

- 07 1.71E

- 07 1 6.49 7.34 0.36 Na phthalene A2

- v0 3.13E

- 07 2.61E

- 07 7.58E

- 07 1.19E

- 07 4 66.90 39.53 1.00 Nickel C3

- v1 9.42E

- 06 1.31E

- 06 2.57E

- 05 1.29E

- 06 1 149.30 168.95 0.95 Phenanthrene A2

- v0 1.46E

- 08 1.50E

- 08 2.25E

- 08 6.91E

- 09 4 32.60 19.27 1.00 Phenol C1

- v1 5.63E

- 06 3.1 4E

- 06 2.54E

- 05 2.84E

- 07 7 114.62 49.02 0.97 Phosphorus C3

- v0 6.42E

- 07 6.43E

- 07 6.57E

- 07 6.26E

- 07 1 2.45 2.78 0.00 Propylene A2

- v0 2.17E

- 06 2.22E

- 06 2.98E

- 06 1.08E

- 06 3 23.69 15.47 0.05 Pyrene A2

- v0 2.84E

- 09 2.72E

- 09 4.53E

- 09 1.87E

- 09 4 28.87 17.06 1.00 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-31 Table D-10b. Summary of Data for Emission Factor Development
– Heaters Firing Refinery Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### ) (continued)

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Selenium C3

- v0 1.96E

- 08 2.03E

- 08 2.54E

- 08 1.32E

- 08 1 31.23 35.34 0.78 Silver C3

- v1 1.61E

- 06 1.31E

- 06 3.21E

- 06 3.14E

- 07 1 91.23 103.24 0.94 Thallium C3

- v0 5.78E

- 06 5.78E

- 06 5.92E

- 06 5.63E

- 06 1 2.45 2.78 0.00 Toluene D1

- v2 1.07E

- 04 7.00E

- 05 9.19E

- 04 4.04E

- 06 11 148.57 50.69 0.55 Xylene (Total) A2

- v1 3.73E

- 05 3.16E

- 05 1.08E

- 04 4.66E

- 06 4 99.32 56.19 0.60 Zinc C3

- v0 2.08E

- 05 2.58E

- 05 2.83E

- 05 8.48E

- 06 1 51.72 58.53 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-32 Table D- 11a
. Summary of Data for Emission Factor Development
–

Heaters Firing Refinery Fuel Gas

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A2

- v0 2.33E

- 06 1.46E

- 06 5.28E

- 06 1.11E

- 06 4 65.80 38.88 0.95 Acenaphthylene A2

- v0 1.52E

- 06 1.39E

- 06 2.64E

- 06 9.83E

- 07 4 38.62 22.82 0.51 Acetaldehyde B1

- v3 1.95E

- 02 1.08E

- 02 1.12E

- 01 1.10E

- 04 8 129.02 51.62 0.88 Anthracene A2

- v0 2.81E

- 06 2.40E

- 06 5.93E

- 06 1.01E

- 06 4 57.37 33.90 0.92 Antimony C3

- v0 5.81E

- 04 6.56E

- 04 8.51E

- 04 2.36E

- 04 1 54.13 61.25 1.00 Arsenic C3

- v0 9.54E

- 04 1.11E

- 03 1.43E

- 03 3.19E

- 04 1 60.10 68.00 1.00 Barium C3

- v0 6.49E

- 03 6.49E

- 03 6.64E

- 03 6.33E

- 03 1 2.45 2.78 0.00 Benz ene B1

- v2 8.42E

- 02 6.76E

- 02 2.76E

- 01 2.35E

- 03 11 93.71 31.97 0.02 Benzo(a)anthracene A1

- v2 3.70E

- 05 7.11E

- 06 3.97E

- 04 1.00E

- 06 9 261.62 100.56 1.00 Benzo(a)pyrene A1

- v3 9.89E

- 05 2.20E

- 06 1.32E

- 03 9.83E

- 07 9 344.55 132.44 0.98 Benzo(b)fluoran thene A1

- v2 4.61E

- 05 4.20E

- 06 6.04E

- 04 9.83E

- 07 9 315.76 121.37 0.99 Benzo(g,h,i)perylene A2

- v0 1.17E

- 06 1.04E

- 06 1.41E

- 06 9.83E

- 07 4 16.09 9.51 0.00 Benzo(k)fluoranthene A1

- v2 2.72E

- 05 2.66E

- 06 3.40E

- 04 9.83E

- 07 9 309.39 118.92 0.96 Berylli um C3

- v0 2.88E

- 04 2.89E

- 04 2.95E

- 04 2.81E

- 04 1 2.45 2.78 0.00 Cadmium C3

- v0 1.11E

- 03 1.08E

- 03 1.33E

- 03 9.15E

- 04 1 18.76 21.23 1.00 Chromium (Hex) C3

- v0 2.43E

- 03 2.48E

- 03 2.51E

- 03 2.30E

- 03 1 4.62 5.23 0.00 Chromium (Total) C3

- v0 1.20E

- 03 7.3 8E

- 04 2.16E

- 03 7.03E

- 04 1 69.39 78.52 0.60 Chrysene A2

- v0 1.66E

- 06 1.29E

- 06 5.37E

- 06 9.83E

- 07 4 76.71 45.33 0.63 Copper C3

- v0 4.73E

- 03 2.16E

- 03 1.05E

- 02 1.48E

- 03 1 106.76 120.81 1.00 Dibenz(a,h)anthracene A1

- v2 1.06E

- 05 1.95E

- 06 1.31E

- 04 6.7 8E

- 07 9 262.22 100.79 0.00 Ethylbenzene A2

- v1 3.04E

- 02 1.74E

- 02 9.50E

- 02 2.53E

- 03 4 100.75 57.01 0.51 Fluoranthene A2

- v0 3.06E

- 06 3.03E

- 06 5.66E

- 06 1.72E

- 06 4 37.95 22.43 1.00 Fluorene A2

- v0 1.06E

- 05 8.55E

- 06 2.64E

- 05 3.33E

- 06 4 67.66 39.98 1.00 Formaldehyde B1

- v3 1.51E

- 01 3.03E

- 02 1.76E+00 7.92E

- 04 7 254.14 108.70 1.00 Hydrogen Sulfide A1

- v1 4.05E

- 01 3.27E

- 01 1.20E+00 1.82E

- 02 7 84.49 36.13 0.00 Indeno(1,2,3

- cd)pyrene A1

- v3 1.15E

- 04 2.29E

- 06 1.55E

- 03 9.83E

- 07 9 342.12 131.50 0.99 Lead C3

- v0 5.49E

- 03 4.43E

- 03 8.43E

- 03 3.61E

- 03 1 47.03 53.22 1.00 Manganese C3

- v0 7.65E

- 03 7.03E

- 03 1.37E

- 02 2.21E

- 03 1 75.45 85.38 1.00 Mercury C3

- v0 2.02E

- 04 1.97E

- 04 2.17E

- 04 1.92E

- 04 1 6.49 7.34 0.36 Naphthalene A2

- v0 3.02E

- 04 2 .43E

- 04 6.96E

- 04 1.33E

- 04 4 62.74 37.08 1.00 Nickel C3

- v1 1.06E

- 02 1.48E

- 03 2.88E

- 02 1.44E

- 03 1 149.30 168.95 0.95 Phenanthrene A2

- v0 1.44E

- 05 1.49E

- 05 2.17E

- 05 7.69E

- 06 4 32.45 19.18 1.00 Phenol C1

- v1 6.96E

- 03 4.70E

- 03 2.68E

- 02 2.93E

- 04 7 1 03.61 44.32 0.97 Phosphorus C3

- v0 7.21E

- 04 7.22E

- 04 7.38E

- 04 7.03E

- 04 1 2.45 2.78 0.00 Propylene A2

- v0 2.05E

- 03 2.14E

- 03 2.91E

- 03 1.00E

- 03 3 25.36 16.57 0.05 Pyrene A2

- v0 2.84E

- 06 2.63E

- 06 5.09E

- 06 1.78E

- 06 4 33.95 20.06 1.00 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-33 Table D- 11a
. Summary of Data for Emission Factor Development
–

Heaters Firing Refinery Fuel Gas (continued)

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Selenium C3

- v0 2.2 0E

- 05 2.28E

- 05 2.85E

- 05 1.48E

- 05 1 31.23 35.34 0.78 Silver C3

- v1 1.81E

- 03 1.48E

- 03 3.61E

- 03 3.53E

- 04 1 91.23 103.24 0.94 Thallium C3

- v0 6.49E

- 03 6.49E

- 03 6.64E

- 03 6.33E

- 03 1 2.45 2.78 0.00 Toluene D1

- v2 1.37E

- 01 7.81E

- 02 1.21E+00 3.71E

- 03 11 154.31 52.65 0.55 Xylene (Total) A2

- v1 3.74E

- 02 3.37E

- 02 9.90E

- 02 4.27E

- 03 4 95.86 54.24 0.60 Zinc C3

- v0 2.34E

- 02 2.89E

- 02 3.18E

- 02 9.52E

- 03 1 51.72 58.53 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-34 Table D-11b. Summary of Data for Emission Factor Development
–

Heaters Firing Refinery Fuel Gas

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A2

- v0 2.36E

- 09 1.55E

- 09 5.61E

- 09 1.20E

- 09 4 69.14 40.86 0.95 Acenaphthylene A2

- v0 1.55 E

- 09 1.25E

- 09 2.74E

- 09 1.02E

- 09 4 41.70 24.64 0.51 Acetaldehyde B1

- v3 1.53E

- 05 8.12E

- 06 8.55E

- 05 8.41E

- 08 8 126.30 50.53 0.88 Anthracene A2

- v0 2.87E

- 09 2.30E

- 09 6.45E

- 09 1.09E

- 09 4 61.24 36.19 0.92 Antimony C3

- v0 5.17E

- 07 5.84E

- 07 7.58E

- 07 2.10E

- 07 1 54.13 61.25 1.00 Arsenic C3

- v0 8.50E

- 07 9.90E

- 07 1.28E

- 06 2.84E

- 07 1 60.10 68.00 1.00 Barium C3

- v0 5.78E

- 06 5.78E

- 06 5.92E

- 06 5.63E

- 06 1 2.45 2.78 0.00 Benzene B1

- v1 6.47E

- 05 5.49E

- 05 1.85E

- 04 2.54E

- 06 11 87.67 29.91 0 .02 Benzo(a)anthracene A1

- v2 3.21E

- 08 5.40E

- 09 3.39E

- 07 1.05E

- 09 9 265.30 101.97 1.00 Benzo(a)pyrene A1

- v3 8.96E

- 08 1.73E

- 09 1.38E

- 06 1.02E

- 09 9 352.36 135.44 0.98 Benzo(b)fluoranthene A1

- v2 4.04E

- 08 3.31E

- 09 4.87E

- 07 1.02E

- 09 9 314.58 120.92 0.99 Benzo(g,h,i)perylene A2

- v0 1.17E

- 09 1.10E

- 09 1.40E

- 09 1.02E

- 09 4 11.55 6.82 0.00 Benzo(k)fluoranthene A1

- v2 2.41E

- 08 2.18E

- 09 2.96E

- 07 1.02E

- 09 9 310.01 119.16 0.96 Beryllium C3

- v0 2.57E

- 07 2.57E

- 07 2.63E

- 07 2.50E

- 07 1 2.45 2.78 0.00 Cadmium C3

- v0 9.88E

- 07 9.65E

- 07 1.18E

- 06 8.15E

- 07 1 18.76 21.23 1.00 Chromium (Hex) C3

- v0 2.17E

- 06 2.21E

- 06 2.24E

- 06 2.05E

- 06 1 4.62 5.23 0.00 Chromium (Total) C3

- v0 1.07E

- 06 6.57E

- 07 1.93E

- 06 6.26E

- 07 1 69.39 78.52 0.60 Chrysene A2

- v0 1. 63E

- 09 1.23E

- 09 4.79E

- 09 1.02E

- 09 4 66.84 39.50 0.63 Copper C3

- v0 4.21E

- 06 1.93E

- 06 9.39E

- 06 1.31E

- 06 1 106.76 120.81 1.00 Dibenz(a,h)anthracene A1

- v2 1.02E

- 08 1.60E

- 09 1.37E

- 07 5.93E

- 10 9 279.09 107.28 0.00 Ethylbenzene A2

- v1 3.02E

- 05 1.79E

- 05 1.03E

- 04 2.72E

- 06 4 104.65 59.21 0.51 Fluoranthene A2

- v0 3.06E

- 09 3.14E

- 09 5.04E

- 09 1.85E

- 09 4 33.80 19.97 1.00 Fluorene A2

- v0 1.08E

- 08 8.77E

- 09 2.74E

- 08 2.96E

- 09 4 70.62 41.74 1.00 Formaldehyde B1

- v3 1.11E

- 04 1.90E

- 05 1.34E

- 03 7.67E

- 07 7 262.94 112.46 1.00 Hydrogen Sulfide A1

- v1 2.92E

- 04 2.46E

- 04 8.04E

- 04 1.76E

- 05 7 75.53 32.30 0.00 Indeno(1,2,3

- cd)pyrene A1

- v3 1.03E

- 07 1.75E

- 09 1.42E

- 06 1.02E

- 09 9 343.01 131.85 0.99 Lead C3

- v0 4.89E

- 06 3.94E

- 06 7.51E

- 06 3.21E

- 06 1 47.03 53.22 1.00 Manganese C3

- v0 6.81E

- 06 6.26E

- 06 1.22E

- 05 1.97E

- 06 1 75.45 85.38 1.00 Mercury C3

- v0 1.80E

- 07 1.75E

- 07 1.93E

- 07 1.71E

- 07 1 6.49 7.34 0.36 Naphthalene A2

- v0 3.13E

- 07 2.61E

- 07 7.58E

- 07 1.19E

- 07 4 66.90 39.53 1.00 Nickel C3

- v1 9. 42E

- 06 1.31E

- 06 2.57E

- 05 1.29E

- 06 1 149.30 168.95 0.95 Phenanthrene A2

- v0 1.46E

- 08 1.50E

- 08 2.25E

- 08 6.91E

- 09 4 32.60 19.27 1.00 Phenol C1

- v1 5.63E

- 06 3.14E

- 06 2.54E

- 05 2.84E

- 07 7 114.62 49.02 0.97 Phosphorus C3

- v0 6.42E

- 07 6.43E

- 07 6.57E

- 07 6.26E

- 07 1 2.45 2.78 0.00 Propylene A2

- v0 2.17E

- 06 2.22E

- 06 2.98E

- 06 1.08E

- 06 3 23.69 15.47 0.05 Pyrene A2

- v0 2.84E

- 09 2.72E

- 09 4.53E

- 09 1.87E

- 09 4 28.87 17.06 1.00 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-35 Table D-11b. Summary of Data for Emission Factor Development
–

