## May 2011 

# Emission Estimation Protocol for Petroleum Refineries

Version 2.1.1 Final ICR Version – Corrected

Version 2.1: Final ICR Version

Form Approved: 03/28/2011 OMB Control No.: 2060-0657 Approval Expires: 03/31/2014

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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### Version 2.1.1 Final ICR Version – Corrected Table of Contents

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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 Rank 2 for Equipment Leaks.............................................................................. 2-3 2.2.1 Speciating Equipment Leak Emissions ....................................................................... 2-5 2.2.2 Calculating Hourly and Annual E quipment Leak Emissions ..................................... 2-7 2.3 Methodology Rank 3 for Equipment Leaks............................................................................ 2-10 2.3.1 Speciating Equipment Leak Emissions ..................................................................... 2-12 2.3.2 Calculating Hourly and Annual E quipment Leak Emissions ................................... 2-12 2.4 Methodology Ranks 4 and 5 for Equipment Leaks ................................................................ 2-13 2.4.1 Speciating Equipment Leak Emissions ..................................................................... 2-14 2.4.2 Calculating Hourly and Annual E quipment Leak Emissions ................................... 2-17
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 ................................................................................... 3-4
4. Stationary Combustion Sources ................................................................................................. ......... 4-1 4.1 Methodology Rank 1 for Stationa ry Combustion Sources ....................................................... 4-2 4.2 Methodology Rank 2 for Stationa ry Combustion Sources ....................................................... 4-5 4.3 Methodology Rank 3A for Stationa ry Combustion Sources .................................................... 4-9 4.4 Methodology Rank 3B for Stationa ry Combustion Sources .................................................. 4-10 4.5 Methodology Rank 4 for Stationa ry Combustion Sources ..................................................... 4-11 4.5.1 Default Emission Factors for Process Heaters .......................................................... 4-12 4.5.2 Default Emission Factor for Internal Combustion Engines ...................................... 4-18 4.5.3 Default Emission Factors for Combustion Turbines ................................................. 4-18
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 5.1.3 Methodology Rank 5A for CCU Metal HAP Emissions Estimates ............................ 5-7 5.1.4 Methodology Rank 5B for Catalytic Cracking Units ................................................ 5-10 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 ........................................................................................................ ... 5-17 5.5.1 Methodology Ranks 1 and 2 for Su lfur Recovery Plants .......................................... 5-17

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iv 5.5.2 Methodology Ranks 3 and 4 for Su lfur 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 ............................................................................................... 5-19 5.6.2 Asphalt Plant Vents ................................................................................................... 5-19 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 Wastewater Treatment Units ............................................................ 7-2 7.2 Methodology Rank 2 for Wastewater Treatment Units ............................................................ 7-2 7.2.1 Wastewater Collection Systems .................................................................................. 7-3 7.2.2 Primary Weirs ............................................................................................................. 7-5 7.2.3 Oil-Water Separators .................................................................................................. 7-5 7.2.4 Dissolved Air Flotation Units ..................................................................................... 7-6 7.2.5 Equalization Tanks ...................................................................................................... 7-6 7.2.6 Biological Treatment Units ......................................................................................... 7-6 7.2.7 Polishing Ponds ........................................................................................................... 7-8 7.2.8 Site-Specific Factors ................................................................................................... 7-8 7.2.9 Model Validation ........................................................................................................ 7-9 7.3 Methodology Rank 3 for Uncovered Units .............................................................................. 7-9 7.3.1 Engineering Estimates Based on Wastew ater Treatment Plant Load ......................... 7-9 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 ................................................................................ 8-8 8.3 Methodology Rank 4 for Cooling Towers .............................................................................. 8-10 8.4 Methodology Rank 5 for Cooling Towers .............................................................................. 8-11 8.4.1 VOC and Volatile Organic HAP ............................................................................... 8-12 8.4.2 Particulate Matter Emissions .................................................................................... 8-13 8.4.3 Non-volatile Organic HAP Emissions ...................................................................... 8-16 8.4.4 Chlorine Emissions ................................................................................................... 8-16

9. Loading Operations ............................................................................................................ ................. 9-1 9.1 Data Available on Product Co mposition and Properties .......................................................... 9-2 9.2 Methodology Rank 1 for Loading Operations .......................................................................... 9-2 9.3 Methodology Ranks 2 and 3 for Loading operations ............................................................... 9-3 9.4 Methodology Rank 4 for Loading operations ........................................................................... 9-4 9.4.1 AP-42 Emission Factors for “Product” or “Total Hydrocarbon” Emissions .............. 9-5 9.4.2 Estimate Uncontrolled Emissions and Speciate .......................................................... 9-6 9.4.3 Capture Efficiency ...................................................................................................... 9-6 9.4.4 Overall Control Efficiency .......................................................................................... 9-7

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v 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
12. Malfunctions/Upsets ........................................................................................................... ............... 12-1 12.1 Control Device Malfunctions ................................................................................................. 1 2-2 12.2 Vessel Overpr essurization ..................................................................................................... . 12-3 12.3 Spills ........................................................................................................................ ............... 12-6
13. References .................................................................................................................... ..................... 13-1

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## List of Figures Figure 2-1. Illustration of alternative methods to determine equipment leak emissions from routine monitoring data. ...................................................................................................... .......... 2-8 Figure 7-1. Typical refinery w astewater treatme nt system. ..................................................................... .. 7-1 Figure 7-2. Typical refinery wastewater collection system process drainage areas. ................................. 7-4 Figure 7-3. Simplified drawing of a constituent m ass balance in a biological treatment unit. .................. 7-7



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

### ........................... 2-4 Table 2-3. Screening Ranges Emission Factors a 

### ...................................................................................... 2-11 Table 2-4. Median Equipment Leak Component Counts for Small Model Processes a 

### ............................ 2-15 Table 2-5. Median Equipment Leak Component Counts for Large Model Processes a 

### ............................ 2-16 Table 2-6. Refinery and SOCMI Average Component Emission Factors a 

### .............................................. 2-17 Table 2-7. Concentration of HAP in Refinery Process Unit Streams a 

### ..................................................... 2-18 Table 3-1. Summary of Typical Hierarchy of Storage Tank Emission Estimates ..................................... 3-1 Table 3-2. Default Control Efficiencies for Different VOC Control Devices ........................................... 3-4 Table 4-1. Summary of Typical Hierarchy of Stat ionary Combustion Source Emission Estimates .......... 4-2 Table 4-2. Molar Exhaust Volumes and Molar Heat Content of Refinery Fuel Gas Constituents ............ 4-5 Table 4-3. Summary of Emission Factors for Boilers and Process Heaters Firing Various Fuels .......... 4-13 Table 4-4. Summary of Emission Factors for Internal Combustion Engines Firing Various Fuels a 

### ....... 4-19 Table 4-5. Summary of Emission Factors for Combustion Turbines Firing Various Fuels a 

### ................... 4-23 Table 5-1. Summary of Typical Hierarchy of Process Vent Emissions Estimates .................................... 5-1 Table 5-2. Default Size Distribution for Filterable PM from CCU ........................................................... 5-6 Table 5-3. Default Ratio of Me tal HAP Composition of CCU Fines a 

### ....................................................... 5-8 Table 5-4. Organic HAP Emissions Factors for CCU Catalyst Regenerator Vent .................................. 5-10 Table 5-5. Average Vent Concentrations and Emis sions Factors for Delayed Coking Unit Vents ......... 5-14 Table 5-6. Emissions Factors for CRU Catalyst Regeneration Vent ....................................................... 5-16 Table 5-7. Emissions Factors fo r Sulfur Recovery Plants ....................................................................... 5-18 Table 5-8. Emission Factors for Asphalt Blowing (U.S. EPA, 1995a) .................................................... 5-19 Table 5-9. Asphalt Blowing – Nonmethane Volatile Organic Compounds Speciation a 

### .......................... 5-20 Table 5-10. Summary of Emissions Factors for Controlled Asphalt Blowing ........................................ 5-20 Table 5-11. Summary of Emissions Factor s for Controlled Coke Calcining ........................................... 5-21 Table 5-12. Default Emissions Factors for Blowdown Systems .............................................................. 5-24 Table 5-13. Default Emissions Factor for Vacuum Producing Systems .................................................. 5-25 Table 6-1. Summary of Flare Emi ssions Estimate Methodologies ............................................................ 6-2 Table 6-2. Flare Energy Consumption-Based Emission Factors ............................................................... 6-5 Table 6-3. TCEQ Energy Consumption-Based Emission Factors for Flares ............................................. 6-5 Table 6-4. Emission Factors for Soot from Flares .............................................................................. ....... 6-6 Table 6-5. Flare General Emission Factors a 

### ............................................................................................... 6-8 Table 7-1. Summary of Wastewater Treatment Emission Estimates ......................................................... 7-2 Table 7-2. Critical Inputs and Chemical Proper ties Specific to Wastewater Collection System PDA Air Emission Calculations ................................................................................................. .. 7-5 Table 7-3. Critical Inputs, Variables, and Chemical Properties Specific to Primary Weir Air Emission Calculations ......................................................................................................... .......... 7-5

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vii Table 7-4. Critical Inputs, Variables, and Chemi cal Properties Specific to Oil-Water Separators Air Emission Calculations ..................................................................................................... ....... 7-5 Table 7-5. Critical Inputs, Variables, and Chemical Properties Specific to DAF Air Emission Calculations .................................................................................................................. ................ 7-6 Table 7-6. Critical Inputs, Variables, and Chemical Properties Specific to Equalization Tank Air Emission Calculations ......................................................................................................... .......... 7-6 Table 7-7. Critical Inputs, Variables, and Chemi cal Properties Specific to Biological Treatment Unit Air Emission Calculations ................................................................................................ .... 7-8 Table 7-8. Model Process Unit Characteristics for Petroleum Refinery Wastewater a 

### ............................. 7-10 Table 7-9. Refinery Wastewater Contaminant Concentrations as a Ratio to Benzene ............................ 7-10 Table 7-10. Default Mass Emission Factors for Refinery Wastewater Collection and Treatment Systems ....................................................................................................................... ................ 7-11 Table 8-1. Summary of Cooling Tower Emissions Estimation Methodologies ........................................ 8-2 Table 8-2. Data Requirements for VOC or Speci ated VOC Emissions, Methodology Ranks 1 and 2 ............................................................................................................................. ....................... 8-3 Table 8-3. Data Requirements for Speciated Compound Emissions, Methodology Rank 3 ..................... 8-9 Table 8-4. Data Requirements for Speciated Compound Emissions, Methodology Rank 4 ................... 8-11 Table 8-5. Methodology Rank 5 Default Emission Factors ..................................................................... 8- 11 Table 8-6. Data Requirements for VOC or Speci ated VOC Emissions, Methodology Rank 5 ............... 8-12 Table 9-1. Summary of Loading operations Emission Estimates .............................................................. 9-2 Table 9-2. Data Requirements for VOC or Speciated Emissions, Methodology Rank 1 or 2 ................... 9-3 Table 9-3. Saturation Factors a 

### .................................................................................................................... 9-5 Table 9-4. VOC Emission Factors for Marine Vess el Loading of Gasoline at Marine Terminals a 

### ........... 9-6 Table 9-5. Capture Efficiencies for Vapor Collection Systems a 

### ................................................................ 9-7 Table 9-6. Sample Calculation Methodology Rank 4—Summary of Emissions (When Property Data Are Not Available) ....................................................................................................... ...... 9-10 Table 10-1. Default Values for Fugitive Dust Emission Estimates ......................................................... 10-1 Table 12-1. Control Device Efficiency and Multiplier Factors for Control Device Malfunctions .......... 12-2

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### Version 2.1.1 Final ICR Version – Corrected List of Acronyms and Abbreviations

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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 barrels per calendar day bbl/sd barrels per stream day bbl/hr barrels per hour BID Background Information Document BOX test Batch test with oxygen addition (a type of aerated reactor test specified in Appendix C to 40 CFR Part 63) 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 CRU catalytic reforming 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 standard cubic feet per mole dscfm dry standard cubic feet per minute E-cat equilibrium catalyst EPA U.S. Environmental Protection Agency ESP electrostatic precipitator FCCU fluid catalytic cracking unit FCU fluid coking unit FID flame ionization detection g/hr grams per hour

### Version 2.1.1 Final ICR Version – Corrected List of Acronyms and Abbreviations

x 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 hazardous air pollutants HCl hydrogen chloride hepta-CDD heptachloro-dibenzo-p-dioxin Hg Mercury hr/yr hours per year IAF induced air flotation ICR information collection request 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 dry 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 LIDAR Light Detection and Ranging

m 3 

### /day cubic 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 million British thermal units per standard cubic foot MW molecular weight Ni Nickel

### Version 2.1.1 Final ICR Version – Corrected List of Acronyms and Abbreviations

xi 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-d ibenzo-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 filterable (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 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

### Version 2.1.1 Final ICR Version – Corrected List of Acronyms and Abbreviations

xii TDS total dissolved solids TEQ toxic equivalents THC total hydrocarbons TOC total organic compounds tons/hr tons per hour tons/kg tons per kilogram tons/yr tons per year VOC volatile organic compounds vol% volume percent WebFIRE Internet version of the Factor In formation Retrieval (FIRE) data system WF weight fraction WSPA Western States Petroleum Association wt% weight percent °C degrees Celsius °F degrees Fahrenheit °R degrees Rankine

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1-1 

# 1. Introduction This Refinery Emissions Protocol document is intende d to provide guidance and instructions to petroleum refinery owners and operators for the purpose of im proving emission inventorie s as collected through the U.S. Environmental Protection Agency’s (EPA’s) 2011 information collection request (ICR) for the petroleum refining industry. This document presents a hierarchy of emission measurement or estimation methods for various petroleum refinery emission s ources and provides a listing of pollutants for which emissions are anticipated for each source type.
For each emission source, the various emission measurement or 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 are requested to use the highest ranked method (with Methodology Rank 1 being the highest) for which data are available

. Methodology Ranks 1 or 2 generally rely on con tinuous emission measurements. When continuous measurement data are not available, engineeri ng calculations or site-specific emission factors (Methodology Ranks 3 and 4) are specified; these me thods generally need periodic, site-specific measurements. When site-specific measurement or test data are not available, default emission factors (Methodology Rank 5) are provided. Nothing in this Refinery Emissions Protocol document should be construed to require additional monito ring or testing by the petroleum refi nery owner or operator. Thus, if an emission source has continuous emission measuremen ts, these data should be used in developing the emission inventory for that source; however, this Refi nery Emissions Protocol document does not require the installation and use of continuous emission m easurement systems. When no measurement data are available, the emission factors provided in this Refi nery Emissions Protocol document should be used when developing emission estimates for reporting in response to the petroleum refinery ICR.
In the development of this Refinery Emissions Prot ocol document, EPA reviewed available source test data to verify or refine existing emission factor s and develop new emission factors for sources that currently do not have default emission factors. EPA also provided guidance on characterizing and quantifying emissions associated with start-up, s hut-down, and malfunction events. The “peer review draft version” (Version 1.0) of the Refinery Emi ssions Protocol document was posted on the EPA Web site ( http://www.epa.gov/ttn/chief/efpac/esttools.html ) on January 7, 2010, for initial public comment. Public comments were received from three different commenters. The “draft ICR version” (Version 2.0) of the Refinery Emissions Protocol document was revised to address these comments, as appropriate, and was made available for additional public comments prio r to the implementation of the ICR. This “final ICR version” (Version 2.1) of the Refinery Emissi ons Protocol document addresses, as appropriate, any additional public comments received during this re view period. Refinery owners and operators responding to the 2011 petroleum refinery ICR should check the EPA Web site ( http://www.epa.gov/ttn/chief/efpac/esttools.html ) or the refinery ICR Web site ( https://refineryicr.rti.org ) prior to preparing the emission inventory to ensure that the most recent Refinery Emissions Protocol document is used.


## 1.1 Completeness Emission estimates should be provided for each emi ssion source at the refinery, including ancillary sources and non-refinery process units. While this Refi nery Emissions Protocol document attempts to identify and provide methodologies for each emission source at a typical petroleum refinery, there may be certain sources located at the refinery facility (i.e ., that are owned or under the common control of the refinery owners or operators) that are not specifica lly addressed within the Refinery Emissions Protocol document. Additionally, there are sources included in this Refinery Emissions Protocol document for which no emission data are available to provide default (Methodology Rank 5) methods. Emission

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1-2 estimates should be provided for every emission sour ce present at the refinery, even for emission sources that are not specifically included in this Refinery Emissions Protocol document.
Similarly, emission estimates should be provided fo r each pollutant (except for greenhouse gases [GHGs], which are required to be reported under the Mandatory Greenhouse Gas Emissions Reporting Rule [Final Rule, 74 FR 56260]) emitted from a given 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 emissi on estimates should be developed. Hollow circles indicate pairings for which data may be reported (if th e 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) emi ssions is preferred to overall VOC emission measurement methods via EPA Methods 25, 25A-E, or 305, and should be provided when these data are readily available; however, speciation of VOC emissions is not required. While emission estimates are desirable for every compound/emission source paring where there is a filled circle in Table 1-1 , no new sampling or analyses is required to provide these emis sion estimates. Rather available data, supplemented with engineering analyses (following the guidance provid ed in this Protocol, where applicable), may be used to provide the desired speciation.
Some criteria pollutants, such as PM 10 

### or PM 2.5 

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

### ), are often determined or 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 that these co mpounds are criteria pollutants, but that these “pollutants” should be included in the refinery emi ssion inventory. No new sampling or analysis is required to provide these estimates; available data , supplemented with engineering analyses (following the guidance provided in this Protocol, where app licable), may be used to develop these estimates

PM Emission 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 c ondensable PM is assumed to be less than 2.5 microns (μm) in diameter (PM 2.5 ).

 PM 2.5 -PRI: “Primary” PM emissions that ar e 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.

Although a complete PM emissions inventory includes PM emissions that are 10 μm in diameter or less, some measurement methods also collect PM particles that are greater than 10 μm in diameter. The following nomenclature is used to designate PM emissions that include PM greater than 10 μm in diameter:

 PM-PRI: “Primary” PM emissions of any pa rticle size. PM-PRI = PM-FIL + PM-CON.

 PM-FIL: Filterable (or front-half catch) portion of the PM emissions of any particle size.

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1-3 Table 1-1. Summary of Pollutants and Emission Sources Inclusion in a Petroleum Refinery’s Emission Inventory

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

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 ● ● ● ● ● ● ○ ○

NO X Nitrogen oxides ● ● ● ● ● ● ○ ○

7446-09-5 Sulfur dioxide ● ● ● ● ● ● ● ●

VOC Volatile organic compounds ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

Specific VOC Constituents (Compounds listed below plus those listed under “Volatile Organic HAPs”)

74-85-1 Ethylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
74-86-2 Acetylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
74-98-6 Propane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
115-07-1 Propylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
463-49-0 Propadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

106-97-8 n-Butane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

75-28-5 Isobutane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

106-98-9 1-Butene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

107-01-7 2-Butene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

115-11-7 Isobutene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
(continued)

### Version 2.1.1 Final ICR Version – Corrected Section 1—Introduction

1-4 Table 1-1. Summary of Pollutants and Emission Sources Inclusion in a Petroleum Refinery’s Emission 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

590-19-2 1,2-Butadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
109-66-0 n-pentane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
78-78-4 2-Methylbutane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
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-Pentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
591-96-8 2,3-Pentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
598-25-4 3-Methyl-1,2-butadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
78-79-5 2-Methyl-1,3-butadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
542-92-7 Cyclopentadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
110-82-7 Cyclohexane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
108-87-2 Methylcylcohexane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
142-82-5 Heptane (and isomers) ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
111-65-9 Octane (and isomers) ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
78-93-3 Methyl ethyl ketone ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
25551-13-7 Trimethylbenzene(s) ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○
Hazardous Air Pollutants (HAPs)
Volatile Organic HAPs
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 ○ ○ ○ ○ ○
(continued)

### Version 2.1.1 Final ICR Version – Corrected Section 1—Introduction

1-5 Table 1-1. Summary of Pollutants and Emission Sources Inclusion in a Petroleum Refinery’s Emission 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

67-66-3 Chloroform ○ ○ ● ○ ○

74-87-3 Chloromethane ○ ○ ○ ○ ○

98-82-8 Cumene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●
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-Dichloroethylene ○ ○ ● ○ ○
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 n-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 ○ ○ ○ ○ ○ (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 1—Introduction

1-6 Table 1-1. Summary of Pollutants and Emission Sources Inclusion in a Petroleum Refinery’s Emission 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

75-01-4 Vinyl chloride ○ ○ ● ○ ○
95-47-6 o-Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●
108-38-3 m-Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●
106-42-3 p-Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

1330-20-7 Xylenes (total) ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●
Semi-volatile and Non-volatile Organic HAPs (except dioxins, furans, and polychlorinated biphenyls [PCBs])
83-32-9 Acenaphthene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

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 ○ ● ● ○ (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 1—Introduction

1-7 Table 1-1. Summary of Pollutants and Emission Sources Inclusion in a Petroleum Refinery’s Emission 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

57-97-6 7,12-Dimethylbenz(a) anthracene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

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 ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

Dioxins/Furans/PCBs

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 Dibenzofurans ● ● ● ● ● ○ ○ ○

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 ○ ○ ○ ○ ○ ○ ○ ○ (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 1—Introduction

1-8 Table 1-1. Summary of Pollutants and Emission Sources Inclusion in a Petroleum Refinery’s Emission 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

72918-21-9 Furan: 6F 123789 k ○ ○ ○ ○ ○ ○ ○ ○

60851-34-5 Furan: 6F 234678 k ○ ○ ○ ○ ○ ○ ○ ○

67562-39-4 Furan: 7F 1234678 k ○ ○ ○ ○ ○ ○ ○ ○

55673-89-7 Furan: 7F 1234789 k ○ ○ ○ ○ ○ ○ ○ ○

39001-02-0 Furan: 8F k ○ ○ ○ ○ ○ ○ ○ ○

1336-36-3 Polychlorinated biphenyls (total) ● ● ● ● ● ○ ○ ○

Metal HAPs

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 HAPs

75-15-0 Carbon disulfide ○ ○ ○ ○ ● ○ ○ ○ ○ ○ ○ ○ ○ ○
463-58-1 Carbonyl sulfide ○ ○ ○ ○ ● ○ ○ ○ ○ ○ ○ ○ ○ ○

7782-50-5 Chlorine ● ●
7647-01-0 Hydrogen chloride ○ ○ ○ ○ ● ○ ○ ○ ○ ○ ○ ○ ○ ○

74-90-8 Hydrogen cyanide (& cyanide compounds) ● ● ● ● ○ ○ ● ● ● ○ ○ ● ○ ○ ○ ● ●

7664-39-3 Hydrogen fluoride ○ ○ ○ (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 1—Introduction

1-9 Table 1-1. Summary of Pollutants and Emission Sources Inclusion in a Petroleum Refinery’s Emission 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

7723-14-0 Phosphorus ○ ○ ○
Other Compounds of Interest

7664-41-7 Ammonia ○ ○ ○ ● ● ○ ○ ○

74-84-0 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 wh ich emission estimates should be developed.

○ Designates compound/source pairings fo r which emission estimates may be dev eloped depending on the available data.

POM Designates compounds that meet the HAP definition of polycyclic organic matter (POM). j The listed HAP is 2,3,7,8-Tetrachlorodibenzo-p-dioxin (2378-T CDD); other dioxin isomers are listed because they can be used to calculate a 2378 TCDD toxicity e quivalence. Abbreviations 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-Hept achlorodibenzo-p-dioxin; 8D = Octachlorodibenzo-p-dioxin.

k The listed HAP is dibenzofurans. Abbrev iations used in the table are as follows : 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-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-Hept achlorodibenzofuran; 8F = Octachlorodibenzofuran



### Carbon dioxide, methane (CH 4 

### ), and nitrous oxide are GHGs 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 emission 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, respectivel y). 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 will be calculated and reported according to the methodologies and requirements in the GHG reporting rule and are not required to be reported as part of the refinery ICR. 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 co mbustion sources in this protocol document; the Tier 3 method is equivalent to Methodology Rank 2, and so on.

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1-10 While Table 1-1 is intended to provide a comprehensive lis t of pollutants for each emission source for which emission estimates should be provided, there may be pollutants released from some sources for which we have little or no information. If there is cred ible information that emissions of other pollutants are released from a given emission source (e.g., from a source test that was conducted on a particular process unit), then emission estimates for these additional pollutants should also be provided for that process unit, even if Table 1-1 does not include a bullet for that pollutant/emission source combination. Again, no new sampling or analysis is required to provide these estimates; available data, supplemented with engineering analyses, may be used to develop these estimates.


## 1.2 Data Quality
The consistent use of standardized methods and procedures is essential in the compilation of reliable emission inventories. Quality assurance (QA) and qua lity control (QC) of an emission 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 appropr iate emission 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 to assist data users with assessing the accuracy of the reported emissions. QA/QC and other metadata records should also be maintained to allow verification of the reported emissions, although this information does not need to be reported unless specifically requested. For measured emissions , these metadata include manufacturer’s design specifications for accuracy, initial calibrations, period ic calibration checks, and other QA/QC procedures used to ensure the accuracy of the measurement devi ce(s). For source tests used to develop site-specific emission 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). 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) and su btracting any non-VOCs present or by speciating individual VOCs and summin g the emissions of these compounds to determine the overall VOC emissions. When reporting VOC emissi ons, therefore, it should be clearly indicated how the emissions were determined. If the emissions are determined as TOC or from a TOC measurement, it must be indicated how the emission are being re ported, i.e., “as methane” (or “as” whatever compound was used to calibrate the total organic analyzer). Th ese metadata assist users of the inventory data and help to ensure that the inventory data are corr ectly used when performing subsequent analyses.



## 1.3 Calculations and Significant Digits The methodology ranking presented in this Refinery Emissions Protocol document is designed to highlight and promote those methods that are expected to yield the most accurate emission data. We recognize that the Methodology Rank 5 methodologies may only provide emission estimates that are within a factor of 2 or 3 from the actual emission ra te. Nonetheless, the emission factors presented in this document are generally presented with two 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 r ecommended that all calculations be performed carrying at least one additional significant digit to mini mize round-off errors. The emissions calculated using default emission factors may be rounded to one signif icant digit when reporting the emissions, but at least two significant digits should be carried in the cal culations. For methodologies that may have uncertainties in the range of ±10 percent, at least three signi ficant digits should be carried when performing the calculations, even though the final emission estim ate may only warrant two significant digits.

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2-1 

# 2. Equipment Leaks Equipment leaks are small emission sources that occu r throughout the process area of the refinery from various equipment components and conn ections 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 [OVA]) or using optical leak imaging techniques; ot her 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, refineri es 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 emissi ons 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 charact erized at least to the point of identifying the typical VOC concentration.
The most common optical leak imaging technique at th is time uses passive infrared spectral imaging at a wavelength that is strongly absorbed by the gas of interest to produce a real-time video image of the emission plume. Although this technology is very usef ul for quickly and easily identifying the presence of leaks, particularly large leaks, it has not yet been 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 techni ques measure either the volumetric or mass concentrations of a compound or mixture of compounds in a vertical cut through a plume. Combining these data with wind speed can be used to estimat e 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 fo r any optical leak imaging or other remote sensing techniques that develop to the point of being able to quantify equipment leak emissions.

Table 2-1 summarizes the hierarchy of equipment leak emission 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 constituen t-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 2a for equipment leaks may be used for certain components and Methodology Rank 2b for equipment leaks may be used for other components that are monitored using Method 21, depe nding on the availability of equipment-specific or process-specific concentration profiles for a given component or group of components. Additiona lly, 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 deta ils 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 for the petroleum refi nery industry. For more information regarding the way in which the correlations were deve loped, please refer to EPA’s document, Protocol for Equipment Leak Emission Estimates (U.S. EPA, 1995b).
For heavy liquid leaks (e.g., fuel oil, heavy gas oil, re sidual fuel oil, bitumen) that create a pool or puddle of liquid, emissions from the accumulated liquid pool should be estimated using the methods for spills in Section 12, Malfunctions, of this Refinery Emissions Protocol do cument in addition to using the methods

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2-2 presented in this section to estimate the emissions that occur at the leaking component. The spill methodology is needed in these cases fo r several reasons. First, for some refinery heavy liquids, the low volatility of heavy liquids will result in a relativel y low OVA reading using EPA Method 21, even with large visible leaks, so that the equipment leak methodologies are expected to understate the potential emissions from the pooled material. Second, emissions from the pooled material will be dominated by the more volatile components of the heavy liquid, and the spill methodology will more accurately assess the speciated emissions from the pooled material. Finally, the spill methodology will better account for the dimensions and duration of the liquid pool, which can be affected by the clean-up measures used.

Table 2-1. Summary of Equi pment Leak Emission Estimates

Rank Measurement Method Correlation Equations or Emission 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, equipmentspecific concentrations b) Process-specific average concentrations c) Refinery average stream concentrations 3 EPA Method 21 Default screening ranges factors

4 No monitoring; facility-specific component counts Default average emission factors a) Process-specific, service-specific concentrations b) Process-specific average concentrations c) Refinery average stream concentrations d) Default process compositions 5 No monitoring; default model process component counts Default average emission factors

a The letters represent ranking sublevels. 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 measurem ent 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 quanti fy the mass emission rate of the leak. Direct leak rate measurement, using either of these techniques, is accurate within ±15 percent (U.S. EPA, 2003).
In the bagging method, the 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 ba g, and the TOC concentration of the sample is measured. That collected gas can also be analyzed for individual compound concentrations. The mass emission rate is calculated from the measured concentr ations of the bag sample and the flow rate of the carrier gas. Although bagging techniques are useful fo r the direct measurement of larger leaks, bagging may not be possible for equipment components that ar e inaccessible, unusually shaped, or very large, and it is a relatively slow process (i.e., only two or three samples per hour).
High-volume samplers are essentially vacuums that capture all of the emissions from a leaking component to accurately quantify leak emission 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 hydrocarbo n detectors, which measure the concentration of hydrocarbon gas in the captured sample and the c oncentration of ambient hydrocarbon gas. Sample

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2-3 measurements are corrected for the ambient hydrocarbon concentration, and a mass leak rate is calculated by multiplying the flow rate of the measured sa mple by the difference between the ambient gas concentration and the gas concentration in the measu red sample. Chemical speciation of the leak, using vacuum canisters or similar methods, can be usedto apportion the TOC emission rate to individual constituents. High-volume samplers measure leak rates up to 0.23 cubic meters per minute (m 3 

### /min), 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).
While bagging or high-volume sampling are more accu rate than other equipment leak emission estimate methods, they are time consuming and impractical fo r routine screening of the large number of equipment components present at a refinery. However, some dire cted inspection and maintenance programs use, for example, optical imaging techniques to identify leaking components and then use high-volume sampling to quantitate the limited number of leaks identified. While these methods are more common at oil and gas production operations, they could also be applied at some refineries for certain sources. As the emission rate measured by the high-volume sampler (or baggi ng method) will be more accurate for that specific leak than emission estimates developed using any of the lower-ranked methodologies, the high-volume sampling (or bagging) results should be used for that specific leak if high-volume sampling (or bagging) is conducted.


## 2.2 Methodology Rank 2 for Equipment Leaks Most leak detection and repair (LDAR) programs require periodic monitoring using EPA Method 21 to identify leaking components. The preferred methodol ogy for estimating equipment leak emission rates directly from EPA Method 21 data (i.e., Methodology Ra nk 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 zero 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 parts per milli on by volume (ppmv) or 100,000 ppmv, then the applicable values for pegged emission rates in Table 2-2 are used to estimate emissions. Table 2-2 includes screening value correlations for both the petr oleum industry (applicable for petroleum refinery operations, marketing terminals, and oil and gas production) and the synthetic organic chemical manufacturing industry (SOCMI). Generally, most pe troleum refineries will use the petroleum industry correlations; however, the SOCMI correlations are provi ded here for convenience because some refineries may also have chemical manufacturing processes th at must be included in the facility’s emission inventory.
Many refineries or monitoring specialists use software programs that directly record the TOC reading (or screening value) for each component. Many of these so ftware programs will directly calculate the TOC emissions for each component using the screening valu e correlations and will even calculate componentspecific emission rates when composition data are en tered for the components. The TOC rates calculated by the correlation equation (and the default zero a nd pegged emission rate values) include non-VOC organic compounds, primarily methane and ethane. Th e 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 co mponents, the uncertainty in the cumulative total emissions is expected to be much less. For exam ple, based on Monte Carlo simulations of 100 leaking components and using an uncertainty of plus or minus a factor of 10, the uncertainty in the cumulative emissions is approximately plus or minus a factor of 1.4. The advantage of Methodology Rank 2 for equipment leaks is that it is not based on a presuppos ed distribution of equipment leaks, as are the lower ranked methodologies. Consequently, Methodology Rank 2 for equipment leaks is much more accurate than any of the lower ranked equipment leak emission estimation methods.

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2-4 Table 2-2. Equipment Leak Rate for Pe troleum and SOCMI Equipment Components a

Equipment Type

(All Services) Default Zero Emission Rate (kg/hr/source) Pegged Emission Rates (kg/hr/source) Correlation Equation b (kg/hr/source) 10,000 ppmv 100,000 ppmv
Leak Rates for Petroleum Industr y (Refinery, Marketing Termina ls, and Oil and Gas Production) Valve 7.8E-06 0.064 0.14 2.29E-06×SV 0.746 Pump 2.4E-05 0.074 0.16 5.03E-05×SV 0.610
Other c 4.0E-06 0.073 0.11 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 Leak Rates for Synthetic Organic Chem ical Manufacturing Industry (SOCMI) Gas valve 6.6E-07 0.024 0.11 1.87E-06×SV 0.873 Light liquid valve 4.9E-07 0.036 0.15 6.41E-06×SV 0.797 Light liquid pump d 7.5E-06 0.14 0.62 1.90E-05×SV 0.824
Connector 6.1E-07 0.044 0.22 3.05E-06×SV 0.885 Note: kg/hr/source = kilograms TOC per hour per source

a Data reported 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 instrume nts, loading arms, pressure relief devices, stuffing

boxes, vents, compressors, dump lever arms, diaphragm s, drains, hatches, meters, and polished rods. This “other” equipment type should be applied to any equi pment other than connectors, flanges, open-ended lines, pumps, or valves.
d The light liquid pump factors can also be applied to co mpressors, pressure relief valves, agitators, and heavy

liquid pumps.



### When an optical gas imaging camera is used to id entify leaks, the emissions can be quantified under Methodology Rank 2 (or Methodology Rank 1 for certain components) 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 be fore repair using Method 21 or are measured using high-volume sampling or bagging methods. For equipmen t found to be leaking when monitoring with the camera, either the subsequent Method 21 screening va lues in the applicable correlation equation should be used to estimate the emissions (Methodology Rank 2) or the leak rake rates measured via the highvolume sampling or bagging method (Methodology Rank 1) should be used, as applicable. For all equipment not found to be leaking when monitori ng with the camera, emissions should be estimated using the screening values obtained when conducting the annual Method 21 monitoring required by §63.11(d)(7) in the applicable correlation equations.

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2-5 2.2.1 Speciating Equipment Leak Emissions In developing constituent-specific emission estimates, the composition of the process stream in contact with the equipment is used to estimate the speciat ed equipment leak emissions. To the extent that compositional data are available for individual pro cess streams, each equipment component associated with that process stream should be tagged with the average composition of that process stream (Methodology Rank 2a 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 de tail may not be available. Alternatively, average compositional data may be determined for all streams in a specific process unit, for groups of streams in different portions of a process unit, or for groups of st reams in a particular service type in a process unit. Under this approach, all equipment associated with the applicable group of streams would be tagged with the same concentration profile (Methodology Rank 2b for equipment leaks). For example, an average composition could be determined for all gas streams, all light liquid streams, a nd all heavy liquid streams at a given refinery process unit (resulting in three com position profiles per unit). Alternatively, an overall average composition could be determined for all str eams (regardless of the type of service) for that process unit (resulting in one composition profile per un it). As a last resort, a single, overall average

Example 2-1: Calculation for Methodology Rank 2 for Equipment Leaks A refinery catalytic reforming unit (CRU) 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 ethane in all streams are known or estimated to be equal to 3 percent and 1 percent of the TOC, respectively. Also assume the TOC cont ent of each stream is 100 percent. Using Methodology Rank 2b for equipment leaks (corre lation approach), what is the cumulative hourly VOC emission rate from the valves in this process unit at the time the monitoring is conducted? To calculate the emissions, the default zero value for valves on Table 2-2 (7.8E-06) is used to estimate the TOC emissions from the 580 valv es 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 two valves with pegged readi ngs. 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.

Number of Valves Method 21 Screening Value, 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 0.00733 0.00704 2 Pegged at 100,000 0.28000 0.26880
Total 0.30 0.29

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2-6 process stream composition can be estimated on a refine ry-wide basis (e.g., one concentration profile for the entire refinery, which is Methodology Rank 2c for equipment leaks). Methodology Rank 2c for equipment leak emissions is very easy to implement in that the TOC emissions can be aggregated for all components first, and then the chemical-specific emissions can be calculated from the cumulative TOC emissions. However, this method greatly reduces the accuracy of the chemical-specific emission 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 implem ent Methodology Rank 2a or 2b for equipment leaks.
The correlation equations for equipment leaks provided in Table 2-2 provide emissions in terms of TOC (including methane and ethane). To calculate the emission rate for VOC (i.e., to exclude methane and ethane), use Equation 2-1.

E VOC 

### = E TOC 

### × (WF VOC 

### /WF TOC 

### ) (Eq. 2-1)
where:

E VOC 

### = Emission rate of VOC for a specific type of equipment (kilograms per year [kg/yr]) E TOC 

### = Emission rate of TOC for a specific type of equipment (kg/yr) WF VOC 

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

### = Average weight fraction of TOC in the stream.

Table 1-1 in Section 1, Introduction, lists the specific organic compounds that should be included in an inventory of equipment leak emissions. Either of the following equations (Equation 2-2a or Equation 2-2b) is used to speciate emissions for specifi c organic compounds from a single equipment piece:

E i 

### = E TOC 

### × (WF i 

### /WF TOC 

### ) (Eq. 2-2a)

E i 

### = E VOC 

### × (WF i 

### /WF VOC 

### ) (Eq. 2-2b)
where:

E i 

### = Mass emissions of organic chemical “i” from the equipment (kg/yr) WF i 

### = Concentration of organic chemical “i” in the equipment (weight fraction).

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2-7 2.2.2 Calculating Hourly and Annual Equipment Leak Emissions The emissions estimated based on EPA Method 21 measurement data (i.e., Methodology Rank 2 for equipment leaks) represent the emission rate at the time when the measurements were made (i.e., hourly emission estimates). Thus, the direct emission rate calculated based on the monitored screening values should be used for the hourly emission estimate. If the components are monitored multiple times per year, the hourly emissions for each process unit should be calculated for each monitoring period (as the summation of the emissions of all components for that process unit), and the monitoring period resulting in the highest overall emission rate is to be reporte d as the hourly emission rate for that unit. There may be components that are monitored at different fre quencies; for example, pumps may be monitored monthly, while valves are monitored either quarterly or semi-annually. In general, the hourly emissions for the process unit should only be calculated fo r the periods where a significant number of the components are monitored (in the example, quarterly or semi-annually). One should not take the highest hourly emission rate for each individual component, regardless of when it was monitored during the year, and then sum the maximum value for the individual components because this will tend to overstate the actual hourly emission rate from the process unit.
The first time an LDAR program is implemented, the emission estimates from the component screening measurements should be used as the emission rate for the facility (or an individual component or set of components) for all periods prior to the screening me asurements (i.e., the portions of the inventory year 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., monthl y, quarterly, or semiannually) as part of an ongoing LDAR program. Leaks greater than a certain threshol d are required to be repaired within certain time frames (although many LDAR programs allow some repair s to be delayed). After repairs are made, the

Example 2-2: 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 (VOCs) 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 or ganic compounds, minus methane and ethane, as shown in the following equation:

WF VOC 

### = (%Hexane + %Toluene + %Benzene +% Other VOC)/100% = (10 + 8 + 2 + 60)/100 = 0.80 From Example 2-1, the valve’s VOC emission rate was 0.81 grams per hour (g/hr). Equation 2-1 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 OtherVOC 

### = 0.81 × (0.60/0.8) = 0.61 g/hr

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2-8 repaired components should be re-screened to verify th at the leak has been repaired and to provide a new starting emission rate for that component. During th e next routine monitoring period, new screening values will be determined for each component, providi ng new instantaneous emission rate estimates for each component. The variations in component emissions during the year need to be accounted for when developing annual emission estimates for equipm ent components that are routinely monitored. Figure 2-1 illustrates the three acceptable methods for estim ating annual emissions from routinely (monthly, quarterly, semiannually) monitored equipment components.

Figure 2-1. Illustration of alternative met hods to determine equipment leak emissions from routine monitoring data.


### The mid-period method assumes that the initial reading represents the emission rate for the first half of the period between monitoring events and that the sub sequent reading represents the emission rate for the second half of the period between monitoring events. When a leak is detected for subsequent repair, the “leak” monitor reading is used from the time the leak is detected to the time it is repaired (i.e., rescreened). The modified trapezoid method assumes that the mass leak rate changes linearly between any two monitoring points, except for periods between leak detection and repair; the leak monitor reading is used from the time the leak is detected to the time it is repaired (i.e., re-screened). The average period method uses the arithmetic average emission rate of two adjacent instantaneous emission rate estimates

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2-9 (except for periods between leak detection and repa ir) for the emission rates between the measurement periods. As in the mid-period and modified trapezoid method, the average period method uses the leak monitor reading from the time the leak is detected to the time it is repaired (i.e., re-screened). In all of these alternatives, it is important that the emissi on rate be determined for each component and each monitoring event before extrapolating the emissions to the intervening periods. It is invalid to average the monitored screening values first and then to calculate the emission rate based on the average screening value.
Mathematically, the calculated emissions for periods w holly within the inventory year will be identical regardless of the alternative selected. Provided that on e can elect the “inventory year period” to start and end with a monitoring event, then the method select ed is immaterial. The only difference in the annual emissions determined using the three alternative me thods for routinely monitored components will occur if emissions must be determined for a specific time period (e.g., a calendar year), and the emissions determined for an intervening interv al (between monitoring events at the end of one year and start of the next year) must be parsed between the two years. While there can be differences in the annual emissions calculated using these different methods for a partic ular component, these differences will tend to cancel out when emissions are summed over a large number of components. Therefore, it is only important that there is consistency in the application of the sel ected method (i.e., all components use the mid-period method or all components use the modified trapezoid method or all components use the average period method).
If the equipment is taken out of service (e.g., no pro cess fluid is in the piping at the location of the specific component), the emission rate for that component can be assumed to be zero for the time period the equipment in out of service. If the process unit is not operating, but fluid remains in the components, then no correction for operating hours should be made . There can be some differences in the emissions calculated for the operating periods between monitoring intervals when the components are out of service, but these differences are expected to be small. Agai n, consistency in the application of the selected method is of key importance.
When emission inventories are required for a set calenda r year, there are also some practical matters to consider when selecting an annual estimation met hod for components, especially when components are monitored semiannually or less often. The midpoint method has the advantage of not relying on the subsequent year’s first semiannual monitoring if th e last semiannual monitoring event for the inventory year occurred in October or later. If the last semia nnual monitoring event for the inventory year occurred prior to October, then the subsequent year’s first semiannual monitoring would likely occur in March or earlier, so that the inventory could be developed in a timely fashion, even if the subsequent year’s monitoring data are needed to complete the invent ory for the current year. Similarly, for annual component monitoring, the midpoint method would not require the subsequent year’s monitoring results if monitoring occurred in July or later. On the other hand, the application of either the modified trapezoid method or the average period method requires the subse quent year’s monitoring data, regardless of when that monitoring event occurs; the modi fied trapezoid method is further complicated in that interpolation is required to correctly account for emissions between tw o inventory years. If allowed, an “equipment leak year” (like a fiscal year) could be established based on the typical timing of the monitoring events, so that the emissions for that equipment leak year can be de termined based entirely on whole monitoring periods.

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2-10 

## 2.3 Methodology Rank 3 for Equipment Leaks In some older LDAR programs, the only information th at is recorded is whether a leak was found. For these LDAR programs, leaks were defined as screening value readings greater than 10,000 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 read ings less than 10,000 ppmv and the number of components of each type with TOC readings greater than or equal to 10,0 00 ppmv. Methodology Rank 3 for equipment leaks estimates the emission rate using these data and the screening ranges emission factors in AP-42 (U.S. EPA, 1995b). Table 2-3 provides the screening ranges emission factors for refinery and SOCMI sources; see AP-42 for additional screening rang es emission factors for marketing terminals or oil and gas production operations if these sources are also part of the facility. If the number of components and the number of leakers are recorded by process, then this provides a more accurate method for using

Example 2-3: Calculation for Annual Emissions Using the Midpoint Method 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 zero, and the default zero rate is used when the OVA reading is zero. 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 “leak” emission rate.

1 Date and Time 2 OVA Reading (ppm) 3 TOC Emission Rate (kg/hr) 4 Hours a 5 TOC Emissions (kg/period) January 2, 8:00 a.m. 200 1.27E-3 32+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 2.23E-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-3 372-32 0.50 Annual Totals 8,760 40.0 kg/yr

a Each emission rate applies over half of the hours sinc e the previous screening and over half of the hours

until the next screening. For example, the results from the July 2 measur ement apply to half of the hours since the June 2 measurement and to half of the hour s 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 August 2 measur ements. Therefore, the July 2 result s 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 process-specific compositional data to estimate constituent-specific emission rates (Methodology Ranks 3a and 3b). 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 3c).
Table 2-3. Screening Ranges Emission Factors a

Equipment type Service Refinery Factors b SOCMI Factors c

≥ 10,000 ppmv emission factor (kg/hr/

source) b <10,000 ppmv emission factor (kg/hr/

source) b ≥ 10,000 ppmv emission factor (kg/hr/

source) c <10,000 ppmv emission factor (kg/hr/

source) c

Valves Gas 0.2626 0.0006 0.0782 0.000131 Light liquid 0.0852 0.0017 0.0892 0.000165 Heavy liquid 0.00023 0.00023 0.00023 0.00023 Pump and agitator seals Light liquid 0.437 0.0120 0.243 0.00187 Heavy liquid 0.3885 0.0135 0.216 0.0210 Compressor seals All 1.608 0.0894 1.608 0.0894
Pressure relief valves All 1.691 0.0447 1.691 0.0447

Connectors All 0.0375 0.00006 0.113 0.000081 Open-ended lines All 0.01195 0.00150 0.01195 0.00150

a Data reported in U.S. EPA, 1995b.
b These factors are for non-methane organic compound emissions.

c These factors are for total organic compound emissions.



### The uncertainty of the leak rates calculated usi ng the screening ranges emission factors for any single measurement may be a factor of 10 or more. Alt hough this methodology is intended to account for reduced emissions gained by an LDAR program, th e underlying default leak rates are based on the distribution of leaks prior to the implementation of an LDAR program. This method is expected to be biased high for facilities that have implemented an LDAR program, especially an LDAR program with leak action levels less than 10,000 ppmv. First, the implementation of any LDAR program is expected to alter not only the prevalence of leaks, but the relativ e magnitude of leaks above the action level (i.e., the average component leak rate for components w ith screening values of 10,000 ppmv or more). Furthermore, if an LDAR program uses a 1,000 pp mv leak action level, the relative magnitude and number of leaks with screening values between 1,000 ppmv and 10,000 ppmv is expected to be much less than for facilities that use a 10,000 ppmv screening level or do not have an LDAR program. The distribution of leaks is also affected by the monitoring frequency, so components that are monitored quarterly are expected to have a different leak fre quency distribution than components that are monitored annually. As such, the emissions estimated using Me thodology Rank 3 for equipment leaks is expected to be an upper-range emission estimate of equipment leak emissions. The accuracy of this method is dependent on the level of LDAR program used; the more frequent the monitoring and the lower the leak action level is, the more likely this method will be to significantly overestimate emissions (by as much as a factor of 10 to 50, based on data from Lev-On et al. [2007]).
The leak/no-leak factors presented by Lev-On et al. (2 007) were evaluated for facilities that use an optical gas imaging camera to identify leaks as a potential Methodology Rank 3 for equipment leaks. However, for the same reasons the screening ranges emission factors presented in Table 2-3 are expected to overestimate actual emissions for facilities that have implemented a stringent LDAR program, the leak/no-leak factors presented by Lev-On et al. (2007) are expected to underestimate the emissions from

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2-12 facilities that only use an optical gas imaging camera. The leak/no-leak factors presented by Lev-On et al. (2007) are based on a distribution of leaks for refineries that used quarterly monitoring with a leak definition of 1,000 ppmv. Most optical gas imaging cameras have leak detection sensitivities much higher than this level. As such, the distri bution of leaks by screening range is e xpected to be much different than the baseline distribution used to develop the leak/no-leak factors for optical imaging cameras. Until leak/no-leak factors are available for a more represen tative distribution of leaks, there is no acceptable Methodology Rank 3 for quantifying emissions using an optical gas imaging camera.
2.3.1 Speciating Equipment Leak Emissions The refinery screening ranges emission factors are for non-methane organic compound emissions. To apply the refinery screening ranges emission factor approach, use Equation 2-3 to calculate the total annual TOC emissions per type of equipment for wh ich Methodology Rank 3 is used. Note: Equation 2-3 should be applied separately to groups of equipmen t in streams with significantly different methane weight fractions. The SOCMI screening ranges emission factors are presented in terms of TOC, so Equation 2-3 does not apply to the SOCMI factors. For both refinery and SOCMI screening ranges emission factors, use Equations 2-1 and 2-2a or 2-2b (p resented previously in Section 2.2.1) to calculate the VOC and specific compound emissions, respectively.



### ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛ ⎥ ⎥ ⎦ ⎤ ⎢ ⎢ ⎣ ⎡

× ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

− × + ⎥ ⎥ ⎦ ⎤ ⎢ ⎢ ⎣ ⎡

× ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

− × = L

m TOC TOC L G

m TOC TOC G TOC 

### N WF WF WF F N WF WF WF F E (Eq. 2-3)

where:

E TOC 

### = Emission rate of TOC for a specific type of equipment (kg/hr) F G 

### = Applicable emission factor for specific t ype 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.
2.3.2 Calculating Hourly and Annual Equipment Leak Emissions Typically, facilities that use Methodology Rank 3 have limited data. The inst antaneous emission rate measured during a given monitoring event is used di rectly as the hourly emission rate for the process unit at that time. If the facility monitors annually, the instantaneous emission rate calculated for a given process or facility is used directly as the hourly em ission rate for the process unit. The annual emissions for the process unit are calculated using the hourly emission rate and annual operating hours of the process equipment as shown in Equation 2-4. If more than one monitoring event occurs during the year, the instantaneous (hourly) emission rates calculate d for each monitoring period are calculated and the highest value is reported for the hourly emissions. Th e annual emissions are calculated as the average of the calculated instantaneous emission rates multiplie d by the operating hours of the equipment.



### H E E TOC annual TOC 

### × =

, 

### (Eq. 2-4)

### Version 2.1.1 Final ICR Version – Corrected Section 2—Equipment Leaks

2-13 where:

E TOC,annual 

### = Annual emission rate of TOC for a specific type of equipment (kilograms per year [kg/yr]) E TOC 

### = Emission rate of TOC for a specific type of equipment (kg/hr) H = Operating hours per year (hr/yr).



## 2.4 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 hazardous air pollutant (HAP) and low VOC content, or it might be specific t ypes 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.,

Example 2-4: Calculation for Methodology Rank 3 for Equipment Leaks For the valves in the same reforming unit descr ibed in Example 2-1, what is the cumulative hourly VOC emission rate when Methodology Rank 3 is used? What are the annual VOC emissions? Assume that the distribution of valves in gas, light liquid, and heavy liquid service is as shown in the table below, and assume th at the valves were monitored once during the year. To calculate hourly TOC emissions for valves in gas service with screening values less than 10,000 ppmv, use the second half of Equation 2-3.

E TOC 

### = [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 kilograms 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 2-1 to calculate the VOC emissions from these valves. E VOC 

### = E TOC 

### × (WF VOC 

### /WF TOC 

### ) = 0.675 × (100-4)/100 = 0.648 kg VOC/hr Use the same procedure with the first half of Equation 2-3 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 2-1 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

Value, ppmv Number of Valves by Type of Service Emission Factors, kg/hr/source TOC Emissions, kg/hr VOC Emissions, 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 0.08 52 0.00023 1.076 1.033
1.68

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2-14 connectors) in the new source performance sta ndards (NSPS) or Petroleum Refinery Maximum Achievable Control Technology (MACT) I rules. Facility- or process-specific component counts (Methodology Rank 4 for equipment leaks) should be used when these data are available. Methodology Rank 4 is preferred over default component counts (Methodology Rank 5 for equipment leaks) because these defaults may not account for facility-specific f actors (e.g., control of pressure relief valves).
Default component counts (Methodology Rank 5 for equipment leaks) are dependent on the size of the refinery and the process units present. The median (default) equipment component counts for small refineries (those less than 50,000 ba rrels 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.
For both Methodology Ranks 4 and 5 for equipment l eaks, default emission factors per component for uncontrolled or unmonitored components must be used. It is assumed that these components are not monitored because emissions from monitored compone nts should be estimated using a higher ranked methodology (Methodology Rank 1, 2, or 3 for equipment leaks). The default emission 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 emission factors for refinery and SOCMI components are summarized in Table 2-6

. 2.4.1 Speciating Equipment Leak Emissions The emission factors for refinery components in Table 2-6 were developed to estimate emissions of nonmethane organic compounds (NMOCs). Therefore, to estimate VOC emissions, the emission factor must be multiplied by the ratio of the VOC-to-NMOC weight fractions. Additionally, the emission factors apply specifically to streams that are 100 percent TO C. To calculate VOC emissions from equipment in contact with a stream that contains both organi c compounds and other compounds, such as nitrogen or water vapor, the emission factor must be multiplied by th e 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 as shown in Equation 2-5.



## N WF WF WF WF WF WF FA E TOC methane TOC methane ethane TOC VOC 

## × × ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

− − − × = (Eq. 2-5)

where:

E VOC 

### = Emission rate of VOC from all equipment in the stream of a given equipment type (kg/hr) FA = Applicable average non-methane or ganic compounds emission 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.

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.Version 2.1.1Final ICR Version – CorrectedSection 2—Equipment Leaks2-15Table 2-4. Median Equipment Leak Component Counts for Small Model ProcessesaProcess UnitValvesPumpsCompressorsPressure Relief ValvesFlangesOpenEndedLinesSamplingConnectionsGasLightLiquidHeavyLiquidLightLiquidHeavyLiquidGasLightLiquidHeavyLiquidGasLightLiquidHeavyLiquidCrude distillation 75 251 216 8 8 2 6 6 5 164 555 454 39 10Alkylation (sulfuric acid) 278 582 34 18 10 1 12 15 4 705 1,296 785 20 16Alkylation (HF) 102 402 62 13 3 2 12 13 0 300 1,200 468 26 8Catalytic reforming 138 234 293 8 5 3 5 3 3 345 566 732 27 6Hydrocracking 300 375 306 12 9 2 9 4 4 1,038 892 623 25 10Hydrotreating/hydrorefining 100 208 218 5 5 2 5 3 5 290 456 538 20 6Catalytic cracking 186 375 450 13 14 2 8 8 7 490 943 938 8 8Thermal cracking (visbreaking) 206 197 0 7 0 0 4 0 0 515 405 0 0 4Thermal cracking (coking) 148 174 277 9 8 2 7 16 13 260 322 459 13 8Hydrogen plant 168 41 0 3 0 2 4 2 0 304 78 0 8 4Asphalt plant 120 334 250 5 8 2 5 10 9 187 476 900 16 6Product blending 67 205 202 6 11 1 10 6 22 230 398 341 33 14Sulfur plant 58 96 127 6 6 3 3 88 15 165 240 345 50 3Vacuum distillation 54 26 84 6 6 2 2 5 2 105 121 230 16 4Full-range distillation 157 313 118 7 4 2 5 4 6 171 481 210 20 6Isomerization 270 352 64 9 2 2 7 10 1 432 971 243 7 8Polymerization 224 563 15 12 0 1 10 5 3 150 450 27 5 7MEK dewaxing 145 1,208 200 35 39 3 10 14 4 452 1,486 2,645 19 17Other lube oil processes 153 242 201 7 5 2 5 5 5 167 307 249 60 6aProcess component countsas presented in EPA’s document,Locating and Estimating Air Emissions from Sources of Benzene(U.S. EPA, 1998a), for refineries with crude capacities less than50,000 bbl/cd.Version 2.1.1Final ICR Version – CorrectedSection 2—Equipment Leaks2-16Table 2-5. Median Equipment Leak Component Counts for Large Model ProcessesaProcess UnitValvesPumpsCompressorsPressure Relief ValvesFlangesOpenEndedLinesSamplingConnectionsGasLightLiquidHeavyLiquidLightLiquidHeavyLiquidGasLightLiquidHeavyLiquidGasLightLiquidHeavyLiquidCrude distillation 204 440 498 15 14 2 7 5 12 549 982 1,046 75 9Alkylation (sulfuric acid) 192 597 0 21 0 2 13 4 0 491 1,328 600 35 6Alkylation (HF) 104 624 128 13 8 1 9 11 1 330 1,300 180 40 14Catalytic reforming 310 383 84 12 2 3 8 11 0 653 842 132 48 9Hydrocracking 290 651 308 22 12 2 10 12 0 418 1,361 507 329 28Hydrotreating/hydrorefining 224 253 200 7 6 2 9 4 8 439 581 481 49 8Catalytic cracking 277 282 445 12 12 2 11 9 13 593 747 890 59 15Thermal cracking (visbreaking) 110 246 130 7 6 1 6 3 15 277 563 468 30 7Thermal cracking (coking) 190 309 250 12 11 1 8 5 10 627 748 791 100 10Hydrogen plant 301 58 0 7 360 3 4 139 0 162 148 0 59 21Asphalt plant 76 43 0 4 0 0 3 7 0 90 90 0 24 24Product blending 75 419 186 10 10 2 9 16 6 227 664 473 24 8Sulfur plant 100 125 110 8 3 1 4 4 4 280 460 179 22 7Vacuum distillation 229 108 447 2 12 1 5 1 4 473 136 1,072 0 7Full-range distillation 160 561 73 14 2 2 7 8 2 562 1,386 288 54 6Isomerization 164 300 78 9 5 2 15 5 2 300 540 265 36 7Polymerization 129 351 82 6 2 0 7 12 28 404 575 170 17 9MEK dewaxing 419 1,075 130 29 10 4 33 6 18 1,676 3,870 468 0 7Other lube oil processes 109 188 375 5 16 3 8 6 20 180 187 1,260 18 9aProcess component countsas presented in EPA’s document,Locating and Estimating Air Emissions from Sources of Benzene(U.S. EPA, 1998a), for refineries with crude capacities greater than50,000 bbl/cd.

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2-17 Table 2-6. Refinery and SOCMI Average Component Emission Factors a

Equipment Type Service Refinery Emission Factor (kg/hr/source) b SOCMI Emission Factor (kg/hr/source) c

Valves Gas 0.0268 0.00597 Light liquid 0.0109 0.00403 Heavy liquid 0.00023 0.00023 Pump seals d Light liquid 0.114 0.0199 Heavy liquid 0.021 0.00862 Compressor seals Gas 0.636 0.228
Pressure relief valves Gas 0.16 0.104
Connectors All 0.00025 0.00183 Open-ended lines All 0.0023 0.0017 Sampling connections All 0.0150 0.0150 Note: kg/hr/source = kilograms per hour per source

a Source: U.S. EPA, 1995b.
b The refinery emission factors are for non- methane organic compound emission rates.

c The SOCMI emission factors are for TOC (including methane).
d The light liquid pump seal factor can be used to estimate the leak rate from agitator seals.



### If a process stream contains no ethane, the non-methan e organic fraction is equal to the VOC fraction, which means the emission factor can be used without the correction ratio noted above, and the equation simplifies to Equation 2-6:

E VOC 

### = FA × WF TOC 

### × N (Eq. 2-6)
Two guidelines when correcting the “FA” term when applied to refineries are as follows:

 The correction should only be applied to equi pment containing a mixture of organics and methane.

 The maximum correction for the methane weight fraction should not be greater than 0.10, even if the equipment contains greater than 10 weight perc ent of methane. (This reflects the fact that the equipment for which the average refinery emission factors in Table 2-6 were developed typically contained 10 weight percent or less of methane).
When using Methodology Ranks 4 and 5, speciated emissions are calculated using the same procedures described in Section 2.2.1 of this document. Pr eferably, facility- or process-specific compositional analyses would be available to develop constituent- specific emission estimates. When facility-specific data are not available, average stream compositions presented in Table 2-7 should be used. The average stream compositions presented in Table 2-7 were calculated based on the Petroleum Environmental Research Forum (PERF) refinery process stream speciation study (API, 2002).
2.4.2 Calculating Hourly and Annual Equipment Leak Emissions Equations 2-5 and 2-6 provide the hourly emission rate. Because the components for which Methodology Ranks 4 or 5 for equipment leaks is applicable are not monitored, there are no additional considerations other than operating hours of the equipment (as seen in Equation 2-4) to convert the hourly emission estimate into an annual value.

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2-18 Table 2-7. Concentration of HAP in Refinery Process Unit Streams a

Process Unit Average Weight Percent of Compound in Process Unit Stream1,3-Butadienen-Hexane2,2,4-TrimethylpentaneBenzeneTolueneXylenes (total)EthylbenzeneCumene1,2,4-trimethylbenzeneNaphthaleneBiphenyl

Crude/Atmospheric distillation 0.01 4.3 0.05 0.9 1.7 2.0 0. 63 0.12 0.63 0.25 0.06

Vacuum distillation - 0.01 0.003 0. 003 0.04 0.04 0.02 - 0.02 0.12 0.09 Coking 0.04 2.5 0.75 0.42 1. 3 1.3 1.3 0.12 0.7 0.28 - Hydrocracking 0.025 1.9 1.0 1.3 2.7 2.7 0.7 0.09 1.3 0.20 - Catalytic cracking/FCCU 0.012 1.0 0. 3 1.0 3.3 4.9 1.1 0.10 1.9 0.72 0.43 Catalytic reforming/CRU 0.009 2.8 0.25 6.3 17.4 17.6 3. 9 0.42 5.9 0.87 - Hydrotreating/ Hydrode sulfurization - 1.9 - 0.37 1.7 1.9 0. 37 0.07 0.4 0.25 0.22

Alkylation 0.22 1.6 25 0.03 2.0 0.08 - - - - -
Isomerization - 3.2 0.01 0.5 0.6 0.15 - - - - - Polymerization - 0.5 0.7 1.2 - 1.8 1.2 0.09 - - -

a Source: API, 2002.



### Example 2-5: Calculation of Equipment Leak Emissions Using Refinery Average Emission Factors At a refinery, assume there are 100 gas valves in a stream that, on average, contains 80 weight percent non-methane organic compounds, 10 weight percent water vapor, 10 weight percent methane, and no ethane (thus, the TOC weight percent would be 90). If the process operates 8,000 hours per year, what are the hourly a nd annual VOC emissions from the 100 gas valves? Because the process stream contains no ethane, the average hourly VOC emissions from the gas valves in the stream can be calculated using the applicable emission factor from Table 2-5 and Equation 2-6.

E VOC 

### = FA × WF TOC 

### × N = 0.0268 kg NMOC/hr/gas valve × 0.9 × 100 gas valves = 2.412 kg VOC/hr

The annual emissions from the valves in the st ream are calculated using Equation 2-4 (with E TOC 

### replaced by E VOC 

### ).

E VOC, annual 

### = E VOC 

### × H
= 2.412 kg VOC/hr × 8,000 hr/yr

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3-1 

# 3. Storage Tanks Storage tanks (which are also sometimes referred to 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 cons truction 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 a nd vertical fixed-roof tanks, external floating roof tanks, internal floating roof tanks, and domed extern al floating roof tanks. Chapter 7.1 (Organic Liquid Storage 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 emission 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 emissi on factors. Direct measurements can only be taken from storage tanks that are covered and vented to a control device. Tank-specific modeling can be accomplished with emission 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 ra re cases when tank-specific data are not available, engineering estimates can be made using actual or estimated production quantities and default emission factors. For the purposes of the refinery ICR, a ll storage tank emission estimates should be developed using Methodology Ranks 1 or 2.

Table 3-1. Summary of Typical Hierarchy of Storage Tank Emission Estimates

Rank Methodology Description Application Data Requirements
1 Direct 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/fitting information, throughput 3 Default tank modeling Not applicable for refinery ICR emission estimates


## 3.1 Methodology Rank 1 for Storage Tanks Emissions from fixed-roof storage tanks may be purge d (e.g., tanks under a nitrog en blanket) and vented to a control device; these emissions can be directly m easured 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, thermal oxidizers, or carbon adsorption systems, it may be possible to measure the concentration of the gas upstr eam of the control device and estimate the emissions using an assumed control device efficiency (for more details on these types of methods, see the discussion at the end of Section 3.2 below; Section 4, Stationary Combustion Sources ; and/or Section 6, Flares ).

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3-2 This method is also recommended as a means to estim ate 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 r esulting 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 ve nted (i.e., DIAL [Differential Absorption LIDAR] techniques); however, these methods do not provide continuous monitoring and have additional limitations (requiring consistent wi nd direction, etc.). Therefore, at the present time they are not recommended as primary techniques for annual emission estimation.
If direct measurement methods are used, emissions from the tank during degassing, cleaning, or drained idle periods may or may not be included, de pending 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 monitored using direct measurement methods, the emissions from the tank during degassing and cleaning should be estimated separately using the methods provided in Section 11, Startup and Shutdown , of this Emissions Protocol Document.


## 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 emission est imation procedures detailed in Chapter 7.1 of AP42 (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 em ission 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/ttn/chief/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 fro m 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 i ndividually using site-specific conditions. 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 approach s hould 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 si milar software), and the emission results for individual tanks be reported. 2. Each tank should be modeled based on the vapor pr essure and composition of the material stored in the tank. The TANKS model has default vapor pressure and composition for certain streams; however, these defaults should not be used unless th e default parameters have been specifically evaluated and determined to adequately represent the stored liquid. For example, it is possible that a specific gasoline default stream (where different defaults are available for different Reid vapor pressures) will match well the gasoline stored in cer tain tanks, but it is less likely that the single crude oil default in TANKS will match the cr ude oil stored in the crude oil tanks. 3. 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 use the “default” fitting settings when using TANKS v4.09D, particularly for the type and control for guide poles. The default fitting settings should be

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3-3 reviewed and revised to properly account for the nu mber and control status of the specific tank’s fittings. 4. The storage tanks should be modeled using monthly parameters, including average monthly measured tank liquid temperatures, when availabl e. In TANKS, selecting the city will set the meteorological data that will be used in the calcu lations. Even if you select the monthly calculation option, the liquid temperature remains at the annua l average. As such, the TANKS 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. 1 

### Therefore, for storage tanks with throughputs that vary significantly with the seasons and fl oating 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. 5. Special calculations should be performed to acc ount 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 sep arately for each landing event using the methods provided in Section 7.1.3.2.2 of the 2006 update of Section 7.1 of AP-42. Tank degassing emissions can be calculated using the liquid heal method described in Section 11, Startup and Shutdown , of this Refinery Emissions Protocol document.
6. Emission estimates should be calculated and reported for individual pollutants. The TANKS program typically provides total hydrocarbon emission estimates, but can also provide estimates for individual pollutants. 7. Maximum hourly average emission rates for each tank should be calculated based on the reasonable worst-case (high emission rate) situation for a give n storage tank, which will generally correspond to the emissions while the tank is actively filling. Fact ors that should be considered are the volatility of the material stored, the filling rate, the bulk liqui d and ambient air temperature, and the wind speed. Higher emissions will occur when these parameters ar e at their highest values. Note that the TANKS program is primarily designed to estimate long-te rm, annual average emissions and cannot be easily manipulated to estimate the maximum hourly emis sion rate. Also note that the maximum hourly average emission rate should not be based on the tank’s degassing emission estimate.

For fixed-roof tanks that are vented to a control de vice, but for which flow and composition data are not measured (i.e., data are not available to use Me thodology Rank 1for storage tanks), the pre-control emissions from the fixed-roof storage tanks can be est imated using the appropria te equations for fixedroof storage tanks presented in Chapter 7.1 of AP-42 (U.S. EPA, 1995a). The post-control device emissions are then estimated from the pre-control em ission estimates and the efficiency of the control device using Equation 3-1

. 

## ⎟ ⎠ ⎞ ⎜ ⎝ ⎛
× = 100% CD

- 1 eff

, i unc i 

## E E (Eq. 3-1)

where:

E i 

### = Emission rate of pollutant “i” (tons/yr) E unc,i 

### = Projected emission rate of pollutant “i” assuming storage tank or unit does not have an add-on control device (tons/yr) CD eff,i 

### = Control device efficiency F eff 

### for pollutant “i” (weight percent). See Table 3-2 for default control efficiencies for various control devices.

1 

### 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 Control Efficien cies for Different VOC Control Devices

Control Device Pollutants Control Device Efficiency Refrigerated Condenser All VOC constituents Variable based on constituents and operating temperature a
Thermal oxidizer All VOC constituents 98% Catalytic oxidizer All VOC constituents 98% Carbon adsorption VOC constituents other than those listed in table note b 95%
Constituents listed in table note b 0%

a The control efficiency of a condenser should be determi ned based on the operating co nditions of the condenser

and composition of the vent st ream following the methods Methods for Estimating Air Emissions from Chemical Manufacturing Facilities (EIIP, 2007, Section 4.2.3)
b The following compounds have extremely low adsorptive capacities on activated carbon: acetaldehyde,

acetonitrile, acetylene, br omomethane, chloroethane, chloromethane, ethylene, formaldehyde, methanol, and vinyl chloride. 

## 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. Methodology Rank 3 for storage tanks (default emission factors) was originally intended for state and local agency staff that may not have access to the tank-specific information needed to implement the AP-42 modeli ng equations. Because this version of the Refinery Emissions Protocol document is intended specifically for refinery owners and operators in completing the emission inventory estimates required by the ICR, the Methodology Rank 3 for storage tanks has been deleted from this version of the pr otocol. Based on the information collected as a result of the ICR, we will determine if a Methodology Rank 3 for storage ta nks is appropriate and, if appropriate, we will provide the methodology and default emission factors at that time.