Heaters Firing Refinery Fuel Gas (continued)

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Selenium C3

- v0 1.96E

- 08 2.03E

- 08 2.54E

- 08 1.32E

- 08 1 31.23 35.34 0.78 Silver C3

- v1 1.61E

- 06 1.31E

- 06 3.21E

- 06 3.14E

- 07 1 91.23 103.24 0.94 Thallium C3

- v0 5.78E

- 06 5.78E

- 06 5.92E

- 06 5.63E

- 06 1 2.45 2.78 0.00 Toluene D1

- v2 1.07E

- 04 7.00E

- 05 9.19E

- 04 4.04E

- 06 11 148.57 50.69 0.55 Xylene (Total) A2

- v1 3.73E

- 05 3.16E

- 05 1 .08E

- 04 4.66E

- 06 4 99.32 56.19 0.60 Zinc C3

- v0 2.08E

- 05 2.58E

- 05 2.83E

- 05 8.48E

- 06 1 51.72 58.53 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-36 Table D- 12a. Summary of Data for Emission Factor Development
– Heaters Firing Refinery

Fuel Gas Controlled with Selective Catalytic Reduction

S ubstance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A2

- v0 2.33E

- 06 1.46E

- 06 5.28E

- 06 1.11E

- 06 4 65.80 38.88 0.95 Acenaphthylene A2

- v0 1.52E

- 06 1.39E

- 06 2.64E

- 06 9.8 3E

- 07 4 38.62 22.82 0.51 Acetaldehyde B1

- v3 1.95E

- 02 1.08E

- 02 1.12E

- 01 1.10E

- 04 8 129.02 51.62 0.88 Anthracene A2

- v0 2.81E

- 06 2.40E

- 06 5.93E

- 06 1.01E

- 06 4 57.37 33.90 0.92 Antimony C3

- v0 5.81E

- 04 6.56E

- 04 8.51E

- 04 2.36E

- 04 1 54.13 61.25 1. 00 Arsenic C3

- v0 9.54E

- 04 1.11E

- 03 1.43E

- 03 3.19E

- 04 1 60.10 68.00 1.00 Barium C3

- v0 6.49E

- 03 6.49E

- 03 6.64E

- 03 6.33E

- 03 1 2.45 2.78 0.00 Benzene B1

- v2 8.42E

- 02 6.76E

- 02 2.76E

- 01 2.35E

- 03 11 93.71 31.97 0.02 Benzo(a)anthracene A1

- v2 3.70E

- 05 7.11E

- 06 3.97E

- 04 1.00E

- 06 9 261.62 100.56 1.00 Benzo(a)pyrene A1

- v3 9.89E

- 05 2.20E

- 06 1.32E

- 03 9.83E

- 07 9 344.55 132.44 0.98 Benzo(b)fluoranthene A1

- v2 4.61E

- 05 4.20E

- 06 6.04E

- 04 9.83E

- 07 9 315.76 121.37 0.99 Benzo(g,h,i)perylene A2

- v0 1.17E

- 06 1.04E

- 06 1.41E

- 06 9.83E

- 07 4 16.09 9.51 0.00 Benzo(k)fluoranthene A1

- v2 2.72E

- 05 2.66E

- 06 3.40E

- 04 9.83E

- 07 9 309.39 118.92 0.96 Beryllium C3

- v0 2.88E

- 04 2.89E

- 04 2.95E

- 04 2.81E

- 04 1 2.45 2.78 0.00 Cadmium C3

- v0 1.11E

- 03 1.08E

- 03 1. 33E

- 03 9.15E

- 04 1 18.76 21.23 1.00 Chromium (Hex) C3

- v0 2.43E

- 03 2.48E

- 03 2.51E

- 03 2.30E

- 03 1 4.62 5.23 0.00 Chromium (Total) C3

- v0 1.20E

- 03 7.38E

- 04 2.16E

- 03 7.03E

- 04 1 69.39 78.52 0.60 Chrysene A2

- v0 1.66E

- 06 1.29E

- 06 5.37E

- 06 9.83E

- 07 4 7 6.71 45.33 0.63 Copper C3

- v0 4.73E

- 03 2.16E

- 03 1.05E

- 02 1.48E

- 03 1 106.76 120.81 1.00 Dibenz(a,h)anthracene A1

- v2 1.06E

- 05 1.95E

- 06 1.31E

- 04 6.78E

- 07 9 262.22 100.79 0.00 Ethylbenzene A2

- v1 3.04E

- 02 1.74E

- 02 9.50E

- 02 2.53E

- 03 4 100.75 57.01 0.51 Fluoranthene A2

- v0 3.06E

- 06 3.03E

- 06 5.66E

- 06 1.72E

- 06 4 37.95 22.43 1.00 Fluorene A2

- v0 1.06E

- 05 8.55E

- 06 2.64E

- 05 3.33E

- 06 4 67.66 39.98 1.00 Formaldehyde B1

- v3 1.51E

- 01 3.03E

- 02 1.76E+00 7.92E

- 04 7 254.14 108.70 1.00 Hydrogen Sul fide A1

- v1 4.05E

- 01 3.27E

- 01 1.20E+00 1.82E

- 02 7 84.49 36.13 0.00 Indeno(1,2,3

- cd)pyrene A1

- v3 1.15E

- 04 2.29E

- 06 1.55E

- 03 9.83E

- 07 9 342.12 131.50 0.99 Lead C3

- v0 5.49E

- 03 4.43E

- 03 8.43E

- 03 3.61E

- 03 1 47.03 53.22 1.00 Manganese C3

- v0 7.65E

- 03 7.03E

- 03 1.37E

- 02 2.21E

- 03 1 75.45 85.38 1.00 Mercury C3

- v0 2.02E

- 04 1.97E

- 04 2.17E

- 04 1.92E

- 04 1 6.49 7.34 0.36 Naphthalene A2

- v0 3.02E

- 04 2.43E

- 04 6.96E

- 04 1.33E

- 04 4 62.74 37.08 1.00 Nickel C3

- v1 1.06E

- 02 1.48E

- 03 2.88E

- 02 1.44E

- 03 1 1 49.30 168.95 0.95 Phenanthrene A2

- v0 1.44E

- 05 1.49E

- 05 2.17E

- 05 7.69E

- 06 4 32.45 19.18 1.00 Phenol C1

- v1 6.96E

- 03 4.70E

- 03 2.68E

- 02 2.93E

- 04 7 103.61 44.32 0.97 Phosphorus C3

- v0 7.21E

- 04 7.22E

- 04 7.38E

- 04 7.03E

- 04 1 2.45 2.78 0.00 Propyl ene A2

- v0 2.05E

- 03 2.14E

- 03 2.91E

- 03 1.00E

- 03 3 25.36 16.57 0.05 Pyrene A2

- v0 2.84E

- 06 2.63E

- 06 5.09E

- 06 1.78E

- 06 4 33.95 20.06 1.00 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-37 Table D- 12a. Summary of Data for Emission Factor Development
– Heaters Firing Refinery

Fuel Gas Controlled with Selective Catalytic Reduction (continued)

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Selenium C3

- v0 2.20E

- 05 2.28E

- 05 2.85E

- 05 1.48E

- 05 1 31.23 35.34 0.78 Silver C3

- v1 1.81E

- 03 1.48E

- 03 3.61E

- 03 3.53E

- 04 1 91.23 103.24 0.94 Thallium C3

- v0 6.49E

- 03 6.49E

- 03 6.64E

- 03 6.33E

- 03 1 2.45 2.78 0.00 Toluene D1

- v2 1.37E

- 01 7.81E

- 02 1.21E+00 3.71E

- 03 11 154.31 52.65 0.55 Xylene (Total) A2

- v1 3.74E

- 02 3. 37E

- 02 9.90E

- 02 4.27E

- 03 4 95.86 54.24 0.60 Zinc C3

- v0 2.34E

- 02 2.89E

- 02 3.18E

- 02 9.52E

- 03 1 51.72 58.53 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-38 Table D-12b. Summary of Data for Emission Factor Development
– Heaters Firing Refinery

Fuel Gas Controlled with Selective Catalytic Reduction

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A2

- v0 2.36E

- 09 1.55E

- 09 5.61E

- 09 1.20E

- 09 4 69.14 40.86 0.95 Acenaphthylene A2

- v0 1.55E

- 09 1.25E

- 09 2.7 4E

- 09 1.02E

- 09 4 41.70 24.64 0.51 Acetaldehyde B1

- v3 1.53E

- 05 8.12E

- 06 8.55E

- 05 8.41E

- 08 8 126.30 50.53 0.88 Anthracene A2

- v0 2.87E

- 09 2.30E

- 09 6.45E

- 09 1.09E

- 09 4 61.24 36.19 0.92 Antimony C3

- v0 5.17E

- 07 5.84E

- 07 7.58E

- 07 2.10E

- 07 1 54.13 61.25 1.00 Arsenic C3

- v0 8.50E

- 07 9.90E

- 07 1.28E

- 06 2.84E

- 07 1 60.10 68.00 1.00 Barium C3

- v0 5.78E

- 06 5.78E

- 06 5.92E

- 06 5.63E

- 06 1 2.45 2.78 0.00 Benzene B1

- v1 6.47E

- 05 5.49E

- 05 1.85E

- 04 2.54E

- 06 11 87.67 29.91 0.02 Benzo(a)anthracene A1

- v2 3.21E

- 08 5.40E

- 09 3.39E

- 07 1.05E

- 09 9 265.30 101.97 1.00 Benzo(a)pyrene A1

- v3 8.96E

- 08 1.73E

- 09 1.38E

- 06 1.02E

- 09 9 352.36 135.44 0.98 Benzo(b)fluoranthene A1

- v2 4.04E

- 08 3.31E

- 09 4.87E

- 07 1.02E

- 09 9 314.58 120.92 0.99 Benzo(g,h,i)perylen e A2

- v0 1.17E

- 09 1.10E

- 09 1.40E

- 09 1.02E

- 09 4 11.55 6.82 0.00 Benzo(k)fluoranthene A1

- v2 2.41E

- 08 2.18E

- 09 2.96E

- 07 1.02E

- 09 9 310.01 119.16 0.96 Beryllium C3

- v0 2.57E

- 07 2.57E

- 07 2.63E

- 07 2.50E

- 07 1 2.45 2.78 0.00 Cadmium C3

- v0 9.88E

- 07 9. 65E

- 07 1.18E

- 06 8.15E

- 07 1 18.76 21.23 1.00 Chromium (Hex) C3

- v0 2.17E

- 06 2.21E

- 06 2.24E

- 06 2.05E

- 06 1 4.62 5.23 0.00 Chromium (Total) C3

- v0 1.07E

- 06 6.57E

- 07 1.93E

- 06 6.26E

- 07 1 69.39 78.52 0.60 Chrysene A2

- v0 1.63E

- 09 1.23E

- 09 4.79E

- 09 1.0 2E

- 09 4 66.84 39.50 0.63 Copper C3

- v0 4.21E

- 06 1.93E

- 06 9.39E

- 06 1.31E

- 06 1 106.76 120.81 1.00 Dibenz(a,h)anthracene A1

- v2 1.02E

- 08 1.60E

- 09 1.37E

- 07 5.93E

- 10 9 279.09 107.28 0.00 Ethylbenzene A2

- v1 3.02E

- 05 1.79E

- 05 1.03E

- 04 2.72E

- 06 4 104. 65 59.21 0.51 Fluoranthene A2

- v0 3.06E

- 09 3.14E

- 09 5.04E

- 09 1.85E

- 09 4 33.80 19.97 1.00 Fluorene A2

- v0 1.08E

- 08 8.77E

- 09 2.74E

- 08 2.96E

- 09 4 70.62 41.74 1.00 Formaldehyde B1

- v3 1.11E

- 04 1.90E

- 05 1.34E

- 03 7.67E

- 07 7 262.94 112.46 1.00 Hyd rogen Sulfide A1

- v1 2.92E

- 04 2.46E

- 04 8.04E

- 04 1.76E

- 05 7 75.53 32.30 0.00 Indeno(1,2,3

- cd)pyrene A1

- v3 1.03E

- 07 1.75E

- 09 1.42E

- 06 1.02E

- 09 9 343.01 131.85 0.99 Lead C3

- v0 4.89E

- 06 3.94E

- 06 7.51E

- 06 3.21E

- 06 1 47.03 53.22 1.00 Manganese C3

- v0 6.81E

- 06 6.26E

- 06 1.22E

- 05 1.97E

- 06 1 75.45 85.38 1.00 Mercury C3

- v0 1.80E

- 07 1.75E

- 07 1.93E

- 07 1.71E

- 07 1 6.49 7.34 0.36 Naphthalene A2

- v0 3.13E

- 07 2.61E

- 07 7.58E

- 07 1.19E

- 07 4 66.90 39.53 1.00 Nickel C3

- v1 9.42E

- 06 1.31E

- 06 2.57E

- 05 1.2 9E

- 06 1 149.30 168.95 0.95 Phenanthrene A2

- v0 1.46E

- 08 1.50E

- 08 2.25E

- 08 6.91E

- 09 4 32.60 19.27 1.00 Phenol C1

- v1 5.63E

- 06 3.14E

- 06 2.54E

- 05 2.84E

- 07 7 114.62 49.02 0.97 Phosphorus C3

- v0 6.42E

- 07 6.43E

- 07 6.57E

- 07 6.26E

- 07 1 2.45 2.78 0.00 Propylene A2

- v0 2.17E

- 06 2.22E

- 06 2.98E

- 06 1.08E

- 06 3 23.69 15.47 0.05 (continued)

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-39 Table D-12b. Summary of Data for Emission Factor Development
– Heaters Firing Refinery

Fuel Gas Controlled with Selective Catalytic Reduction (continued)

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Pyrene A2

- v0 2.84E

- 09 2.72E

- 09 4.53E

- 09 1.87E

- 09 4 28.87 17.06 1.00 Selenium C3

- v0 1.96E

- 08 2.03E

- 08 2.54E

- 08 1.32E

- 08 1 31.23 35.3 4 0.78 Silver C3

- v1 1.61E

- 06 1.31E

- 06 3.21E

- 06 3.14E

- 07 1 91.23 103.24 0.94 Thallium C3

- v0 5.78E

- 06 5.78E

- 06 5.92E

- 06 5.63E

- 06 1 2.45 2.78 0.00 Toluene D1

- v2 1.07E

- 04 7.00E

- 05 9.19E

- 04 4.04E

- 06 11 148.57 50.69 0.55 Xylene (Total) A2

- v1 3 .73E

- 05 3.16E

- 05 1.08E

- 04 4.66E

- 06 4 99.32 56.19 0.60 Zinc C3

- v0 2.08E

- 05 2.58E

- 05 2.83E

- 05 8.48E

- 06 1 51.72 58.53 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-40 Table D-13a. Summary of Data for Emission Factor Development
– Internal Combustion Engines Firing Diesel Fuel, O 2 

### < 13%

Subst ance CARB

Rating Emission Factor (lb/Mgal) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v0 6.44E

- 04 6.87E

- 04 8.67E

- 04 3.78E

- 04 1 38.39 43.44 1.00 Acenaphthylene C3

- v0 1.27E

- 03 1.31E

- 03 1.32E

- 03 1.18E

- 0 3 1 6.10 6.91 1.00 Acetaldehyde A3

- v0 3.47E

- 03 2.25E

- 03 6.46E

- 03 1.69E

- 03 1 75.34 85.25 1.00 Acrolein A3

- v0 1.07E

- 03 7.15E

- 04 1.79E

- 03 7.15E

- 04 1 57.74 65.33 0.56 Anthracene C3

- v0 1.70E

- 04 1.34E

- 04 2.89E

- 04 8.61E

- 05 1 62.56 70.79 1.00 Be nzene A3

- v0 1.01E

- 01 9.93E

- 02 1.04E

- 01 9.93E

- 02 1 2.71 3.06 1.00 Benzo(a)anthracene C3

- v0 8.71E

- 05 8.30E

- 05 9.69E

- 05 8.15E

- 05 1 9.72 11.00 1.00 Benzo(a)pyrene C3

- v0 3.54E

- 05 3.84E

- 05 4.77E

- 05 2.00E

- 05 1 39.85 45.09 0.45 Benzo(b)fluoranthene C3

- v0 1.53E

- 04 1.41E

- 04 1.92E

- 04 1.26E

- 04 1 22.58 25.55 0.27 Benzo(g,h,i)perylene C3

- v0 7.69E

- 05 7.84E

- 05 8.30E

- 05 6.92E

- 05 1 9.17 10.37 1.00 Benzo(k)fluoranthene C3

- v0 3.02E

- 05 1.23E

- 05 6.92E

- 05 9.22E

- 06 1 111.67 126.37 0.76 Chrysene C3

- v0 2.11E

- 04 2.21E

- 04 2.28E

- 04 1.84E

- 04 1 11.03 12.48 1.00 Dibenz(a,h)anthracene C3

- v0 4.77E

- 05 4.61E

- 05 5.07E

- 05 4.61E

- 05 1 5.59 6.32 0.00 Fluoranthene C3

- v0 5.56E

- 04 5.47E

- 04 5.84E

- 04 5.37E

- 04 1 4.50 5.09 1.00 Fluorene C3

- v0 1.77E

- 03 1.76E

- 03 1.81E

- 03 1.72E

- 03 1 2.62 2.96 1.00 Formaldehyde A3

- v1 1.09E

- 02 4.64E

- 03 2.63E

- 02 1.74E

- 03 1 123.19 139.41 1.00 Indeno(1,2,3

- cd)pyrene C3

- v0 5.69E

- 05 5.84E

- 05 6.61E

- 05 4.61E

- 05 1 17.72 20.05 0.34 Naphthalene C3

- v0 1.80E

- 02 1.81E

- 02 1.85E

- 02 1.72E

- 02 1 3.74 4.24 1.00 Phenanthrene C3

- v0 5.62E

- 03 5.65E

- 03 5.76E

- 03 5.47E

- 03 1 2.58 2.92 1.00 Propylene A3

- v0 3.85E

- 01 4.03E

- 01 4.03E

- 01 3.49E

- 01 1 8.06 9.12 1.00 Pyrene C3

- v0 5.11E

- 04 4.89E

- 04 5.60E

- 04 4.86E

- 04 1 8.16 9.24 1.00 Tolu ene A3

- v0 3.74E

- 02 3.70E

- 02 3.87E

- 02 3.64E

- 02 1 3.27 3.70 1.00 Xylene (Total) A3

- v0 2.68E

- 02 2.70E

- 02 2.77E

- 02 2.57E

- 02 1 3.85 4.36 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-41 Table D-13b. Summary of Data for Emission Factor Development
– Internal Combustion Engines Firing Diesel Fuel, O 2 

### < 13%

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v0 4.54E

- 06 4.85E

- 06 6.12E

- 06 2.67E

- 06 1 38.39 43.44 1.00 Acenaphthylene C3

- v0 8.97E

- 06 9.23E

- 06 9.34E

- 06 8.34E

- 06 1 6.10 6.91 1.00 Acetaldehyde A3

- v0 2.44E

- 05 1.59E

- 05 4.56E

- 05 1.19E

- 05 1 75.34 85.25 1.00 Acrolein A3

- v0 7.57E

- 06 5.04E

- 06 1.26E

- 05 5.04E

- 06 1 57.74 65.33 0.56 Anthracene C3

- v0 1.20E

- 06 9.43E

- 07 2.04E

- 06 6.07E

- 07 1 62.5 6 70.79 1.00 Benzene A3

- v0 7.11E

- 04 7.00E

- 04 7.33E

- 04 7.00E

- 04 1 2.71 3.06 1.00 Benzo(a)anthracene C3

- v0 6.14E

- 07 5.85E

- 07 6.83E

- 07 5.75E

- 07 1 9.72 11.00 1.00 Benzo(a)pyrene C3

- v0 2.49E

- 07 2.71E

- 07 3.36E

- 07 1.41E

- 07 1 39.85 45.09 0.45 Be nzo(b)fluoranthene C3

- v0 1.08E

- 06 9.98E

- 07 1.36E

- 06 8.89E

- 07 1 22.58 25.55 0.27 Benzo(g,h,i)perylene C3

- v0 5.42E

- 07 5.53E

- 07 5.85E

- 07 4.88E

- 07 1 9.17 10.37 1.00 Benzo(k)fluoranthene C3

- v0 2.13E

- 07 8.67E

- 08 4.88E

- 07 6.51E

- 08 1 111.67 126.37 0.7 6 Chrysene C3

- v0 1.49E

- 06 1.56E

- 06 1.60E

- 06 1.30E

- 06 1 11.03 12.48 1.00 Dibenz(a,h)anthracene C3

- v0 3.36E

- 07 3.25E

- 07 3.58E

- 07 3.25E

- 07 1 5.59 6.32 0.00 Fluoranthene C3

- v0 3.92E

- 06 3.86E

- 06 4.12E

- 06 3.78E

- 06 1 4.50 5.09 1.00 Fluorene C3

- v 0 1.25E

- 05 1.24E

- 05 1.28E

- 05 1.21E

- 05 1 2.62 2.96 1.00 Formaldehyde A3

- v1 7.68E

- 05 3.27E

- 05 1.85E

- 04 1.23E

- 05 1 123.19 139.41 1.00 Indeno(1,2,3

- cd)pyrene C3

- v0 4.01E

- 07 4.12E

- 07 4.66E

- 07 3.25E

- 07 1 17.72 20.05 0.34 Naphthalene C3

- v0 1.27E

- 04 1.28E

- 04 1.31E

- 04 1.21E

- 04 1 3.74 4.24 1.00 Phenanthrene C3

- v0 3.97E

- 05 3.98E

- 05 4.06E

- 05 3.86E

- 05 1 2.58 2.92 1.00 Propylene A3

- v0 2.71E

- 03 2.84E

- 03 2.84E

- 03 2.46E

- 03 1 8.06 9.12 1.00 Pyrene C3

- v0 3.61E

- 06 3.45E

- 06 3.95E

- 06 3.43E

- 06 1 8.16 9.24 1.00 Toluene A3

- v0 2.63E

- 04 2.61E

- 04 2.73E

- 04 2.57E

- 04 1 3.27 3.70 1.00 Xylene (Total) A3

- v0 1.89E

- 04 1.91E

- 04 1.95E

- 04 1.81E

- 04 1 3.85 4.36 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-42 Table D-14a. Summary of Data for Emission Factor Development
– Internal Combustion Engines Firing Diesel Fuel, O 2 

### > 13%

Substance CARB

Rating Emission Factor (lb/Mgal) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v2 1.98E

- 04 1.15E

- 04 6.88E

- 04 1.41E

- 06 2 136.01 108.83 1.00 Acenaphthylene C 3

- v3 7.03E

- 04 3.13E

- 04 1.86E

- 03 1.41E

- 06 2 125.21 100.19 1.00 Acetaldehyde A3

- v0 1.07E

- 01 1.07E

- 01 1.52E

- 01 5.82E

- 02 2 43.11 34.50 1.00 Acrolein A3

- v0 1.30E

- 02 8.43E

- 03 3.16E

- 02 6.62E

- 03 2 74.07 59.27 0.82 Anthracene C3

- v1 2.60E

- 04 2.95E

- 04 3.71E

- 04 3.11E

- 05 2 45.24 36.20 1.00 Benzaldehyde A3

- v0 1.26E

- 02 1.24E

- 02 1.35E

- 02 1.20E

- 02 1 6.29 7.12 0.68 Benzene B3

- v0 1.22E

- 01 1.13E

- 01 1.91E

- 01 6.57E

- 02 2 48.35 38.69 1.00 Benzo(a)anthracene C3

- v1 2.34E

- 04 2.04E

- 04 6.75E

- 04 1.55E

- 05 2 104.10 83.30 1.00 Benzo(a)pyrene C3

- v1 2.60E

- 05 1.82E

- 05 5.83E

- 05 1.41E

- 06 2 108.55 86.85 0.00 Benzo(b)fluoranthene C3

- v0 2.59E

- 05 2.72E

- 05 3.88E

- 05 1.17E

- 05 1 52.68 59.61 0.50 Benzo(b+k)fluoranthene C3

- v0 1.44E

- 06 1.45E

- 06 1.46E

- 06 1.41E

- 06 1 1.90 2.14 0.00 Benzo(g,h,i)perylene C3

- v1 6.78E

- 05 5.89E

- 05 1.55E

- 04 1.17E

- 05 2 71.76 57.42 0.43 Benzo(k)fluoranthene C3

- v0 4.14E

- 05 4.27E

- 05 6.22E

- 05 1.94E

- 05 1 51.63 58.43 0.50 1,3

- Butadiene C3

- v0 5.41E

- 03 5.41E

- 03 5.41E

- 03 5.41E

- 03 1 0 .00 0.00 0.00 Chrysene C3

- v0 4.90E

- 05 5.23E

- 05 6.75E

- 05 2.72E

- 05 2 33.96 27.17 1.00 Dibenz(a,h)anthracene C3

- v0 8.12E

- 05 6.41E

- 05 1.44E

- 04 4.42E

- 05 2 50.80 40.65 0.35 Fluoranthene C3

- v1 1.06E

- 03 8.29E

- 04 2.70E

- 03 6.99E

- 05 2 90.38 72.32 1.0 0 Fluorene C3

- v1 4.06E

- 03 3.96E

- 03 7.57E

- 03 2.10E

- 04 2 87.57 70.07 0.99 Formaldehyde A3

- v0 1.65E

- 01 1.45E

- 01 3.35E

- 01 8.55E

- 02 2 55.71 44.58 1.00 Indeno(1,2,3

- cd)pyrene C3

- v1 6.43E

- 05 4.08E

- 05 1.32E

- 04 7.77E

- 06 2 83.82 67.07 0.30 Naphthale ne C3

- v0 1.18E

- 02 7.84E

- 03 3.04E

- 02 5.92E

- 03 2 80.11 64.10 1.00 Phenanthrene C3

- v1 4.09E

- 03 4.23E

- 03 7.54E

- 03 3.11E

- 04 2 65.51 52.42 1.00 Propylene B3

- v0 3.58E

- 01 3.38E

- 01 5.83E

- 01 1.45E

- 01 2 56.61 45.30 1.00 Pyrene C3

- v0 6.66E

- 04 6.10E

- 04 1.07E

- 03 1.17E

- 04 2 51.99 41.60 1.00 Toluene B3

- v0 5.50E

- 02 5.49E

- 02 7.56E

- 02 3.44E

- 02 2 38.06 30.45 1.00 Xylene (m,p) C3

- v0 2.16E

- 02 2.09E

- 02 2.40E

- 02 1.98E

- 02 1 10.07 11.40 1.00 Xylene (o) C3

- v0 2.09E

- 02 2.09E

- 02 2.09E

- 02 2.09E

- 02 1 0.00 0.00 0.00 Xylene (Total) A3

- v0 3.59E

- 02 4.44E

- 02 4.44E

- 02 1.88E

- 02 1 41.24 46.67 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-43 Table D-14b. Summary of Data for Emission Factor Development
– Internal Combustion Engines Firing Diesel Fuel, O 2 

### > 13%

Substance CARB

Rating Emission Factor (l b/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v2 1.43E