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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 engin es, and combustion turbines. These combustion sources are vent (point) sources that occur throughout the pro cess 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 for a given process, to reheat intermediates of a process, or to heat distillation co lumns (the latter are often termed “reboilers”). These emission sources are typically localized at or near the process requiring the heater (or reboiler). Boilers are used to generate steam for various refinery opera tions and to raise the temperature of feedstocks and process streams. The primary fuel for nearly all petrol eum refinery process heaters and boilers is refinery fuel gas, which is a mixture of uncondensed overh ead gases from distillation columns (also referred to as “still gas”) and natural gas. Still gas is produced fro m a variety of refinery process units, including atmospheric crude oil distillation units, fluid catalytic cracking units, catalytic reforming units, fluid and delayed coking units, and hydrocracking units. Other fuel s, such as natural gas only, fuel oil, and residual oil, are also used. Internal combustion engines have a variety of uses, including powering fire suppression systems, and supplying emergency back-up power. Internal combustion engines generally combust natural gas, gasoline, or diesel fuel oil. Combusti on turbines are used for cogeneration, and typically combust natural gas or refinery fuel gas.
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 or fuel grade coke. Some refineries may use green petroleum 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 materi al in the manufacture of aluminum. Consequently, calcined petroleum coke is often referred to as a node 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 gasi fied 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 sy ngas) 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 emission estimati on methods for stationary combustion sources. Each refinery may use a combination of differe nt 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. Different methodologies may be used for each combustion source for each pollutant based on the type of monitoring data available for each source (e.g., Methodology Rank 1 may be used for estimating NO x 

### emissions for one combustion source for which continuous emission monitoring systems (CEMS) data are available, wh ile Methodology Rank 4 may be used to estimate NO x 

### emissions for another combustion source at the same f acility where no CEMS data or emission test data are available). 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 po llutant 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 regard ing the implementation of these methods.
A complete inventory for combustion sources will include emission estimates for PM, SO 2 

### , NO x 

### , VOCs, 1 

### and carbon monoxide (CO). Depending on the fuel combusted, a complete inventory will also include

1 

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

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4-2 emission estimates for hydrogen sulfide; metals, includ ing 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 po lycyclic organic matter; and dioxins and furans. It is important to note that this list is not exhaustive; if there is ev idence that a combustion source at a refinery emits a pollutant (e.g., site-specific emission test data for an additional compound or a relevant emission factor for an additional compound), an emission estimate should be included in a complete inventory, even if that pollutant is not specifically identified in this document.

Table 4-1. Summary of Typical Hierarchy of St ationary Combustion Source Emission Estimates

Rank Measurement Method Additional Data Needed

1 Direct measurement (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



##  Heat content of fuel (depending on units of

source-specific emission factors) 3A Fuel analysis/mass balance 

##  Fuel usage



##  Assumed destruction efficiency
3B Source-specific stack testing to calculate sourcespecific emission correlations or factors 

##  Fuel usage



##  Heat content of fuel (depending on units of

source-specific emission factors)
4 Default emission factors 

##  Fuel usage



### There are many sources that describe emission methodol ogies 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 shou ld be consulted for more information if needed. In addition, the American Petroleum Institute (API) has posted a Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry on th eir Web site. While this document is focused on estimating GHG emissions, it contains in formation on how to estimate combustion gas flows and how to estimate emissions from various types of combustion sources, and it includes useful conversion factor discussions and examples.


## 4.1 Methodology Rank 1 for Stationary Combustion Sources Many stationary combustion sources will have a CEMS for NO x 

### and/or SO 2 

### . A CEMS is a comprehensive unit that continually determines gaseous or PM concen trations or emission rates using pollutant analyzer measurements and a convers ion 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 emission rates, such as those needed for an emission 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 concentr ation in the exhaust gas, and records the results. There are two main types of CEMS: in-situ and extr active. An in-situ CEMS measures and analyzes the emissions directly in a stack. There is less sample lo ss associated with the in-s itu CEMS compared to the extractive CEMS because the sample lines of an extractiv e 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 transporte d to a gas analyzer for the measurement of the contaminant concentration. Because an extractive CEMS is located outside the stack, the sampling

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4-3 instruments are not affected by stack conditions, main tenance and replacement are generally simpler, and the cost is lower than with an in-situ CEMS, a lthough 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 ge nerally 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, th ese measurements are made at stack conditions so that the concentrations would be determined on a “wet basis.” That is, the concentrations are based on the total amount of gas, including water vapor. For extr active 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 fl ow rate will be in terms of actual gas volume on a wet basis. If the gas composition is determined on a dr y basis, then a moisture content measurement is 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 a nd 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 emission rate from CEMS: 

# () ( ) 

# [ ] ( )

100% 1

1 20 

# ∑

= 

## ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × ×

− × = N

n N

o n

n o i n i

n H n i 

## K M P P
T T MVC MW C f Q E (Eq. 4-1)

where:

E i 

### = Emission 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 correct s for temperature and pressure, then replace “T o 

### ÷ T n 

### × P n 

### ÷ P o 

### ” with “1.” If the pollutant concentr ation 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 exhaus t 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 

### = Temperature 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 meas ured during measurement period “n” (atm). P o 

### = Average pressure at “standard conditions” (1 atm). M N 

### = Minutes per measurement period (minutes pe r 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.

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4-4 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 devel op 8,760 hourly average c oncentrations 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 emission ra te 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 emission rate is determined per minute and hourly emissions are determined by summing the 60 applicable emission rates; if the CE MS records measurements every 5 minutes, then the emission rate is determined for each 5-minute inte rval and hourly emissions are determined by summing the 12 applicable emission rates. This method ma y be more accurate than hourly averages if the combustion source’s flow rate varies significantly within an hour.

Example 4-1: Calculation of NO x 

### Emissions Using a CEMS The following example shows the calculation fo r 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. Calculate hourly NO X 

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



## – The hourly average NO x 

### concentration calculated by the CEMS for this hour is 60 parts per million by volume (ppmv), wet basis



## – The hourly average flow rate calculated by the CEMS for this hour is 500,000 acfm, wet basis



## – The unit operated at standard conditions for the full hour.
Equation 4-1 should be used to calculate the hourly emissions: 

# () ( ) 

# [ ] ( ) K M P P
T T MVC MW C f Q E N

n N

o n

n o NOx n NOx

n H n NOx 

# ∑

= 

## ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × × × × ×

− × =
1 20 

## 100% 1

= 500,000 × 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 continuously for an entire year and the emission rate remained perfectly constant over that year, annual emissions would be 0.1075 tons/hr × 8,760 hours per year (hr/yr) = 940 tons/yr.

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4-5 

## 4.2 Methodology Rank 2 for Stationary Combustion Sources Because the emission standards for stationary com bustion sources are often pr ovided 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 meas ure exhaust gas flow. In these cases, fairly accurate exhaust gas flow rates can be calculated from th e refinery fuel gas composition and fuel flow measurements. This method is co mmonly 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 u sed to calculate emissions depending on moisture measurements and whether pollu tant concentrations and O 2 

### or CO 2 

### content are measured on a wet or dry basis, and each equation uses one of three different t ypes 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 19 includes default F factors for some common types of fuel 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 co mponents; 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: 

# ( )
( ) ⎟ ⎟ ⎟ ⎟

⎠ ⎞

⎜ ⎜ ⎜ ⎜

⎝ ⎛

× ×

× = 

# ∑ ∑

= =

n

i i i n

i i i

d 

# MHC X MEV X K F

1 1 

### (Eq. 4-2)

where:

F d 

### = Volume of combustion components resulti ng from stoichiometric combustion per unit of heat content (dry standard cubic feet per million British thermal unit [dscf/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 a nd molar heat content for common constituents 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 (continued)

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4-6 Table 4-2. Molar Exhaust Volumes and Molar Heat Content of Refinery Fuel Gas Constituents (continued)

Constituent MEV a (dscf/g-mol) MHC b (Btu/g-mol) 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 standar d cubic feet per gram-mole [dscf/g-mol])
b MHC = molar heat content (Btu per gram-mol e [Btu/g-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 th e fuel can be used to calculate the volumetric flow rate of the exhaust gas, (Q) n 

### , using the following equation.



# ) % 9

. 20 ( 9

. 20

2 d f d n 

# O HHV Q F Q

− × × × = (Eq. 4-3)

where: Q n 

### = Volumetric flow rate for measurement pe riod “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 (dscfm) HHV = Higher heating value of fuel (million Br itish thermal units per standard cubic foot [MMBtu/scf]) %O 2d 

### = Concentration of O 2 

### on a dry basis (percent)

Once the volumetric flow rate is known, emissi ons 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 ra te will be in units of dry standard cubic feet per minute, so the temperature and pressure correction te rms 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 mu st 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 calcula te an emission factor (Equation 4-4) that can then be multiplied by the higher heating value of the fuel to estimate emissions (Equation 4-5).



## ) % 9

. 20 ( 9

. 20

2 d d d i 

## O F C EF

− = (Eq. 4-4)

where:

EF i 

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

### = Pollutant concentration, dry basis (pounds per standard cubic foot [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)

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-7 

# ( ) HHV Q EF E f i i 

## × × × = 60 (Eq. 4-5)

where:

E i 

### = Emissions of pollutant “i” (pounds per hour [lb/hr]) EF i 

### = Emission 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)
Example 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 emission 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 emission factor for each hour in the year. That emi ssion factor and the hourly measurements of the fuel flow rate should then be used in Equation 4-5 to de termine the hourly emissions for each hour in the year. The sum of all of those hourly emission estimates is the annual emission estimate.

Example 4-2: Calculation of Fuel-Specific F Factor The CEMS measures SO 2 

### and O 2 

### content on a dry basis, so in lieu of using a default F factor, the facility can use fuel analysis results and Equation 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 to calculate F d 

### as follows: 

# ( ) 

# ( ) ( ) ( ) 

# ( ) ( )( )( ) ( ) 

# ( ) 

# ( ) ( )( ) 

# ( ) ( )( )( ) ( ) ] [ ] [

8 4 8 4 10 4 10 4 6 3 6 3 8 3 8 3 4 2 4 2 2 2 6 2 6 2 4 4 8 4 8 4 10 4 10 4 6 3 6 3 8 3 8 3 4 2 4 2 2 2 6 2 6 2 4 4

inerts inerts H C H C H C H C H C H C H C H C H C H C H H H C H C CH CH inerts inerts H C H C H C H C H C H C H C H C H C H C H H H C H C CH CH d



### MHC X MHC X MHC X MHC X MHC X MHC X MHC X MHC X MHC X MEV X MEV X MEV X MEV X MEV X MEV X MEV X MEV X MEV X K F

× + × + × + × + × + × + × + × + × ÷ × + × + × + × + × + × + × + × + × × =



### 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 × 1947) + (0.17 × 2717) + (0.01 × 2558) + (0.04 × 0)] = 10 6 

### × 12.55 ÷ 1425 = 8,809 dscf/MMBtu

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-8 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 basis), 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 d scfm. Equation 4-3 should be used to calculate the exhaust flow rate from F factor as follows:



# ) % 9

. 20 ( 9

. 20

2 d f d n 

# O HHV Q F Q

− × × × =

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: 

# () ( ) 

# [ ] ( ) K M MVC MW % C f Q E N i n i

n H n SO 

## × × × ×

− × = 100 1 20 2



### E SO 2 

### = 8,031 × 1 × (20 ÷ 1,000,000) × 64.06 ÷ 849.5 × 60 × 2.2046 = 1.6 lb/hr

Example 4-4: Calculation of Emissions Factor from F Factor Given the same measurements as Example 4-3, calculate hourly SO 2 

### emissions. First, the following equation should be used to convert 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 emission factor:



## ) % 9

. 20 ( 9

. 20

2 2 d d d SO 

## O F C EF

− =

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 calculat e the hourly emissions (the fuel flow rate is 500 dscfm, or 30,000 dscf/hr [500 dscfm × 60 minutes per hour (min/hr)])


# HHV Q EF E f SO SO 

# × × = 2 2 

### 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 emission 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.

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-9 

## 4.3 Methodology Rank 3A for St ationary Combustion Sources Fuel analysis can be used to pred ict emissions of pollutants such as SO 2 

### by examining the compounds in the fuel being combusted. Given a known concentrati on 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 calcu lated by assuming that all of that 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 chemi cal 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, Methodol ogy Rank 3A for stationary combustion sources is considered a more accurate method of emission 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 available 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 emission 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 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 operati on, and this increase in oxygen content may lead to higher concentrations of NO x 

### . Equation 4-6 is a general equation used to determine a mass emission 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). 

# ( )( ) ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

= f i f f i 

# MW MW C Q E (Eq. 4-6)

where (assuming gaseous fuel):

E i 

### = Emission 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 em itted (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 emission s, 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 emission estimat es for that hour should be multiplied by the fraction of the hour that it did operate.
If the compound concentration is measured in parts pe r 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 

### . 

# ( ) ( )
385.3 × ×

= K MW C C i c f 

### (Eq. 4-7)

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-10 where:
C f 

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

### = Volumetric concentration of pollu tant 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 (sta ndard cubic feet per pound mole [scf/lb-mol])



## 4.4 Methodology Rank 3B for St ationary Combustion Sources Source testing can provide useful data for developi ng site-specific emission correlations or emission 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 emission measurement can provide an estimate of emissions at similar operating conditions. Emission factors are developed by dividing the emission rate by a process para meter such as fuel usage. It is important to note that this methodology will be less reliable when the un it 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 emission factor that is assumed to apply at all heat input rates. Example 4-5 demonstrates a sample emis sion 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 emission factor based on three test runs. That section also includes a 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



## – Molecular 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: 

# ( ) ( )
385.3 × ×

= K MW C C S c f



### C f 

### = (160) × (32) ÷ (10 6 

### ) ÷ (385.3)
C f 

### = 1.33 × 10 -5 

### lb/scf Then, use Equation 4-6 to calculate the hourly mass emissions: 

# ( )( ) ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

=

S SO f f SO 

# MW MW C Q E 2

2



### 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 rate 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.

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-11 detailed description of the ways in which source t ests and analyses for PM may need to be handled differently than other pollutants.

A more complex methodology for developing a correlati on rather than one emission 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 fo r 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 Peak ing 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 thr ee load levels, ideally 50%, 75%, and 100% firing rates. The test results at each firing rate are used to calculate an emission 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 calculati ons 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 emission monitoring or site-specific emi ssion factors are not available, then default emission factors may be the only way to estimate emissions. The EPA has developed emission factors for various types of combustion sources, which are compiled in AP -42. Emission 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 emission factors for internal combustion sources (including engines and combustion tu rbines) are presented in Chapter 3 of this same document (U.S. EPA, 1995a). It is important to note that AP-42 does not include emission factors for all fuels (notably refinery fuel gas and coke). The em ission factors in AP-42 are the recommended default emission factors, and AP-42 should be consulted to obtain the appropriate emission 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 emission source tests of combustion sources and has compiled

Example 4-6: Site-Specific Emissions Factor During the most recent source test, three 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 fo r 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

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-12 emission factors that may be used for refinery combustion sources if AP-42 does not include an applicable emission factor (Hansell and England, 199 8). Separate emission fact ors were developed for different combustion sources based on the type of sour ce and fuel used. Appendix D presents the full data 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) emission factor rating; the mean, median, maximum, and minimum emission factors; number of tests analyzed; standard deviation; uncertainty; and percent of test run resu lts at or above the detection limit.
The following tables present the recommended emissi on factors for a variety of metals and organic compounds. The emission factors in these tables are eith er the applicable emission factors as presented in AP-42 or the mean emission factors compiled by Ha nsell and England (1998). (Additional details on the rating and quality of these emission factors are located in the original document for AP-42 emission factors and in Appendix D for the emission factors compiled by Hansell and England (1998).) Emission factors for boilers and process heaters using various fuels are presented in Table 4-3 . Emission factors for reciprocating internal combustion engines using a variety of fuels are presented in Table 4-4 . Emission factors for combustion turbines using a variety of fuels are presented in Table 4-5

. To use any of these emission factors appropriately, th e refinery must monitor or keep records of the amount of fuel combusted or the heat input.
It is important to note that the bold italic emission factor values in Tables 4-3 through 4-5 from Hansell and England (1998) are based on method detection limits and are likely biased high. Additional data are needed to develop accurate emission factors for th e compounds that were below the method detection limits (RTI, 2002). The footnotes to Tables 4-3 through 4-5 explain any differences if a recommended emission factor is derived from another emission factor.
It is also important to note that this document do es not include emission factors for refinery combustion sources combusting either green or calcined petrol eum coke. In addition, while emissions from the combustion of syngas (gas produced by coke gasificati on) can be estimated using the methods provided in this section, this document does not include emissi on factors for syngas as a fuel. Emission factors for these fuels will need to be developed fro m future emission testing and analysis.

4.5.1 Default Emission Factors for Process Heaters The emissions from boilers and process heaters were depe ndent on the fuel type: gas (i.e., natural gas or refinery gas), crude oil/pipeline oil, residual (No. 6) fuel oil, and distillate (No. 2) fuel oil. No distinctions in HAP emission factors were made for criteria pollutant controls, such as selective catalytic reduction (SCR), or selective non-catalytic reduction (SNCR). Table 4-3 presents a summary of emission factors for boilers and process heaters.Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-13Table 4-3. Summary of Emission Factors for Boilers and Process Heaters Firing Various FuelsCASNumberSubstanceEmission Factor for Fuel TypeaExternal Combustion,Natural Gas/RefineryGas (lb/MMBtu)bExternal Combustion,Crude Oil/Pipeline Oil(lb/MMBtu)bExternal Combustion,Residual Fuel Oil(No. 6 Oil) (lb/MMBtu)bExternal Combustion,Distillate Fuel Oil(No. 2 Oil) (lb/MMBtu)i83-32-9 Acenaphthene2.4E-09 1.7E-07 1.4E-07f--208-96-8 Acenaphthylene6.5E-092.3E-08 1.7E-09f--75-07-0 Acetaldehyde1.2E-051.1E-057.0E-06--107-02-8 Acrolein1.7E-053.3E-06----120-12-7 Anthracene4.7E-093.7E-088.1E-09f--7440-36-0 Antimony5.2E-07--3.5E-05h--7440-38-2 Arsenic2.0E-07c6.7E-06 8.8E-06h4E-067440-39-3 Barium4.3E-06c-- 1.7E-05h--71-43-2 Benzene2.1E-06d4.1E-06 1.4E-06f--56-55-3 Benzo(a)anthracene2.2E-083.2E-08 2.7E-08f--50-32-8 Benzo(a)pyrene5.7E-081.4E-081.4E-09--205-99-2 Benzo(b)fluoranthene2.7E-08 5.5E-09 9.9E-09f, g--192-97-2 Benzo(e)pyrene--3.9E-095.8E-09--191-24-2 Benzo(g,h,i)perylene 1.3E-091.9E-08 1.5E-08f--207-08-9 Benzo(k)fluoranthene1.7E-08 2.3E-10 9.9E-09f, g--7440-41-7 Beryllium1.3E-071.9E-061.9E-07h3E-06106-99-0 1,3-Butadiene--1.4E-04----106-97-8 Butane2.1E-03d-- -- --7440-43-9 Cadmium1.1E-06c2.2E-06 2.7E-06h3E-0616887-00-6 Chloride----2.3E-03h--67-66-3 Chloroform--6.0E-05 3.4E-05--(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-14Table 4-3. Summary of Emission Factors for Boilersand Process Heaters Firing Various Fuels (continued)CASNumberSubstanceEmission Factor for Fuel TypeaExternal Combustion,Natural Gas/RefineryGas (lb/MMBtu)bExternal Combustion,Crude Oil/Pipeline Oil(lb/MMBtu)bExternal Combustion,Residual Fuel Oil(No. 6 Oil) (lb/MMBtu)bExternal Combustion,Distillate Fuel Oil(No. 2 Oil) (lb/MMBtu)i91-58-7 2-Chloronaphthalene--8.2E-081.5E-10--18540-29-9 Chromium (hexavalent)2.8E-07l1.1E-06 1.7E-06h--7440-47-3 Chromium (total)1.4E-06c8.7E-06 5.6E-06h3E-06218-01-9 Chrysene1.6E-097.5E-081.6E-08f--7440-48-4 Cobalt8.2E-08c-- 4.0E-05h--7440-50-8 Copper8.3E-07c9.5E-06 1.2E-05h6E-0653-70-3 Dibenz(a,h)anthracene1.2E-09d1.2E-08 1.1E-08f--25321-22-6 Dichlorobenzene1.2E-06d-- -- --57-97-67,12-Dimethylbenz(a)anthracene1.6E-08d-- -- --1746-01-6 Dioxin: 4D 2378j--3.5E-12 4.3E-12--40321-76-4 Dioxin: 5D 12378j--1.7E-11 2.5E-12--39227-28-6 Dioxin: 6D 123478j--1.5E-11 2.5E-12--57653-85-7 Dioxin: 6D 123678j-- 2.1E-112.5E-12--19408-74-3 Dioxin: 6D 123789j-- 3.3E-112.5E-12--35822-46-9 Dioxin: 7D 1234678j-- 9.3E-11 2.1E-11 --3268-87-9 Dioxin: 8Dj--3.3E-102.1E-11f--74-84-0 Ethane3.0E-03d-- -- --100-41-4 Ethylbenzene1.6E-05--4.2E-07f--206-44-0 Fluoranthene2.9E-09d6.9E-08 3.2E-08f--86-73-7 Fluorene2.7E-09d2.0E-07 3.0E-08f--(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-15Table 4-3. Summary of Emission Factors for Boilersand Process Heaters Firing Various Fuels (continued)CASNumberSubstanceEmission Factor for Fuel TypeaExternal Combustion,Natural Gas/RefineryGas (lb/MMBtu)bExternal Combustion,Crude Oil/Pipeline Oil(lb/MMBtu)bExternal Combustion,Residual Fuel Oil(No. 6 Oil) (lb/MMBtu)bExternal Combustion,Distillate Fuel Oil(No. 2 Oil) (lb/MMBtu)i16984-48-8 Fluoride----2.5E-04h--50-00-0 Formaldehyde7.4E-05d1.1E-052.2E-04f--51207-31-9 Furan: 4F 2378k-- 6.2E-10 5.5E-12 --57117-41-6 Furan: 5F 12378k--6.0E-11 3.1E-12--57117-31-4 Furan: 5F 23478k--1.1E-10 3.1E-12--70648-26-9 Furan: 6F 123478k-- 1.3E-102.5E-12 --57117-44-9 Furan: 6F 123678k-- 4.3E-111.9E-12 --72918-21-9 Furan: 6F 123789k--3.5E-12 2.5E-12--60851-34-5 Furan: 6F 234678k-- 6.1E-113.7E-12 --67562-39-4 Furan: 7F 1234678k-- 1.4E-10 9.8E-12 --55673-89-7 Furan: 7F 1234789k--8.3E-12 3.2E-12--39001-02-0 Furan: 8Fk--7.3E-114.9E-11--110-54-3 Hexane1.8E-03d-- -- --7783-06-4 Hydrogen sulfide8.5E-05------193-39-5 Indeno(1,2,3-cd)pyrene 7.1E-081.9E-08 1.4E-08f--7439-92-1 Lead4.9E-07e1.9E-06 1.0E-05h9E-067439-96-5 Manganese3.7E-07c1.8E-05 2.0E-05h6E-067439-97-6 Mercury2.5E-07c1.0E-05 7.5E-07h3E-0656-49-5 3-Methylchloranthrene1.8E-09d-- -- --91-57-6 2-Methylnaphthalene2.4E-08d2.5E-07 7.4E-08 --7439-98-7 Molybdenum1.1E-06c-- 5.2E-06h--(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-16Table 4-3. Summary of Emission Factors for Boilersand Process Heaters Firing Various Fuels (continued)CASNumberSubstanceEmission Factor for Fuel TypeaExternal Combustion,Natural Gas/RefineryGas (lb/MMBtu)bExternal Combustion,Crude Oil/Pipeline Oil(lb/MMBtu)bExternal Combustion,Residual Fuel Oil(No. 6 Oil) (lb/MMBtu)bExternal Combustion,Distillate Fuel Oil(No. 2 Oil) (lb/MMBtu)i91-20-3 Naphthalene6.0E-07d5.5E-06 7.5E-06f--7440-02-0 Nickel2.1E-06c2.4E-03 5.6E-04h3E-06109-66-0 Pentane2.5E-03------198-55-0 Perylene--5.2E-107.4E-10--85-01-8 Phenanthrene1.7E-08d1.7E-07 7.0E-08f--108-95-2 Phenol4.0E-06------7723-14-0 Phosphorus6.4E-071.8E-04 6.3E-05h--74-98-6 Propane1.6E-03d-- ----115-07-1 Propylene1.5E-044.4E-05----129-00-0 Pyrene4.9E-09d1.2E-07 2.8E-08f--7782-49-2 Selenium8.8E-077.9E-06 4.5E-06h1.5E-0571-55-6 1,1,1-Trichloroethane----1.6E-06f--108-88-3 Toluene3.3E-06d3.5E-05 4.1E-05f--7440-62-2 Vanadium2.3E-06c-- 2.1E-04h--95-47-6 Xylene (o)----7.3E-06f--1330-20-7 Xylene (total)2.5E-052.9E-06----7440-66-6 Zinc2.8E-05c4.2E-04 1.9E-04h4E-06(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-17Table 4-3. Summary of Emission Factors for Boilersand Process Heaters Firing Various Fuels (continued)Note: lb/MMBtu = pounds per million British thermal unitsaBold italic values indicate that all test runs were below detection limit; underlined values indicate that 75% or more of thetest runs were below the detectionlimit.bSource: Hansell and England, 1998, unless otherwise specified.cSource: U.S. EPA, 1995a, AP-42 Section 1.4,Table 1.4-4. Emission factors were provided for natural gas combustion sources. Values converted from lb/106scf to lb/MMBtu by dividing by 1,020 MMBtu/106scf.dSource: U.S. EPA, 1995a, AP-42 Section 1.4,Table 1.4-3. Emission factors were provided for natural gas combustion sources. Values converted from lb/106scf to lb/MMBtu by dividing by 1,020 MMBtu/106scf.eSource: U.S. EPA, 1995a, AP-42 Section 1.4,Table 1.4-2. Emission factors were provided for natural gas combustion sources. Values converted from lb/106scf to lb/MMBtu by dividing by 1,020 MMBtu/106scf.fSource: U.S. EPA, 1995a, AP-42 Section 1.3,Table 1.3-9. Emission factors were provided specifically for residual oil (No. 6oil) fired boilers. Values convertedfrom lb/103Gal to lb/MMBtu bydividing by 150 MMBtu/103Gal.gEmission factor includes both benzo(b)fluoranthene and benzo(k)fluoranthene.hSource: U.S. EPA, 1995a, AP-42 Section 1.3,Table 1.3-11. Emission factors were provided specifically for residual oil (No. 6oil) fired boilers. Valuesconverted from lb/103Gal to lb/MMBtu by dividing by 150 MMBtu/103Gal.iSource: U.S. EPA, 1995a, AP-42 Section 1.3, Table 1.3-10. Emission factors were provided specifically for distillate oil-fired boilers. Values converted fromlb/1012Btu to lb/MMBtuby dividing by 106.j4D 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; 6D123678 = 1,2,3,6,7,8-Hexachlorodibenzo-p-dioxin; 6D 123789 = 1,2,3,7,8,9-Hexachlorodibenzo-p-dioxin; 7D1234678 = 1,2,3,4,6,7,8-Heptachlorodibenzo-pdioxin; 8D = Octachlorodibenzo-p-dioxin.k4F 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-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.lHexavalent chromium was not detected. Twenty percent of the total chromium emissionfactor is assumed for the hexavalent chromium emission factor. Thehexavalent chromium emission factors for gas turbines are between 10 and 15 percent of the total chromium emission factor, andthe hexavalent chromiumemission factor for boilers firing fuel oil is about 30 percentof the total chromium emission factor (based on detection limits, which are expected to overstatehexavalent chromium emissions), so 20 percent is a conservative(reasonable high-end) estimate for hexavalent chromium emissions from refinery fuel gas.

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-18 4.5.2 Default Emission Factor for Internal Combustion Engines The emissions from reciprocating internal combustion engines were dependent on: (1) the type of fuel used (diesel fuel, or gas [field gas, or natural gas]), (2) the type of engine used (two-stroke versus fourstroke engines), and (3) the fuel-to-air ratio. As shown in Table 4-4 , high air rates (or lean fuel mixtures) tend to have higher emissions of acetaldehyde and form aldehyde, whereas lean gas mixtures tend to have higher emissions of benzene, toluene, and xylenes.

4.5.3 Default Emission Factors for Combustion Turbines The emissions from combustion turbines were dependent on (1) the type of fuel used (e.g., distillate fuel oil, or gas [refinery fuel gas, liquefied petroleum g as, or natural gas]), and (2) the presence or absence of duct burners. No distinctions in HAP emission factors were made for criteria pollutant controls, such as selective catalytic reduction (SCR), or carbon monoxide oxidation catalyst. Table 4-5 presents a summary of emission factors for combustion turbines.Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-19Table 4-4. Summary of Emission Factors for Internal Combustion Engines Firing Various FuelsaCASNumberSubstanceEmission Factor for Engine and Fuel TypebDiesel,O2< 13%(lb/MMBtu)Diesel,O2> 13%(lb/MMBtu)Diesel,O2not specified(lb/MMBtu)cNatural Gas/FieldGas,Lean (2-Stroke)(lb/MMBtu)dNaturalGas/Field Gas,Lean (4-Stroke)(lb/MMBtu)eNaturalGas/Field Gas,Rich (4-Stroke)(lb/MMBtu)j83-32-9 Acenaphthene4.5E-06 1.4E-06 < 1.4E-06f1.3E-06g1.3E-06h--i208-96-8 Acenaphthylene9.0E-06 5.1E-06 < 5.1E-06f3.2E-06g5.5E-06h--i75-07-0 Acetaldehyde2.4E-05 7.6E-04 7.7E-04 7.8E-03 8.4E-03 2.8E-03107-02-8 Acrolein7.6E-06 9.4E-05 <9.3E-05 7.8E-03 5.1E-03 2.6E-03120-12-7 Anthracene1.2E-06 1.9E-06 1.9E-06f7.2E-07g2.4E-07a,h--i100-52-7 Benzaldehyde-- 9.0E-05--------71-43-2 Benzene7.1E-04 8.8E-049.3E-04 1.9E-03 4.4E-04 1.6E-0356-55-3 Benzo(a)anthracene6.1E-07 1.7E-06 1.7E-06f3.4E-07g7.4E-08a,h--i50-32-8 Benzo(a)pyrene 2.5E-071.0E-08< 1.9E-07f5.7E-09g3.4E-08a,h--i205-99-2 Benzo(b)fluoranthene1.1E-06 1.9E-07 < 9.9E-08f8.5E-09g1.7E-07h--i192-97-2 Benzo(e)pyrene------ 2.3E-08g4.2E-07h--i191-24-2 Benzo(g,h,i)perylene5.4E-07 4.1E-07 < 4.9E-07f2.5E-08g4.1E-07h--i207-08-9 Benzo(k)fluoranthene2.1E-07 3.0E-07 < 1.6E-07f4.3E-09g5.0E-07a,h--i92-52-4 Biphenyl------4.0E-06 2.1E-04--106-99-0 1,3-Butadiene--3.9E-05< 3.9E-05 8.2E-042.7E-046.6E-04106-97-8 Butane------4.8E-03 5.4E-04--Butyr/Isobutyraldehyde -- -- -- 4.4E-04 1.0E-044.9E-0556-23-5 Carbon tetrachloride------6.1E-05 < 3.7E-05 < 1.8E-05108-90-7 Chlorobenzene------4.4E-05 < 3.0E-05 < 1.3E-0575-00-3 Chloroethane--------1.9E-06 --(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-20Table 4-4. Summary of Emission Factors for Internal Combustion Engines Firing Various Fuelsa(continued)CASNumberSubstanceEmission Factor for Engine and Fuel TypebDiesel,O2< 13%(lb/MMBtu)Diesel,O2> 13%(lb/MMBtu)Diesel,O2not specified(lb/MMBtu)cNatural Gas/FieldGas,Lean (2-Stroke)(lb/MMBtu)dNaturalGas/Field Gas,Lean (4-Stroke)(lb/MMBtu)eNaturalGas/Field Gas,Rich (4-Stroke)(lb/MMBtu)j67-66-3 Chloroform------4.7E-05 < 2.9E-05 < 1.4E-05218-01-9 Chrysene1.5E-06 3.5E-07 3.5E-07f6.7E-07g6.9E-07h--i110-82-7Cyclohexane -- -- -- 3.1E-04 -- --287-92-3 Cyclopentane------9.5E-05 2.3E-04--53-70-3 Dibenz(a,h)anthracene3.4E-074.1E-07 < 5.8E-07f--g1.0E-08a,h--i75-34-3 1,1-Dichloroethane------3.9E-05 < 2.4E-05< 1.1E-05107-06-2 1,2-Dichloroethane------4.2E-05 < 2.4E-05 < 1.1E-0578-87-5 1,2-Dichloropropane------4.5E-05 < 2.7E-05 < 1.3E-05542-75-6 1,3-Dichloropropene ------4.4E-05 < 2.6E-05< 1.3E-0574-84-0 Ethane------7.1E-02 1.1E-01 7.0E-02100-41-4 Ethylbenzene------1.1E-04 4.0E-05 < 2.5E-05106-93-4 Ethylene dibromide------7.3E-05 < 4.4E-05 < 2.1E-05206-44-0 Fluoranthene3.9E-06 7.6E-06 7.6E-06f3.6E-07g1.1E-06h--i86-73-7 Fluorene1.2E-05 2.9E-05 2.9E-05f1.7E-06g5.7E-06h--i50-00-0 Formaldehyde7.7E-05 1.2E-03 1.2E-03 5.5E-02 5.3E-02 2.1E-02110-54-3 n-Hexane------4.5E-04 1.1E-03--193-39-5 Indeno(1,2,3-cd)pyrene4.0E-07 2.7E-07 < 3.8E-07f9.9E-09g1.1E-07a,h--i75-28-5Isobutane -- -- -- 3.8E-03 -- --67-56-1 Methanol------2.5E-03 2.5E-03 3.1E-03108-87-2 Methylcyclohexane------3.4E-04 1.2E-03--(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-21Table 4-4. Summary of Emission Factors for Internal Combustion Engines Firing Various Fuelsa(continued)CASNumberSubstanceEmission Factor for Engine and Fuel TypebDiesel,O2< 13%(lb/MMBtu)Diesel,O2> 13%(lb/MMBtu)Diesel,O2not specified(lb/MMBtu)cNatural Gas/FieldGas,Lean (2-Stroke)(lb/MMBtu)dNaturalGas/Field Gas,Lean (4-Stroke)(lb/MMBtu)eNaturalGas/Field Gas,Rich (4-Stroke)(lb/MMBtu)j75-09-2 Methylene chloride---- -- 1.5E-04 2.0E-05 4.1E-0591-57-6 2-Methylnaphthalene ------ 2.1E-05g3.3E-05h--i91-20-3 Naphthalene1.3E-04 8.5E-05 8.5E-05f9.6E-05g7.4E-05h< 9.7E-05i111-84-2 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-09g--h--i85-01-8 Phenanthrene4.0E-05 2.9E-05 2.9E-05f3.5E-06g1.0E-05h--i108-95-2 Phenol------4.2E-05 2.4E-05--74-98-6 Propane------2.9E-02 4.2E-02 --115-07-1 Propylene2.7E-032.6E-03 2.6E-03 2.4E-02a1.7E-02a2.0E-02a129-00-0 Pyrene3.6E-06 4.8E-06 4.8E-06f5.8E-07g1.4E-06h--i100-42-5 Styrene------5.5E-05 < 2.4E-05 < 1.2E-0579-34-5 1,1,2,2-Tetrachloroethane-- -- -- 6.6E-05 <4.0E-05 2.5E-05108-88-3 Toluene2.6E-04 4.0E-04 4.1E-04 9.6E-04 4.1E-045.6E-0479-00-5 1,1,2-Trichloroethane -- -- -- 5.3E-05 <3.2E-05< 1.5E-05526-73-8 1,2,3-Trimethylbenzene -- -- -- 3.5E-05 2.3E-05--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--(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-22Table 4-4. Summary of Emission Factors for Internal Combustion Engines Firing Various Fuelsa(continued)CASNumberSubstanceEmission Factor for Engine and Fuel TypebDiesel,O2< 13%(lb/MMBtu)Diesel,O2> 13%(lb/MMBtu)Diesel,O2not specified(lb/MMBtu)cNatural Gas/FieldGas,Lean (2-Stroke)(lb/MMBtu)dNaturalGas/Field Gas,Lean (4-Stroke)(lb/MMBtu)eNaturalGas/Field Gas,Rich (4-Stroke)(lb/MMBtu)j75-01-4 Vinyl chloride------ 2.5E-05 1.5E-05 <7.2E-06108-38-3,106-42-3Xylene (m,p) -- 1.5E-04 -- 5.8E-04a1.4E-04a4.7E-04a95-47-6 Xylene (o)--1.5E-04-- 2.7E-04a5.9E-05a2.3E-04a1330-20-7 Xylene (total)1.9E-04 2.6E-04 2.9E-04 2.7E-04 1.8E-04 2.0E-04Note: lb/MMBtu = pounds per million British thermal unitsaSource: Hansell and England, 1998, unless otherwise specified.bBold italic values indicate that all test runs were below detection limit.cSource: U.S. EPA, 1995a, AP-42 Section 3.3,Table 3.3-2. Emission factors are for uncontrolled sources. Emission factors preceded with a less than symbolare based on method detection limits. Note that these emission factors are for dieselengines up to 600 hp. Emission factors for diesel engines greater than600 hp can be found in AP-42 Section 3.4.dSource: U.S. EPA, 1995a, AP-42 Section 3.2, Table 3.2-1. Emission factors are for uncontrolled sources.eSource: U.S. EPA, 1995a, AP-42 Section 3.2,Table 3.2-2. Emission factors are for uncontrolled sources. Emission factors preceded with a less than symbolare based on method detection limits.fThe emission factor for total polycyclic aromatic hydrocarbons(PAH) in U.S. EPA, 1995a, Table 3.3-2 is 1.7E-04 lb/MMBtu.gThe emission factor for total PAH in U.S.EPA, 1995a, Table 3.2-1 is 1.3E-04 lb/MMBtu.hThe emission factor for total PAH in U.S.EPA, 1995a, Table 3.2-2 is 2.7E-05 lb/MMBtu.iThe emission factor for total PAH in U.S.EPA, 1995a, Table 3.2-3 is 1.4E-04 lb/MMBtu.jSource: U.S. EPA, 1995a, AP-42 Section 3.2,Table 3.2-3. Emission factors are for uncontrolled sources. Emission factors preceded with a less than symbolare based on method detection limits.Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-23Table 4-5. Summary of Emission Factorsfor Combustion Turbines Firing Various FuelsaCAS NumberSubstanceEmission Factors for Combustion Turbine and Fuel Typea, bDistillate Oil, Typenot specified(lb/MMBtu)cNatural Gas, Typenot specified(lb/MMBtu)dNatural Gas/RefineryFuel Gas/LiquefiedPetroleum Gas, DuctBurners (lb/MMBtu)Natural Gas/Refinery FuelGas/Liquefied PetroleumGas, No Duct Burners(lb/MMBtu)83-32-9 Acenaphthene--e--f2.2E-08 3.3E-09208-96-8 Acenaphthylene--e--f1.1E-08 2.9E-0975-07-0 Acetaldehyde--4.0E-05 4.1E-062.7E-05107-02-8 Acrolein--6.4E-06 --1.7E-05120-12-7 Anthracene--e--f2.5E-08 3.4E-087440-38-2 Arsenic< 1.1E-05------71-43-2 Benzene5.5E-05 1.2E-05----56-55-3 Benzo(a)anthracene--e--f1.5E-08 2.8E-0950-32-8 Benzo(a)pyrene--e--f-- --205-99-2 Benzo(b)fluoranthene--e--f2.5E-08 3.3E-09191-24-2 Benzo(g,h,i)perylene--e--f-- 1.9E-09207-08-9 Benzo(k)fluoranthene--e--f-- 2.3E-097440-41-7 Beryllium< 3.1E-07------106-99-0 1,3-Butadiene< 1.6E-05< 4.3E-07----7440-43-9 Cadmium4.8E-06--2.9E-065.3E-0618540-29-9 Chromium (hexavalent)2.2E-06g--7.0E-06 1.5E-067440-47-3 Chromium (total)1.1E-05 -- 5.0E-05 1.3E-05218-01-9 Chrysene--e--f1.1E-07 4.9E-097440-50-8 Copper----1.2E-054.1E-0553-70-3 Dibenz(a,h)anthracene--e--f-- --(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-24Table 4-5. Summary of Emission Factorsfor Combustion Turbines Firing Various Fuelsa(continued)CAS NumberSubstanceEmission Factors for Combustion Turbine and Fuel Typea, bDistillate Oil, Typenot specified(lb/MMBtu)cNatural Gas, Typenot specified(lb/MMBtu)dNatural Gas/RefineryFuel Gas/LiquefiedPetroleum Gas, DuctBurners (lb/MMBtu)Natural Gas/Refinery FuelGas/Liquefied PetroleumGas, No Duct Burners(lb/MMBtu)100-41-4 Ethylbenzene--3.2E-05 -- --206-44-0 Fluoranthene--e--f9.9E-08 1.2E-0886-73-7 Fluorene--e--f1.8E-07 1.5E-0850-00-0 Formaldehyde2.8E-04 7.1E-04 3.1E-03 3.1E-047783-06-4 Hydrogen sulfide--------193-39-5 Indeno(1,2,3-cd)pyrene--e--f-- 1.8E-097439-92-1 Lead1.4E-05--3.6E-052.8E-057439-96-5 Manganese7.9E-04--4.8E-051.3E-047439-97-6 Mercury1.2E-06--4.4E-061.5E-0591-20-3 Naphthalene3.5E-05e1.3E-06f3.7E-05 7.3E-077440-02-0 Nickel< 4.6E-06--7.7E-051.7E-0485-01-8 Phenanthrene--e--f6.4E-07 6.5E-08108-95-2 Phenol----2.2E-05 6.7E-06115-07-1 Propylene------1.6E-03129-00-0 Pyrene--e--f1.2E-07 2.3E-087782-49-2 Selenium< 2.5E-05------108-88-3 Toluene--1.3E-041.6E-043.1E-041330-20-7 Xylene (total)--6.4E-053.7E-047.7E-047440-66-6 Zinc----1.2E-045.0E-03(continued)Version 2.1.1Final ICR Version – Corrected Section 4—Stationary Combustion Sources4-25Table 4-5. Summary of Emission Factorsfor Combustion Turbines Firing Various Fuelsa(continued)Note: lb/MMBtu = pounds per million British thermal unitsaSource: Hansell and England, 1998, Volume 1, unless otherwise specified.bBold italic values indicate that all test runs were below detection limit.cSource: U.S. EPA, 1995a, Section 3.1, Table 3.1-4 and Table 3.1-5. Emission factors are based on an average distillate oil heating value (HHV) of 139MMBtu/103gal.dSource: U.S. EPA, 1995a, Section 3.1, Table 3.1-3. Emission factors are based on an average natural gas heating value (HHV) of1,020 Btu/scf at 60°F.eThe emission factor for total polycyclic aromatic hydrocarbons (PAH) is 4.0E-05 lb/MMBtu.fThe emission factor for total PAH is 2.2E-06 lb/MMBtu.gHexavalent chromium is assumed to be twenty percent of the total chromium emission factor for the hexavalent chromium emissionfactor. The hexavalentchromium emission factors for boilers firing fuel oil is about 30percent of the total chromium emission factor (based on detection limits, which are expected tooverstate hexavalent chromium emissions)and 18 percent of the total chromium foroil-fired utilities (U.S. EPA, 1998c), so 20percent is expected to be areasonable approximation for hexavalent chromium emissions from distillate oil-fired combustion turbines.