- 06 8.34E

- 07 4.97E

- 06 1.00E

- 08 2 136.02 108.84 1.00 Acenaphthylene C3

- v3 5.08E

- 06 2.27E

- 06 1.35E

- 05 1.00E

- 08 2 125.21 100.19 1.00 Aceta ldehyde A3

- v0 7.64E

- 04 7.65E

- 04 1.08E

- 03 4.21E

- 04 2 42.48 33.99 1.00 Acrolein A3

- v0 9.37E

- 05 6.05E

- 05 2.29E

- 04 4.72E

- 05 2 74.63 59.71 0.82 Anthracene C3

- v1 1.86E

- 06 2.10E

- 06 2.65E

- 06 2.25E

- 07 2 45.07 36.07 1.00 Benzaldehyde A3

- v0 9.01E

- 05 8 .84E

- 05 9.64E

- 05 8.54E

- 05 1 6.29 7.12 0.68 Benzene B3

- v0 8.81E

- 04 8.17E

- 04 1.38E

- 03 4.69E

- 04 2 48.96 39.17 1.00 Benzo(a)anthracene C3

- v1 1.67E

- 06 1.47E

- 06 4.81E

- 06 1.12E

- 07 2 103.79 83.05 1.00 Benzo(a)pyrene C3

- v1 1.88E

- 07 1.32E

- 07 4.21E

- 07 1.00E

- 08 2 108.63 86.92 0.00 Benzo(b)fluoranthene C3

- v0 1.87E

- 07 1.97E

- 07 2.81E

- 07 8.43E

- 08 1 52.68 59.61 0.50 Benzo(b+k)fluoranthene C3

- v0 1.03E

- 08 1.03E

- 08 1.04E

- 08 1.00E

- 08 1 1.90 2.14 0.00 Benzo(g,h,i)perylene C3

- v1 4.87E

- 07 4.24E

- 07 1.1 2E

- 06 8.43E

- 08 2 72.27 57.82 0.43 Benzo(k)fluoranthene C3

- v0 3.00E

- 07 3.09E

- 07 4.49E

- 07 1.40E

- 07 1 51.63 58.43 0.50 1,3

- Butadiene C3

- v0 3.86E

- 05 3.86E

- 05 3.86E

- 05 3.86E

- 05 1 0.00 0.00 0.00 Chrysene C3

- v0 3.52E

- 07 3.76E

- 07 4.81E

- 07 1.97E

- 07 2 33.43 26.75 1.00 Dibenz(a,h)anthracene C3

- v0 5.84E

- 07 4.57E

- 07 1.04E

- 06 3.16E

- 07 2 51.34 41.08 0.35 Fluoranthene C3

- v1 7.59E

- 06 5.94E

- 06 1.93E

- 05 5.06E

- 07 2 90.02 72.03 1.00 Fluorene C3

- v1 2.90E

- 05 2.83E

- 05 5.40E

- 05 1.52E

- 06 2 87.31 69.86 0.99 Formaldehyde A3

- v0 1.19E

- 03 1.04E

- 03 2.39E

- 03 6.18E

- 04 2 55.30 44.25 1.00 Indeno(1,2,3

- cd)pyrene C3

- v1 4.63E

- 07 2.91E

- 07 9.55E

- 07 5.62E

- 08 2 84.39 67.52 0.30 Naphthalene C3

- v0 8.48E

- 05 5.59E

- 05 2.20E

- 04 4.28E

- 05 2 80.69 64.56 1.00 Ph enanthrene C3

- v1 2.93E

- 05 3.03E

- 05 5.38E

- 05 2.25E

- 06 2 65.09 52.08 1.00 Propylene B3

- v0 2.58E

- 03 2.44E

- 03 4.22E

- 03 1.04E

- 03 2 57.16 45.74 1.00 Pyrene C3

- v0 4.78E

- 06 4.38E

- 06 7.62E

- 06 8.43E

- 07 2 52.00 41.61 1.00 Toluene B3

- v0 3.96E

- 04 3.95E

- 04 5.47E

- 04 2.46E

- 04 2 38.72 30.98 1.00 Xylene (m,p) C3

- v0 1.54E

- 04 1.49E

- 04 1.71E

- 04 1.42E

- 04 1 10.07 11.40 1.00 Xylene (o) C3

- v0 1.49E

- 04 1.49E

- 04 1.49E

- 04 1.49E

- 04 1 0.00 0.00 0.00 Xylene (Total) A3

- v0 2.59E

- 04 3.21E

- 04 3.21E

- 04 1.36E

- 04 1 41.24 46.67 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-44 Table D-15a. Summary of Data for Emission Factor Development
– Two-Stroke Internal Combustion Engines Firing Field Gas, Lean

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median M aximum Minimum Acenaphthene A3

- v0 7.41E

- 04 7.41E

- 04 1.08E

- 03 4.00E

- 04 1 65.08 90.19 0.00 Acenaphthylene A3

- v0 1.11E

- 02 1.11E

- 02 1.57E

- 02 6.44E

- 03 1 59.06 81.86 1.00 Acetaldehyde A3

- v0 8.77E+00 9.42E+00 1.14E+01 5.53E+00 1 33.90 38.37 1.00 Acrolein A3

- v1 2.00E+00 1.44E+00 4.36E+00 2.00E

- 01 1 106.79 120.84 1.00 Anthracene A3

- v0 4.50E

- 03 4.50E

- 03 6.67E

- 03 2.34E

- 03 1 67.84 94.02 1.00 Benzene A3

- v0 7.85E+00 4.60E+00 1.36E+01 4.23E+00 2 60.68 53.19 1.00 Benzo(a)anthracene A3

- v0 8.97E

- 04 8.97E

- 04 9.11E

- 04 8.83E

- 04 1 2.17 3.01 1.00 Benzo(a)pyrene A3

- v0 8.75E

- 04 8.75E

- 04 1.53E

- 03 2.16E

- 04 1 106.44 147.52 0.00 Benzo(b)fluoranthene A3

- v0 1.48E

- 04 1.48E

- 04 1.71E

- 04 1.24E

- 04 1 22.41 31.05 0.00 Benzo(g,h,i)perylene A3

- v0 9.40E

- 05 9.40E

- 05 9.92E

- 05 8.89E

- 05 1 7.74 10.72 0.00 Benzo(k)fluoranthene A3

- v0 4.57E

- 03 4.57E

- 03 4.69E

- 03 4.44E

- 03 1 3.78 5.23 1.00 Chrysene A3

- v0 1.69E

- 03 1.69E

- 03 1.80E

- 03 1.58E

- 03 1 9.43 13.07 1.00 Dibenz(a,h)anthracene A3

- v0 7.70E

- 05 7 .70E

- 05 8.29E

- 05 7.11E

- 05 1 10.86 15.06 0.00 Fluoranthene A3

- v0 1.66E

- 04 1.66E

- 04 2.16E

- 04 1.16E

- 04 1 42.96 59.53 0.00 Fluorene A3

- v0 2.44E

- 03 2.44E

- 03 3.61E

- 03 1.27E

- 03 1 67.90 94.10 0.00 Formaldehyde A3

- v1 5.09E+01 6.79E+01 8.53E+01 4.21E+ 00 2 69.80 55.85 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 1.37E

- 04 1.37E

- 04 1.46E

- 04 1.29E

- 04 1 8.83 12.24 0.00 Naphthalene A3

- v0 2.19E

- 01 2.19E

- 01 2.22E

- 01 2.16E

- 01 1 1.88 2.61 1.00 Phenanthrene A3

- v0 4.91E

- 03 4.91E

- 03 6.49E

- 03 3.33E

- 03 1 45.46 6 3.00 1.00 Propylene A3

- v0 2.49E+01 1.77E+01 4.02E+01 1.14E+01 2 56.74 49.73 1.00 Pyrene A3

- v0 2.39E

- 04 2.39E

- 04 3.06E

- 04 1.71E

- 04 1 40.10 55.57 0.64 Toluene A3

- v1 2.86E+00 2.36E+00 5.74E+00 2.23E

- 01 2 72.83 63.84 1.00 Xylene (m,p) A3

- v0 6.04E

- 01 3.17E

- 01 1.25E+00 1.89E

- 01 2 80.76 70.79 1.00 Xylene (o) A3

- v0 2.88E

- 01 1.36E

- 01 5.91E

- 01 6.80E

- 02 2 88.41 77.49 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-45 Table D-15b. Summary of Data for Emission Factor Development
– Two-Stroke Internal Combustion Engines Firing Field Gas, Lean

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 7.06E

- 07 7.06E

- 07 1.03E

- 06 3.81E

- 07 1 65.08 90.19 0.00 Acenaphthylene A3

- v0 1.05E

- 05 1.05E

- 05 1.4 9E

- 05 6.14E

- 06 1 59.06 81.86 1.00 Acetaldehyde A3

- v0 8.36E

- 03 8.98E

- 03 1.08E

- 02 5.27E

- 03 1 33.90 38.37 1.00 Acrolein A3

- v1 1.90E

- 03 1.37E

- 03 4.15E

- 03 1.90E

- 04 1 106.79 120.84 1.00 Anthracene A3

- v0 4.29E

- 06 4.29E

- 06 6.35E

- 06 2.23E

- 06 1 67.84 94.02 1.00 Benzene A3

- v0 7.48E

- 03 4.38E

- 03 1.30E

- 02 4.03E

- 03 2 60.68 53.19 1.00 Benzo(a)anthracene A3

- v0 8.54E

- 07 8.54E

- 07 8.68E

- 07 8.41E

- 07 1 2.17 3.01 1.00 Benzo(a)pyrene A3

- v0 8.33E

- 07 8.33E

- 07 1.46E

- 06 2.06E

- 07 1 106.44 147.52 0.00 B enzo(b)fluoranthene A3

- v0 1.41E

- 07 1.41E

- 07 1.63E

- 07 1.18E

- 07 1 22.41 31.05 0.00 Benzo(g,h,i)perylene A3

- v0 8.95E

- 08 8.95E

- 08 9.44E

- 08 8.46E

- 08 1 7.74 10.72 0.00 Benzo(k)fluoranthene A3

- v0 4.35E

- 06 4.35E

- 06 4.46E

- 06 4.23E

- 06 1 3.78 5.23 1.00 Chrysene A3

- v0 1.61E

- 06 1.61E

- 06 1.72E

- 06 1.50E

- 06 1 9.43 13.07 1.00 Dibenz(a,h)anthracene A3

- v0 7.33E

- 08 7.33E

- 08 7.90E

- 08 6.77E

- 08 1 10.86 15.06 0.00 Fluoranthene A3

- v0 1.58E

- 07 1.58E

- 07 2.06E

- 07 1.10E

- 07 1 42.96 59.53 0.00 Fluorene A3

- v 0 2.32E

- 06 2.32E

- 06 3.43E

- 06 1.21E

- 06 1 67.90 94.10 0.00 Formaldehyde A3

- v1 4.85E

- 02 6.46E

- 02 8.13E

- 02 4.01E

- 03 2 69.80 55.85 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 1.31E

- 07 1.31E

- 07 1.39E

- 07 1.23E

- 07 1 8.83 12.24 0.00 Naphthalene A3

- v0 2.09E

- 04 2.09E

- 04 2.12E

- 04 2.06E

- 04 1 1.88 2.61 1.00 Phenanthrene A3

- v0 4.68E

- 06 4.68E

- 06 6.18E

- 06 3.17E

- 06 1 45.46 63.00 1.00 Propylene A3

- v0 2.37E

- 02 1.69E

- 02 3.82E

- 02 1.09E

- 02 2 56.74 49.73 1.00 Pyrene A3

- v0 2.27E

- 07 2.27E

- 07 2.92E

- 07 1.63E

- 07 1 4 0.10 55.57 0.64 Toluene A3

- v1 2.72E

- 03 2.25E

- 03 5.47E

- 03 2.12E

- 04 2 72.83 63.84 1.00 Xylene (m,p) A3

- v0 5.75E

- 04 3.02E

- 04 1.19E

- 03 1.80E

- 04 2 80.76 70.79 1.00 Xylene (o) A3

- v0 2.74E

- 04 1.30E

- 04 5.63E

- 04 6.48E

- 05 2 88.41 77.49 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-46 Tabl e D -16a. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Field Gas, Lean

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Benzene A2

- v0 1.72E+00 2.07E+00 2.24E+00 9.25E

- 01 3 35.58 28.47 1.00 Formaldehyde A2

- v1 4.15E+01 3.14E+01 9.78E+01 4.62E+00 3 76.73 50.13 1.00 Propylene A2

- v0 1.59E+01 1.84E+01 2.02E+01 9.48E+00 3 30.49 24.40 1.00 Toluene A2

- v0 7.68E

- 01 9.38E

- 01 1. 17E+00 2.69E

- 01 3 51.12 40.90 1.00 Xylene (m,p) A2

- v1 3.02E

- 01 1.90E

- 01 9.03E

- 01 7.74E

- 02 3 99.71 79.78 1.00 Xylene (o) A2

- v0 8.97E

- 02 9.57E

- 02 1.22E

- 01 6.13E

- 02 3 25.60 20.49 1.00



### Table D-16b. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Field Gas, Lean

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Benzene A2

- v0 1.64E

- 03 1.97E

- 03 2.14E

- 03 8.81E

- 04 3 35.58 28. 47 1.00 Formaldehyde A2

- v1 3.95E

- 02 2.99E

- 02 9.32E

- 02 4.40E

- 03 3 76.73 50.13 1.00 Propylene A2

- v0 1.52E

- 02 1.75E

- 02 1.92E

- 02 9.03E

- 03 3 30.49 24.40 1.00 Toluene A2

- v0 7.31E

- 04 8.94E

- 04 1.11E

- 03 2.56E

- 04 3 51.12 40.90 1.00 Xylene (m,p) A2

- v1 2.87E

- 04 1.81E

- 04 8.60E

- 04 7.37E

- 05 3 99.71 79.78 1.00 Xylene (o) A2

- v0 8.55E

- 05 9.11E

- 05 1.16E

- 04 5.84E

- 05 3 25.60 20.49 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-47 Table D-17a. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Field Gas, Rich

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Benzene A3

- v0 1.10E+01 1.10E+01 1.11E+01 1.09E+01 1 1.15 1.59 1.00 Formaldehyde A3

- v0 5.05E+00 4.65E+00 5.98E+00 4 .53E+00 1 15.91 18.00 1.00 Propylene A3

- v0 3.04E+00 3.04E+00 3.04E+00 3.04E+00 1 0.00 0.00 0.00 Toluene A3

- v0 3.44E+00 3.44E+00 3.55E+00 3.33E+00 1 4.56 6.32 1.00 Xylene (m,p) A3

- v0 5.37E

- 01 5.37E

- 01 5.62E

- 01 5.11E

- 01 1 6.73 9.33 1.00 Xylen e (o) A3

- v0 2.68E

- 01 2.68E

- 01 2.81E

- 01 2.56E

- 01 1 6.73 9.33 1.00



### Table D-17b. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Field Gas, Rich

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Benzene A3

- v0 1.05E

- 02 1.05E

- 02 1.06E

- 02 1.04E

- 02 1 1.15 1.59 1.00 Formaldehyde A3

- v0 4.81E

- 03 4.43E

- 03 5.69E

- 03 4.31E

- 03 1 15.91 18.00 1.00 Propylene A3

- v0 2.90E

- 03 2.90E

- 03 2.9 0E

- 03 2.90E

- 03 1 0.00 0.00 0.00 Toluene A3

- v0 3.28E

- 03 3.28E

- 03 3.38E

- 03 3.17E

- 03 1 4.56 6.32 1.00 Xylene (m,p) A3

- v0 5.11E

- 04 5.11E

- 04 5.36E

- 04 4.87E

- 04 1 6.73 9.33 1.00 Xylene (o) A3

- v0 2.56E

- 04 2.56E

- 04 2.68E

- 04 2.43E

- 04 1 6.73 9.33 1.0 0

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-48 Table D-18a. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Natural Gas, Lean