### Version 2.1.1 Final ICR Version – Corrected Section 4—Stationary Combustion Sources

4-26 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

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 t echniques. This section describes the key process vents and emissions estimation procedures considering cont rols. At some facilities, the process gases may be routed to the refinery’s fuel gas system rather than directly to a control device to the atmosphere. These gases would then be combusted with the fuel gas in e ither a stationary combustion unit (process heater or boiler) or in a flare. As such, emissions from these ga ses are expected to be included in the emissions estimated for stationary combustion sources (see Secti on 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 fo r estimating the emissions associated with catalytic cracking units (CCUs), coking units, CRUs, sulfur r ecovery plants, and other process vents (e.g., from hydrogen (H 2 

### ) plants, asphalt blowing stills, coke calci ning 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 determ ining 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 Method Compositional Analysis Data

1 Continuous flow meter Continuous gas composition analyzer 2 Engineering estimates (e.g., F factor) Continuous gas composition analyzer 3 Continuous flow meter or engineering estimates Occasional grab samples 4 Measured process rates Site-specific 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 la rgest emissions vent at the refinery. The CCU is a catalytic process used to upgrade (crack) heavy distillat es 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 fo r 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 partic les 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, although data for PM, SO 2 

### and NO X 

### emissions are available for one TCCU. The emissions from the TCCU, when normalized on the basis of the coke burn-off rate, are similar to those of a similarly operated (uncontrolled) FCCU. Conse quently, while the emissions inventory methods presented in this section are based primarily on F CCU operation and emissions data, these emissions inventory methods should be used for TCCU systems unless direct emissions data are available.

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

5-2 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 reactions, coke is deposited on the cat alyst 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 co mbustion regenerators. In a complete co mbustion regenerator, the regenerator is typically operated at approxima tely 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 inco mplete) combustion regenera tor, the regenerator is typically operated at approxima tely 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 par ticles 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 circul ating 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. Va rious 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 catal yst 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 variet y of energy recovery or emissions control systems may be used to reduce pollutant releases. For a co mplete combustion CCU, a waste heat boiler is often used to recover the latent heat of th e flue gas. The energy recovery syst em 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 a partial com bustion CCU, the first control system is typically a CO boiler used to combust th e 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 VOC, it is anticipated that ma ny CCUs will have CEMS for measuring the composition of these pollutants in the exhaust gas. Although few CCUs are expected to have PM CEMS, if PM CEMS are used, these measurements would are also qualify as Methodology Rank 1 or 2 for CCUs even though some “PM augmentation” will be needed as described in Sections 5.1.2.1 and 5.1.2.2

. Similarly, if CEMS are used for specific HAPs, these measurements should be used and reported as Methodology Rank 1 or 2 for CCUs. 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 typi cally used to monitor the regenerator combustion parameters. When CEMS or direct-flow monitors ar e present, these data should be used to calculate annual pollutant emissions.
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 infreque ntly so the testing results represent an emissions rate at a given point in time a nd production level. Rather than assuming that the mass emissions rate measured during the test occurs continuously for a ll process operating hours, the resulting source test data are most appropriately used for developing a site-speci fic 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 b est correlated with coke burn-off rates; however, if CCU feed and operating conditions do not vary sign ificantly, then throughput-based emissions factors

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5-3 may be used. If multiple tests have been conducted on the CCU and no significant modifications have been made on the CCU or its control system, then an arithmetic average of the emission factors should be used to estimate annual average emissions. If modifi cations have been made on the CCU or its control system, the most recently performed source test shoul d be used to develop the site-specific emissions factor. To estimate maximum hourly emissions, the highest emission factor developed from the individual runs should be used along with the maximum cap acity (or coke burn-off rate) of the CCU.

Although site-specific emissions factors can be deve loped 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. Add itionally, a quasi Methodology Rank 4 for CCU metal

Example 5-1: Development of Site-Specific Emissions Factor A source test was performed to determine 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, respectivel y. The processing rates during the three runs were 1,600; 1,700; and 1,500 barrels per hour (bbl/h r) 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 factor for each individual r un should be calculated, and then the emissions factors should be averaged. Emissions factor s 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 coke 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 whic h 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 average, and the lowest single-run emissions factor is 5.9% lowe r 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 differences in the observed emissions than does throughput. Consequently, th e average coke burn-off emissions factor would be preferred to the throughput-based emissions factor in this example. The highest individual run emission factor, 0.866 lb/1,000 lbs coke burn-off in this example, would be used, along with the maximum hourly c oke burn-off rate during the year, to estimate the maximum hourly emission rate from this CCU.

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5-4 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 th e PM testing methods is needed. This subsection provides guidance and background information regard ing PM emissions, with a focus on the PM test methods, particularly those methods comm only used when testing the CCU vent.

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 of ten referred to as the “front-half” or “filterable” PM catch. PM that condenses in the impinger section of th e 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 Method 201 is 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 Method 201 determine PM 10 

### -FIL directly. EPA Method 201A, formerly EPA Other Test Method 27 (OTM 27), is similar to EPA Method 201 sampling at stack temperature, but uses a series of cylones to filter out, in succession, particles greater than 10 μm and 2.5 μm in diameter. The particle catch from the second cyclone can be used to determin e the PM emissions that are less than 10 μm in diameter but greater than 2.5 μm in diameter. The “filterable” catch from OTM 27 is a direct measure of PM 2.5 

### -FIL. Therefore, EPA Method 201A provides a means to directly determine PM-FIL, PM 10 

### -FIL, and PM 2.5 

### -FIL. PM CEMS, if used, generally measure only the filterable PM (i.e., PM-FIL).
Any of the Method 5, 17, or 201 variant methods desc ribe only the procedures to determine the front-half or filterable PM catch. EPA Method 202, formerly EPA Other Test Method 28 (OTM 28), uses a dry condensing chamber followed liquid impingers and specifies the procedures to determine the mass of condensable PM (i.e., PM-CON). Although Method 202 ge nerally 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

PM Emissions Inventory Nomenclature 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 c ondensable PM is assumed to be less than 2.5 microns (μm) in diameter (PM 2.5 ).

 PM 2.5 -PRI: “Primary” PM emissions that ar e 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. Although a complete PM emissions inventory includes PM emissions that are 10 μm in diameter or less, some measurement methods also collect PM particles that are greater than 10 μm in diameter. The following nomenclature is used to designate PM emissions that include PM greater than 10 μm in diameter:

 PM-PRI: “Primary” PM emissions of any pa rticle size. PM-PRI = PM-FIL + PM-CON.

 PM-FIL: Filterable (or front-half catch) portion of the PM emissions of any particle size.

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5-5 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, PM CEMS and EPA Methods 5 (inclu ding 5B or 5F) and 17 provide a measure of PMFIL; EPA Method 201 provides a measure of PM-FIL and PM 10 

### -FIL; and EPA Method 201A provides a measure of PM-FIL, PM 10 

### -FIL, and PM 2.5 

### -FIL. EPA Method 202 provides a measure of PM-CON. One important caveat to this is that, in Method 5F, ammo nia sulfate particulates are determined and subtracted from the total PM catch to determine the non-sulfat e PM emissions. Although the non-sulfate PM value may be used for compliance purposes (for the Petrol eum Refinery NSPS or for Refinery MACT II), emissions reported for the inventory should include th e total filterable PM catch. That is, the total PM catch before subtracting the sulfate PM emissions should be used to determine PM-FIL 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 

### ). 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 fo r uncontrolled CCU PM emissions, but it does contain typical control device default control efficiencies for different types of PM emissions control devices. A 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 PMCON is assumed to be less than 2.5 μm. The size dist ribution data guidance presented here is specific to FCCU. Facilities operating a TCCU should use site-specifi c size distribution data if available; otherwise, the default factors in Table 5-2 for a CCU with no pos t-regenerator PM control device should be used to project PM emissions by particle size. 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 Protocol 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 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 filter) 0.80 0.97



### 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 burnoff. The “back-half” catch was al so 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 coke 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 fo r the sulfate PM, because all of this PM is expected to be less than 2.5 μm. 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 c onsideration 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 calculation 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 = fraction < 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 μ m from Table 5-2 ) × PMnon-sulfate + PMsulfate = 0.8 × 109.6 + 31.3 = 119.0 tons/yr

PM 2.5 

### -PRI = PM 2.5 

### -FIL + PM-CON = 119.0 +70.5 = 189.5 tons/yr

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5-7 5.1.3 Methodology Rank 5A for CCU Metal HAP Emissions Estimates During CCU processing, metals deposit on the catalyst pa rticles 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 CC U 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 recirculat ing 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 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 s ite-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 equilib rium catalyst (i.e., the catalyst within the CCU, commonly referred to as “E-cat”) tested regularly fo r 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 ra te using the methodology described in this section. This Methodology Rank 5A for CCU metal HAP em issions 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-s pecific (non-sulfate, if available) PM emissions rate, and estimating the concentra tion of metal HAP on the emitted PM based on the concentration of metal HAP on the CCU fines or E-cat using the proce dures provided in this section. This method is not applicable for mercury (Hg) because it assumes the me tals 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 fin es. 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 annual metal HAP emissions based on the annual PM emissions rate and CCU fines metal HAP concentrations.



## mg/kg 000
, 000
, 1 i i 

## C FIL PM E ×

− = (Eq. 5-1)

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5-8 where:

E i 

### = Emissions rate of metal HAP “i” (tons/yr) PM-FIL = Filterable PM emissions rate from s ite-specific PM emissions factor; if EPA Method 5F is used, then use PMnon-sulf ate 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 meta l 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. If vanadium concentra tions are available but nickel concentrations are not, the nickel concentration should be calculated by dividing the vanadium concentration by the default ratio for vanadium in Table 5-3, and the calculated nickel con centrations and the default ratios in Table 5-3 then used to project the concentrations of other metal HAPs.

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
Vanadium d 1.32
Zinc d 0.74

a Concentration ratios are based on aver age electrostatic precipitator dust

analyses across six refineries.
b Limited data are available to assess the amount for hexavalent chromium that

is present, if any. If site specific data ar e not available, it is recommended that a default value of 10 percent of the total chromium emissions be used to estimate the hexavalent chromium emissions associated with the CCU.

c Selenium was highly variable, being significant for some units and below the

detection limit for several others. Consequently, this value is highly uncertain.
d Vanadium and zinc are not HAPs, but are included here (and in Table 1-1) as

other pollutants of interest.

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5-9 Although total chromium emissions have been f ound above detectable concentrations in the CCU regenerator vent, very few tests ha ve been performed to determine Cr +6 

### emissions. The few tests that have been performed have not found Cr +6 

### above detection limits, but the det ection limits have been comparable to the detected total chromium emissions. Emissions of Cr +6 

### from coal-fired power plants indicated that Cr +6 

### emissions were 11 percent of the total chromium emissions (U.S. EPA, 1998c). 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 be particulate bound. Mercury emissions are more likely correlated with the CCU throughput or coke burnoff rate. Thus, Hg emissions should be estimated i ndependently 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.

Example 5-3: Methodology Rank 5A for Metal HAP Emissions Estimates Following the previous example, PMnon-sulfat e emissions were calculated to be 109.6 tons/yr. If only Ni concentration for E-cat 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 equation should be used to calcu late 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 es timate 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 tons/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

E Vanadium 

### = 0.105 tons/yr × 1.32 = 0.14 tons/yr

E Zinc 

### = 0.105 tons/yr × 0.74 = 0.088 tons/yr

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5-10 5.1.4 Methodology Rank 5B for Catalytic Cracking Units For most organic HAP (e.g., formaldehyde, benzene, benzo[a]pyrene, dioxin/fura ns) and other pollutants such as hydrogen cyanide and Hg, default emissions fact ors may be all that are available. When direct emissions monitoring or site-specific emissions fact ors are not available, then the default emissions factors presented in Table 5-4 should be used to calculate the em issions from the CCU regenerator vent. Note that all CCU are considered “controlled for orga nics” if they meet the 500 ppmv CO emissions limit.

Table 5-4. Organic HAP Emissions Factor s for CCU Catalyst Regenerator Vent

CAS No. Compound Emissions Factor (lb/MMbbl) a Emissions Factor (lb/klb coke burn-off) b
Volatile Organics 75-07-0 Acetaldehyde 20 0.0013
67-64-1 Acetone 2.4 1.6E-4
107-02-8 Acrolein 1.0 6.6E-5
71-43-2 Benzene 18 1.1E-3
74-83-9 Bromomethane 2.1 1.4E-4 106-99-0 1,3-Butadiene 0.033 2.0E-6 100-41-4 Ethylbenzene 0.24 1.6E-5 50-00-0 Formaldehyde 260 0.016 75-09-2 Methylene chloride 6.7 4.4E-4
108-95-2 Phenol 8.7 5.7E-4
108-88-3 Toluene 3.5 2.1E-4
75-69-4 Trichlorofluoromethane 2.4 1.6E-4 1330-20-7 Xylene 3.2 2.1E-4
Semivolatile and Nonvolatile Or ganics(excluding dioxin/furans) 83-32-9 Acenaphthene 0.0033 2.2E-7 208-96-8 Acenaphthylene 0.13 7.8E-6
120-12-7 Anthracene 0.10 6.7E-6 56-55-3 Benzo(a)anthracene 0.00052 3.8E-8 50-32-8 Benzo(a)pyrene 0.011 7.1E-7 205-99-2 Benzo(b)fluoranthene 0.0035 2.4E-7 192-97-2 Benzo(e)pyrene 0.00045 3.3E-8 191-24-2 Benzo(g,h,i)per ylene 0.0046 3.1E-7 207-08-9 Benzo(k)fluoranthene 0.0026 1.8E-7 218-01-9 Chrysene 0.0033 2.3E-7 53-70-3 Dibenz(a,h)anthracene 0.0042 2.8E-7
206-44-0 Fluoranthene 0.093 6.1E-6
86-73-7 Fluorene 0.037 2.4E-6 193-39-5 Indeno(1,2,3-cd)p yrene 0.0044 3.0E-7 91-57-6 2-Methylnaphthalene 0.026 1.8E-6 91-20-3 Naphthalene 1.0 7.0E-5
85-01-8 Phenanthrene 0.24 1.6E-5 129-00-0 Pyrene 0.0031 2.2E-7 (continued)

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5-11 Table 5-4. Organic HAP Emissions Factors for CCU Catalyst Regenerator Vent (continued)

CAS No. Compound Emissions Factor (lb/MMbbl) a Emissions Factor (lb/klb coke burn-off) b

Dioxins/Furans
57117-31-4 Pentachlorodibenz ofurans 5.5E-07 3.2E-11
57117-44-9 Hexachlorodibenzofuran 1.1E-06 6.3E-11 35822-46-9 Heptachlorodibenzo- p-dioxin 9.4E-07 5.6E-11 Inorganics 7664-41-7 Ammonia 13,000 0.57

75-15-0 Carbon disulfide 0.56 3.7E-5 7647-01-0 Hydrogen chloride 1,800 0.11

74-90-8 Hydrogen cyanide 770 0.049 7439-97-6 Mercury 1.1 6.0E-5

a Emissions factors for CCU controlled for organics in pounds per million barrels of CCU feed.
b Emissions factors for CCU controlled for organics in pounds per thousand pounds of coke burn-off.



### The emission factors presented in Table 5-4 are b ased on the emission data collected to support the Refinery MACT 2 rule. While there appear to be s light differences in how outlier and non-detect values were handled, the emission factors in Table 5-4 agree well with the average emission factors developed by Bertrand and Siegell (2002).
Based on the lack of data for PAH and furan emissions, the emissions estimates for these compounds have high uncertainties, likely an order-of-magnitu de either high or low. The California Air Resources Board (CARB), with EPA’s support, conducted an emi ssions 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 (OCDF) and heptachloro-dibenzo-p-dioxin (hepta-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 polychl orinated 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 ar e three basic types of coking units: traditional fluid coking units, flexicoking units, and delayed coking un its. 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 flui d 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 syngas that can be subse quently 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 pa rticles are produced as a result of the thermal cracking

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5-12 process. Prior to exiting the coking unit, coke partic les 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 va riety 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 of methyl mercaptans and other reduced sulfur co mpounds that are not as efficiently removed from sour gas as is H 2 

### S. Consequently, SO 2 

### emissions from fuel gas combustion devices receiving fuel gas generated from a fluid coking unit should account for th is 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 10, 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 ra tes 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 em issions 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 co king 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 th e drum and begins to fill the drum with sponge-like solid coke material. Once filled, the feed is divert ed to the second coke drum. The full coke drum is cooled by slowly adding water to the vessel, which qui ckly 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 single coke drum is typically on-line receiving oil for 14 to 18 hours and then off-line for cooling and decoking for 14 to 18 hours, so a complete cycle time is approximately 28 to 36 hours.

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5-13 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 recovere d 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 rema ining steam and vapors to be released into the atmosphere prior to opening the drum. Emissi ons 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. At this time, however, no methods are available for estimating the direct organic releases during coke cutting. PM emissions from the coke cutting operations and subsequent coke storage and hand ling facilities should be estimated using the methodologies described in Section 10, Fugitive Dust Sources . The cutting water will absorb some hydrocarbons, so this water will also become a source of organic emissions; ther efore, organic emissions from impoundments, ponds, or open tanks used to store the cutti ng liquids should be estimated using the methodologies described in Section 7.2.5, Equalization Tanks

. As with fluid coking units, special c onsiderations 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 me rcaptans 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 periodi cally 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 pr ocess 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 b een performed on delayed coking unit vents. For facilities that have performed source tests, site-specifi c 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 de layed 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 co ncentrations and emissions factors were developed (see Table 5-5 ). While the emissions are expected to be highe r for units that start to depressurize 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 th e delayed coking unit steam vent and the limited test data available, correlations to acc ount 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.

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5-14 Table 5-5. Average Vent Concentrations and Em issions Factors for Delayed Coking Unit Vents

CAS No. Compound Vent Concentration (ppmv, wet basis) Emissions Factor (lb/cycle) a
106-99-0 Methane 7,600 200 74-84-0 Ethane 1,060 42

VOC Nonmethane/nonethane VOC 820 b 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
108-95-2 Phenol 0.12 1319-77-3 Cresols (total) 0.23 105-67-9 2,4-Dimethylphenol 0.086
62-53-3 Aniline 0.057

POM Total all POM 6.4 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)perylene 0.014 207-08-9 Benzo(k)fluoranthene 0.005 218-01-9 Chrysene 0.032 53-70-3 Dibenz(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.
b Concentration of VOC reported as propane.


## 5.4 Catalytic Reforming Units The CRU is a series of catalytic reactors that turn na phtha into high-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 operations: continuous, cyclic, and semi-regenerative. Continuous CRU catalyst regenerators operate continuously with a small slip stream of catal yst 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 regene ration of the offline reactor is a batch process. When complete, the reactor is returned to service, and the ne xt reactor is cycled offline and regenerated. This process continues until all reactors are regenerated. In a cyclic CRU, regeneration may occur for 1,000 to

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5-15 4,000 hours per year. The semi-regenerative CRU opera tes 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 atmos pheric vents. Although the location of the emission points might vary depending on whether catalyst regenera tion is continuous, cyclic, or semi-regenerative, there are three times or locations during the regene ration 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 catalyst purge vent. For cyclic and semi-regenerativ e 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. The gases generated from the initial depressurization and purge cycles are typically vented to the refinery fuel gas sy stem 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 primar y 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 cata lyst. The final purge and reduction cycle removes O 2 

### and any remaining chlorination agent from the syst em and reduces the catalyst prior to returning the CRU catalyst to the reforming process or bringing th e 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 or perchloroethene) and residual HCl or Cl 2 

### remaining in the system. The final purge gases are typically vented into the atmosphere or to the re finery 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 refinery fuel gas system).
5.4.1 Emissions Estimation Methodology for Catalytic Reforming Units Few data are available to characterize the emissi ons from the CRU catalyst regeneration vent because venting is infrequent, the vent flow rates are sl ow and usually variable, and the vents have small diameters. All of these factors make traditional source t esting difficult. Most of the available data are for HCl and Cl 2 

### emissions from uncontrolled coke burn vents (20 data points are available for HCl emissions; 10 data points are available for Cl 2 

### ). A few data points were available for a limited number of organic chemicals. These data are compiled in the Backgr ound 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 diox ins/furans, PCBs, and PAHs. The results from this source test, which were not available at the time for inclusion into th e Petroleum Refinery MACT II BID, were used to develop emissions factors for these compounds. The em issions 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 associati on with the coke-burn vent is a wet scrubber. The dioxin/furan emissions source tests and the volatile or ganics were performed on a system controlled by a wet scrubber. Because of the limited solubiliti es of these chemicals and the scrubbing medium recirculation rate used for wet scrubbers on this ve nt stream, the scrubber is assumed to have limited effectiveness at reducing the emissions of these chem icals. Therefore, the same emissions factor is recommended for these chemicals for both controlled and uncontrolled CRU. Wet scrubbers are used to reduce the emissions of HCl and Cl 2 

### . The wet scrubbers used for these ve nts were characterized into two classes: single-stage scrubbers and multiple-stage scrubbers. Single-stage scrubbers are estimated to

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5-16 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 into the atmosphere from these purge cycles, but these emissions should be characterized and reported in the inventory.

Table 5-6. Emissions Factors for CRU Catalyst Regeneration Vent

CAS No. Chemical Name Emissions Factor (lb/1,000 bbl) a 1746-01-6 Dioxin toxic equivalents (TEQ) b 5.7E-09 1336-36-3 Total polychlorinated biphenyls c 2.6E-06 91-20-3 Naphthalene 3.5E-05 91-57-6 2-Methylnaphthalene 1.3E-06 208-96-8 Acenaphthylene 3.0E-08 83-32-9 Acenaphthene 4.3E-08
86-73-7 Fluorene 2.0E-07
85-01-8 Phenanthrene 6.1E-07
120-12-7 Anthracene 9.1E-08
206-44-0 Fluoranthene 1.0E-07 129-00-0 Pyrene 1.5E-08 56-55-3 Benzo(a)anthracene 9.0E-10 218-01-9 Chrysene 2.9E-09 205-99-2 Benzo(b)fluoranthene 1.5E-09 207-08-9 Benzo(k)fluoranthene 7.5E-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 7.8E-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 Hydrogen chloride 4.2 d

7782-50-5 Chlorine 0.23 d

a Emissions factor in pounds pollutant emitted per 1,000 barrels of catalytic reforming unit process

capacity.
b Dioxin TEQ = toxic equivalents to 2,3,7,8-tetrachloro-dibenzo-p-diox in 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 each class of

chlorinated biphenyls (e.g., mono-, di-, tri-..., decachlorobiphenyl).
d Emissions factor for uncontrolled coke burn vent; controlled emissions should be estimated based on

the efficiency of the control device for these pollut ants. Single-stage scrubbers (including direct caustic injection) 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%

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5-17 

## 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 scrubbe rs. 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 re fineries, 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 recovery plant consists of one or more SRU opera ted in parallel and may al so 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 

### . Some sulfur recovery plants use reducing controls and thus emit H 2 

### S rather than SO 2 

### . 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 th at may have atmospheric vents without thermal destruction.
When the sulfur recovery plant is in operation, the sulf ur plant vent flow rate is fairly small so that the SO 2 

### emissions from the sulfur recovery plant are also re latively 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 backup sulfur recovery unit or directed to a flare or the thermal oxidizer. If the sour gas in these cases is sent to a flare or thermal oxidizer, 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.
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 me asurements and assumed recovery efficiencies. For most Claus units, especially those with tail gas tr eatment/recovery units, a mass balance approach for sulfur is expected to yield emissions estimates w ith high uncertainties (e.g., when two large numbers are subtracted so that the difference is only a few percen tages of the original valu es, the uncertainties in the original values may be as large as the difference). A three-stage Claus unit is expected to have sulfur

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5-18 recovery efficiencies of 95% to 97%. Combining a th ree-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 su lfur 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 ac curate than using a mass balance approach when calculating sulfur compound emissions from the sulfur r ecovery 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 g ases to the sulfur recovery plant can be used to accurately estimate CO 2 

### emissions.
Given the high uncertainty expected in engineering/m ass-balance calculations for sulfur recovery plants, site-specific emissions factors may be as or more usef ul than using an engineering/mass-balance approach for calculating emissions from sulfur recovery plan ts, particularly sulfur compound emissions. Sitespecific emissions factors are also recommended for re ductive tail gas treatment units not followed by an incinerator and for non-Claus sulfur recovery pl ants. 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 fro m 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 Nationa l 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 Emissions Factor (lb/lton) a Uncontrolled SRU Emissions Factor (lb/lton) a 43-58-1 Carbonyl sulfide 0.12 5.85 b

75-15-0 Carbon disulfide 0.040 2.00 b Note: lb/lton = pou nds per long ton

a Emissions factor in pounds of HAP per long-ton of sulfur produced.
b Values estimated as 50 times the controlled SRU emissions factor.



## 5.6 Other Miscellaneous Process Vents There are many other process vents at a refinery; ho wever, there are limited data for these vents, so default emissions factors are not available. Fo r 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. For atmospheric vents asso ciated with continuous monitoring systems, the flow rate and composition of the purge d gases should be well characterized and emission estimates can be developed using Meth odology Rank 1 for process ve nts. For other process vents, measurement data may not be available. Engineering or model estimates ca n be used to estimate the uncontrolled emissions. If

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5-19 the emissions are subsequently controlled, the actual emissions can be estimated based on the efficiency of the control device. 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 r eactors 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 f actors are available at this time for the hydrogen plant vent.
5.6.2 Asphalt Plant Vents Asphalt blowing is used for polymerizing and stabilizi ng asphalt to improve its weathering characteristics. Air-blown asphalts are used in the production of asp halt roofing products and certain road asphalts. Air blowing of asphalt may be conducted at petroleu m refineries, asphalt processing plants, and asphalt roofing plants. Asphalt blowing involves the oxida tion of asphalt flux by bubbling air through liquid asphalt flux at 260°C (500°F) for 1 hour to 10 hour s. 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 em issions from a blowing still are primarily organic particulate with a fairly high concentration of g aseous hydrocarbon and polycyclic organic matter. The blowing still gas is commonly controlled with a we t scrubber to remove sour gas, entrained oil, particulates, and condensable organics and/or a th ermal oxidizer to combust the hydrocarbons and sour gas to CO 2 

### and SO 2 

### . Overall PM and TOC emissions factors for asphalt blow ing 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, 1995a)

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 asphalt 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.

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5-20 Tumbore (1998) provided an additional summary an d 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.