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 7.17E

- 04 6.36E

- 04 9.60E

- 04 5.57E

- 04 1 29.79 33.71 1.00 Acenaphthylene A3

- v0 7.59E

- 03 7.65E

- 03 1.07E

- 02 4.40E

- 03 1 41.56 47.03 1.00 Acetaldehyde A1

- v0 3.99E+00 2.96E+00 9.94E+00 1.52E+00 5 64.91 32.85 1.00 Acrolein A1

- v1 1.63E+00 1.10E+00 5.48E+00 2.01E

- 01 5 92.02 48.20 1.00 Anthracene A3

- v0 2.56E

- 04 2.40E

- 04 3.69E

- 04 1.60E

- 04 1 41.20 46.62 1.00 Benzene A1

- v1 1.21E+00 1.22E+00 2.47E+00 2.47E

- 01 7 47.28 24.77 1.00 Benzo(a)anthracene A3

- v0 7.78E

- 05 7.83E

- 05 9.60E

- 05 5.91E

- 05 1 23.70 26.82 1.00 Benzo(a)pyrene A3

- v0 3.55E

- 05 2.93E

- 05 5.17E

- 05 2.54E

- 05 1 39.97 45.23 0.76 Benzo(b)fluoranthene A3

- v2 3.27E

- 04 4.43E

- 05 9.29E

- 04 6.26E

- 06 1 159.90 180.94 0.95 Benzo(g,h,i)perylene A3

- v1 1.03E

- 04 2.93E

- 0 5 2.58E

- 04 2.09E

- 05 1 131.00 148.24 1.00 Benzo(k)fluoranthene A3

- v1 5.30E

- 04 4.87E

- 04 1.07E

- 03 3.08E

- 05 1 98.44 111.40 0.98 Chrysene A3

- v0 9.64E

- 05 1.11E

- 04 1.12E

- 04 6.61E

- 05 1 27.27 30.86 1.00 Dibenz(a,h)anthracene A3

- v0 1.09E

- 05 1.11E

- 05 1 .47E

- 05 6.96E

- 06 1 35.41 40.07 1.00 Fluoranthene A3

- v0 2.50E

- 04 2.64E

- 04 3.32E

- 04 1.53E

- 04 1 36.21 40.98 1.00 Fluorene A3

- v0 4.60E

- 04 4.16E

- 04 6.28E

- 04 3.37E

- 04 1 32.63 36.92 0.00 Formaldehyde A1

- v0 2.87E+01 2.77E+01 4.79E+01 9.68E+00 7 38.5 6 16.49 1.00 Indeno(1,2,3

- cd)pyrene A3

- v1 1.20E

- 04 3.91E

- 05 2.95E

- 04 2.43E

- 05 1 127.40 144.16 1.00 Naphthalene A3

- v0 1.22E

- 01 1.60E

- 01 1.86E

- 01 1.99E

- 02 1 73.21 82.85 1.00 Phenanthrene A3

- v0 8.93E

- 04 8.31E

- 04 1.26E

- 03 5.91E

- 04 1 37.66 42.62 1.00 Propylene A1

- v1 1.87E+01 8.81E+00 5.85E+01 4.12E+00 7 109.05 57.12 0.97 Pyrene A3

- v0 1.23E

- 04 1.42E

- 04 1.62E

- 04 6.61E

- 05 1 41.10 46.51 1.00 Toluene A1

- v0 4.12E

- 01 3.96E

- 01 5.70E

- 01 1.65E

- 01 7 33.98 17.80 1.00 Xylene (m,p) A1

- v0 8.6 3E

- 02 8.13E

- 02 1.59E

- 01 3.53E

- 02 7 46.27 24.24 1.00 Xylene (o) A1

- v0 4.94E

- 02 4.95E

- 02 9.14E

- 02 1.06E

- 02 7 39.52 20.70 0.95

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-49 Table D-18b. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Natural Gas, Lean

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 6.83E

- 07 6.06E

- 07 9.14E

- 07 5.30E

- 07 1 29.79 33.71 1.00 Acenaphthylene A3

- v0 7.23E

- 06 7.29 E

- 06 1.02E

- 05 4.19E

- 06 1 41.56 47.03 1.00 Acetaldehyde A1

- v0 3.80E

- 03 2.82E

- 03 9.47E

- 03 1.45E

- 03 5 64.91 32.85 1.00 Acrolein A1

- v1 1.56E

- 03 1.05E

- 03 5.22E

- 03 1.92E

- 04 5 92.02 48.20 1.00 Anthracene A3

- v0 2.44E

- 07 2.28E

- 07 3 .52E

- 07 1.52E

- 07 1 41.20 46.62 1.00 Benzene A1

- v1 1.15E

- 03 1.17E

- 03 2.35E

- 03 2.35E

- 04 7 47.28 24.77 1.00 Benzo(a)anthracene A3

- v0 7.41E

- 08 7.45E

- 08 9.14E

- 08 5.63E

- 08 1 23.70 26.82 1.00 Benzo(a)pyrene A3

- v0 3.38E

- 08 2.79E

- 08 4.92E

- 08 2.42E

- 08 1 39.97 45.23 0.76 Benzo(b)fluoranthene A3

- v2 3.11E

- 07 4.22E

- 08 8.85E

- 07 5.96E

- 09 1 159.90 180.94 0.95 Benzo(g,h,i)perylene A3

- v1 9.80E

- 08 2.79E

- 08 2.46E

- 07 1.99E

- 08 1 131.00 148.24 1.00 Benzo(k)fluoranthene A3

- v1 5.04E

- 07 4.64E

- 07 1.02E

- 06 2.93E

- 08 1 98.44 111.40 0.98 Chrysene A3

- v0 9.19E

- 08 1.05E

- 07 1.07E

- 07 6.29E

- 08 1 27.27 30.86 1.00 Dibenz(a,h)anthracene A3

- v0 1.04E

- 08 1.05E

- 08 1.40E

- 08 6.63E

- 09 1 35.41 40.07 1.00 Fluorant hene A3

- v0 2.38E

- 07 2.52E

- 07 3.16E

- 07 1.46E

- 07 1 36.21 40.98 1.00 Fluorene A3

- v0 4.38E

- 07 3.96E

- 07 5.98E

- 07 3.21E

- 07 1 32.63 36.92 0.00 Formaldehyde A1

- v0 2.73E

- 02 2.64E

- 02 4.56E

- 02 9.22E

- 03 7 38.56 16.49 1.00 Indeno(1,2,3

- cd)pyrene A3

- v1 1.14E

- 07 3.73E

- 08 2.81E

- 07 2.32E

- 08 1 127.40 144.16 1.00 Naphthalene A3

- v0 1.16E

- 04 1.52E

- 04 1.77E

- 04 1.90E

- 05 1 73.21 82.85 1.00 Phenanthrene A3

- v0 8.50E

- 07 7.92E

- 07 1.20E

- 06 5.63E

- 07 1 37.66 42.62 1.00 Pro pylene A1

- v1 1.78E

- 02 8.39E

- 03 5.57E

- 02 3.92E

- 03 7 109.05 57.12 0.97 Pyrene A3

- v0 1.18E

- 07 1.35E

- 07 1.55E

- 07 6.29E

- 08 1 41.10 46.51 1.00 Toluene A1

- v0 3.92E

- 04 3.77E

- 04 5.43E

- 04 1.57E

- 04 7 33.98 17.80 1.00 Xylene (m,p) A1

- v0 8.22E

- 05 7.74E

- 05 1.51E

- 04 3.36E

- 05 7 46.27 24.24 1.00 Xylene (o) A1

- v0 4.71E

- 05 4.71E

- 05 8.70E

- 05 1.01E

- 05 7 39.52 20.70 0.95

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-50 Table D-19a. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Natural Gas, Rich

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde A3

- v0 1.71E+00 1.70E+00 1.82E+00 1.60E+00 1 6.46 7.31 1.00 Acrolein A3

- v2 5.40E

- 01 4.1 6E

- 01 1.37E+00 2.59E

- 03 2 105.82 84.67 1.00 Benzene A3

- v0 9.87E+00 9.87E+00 1.02E+01 9.51E+00 1 5.05 7.00 1.00 Formaldehyde A3

- v1 5.32E+00 4.48E+00 1.14E+01 4.21E

- 01 2 100.69 80.57 1.00 Propylene A3

- v0 3.95E+01 3.95E+01 4.20E+01 3.70E+01 1 8 .95 12.40 1.00 Toluene A3

- v0 2.51E+00 2.51E+00 2.62E+00 2.41E+00 1 6.15 8.52 1.00 Xylene (m,p) A3

- v0 4.41E

- 01 4.41E

- 01 4.54E

- 01 4.28E

- 01 1 4.04 5.60 1.00 Xylene (o) A3

- v0 2.17E

- 01 2.17E

- 01 2.22E

- 01 2.12E

- 01 1 3.29 4.56 1.00



### Table D-19b. Summary of Data for Emission Factor Development
– Four -Stroke Internal Combustion Engines Firing Natural Gas, Rich

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde A3

- v0 1.63E

- 03 1.62E

- 03 1.74E

- 03 1.53E

- 03 1 6.46 7.31 1.00 Acrolein A3

- v2 5.15E

- 04 3.97E

- 04 1.31E

- 03 2.50E

- 06 2 105.65 84.54 1.00 Benzene A3

- v0 9.40E

- 03 9.40E

- 03 9.73E

- 03 9.06E

- 03 1 5.05 7.00 1.00 Formaldehyde A3

- v1 5.07E

- 03 4.27E

- 03 1.09E

- 02 4.08E

- 04 2 100.52 80.43 1.00 Propylene A3

- v0 3.76E

- 02 3.76E

- 02 4.00E

- 02 3.52E

- 02 1 8.95 12.40 1.00 Toluene A3

- v0 2.40E

- 03 2.40E

- 03 2.50E

- 03 2.29E

- 03 1 6.15 8.52 1.00 Xylene (m,p) A3

- v0 4.20E

- 04 4.20E

- 04 4.32E

- 04 4.08E

- 04 1 4.04 5.60 1.0 0 Xylene (o) A3

- v0 2.06E

- 04 2.06E

- 04 2.11E

- 04 2.02E

- 04 1 3.29 4.56 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-51 Table D-20a. Summary of Data for Emission Factor Development
–

Steam Generators Firing Natural Gas

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde A3

- v0 1.56E

- 02 1.57E

- 02 1.66E

- 02 1.44E

- 02 1 7.27 8.22 1.00 Acrolein A3

- v0 1.84E

- 02 1.75E

- 02 2.22E

- 02 1.55E

- 02 1 18.73 21.19 1.00 Benzene B3

- v0 3.86E

- 03 3.87E

- 03 3.88E

- 03 3.83E

- 03 2 0 .57 0.46 0.00 Formaldehyde A3

- v1 2.95E

- 02 1.83E

- 02 9.16E

- 02 3.96E

- 03 2 111.23 89.00 1.00 Propylene C3

- v0 1.09E

- 01 1.09E

- 01 1.09E

- 01 1.09E

- 01 1 0.36 0.41 0.00 Toluene B3

- v0 1.20E

- 02 1.20E

- 02 1.20E

- 02 1.19E

- 02 2 0.57 0.46 0.00 Xylene (Tota l) B3

- v0 2.76E

- 02 2.76E

- 02 2.77E

- 02 2.74E

- 02 2 0.57 0.46 0.00



### Table D-20b. Summary of Data for Emission Factor Development
–

Steam Generators Firing Natural Gas

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Rati o Mean Median Maximum Minimum Acetaldehyde A3

- v0 1.66E

- 05 1.68E

- 05 1.77E

- 05 1.53E

- 05 1 7.27 8.22 1.00 Acrolein A3

- v0 1.96E

- 05 1.86E

- 05 2.37E

- 05 1.65E

- 05 1 18.73 21.19 1.00 Benzene B3

- v0 3.94E

- 06 3.93E

- 06 4.10E

- 06 3.78E

- 06 2 4.28 3.42 0 .00 Formaldehyde A3

- v1 3.11E

- 05 1.87E

- 05 9.75E

- 05 3.87E

- 06 2 113.45 90.78 1.00 Propylene C3

- v0 1.16E

- 04 1.16E

- 04 1.17E

- 04 1.16E

- 04 1 0.36 0.41 0.00 Toluene B3

- v0 1.22E

- 05 1.22E

- 05 1.27E

- 05 1.17E

- 05 2 4.28 3.42 0.00 Xylene (Total) B3

- v0 2. 81E

- 05 2.81E

- 05 2.94E

- 05 2.70E

- 05 2 4.28 3.42 0.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-52 Table D-21a. Summary of Data for Emission Factor Development
– Steam Generators Firing Natural Gas and Casing Vapor Recovery Gas

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tai nty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 1.04E

- 06 7.23E

- 07 2.38E

- 06 4.12E

- 07 2 69.67 55.75 0.72 Acenaphthylene A3

- v1 2.70E

- 06 6.70E

- 07 1.03E

- 05 4.12E

- 07 2 144.60 115.70 0.85 Acetaldehyde A2

- v0 1.12E

- 02 1.02E

- 02 2.67E

- 02 5.02E

- 03 4 55.73 31.53 0.84 Acrolein A2

- v0 1.05E

- 02 1.07E

- 02 1.82E

- 02 5.02E

- 03 4 37.86 21.42 0.88 Anthracene A3

- v0 2.09E

- 06 2.28E

- 06 3.82E

- 06 4.12E

- 07 2 62.45 49.97 0.97 Benzene B1

- v0 3.33E

- 03 2.68E

- 03 6.21E

- 03 2.36E

- 03 5 44.41 22. 47 0.00 Benzo(a)anthracene A3

- v0 1.22E

- 06 1.12E

- 06 2.16E

- 06 6.82E

- 07 2 40.32 32.26 0.45 Benzo(a)pyrene A3

- v0 6.86E

- 07 6.46E

- 07 1.33E

- 06 3.98E

- 07 2 49.51 39.61 0.32 Benzo(b)fluoranthene A3

- v0 2.00E

- 06 9.18E

- 07 4.78E

- 06 6.36E

- 07 2 95.49 76.41 0.84 Benzo(g,h,i)perylene A3

- v0 9.80E

- 07 6.70E

- 07 1.75E

- 06 4.12E

- 07 2 61.38 49.11 0.59 Benzo(k)fluoranthene A3

- v0 8.21E

- 07 6.70E

- 07 1.39E

- 06 4.12E

- 07 2 44.95 35.97 0.52 Chrysene A3

- v0 1.55E

- 06 1.83E

- 06 2.16E

- 06 6.82E

- 07 2 38.63 30.91 0.33 Dibenz(a,h)anthracene A3

- v0 5.30E

- 07 5.24E

- 07 6.82E

- 07 3.96E

- 07 2 26.65 21.32 0.00 Ethylbenzene A3

- v0 9.22E

- 03 7.34E

- 03 1.86E

- 02 3.69E

- 03 2 55.96 44.77 0.54 Fluoranthene A3

- v0 3.66E

- 06 1.71E

- 06 9.03E

- 06 1.01E

- 06 2 98.55 78.86 1.00 Fluorene A3

- v0 5.63E

- 06 2.47E

- 06 1.30E

- 05 1.77E

- 06 2 95.48 76.40 1.00 Formaldehyde A2

- v1 1.58E

- 02 9.51E

- 03 7.01E

- 02 5.02E

- 03 4 117.82 66.66 0.70 Hydrogen Sulfide C3

- v0 1.48E

- 01 1.43E

- 01 2.28E

- 01 7.39E

- 02 1 51.99 58.83 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 1.17E

- 06 6.70E

- 07 2.38E

- 06 4.12E

- 07 2 76.13 60.92 0.66 Naphthalene A3

- v0 2.89E

- 04 2.24E

- 04 5.54E

- 04 1.50E

- 04 2 56.04 44.84 1.00 Phenanthrene A3

- v0 1.64E

- 05 1.21E

- 05 3.17E

- 05 6.59E

- 06 2 64.15 51.33 1.00 Propylene C2

- v1 1.83E

- 01 7.80E

- 02 6. 30E

- 01 6.71E

- 03 4 117.13 66.27 0.72 Pyrene A3

- v1 6.00E

- 06 2.78E

- 06 1.74E

- 05 8.19E

- 07 2 109.69 87.77 1.00 Toluene B1

- v0 1.37E

- 02 9.47E

- 03 3.08E

- 02 7.33E

- 03 5 59.41 30.07 0.64 Xylene (Total) B1

- v0 1.85E

- 02 1.70E

- 02 4.03E

- 02 1.11E

- 02 5 36.66 1 8.55 0.23

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-53 Table D-21b. Summary of Data for Emission Factor Development
– Steam Generators Firing Natural Gas and Casing Vapor Recovery Gas

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximu m Minimum Acenaphthene A3

- v0 1.06E

- 09 7.84E

- 10 2.34E

- 09 4.06E

- 10 2 65.71 52.57 0.72 Acenaphthylene A3

- v1 2.69E

- 09 7.14E

- 10 1.01E

- 08 4.06E

- 10 2 142.14 113.73 0.85 Acetaldehyde A2

- v0 1.85E

- 05 1.68E

- 05 4.88E

- 05 5.47E

- 06 4 66.12 37.41 0.84 Acrolein A2

- v0 1.69E

- 05 1.92E

- 05 2.62E

- 05 5.47E

- 06 4 41.86 23.68 0.88 Anthracene A3

- v1 2.18E

- 09 2.33E

- 09 4.26E

- 09 4.06E

- 10 2 64.55 51.65 0.97 Benzene B1

- v0 4.45E

- 06 4.40E

- 06 6.12E

- 06 2.75E

- 06 5 23.61 11.95 0.00 Benzo(a)anthracene A3

- v0 1.28 E

- 09 1.12E

- 09 2.42E

- 09 7.12E

- 10 2 45.67 36.54 0.45 Benzo(a)pyrene A3

- v0 7.08E

- 10 7.11E

- 10 1.31E

- 09 3.92E

- 10 2 47.05 37.64 0.32 Benzo(b)fluoranthene A3

- v0 2.01E

- 09 9.26E

- 10 4.71E

- 09 7.10E

- 10 2 92.63 74.12 0.84 Benzo(g,h,i)perylene A3

- v0 9.98E

- 10 7.14E

- 10 1.73E

- 09 4.06E

- 10 2 57.41 45.93 0.59 Benzo(k)fluoranthene A3

- v0 8.41E

- 10 7.14E

- 10 1.37E

- 09 4.06E

- 10 2 41.36 33.09 0.52 Chrysene A3

- v0 1.60E

- 09 1.80E

- 09 2.42E

- 09 7.12E

- 10 2 39.17 31.35 0.33 Dibenz(a,h)anthracene A3

- v0 5.54E

- 10 5. 58E

- 10 7.15E

- 10 3.90E

- 10 2 31.29 25.04 0.00 Ethylbenzene A3

- v0 9.63E

- 06 7.23E

- 06 2.02E

- 05 4.02E

- 06 2 59.81 47.86 0.54 Fluoranthene A3

- v0 3.67E

- 09 1.78E

- 09 8.90E

- 09 1.07E

- 09 2 95.56 76.46 1.00 Fluorene A3

- v0 5.66E

- 09 2.64E

- 09 1.28E

- 08 1.85E

- 0 9 2 92.16 73.74 1.00 Formaldehyde A2

- v1 2.53E

- 05 1.56E

- 05 1.01E

- 04 5.47E

- 06 4 111.34 63.00 0.70 Hydrogen Sulfide C3

- v0 1.59E

- 04 1.60E

- 04 2.38E

- 04 8.02E

- 05 1 49.59 56.11 1.00 Indeno(1,2,3

- cd)pyrene A3

- v0 1.18E

- 09 7.14E

- 10 2.34E

- 09 4.06E

- 10 2 72.24 57.80 0.66 Naphthalene A3

- v0 2.93E

- 07 2.33E

- 07 5.46E

- 07 1.57E

- 07 2 52.01 41.62 1.00 Phenanthrene A3

- v0 1.68E

- 08 1.34E

- 08 3.12E

- 08 6.50E

- 09 2 60.61 48.50 1.00 Propylene C2

- v1 2.29E

- 04 1.27E

- 04 6.83E

- 04 1.23E

- 05 4 94.36 53.39 0.72 Py rene A3

- v1 6.02E

- 09 2.93E

- 09 1.72E

- 08 8.55E

- 10 2 106.75 85.42 1.00 Toluene B1

- v0 1.73E

- 05 1.43E

- 05 3.04E

- 05 1.34E

- 05 5 33.16 16.78 0.64 Xylene (Total) B1

- v0 2.66E

- 05 3.11E

- 05 4.36E

- 05 1.21E

- 05 5 36.70 18.57 0.23

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-54 Table D-22a. Summary of Data for Emission Factor Development
– Turbines with No Duct Burners Firing Natural Gas

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 3.39E

- 06 2.11E

- 06 8.87E

- 0 6 1.26E

- 06 2 88.62 70.91 0.67 Acenaphthylene A3

- v0 3.00E

- 06 2.87E

- 06 5.78E

- 06 1.26E

- 06 2 56.64 45.32 0.54 Acetaldehyde A3

- v0 3.96E

- 02 4.76E

- 02 5.38E

- 02 1.73E

- 02 1 49.40 55.90 0.85 Acrolein A3

- v0 1.81E

- 02 1.81E

- 02 1.82E

- 02 1.79E

- 02 1 0.68 0. 77 0.00 Anthracene A3

- v1 3.52E

- 05 7.45E

- 06 1.53E

- 04 3.77E

- 06 2 167.76 134.23 1.00 Benzene A3

- v0 1.24E

- 02 1.23E

- 02 1.85E

- 02 6.96E

- 03 2 47.07 37.67 0.00 Benzo(a)anthracene A3

- v0 2.89E

- 06 2.39E

- 06 5.89E

- 06 1.84E

- 06 2 53.67 42.94 0.34 Benzo(a )pyrene A3

- v0 2.13E

- 06 2.09E

- 06 3.17E

- 06 1.26E

- 06 2 43.24 34.60 0.00 Benzo(b)fluoranthene A3

- v0 3.40E

- 06 2.87E

- 06 8.93E

- 06 1.26E

- 06 2 83.26 66.62 0.44 Benzo(g,h,i)perylene A3

- v0 2.47E

- 06 2.87E

- 06 3.31E

- 06 1.26E

- 06 2 37.62 30.10 0.22 Benzo(k) fluoranthene A3

- v0 2.67E

- 06 2.87E

- 06 4.54E

- 06 1.26E

- 06 2 46.39 37.12 0.28 Chrysene A3

- v0 5.08E

- 06 5.99E

- 06 6.34E

- 06 2.89E

- 06 2 31.73 25.39 0.31 Dibenz(a,h)anthracene A3

- v0 2.13E

- 06 2.09E

- 06 3.17E

- 06 1.26E

- 06 2 43.24 34.60 0.00 Ethylbenzene A3

- v0 1.53E

- 02 1.52E

- 02 2.20E

- 02 9.49E

- 03 2 40.90 32.72 0.00 Fluoranthene A3

- v0 1.20E

- 05 1.21E

- 05 1.74E

- 05 5.78E

- 06 2 36.16 28.93 1.00 Fluorene A3

- v0 1.55E

- 05 1.42E

- 05 3.17E

- 05 8.05E

- 06 2 54.85 43.89 1.00 Formaldehyde A3

- v0 2.09E

- 02 1.73E

- 02 2.81E

- 02 1.73E

- 02 1 29.80 33.72 0.45 Indeno(1,2,3

- cd)pyrene A3

- v0 2.38E

- 06 2.82E

- 06 3.17E

- 06 1.26E

- 06 2 35.90 28.73 0.20 Naphthalene A3

- v0 7.51E

- 04 8.01E

- 04 9.51E

- 04 4.56E

- 04 2 28.73 22.99 1.00 Phenanthrene A3

- v0 6.71E

- 05 4.95E

- 05 1.46E

- 04 2.62E

- 05 2 64.08 51.28 1.00 Propylene A3

- v0 1.71E+00 1.68E+00 2.00E+00 1.46E+00 1 15.66 17.72 1.00 Pyrene A3

- v0 2.31E

- 05 2.09E

- 05 4.23E

- 05 5.78E

- 06 2 63.17 50.55 1.00 Toluene A3

- v1 7.17E

- 02 5.89E

- 02 1.68E

- 01 8.22E

- 03 2 88.92 71.15 0.98 X ylene (Total) A3

- v0 3.63E

- 02 4.11E

- 02 6.26E

- 02 9.70E

- 03 2 52.17 41.75 0.38

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-55 Table D-22b. Summary of Data for Emission Factor Development
– Turbines with No Duct Burners Firing Natural Gas

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 3.25E

- 09 2.03E

- 09 8.46E

- 09 1.23E

- 09 2 87.69 70.16 0.67 Acenaphthylene A3

- v0 2.90E

- 09 2.74E

- 09 5.67E

- 09 1.23E

- 09 2 57.20 45.77 0.54 Acetaldehyde A3

- v0 3.78E

- 05 4. 55E

- 05 5.14E

- 05 1.65E

- 05 1 49.40 55.90 0.85 Acrolein A3

- v0 1.72E

- 05 1.73E

- 05 1.73E

- 05 1.71E

- 05 1 0.68 0.77 0.00 Anthracene A3

- v1 3.43E

- 08 7.19E

- 09 1.50E

- 07 3.70E

- 09 2 168.94 135.17 1.00 Benzene A3

- v0 1.20E

- 05 1.19E

- 05 1.82E

- 05 6.64E

- 06 2 48. 32 38.66 0.00 Benzo(a)anthracene A3

- v0 2.78E

- 09 2.31E

- 09 5.62E

- 09 1.80E

- 09 2 52.46 41.98 0.34 Benzo(a)pyrene A3

- v0 2.05E

- 09 2.01E

- 09 3.02E

- 09 1.23E

- 09 2 41.94 33.56 0.00 Benzo(b)fluoranthene A3

- v0 3.30E

- 09 2.74E

- 09 8.77E

- 09 1.23E

- 09 2 84.51 67.62 0.44 Benzo(g,h,i)perylene A3

- v0 2.38E

- 09 2.74E

- 09 3.25E

- 09 1.23E

- 09 2 37.17 29.74 0.22 Benzo(k)fluoranthene A3

- v0 2.58E

- 09 2.74E

- 09 4.46E

- 09 1.23E

- 09 2 46.68 37.35 0.28 Chrysene A3

- v0 4.93E

- 09 5.88E

- 09 6.05E

- 09 2.76E

- 09 2 32.43 25.95 0.31 Dibenz(a,h)anthracene A3

- v0 2.05E

- 09 2.01E

- 09 3.02E

- 09 1.23E

- 09 2 41.94 33.56 0.00 Ethylbenzene A3

- v0 1.49E

- 05 1.48E

- 05 2.16E

- 05 9.05E

- 06 2 42.21 33.78 0.00 Fluoranthene A3

- v0 1.16E

- 08 1.16E

- 08 1.71E

- 08 5.51E

- 09 2 36.82 29.47 1.00 Fl uorene A3

- v0 1.49E

- 08 1.40E

- 08 3.02E

- 08 7.90E

- 09 2 53.86 43.09 1.00 Formaldehyde A3

- v0 1.99E

- 05 1.65E

- 05 2.68E

- 05 1.65E

- 05 1 29.80 33.72 0.45 Indeno(1,2,3

- cd)pyrene A3

- v0 2.29E

- 09 2.73E

- 09 3.02E

- 09 1.23E

- 09 2 35.08 28.07 0.20 Naphthalene A3

- v0 7.29E

- 07 7.77E

- 07 9.33E

- 07 4.35E

- 07 2 30.01 24.02 1.00 Phenanthrene A3

- v0 6.46E

- 08 4.86E

- 08 1.39E

- 07 2.57E

- 08 2 62.98 50.39 1.00 Propylene A3

- v0 1.63E

- 03 1.61E

- 03 1.90E

- 03 1.39E

- 03 1 15.66 17.72 1.00 Pyrene A3

- v0 2.25E

- 08 2.03E

- 08 4.15E

- 08 5.51E

- 09 2 64.16 51.34 1.00 Toluene A3

- v1 7.01E

- 05 5.75E

- 05 1.65E

- 04 7.85E

- 06 2 89.58 71.67 0.98 Xylene (Total) A3

- v0 3.52E

- 05 4.04E

- 05 5.97E

- 05 9.25E

- 06 2 51.95 41.57 0.38

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-56 Table D-23a. Summary of Data for Emission Factor Development
– Turbines with No Duct Burners Firing Natural Gas Controlled with Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 3.39E