Table 5-9. Asphalt Blowing – Nonmethane Volatile Organic Compounds Speciation a

Compound % Weight
Ethane 6.0 Propane 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 have 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 Oxidizer (lb/MMBtu) b Without Blow Cycle and with Thermal Oxidizer (lb/MMcf) b Without Blow Cycle and with Thermal Oxidizer (lb/MMBtu) b
75-07-0 Acetaldehyde 1.8E-03 1.67E-06 4.3E-03 4.1E-06
7440-28-2 Arsenic 1.3E-02 1.2E-05 1.2E-02 1.1E-05

71-43-2 Benzene 3.2E-01 3.0E-04 2.8E-01 2.6E-04 7440-41-7 Beryllium 2.6E-03 2.5E-06 2.3E-03 2.2E-06
7440-43-9 Cadmium 5.3E-03 4.9E-06 4.7E-03 4.4E-06 (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

5-21 Table 5-10. Summary of Emissions Factors for Controlled Asphalt Blowing (continued)

CAS Number Substance Mean Emissions Factor a

With Blow Cycle and Thermal Oxidizer (lb/MMcf) b With Blow Cycle and Thermal Oxidizer (lb/MMBtu) b Without Blow Cycle and with Thermal Oxidizer (lb/MMcf) b Without Blow Cycle and with Thermal Oxidizer (lb/MMBtu) b

18540-29-9 Chromium (hexavalent) 3.2E-03 3.0E-06 3.3E-03 3.1E-06

7440-47-3 Chromium (total) 4.2E-02 3.9E-05 1.4E-02 1.3E-05 7440-50-8 Copper 4.8E-02 4.5E-05 3.8E-02 3.6E-05 100-41-4 Ethylbenzene 8.6E-01 8.1E-04 7.6E-01 7.2E-04 50-00-0 Formaldehyde 3.6E-0 3 3.3E-06 1.3E-02 1.2E-05 7647-01-0 Hydrogen chloride 2.2E -03 2.1E-06 8.2E-04 7.7E-07 7783-06-4 Hydrogen sulfide 2.1E+00 2.0E-03 1.8E+00 1.7E-03
7439-92-1 Lead 5.3E-02 4.9E-05 4.7E-02 4.4E-05 7439-96-5 Manganese 1.2E-01 1.2E-04 2.1E-01 2.0E-04 7439-97-6 Mercury 9.1E-03 8.5E-06 8.5E-03 8.0E-06
7440-02-0 Nickel 6.7E-02 6.3E-05 6.0E-02 5.7E-05
108-95-2 Phenol 7.6E-02 7.1E-05 4.6E-02 4.4E-05
7782-49-2 Selenium 1.3E-02 1.2E-05 1.2E-02 1.1E-05 1330-20-7 Xylene (total) 8.6E-01 8.1E-04 7.6E-01 7.2E-04
7440-66-6 Zinc 8.4E-01 7.9E-04 5.4E-01 5.0E-04 Note: lb/MMcf = pounds per million cubic feet asphalt fume s, lb/MMBtu = pounds per million British thermal units

a Bold italic values indicate that a ll 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/MMBtu b
83-32-9 Acenaphthene 1.5E-08 4.4E-08 208-96-8 Acenaphthylene 1.8E-08 5.6E-08 75-07-0 Acetaldehyde 1.0E-03 3.1E-03
107-02-8 Acrolein 3.4E-04 1.0E-03
120-12-7 Anthracene 1.8E-08 5.4E-08 (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

5-22 Table 5-11. Summary of Emissions Factors for Controlled Coke Calcining (continued)

CAS Number Substance Mean Emissions Factor a

lb/ton coke b lb/MMBtu b
7440-36-0 Antimony 4.6E-05 1.4E-04
7440-28-2 Arsenic 4.7E-06 1.5E-05
7440-39-3 Barium 2.0E-05 6.1E-05

71-43-2 Benzene 3.2E-04 1.0E-03 56-55-3 Benzo(a)anthrac ene 8.7E-09 2.6E-08 50-32-8 Benzo(a)pyrene 8.1E-09 2.4E-08 205-99-2 Benzo(b)fluoranthene 8.1E-09 2.4E-08 191-24-2 Benzo(g,h,i)perylene 8.1E-09 2.4E-08 207-08-9 Benzo(k)fluoranthene 8.1E-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 (hexavalent) 6.3E-07 2.1E-06 7440-47-3 Chromium (total) 2.1E-05 6.9E-05 218-01-9 Chrysene 1.3E-08 3.7E-08 7440-50-8 Copper 9.3E-06 2.9E-05

53-70-3 Dibenz(a,h)anthracene 8.1E-09 2.4E-08
1746-01-6 Dioxin:4D 2378 1.1E-11 3.7E-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 1.4E-11 4.4E-11
19408-74-3 Dioxin:6D 123789 1.3E-11 4.2E-11
Dioxin:6D Other 6.4E-11 2.1E-10
35822-46-9 Dioxin:7D 1234678 1.4E-10 4.2E-10
Dioxin:7D Other 1.3E-10 4.1E-10
3268-87-9 Dioxin:8D 1.8E-09 5.3E-09
206-44-0 Fluoranthene 3.6E-08 1.1E-07
86-73-7 Fluorene 5.6E-08 1.7E-07 50-00-0 Formaldehyde 3.4E-04 1.0E-03
51207-31-9 Furan:4F 2378 1.3E-11 4.2E-11
Furan:4F Other 1.4E-10 4.4E-10
57117-41-6 Furan:5F 12378 1.4E-11 4.4E-11
57117-31-4 Furan:5F 23478 1.3E-11 4.1E-11
Furan:5F Other 1.2E-10 3.8E-10 (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

5-23 Table 5-11. Summary of Emissions Factors for Controlled Coke Calcining (continued)

CAS Number Substance Mean Emissions Factor a

lb/ton coke b lb/MMBtu b

70648-26-9 Furan:6F 123478 2.4E-11 7.9E-11
57117-44-9 Furan:6F 123678 2.2E-11 7.1E-11
72918-21-9 Furan:6F 123789 9.2E-12 3.0E-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 4.8E-10
55673-89-7 Furan:7F 1234789 2.6E-11 8.0E-11
Furan:7F Other 5.2E-11 1.8E-10
39001-02-0 Furan:8F 1.5E-10 4.1E-10

193-39-5 Indeno(1,2,3-cd)pyrene 8.1E-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 1.5E-04

91-20-3 Naphthalene 2.4E-06 7.3E-06
7440-02-0 Nickel 9.1E-05 2.9E-04

85-01-8 Phenanthrene 1.9E-07 5.7E-07 7723-14-0 Phosphorus 4.7E-04 1.5E-03 129-00-0 Pyrene 2.7E-08 7.9E-08
7782-49-2 Selenium 4.7E-06 1.5E-05
108-88-3 Toluene 5.3E-05 1.6E-04 1330-20-7 Xylene (m,p) 3.1E-05 8.9E-05

95-47-6 Xylene (o) 4.5E-05 1.3E-04
7440-66-6 Zinc 1.2E-04 3.7E-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-Tetr achlorodibenzo-p-dioxin; 5D 12378 = 1, 2,3,7,8-Pentachlor odibenzo-p-dioxin;

6D 123478 = 1,2,3,4,7,8-Hexachlorodi benzo-p-dioxin; 6D 123678 = 1,2,3,6, 7,8-Hexachlorodibenzo-p-dioxin; 6D 123789 = 1,2,3,7,8,9-He xachlorodibenzo-p-dioxin; 7D 1234678 = 1,2, 3,4,6,7,8-Heptachlor odibenzo-p-dioxin; 8D = Octachlorodibenzo-p-dioxin; 4F 2378 = 2,3,7, 8-Tetrachlorodibenzofuran ; 5F 12378 = 1,2,3,7,8- Pentachlorodibenzofuran; 5F 234 78 = 2,3,4,7,8-Pentac hlorodibenzofuran; 6F 123478 = 1,2,3,4,7,8- Hexachlorodibenzofuran; 6F 12367 8 = 1,2,3,6,7,8-Hexachlorodibenzofuran; 6F 123789 = 1,2,3,7,8,9- Hexachlorodibenzofuran; 6F 23467 8 = 2,3,4,6,7,8-Hexach lorodibenzofuran; 7F 1234678 = 1,2, 3,4,6,7,8- Heptachlorodibenzofuran; 7F 1234789 = 1,2,3,4,7,8,9-Hept achlorodibenzofuran; 8F = Octachlorodibenzofuran.

a Emissions factors provided are for coke calcining controlled with a spray dryer and fabric filter. Bold italic values

indicate that all test runs were below detection limit; und erlined values indicate that more than 75% of the test runs were below the detection limit.
b Source: 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 co mpressed 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

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

5-24 would be considered a “controlled” blowdown syst em. In an “uncontrolled” blowdown system, the uncondensed gases are vented directly to the atmosphe re. 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). For blowdown gases that are vented to a flare, the emissions from these gases would be accounted for in the emissions proj ected for flares if Methodology Rank 1, 2, 3, or 4 for flares is used (see Section 6).
AP-42 (U.S. EPA, 1995a) contains default emission factors for uncontrolled blowdown systems as well as blowdown systems that recover the vapors for destructi on 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 originating from blowdown gases. The AP-42 defa ult emission factors for blowdown systems are provided in Table 5-12 . For blowdown gases that are vented to co ntrol device other than a flare, use the methodologies for direct process vent measurement pr ovided in this section, if appropriate data are available. If appropriate data are not available, use the emission factors for “blowdown systems with vapor recovery and flaring” in Table 5-12 for blowdown vents controlled with a thermal oxidizer, catalytic oxidizer, or similar combustion control syst em; for other control systems, use the uncontrolled blowdown default THC emissions factor provided in Table 5-12 and adjust for the efficiency of the control device using the default control efficiencies provided in Table 3-2 (Section 3, Storage Tanks ).

Table 5-12. Default Emissions Factors for Blowdown Systems

Process Description Pollutant Emissions Factor 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 dioxide 27 C Total hydrocarbons b 0.8 C

a Source: U.S. EPA, 1995a.
b Total hydrocarbon may be estimated as a surrogate for VO C. (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 blowers 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 of crude oil is typically the largest vacuum producing system at a petroleum refinery; vacuum producing systems may also be used to evacuate reac tor vessels or vacuum trucks. AP-42 provides a total hydrocarbon emission factor for the vacuum dis tillation column condenser, which is provided in Table 5-13 . 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.

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

5-25 Table 5-13. Default Emissions Fact or for Vacuum Producing Systems

Process Description Pollutant Emissions Factor a (lb/10 3 barrel of vacuum feed) Rating Vacuum producing system on vacuum distillation column, uncontrolled 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 total

hydrocarbon emissions is methane.)

### Version 2.1.1 Final ICR Version – Corrected Section 5—Process Vents

5-26 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Section 6—Flares

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 combus tion. 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 difficu lt to obtain because they do not lend themselves to conventional emissions-testing techniques, and only a fe w attempts have been ma de 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, pr ovide a direct emissions measurement technique for flares. However, DIAL measurements provide only a sn apshot in time. Unless the flow and composition of the flare gas is highly stable, inaccuracies build as these measurements are extrapolated to annual emission 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 monito rs 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 add ition, 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 inside the tank, the pressure outside the tank, the crosssectional area of the valve opening, and the dur ation the valve is open (see Section 12, Malfunctions/Upsets , in this Refinery Emissions Protocol document. Product knowledge of the tank liquid composition can be used to calculate the equ ilibrium vapor space composition, which is assumed to be the composition of the gas vented. Some emi ssion factors are available, but these have high uncertainty. EPA concludes that direct measurement methods are best used to develop site- or flarespecific emission factors or to verify the combus tion 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 emissi ons estimation techniques. Within a given measurement method (or rank), there may be alterna tive methods for determining the constituent-specific emissions; these compositional analysis methods are pr ovided in order of accuracy. Each refinery will likely use a mixture of different methods. For exam ple, Methodology Rank 1 for flares may be used for events that are directly monitored and are fairly routine releases, but Met hodology Rank 4 for flares may have to be used to estimate emissions for unusua l events. The remainder of this section provides additional detail and guidance regardi ng the implementation of these methods.

### Version 2.1.1 Final ICR Version – Corrected Section 6—Flares

6-2 Table 6-1. Summary of Flare Emissions Estimate Methodologies

Rank Measurement Method Additional Data Needed

1 Continuous composition monitoring (or manual sampling at least once every 3 hours during flaring events) and continuous 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 daily or weekly compositional analysis 

##  Representative sample (grab or integrated)



##  Assumed combustion efficiency
3 Continuous flow rate and heating value monitoring 

##  Emission factors based on heating value

4 Engineering calculations 

##  Process knowledge of units connected to flare (e.g., volume, composition of process streams)



##  Temperature and pressure monitoring data or other

process operating data as needed



##  Assumed combustion efficiency
5 Emission factors based on energy consumption 

##  Flow estimates (not continuous)



##  Heat value estimates (not continuous)
6 Default emission 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 me asuring composition and flow of gas sent to the flare. For flares that do not have routine flow, manual sampling of the flare gas at least once every 3 hours during each flaring event is also considered Methodol ogy Rank 1 for flares. 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, monitori ng 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 concentrati ons in the gas sent to the flare rath er than the gas exiting the flare, the other piece of information needed to estimate em issions 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 th e 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 emission rate.
As noted above, direct measurement methods are availa ble 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 fo r 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 whet her this combustion efficiency continues to be appropriate for properly operated flares. At this tim e, sufficient data have not yet been collected and evaluated to support revising this efficiency estimate.
Most gas composition monitors measure the concen tration on a volume basis (and generally on a dry basis), although some will provide the concentrati on on a mass basis. Most flow monitors measure

### Version 2.1.1 Final ICR Version – Corrected Section 6—Flares

6-3 volumetric flow rate in actual cubic feet. Many flow monitoring systems are equipped with temperature and pressure monitors to automatically convert the fl ow to standard conditions. If the gas composition is determined on a dry basis, which is typical for extract ive monitoring systems, then it is important to also correct the flow to be on a dry basis. The total volum etric flow of the pollutant can be converted to a mass emission rate using the molecular weight of the pollu tant and/or the ideal gas law, as appropriate. An emissions estimate can be calculated using Equation 6-1, which is a va riation of Equation 4-1 for CEMS:


# () ( ) 

# [ ] ( )

100% 1

1 20 

# ∑

= 

## ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × × × ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

×

− × = N

n i n i eff

o n

n o

n H n i 

## K MVC MW C K P P
T T f Q E (Eq. 6-1)

where:

E i 

### = Emission rate of pollutant “i” (tons per y ear [tons/yr] or tons per event [tons/event]). N = Number of measurement periods per year or per event (e.g., for hourly measurements, N = 8,760 to calculate annual emissions). n = Index for measurement period. (Q) n 

### = Volume of gas sent to the flare for measurement period “ n ” (actual cubic feet [acf]). If the flow rate meter automatically correct s 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 automati cally 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). T o 

### = Temperature at “standard conditions” (520 °R or 528 °R). T n 

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

### = Average pressure at which flow is meas ured during measurement period “n” (atm). P o 

### = Average pressure at “standard conditions” (1 atm). 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 ga s, such as VOC, reduced sulfur, and specific HAP. (C i 

### ) n 

### = Concentration of pollutant “i” or the appr opriate precursor to pollutant “i” in the gas sent to the flare 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 (standard cubic feet per kilogram mole [scf/kg-mol]) = 836.6 scf/kg-mol at “standard condition s” of 60°F (520°R) and 1 atmosphere (atm) = 849.5 scf/kg-mol at “standard conditions” of 68°F (528°R) and 1 atm. 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 multip le measurements per hour, and the individual measurements can be used to calculate annua l emissions in two ways. For a flare, the selection of an hourly average approach or heavier relia nce on individual measurements will depend on the duration of the flare’s operation (particularly for fl ares that operate only intermittently) and the process 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 dete rmining composition by continuously monitoring a “surrogate” component, and then using sampling or othe r data to periodically check a correlation between

### Version 2.1.1 Final ICR Version – Corrected Section 6—Flares

6-4 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 

### emissions similar to the process describe d for Methodology Rank 1, but because H 2 

### S is only one of several sulfur compounds potentially present in the flar e 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-toH 2 

### S ratio of the flare gas. Th is 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 d estruction of pollutants in the flare will depend on the flare combustion efficiency. As mentioned previous ly, 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 hea ting value of the fuel, and emission 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: 

# ( ) ∑

= 

## × × = N

n i n n std i 

## EF LHV Q E

1 , 

### (Eq. 6-2)

where:

E i 

### = Emission rate of pollutant “i” (lbs/yr or lbs/event). N = Number of measurement periods per year or per event (e.g., for hourly measurements, N = 8,760 to calculate annual emissions). n = Index for measurement period. Q std,n 

### = Volume of gas sent to the flare for meas urement period “n” (scfm). If the flow meter does not output flow at “standard conditions,” the Q std,n 

### can be calculated using the first four terms within the summation of Equa tion 6-1. Note: the “standard conditions” used for the volume of gas must match th e “standard conditions” at which the heating value of the gas is determined. LHV n 

### = Heating value of gas being flared duri ng measurement period “n” on a lower heating value (LHV) basis (MMBtu/scf). (Heating value for flares is usually determined on a lower (net) heating value (LHV) basis wher eas heating value for process heaters and boilers are usually determined on a higher heating value basis.) EF i 

### = Emission 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 emission factors are intended for use with properly op erating flares meeting the criteria of 40 CFR 60.18; therefore, the flare efficiency is already included in th ese emission factors. It is also important to note that the number of components for which emission factors are available is limited because these emission factors are based on general combustion characteristics and limited emission tests. For example, the emission factors for NO x 

### are generally based on the amount of nitr ogen in the air during combustion, so if there are constituents containing nitrogen in the fuel gas, such as ammonia, additional calculations are

### Version 2.1.1 Final ICR Version – Corrected Section 6—Flares

6-5 needed to account for all NO x 

### emissions (based on Methodology Rank 2 for flares, particularly if flow rate is monitored continuously.)

The emission factors in Table 6-2 are from Section 13.5 of EPA’s Compilation of Air Pollutant Emission Factors (U.S. EPA, 1995a, also known as AP-42) and have an emission factor rating of “B” (U.S. EPA, 1995a, for details on the emission factor rating system). These flare emission factors are based on limited EPA tests conducted decades ago. Although AP-42 do es not specify, it is common practice that the heating value for flares is determined on a LHV b asis. As such, it is recommended that these emission factors be used with LHV heat content measurements.

Table 6-2. Flare Energy Cons umption-Based Emission Factors

Component Emission Factor a (lb/10 6 Btu, LHV basis) Total hydrocarbons b 0.14 Carbon monoxide (CAS No. 630-08-0) 0.37 Nitrogen oxides 0.068

a Source: U.S. EPA, 1995a. Assumes values are reported on a LHV basis.
b Measured as methane equivalent.



### The emission factors in Table 6-3 are from Technical Supplement 4 of TCEQ’s 2008 Emissions Inventory Guidelines (TCEQ, 2009). The emission factor rating for these emission factors is not specified. These flare emission factors are intended to be used with LHV, or net heating value, heat content measurements.
Table 6-3. TCEQ Energy Consumptio n-Based Emission Factors for Flares

Component Assist Type Waste Gas Stream Net Heating Value a Emission Factor (lb/MMBtu. LHV basis) b

Nitrogen oxides Steam High Btu 0.049

Low Btu 0.068

Air or Unassisted High Btu 0.14

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.



### Additional emission factors for soot (i.e., PM) are also provided AP-42; however, the soot factors provided in units of concentration in the flare exhaust stream. These factors have been converted to heating value-based factors to allow calculation of s oot (PM) emissions using Equation 6-2. To calculate the soot (PM) emissions from flares, each measurement period would be assigned a flare operation category based on the amount of smoke generated by the flare during that measurement period, so the appropriate emission factor could be applied.

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6-6 Table 6-4. Emission Factor s for Soot from Flares

Flare Operation Emission Factor a (μg/L in exhaust) Emission Factor b (lb/MMBtu, LHV basis)
Nonsmoking flares 0 0.0 Lightly smoking flares 40 0.027 Average smoking flares 177 0.12 Heavily smoking flares 274 0.19

a Source: U.S. EPA, 1995a; reported as micr ograms per liter (μg/L) in flare exhaust.
b Calculated from concentration using F-fa ctor method on a dry basis, assuming 3% O 2 in exhaust

gas stream.



## 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 fro m flares can be calculated using this rank based on process knowledge of units connected to the flar e, 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 specifi c methods used will vary based on the ways in which the flare is used and the units the flare serve s. 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

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: 

# ( )

1 

# ∑

= 

## ××× = N

n CO Nnn CO 

## EFMFRHV E

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 remained 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 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 di fferences between them. When emissions are estimated using Methodology Rank 4 for flares, a descripti on of the methodology, assumptions, and specific pieces of data should be recorded and kept for future re ference, both to document the emissions calculation methodology and to ensure consis tency from one estimate to the next for a particular process.
For routine or planned releases from flares not equipp ed with a continuous monitor, the refiner should know the quantity and composition of the gas being rel eased. If the gas is excess fu el 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 g as 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 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 em ptying 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 dur ing 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) cont ributing 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 ga s 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 emission factors have been developed for flares. Available emission factors for flares were provided in Tables 6-2, 6-3, and 6-4 for use with continuous flow and heat content monitoring. Methodology Rank 5 for fl ares consists of using these same emission factors, but with estimates of the flow rate a nd heating content of the flare gas rather than direct measurement of these values. The total hydrocarbon emi ssion factor could be used with knowledge of the components in the flare gas to estimate HAP emissions.
Methodology Rank 6 for flares includes emission 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 emission 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 emission factors from the State of Louisiana’s title V permit applications da ta were calculated and are provided in Table 6-5 . These emission factors yield a cumulative emission estimate from all flares (not per flare) for the refinery based on the total refinery crude capacity in barrels per cal endar day (bbl/cd). It is uncertain how the permit

### Version 2.1.1 Final ICR Version – Corrected Section 6—Flares

6-8 application estimates were developed and whether these estimates include SSM events, but it is likely that these factors would not include emissions relea sed during significant SSM events. As such, these emission factors are very general and are not reco mmended 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 Emission Factors a

CAS Number Component Emission Factor (tons/yr/bbl/cd)

71-43-2 Benzene 9 E-06

108-88-3 Toluene 7 E-06 1330-20-7 Xylene 6 E-06 1634-04-4 Methyl tertiary-butyl ether 3 E-06

110-54-3 Hexane 1 E-05 50-00-0 Formaldehyde 1 E-06 100-41-4 Ethylbenzene 2 E-07
106-99-0 1,3-Butadiene 7 E-06

a Source: Log-mean average from State of Louisiana’s title V permit

applications data



### The application of these emission factors is straightforward, using Equation 6-3.

i i 

# EFCapE × = (Eq. 6-3)

where:

E i 

### = Mass emissions per year of pollutant “i” (tons/yr) Cap = Crude capacity of refinery (bbl/cd) EF i 

### = Emission factor for pollutant “i” (tons/yr/bbl/cd)
Example 6-2 shows the calculation of emissions from fl ares at a refinery with a given crude capacity.

Example 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:

66 66 HC HC 

# EFCapE × =

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 operati ons range from simple pre-treatment operations that discharge to publicly owned treatment works (POTW) to full-scale wastewater treatment systems. Fullscale 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 we irs. 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 refine ries are to: (1) equalize flow and pollutant load by buffering flow surges in large tanks, (2) separate free a nd 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 re moval or destruction system s (e.g., stream strippers, enhanced biodegradation units) at most petroleum refineries are regulated under BWON (Benzene Waste Operations NESHAP) and thus should be covered and vented to appropr iate 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, emission estimation methods are presented in this Refinery Emissions Protocol do cument. Biological treatment units are typically the first uncovered process in the wastewater treatment system and thus the first air emission source.

Table 7-1 lists the emission estimation methods for wastewater treatment systems. The methods are ranked according to anticipated reliability. There ar e three primary estimation methods: (1) direct measurement, (2) predictive modeling, and (3) engi neering estimates. Direct measurements can only be

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-2 taken from process units that are covered and vented to a control device. Predictive modeling can be accomplished using analytical equations, such as those presented in AP-42, by using computer-based fate and transport models (e.g., WATER9, TOXCHEM), or by using the simplified refinery wastewater emission tool (RWET) presented in this Refinery Em issions Protocol document. Engineering estimates can be made using emission factors based on crude throughput or wastewater load.

Table 7-1. Summary of Wastewater Treatment Emission 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 sitespecific 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 sitespecific factors and biodegradation rates Uncovered units  Constituent load and speciation of process wastewaters

 Site-specific biodegradation rates
2c Predictive modeling with sitespecific 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 Wastewater Treatment Units
Emissions from covered and vented wastewater treatme nt units and drainage system components can be directly measured using CEMS or periodic samp ling; emission inventory estimates for these vented sources can be developed using the methods summarized in Section 4, Stationary Combustion Sources
, and Section 5, Process Vents , of this Refinery Emissions Protocol document.
Although there are direct measurement methods for unc overed units (i.e., off gas collectors and open path optical methods such as DIAL), these methods do not provide continuous mon itoring data. Therefore, these methods are not recommended as primary techniques for emission estimations, but are reasonable for predictive modeling validation.


## 7.2 Methodology Rank 2 for Wastewater Treatment Units Air emission estimation modeling techniques use mathema tical equations to predic t the fate and transport of specific constituents in wastewater. This section d escribes some key wastewater treatment units and the applicable methods for estimating the emissions fro m these units. Wastewater collection systems are considered an initial wastewater treatment unit to account for the emissions.
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 emission tool (RWET) has been developed as part of this document to address these issues and provide more accurate comparisons among refineries. RWET was designed to help the user identify critical model inputs for each process unit, r ecognize variables and constants that may be sitespecific, 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).

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-3 The “Critical Inputs” section of the refinery wastewater emission tool includes data that is required to estimate air emissions from the specific process un it. 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, a nd 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 emission tool.

Since reliable variables to estimate emissions for a ll volatile organic compounds (VOC) are not available, air emission estimates for compounds not listed in th e 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 emission tool. Air emission estimates fo r compounds not listed and considered non-volatile (e.g., > C 9 

### and Henry’s law constant > 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: 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

The calculations used in RWET and variable defin itions are based on those presented in AP-42 and on peer-reviewed journals and are pr esented in detail in Appendix B, Wastewater Treatment System Equations , of this Refinery Emissions Protocol docume nt. RWET is available for free at the following EPA website: http://www.epa.gov/ttn/chief/efpac/esttools.html

. 7.2.1 Wastewater Collection Systems Wastewater collection systems are complex networks of various components that drain large surface areas. These complexities make accurately estima ting air emissions a very challenging task. RWET utilizes process drainage areas (PDAs), shown schematically in Figure 7-2 , to more-easily estimate air emissions. Rather than summing all of the drains a nd other components within the processing area, model drainage systems are developed for each PDA. The model drainage components are based on the typical (or reasonable worst-case) components that an indi vidual waste stream will experience. In the top drainage area of Figure 7-2 , an individual waste stream would experience typically two drains (or, for a worst-case assessment, three drains), one junction box , one manhole cover, and a lift station. For the lower drainage area of Figure 7-2 , an individual waste stream in this area would experience typically two drains (or, for a worst-ca se assessment, three drains), a length of open trench (from either the middle or furthest most drain for the typical or worst-case as sessment, respectively), one sump, and a lift station. Each of the model drainage system components may be identified as either controlled or uncontrolled. Components meeting the requirements for controlle d drainage components in BWON are considered controlled components. The drainage components do not necessarily have to be subject to BWON to be

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-4 considered controlled, only that the specified contro ls are used (e.g., water seals for drains, gasketed manhole covers, or drainage systems vented to a control device).
For each PDA, the wastewater generation rate and po llutant concentration at the point of generation (POG) are needed to determine the pollutant load to the system. Model drainage components, constituent load, and control efficiencies are th en utilized within RWET to estimate air emissions for a given PDA. The emissions from each PDA are then combined to obta in the total for the wastewater collection system. More details of this method are presented in Appendix B, Wastewater Treatment System Equations

. Table 7-2 lists the critical inputs, variables with defa ult values, and chemical properties specific to wastewater collection system PDAs.
As previously stated, RWET utilizes model drainage system components to ease the complexity of estimating air emissions from collection systems. Ho wever, if system components (e.g., lift stations, junction boxes, and sumps) vary greatly from those de scribed in the Best Available Control Technology/ Lowest Achievable Emission Rate (BACT/LAER), site -specific air emissions can be determined from the procedures described in Appendix B, Wastewater Treatment System Equations

.

Figure 7-2. Typical refinery wastewater collection system process drainage areas.

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-5 Table 7-2. Critical Inputs and Chemical Properties Specific to Wastewater Collection System PDA Air Emission Calculations
Critical Inputs Variables with Default Values Chemical Properties
Number of drains Controlled / Unc ontrolled Henry’s Law Constant (H) Linear meters of open trench Control Efficiency
Number of manholes Number of junction boxes
Number of lift stations Number of sumps Wastewater flow rate (Q) Constituent concentration at POG (C 0 )


### 7.2.2 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 emission estimations are not require d. However, if the treatment units are uncovered, then the refinery wastewater emission tool can be used to estimate air emissions. Table 7-3 lists the critical inputs, variables with default values, and chemical properties specific to weirs. Table 7-3. Critical Inputs, Variabl es, and Chemical Properties Specific to Primary Weir Air Emission Calculations
Critical Inputs Variables with Default Values Chemical Properties Wastewater flow rate (Q) Diffu sivity of oxygen in water (D O2,w ) Diffusivity of constituent in water (D w ) Constituent influent concentration (C 0 ) Weir height (h)



### 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 vent ed; therefore, open-air emission estimations are not required. However, if th e treatment units are uncovered, then the refinery wastewater emission 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.
If an oil-water separator is covered except for the e ffluent weir, air emissions can be calculated by using the methods described in Section 7.2.3 (prima ry weirs) and the associated sheet in RWET. Table 7-4. Critical Inputs, Variabl es, and Chemical Properties Specific to Oil-Water Separators Air Emission Calculations
Critical Inputs Variables 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)

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-6 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 th e refinery wastewater emission 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, Variabl es, and Chemical Properties Specific to DAF Air Emission Calculations
Critical Inputs Variables with Default Values Chemical Properties Surface area (A) Viscosity of water (μ L ) Diffusivity of constituent in air (D a ) Temperature (T) Density of water ( ρ L ) Diffusivity of constituent in water (D w ) Total pressure (P 0 ) Molecular weight of water (MW L ) Henry’s law constant (H) 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 are commonly covered and vented to control devices; however, if the treatment units are uncovered, then the refinery wastewater emission tool can be used to estimate air emissions. Table 7-6 lists the critical inputs, variables with default values, and chemical proper ties specific to equalization tanks.

Table 7-6. Critical Inputs, Variabl es, and Chemical Properties Specific to Equalization Tank Air Emission Calculations
Critical Inputs Variables 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 re duce, 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

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-7 treatment efficiency, resulting in units that are di fficult to characterize. Multiple fate and transport mechanisms are often involved in the ultimate removal of a specific compound. As seen in Figure 7-3
, 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 me chanism. Therefore, it is important to obtain and use site-specific variables when estimating emissions to obtain accurate results.



## Biological Treatment Unit

Reactions and

Absorption Constituent In (Wastewater) Constituent Out (Wastewater)

Constituent Out (Sludge)



### Figure 7-3. Simplified drawing of a constituent mass balance in a biological treatment unit.


### The two primary classes of biological treatment units are suspended-growth and attached-growth systems. Suspended-growth systems maintain the biomass (floc s) 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 biofilms on fixed surfaces where biochemical reactions occur. Examples of attached-growth systems include trickling filters, rotating bi ological contactors, and fluidized-bed reactors. Regardless of the type of biological treatment used, the biochemical reactio ns 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 ensu re 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 di ssolved oxygen concentra tion in the water also increase the emission rate of organic constituents th rough increased volatilization. The volatilization rate can be affected by the wastewater surface area, tur bulence, and temperature; hydraulic retention; water depth; concentration and physical properties of th e 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 and potentially the greatest source of air emissions. Table 7-7 lists the critical inputs, variables with default values, and chem ical properties specific to biological treatment unit air emission calculations.

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-8 Table 7-7. Critical Inputs, Variabl es, and Chemical Properties Specific to Biological Treatment Unit Air Emission Calculations
Critical Inputs Variables 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 partitioning 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 concentration (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 tr eatment 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 emission estimates are needed for polishing ponds, then the equalization tank sheet of the refinery wastewater emission tool can be used. Although polishing ponds may function as a plug-flow reactor, the assumption can be made that vol atilization 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 defa ult values for specific va riables to estimate air emissions; however, site-specific data provide the mo st 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 biode gradation 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 mode l for more accurate results than can be developed when default biodegradation rate constant values are use. The methods used to determine the fraction of organic constituent biodegraded are provided in 40 CFR Part 63, Appendix C (also available at: http://www.epa.gov/EPA-AIR/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 w ith only one constituent of in terest 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

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-9 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, respectiv ely, when used as the sole substrate, versus a mixture of organic compounds. It is recommended th at the constituent of interest be dosed in the appropriate ratio with organic com pounds 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. Di rect measurements are taken of a modeled process unit, and the results are compared. Favorable compar isons are indicative of accurate predictive modeling, whereas poor comparisons could be the result of in correct assumptions or errors in the model. If corrective actions are necessary, a review of the consta nts 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 pr edictive modeling methods in Section 7.2, Methodology Rank 2 for Uncovered Units . The wastewater generation rates, be nzene 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 conc entration 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 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 refine ry wastewater is known, then the concentration of other organics in the wastew ater can be estimated using the ratios in Table 7-9

. 7.3.2 Engineering Estimates Based on Process 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 system. 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 th e 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 unkn own, then the default emission factors in Table 7-10 can be used to estimate the fraction of the total cons tituent 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.

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-10 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/hydror efining 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 units 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 c apacity at a given process unit, ppmw = parts per million by

weight

a Source: U.S. EPA, 1998.
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



### Table 7-9. Refinery Wastewater Contamin ant 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 BiologicalTreatment Unit (After OilWater Separator) 540841 2,2,4-Trimethy lpentane 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 (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-11 Table 7-9. Refinery Wastewater Contaminant Co ncentrations as a Ratio to Benzene (continued)

CAS No. HAP Mass Concentration Ratio of Compounds to the Concentration of Benzene

Inlet to Oil-Water Separator or DAF Unit Inlet to BiologicalTreatment Unit (After OilWater Separator) 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 Emission Factor s 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-Compliant Wastewater Collection and Treatment System 106990 1,3-Butadiene 0.91 0.75 540841 2,2,4-Trimethy lpentane 0.95 0.55
71432 Benzene 0.65 0.25 92524 Biphenyl 0.34 0.031
1319773 Cresols 0.002 0.000

98828 Cumene 0.68 0.24 100414 Ethylbenzene 0.66 0.22
110543 Hexane 0.97 0.55 1634044 Methyl tertiary-butyl ether 0.45 0.091

91203 Naphthalene 0.41 0.098
108952 Phenol 0.000 0.000 100425 Styrene 0.81 0.64
108883 Toluene 0.66 0.19 1330207 Xylene 0.64 0.21

VOC Total VOCs (using butane) 0.94 0.60

### Version 2.1.1 Final ICR Version – Corrected Section 7—Wastewater Collection and Treatment Systems

7-12 Example 7-1. Methodology Rank 3 for Wastewater A refinery has the following processing and prod uction rates. The average annual emissions of hexane, benzene, toluene, and xylene can be estim ated from the wastewater collection and treatment system for a BWON-compliant refinery.

Process Unit or Operation Average Throughput (bbl/cd) Atmospheric distillation 100,000 Vacuum distillation 50,000 Catalytic refo rming 20,000 Catalytic cracking 40,000 Alkylation 10,000 Product blending 60,000 Total crude and product tank throughput 180,000



### Use the factors in Table 7-8 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 7-9 to estimate the mass loading rate of other compounds and the BWON-compliant emission factors in Table 7-10 to estimate the annual emissions.

Compound (A) Mass Ratio from Table 7-9 (B) = A×144.7 Mass Flow (lb/cd) (C) Emission Factor from Table 7-10 (D) = B×C×365/2000 Annual Emissions (tons/yr)
Hexane 3.5 506.5 0.55 51
Benzene 1.0 144.7 0.25 6.6
Toluene 3.34 483.3 0.19 17 Xylene 3.57 516.6 0.21 20

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

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 reci rculation system may be sent to a cooling tower, where it is cooled to near ambient temperature for reuse, and then is return ed to the process or to refrigeration units for additional cooling. The coolin g water for a once-through system may be cooled and sent to a receiving waterbody. This section focu ses on cooling towers because these are used predominately in the petroleum refining industry. Some refineries use once-through cooling systems (emission estimates for once-through cooling syst ems can be estimated using essentially the same techniques used for cooling towers).
Organic HAP and VOC are picked up by cooling wa ter when leaks occur in heat exchangers or condensers. Product on the high-pressure side leaks th rough 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 wate r contact) in the cooling tower and 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 met hods presented in this section for calculating volatile hydrocarbon emissions from cooling towers. The coo ling tower emission estimates require information on the cooling water flow rate and the composition of th e process stream in the heat exchanger or in the condenser or refrigeration units. These emission estim ates are also dependent on the type of heat exchange monitoring system used.