- 06 2.11E

- 06 8.87E

- 06 1.26E

- 06 2 88.62 70.91 0.67 Acenaphthylene A3

- v0 3.00E

- 06 2.87E

- 06 5.78E

- 06 1.26E

- 06 2 56.64 45.32 0.54 Acetaldehyde A3

- v0 3.96E

- 02 4.76E

- 02 5.38E

- 02 1.73E

- 02 1 49.40 55.90 0.85 Acrolein A3

- v 0 1.81E

- 02 1.81E

- 02 1.82E

- 02 1.79E

- 02 1 0.68 0.77 0.00 Anthracene A3

- v1 3.52E

- 05 7.45E

- 06 1.53E

- 04 3.77E

- 06 2 167.76 134.23 1.00 Benzene A3

- v0 1.24E

- 02 1.23E

- 02 1.85E

- 02 6.96E

- 03 2 47.07 37.67 0.00 Benzo(a)anthracene A3

- v0 2.89E

- 06 2.39E

- 06 5.89E

- 06 1.84E

- 06 2 53.67 42.94 0.34 Benzo(a)pyrene A3

- v0 2.13E

- 06 2.09E

- 06 3.17E

- 06 1.26E

- 06 2 43.24 34.60 0.00 Benzo(b)fluoranthene A3

- v0 3.40E

- 06 2.87E

- 06 8.93E

- 06 1.26E

- 06 2 83.26 66.62 0.44 Benzo(g,h,i)perylene A3

- v0 2.47E

- 06 2.87E

- 06 3 .31E

- 06 1.26E

- 06 2 37.62 30.10 0.22 Benzo(k)fluoranthene A3

- v0 2.67E

- 06 2.87E

- 06 4.54E

- 06 1.26E

- 06 2 46.39 37.12 0.28 Chrysene A3

- v0 5.08E

- 06 5.99E

- 06 6.34E

- 06 2.89E

- 06 2 31.73 25.39 0.31 Dibenz(a,h)anthracene A3

- v0 2.13E

- 06 2.09E

- 06 3.17E

- 0 6 1.26E

- 06 2 43.24 34.60 0.00 Ethylbenzene A3

- v0 1.53E

- 02 1.52E

- 02 2.20E

- 02 9.49E

- 03 2 40.90 32.72 0.00 Fluoranthene A3

- v0 1.20E

- 05 1.21E

- 05 1.74E

- 05 5.78E

- 06 2 36.16 28.93 1.00 Fluorene A3

- v0 1.55E

- 05 1.42E

- 05 3.17E

- 05 8.05E

- 06 2 54.85 43. 89 1.00 Formaldehyde A3

- v0 2.09E

- 02 1.73E

- 02 2.81E

- 02 1.73E

- 02 1 29.80 33.72 0.45 Indeno(1,2,3

- cd)pyrene A3

- v0 2.38E

- 06 2.82E

- 06 3.17E

- 06 1.26E

- 06 2 35.90 28.73 0.20 Naphthalene A3

- v0 7.51E

- 04 8.01E

- 04 9.51E

- 04 4.56E

- 04 2 28.73 22.99 1.00 Phenanthrene A3

- v0 6.71E

- 05 4.95E

- 05 1.46E

- 04 2.62E

- 05 2 64.08 51.28 1.00 Propylene A3

- v0 1.71E+00 1.68E+00 2.00E+00 1.46E+00 1 15.66 17.72 1.00 Pyrene A3

- v0 2.31E

- 05 2.09E

- 05 4.23E

- 05 5.78E

- 06 2 63.17 50.55 1.00 Toluene A3

- v1 7.17E

- 02 5.8 9E

- 02 1.68E

- 01 8.22E

- 03 2 88.92 71.15 0.98 Xylene (Total) A3

- v0 3.63E

- 02 4.11E

- 02 6.26E

- 02 9.70E

- 03 2 52.17 41.75 0.38

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-57 Table D-23b. Summary of Data for Emission Factor Development
– Turbines with No Duct Burners Firing Natural Gas Controlled with Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene A3

- v0 3.25E

- 09 2.03E

- 09 8.46E

- 09 1.23E

- 09 2 87.69 70.16 0.67 Acenaphthylene A3

- v0 2.90E

- 09 2.74E

- 09 5.67E

- 09 1.23E

- 09 2 57.20 45.77 0.54 Acetaldehyde A3

- v0 3.78E

- 05 4.55E

- 05 5.14E

- 05 1.65E

- 05 1 49.40 55.90 0.85 Acrolein A3

- v0 1.72E

- 05 1.73E

- 05 1.73E

- 05 1.71E

- 05 1 0.68 0.77 0.00 An thracene A3

- v1 3.43E

- 08 7.19E

- 09 1.50E

- 07 3.70E

- 09 2 168.94 135.17 1.00 Benzene A3

- v0 1.20E

- 05 1.19E

- 05 1.82E

- 05 6.64E

- 06 2 48.32 38.66 0.00 Benzo(a)anthracene A3

- v0 2.78E

- 09 2.31E

- 09 5.62E

- 09 1.80E

- 09 2 52.46 41.98 0.34 Benzo(a)pyrene A3

- v 0 2.05E

- 09 2.01E

- 09 3.02E

- 09 1.23E

- 09 2 41.94 33.56 0.00 Benzo(b)fluoranthene A3

- v0 3.30E

- 09 2.74E

- 09 8.77E

- 09 1.23E

- 09 2 84.51 67.62 0.44 Benzo(g,h,i)perylene A3

- v0 2.38E

- 09 2.74E

- 09 3.25E

- 09 1.23E

- 09 2 37.17 29.74 0.22 Benzo(k)fluoranthene A3

- v0 2.58E

- 09 2.74E

- 09 4.46E

- 09 1.23E

- 09 2 46.68 37.35 0.28 Chrysene A3

- v0 4.93E

- 09 5.88E

- 09 6.05E

- 09 2.76E

- 09 2 32.43 25.95 0.31 Dibenz(a,h)anthracene A3

- v0 2.05E

- 09 2.01E

- 09 3.02E

- 09 1.23E

- 09 2 41.94 33.56 0.00 Ethylbenzene A3

- v0 1.49E

- 0 5 1.48E

- 05 2.16E

- 05 9.05E

- 06 2 42.21 33.78 0.00 Fluoranthene A3

- v0 1.16E

- 08 1.16E

- 08 1.71E

- 08 5.51E

- 09 2 36.82 29.47 1.00 Fluorene A3

- v0 1.49E

- 08 1.40E

- 08 3.02E

- 08 7.90E

- 09 2 53.86 43.09 1.00 Formaldehyde A3

- v0 1.99E

- 05 1.65E

- 05 2.68E

- 05 1.6 5E

- 05 1 29.80 33.72 0.45 Indeno(1,2,3

- cd)pyrene A3

- v0 2.29E

- 09 2.73E

- 09 3.02E

- 09 1.23E

- 09 2 35.08 28.07 0.20 Naphthalene A3

- v0 7.29E

- 07 7.77E

- 07 9.33E

- 07 4.35E

- 07 2 30.01 24.02 1.00 Phenanthrene A3

- v0 6.46E

- 08 4.86E

- 08 1.39E

- 07 2.57E

- 08 2 62 .98 50.39 1.00 Propylene A3

- v0 1.63E

- 03 1.61E

- 03 1.90E

- 03 1.39E

- 03 1 15.66 17.72 1.00 Pyrene A3

- v0 2.25E

- 08 2.03E

- 08 4.15E

- 08 5.51E

- 09 2 64.16 51.34 1.00 Toluene A3

- v1 7.01E

- 05 5.75E

- 05 1.65E

- 04 7.85E

- 06 2 89.58 71.67 0.98 Xylene (Total) A3

- v0 3.52E

- 05 4.04E

- 05 5.97E

- 05 9.25E

- 06 2 51.95 41.57 0.38

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-58 Table D-24a. Summary of Data for Emission Factor Development
– Turbines with Duct Burners

Firing Natural Gas Controlled with Selective Catalytic Reduction

Substance CARB

Rating Emission F actor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Formaldehyde C3

- v0 6.22E+00 6.09E+00 6.87E+00 5.71E+00 1 9.57 10.83 1.00



### Table D-24b. Summary of Data for Emission Factor Development
– Turbines with Duct Burners

Firing Natural Gas Controlled with Selective Catalytic Reduction

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Formaldehyde C3

- v0 6.02E

- 03 5.89E

- 03 6.65E

- 03 5.52E

- 03 1 9. 57 10.83 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-59 Table D-25a. Summary of Data for Emission Factor Development
– Turbines with Duct Burners Firing Natural Gas and Refinery Fuel Gas Controlled with Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating E mission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v0 2.37E

- 05 2.15E

- 05 3.82E

- 05 1.15E

- 05 1 56.84 64.32 1.00 Acenaphthylene C3

- v0 1.15E

- 05 1.29E

- 05 1.32E

- 05 8.53E

- 06 1 22.70 25.68 1.00 Acetaldehyde A3

- v0 4.54E

- 03 3.41E

- 03 6.83E

- 03 3.38E

- 03 1 43.72 49.48 1.00 Anthracene C3

- v0 2.66E

- 05 2.43E

- 05 3.66E

- 05 1.89E

- 05 1 34.03 38.51 1.00 Benzene C3

- v0 1.66E

- 01 1.68E

- 01 1.81E

- 01 1.46E

- 01 2 9.66 7.73 0.00 Benzo(a)anthracene C 3

- v1 1.60E

- 05 3.47E

- 06 4.15E

- 05 3.03E

- 06 1 138.05 156.22 0.86 Benzo(a)pyrene C3

- v0 1.02E

- 05 1.05E

- 05 1.36E

- 05 6.63E

- 06 1 34.09 38.57 0.00 Benzo(b)fluoranthene C3

- v0 2.69E

- 05 3.19E

- 05 3.44E

- 05 1.45E

- 05 1 40.14 45.42 0.82 Benzo(g,h,i)perylene C3

- v0 2.06E

- 05 2.00E

- 05 2.71E

- 05 1.45E

- 05 1 30.62 34.65 0.00 Benzo(k)fluoranthene C3

- v0 1.34E

- 05 1.21E

- 05 2.00E

- 05 8.05E

- 06 1 45.53 51.52 0.00 Cadmium C3

- v0 2.08E

- 03 1.06E

- 03 4.16E

- 03 1.03E

- 03 1 86.47 97.85 0.67 Chromium (Hex) C3

- v0 7.46E

- 03 7.08E

- 03 1.50E

- 02 1.53E

- 03 2 83.96 67.18 0.00 Chromium (Total) C3

- v1 5.35E

- 02 3.36E

- 02 1.84E

- 01 1.51E

- 02 2 121.46 97.19 1.00 Chrysene C3

- v0 1.16E

- 04 6.85E

- 05 2.43E

- 04 3.47E

- 05 1 96.95 109.70 1.00 Copper A3

- v0 1.89E

- 03 1.98E

- 03 2.64E

- 03 1.04 E

- 03 1 42.72 48.34 1.00 Dibenz(a,h)anthracene C3

- v0 7.10E

- 06 8.12E

- 06 8.59E

- 06 4.58E

- 06 1 30.92 34.99 0.00 Fluoranthene C3

- v0 1.06E

- 04 1.07E

- 04 1.58E

- 04 5.53E

- 05 1 48.01 54.33 1.00 Fluorene C3

- v1 1.90E

- 04 8.02E

- 05 4.46E

- 04 4.26E

- 05 1 117.53 132.99 1.00 Formaldehyde A3

- v0 1.71E

- 01 9.23E

- 02 3.42E

- 01 7.76E

- 02 1 87.01 98.46 1.00 Hydrogen Sulfide A3

- v0 1.65E

- 01 1.64E

- 01 1.72E

- 01 1.59E

- 01 1 4.20 4.76 0.00 Indeno(1,2,3

- cd)pyrene C3

- v0 9.83E

- 06 1.06E

- 05 1.18E

- 05 7.10E

- 06 1 24.76 28.02 0.00 Manganese A3

- v0 3.49E

- 03 2.36E

- 03 6.79E

- 03 1.32E

- 03 1 83.26 94.21 1.00 Mercury A3

- v0 4.63E

- 03 4.01E

- 03 8.27E

- 03 2.55E

- 03 2 51.31 41.05 1.00 Naphthalene C3

- v0 4.02E

- 02 3.98E

- 02 4.30E

- 02 3.79E

- 02 1 6.36 7.20 1.00 Nickel C3

- v0 8.18E

- 0 3 6.79E

- 03 1.43E

- 02 3.40E

- 03 1 68.51 77.52 1.00 Phenanthrene C3

- v0 6.85E

- 04 5.53E

- 04 9.72E

- 04 5.30E

- 04 1 36.34 41.12 1.00 Phenol C3

- v0 1.53E

- 02 1.58E

- 02 1.59E

- 02 1.43E

- 02 1 5.81 6.57 0.00 Pyrene C3

- v0 1.28E

- 04 1.04E

- 04 2.29E

- 04 5.21E

- 05 1 71 .00 80.34 1.00 Toluene E3

- v0 1.79E

- 01 1.78E

- 01 1.87E

- 01 1.72E

- 01 1 4.37 4.94 0.00 Xylene (Total) E3

- v0 4.13E

- 01 4.14E

- 01 4.15E

- 01 4.11E

- 01 1 0.50 0.56 0.00 Zinc A3

- v0 1.65E

- 02 1.56E

- 02 1.93E

- 02 1.45E

- 02 1 15.37 17.39 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-60 Table D-25b. Summary of Data for Emission Factor Development
– Turbines with Duct Burners Firing Natural Gas and Refinery Fuel Gas Controlled with Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acenaphthene C3