Table 8-1 summarizes the hierarchy of cooling tower em ission 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 constituen t-specific emissions; these compositional analysis methods are also provided in order of reliability. Multiple methods are provided for volatile organic HAP and VOC, while one method is provided for PM 10 

### , chlorine, and heavy organic HAP. Cooling towers may service more than one process and have multiple coo ling water return lines. The monitoring performed on different cooling water return lines may differ for re turn lines leading to a single cooling tower. The methods described in this section can be applied to indi vidual return lines (if the flow rate of each line is known) so that the total emissions from a cooling to wer may be calculated as the sum of the emissions estimated for each return line. Different return lines to a single cooling tower may use different rank methodologies based on difference in the monitoring conducted on the individual return lines.
The remainder of this section provides additional de tail and guidance regarding the implementation of these methods. In general, annual emissions from c ooling 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 mon itoring periods or can be estimated using emission factors for the full annual operating time of the cooli ng tower. Hourly emissions should be estimated based on the highest hourly emission rate for the cool ing tower; when default emission factors are used, the hourly emissions should be determined based on th e highest recirculation rate experienced for that year.

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-2 Table 8-1. Summary of Cooling Towe r Emissions Estimation Methodologies

Rank Measurement Method or Emission Factor Compositional Analysis Data

1 

##  Air stripping simulation using Appendix P, Modified El Paso method (speciated VOC) a



##  Water recirculation rate 

##  Speciation of collected gas samples with EPA TO14 or TO-15 methods, with EPA Method 18, or with a portable (not handheld) gas chromatograph/flame ionization detector

2 

##  Air stripping simulation using Appendix P, Modified El Paso method a , using a flame ionization detection analyzer (total VOC)



##  Water recirculation rate 

##  Process-specific, service-specific concentrations



##  Process-specific average concentrations



##  Site-specific refinery average stream

concentrations



##  Default process compositions

3 

##  Direct water measurement by EPA Method 8260B b before and after exposure to the atmosphere (e.g., at t he 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 8260B 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 emission factor for VOC, PM 10 , and chlorine



##  Water recirculation rate OR



##  Material balance 

##  Process-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 transferred via a pipe or flexible tubing to an air-stripping column apparatus. Air fl owing countercurrent to the cooling water in the apparatus strips VOC and organic HAP from the water. Concentrations of pollutants in the air exiting the stripping column are measured, along with the air a nd water flow rates to the apparatus, to allow estimation of the concentrations of strippable VOC in the cooling water. At the apparatus air outlet, the concentrations may be measured us ing an on-site FID analyzer to determine the total strippable VOC (Methodology Rank 2 for cooling towers) or an on-si te 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 speci ation of air contaminants (Compendium Method TO14A, 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, op erating parameters of the air-str ipping apparatus, and the cooling water flow rate. Table 8-2 summarizes the data requirements for Methodology Ranks 1 and 2.

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-3 Table 8-2. Data Requirements for VOC or Speciated VOC Emissions, Methodology Ranks 1 and 2

Rank Data That Must Be Collected The Way in Which Data Are Obtained
Rank 1— speciated VOC emissions 

##  Speciated air-strippable VOC concentration measured in the stripped air (ppmv) 

##  Periodic Appendix P testing results using an air-stripping column apparatus, followed by TO-14A, TO-15, EPA Method 18, or GC/FID



##  Sample water flow rate of the apparatus,

stripping air flow rate of the apparatus, pressure in the air-stripping column apparatus 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 stripping 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 apparatus 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 monitoring period

(hours) 

##  From dates of monitoring events



### For cooling towers servicing process streams with multip le components, it is best to determine speciated compounds for air-strippable compounds from the coo ling 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:

Water rflow samplewate ow stripairfl i Air i Water 

## a T R b PC P MW C C ρ * * ) 273 ( * * * * *

,

, 

## +

= (Eq. 8-1)

where:
C Water,i 

### = Concentration of air strippable compound “i” in the water matrix (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 a pparatus (milliliters per minute [mL/min]) R = Universal gas constant (82.054 milliliters-a tmospheres per mole-Kelvin [mL-atm/mol-K]) T = Stripping chamber temperature (°C)

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-4 a samplewaterflow 

### = Sample water flow rate of apparatus (mL/min) ρ Water 

### = Density of the sample cooling water (g/mL).
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 strippin g. As such, this calculated water concentration is referred to as the “strippable pollutant concentration” in the cooling 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 concentration in the water and the emission rate (reported “as CH 4 

### ”). Even when a different calibration gas is used, one ma y 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 si ngle 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. For a multi-component process stream, it is better to determ ine speciated compounds using a portable GC/FID, TO-14A, TO-15, or Method 18. For portable GC r esults, in addition to ca libration with a standard compound (CH 4 

### or propane), the response factor of the un it 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 sp eciated concentrations (calculated using the compound-specific MW) should be used when estimat ing 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, as shown below in Example 8-1.

Example 8-1: How to Compare Speciated Concentration Results with Leak Definitions That Are Defined as Methane A facility conducts El Paso monitoring that provides speciated results, but, for regulatory purposes, these concentrations must be converted to a CH 4 

### basis for comparison to a leak definition for the stripping air that is on a CH 4 

### basis. Given: Speciated El Paso monitoring found hexane concentration in the stripped air of 5 ppmv. What is the concentration “as methane?” In this example, hexane concentration in th e stripped air is 5 ppmv. The following equation should be used to convert this concentration to CH 4 

### basis:

4 4

14 6 6 14 6 

## CH as ppmv 30 C mole 1 CH mole 1 * H C mole 1 C mole 6 * air mole 10 H C mole 5 Hexane ppmv 5 = ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

=

If the leak definition 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 

### .

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-5 Equation 8-2 should be used to estimate emissions fo r air strippable total VOC from the cooling water:



## lb 2000

ton 1 gal lb 34

. 8 hr min 60 ppm 10 6 , 

## × × × × × = Year er CoolingWat i Water i 

## H Flow C E (Eq. 8-2)

where:

E i 

### = Emissions of air strippable pollutant “i” from the cooling water (tons) Flow CoolingWater 

### = Flow rate of cooling water (gallons per minute [gal/min]) 60 = Unit conversion for minutes per year (min/yr) 8.34 = Density of water in pounds per gallon (lb/gal) 1/2000 = Unit conversion for tons per pound (tons/lb) H Year 

### = Length of time of the monitoring period or the length of time a leak occurs (hr)

When C air,i 

### is based on total VOC results from an FID an alyzer (Methodology Rank 2 for cooling towers), pollutant “i” is simply VOC.

When C air,i 

### is based on GC analysis results for indi vidual species (Methodology Rank 1 for cooling towers) or based on site-specific or default sp ecies 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 monitori ng events can be used to estimate the average emission rate during the intervening period by assigni ng each concentration measurement to half of the time period between monitoring/sampling events. If signifi cant 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 the “midpoint” method used to annualize equipment l eak emissions when periodic monitoring is used. As with equipment leaks, the “modified trapezoid” or “average period” methods could also be used to annualize emissions from cooling towers when periodic monitoring of the cooling water is performed (see Section 2.2.2, Calculating Annual Average Equipment Leak Emissions , in this Refinery Emissions Protocol for additional details).
When monitoring or sampling is not conducted regul arly or periodically, any measured concentration should be used to calculate the average emission 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 determin ed “leak” concentration for the entire reporting year up to the time when the leak was repaired.

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-6 Example 8-2: Calculation for Methodology Rank 1 for Cooling Towers Given: A cooling tower with a water recircula tion rate of 32,000 gal/min is monitored quarterly using speciated El Paso monitoring. A he xane concentration in the stripped air of 5.0 ppmv is detected during the second quarterly monitoring event, indicating a “leak.” The properties of the El Paso stripping column during this monitoring event were as follows: pressure =29.9 in. of Hg; strippable air flow in the apparatus = 2,500 mL/min; temperature = 32°C; sample water flow rate in the apparatu s = 125 mL/min. The leak repair took 45 days from the monitoring event to complete. Assuming all other monitoring events found no detectible concentrations of hexane, wh at are the annual emissions of hexane?
Solution: First use Equation 8-1 to calculate the concentration of air strippable compound in the water as follows.

Hexane ppmw

ml g ml
K mole atm ml ml Hg in

atm Hg in mole

g ppmv C
es

WaterSpeci 34

. 0 1 * min 125 * ) 273 32 ( * 054

. 82 min 2500 *

. 03342

. 0 *

. 9

. 29 * 17

. 86 * 0

. 5

=
+

− − =



### Thus, the 5 ppmv hexane concentration in the ai r stream translates to 0.34 ppmw “strippable” hexane in the cooling water. Next, the emissions must be estimated for th e period between the first and second quarterly monitoring events. The exact timing of the mon itoring events should be recorded and used, but from the information given (quarterly monitoring), we assume the monitoring events occur 91 days (2,184 hours) apart. One can use either the midpoint, modified trapezoid, or average period emission rate. Using the modifi ed trapezoid or average period method and noting the effective water concentration of the first monitoring event is 0 ppmv hexane, the emissions between the first and second monitoring event is: 

# ( ) Hexane ton 97

. 2 lb 2000 ton 1 * hr 184
, 2 * gal lb 34

. 8 * hr min 60 * min gal 000
, 32 * 10 2 0 34

. 0

6 1
, 

## = −
= i 

## E

Similarly, the emissions for the period from the second quarterly monitoring event and the leak repair is estimated. This peri od is given as 45 days (or 1,080 hours).



## Hexane ton 94

. 2 lb 2000 ton 1 * hr 080
, 1 * gal lb 34

. 8 * hr min 60 * min gal 000
, 32 * 10

34

. 0

6 2
, 

## = = i 

## E

As these are the only measurable emissions for the year, the annual emissions would be calculated as E i 

### = E i,1 

### + E i,2 

### = 2.97+2.94 = 5.91 tons, which is 5.9 tons when rounded to two significant figures.

Note: The advantage of the midpoint method is that it uses the same leak concentration for the period between the leak being detected and repaired as the “half” period prior to the monitoring event. Consequently, the time peri od from the monitoring event and leak repair can be added to the “half” period prior to the monitoring event (91 days ÷ 2 = 1,092 hrs) to calculate a total duration of the leak and calcu late the cumulative emissions in one step as follows: 

# ( ) Hexane ton 9

. 5 lb 2000 ton 1 * hr 080
, 1 092
, 1 * gal lb 34

. 8 * hr min 60 * min gal 000
, 32 * 10

34

. 0

6 

## = + = i 

## E

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-7 Example 8-3: Calculation for VOC Emissions Using Methodology Rank 2 for Cooling Towers Given: The cooling tower with a wa ter recirculation rate of 25,000 gal/min is monitored quarterly using El Paso stripping column (same stripping column properties as in Example 8-2 ) and a VOC concentration in the stripped air of 14 ppmv (as CH 4 

### ) is measured on February 1, 2009. The leak was repaired on Marc h 4, 2009 (31 days later). All previous and subsequent monitoring events found VOC concentr ation in the stripped air of 1 ppmv. What is the annual emissions of VOC from this cooli ng tower in 2009? If the process fluid contains 10 wt% benzene and a total light (strippable) organic content of 80%, what is the annual emissions of benzene from this cooling tower in 2009?
Solution: Equation 8-1 is used to calculate the concentration of air strippable VOC in the water as CH 4 

### . The water concentration corresponding to the stripping air concentration of 14 ppmv is:

4

, 

## CH as VOC ppmw 179

. 0 1 * min 125 * ) 273 32 ( * 054

. 82 min 2500 *

. 03342

. 0 *

. 9

. 29 * 04

. 16 * 14

=
+

− − =

ml g ml
K mole atm ml ml Hg in

atm Hg in mole

g ppmv C VOC

Water



### In the same manner, the water concentration corresponding to the stripping air concentration of 1 ppmv is: 0.0128 ppmw as CH 4 

### (0.179 / 14). Because the leak was identified during the first quarterly monitoring event, the method used to estimate emissions between monitoring interval s (i.e., the midpoint, modified trapezoid, or average period method) will yield slightly different results for 2009, although the total emissions across both 2008 and 2009 will be id entical. The modified trapezoid method is the most complicated, requiring interpolation to de termine the effective leak rate on January 1, 2009, before the emissions between Januaruy 1 and February 1 can be calculated. We generally recommend the midpoint method due to its ease of use, but the same method should be used for all cooling towers and all inventory years. Using the midpoint method, the water concentration of 0.179 ppmw as CH 4 

### is present for 62 days (or 1,488 hour) in 2009 (from Jan. 1 to Marc h 4, 2009). The emissions during this period

are:



## VOC ton 67

. 1 2000

1 * 488
, 1 * 34

. 8 * min 60 * min 000
, 25 * 10

179

. 0

6 1
, 

## =

= lb ton hr gal lb hr gal E VOC



### For the remainder of the year (8760 – 1488 = 7,272 hrs), the emissions are:



## VOC ton 58

. 0 2000

1 * 272
, 7 * 34

. 8 * min 60 * min 000
, 25 * 10 0128

. 0

6 2
, 

## = = lb ton hr gal lb hr gal E VOC



### Therefore, the 2009 VOC emissions from this cooling tower are 1.67 + 0.58 = 2.25 tons VOC.

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8-8 

## 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 wate r before and after the cooling tower. Although Methodology Rank 3 has the potential to be as approp riately reliable as Methodology Ranks 1 or 2 for large leakers, Rank 3 suffers from detection limit issu es 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 co mponents and large volumes of flow rate, so direct water sampling typically requires analysis for lo w-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 dete cted 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 sampl e after the cooling water has been exposed to the atmosphere. The change in the component concentra tion 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.

Example 8-4: Calculation for Speciated HAP Emissions using Methodology Rank 2 for Cooling Towers Given: The cooling tower in Example 8-3 serves a process unit whose process fluid contains 10 wt% benzene and a total light (strippable) organic content of 80%. What is the annual emissions of benzene from this cooling tower in 2009?
Solution: In Example 8-3 , theVOC emissions were calculated to be 2.25 tons in 2009. To determine the mass emissions of benzene, the mass of benzene per mass of VOC stripped in the El Paso column must be calculated. In this example, 80 percent of the process fluid is expected to be strippable organics. The remaining 20 percent may be either inorganic compounds, like H 2 

### or N 2 

### that are stripped but are not detected by the organic analyzer, or heavier organics that do not strip appreciably in the stripping column. While more detailed calculations could be performed for compounds th at may marginally strip, for the purposes of speciating volatile emissions, it is assumed th ese non-volatile compounds are not stripped. Benzene represents 10% of the total mass of flui d leaking into the cooling water. Since the total strippable organic content of fluid leaking into the cooling water is 80 percent, the mass fraction of benzene per mass of strippable VOC is 0.1/0.8 or 0.125. Therefore, benzene is expected to contri bute 12.5 percent of the total strippable VOC concentration or 0.28 tons benzene (0.125 to ns benzene per ton VOC × 2.25 tons VOC).

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-9 Table 8-3. Data Requirements for Speciated Compound Emissions, Methodology Rank 3

Rank Data That Must Be Collected The Way in Which Data Are Obtained
Rank 3— speciated emissions 

##  Speciated compounds concentration measured in the inlet cooling tower return line (ppmw) 

##  Periodic sampling results using Method 8260B, including a measurement prior to exposure to the atmosphere



##  Speciated compounds concentration

measured in the outlet cooling water (ppmw) 

##  Periodic sampling results using Method 8260B, including a measurement after 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 change in the component concentration in the co oling water before and after being exposed to the atmosphere is used, along with the cooling water r ecirculation 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 water make-up rates offset any drift loss and blowdown loss; therefore, flow “in” to a cooling tower is the same as flow “out” and can be determined based on the water recirculatio n flow rate, regardless of where this measurement takes place. 

# ( )

lb 2000

ton 1 hr min 60 gal lb 34

. 8 10 6 , , 

## × × × × × −

= Year er CoolingWat Out i In i i 

## H Flow C C E (Eq. 8-3)

where:
C i,In 

### = Concentration of component “i” in the cooling water prior to exposure to the atmosphere (ppmw) C i,Out 

### = Concentration of component “i” in the c ooling water after exposure to the atmosphere (ppmw)
As shown in Equation 8-4, the total emissions fro m the cooling water are the sum of all component species emitted and can be summed specifically for VOC or organic HAP: 

# ∑

= 

## = n

i i Total 

## E E

1 

### (Eq. 8-4)

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8-10 

## 8.3 Methodology Rank 4 for Cooling Towers Methodology Rank 4, similar to Methodology Rank 3, u ses direct cooling water sa mples 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 su ch, this methodology will likely overestimate the cooling water emissions, and would be a conservativ e (i.e., resulting in greatest emissions) estimate.
The data necessary to implement Methodology Rank 4 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 8-5: Calculation for Methodology Rank 3 for Cooling Towers Given: Concentrations for total xylenes in the c ooling water are determined semi-annually. During the first measurement event the concentra tion of xylene in the cooling water return line before exposure to the atmosphere was 0. 220 ppmw and 0.080 ppmw in the cooling water flow to the heat exchanger after exposure to the atmosphere. Sampling during the second monitoring event showed xylene concentrati ons of 0.320 ppmw before and 0.100 ppmw after exposure to the atmosphere in the cooling tower. The cooling water recirculation rate averages 55,000 gal/min with a maximum recirculation ra te of 65,000 gal/min. The cooling tower operated for 8,000 hours during the year. What are the annual and maximum hourly emissions of xylene from the cooling tower?
Solution: For monitoring that occurs semi-annually or less often attributing the emissions between monitoring events and the calendar year can be cumbersome. As no leak repair was conducted, it can be assumed that these two meas urement are equally representative for the year. The average hourly emission rate of xyle ne is calculated using Equation 8-3 for each of the monitoring events as follows: 

# ( ) lb/hr 85

. 3 hr min 60 gal lb 34

. 8 min gal 000
, 55 10 08

. 0 22

. 0

6 1
, 

## = × × × −
= i 

## E 

# ( ) lb/hr 05

. 6 hr min 60 gal lb 34

. 8 min gal 000
, 55 10 10

. 0 32

. 0

6 2
, 

## = × × × −
= i 

## E

The average hourly emissions rate during the y ear can be calculated as the arithmetic average of these two hourly estimates, which is 4.95 lb/h r [(3.85+6.05)/2]. The annual emissions are then calculated based on the operating hours as: 4.95 lb/hr × 8,000 hours × 1 ton/2,000 lbs = 19.8 tons of xylene. The maximum hourly emissions of xylene are cal culated using they highest net measurement concentration and the maximum recirculation rate as follows. 

# ( ) lb/hr 16

. 7 hr min 60 gal lb 34

. 8 min gal 000
, 65 10 10

. 0 32

. 0

6 max , 

## = × × × −
= i 

## E

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8-11 Table 8-4. Data Requirements for Speciated Compound Emissions, Methodology Rank 4

Rank Data That Must Be Collected The Way in Which Data Are Obtained
Rank 4— speciated emissions 

##  Speciated compounds concentration measured in the inlet cooling tower return line (ppmw) 

##  Periodic sampling results using Method 8260B, including a measurement prior to exposure to the atmosphere



##  Cooling water flow recirculation rates

(gal/min) 

##  Continuous measurements from pump flow rate curves, ro tameters, 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 befo re being exposed to the atmosphere is used with the cooling water flow rate to estimate the emis sions from the cooling water. The following equation (Equation 8-5) should be used to calculate the emissions of components from the cooling water: 

# ( )

lb 2000 ton 1 hr min 60 gal lb 34

. 8 10 6

, 

## × × × × × = Year er CoolingWat In i i 

## H Flow C E (Eq. 8-5)

where:
C i,In 

### = Concentration of component “i” in the cooling water prior to exposure to the atmosphere (ppmw)
Equation 8-5 is equivalent to Equation 8-3 with C i,Out 

### set equal to zero. Thus, the calculations performed for Methodology Rank 4 for cooling towers is essentially identical to those for Methodology Rank 3 for cooling towers. Equation 8-4 can be used to calcula te the total VOC or total organic HAP emissions from the cooling water.


## 8.4 Methodology Rank 5 for Cooling Towers Methodology Rank 5 for cooling towers uses emission factors from AP-42 (U.S. EPA, 1995a; Sections 5.1 and 13.4). The AP-42 emission factors approved for use in Methodology Rank 5 for cooling towers are summarized in Table 8-5 . The remainder of this section describes the use of these emission factors for different classes of pollutants.

Table 8-5. Methodology Rank 5 Default Emission Factors

Type of Cooling Tower VOC Emission Factor (lbs/MMgal) a Drift Factor (lbs/MMgal) a PM 10 Emission Factor (lbs/MMgal) b
Induced draft, counter flow 6.0 1,700 31.5 Induced draft, cross flow 6.0 1,700 40.8 Unspecified draft or flow type 6.0 1,700 35.0
Natural draft 6.0 73 No data

a Source: U.S. EPA, 1995a; presented in units of pounds per million gallons (lb/MMgal) of recirculation.
b Source: U.S. EPA, 1995a; calculated as the product of the drift factor fr om Table 13.4-1 and the total dissolved

solids concentration in Table 13.4-2.

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8-12 8.4.1 VOC and Volatile Organic HAP Methodology Rank 5 for volatile organics from coo ling towers uses the uncontrolled VOC emission 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 th e water of 0.7 ppmw). The controlled emission factor provided in AP-42 should not be used. The controlle d emission factor only applies to refineries that directly monitor for hydrocarbons (and organic HAP) a nd repair leaks when they occur, in which case the refineries would have monitoring data to conduct em ission 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 process streams 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 the default average refinery process stream compositions 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 emission factor, the cooling wate r flow rate, and the process stream composition. Table 8-6 summarizes the data requirements of Methodology Rank 5.

Table 8-6. Data Requirements for VOC or Speciated VOC Emissions, Methodology Rank 5

Rank Data That Must Be Collected The Way in Which Data Are Obtained
Rank 5—estimated speciated emissions 

##  AP-42 uncontrolled emission factor for cooling 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, ro tameters, or similar methods



##  Operating hours (hours) 

##  Use operating hours of cooling tower or assume continuous operation (8,760 hr/yr, non-leap year)



### The following equation (Equation 8-6) shoul d be used to estimate VOC emissions:



## lb 2000

ton 1 h r min 60 × × × × = Year er CoolingWat Unc VOC 

## H Flow EF E (Eq. 8-6)

where:

EF Unc 

### = Uncontrolled emission factor for cooling towers from AP-42 (Section 5.1) = 6.0 pounds of VOC per 10 6 

### gallons of cooling water (lb/MMgal).
The following equation (Equation 8-7) should be used to estimate the emissions for a particular species component:



## lb 2000 ton 1 hr min 60 × × × × × = Year er CoolingWat i Unc i 

## H Flow WtFrac EF E (Eq. 8-7)

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-13 where:

WtFrac i 

### = Approximate weight fraction of component i in the cooling water

8.4.2 Particulate Matter Emissions Methodology Rank 5 for cooling towers uses the total liquid drift emission factors given in AP-42 (U.S. EPA, 1995a; Section 13.4), which are also provided for convenience in Table 5-5 , and the total dissolved solids (TDS) weight fraction to estimate PM 10 

### emissions. It is conservatively assumed that all TDS are in the PM 10 

### size range.
Site-specific TDS concentration in the cooling wate r should be used when available (Methodology Rank 5A for PM from cooling towers). When direct TD S monitoring is not conducted, AP-42 (U.S. EPA, 1995a) recommends that the TDS be estimated from TDS concentration of the makeup water times the “cycles of concentration ratio” of a monitored pa rameter (Methodology Rank 5B for PM from cooling towers). The cycles of concentration ratio is th e concentration of a monitored parameter (such as conductivity, calcium, chlorides, or phosphate) in the cooling tower recirculating water divided by the concentration of that measured parameter in the ma keup water. Alternatively, Methodology Rank 5B for PM from cooling towers can use a direct correlationof a monitored parameter to TDS concentration. For

Example 8-6: Calculation for Methodology Rank 5 for Cooling Towers Given: An unmonitored cooling tower with a water recirculation rate of 25,000 gal/min is servicing a heat exchanger cooling a reformulat ed gasoline stream. Estimate the annual VOC and HAP emissions from this cooling tower.
Solution: Equation 8-6 should be used to calculate the annual emissions of VOC, E VOC 

### :



## VOC ton 4

. 39 lb 2000 ton 1 760
, 8 hr min 60 min gal 000
, 25 gal 10 VOC lb 6

6 

## = × × × × = hr E VOC



### Without site-specific stream composition, use the default concentrations for reformulated gasoline in Appendix A, Average Stream Compositions , and use Equation 8-7 to estimate the emissions for each HAP component in the gaso line stream. For example, to calculate the annual emissions of benzene, the liquid compos ition for benzene is 0.7 wt%. Using this concentration in Equation 8-7 yields:



## Benzene ton 28

. 0 lb 2000 ton 1 760
, 8 hr min 60 min gal 000
, 25 007

. 0 gal 10 VOC lb 6

6 

## = × × × × × = hr E i



### Similarly, emissions of other consistuents are estimated as follows:

 Cumene of 0.19% by weight; emissions are 0.075 ton

 Ethylbenzene of 1.26% by weight; emissions are 0.50 ton

 Hexane of 1.36% by weight; emissions are 0.54 ton

 Naphthalene of 0.21% by weight; emissions are 0.083 ton

 Toluene of 7.0% by weight; emissions are 2.8 ton

 2,2,4-Trimethylpentane of 1.1% by weight; emissions are 0.43 ton

 Xylene of 7.3% by weight; emissions are 2.9 ton The total HAP emissions for this cooling tower are calculated by summing the emissions of the individual HAP; the total annual HAP emissi ons for this cooling tower are 7.6 tons.

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-14 example, it is commonly suggested that the Equati on 8-8 be used to estimate TDS concentration from conductivity measurements.


## mho/cm)) ( C (ppmw) TDS μ 

## ty Conductivi F

TDS 

## × = (Eq. 8-8)

where:
TDS = Total dissolved solids concentr ation of the cooling water (ppmw) Conductivity = Conductivity of cooling wate r (micromho per centimeter [μmho/cm]). CF TDS 

### = Correlation factor to convert conductivity to TDS concentration (ppmw per μmho/cm) = 0.5 to 1.0; default is 0.67 (see http://www.appslabs.com.au/salinity.htm )
The correlation factor is dependent on the specific electrolytes present and the total concentration of electrolytes. At low conductivity (<1,000 μmho/cm), CF TDS 

### = 0.5. The correction factor increases with increasing TDS concentrations. A site-specific correcti on factor or curve should be used based on paired measurements over the range of typical measured c onductivity values. Otherwise, the default correction factor of 0.67 should be used.
Once the the TDS weight fraction is determented, the PM 10 

### emissions corresponding to the TDS measurement value is calcula ted using Equation 8-9.



### lb 2000 ton 1 hr min 60 10 

### × × × × × = Period er CoolingWat TDS Drift PM 

### H Flow WtFrac EF E (Eq. 8-9)

where:

E PM10 

### = Emissions of PM 10 

### during the measurement period (tons or tons per period) WtFrac TDS 

### = Weight fraction of TDS (Note, 1,000 ppmw = 0.001 wt fraction) H Period 

### = Number of hours associated with the monitored TDS concentration (hrs).

If no data are available to estimate TDS concentration in the cooling water, then the default average PM 10 

### emission factors provided in Table 8-5 (which are based in the TDS fraction from AP-42, Table 13.4-2) should be used. These default PM 10 

### emission factors represent Methodology Rank 5C for PM from cooling towers. Emissions of PM 10 

### are calculated using Equation 8-10, which is essentially identical to the calculation for total VOC emissions.



## lb 2000

ton 1 h r min 60 10 10 

## × × × × = Year er CoolingWat PM PM 

## H Flow EF E (Eq. 8-10)

where:

EF PM10 

### = Default emission factor for PM 10 

### from cooling towers from Table 8-5

.

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-15 Example 8-7: Calculation for Annual PM Emissions Using Methodology Rank 5B for PM from Cooling Towers Given: A cooling tower with a water recirculation rate of 25,000 gal/min is sampled monthly for TDS. What are the annual emissions of PM 10 

### ? If the highest recirculation rate is 30,000 gal/min, what is the maximum hourly PM 10 

### emissions rate?
Solution: Using the site-specific TDS fraction, the operating hours associated with each TDS concentration period can be determined usi ng the midpoint method as shown in the following table (Column 3). Equation 8- 9 is applied to each concentration period to calculate the emissions of PM 10 

### for that period (Column 4). The sum of the emissions in Column 4 yields a total annual emissions of 22.7 tons (or 23 tons rounded to 2 significant digits).

1 Date 2 TDS Concentration (ppmw) 3 Hours Assigned to TDS Concentration 4 Emissions (tons for concentration period) Jan 10 (startup Jan 1) 360 240+300=540 0.25 February 4 520 300+336=636 0.33
March 4 780 336+372=708 0.70 April 4 1,100 372+360=732 1.03 May 4 1,260 360+372=732 1.18 June 4 2,300 372+360=732 2.15 July 4 3,500 360+372=732 3.27 August 4 5,500 372+372=744 5.22 September 4 4,600 372+360=732 4.29 October 4 1,700 360+372=732 1.59 November 4 2,100 372+624=996 2.67 December (shutdown Dec 1 - not operating in December) 0 744 0.00

Total 8,760 22.7 ton 

### The maximum TDS concentration (5,500 ppmw) and the maximum cooling water recirculation rate of 30,000 gal/min is used in Equation 8-9 to calculate the maximum hourly PM 10 

### emissions rate as follows:

10 6 6 10 

## PM lbs/hr 14 hr min 60 min gal 000
, 25 water lb 10 TDS lb 500
, 5 gal 10 drift lb 700
, 1

= × × × = PM 

## E

### Version 2.1.1 Final ICR Version – Corrected Section 8—Cooling Towers

8-16 8.4.3 Non-volatile Organic HAP Emissions Organic compounds with low volatility, such as mo st POM compounds, will not be effectively stripped from the cooling water. These compounds will tend to accu mulate in recirculated cooling water, and will primarily be released as drift from the cooling tower. The emissions of these compounds can be estimated from their concentration in the cooling wate r and the liquid drift factor in the same manner used to calculate PM 10 

### emissions using Equation 8-9.

8.4.4 Chlorine Emissions Site-specific material balance may be one method of estimating chlorine emi ssions. Otherwise, limited information is available regarding chlorine emi ssion factors for cooling towers. EPA is currently reviewing available data to develop guidance for es timating chlorine emissions from cooling towers. To aid in developing that guidance, EPA is seeking add itional data and suggestions for emission estimation methodologies.

Example 8-8: Calculation Using Methodology Rank 5C for PM from Cooling Towers Given: A forced draft, cross-flow cooling towe r with a water recirculation rate of 25,000 gal/min in service all year. No TDS concentrati on data are available. What are the annual emissions of PM 10 

### emissions?
Solution: Since no TDS measurement data are available, use the default PM 10 

### emission factors from Table 8-5 . The appropriate emission factor for a forced draft, cross-flow cooling tower is 40.8 lb/MMgal. The cooling tower was operated all year (8760 hours). Using Equation 8-10, the annual emissions of PM 10 

### , E PM10 

### , are calculated as follows:

10 6 10 10 

## PM ton 268 lb 2000

ton 1 hr 760
, 8 hr min 60 min gal 000
, 25 gal 10 PM

lb 8

. 0 4

= × × × × = PM 

## E

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9-1 

# 9. Loading Operations Product or commodity loading emissions occur when vapor is displaced by the product or commodity when it is loaded into tank trucks, rail cars, and mari ne vessels (which include bo th ships and barges). The vapor may contain constituents from the material prev iously transported and from the product currently being loaded. HAP, VOC, and GHG are emitted from loading operations. Emission from loading operations should be estimated for all materials loaded into tank trucks, rail cars, and marine vessels such as final products, intermediates, additives, or wastes. Loading operations also include loading materials into drums or containers, such as LPG container fillin g operations or loading waste into drums for off-site disposal.
Loading emission estimates require information on the quantity of material loaded annually, the component composition of the material loaded and the 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 re gulated under the Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC) and are limited to 10 m illigrams of TOCs per liter of gasoline (Subpart CC references Subpart R, which references some require ments for 40 CFR Part 60, Subpart XX). Emissions from marine vessel loading operations for crude, gasolin e, 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% emission -reduction requirement for existing sources and 98% emission-reduction requirement for new sources.
Emissions from loading operations may be reduced by using submerged loading or bottom loading. Additionally, emissions from loading operations may be captured and controlled using a vapor collection system and an add-on air pollution control device. Va por balancing may be used as an alternative to addon controls to reduce emissions from loading operatio ns. If an add-on air pollution control device or a vapor balance system is used to capture and cont rol emissions, then capture and control efficiencies should be included in the emission estimate.
Control devices used for loading operations typically include thermal or catalytic incinerators, adsorption systems, scrubbers, and flares. Vapor balancing syst ems 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 emission 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 perform ance 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 loading operation emission estimation techniques. Within a given measurement method (or rank), there may be alterna tive methods for determining the constituent-specific emissions; these compositional analysis methods are also provided in order of accuracy. Methodology Ranks 1, 2, and 3 for loading operations only apply loading operations that are controlled; uncontrolled loading operations must estimate their emissions usi ng Methodology Ranks 4 for loading operations. The remainder of this section provides additional details and guidance regarding the ways in which to implement these methods.

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-2 Table 9-1. Summary of Loading operations Emission Estimates

Rank Measurement Method or Emission Factor Compositional Analysis Data

1A Direct measurement (CEMS) for both flow rate and gas composition  Pressure, temperature, and moisture content (depending on the monitoring system)
1B Direct measurement (CEMS) for both flow rate and THC  Process-specific, service-specific concentrations based on measurement data
2 Direct measurement by EPA Method 18 (sitespecific emission factor) and loading rate  Not applicable

3 Direct measurement by EPA Method 25, Method 25A, or Method 25B (site-specific emission factor) and loading rates  Process-specific, service-specific concentrations

 Process-specific average concentrations

 Site-specific refinery average stream concentrations

 Default process compositions
4 AP-42 emission factor (default emission 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, fac ilities should use site-specific information on the composition of the material loaded if availa ble (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 li quid and vapor phases and sometimes only for the liquid phase. Material-specific or site-specific concentr ations should be used when available. If materialspecific or site-specific data are not available, then the default average compositions for refinery process and product streams presented in Table A-1 of Appendix A, Average Stream Compositions , may be used to speciate and generate VOC and HAP emission factors.
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 av ailable. When these data are not readily available at the refinery, data from various references can be u sed 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 Loading Operations For pollutants such as THC, it is anticipated that so me loading operations may have CEMS for measuring the composition and the gas flow rate of the emissi ons 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. Although it is unlikely th at CEMS are used that can provide emissions for speciated organic compounds, if a facility monitors TH C and has sampled the organic vapors to determine specific organic compound concentrations, then specia tion profile developed from the sampling data can be used with the CEMS data for THC. The TH C emissions would be repor ted as Methodology Rank 1A for loading operations and the speciated organic emissions would be reported as Methodology Rank 1B for loading operations.

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-3 

## 9.3 Methodology Ranks 2 and 3 for Loading operations Performance testing conducted at the refinery may be used to develop site-specific emission factors with emission data correlated to throug hput. These site-specific emission fact ors 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 EP A 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 m easured and recorded the gasoline loading throughput during the testing. The outlet test results on a ma ss basis are correlated with the gasoline throughput during the test to demonstrate that the refinery is meeting the 10 mg/L gasoline emission limitation. The test data could also be used to estimate th e 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 qua ntity of that product loaded. It is important to note that when NMOC is used, a CH 4 

### emission factor may also be de veloped. Additional information about speciation of the gasoline or product either as s ite-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 inle t 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 o ngoing or periodic testing. The outlet test data, along with the recorded product throughput during the tes ting, 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 estim ate emissions. It is important to note that when NMOC is used, a CH 4 

### emission 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 2 and 3 for loading operations include the emission rate or emission 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 2 and 3.

Table 9-2. Data Requirements for VOC or Speciated Emissions, Methodology Rank 1 or 2

Rank Data That Must Be Collected The Way in Which Data Are Obtained
Rank 2— speciated emissions 

##  Speciated component emission factor for a product (milligrams per liter [mg/L] or lb/gal) 

##  Periodic EPA Method 18 testing results



##  Throughput data by product over the

time period of interest (gallons or liters) 

##  Volume flow rate measurements determined by flow meter or pump ra tes, gallons, or liters
Rank 3— VOC or total hydrocarbon emissions 

##  Total hydrocarbon or VOC emission factor for a product (mg/liter or lb/gal) 

##  Periodic EPA Method 25 or 25A testing results



##  Spectiaion profile from measurement data or from

process knowledge



##  Throughput data by product over the

time period of interest (gallons or liters) 

##  Volume flow rate measurements determined by flow meter or pump ra tes, gallons, or liters

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-4 Equation 9-1 should be used to estimate the emissions of each product using emission rates or emission factors developed from testing.


## Thruput ER E Li

Li 

## × = (Eq. 9-1)

where:

E Li 

### = Emissions of component species “i” (lbs) ER Li 

### = Emission rate of component species “i” (lb/gal) Thruput = Throughput of product (gallons)

When ER Li 

### is based on total 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 indivi dual pollutant emissions. To estimate the emissions 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.

Species Li LSpecies 

## Wtfrac Thruput ER E × × = (Eq. 9-2)

where:

E LSpecies 

### = Emissions of component species “i” (lbs) Wtfrac Species 

### = Vapor weight fraction of component species “i” (fraction by weight)
If the vapor weight fraction of the components are no t know, then these concentrations can be calculated from the product knowledge, i.e., the compositi on of compounds in the liquid. Appendix A, Average Stream Compositions , presents the methodology for calculating the vapor phase concentration based on the liquid-phase composition and the system temperature and pressure. It is important to characterize even low levels of the most volatile compounds in the liq uid, because even low levels of the most volatile compounds can significantly affect the vapor phase concen tration. An example calculation is provided in Example A-1 of Appendix A.


## 9.4 Methodology Rank 4 for Loading operations The emission estimating methodology for loading opera tions is given in AP-42 (U.S. EPA, 1995a); these methodologies are for loading operations that are ve nted directly to the atmosphere. Equations are provided in this section for estimating controlled emissions from the “uncontrolled” emissions based on the capture and control efficiency. 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 fo r 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 emission 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 commod ity being loaded, the emission 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 follow ing sections. It is not expected that refineries will be loading crude for transport, but if so, the re finer should consult AP-42 for the emission estimation methodology.

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-5 9.4.1 AP-42 Emission Factors for “Product” or “Total Hydrocarbon” Emissions
9.4.1.1 Tanker Trucks and Railcars (Any Commodity) and Marine Vessels (Products Other than Gasoline and Crude Oil) Equation 9-3 should be used to estimate the uncontroll ed emission factor or the emission rate for the product loaded, in terms of total hydrocarbon or the product:



## T

MW P S ER Vap L 

## × × × = 46

. 12 (Eq. 9-3)

where:

ER L 

### = Loading emission factor or emission 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]) 1 

### MW Vap 

### = Molecular weight of vapors (lb/mol) T = Temperature of bulk liquid loaded (°R; °F + 460)

Table 9-3. Saturation Factors a

Type of Tanker Loaded Loading Scenario Saturation Factor



##  Tank trucks



##  Rail cars



##  Any commodity 

##  Submerged loading



##  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 em ission factors for marine vessels loading gasoline at marine terminals based on measurements of gaso line loading losses from sh ips and barges. Those emission factors are presented in Table 9-4 . (Table 5.2-2 of AP-42 also includes emission factors in units of mg/L.) AP-42 does not provide ratings for these emission factors.

1 

### True vapor pressure is defined as the equilibrium partia l 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 pe troleum liquids. For a pure component at 100 ° F, the true vapor pressure is equivalent to the Reid vapor pressure.

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-6 Table 9-4. VOC Emission Factors for Marine V essel 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-freed 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 emission factors for VO C (which excludes methane and ethane) may be used

to estimate 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 simi lar to tank ships. Shallow draft

barges (compartment depth 10 to 12 ft) exhibit higher emission levels.

c Volatile cargoes are those with a true vapor pre ssure greater than 10 kilopascals (kPa) (1.5 psia).
d Based on observation that 41% of tested ship compar tments were uncleaned, 11% ballasted, 24% cleaned, and 24% gas-freed. For barges, 76% were uncleaned.


### 9.4.2 Estimate Uncontrolled Emissions and Speciate Using the emission factor developed or identified from the methods previously discussed, the emissions can be estimated based on Equation 9-4: 

## Thruput ER E L

L 

## ×

= (Eq. 9-4)

where:

E L 

### = Uncontrolled emissions (lb) of commodity ER L 

### = Loading emission rate (lb/10 3 

### gal of liquid loaded) Thruput = Throughput of commodity (gallons)
As previously discussed, depending on the commodity being loaded, the emission rate ER L 

### could be for gasoline, crude, or other product. Also as previous ly 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 aver ages) can be used as shown in Equation 9-5.

Species L LSpecies 

## Wtfrac Thruput ER E × × = (Eq. 9-5)

where:

E LSpecies 

### = Emissions (lb) of the component species “i” Wtfrac Species 

### = Weight fraction of component species “i” in the vapor (fraction)
9.4.3 Capture Efficiency If an add-on air pollution control device or vapor balan ce system is used to capture and control emissions, then capture and control efficiencies should be include d in the emission estimate. The capture efficiency is the portion of the total emissions that is capture d by the vapor collection system. The effectiveness of the vapor collection system, or capture system, is de pendent on the leak tightness of the truck tank, rail car, or marine vessel; the condition of the connec tion from the tanker or vessel collection header equipment to the vapor collection system; the leak tig htness of the terminal’s vapor collection system; and the control device. For gasoline loading racks subject to Subpart CC, refineries are required to confirm

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-7 and document the vapor tightness of the vehicles bei ng 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 head space to the vapor collection system and to the control device are factors. Typical capture effi ciencies 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 tank er truck, rail car, and marine vessel.

Table 9-5. Capture Efficiencies for Vapor Collection Systems a

Loading Characteristics and Leak Check Frequency for Tankers Capture Efficiencies

 No leak check on tanker 65%

 No leak check on tanker

 Maintain minimum positive pressure below +3 to +5 inches of water 85%

 Annual leak check on tanker per 40 CFR Part 60, Subpart XX (nongasoline) 95%

 Semi-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 inches of water

 Hard-piped bolted, flanged connection from t anker to the vapor collection system 100%

 Pressure tank that is U.S. Depa rtment of Transportation certified

 Hard-piped bolted, flanged connection from t anker to the vapor collection system 100%

Note: Use latest available version if updates to this document have occurred since the cited version.

a Source: TCEQ, 2000.


### 9.4.4 Overall Control Efficiency The overall control efficiency represents the portion of the total captured emissions that are removed from the emission stream by the add-on air pollution control device. The control efficiency determined for the control device should be applied based on performance t esting, if available, or based on design efficiency and operating parameters.
To estimate controlled emissions from loading, use Equa tions 9-6 and 9-7 to apply the capture efficiency and the control efficiency to the uncontrolled emissions: 

## ) CE ( ) Capture ( Thruput ER E L

Cont 

## − ×

− × × = 1 1 (9-6)


## ) CE ( ) Capture ( Wtfrac Thruput ER E Species L s ContSpecie 

## − ×

− × × × = 1 1 (9-7)

where: Capture = Capture efficiency of the vapor collection system (fraction) CE = Control efficiency of the add-on air pollution control device (fraction)

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-8 Example 9-1: Calculation for Rank 4—When Property Data Are Not Available Calculate the VOC and HAP emissions for submer ged loading of reformulated 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, w ith 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. Liquid composition or vapor-phase property data are not available,so the property data for liquid compos ition of reformulated gasoline in Appendix A are used (see Tables A-1 and Table A-2)

. First, the vapor pressure of reformulated 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 vapor pressure for each constituent is de termined at the three loading temperatures using Antoine’s equation and Antoine’s coefficien ts, such as those provided in Table 7.1-5 of AP-42 (U.S. EPA, 1995a). From Example A-1 in Appendix A, at 77°F, the total system vapor pressure is 4.77 psia and the MW of the vapor, MW GasolineVAP 

### , is 67.49 lb/lb-mol. Similar calculations for loading gasoline with bulk temperatures of 90°F and 40°F reveal the following (see Appendix A for further details):

Temperature Vapor Pressure MW GasolineVAP 90°F 6.13 psia 68.08 lb/lb-mol 77°F 4.77 psia 67.49 lb/lb-mol 40°F 2.17 psia 65.79 lb/lb-mol

### Version 2.1.1 Final ICR Version – Corrected Section 9—Loading Operations

9-9 Example 9-1 (continued): Calculation for Rank 4—When Property Data Are Not Available The emissions rates at each temperature are calculated using Equation 9-3:



# ( ) gal lb/10 673

. 5 °R 460 °F 90 mole lb lb 08

. 68 psia 13

. 6 60

. 0 46

. 12 3 90 

## = + − × ×

= Gasoline 

## ER



# ( ) gal lb/10 482

. 4 °R 460 F 77 mole lb lb 49

. 67 psia 77

. 4 60

. 0 46

. 12 3 77 

## = + ° − × ×

= Gasoline 

## ER



# ( ) gal lb/10 135

. 2 °R 460 F 40 mole lb lb 79

. 65 psia 17

. 2 60

. 0 46

. 12 3 40 

## = + ° − × ×

= Gasoline 

## ER

The emissions at each temperature are then calculated using Equation 9-4:



## gasoline lb 538
, 4 trucks 100 truck

gal 000
, 8 gal 000
, 1 lb 673

. 5

90 

## = ⎟ ⎠ ⎞ ⎜ ⎝ ⎛
× × = Gasoline 

## E

gasoline lb 972
, 1 trucks 55 truck

gal 000
, 8 gal 000
, 1 lb 482

. 4

77 

## = ⎟ ⎠ ⎞ ⎜ ⎝ ⎛
× × = Gasoline 

## E

gasoline lb 939 trucks 55 truck

gal 000
, 8 gal 000
, 1 lb 135

. 2

40 

## = ⎟ ⎠ ⎞ ⎜ ⎝ ⎛
× × = Gasoline 

## E

The individual VOC or HAP species at each bulk temperature can be estimated using the calculated gasoline vapor weight fraction for each species in Equation 9-5:

Species gasoline Species L LSpecies 

## Wtfrac E Wtfrac Thruput EF E × = × × =

See Table 9-6 for the emission estimate summary for individual HAP species. Finally, total emissions are estimated by summing the emission estimates for each of the three bulk temperatures. Total gasoline emissions ( VOC) are 7,449 lb (4,538 lb + 1,972 lb + 939 lb), or 3.7 tons (7,449 lb ÷ 2,000 lb/ton). Similarly, total emissions of each of the individual HAP species are estimated by summing the emission estimates for each of the three bulk temperatures. The results are presented in Table 9-6

.Version 2.1.1Final ICR Version – Corrected Section 9—Loading Operations9-10Table 9-6. Sample Calculation Methodology Rank 4—Summaryof Emissions (When Property Data Are Not Available)CASNumberComponent “i”At 40°FGasoline,Vapor,wt%At 40°FEGasoline= 939 lbELSpecies“i” (lb)At 77°FGasoline,Vapor,wt%At 77°FEGasoline= 1,972 lbELSpecies“i” (lb)At 90°FGasoline,Vapor,wt%At 90°FEGasoline= 4,538 lbELSpecies“i” (lb)Sum TotalAnnualEmissions (lb)71-43-2 Benzene0.33 3.140.428.24 0.45 20.2231.60110-54-3 Hexane0.96 9.051.1322.30 1.18 53.6484.99108-88-3 Toluene0.77 7.231.0921.55 1.21 55.0183.801330-20-7 Xylene0.22 2.020.356.93 0.41 18.4627.41100-41-4 Ethylbenzene0.04 0.380.071.30 0.08 3.455.13540-84-1 2,2,4-Trimethylpentane0.23 2.150.305.87 0.32 14.5822.5998-82-8 Cumene0.0027 0.0250.00480.094 0.0057 0.260.3891-20-3 Naphthalene0.0001 0.0010.00030.006 0.0004 0.0180.025Total HAP 24.0 66.3 165.6255.9

### Version 2.1.1 Final ICR Version – Corrected Section 10—Fugitive Dust Sources

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 petroleu m coke storage and handli ng. 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 emission measurem ent 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 th e fugitive dust emission correlations are specific to petroleum refineries. Table 10-1 provides recommended default valu es 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 Sec tion 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 provid ed 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 catalyst “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 % 10 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 faci lity factor in Table 13.2.1-4 in AP-42.

c Based on range for industrial si tes in Table 13.2.2-3 in AP-42.
d Assumed based on median particle size of FCCU cata lyst and equilibrium catalyst (E-cat) of 65 μm.

e Values for coke breeze assumed to apply.
f Value suggested as typical by industr y representatives (API/NPRA, 2010).
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 emissions are all filterable PM so that PM10-PRI = PM10-FIL and PM25-PRI = PM25-FIL. For FCCU catalyst handling emissions and for petroleum coke ha ndling activities, emission estimates should also be provided for metal HAP emissions. Concentrations of specific metal HAP are commonly determined for the FCCU equilibrium catalyst; these con centrations can be used times the PM 10 

### emission rate to

### Version 2.1.1 Final ICR Version – Corrected Section 10—Fugitive Dust Sources

10-2 determine the metal HAP emission 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. These concentration ratios can be used to augment the FCCU catalyst and E-cat metal HAP emission 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.

### Version 2.1.1 Final ICR Version – Corrected Section 11—Startup and Shutdown

11-1 

# 11. Startup and Shutdown Except for the CEMS-based measurements (i.e., Methodol ogy Rank 1), most of the emission estimation methods provided in this Refinery Emissions Pr otocol document characterize the emissions during normal operating conditions. However, during start up and shutdown, the process operations are not normal. During startup, the reactor temperatures may not be sufficient for the n ecessary reactions to occur or the process flow rate may be well below ty pical operating conditions . Under these conditions, processes that do not typically have atmospheric em issions may have significant emissions. While most control devices will operate well at lower vent rat es, some control devices, such as venturi scrubbers, require a minimum flow for effective operation. During startup and shutdown, the emission characteristics of the processes may be significantly di fferent than those during normal operations. When the emission estimation methodology relies on normal ope rating 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 fac ility’s annual emission totals. 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 sy stem. When a hydrotreater or hydrocracking unit is shutdown, this often leads to ex cess 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 fo r combustion sources and flares. However, if default estimates (or site-specific estima tes based on source tests conducted under typical operating conditions) are used, then emissions during these significant fuel g as 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 emi ssion event during startup or shutdown is expected to be vessel depressurization and purging (or degassi ng). Methods are provided in this section to account for these events are described in this section.



## 11.1 Gaseous Process Vessel De pressurization and Purging Process vessel depressurization for gaseous processes 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 partic les, 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. 

# ( ) 

# [ ] ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × × × ° × +

= i i void V V V i 

## MF MVC MW f V T P E R 528
7

. 14 7

. 14 (Eq. 11-1)

where:

E i 

### = Emissions of pollutant “i” during depressurization event (lbs/event). P V 

### = Gauge pressure of the vessel when depr essurization 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).

### Version 2.1.1 Final ICR Version – Corrected Section 11—Startup and Shutdown

11-2 528 = “Standard” temperature 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). MVC = 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 the refinery fuel gas system or a flare or similar control device. Combustion of gases purge d to the refinery fuel gas system (either directly or via a flare gas recovery system) should be accounted for under st ationary combustion source emissions regardless of the methodology used for stationary combustion sour ces. Depending on the methodology used to estimate the emissions from the flare, these gas flows may or ma y not be included in the flare emission estimates. If the flow rate and composition or heating value of the flare gas is measured (Methodology Ranks 1, 2 or 3 for flares), special calculations are not needed beca use episodic releases to the flare, such as those from depressurization and purging events, are adequately accounted for. If the flare emission methodology does not account for these flows (e.g., default factors in Methodology Rank 6 for flares), Equation 11-1 can be used to estimate the mass of gas sent to the flare or other control device (using initial depressurization temperatures and pressures) and these m ass rates can be adjusted by the flare or control device efficiency to estimate the emissions during the controlled venting period. The use of Equation 11-1 is illustrated in Example 11-1 , G aseous Depressurization Calculation

. 

## 11.2 Liquid Process Vessel Depr essurization 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 th e vessel, and the location of the drainage port or pump line (higher viscosities, higher internal surface areas, and high er drainage port locations will increase the heel fraction). Using the heel method, it is assumed the en tire liquid heel is eventually volatilized. Knowledge of the process stream can be used to speciate the emi ssions. Again, some of the heel may be purged to a flare or other control device 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.

### Version 2.1.1 Final ICR Version – Corrected Section 11—Startup and Shutdown

11-3 Example 11-1: Gaseous Depressurization Calculation A catalytic reforming unit is depressurized and pur ged 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 temperatur e and pressure of the vessel when first purged to the atmosphere are 250°C and 10 psig, respectiv ely. 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 liste d 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: 

# ( ) 

# [ ] tons 014

. 0 lbs 5

. 27 01

. 0 3

. 385

78 6

. 0 20000 942 R 528
7

. 14 7

. 14 0 1

= = ⎟ ⎠ ⎞ ⎜ ⎝ ⎛
× × × × ° × +

= i 

## E

Similarly, the emissions of other organic constituents are estimated to be:
Benzene = 27.5 lbs/event Hexane = 12.6 lbs/event 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, wh ich is 158 lbs/event or 0.079 tons/event. If this event occurred twice during the year, the annual emission would be 0.16 tons VOC/yr.

### Version 2.1.1 Final ICR Version – Corrected Section 11—Startup and Shutdown

11-4 Example 11-2: Liquid 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, th e 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). Appendix A contains average composition of va rious 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, th e 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 flare, 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)]. Therefore, a total of 354 lbs of organic materi al (VOC) is estimated to be emitted considering emissions from both the flare and atmospheric purging. Emissions of specific constituents are calcula ted 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.

### Version 2.1.1 Final ICR Version – Corrected Section 12—Malfunctions/Upsets

12-1 

# 12. Malfunctions/Upsets Malfunctions or upsets may occur either within the process unit or to a control device used to reduce a source’s emissions. During malfunction/upset events (h ereafter simply referred to as malfunction events), emissions may be significantly higher than the emi ssions that occur under normal operating conditions. Except for the CEMS-based measurements (i.e., Methodol ogy Rank 1), most of the emissions estimation methods provided in this Refinery Emissions Pr otocol document characterize the emissions during normal operating conditions. As such, emissions dur ing malfunction events must be accounted for separately for each malfunction event and these malfunc tion/upset emissions must be added to the normal process emissions to accurately estimate annual emissions.
Because of the myriad of potential malfunction even ts that could occur, it is impossible to provide specific guidance for all possible malfunction scenar ios. 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 emis sions should be included in the annual emissions reported in response to the ICR.
The following list provides specific events for wh ich malfunction/upset emissions estimates should be made to accurately account for these emissions. Again, th is 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 emission methodol ogy (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 malfunc tion events in light of their inventory methods to determine if it is appropriate to use special ma lfunction emission calculations. Emission 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 

### emission estimates from combustion sources, flares, and/or sulfur recovery plants). 3. Instances of over-steaming a flare (steam-to-g as ratios exceeding 4) or instances where the flare operating conditions do not satisfy 40 CFR 60.18 (i.e., inadequate BTU content, exit velocities exceeding limits). Eighty percent flare destruction efficiencies should be used during periods of over-steaming; 93 percent flare destruction effici encies should be used during periods when the flare operating conditions do not satisfy 40 CFR 60.18. 4. Any instance when a spill or similar emergency release occurs.
Leaks identified as part of a LDAR work practice (for equipment leaks or cooling towers) are not considered malfunction events, and these emissions are covered using the methodologies presented in Section 2, Equipment Leaks , and Section 8, Cooling Towers , of this Refinery Emissions Protocol document. Note, however, the methodology for spills pr esented in this section can be used for estimating emissions from equipment leaks that result in liquid puddles. As noted in Section 3, Storage Tanks , of this Refinery Emissions Protocol document, specific calc ulations should be made for tank roof landings. The emissions from tank roof landings are independent of the cause of the landing (intentional or unintentional), so there is no need to distinguish between landings that occur as a result of a “malfunction event” or for another reason.
There are three types of malfunction events consid ered in this section: control device malfunctions; process vessel overpressurization; and spills.

### Version 2.1.1 Final ICR Version – Corrected Section 12—Malfunctions/Upsets

12-2 

## 12.1 Control Device Malfunctions
When a control device is used to reduce the emissions from a particular source, the site-specific emission 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 annua l emissions projected for the controlled emission

source.
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 based on the control device’s efficiency. It is important to note that the contro l 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 in crease 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. If site-specifi c emission data are available for the controlled emissions, then the “uncontrolled” emissions duri ng the control device malfunction or bypass can be estimated using Equation 12-1.



## t EM E E i cont i cont i unc 

## × × =

, , , 

### (Eq. 12-1)

where:

E unc,i 

### = Uncontrolled emissions estimate from control device malfunction or bypass for pollutant “i” (kg/event) E cont,i 

### = Controlled emission rate of pollutant “i ” from measurement data or site-specific emission test data (kg/hr) EM cont,i 

### = Controlled emission multiplier for pollutant “i” based on the source on control device from Table 12-1 t = Duration of the event (hr/event).

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 Emission Multiplier 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, VO C, most organic HAP 98% 50
NO X , PAH, Formaldehyde -100% 0.5
FCCU or FCU/SCR NO X 92 12.5
FCCU or FCU/SNCR NO X 60% 1.7 (continued)

### Version 2.1.1 Final ICR Version – Corrected Section 12—Malfunctions/Upsets

12-3 Table 12-1. Control Device Efficiency and Multiplier Factors for Control Device Malfunctions (continued)

Source/Control Device Description a Pollutant Class b Control Device Efficiency c (%) Controlled Emission Multiplier d
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 contro l device are listed. For other pollutants, assume the

control device efficiency is 0% and the c ontrolled emission multiplier is 1.

c Control device efficiency. A negative number indicates a control device that may increase the emissions of a

particular pollutant.
d Controlled emission 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 pr essure excursions that must be released from the vessel to prevent a catastrophic failure. Generally, th ese 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 emission methodology does not account for these flow s (e.g., default factors) or if the flow rate during the event exceeds the range of the flow meter installed on the flare gas line, then the methods provided in this section should be used. For discharges through a pressure relief valve or simi lar discharge of a compressible fluid, the flow velocity through the valve, pipe, or other restric tion is limited to the speed of sound or Mach 1. Discharges that are limited by the speed of sound ar e termed “choked” or “sonic,” and discharges that are less than Mach 1 are termed “unchoked” or “subsonic. ” For a pressure relief valve, the outlet pressure is typically known, being either atmospheric pressure (14.7 psia) or atmospheric pressure plus the backpressure of the flare system or other control device. To determine if the flow is choked, first use Equation 12-2 to determine the critical vessel pressure for sonic flow conditions. ( ) 1 /



## 2 1 − 

## ⎟ ⎠ ⎞ ⎜ ⎝ ⎛ +

= ° k k

out vessel 

## k P P (Eq. 12-2)

where:

P vessel 

### ° = Critical vessel pressure for sonic flow conditions (atm) P out 

### = Outlet pressure of vent or discharge piping (atm) k = Ratio of the specific heat at constant pr essure to the specific heat at constant volume, C p 

### /C v 

### (dimensionless); see Table 12-2 for values of k for different gases.

### Version 2.1.1 Final ICR Version – Corrected Section 12—Malfunctions/Upsets

12-4 Table 12-2. Values of k for Various Gases a

Compound k Compound k
Methane 1.30 Air 1.40 Natural gas (methane/ethane) 1.27 Hydrogen 1.40 Ethane 1.22 Nitrogen 1.40 Ethylene 1.20 Oxygen 1.40 Propane 1.14 Carbon monoxide 1.40
n-Butane or Iso-butane 1.11 Carbon dioxide 1.28 Pentane 1.09 Hydrogen sulfide 1.32 Hexane or Cyclohexane 1.08 Sulfur dioxide 1.26
Benzene 1.10

a k = C p /C v = ratio of the specific heat at constant pressure to the specific heat at constant volume



### If the actual vessel pressure is less than the critical vessel pressure, P vessel 

### °, calculated from Equation 12-2, then the flow will be subsonic (unchoked). For subson ic flow, first calculate the Mach number of the discharge flow using Equation 12-3.



## ⎥ ⎥ ⎥
⎦ ⎤

⎢ ⎢ ⎢
⎣ ⎡

− ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

− = ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

− 

## 1 1 2 M 1 k k

out vessel 

## P P k (Eq. 12-3)

where: M = Mach number of the discharge flow P out 

### = Pressure at the discharge outlet, typically atmospheric (atm).
The mass emissions rate is then calculated using Equation 12-4. 

# ( ) ( ) ( ) 1 2 1 2 4



## 2 1 M 1 M 10 8087

. 6

− + 

## ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

− + × × × × × × × =

k k vessel vessel i i 

## k T R MWt k P A C E (Eq. 12-4)

where:

E i 

### = Emission rate of pollutant “i” (lb/sec) C i, 

### = Concentration of pollutant “i” in the discharged gas (weight fraction) 6.8087×10 4 

### = Conversion factor (lb/(ft sec 2 

### ) per atm) A = Cross-sectional area of the vent outlet (ft 2 

### ) MWt = Molecular weight of gas discharged (lb/lb-mol) R = Ideal gas law constant = 4.968×10 4 

### (lb ft 2 

### )/(sec 2 

### °R lb-mol) T

vessel 

### = Temperature of gas in vessel (°R).
If the vessel pressure is greater than P vessel 

### °, then the flow will be choked (i.e., limited to sonic flow). Therefore, M is set to 1, and Equation 12-4 can be used (with M=1) to calculate the mass emission rate during the discharge.

### Version 2.1.1 Final ICR Version – Corrected Section 12—Malfunctions/Upsets

12-5 If the releases are discharged to a flare or other control device (and these discharges are not otherwise measured), the calculated mass release rates determined using Equation 12-4 must then be adjusted by the control efficiency to estimate the emissi ons during the emergency release event. Equation 12-4 is expressed as an instantaneous emis sion rate. If the vessel pressure and temperature remain fairly constant (less than 5% change) during the event, the in stantaneous rate can be multiplied by the duration of the release to determine the total em issions for the event. If the vessel pressure and temperature vary, Equation 12-4 should be estimated fo r discrete time intervals and the emissions for each time interval determined and summed to calcula te the total emissions during the event.

Example 12-1: Calculation for Emissions for Vessel Overpressurization

Given: A hydrocracking unit has a 4 inch diameter pressure relief valve set to open at 2,000 psig. The gas phase is 50 vol% H 2 

### and 50 vol% light (C2 throug h C4) hydrocarbons. If the pressure relief valve opened for 30 minutes, what are the VOC emissions from the unit during the event? Assume the vessel discharges to a flare with an average back pressure of 10 psig. The average temperature and pressure of the vessel during the event were 400 °C and 2,050 psig, respectively.
Solution: P out 

### = 10+14.7 = 24.7 psia. On a mass basis, mo st of the flow will be the hydrocarbons. Therefore, the k value for propane of 1.14 is selected from Table 2-2 as representative of the gas stream. To determine if the flow is choked, firs t use Equation 12-2 to determine the critical vessel pressure for sonic flow conditions. ( ) ( ) 

## psia 9

. 42 2 1 14

. 1 7

. 24 2 1 14

. 0 / 14

. 1 1 /



## = ⎟ ⎠ ⎞ ⎜ ⎝ ⎛ +

= ⎟ ⎠ ⎞ ⎜ ⎝ ⎛ +

= ° − k k

out vessel 

## k P P

The pressure of the vessel is far greater than this, so the flow is choked. Equation 2-4 is used to calculate the discharge rate by setting the Mach number is set to 1. Equation 2-4 requires the following variables in specific units.

• MWt: Using propane’s molecular weight of 44 lb/lb-mol for the hydrocarbon portion, the average molecular weight of the discharge gas is: 0.5×2 + 0.5×44 = 23 lb/lb-mol.

• C i 

### : Using propane as the surrogate for the VOC, the weight fration of VOC is 0.5×44/23 = 0.9565 weight fraction VOC.

• A: Valve diameter = 4”/12 = 0.3333 ft. Area = ( π /4)×(0.3333) 2 

### = 0.08725 ft 2



### • P vessel 

### : (2050+14.7)/14.7 = 140.5 atm

• T vessel 

### : (400 + 273.15)×1.8 = 1,212 °R Plugging these values into Equation 2-4 yields: 

# ( )

( ) 14

. 0 2 14

. 2 4 4



## 2 14

. 0 1 1 212
, 1 10 968

. 4 23 14

. 1 5

. 140 10 8087

. 6 08725

. 0 9565

. 0 ⎟ ⎠ ⎞ ⎜ ⎝ ⎛ + × × × × × × × × × = i 

## E



## lb/sec 314 5962

. 0 10 355

. 4 400
, 798 7 

## = × × × = − i 

## E
The event occurred for 1,800 sec (30 min ×60 sec/ min), so the total release was 565,200 lb or 283 tons. With a flare efficiency of 98%, the emis sions to the atmosphere related to this event was 5.66 tons VOC [283 × (1-0.98)].

### Version 2.1.1 Final ICR Version – Corrected Section 12—Malfunctions/Upsets

12-6 

## 12.3 Spills Generally, it can be assumed that 100% of the com pounds 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 , can be used. Equation 12- 5 can be used to estimate the emissions based on the qua ntity of material spilled, the area of the spill, and the time period from when the initial sp ill occurred to the final clean up: 

# ( ) V At K

o i i oil 

## e VC E /

, 

## 1 −



## − = ρ (Eq. 12-5)

where:

E i 

### = Emission estimate of pollutant “i” (kg/spill event) ρ = Density of spilled liquid (kg/m 3 

### ) V = Volume of spilled material (m 3 

### ) C i,o 

### = Concentration of pollutant “i” in spilled fluid prior to the spill event (mass fraction; kg/kg) K oil 

### = Mass transfer coefficient for an oil (organic) liquid (m/sec) t = Duration of the spill (sec) A = Area covered by the spill (m 2 

### ).

### Version 2.1.1 Final ICR Version – Corrected Section 13—References

13-1 

# 13. References API (American Petroleum Institute). 2002. Refinery Stream Speciation . API Publication No. 4723. November 1.
API (American Petroleum Institute). 2009. Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry . August 2009. Available at: http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf

. API (American Petroleum Institute) and NPRA (Nationa l Petrochemical and Refiners Association). 2010. Review of the Emission Estimation Protocol for Petroleum Refineries. Letter to Ms. Brenda Shine, U.S. EPA. March 31.
Bertrand R. R., and J.H. Siegell. 2002. Emission of trace compounds from catalytic cracking regenerators, Environmental Progress, 21(3)163-167. October.
Bertrand R. R., and J.H. Siegell. 2003. Emission of trace compounds from catalytic reforming units, Environmental Progress, 22(1)74-77. April.
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.
EIIP (Emission Inventory Improvement Program). 2007. Methods for Estimating Air Emissions from Chemical Manufacturing Facilities . Volume 2, Chapter 16. Prepared by Mitchell Scientific, Inc. and RTI International. August.
EMEP/CORINAIR (European Monitoring and Evaluati on 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 Alte rnative Methods for Estimating Air Emissions from Boilers.” Prepared for Point Sources Comm ittee Emission Inventory Improvement Program. January.
Hansell, D., and G. England. 1998. Air Toxic Emission Factors for Combustion Sources Using Petroleum Based Fuels, Volumes 1 and 2 . API Publication 348. Prepared by EER for S. Folwarkow, Western States Petroleum Association, Concor d, 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.
Lev-On, M., Epperson, D., Siegell, J., and Ritter, K. (2007). Derivation of new emission factors for quantification of mass emissions when using optical gas imaging for detecting leaks. J Air Waste Manag Assoc 57( 9):1061-1070

### Version 2.1.1 Final ICR Version – Corrected Section 13—References

13-2Lucas, B. 2007. Memorandum from B. Lucas, EPA/SPPD, to Project Docket File (EPA Docket No. EPAHQ-OAR-2003-0146). Storage Vessels: Control Op tions and Impact Estimates . August 3, 2007. Docket Item No. EPA-HQ-OAR-2003-0146-0014.
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/HydrogenE ducation/6HydrogenPr oductionSteamMethaneR eforming.pdf

. Potter, T., and K. Simmons. 1998. Composition of Petroleum Mixtures
, Volume 2 . Total Petroleum Hydrocarbon Criteria Working Group Series. University of Massachusetts. Amherst, Massachusetts.
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, Resear ch 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, Ca lifornia—Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (P M) 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.
SCAQMD (South Coast Air Quality Management Dist rict). 2004c. Source Test Report 03-198 Conducted at Exxon Mobil Refinery, Torrance, Californ ia—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—Volatile Organic Compound (VOC), Carbon Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent . July 1.
TCEQ (Texas Commission on Environmental Qua lity). 2000. Air Permit Technical Guidance for Chemical Sources: Loading Operations.
TCEQ (Texas Commission on Environmental Qua lity). 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.

### Version 2.1.1 Final ICR Version – Corrected Section 13—References

13-3 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 Qua lity 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). 1998c. Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Boilers—F inal Report to Congress. Volume 1 . EPA-453/R-98- 004a. Office of Air Quality Planning and Standards, Research Triangle Park, NC.
U.S. EPA (Environmental Protection Agency). 2006. TANKS Emissions Estimation Software, Version 4.09D . Office of Air Quality Planning and St andards, Technology Transfer Network, Clearinghouse for Inventories and Emissions Factors, Available at http://www.epa.gov/ttn/chief/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.
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.