- v0 2.21E

- 08 2.00E

- 08 3.55E

- 08 1.07E

- 08 1 56.84 64.32 1.00 Acenaphthylene C3

- v0 1.07E

- 08 1.20E

- 08 1.23E

- 08 7.93E

- 09 1 22.70 25.68 1.00 Acetaldehyde A3

- v0 4.1 1E

- 06 3.09E

- 06 6.18E

- 06 3.06E

- 06 1 43.68 49.43 1.00 Anthracene C3

- v0 2.48E

- 08 2.26E

- 08 3.41E

- 08 1.76E

- 08 1 34.03 38.51 1.00 Benzene C3

- v0 1.52E

- 04 1.54E

- 04 1.69E

- 04 1.32E

- 04 2 11.10 8.88 0.00 Benzo(a)anthracene C3

- v1 1.49E

- 08 3.23E

- 09 3.86E

- 08 2.81E

- 09 1 138.05 156.22 0.86 Benzo(a)pyrene C3

- v0 9.53E

- 09 9.78E

- 09 1.26E

- 08 6.17E

- 09 1 34.09 38.57 0.00 Benzo(b)fluoranthene C3

- v0 2.50E

- 08 2.96E

- 08 3.20E

- 08 1.35E

- 08 1 40.14 45.42 0.82 Benzo(g,h,i)perylene C3

- v0 1.91E

- 08 1.86E

- 08 2.52E

- 08 1.35E

- 08 1 30.62 34.65 0.00 Benzo(k)fluoranthene C3

- v0 1.25E

- 08 1.13E

- 08 1.86E

- 08 7.49E

- 09 1 45.53 51.52 0.00 Cadmium C3

- v0 1.94E

- 06 9.84E

- 07 3.87E

- 06 9.55E

- 07 1 86.47 97.85 0.67 Chromium (Hex) C3

- v0 6.95E

- 06 6.60E

- 06 1.39E

- 05 1.45E

- 06 2 83.59 66.88 0.00 Chromium (Total) C3

- v1 4.99E

- 05 3.15E

- 05 1.71E

- 04 1.43E

- 05 2 120.88 96.72 1.00 Chrysene C3

- v0 1.07E

- 07 6.37E

- 08 2.26E

- 07 3.23E

- 08 1 96.95 109.70 1.00 Copper A3

- v0 1.75E

- 06 1.84E

- 06 2.46E

- 06 9.65E

- 07 1 42.72 48.34 1.00 D ibenz(a,h)anthracene C3

- v0 6.60E

- 09 7.55E

- 09 7.99E

- 09 4.26E

- 09 1 30.92 34.99 0.00 Fluoranthene C3

- v0 9.90E

- 08 9.92E

- 08 1.46E

- 07 5.14E

- 08 1 48.01 54.33 1.00 Fluorene C3

- v1 1.76E

- 07 7.46E

- 08 4.15E

- 07 3.96E

- 08 1 117.53 132.99 1.00 Formaldehyde A3

- v0 1.54E

- 04 8.36E

- 05 3.09E

- 04 7.03E

- 05 1 86.98 98.42 1.00 Hydrogen Sulfide A3

- v0 1.50E

- 04 1.49E

- 04 1.56E

- 04 1.44E

- 04 1 4.30 4.86 0.00 Indeno(1,2,3

- cd)pyrene C3

- v0 9.14E

- 09 9.85E

- 09 1.10E

- 08 6.61E

- 09 1 24.76 28.02 0.00 Manganese A3

- v0 3.2 5E

- 06 2.19E

- 06 6.32E

- 06 1.23E

- 06 1 83.26 94.21 1.00 Mercury A3

- v0 4.35E

- 06 3.73E

- 06 7.82E

- 06 2.37E

- 06 2 51.85 41.49 1.00 Naphthalene C3

- v0 3.74E

- 05 3.70E

- 05 3.99E

- 05 3.52E

- 05 1 6.36 7.20 1.00 Nickel C3

- v0 7.60E

- 06 6.32E

- 06 1.33E

- 05 3.16E

- 06 1 68.51 77.52 1.00 Phenanthrene C3

- v0 6.37E

- 07 5.14E

- 07 9.03E

- 07 4.93E

- 07 1 36.34 41.12 1.00 Phenol C3

- v0 1.43E

- 05 1.47E

- 05 1.48E

- 05 1.33E

- 05 1 5.81 6.57 0.00 Pyrene C3

- v0 1.19E

- 07 9.63E

- 08 2.13E

- 07 4.84E

- 08 1 71.00 80.34 1.00 Toluene E 3

- v0 1.62E

- 04 1.61E

- 04 1.69E

- 04 1.55E

- 04 1 4.30 4.87 0.00 Xylene (Total) E3

- v0 3.74E

- 04 3.76E

- 04 3.76E

- 04 3.72E

- 04 1 0.55 0.63 0.00 Zinc A3

- v0 1.53E

- 05 1.45E

- 05 1.80E

- 05 1.35E

- 05 1 15.37 17.39 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-61 Table D-26a. Summary of Data for Emission F ac tor Development
– Turbines with Duct Burners Firing Natural Gas, Refinery Fuel Gas, and Liquefied Petroleum Gas Controlled with Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD , % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Arsenic B3

- v0 1.70E

- 02 1.71E

- 02 1.79E

- 02 1.61E

- 02 1 5.27 5.96 0.00 Beryllium B3

- v0 3.40E

- 03 3.43E

- 03 3.57E

- 03 3.21E

- 03 1 5.28 5.97 0.00 Cadmium B3

- v0 7.41E

- 03 6.85E

- 03 8.94E

- 03 6.44E

- 03 1 18.06 20.43 0.40 Copper B3

- v0 4.08E

- 02 1.88E

- 02 8.74E

- 02 1.61E

- 02 1 99.07 112.11 0.87 Lead B3

- v0 6.82E

- 02 6.85E

- 02 7.16E

- 02 6.44E

- 02 1 5.25 5.94 0.00 Manganese B3

- v0 1.75E

- 01 9.89E

- 02 3.71E

- 01 5.58E

- 02 1 97.56 110.40 1.00 Nic kel B3

- v0 2.78E

- 01 9.70E

- 02 6.60E

- 01 7.79E

- 02 1 118.86 134.50 1.00 Phenol C3

- v1 5.80E

- 02 2.31E

- 02 1.45E

- 01 5.55E

- 03 1 131.32 148.60 1.00 Selenium B3

- v0 1.70E

- 02 1.71E

- 02 1.79E

- 02 1.61E

- 02 1 5.27 5.96 0.00 Zinc B3

- v0 4.12E

- 01 4.08E

- 01 6.80E

- 01 1.47E

- 01 1 64.69 73.20 1.00



### Table D-26b. Summary of Data for Emission Factor Development
– Turbines with Duct Burners Firing Natural Gas, Refinery Fuel Gas, and Liquefied Petroleum Gas Controlled with Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Arsenic B3

- v0 8.95E

- 06 9.00E

- 06 9.40E

- 06 8.46E

- 06 1 5.25 5.94 0.00 Beryllium B3

- v0 1.79E

- 06 1.80E

- 06 1.88E

- 06 1.69E

- 06 1 5.26 5.95 0.00 Cadmium B3

- v0 3.89E

- 06 3.60E

- 06 4.70E

- 06 3.39E

- 06 1 18.07 20.45 0.40 Copper B3

- v0 2.14E

- 05 9.89E

- 06 4.59E

- 05 8.46E

- 06 1 99.09 112.13 0.87 Lead B3

- v0 3.58E

- 05 3.60E

- 05 3.76E

- 05 3.39E

- 05 1 5.23 5.92 0.00 Manganese B3

- v0 9.21E

- 05 5.20E

- 05 1.95E

- 04 2.93E

- 05 1 97.60 110.45 1.00 Nickel B3

- v0 1.46E

- 04 5.09E

- 05 3.47E

- 04 4.09E

- 05 1 118.88 134.52 1.00 Phenol C3

- v1 3.05E

- 05 1.21E

- 05 7.65E

- 05 2.91E

- 06 1 131.46 148.76 1.00 Selenium B3

- v0 8.95E

- 06 9.00 E

- 06 9.40E

- 06 8.46E

- 06 1 5.25 5.94 0.00 Zinc B3

- v0 2.16E

- 04 2.14E

- 04 3.58E

- 04 7.75E

- 05 1 64.70 73.22 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-62 Table D-27a. Summary of Data for Emission Factor Development
– Turbines with No Duct Burners

Firing Refinery Fuel Gas Controlled with Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating Emission Factor (lb/MMcf) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde C3

- v0 2.18E

- 02 2.22E

- 02 2.65E

- 02 1.67E

- 02 1 22.53 25.49 1.00 Arsenic B3

- v0 4.09E

- 03 4.15E

- 03 4.18E

- 03 3.95E

- 03 1 3.09 3.49 0.00 Benzene C3

- v0 1.49E

- 01 1.51E

- 01 1.53E

- 01 1.44E

- 01 1 3.34 3.78 0.00 Beryllium B3

- v0 2.05E

- 03 2.08E

- 03 2.08E

- 03 1.98E

- 03 1 2.78 3.14 0.00 Cadmium B3

- v0 7.41E

- 03 5.21E

- 03 1.29E

- 02 4.15E

- 03 1 64.24 72.70 1.00 Chromium (Hex) C3

- v0 2.04E

- 03 2.04E

- 03 2.05E

- 03 2.02E

- 03 1 0.70 0.79 0.00 Chromium (Total) C3

- v0 1.84E

- 02 1.01E

- 02 3.93E

- 02 5.93E

- 03 1 98.65 111.63 0.82 Copper B3

- v0 5.78E

- 02 5.49E

- 02 9.72E

- 02 2.12E

- 02 1 65.90 74.57 1.00 Forma ldehyde C3

- v0 8.41E

- 01 8.36E

- 01 8.90E

- 01 7.97E

- 01 1 5.57 6.31 1.00 Hydrogen Sulfide A3

- v0 1.63E

- 01 1.64E

- 01 1.67E

- 01 1.58E

- 01 1 3.06 3.46 0.00 Lead B3

- v0 3.99E

- 02 4.15E

- 02 4.18E

- 02 3.64E

- 02 1 7.62 8.62 0.30 Manganese B3

- v0 1.80E

- 01 1.45E

- 01 3.40E

- 01 5.55E

- 02 1 80.76 91.39 1.00 Mercury A3

- v0 2.15E

- 02 1.55E

- 02 3.63E

- 02 1.27E

- 02 1 59.94 67.83 1.00 Nickel B3

- v0 2.33E

- 01 2.64E

- 01 2.86E

- 01 1.48E

- 01 1 31.93 36.13 1.00 Phenol C3

- v0 9.41E

- 03 5.99E

- 03 1.72E

- 02 5.07E

- 03 1 71.54 80.95 1 .00 Selenium B3

- v0 5.42E

- 03 4.18E

- 03 7.93E

- 03 4.15E

- 03 1 40.11 45.39 0.00 Toluene E3

- v1 1.09E+00 4.34E

- 01 2.58E+00 2.56E

- 01 1 118.63 134.23 1.00 Xylene (Total) E3

- v1 3.14E+00 3.39E

- 01 8.85E+00 2.33E

- 01 1 157.44 178.16 1.00 Zinc B3

- v0 6.99 E+00 8.23E+00 9.17E+00 3.56E+00 1 42.95 48.60 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-63 Table D-27b. Summary of Data for Emission Factor Development
– Turbines with No Duct Burners

Firing Refinery Fuel Gas Controlled with Carbon Monoxide Oxidation Catalyst

Substance CARB

Rating Emission Factor (lb/MMBtu) Tests RSD, % Uncer tainty, % Detect Ratio Mean Median Maximum Minimum Acetaldehyde C3

- v0 1.56E

- 05 1.58E

- 05 1.89E

- 05 1.19E

- 05 1 22.53 25.49 1.00 Arsenic B3

- v0 2.92E

- 06 2.96E

- 06 2.98E

- 06 2.81E

- 06 1 3.09 3.49 0.00 Benzene C3

- v0 1.06E

- 04 1.07E

- 04 1.09E

- 04 1.02E

- 04 1 3.34 3.78 0.00 Beryllium B3

- v0 1.46E

- 06 1.48E

- 06 1.49E

- 06 1.41E

- 06 1 2.78 3.14 0.00 Cadmium B3

- v0 5.28E

- 06 3.71E

- 06 9.18E

- 06 2.96E

- 06 1 64.24 72.70 1.00 Chromium (Hex) C3

- v0 1.45E

- 06 1.45E

- 06 1.46 E

- 06 1.44E

- 06 1 0.70 0.79 0.00 Chromium (Total) C3

- v0 1.31E

- 05 7.19E

- 06 2.80E

- 05 4.23E

- 06 1 98.65 111.63 0.82 Copper B3

- v0 4.12E

- 05 3.91E

- 05 6.93E

- 05 1.51E

- 05 1 65.90 74.57 1.00 Formaldehyde C3

- v0 5.99E

- 04 5.96E

- 04 6.34E

- 04 5.68E

- 04 1 5.57 6.31 1.00 Hydrogen Sulfide A3

- v0 1.16E

- 04 1.17E

- 04 1.19E

- 04 1.12E

- 04 1 3.06 3.46 0.00 Lead B3

- v0 2.84E

- 05 2.96E

- 05 2.98E

- 05 2.59E

- 05 1 7.62 8.62 0.30 Manganese B3

- v0 1.29E

- 04 1.03E

- 04 2.43E

- 04 3.96E

- 05 1 80.76 91.39 1.00 Mercury A3

- v0 1. 53E

- 05 1.11E

- 05 2.59E

- 05 9.05E

- 06 1 59.94 67.83 1.00 Nickel B3

- v0 1.66E

- 04 1.88E

- 04 2.04E

- 04 1.05E

- 04 1 31.93 36.13 1.00 Phenol C3

- v0 6.71E

- 06 4.27E

- 06 1.22E

- 05 3.62E

- 06 1 71.54 80.95 1.00 Selenium B3

- v0 3.86E

- 06 2.98E

- 06 5.65E

- 06 2.96E

- 06 1 40.11 45.39 0.00 Toluene E3

- v1 7.77E

- 04 3.10E

- 04 1.84E

- 03 1.83E

- 04 1 118.63 134.23 1.00 Xylene (Total) E3

- v1 2.24E

- 03 2.42E

- 04 6.31E

- 03 1.66E

- 04 1 157.44 178.16 1.00 Zinc B3

- v0 4.98E

- 03 5.87E

- 03 6.54E

- 03 2.54E

- 03 1 42.95 48.60 1.00

### Version 1.0

– Appendix D

— Emission Factors for Combustion Sources Review Draft

–

Do not cite or quote

D-64

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