### Version 2.1.1 Final ICR Version – Corrected Section 13—References

13-4 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Appendix A—Average Stream Compositions

A-1 

# Appendix A Average Stream Compositions

### Version 2.1.1 Final ICR Version – Corrected Appendix A—Average Stream Compositions

A-2 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Appendix A—Average Stream Compositions

A-3 Table A-1. Refinery Average Stream Hazardou s Air Pollutant Compositions—Default Values

Average Weight Percent of Compound in Process Unit Stream a1,3-Butadiene106-99-0n-Hexane110-54-32,2,4-Trimethylpentane540-84-1Benzene71-43-2Toluene108-88-3Xylenes (total)1330-20-7Ethylbenzene100-41-4Cumene98-82-81,2,4-trimethylbenzeneb95-63-6Naphthalene91-20-3Biphenyl92-52-4Styrene100-42-5

Process Units Atmospheric Distillation 0.01 4.28 0.05 0.86 1.7 1.97 0.63 0.12 0.63 0.25 0.06 0.001
Vacuum Distillation - 0. 007 0.004 0.004 0.043 0.020 0.024 0.001 0.020 0.12 0.09 - Coking Unit 0.04 2.49 0.75 0.42 1. 30 1.76 0.70 0.12 0.70 0.28 0.001 0.19 Cat Hydrocracker 0.03 1.86 1.04 1.27 2.72 2.67 1.02 0.09 1. 33 0.20 0.001 0.19
FCCU 0.01 0.99 0.29 1.03 3.28 4. 90 1.07 0.10 1.92 0.72 0.43 0.14
CRU 0.009 2.75 0.25 6.34 17.44 17. 61 3.88 0.42 5.93 0.87 0.001 0.11 Hydrodesulfurization - 1.89 0.0001 0.37 1.72 1.94 0.37 0.07 0.40 0.25 0.22 - Alkylation 0.22 1.57 25. 24 0.03 2.05 0.08 5.0E-5 5.0E-5 5.0E-5 5.0E-5 5.0E-5 0.02
Isomerization - 3.22 0.01 0.51 0.64 0.15 - - - - - - Polymerization - 0.54 0.73 1.24 1.76 1.18 0.09 - - - -
Products
Aromatics Extract - Benzene - - - 99.99 0.009 0.002 - - - - - -
Aromatics Extract - Toluene - - - 0.296 95.61 3.49 2.82 - 0.3 - - -
Aromatics Extract - Xylenes - - - - - 77.89 16.08 0.59 - - - -
Aromatics Extract - Heavy Aromatics - - - 5.7 19.36 25.03 3.56 0.965 4.94 0.314 - -
Commercial Jet Fuel - 1.68 0.0006 0. 577 0.965 1.22 0.257 0.106 0.815 0.627 0.409 -
Conventional Gasoline 0.0009 2.22 2.94 1.4 c 7.75 6.56 1.490 0.219 3. 002 0.415 - 0.0767
Aviation Gasoline - 2.30 - 1. 01 7.69 3.37 1.2 0. 103 0.5 0.695 - -
Reformulated Gasoline - 1.36 1.10 0.8 b 7 7.31 1.26 0.19 2.52 0.21 - -
Diesel Fuel - 0.030 0.007 0.004 0.081 0.241 0.053 0.056 0.349 0.285 0.117 - Home Heating Oil - - - - 0.108 0.300 0.095 - 0.429 0.453 0.181 -
Solvent-refined Lubes - - - - - - - - - - - -

Crude Oil 9.81E05 1.341 0.185 0.312 0.542 0.811 0.186 0.108 0.377 0.139 0.030

a 

### Based on Petroleum Environmental Re search Forum (PERF) refinery proce ss stream speciation study (API, 2002),

unless otherwise specified. b 

### 1,2,4-Trimethylbenzene is not a HAP, but it is a prevalent VOC in many refinery streams.

c 

### Average benzene content of conventional and reformulated gasoline based on Fuel Trends Resport: Gasoline

1995-2005 (U.S. EPA. Report No. EPA420-R-08-002. January 2008), corrected to weight percent using the density correction factor of 0.876/0.739 (i.e., 1.16vol%×0.876/0.739 = 1.4wt%; 0.67vol%×0.876/0.739 = 0.8wt%).

### Version 2.1.1 Final ICR Version – Corrected Appendix A—Average Stream Compositions

A-4 

## 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, an d 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.”

i i i 

## MW Wtfrac n = (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).

T i i 

## n n x = (Eq. A-2)

3. Equation A-3 should be used to calculate the pa rtial pressure of each component “i” in liquid.

P(i) = P × x i 

### (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, Eq uation A-4 should be used to estimate the average vapor pressure for the gasoline mixture by summ ing the partial pressure of each component “i” (liquid). 

# ∑
= n

i totalVP 

## P P

1 

### (Eq. A-4)

5. From mole fraction of component “i” (liquid), E quation A-5 should be used to estimate the mole fraction of component “i” in the vapor using Raoult’s law.

totalVP

i i 

## P P y = (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 

### ). 

# ∑ × = n

i i Vap 

## MW y MW

1 

### (Eq. A-6)

where:

MW VAP 

### = Molecular weight of the vapor (lb/mol) MW i 

### = Molecular weight of component “i” (lb/mol)

### Version 2.1.1 Final ICR Version – Corrected Appendix A—Average Stream Compositions

A-5 7. Equation A-7 should be used to estimate the g asoline vapor weight fractions using the gasoline vapor mole fractions and the MW VAP 

### .

Vap i i vap 

## MW MW y Wtfrac ×

= (Eq. A-7)

Example A-1: Calculation of Vapor Pressure and Molecular Weight for Reformulated Gasoline Loading Example Calculate the vapor pressure of gasoline and MW VAP 

### for submerged loading of reformulated gasoline into dedicated-service g asoline transport tank trucks (each with a volume of 8,000 gallons) based on the following information: The refinery loads 100 tank trucks per year at a bulk temperature of 77°F. Property 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 equation and Antoine’s coefficients, su ch 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 composition, 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.

i i i 

## MW Wtfrac n =

 Step 2.

T i i 

## n n x =

 Step 3. i 

## x P i P × = ) (

 Step 4. 

# ∑
= n

i totalVP 

## P P

1



###  Step 5.

totalVP i i 

## P P y =

 Step 6. 

# ∑ × = n

i i Vap 

## MW y MW

1



###  Step 7.

Vap i i vap 

## MW MW y wtfrac ×

=

See Table A-2 for the calculations of thee variables. At 77°F, the total system vapor pressure is 4.77 psia and the MW of the vapor, MW GasolineVAP 

### , is 67.4 lb/lb-mol.Version 2.1.1Final ICR Version – Corrected Appendix A—Average Stream CompositionsA-6Table A-2. Sample Calculation of AverageMolecular Weight and Vapor Weight FractionaStep 1Step 2Step 3Step 4Step 5Step 6Step 7ABCD=C/AE=D/(ΣD)F=E*BG=F/(ΣF)H=G*AG=H/(ΣH)*100%CASNumberCompoundMolWtPvap at77°F (psia)GasolineLiquid(wt%)GasolineLiquid(moles/100g)GasolineLiquid(molefraction)GasolinePartialPressure(psia)GasolineVapor(molefraction)MolWtContributionGasolineVapor (g/mol)GasolineVapor (wt%)71-43-2 Benzene78.11 1.840 0.801.02E-04 9.36E-03 1.72E-02 3.61E-03 2.82E-01 0.42110-54-3 Hexane86.18 2.928 1.36 1.58E-04 1.44E-02 4.22E-02 8.85E-03 7.63E-01 1.13108-88-3 Toluene92.14 0.550 7.0 7.60E-04 6.94E-02 3.82E-02 8.01E-03 7.38E-01 1.091330-20-7 Xylene106.14 0.169 7.31 6.89E-04 6.30E-02 1.07E-02 2.23E-03 2.37E-01 0.35100-41-4 Ethylbenzene106.17 0.184 1.261.19E-04 1.08E-02 1.99E-03 4.18E-04 4.44E-02 0.07540-84-1 2,2,4-Trimethylpentane 114.23 0.954 1.0989.61E-05 8.79E-03 8.38E-03 1.76E-03 2.01E-01 0.3098-82-8 Cumene120.19 0.089 0.19 1.58E-05 1.44E-03 1.28E-04 2.68E-05 3.23E-03 0.00591-20-3 Naphthalene128.17 0.005 0.21 1.64E-05 1.50E-03 7.63E-06 1.60E-06 2.05E-04 0.0003106-97-8 n-Butane58.12 35.220 4.7 8.09E-04 7.39E-02 2.60E+00 5.46E-01 3.17E+01 46.9972-28-5 Isobutane58.12 13.294 1.7 2.92E-04 2.67E-02 3.55E-01 7.45E-02 4.33E+00 6.42109-66-0 Pentane72.15 10.285 3.9 5.41E-04 4.94E-02 5.08E-01 1.07E-01 7.69E+00 11.3978-78-4 Isopentane72.15 3.670 7.9 1.09E-03 1.00E-01 3.67E-01 7.70E-02 5.56E+00 8.23C6 surrogate 86.18 4.094 10.081.17E-03 1.07E-01 4.38E-01 9.18E-02 7.91E+00 11.72C7 surrogate100.2 1.274 7.21 7.20E-04 6.58E-02 8.38E-02 1.76E-02 1.76E+00 2.61C8 surrogate 114.23 0.522 3.21 2.81E-04 2.57E-02 1.34E-02 2.81E-03 3.21E-01 0.48C9 surrogate 120.19 0.039 7.29 6.07E-04 5.54E-02 2.18E-03 4.57E-04 5.49E-02 0.08Other VOC 100.20 0.884 34.78 3.47E-03 3.17E-01 2.80E-01 5.88E-02 5.89E+00 8.73nTPtotalVPMWvapTotal1000.0109 1.004.77 1.0067.49 100aWeight percents for HAP based on composition provided in TableA-1; weight percent VOC from n-butane to C9 surrogate are basedonComposition ofPetroleum Mixtures, Volume 2 of the Total Hydrocabon Criteria Working Group Series. Prepared by T.L. Potter and K.E. Simmons. May 1998.ISBN 1-844-940-19-6; n-Heptane was used as the surrogate forthe remaining uncharacterized fraction of the liquid gasoline (“other VOC”). Facilities shoulduse facility-specific data for light VOC (C4to C6 compounds) concentrations becausethese significantly impact the calculatedvapor-phase composition.

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-1 

# Appendix B Wastewater Treatment System Equations

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-2 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-3 

## 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 emission 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 Mass 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 ma ss transfer resistance. The liquid and gas phase mass transfer resistances ar e 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 surfa ce area and the overall mass transfer coefficient for the quiescent surface area based on an area weighted average as follows:



## A A

K A K K q q OL t t OL OL 

## × + ×

= , , 

### (Eq. B-1)

where:

K OL 

### = Overall mass transfer coefficient (m/s) K OL,t 

### = Overall mass transfer coeffici ent 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 coeffici ent 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 turbulen t surface areas based on the two resistance module is:

1

, , , 

## 1 1 − 

## ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× ′ + =

t g t l t OL 

## k H k K (Eq. B-2)

where:
k l,t 

### = liquid phase mass transfer coeffici ent 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 coefficien t for turbulent surface areas (m/s)
Similarly, the overall mass transfer coefficient for quiescent surface areas is

1

, , , 

## 1 1 − 

## ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× ′ + =

q g q l q OL 

## k H k K (Eq. B-3)

where:
k l,q 

### = Liquid phase mass transfer coeffi cient for quiescent surface areas (m/s) k g,q 

### = Gas phase mass transfer coeffici ent for quiescent surface areas (m/s).

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

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 emission model developed by EPA. The documentation of these mass transfer correlations can be accessed from EPA’s Web site at http://www.epa.gov/ttn/chief/software/water/index.html . Only the basic equations are provided here. For a more detailed discussion of these mass transfer correlati ons, 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 transf er coefficient is calculated as follows:
( ) 5

. 0

, 2 , 20 3

, 

## 76

. 10 024

. 1 10 22

. 8 ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛ ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × × × × × × ×

= − −

l O l i

l t l cf T
tot
t l 

## D D
A MW O P J k ρ (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 transf er coefficient is calculated as follows:

1

. 21

. 0 5

. 0 4

. 0 42

. 1 7

, 

## Re 10 35

. 1 −
− − 

## × × × × × × × × = imp a a i g g t g 

## d MW D Fr Sc p k (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 

### / [(62.428 ρ 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

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-5 B.1.3 Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces The appropriate correlation to use to estimate the li quid 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, assuming a circular shape. That is,

5

. 0 

## 4 ⎟ ⎠ ⎞ ⎜ ⎝ ⎛

= π A F (Eq. B-6)

where: F = Fetch (m)
For wind speeds less than 3.25 m/s, the following correla tion is used regardless of the fetch-to-depth ratio (F/d liq 

### ):

3 2

, 6

, 

## 10 78

. 2 ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× = −

ether l i
q l 

## D D k (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, th e appropriate correlation is dependent on the fetch-todepth ratio as follows: 

# ( ) ( ) 5

. 0 * 4 6

, 

## 10 10 0

. 1
, 14 −
− − 

## × + × = < liq b

q l liq 

## Sc U a k d F For (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 

### )

3 2

, 2 7 9

, 

## 10 277

. 1 10 605

. 2
, 2

. 51 14 ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛ ⎥ ⎥ ⎦ ⎤ ⎢ ⎢ ⎣ ⎡

× + ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× = ≤ ≤ − −

ether l i

liq q l liq 

## D D U d F k d F For (Eq. B-9)

3 2

, 2 7

, 

## 10 611

. 2
, 2

. 51 ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× = > −

ether l i
q l liq 

## D D U k d F For (Eq. B-10)

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-6 B.1.4 Gas Phase Mass Transfer Coefficient for Quiescent Surfaces The gas phase mass transfer coefficient for qui escent surface areas is estimated as follows:

11

. 0 67

. 0 78

. 0 3

, 

## 10 82

. 4
− −
− 

## × × × × = F Sc U k g q g 

### (Eq. B-11)



## B.2 Collection System s and Process Units The fraction emitted (fe) values for the collection syst em components are based on the models described in the EPA document titled Industrial Wastewater Volatile Organic Compound Emissions (U.S. EPA, 1990). Briefly, the correlation between the fracti on emitted (fe) and Henry’s law constant were determined. The correlation equations were then used to determine the emissions for each compound and uncontrolled collection system component.

Table B-1. Model Collection System Components and fe–Henry’s Law Correlation
Collection System Component Correlation Drains fe=0.035*ln(HLC)+0.4079 Trenches fe=0.005*ln(HLC)+0.0658 Manholes fe=0.009*ln(HLC)+0.1036 Junction Boxes fe=0.0105*ln(HLC)+0.1416 Lift Stations fe=0.0312*ln(HLC)+0.4163 Sumps fe=0.0004*ln(HLC)+0.007



### B.2.1 Junction Boxes and Lift Stations Junction boxes and lift stations collect and equali ze wastewater prior to pumping to the wastewater treatment system. As previously mentioned, these co mponents 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 tran sfer 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: 

# ( ) ⎥ ⎥ ⎦ ⎤ ⎢ ⎢ ⎣ ⎡

= −

t l i T

t l 

## A D V k 5

. 0

, ) 20 (

, 

## 024

. 1 184

. 0 (Eq. B-12)

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 tr ansfer coefficient for quiescent surfaces (k g,q 

### ) as described in Section B.1.4, Gas Phase Mass Transfer Coe fficient for Quiescent Surfaces

.

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-7  Step 3: Calculate the overall mass transfer coefficient (K) with the following equation: 

# ( ) ( )

t l q g q g t l OL 

## k k H k H k K

, , , ,


## ' '

+ = (Eq. B-13)

 Step 4: Calculate the tank effluent concentration (C L 

### ) with the following equation:


# ( ) Q A K QC m g C

OL

L 

## + = 0 3 

## ) / ( (Eq. B-14)

 Step 5: Calculate the air emissions (N) with the following equation: 

# ( ) A C K s g N L OL 

## = / (Eq. B-15)

B.2.2 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 tr ansfer 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 tr ansfer coefficient for quiescent surfaces (k g,q 

### ) as described in Section B.1.4, Gas Phase Mass Transfer Coe fficient for Quiescent Surfaces

.

 Step 3: Calculate the overall mass transfer coefficient (K) with the following equation: 

# ( ) ( )

q l q g q g q l OL 

## k k H k H k K

, , , ,


## ' '

+ = (Eq. B-16)

 Step 4: Calculate the tank effluent concentration (C L 

### ) with using Equation B-14:

 Step 5: Calculate the air emissions (N) with using Equation B-15:

B.2.3 Weirs Weirs are typically used in wastewater collection a nd treatment units as dams, allowing solids to settle in the quiescent areas. The liquid phase mass transfer coefficients (k l 

### ) is determined by Equations B-17a and 17b. The gas phase mass transfer coefficients (k g 

### ) is determined using Equation B-18. These liquid and gas phase mass transfer coefficient equations are b ased on the work presented by Nakasone (1987) and Pincince (1991). Air emissions ( N ) for each pollutant are calcu lated using equation B-20.
(Eq. B-17a)

(Eq. B-17b)

(Eq. B-18)

(Eq. B-19)

(Eq. B-20)

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-8 where: Q = Volumetric flow rate (m 3 

### /s) C o 

### = Initial constituent concentration (g/m 3 

### ) h = Weir height (ft) r = oxygen deficit ratio q = hydraulic weir loading [m 3 

### /(m·h)] Z = tailwater depth (m) k l 

### = liquid-phase mass transfer coefficient (m/s) D lv 

### = diffusion coefficient for the organic in water (cm 2 

### /s) D lo 

### = diffusion coefficient for air in water (cm 2 

### /s) k g 

### = gas-phase mass transfer coefficient (m/s) D gv 

### = diffusion coefficient of the organic in air (cm 2 

### /s) D go 

### = diffusion coefficient of the reference material in air (cm 2 

### /s) K o 

### = overall mass transfer coefficient (m/s) K = partition coefficient (atm-m 3 

### /mol) N = air emissions (g/s).
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 a nd thus open-air emission estimations are not required. However, if the treatme nt units are uncovered, then the following procedure can be used to estimate air emissions.
First, calculate the gas phase mass tran sfer 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:

oil q g oil 

## Keq k K

, 

## = (Eq. B-21)

where:

o a oil oil a oil 

## P MW

MW P Keq ρ ρ *



## = (Eq. B-22)

Air emissions are determined from the following equations: 

# ( ) A C K s g N oil L oil
, 

## / = (Eq. B-23)

where: 

# ( )

oil oil oil

oil oil L 

## Q A K Co

Q m g C + = 3

, 

## / (Eq. B-24)

If the oil layer is > 1cm, then use this equation:


# [ ]

ow oil oil ow oil 

## K f f Co

K Co +

− = 1 (Eq. B-25)

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-9 If the oil layer is < 1cm, then use this equation:

oil oil 

## f Co Co = (Eq. B-26)



## Q f Q oil

oil 

## = (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 Coe fficient 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: 

# ( ) L a OL 

## C H Q A K s g N ′ + = ) / ( (Eq. B-28)

where:


# ( ) H Q Q A K QC m g C

a OL L 

## ′ + + = 0 3 

## ) / ( (Eq. B-29)

B.2.6 Equalization Tanks (Mixed Tank with No Biodegradation) Equalization tanks dampen variations in wastewater flow rate and pollutant load to lessen negative impacts on downstream processes. As previously men tioned, these tanks should be covered the vented; however, if these tanks are uncovered, then the followi ng procedure can be used to estimate air emissions:

 Step 1: Calculate the liquid phase mass tran sfer coefficient for turbulent surfaces (k l,t 

### ) with Equation B-4.

 Step 2: Calculate the gas phase mass tran sfer coefficient for turbulent surfaces (k g,t 

### ) with Equation B-5.

 Step 3: Calculate the liquid phase mass tr ansfer 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 tr ansfer coefficient for quiescent surfaces (k g,q 

### ) as described in Section B.1.4, Gas Phase Mass Transfer Coe fficient for Quiescent Surfaces

.

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-10  Step 5: Calculate the overall mass transf er coefficient for turbulent surfaces (K OL,t 

### ) with Equation B-2.

 Step 6: Calculate the overall mass tran sfer 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:


# ( ) Q A K QC m g C

OL

L 

## + = 0 3 

## ) / ( (Eq. B-30)

 Step 9: Calculate the air emissions (N) with the following equation: 

# ( ) A C K s g N L OL 

## = / (Eq. B-31)

B.2.7 Biological Treatment Unit (with a Known Wasting Rate) The determination of air emissions from biological treat ment units is similar to equalization tanks with the addition of a biodegradation factor. Additionall y, whereas turbulent a nd quiescent surface areas impact air emissions for mechanically aerated syst ems, the air volumetric flow rate impacts diffused aeration systems. Consequently, two slightly diffe rent methods are used to estimate air emissions.
For mechanically aerated systems, follow Steps 1 through 7 of Section B.2.5 to determine the overall mass transfer coefficient (K OL 

### ).
For diffused aeration systems, first calcula te the average diffused air flow rate Q a,avg 

### (m 3 

### /s):



## 2 0

, 

## ⎥ ⎦ ⎤ ⎢ ⎣ ⎡
+

= a g a

avg a 

## Q P

P Q

Q (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:

4

. 0

, ] 4 [ 

## 012

. 0 08

. 0 ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛
+ =

t avg a NH L 

## A Q
a K (Eq. B-33)

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 

### )

5

. 0

4
, , ] 4 [
, 

## ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

=

NH l l

i NH L t l 

## D D
a K a k (Eq. B-34)

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-11 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:



## a a k k t l

t l 

## 3600 ,

, 

## = (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:

t l t g 

## k k

, , 

## 3

= (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 emission rate (N) with the following equations.
For mechanically aerated systems: 

# ( ) A C K s g N L OL 

## = / (Eq. B-37)
For diffused aeration systems: 

# ( ) ( ) L a OL 

## C H Q A K s g N ′ + = / (Eq. B-38)

where: 

# ( ) ( ) 

# [ ]

a ac b b m g C L 

## 2 4 / 5

. 0 2 3 

## − +

−
= (Eq. B-39)

For mechanically aerated systems:

i e VSS WAS abs w OL 

## Q Q C k Q A K
a + +

= , 

### (Eq. B-40)


# ( )
0 max

, 

## C Q V C V Q C k Q A K Q Ks b

i MLVSS

e VSS WAS abs w OL i 

## − + + + = (Eq. B-41)

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-12 For diffused aerated systems:

i e VSS WAS abs w avg a OL 

## Q Q C k Q H Q A K
a + + ′ +

= , , 

### (Eq. B-42) 

# ( )
0 max

, , 

## C Q V C V Q C k Q H Q A K Q Ks b

i MLVSS

e VSS WAS abs w avg a OL i 

## − + + + ′ + = (Eq. B-43)

0 

## C K c S 

## − = (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:

OC OC abs 

## K f k 6 

## 10 1 −



## × = (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/MgC/(g/ m -3 

### ) 1×10 -6 

### = unit conversion (megagrams per gram, Mg/g)

where:


## 32

. 0 log log

− = OW OC 

## K K (Eq. B-46)

B.2.8 Biological Treatment Unit (with an Unknown Wasting Rate) Air emission 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 th is 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 se ttle, they are considered removed from the system.
Follow the procedure in Section B.2.6 to dete rmine the overall mass transfer coefficient (K OL 

### ), the unit effluent concentration (C L 

### ), and the emission rate (N). However, variables a, b, and c are determined by the following equations
For mechanically aerated systems:

i e abs i BODi OL 

## Q Q k Q C A K a + +

= 67

. 0 (Eq. B-47)



# ( ) 0 max 

## 67

. 0 C Q V C V Q k Q C A K Q Ks b

i MLVSS

e abs i BODi OL i 

## − + + + = (Eq. B-48)

### Version 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-13 For diffused aerated system:

i abs i BODi avg a OL 

## Q k Q C H Q A K
a 67

. 0

, 

## + ′ +

= (Eq. B-49) 

# ( )
0 max

, 

## 67

. 0 C Q V C V k Q C H Q A K Q Ks b

i MLVSS abs i BODi avg a OL i 

## − + + ′ + = (Eq. B-50)

0 

## C K c S 

## − = (Eq. B-51)



## B.3 References Hsieh, C., R. Babcock, and M. Stenstrom. 1992. Estimating semi-volatile or ganic compound emission rates and oxygen transfer coe fficients 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 Conf erence, Dallas, TX, October 5–9.
Nakasone, H. 1987. Study of aeration at weirs and cascades. J. Environ. Eng.113 :64.
Pincince, A.B. 1991. Transfer of oxygen and emissions of volatile organic compounds at clarifier weirs. Res. J. Water Pollut. Control Fed.
, 63 , 114-119.
U.S. EPA (Environmental Protection Agency). 1990. Industrial Wastewater Volatile Organic Compound Emissions—Background Informati on for BACT/LAER Determinations . EPA 450/3-90-004. Office of Air Quality Planning and Standards, Research Triangle Park, NC. January.
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 2.1.1 Final ICR Version – Corrected Appendix B—Wastewater Treatment System Equations

B-14 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-1 

# Appendix C
Primer for TANKS Model Users

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-2 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-3 

## C. Primer for TANKS Model Users
In general, EPA recommends that the emission estim ation 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 em ission estimation software that can be used to perform the necessary calculations detailed in Chap ter 7.1 of AP-42 (U.S. EPA, 1995a). TANKS v4.09D software can be downloaded for free at http://www.epa.gov/ttn/chief/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 usi ng the TANKS program. This appendix will also highlight some potential enhancements to the modeling of storage tank emissi ons that may be implemented when using the AP-42 equations directly (or pot entially 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 highly dependent on the type of liquid stored. Each indivi dual storage tank should be modeled separately. There may be instances in which a set of tanks have id entical properties and materials and very similar throughputs so that the emissions from a single storag e tank can be modeled and used as the emissions for each tank in the set. However, this type of “model ta nk” 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 in to the TANKS program (or other similar software), and the emission results for individual tanks be reported in the emission inventory. For some uses of the emission inventory data, specific emission location and source characteristi cs 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 emission 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 fi xed roof tanks; vertical fixed roof tanks; external floating roof tanks; internal floati ng roof tanks; and domed external fl oating roof tanks. Next, fill out the information in the Identification, Physical Characte ristics, Site Selection, Tank Contents, and Monthly Calculations tabs with th e appropriate information. Tables C-1 and C-2 show the required input by tank orientation. These inputs may either be from a dr op-down list based on the TANKS database for location, tank color, and other tank-specific information or take n 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.

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-4 Table C-1. TANKS Inputs by Tank Configurat ion-Tank Dimensions and Characteristics

Horizontal Tank Vertical Fixed-Roof Tank Internal Floating

Roof External Floating

Roof Domed External Floating

Roof
Identification number z z z z z Description z z z z z
State z z z z z City z z z z z Company z z z z z
Dimensions and Characteristics Shell height (feet [ft]) z z Diameter (shell diameter, ft) z z z
Volume z z Maximum liquid height z z Average liquid height z z Working volume (gallons) z z Turnovers per year z z z z Net throughput (gallons per year [gal/yr]) z z z

Is tank heated? z z Is tank underground? z Self-supporting roof z
Number of columns z
Effective column diameter z Roof type z z Roof fitting category z z
Tank construction z z

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-5 Table C-2. TANKS Inputs by Tank Configuration-Specific Attributes, Site Selection, and Contents

Horizontal Tank Vertical Fixed-Roof Tank Internal Floating

Roof External Floating

Roof Domed External Floating

Roof
Tank/Shell/Roof Characteristics (External) shell/paint color/shade z z z z z (External) shell/paint shell condition z z z z z
Internal shell condition z
Rim Seal Primary seal z z z Secondary seal z z z
Deck Characteristics Deck type z Deck fitting category z Breather Vent Settings Vacuum setting (psig) z z Pressure setting (psig) z z
Roof Characteristics
Color/shade z z
Condition z Type z Height (ft) z Roof paint condition z
Site Selection Nearest major city z z z z z Daily average ambient temperature z z z z z Annual average maximum temperature z z z z z Annual average minimum temperature z z z z z Average wind speed z z z z z Annual average solar insulation factor (Btu/(ft × ft ×day) z z z z z
Atmospheric pressure (pounds of force per square inch absolute [psia]) z z z z z

Tank Contents Chemical category of liquid z z z z z Single or multi-component liquid z z z z z Mixture properties, if applicable z z z z z Throughput by month z z z z z

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-6 For the internal floating roof tank, the external floa ting roof tank, and the domed external floating roof tank, it is possible to define the fitting type to re present specific characteristics of the tanks at your facility. Using facility-specific tank information will en sure that the calculated emission 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 emissi ons 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 not create a new tank record, it only renames and replaces the old record.
Because TANKS uses preloaded meteorological data, yea r-to-year variations in emissions will only result from differing throughput or tank service (storing di fferent material than in previous years). If accommodated in other software pack ages, meteorological data that are specific to the reporting year should be used because this information will provi de more accurate emission 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 av erage ambient temperatures should be used for the bulk liquid temperatures, and these values should be used to calculate monthly average emission 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 un likely to significantly alter the annual emission estimates. Based on limited model analyses, monthly variations in liquid temperature may be significant and may influence the annual average emissions if mo nthly emissions are estimated more rigorously (i.e., by accounting for variations in bulk liqui d temperature) (Coburn and Icenhour, 2008).
The TANKS program typically provides total hydrocarbon emission 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 or ganic 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 input s), then these can be added to the TANKS program.
In addition to the analysis of individual chemical s, the TANKS program also has the capability to calculate the characteristics of defined mixtures. When the “Multiple” option is selected for the “Singleor Multi-Component Liquid” option, and “Full Speciati on” 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 rela tive 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 be calculated by clicking on the Calculate Mixture Properties button.

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-7 Table C-3. Fitting Type and Status Option Inputs for TANKS Program
Fitting Type Status

Access hatch (24 inches in diameter) Bolted cover, gasketed Unbolted cover, gasketed Unbolted cover, ungasketed

Automatic gauge float well Bolted cover, gasketed Unbolted cover, gasketed Unbolted cover, ungasketed

Column well (24 inches in diameter) Built-up column, sliding cover, gasketed Built-up column, sliding cover, ungasketed Pipe column, flexible fabric sleeve seal Pipe column, slidin g cover, gasketed Pipe column, sliding cover, ungasketed Gauge-hatch/sample well (8 inches in diameter) Weighted mechanical actuation, gasketed Weighted mechanical actuation, ungasketed Ladder well (36 inches in diameter) Sliding cover, gasketed Sliding cover, ungasketed Rim vent (6 inches In diameter) Weighted mechanical actuation, gasketed Weighted mechanical actuation, ungasketed Roof drain (3 inches in diameter) Open 90% closed

Roof leg (3 inches In diameter) Adjustable, pontoon area, ungasketed Adjustable, center area, ungasketed Adjustable, double-deck roofs Fixed Adjustable, pontoon area, gasketed Adjustable, pontoon area, sock Adjustable, center area, gasketed Adjustable, center area, sock Roof leg or hanger well Adjustable Fixed

Sample pipe or well (24 inches In diameter) Slotted pipe, sliding cover, gasketed Slotted pipe, sliding cover, ungasketed Slit fabric seal 10% open

Slotted guide-pole/sample well Sliding cover, without float, ungasketed Sliding cover, with float, ungasketed Sliding cover, with out float, gasketed Sliding cover, wi th float, gasketed Sliding cover, with pole wiper, gasketed Sliding cover, with pole sleeve, gasketed Sliding cover, with float, wiper, gasketed Sliding cover, with float, sleeve, wiper, gasketed Sliding cover, with pole sleeve, wiper, gasketed Stub drain (1 inch in diameter) None listed

Unslotted guide-pole well Sliding cover, ungasketed Sliding cover, gasketed Sliding cover, with sleeve ungasketed Sliding cover, with sleeve, gasketed Sliding cover, with wiper, gasketed Vacuum breaker (10 inches in diameter) Weighted mechanical actuation, gasketed Weighted mechanical actuation, ungasketed

### Version 2.1.1 Final ICR Version – Corrected Appendix C—Primer for TANKS Model Users

C-8 Table C-4. Chemical Database Inputs for TANKS

Chemical name CAS number (Chemical Abstracts Service number) Category Liquid molecular weight Liquid density (lb/gal; ~60°F) Vapor molecular weight Vapor pressure at 40°F, 50°F, 60°F, 70°F, 80°F, 90°F, 100°F Constants for Antoine's equation 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 slope: distillates only

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-2 [This page intentionally left blank.]

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-3 

## D. Emission Factors from Air Toxic Emission Factors for Combustion Sources Using Petroleum Based Fu els – Final Report, Volume 2 – Development of Emission F actors 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 interv al 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 12378 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 total. 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-Pentachlorodibenzofuran. 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-Hexachlorodibenzofuran. 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.

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect 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 1.31E-02 1. 31E-02 1.31E-02 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 2.63E-03 2.63E-03 2.63E-03 1 0.00 0.00 0.00
Cadmium D3-v- 5.25E-03 5.25E-03 5. 25E-03 5.25E-03 1 0.00 0.00 0.00 Chromium (Hex) C3-v- 3.17E-03 3.17E- 03 3.17E-03 3.17E-03 1 0.00 0.00 1.00 Chromium (Total) C3-v- 4.18E-02 4.18E -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+0 0 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

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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
Arsenic 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

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 0.00 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+0 0 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

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-8 Table D-3a. Summary of Data for Emission Factor Development – Boilers Firing Fuel Oil

Substance CARB Rating Emission Factor (lb/Mgal)

Tests RSD, % Uncertainty,

% 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 1.44E-03 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 B3-v0 2.09E-07 2.24E- 07 3.58E-07 4.61E-08 2 73.55 58.55 0.00 Benzo(b)fluoranthene B3-v0 1.21E-06 1.02E-06 2.36E-06 3. 34E-07 2 73.99 59.20 0.40 Benzo(e)pyrene C3-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 1 108.86 123.19 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 1234678 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-06 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 42.46 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
Furan: 6F 123678 C3-v0 2.73E-10 2.73E- 10 2.86E-10 2.61E-10 1 4.51 5.10 0.33 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
Furan: 6F 123789 C3-v0 3.68E-10 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 57.86 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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-v 0 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)perylene B3-v 0 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 1.11E-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 32.18 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
Furan:6F 123678 C3-v0 1.86E-12 1.86E- 12 1.94E-12 1.77E-12 1 4.51 5.10 0.33 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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-v 0 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-v0 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 2.26E-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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 2.56E-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-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-v 0 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 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 5.64E- 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 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)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-v 0 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-v 0 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)anthracene A3-v 0 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-v 0 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-14 Table D-5a. Summary of Data for Emission Fa ctor Development – Boilers Firing Refinery Fuel Gas Controlled with Selective Catalytic Reduction (NO x 

### )

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 2.56E-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-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-v 0 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 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 5.64E- 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 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 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)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-v 0 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-v 0 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)anthracene A3-v 0 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-v 0 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum 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-0 8 2.81E-08 9.87E-09 1 50.39 57.02 1.00 Acetaldehyde A3-v0 1.02E-03 1.16E-0 3 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-0 9 8.25E-09 7.67E-09 1 4.04 4.57 0.00 Benzo(b)fluoranthene A3-v 0 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-v 0 8.05E-09 8.22E-09 8.25E-09 7.67E-09 1 4.04 4.57 0.00 Benzo(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 6.31E-07 6.30E-0 7 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 8.84E-06 1 5.34 6.04 0.00 Dibenz(a,h)anthracene A3-v 0 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-1 1 1.32E-11 9.05E-12 1 18.56 21.00 0.00
Dioxin:4D Other A3-v0 1.44E-10 1.01E-1 0 2.99E-10 3.17E-11 1 96.53 109.23 1.00
Dioxin:5D 12378 A3-v0 9.56E-12 9.20E-1 2 1.35E-11 6.01E-12 1 39.05 44.19 0.00
Dioxin:5D Other A3-v0 8.45E-11 8.83E-1 1 1.02E-10 6.34E-11 1 23.10 26.14 0.40
Dioxin:6D 123478 A3-v0 9.93E-12 9.24E-1 2 1.57E-11 4.83E-12 1 55.10 62.35 0.31
Dioxin:6D 123678 A3-v0 1.38E-11 1.27E-1 1 2.04E-11 8.30E-12 1 44.48 50.33 0.69
Dioxin:6D 123789 A3-v0 1.29E-11 1.45E-1 1 1.50E-11 9.20E-12 1 24.83 28.10 0.39
Dioxin:6D Other A3-v0 6.36E-11 6.71E-1 1 8.96E-11 3.39E-11 1 44.09 49.89 0.65
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-1 0 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
Fluoranthene 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-1 1 1.63E-11 1.18E-11 1 19.13 21.65 0.70
Furan:4F Other A3-v0 1.39E-10 1.10E-1 0 2.15E-10 9.21E-11 1 47.70 53.98 1.00
Furan:5F 12378 A3-v0 1.36E-11 1.43E-1 1 1.50E-11 1.16E-11 1 13.01 14.72 0.65 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-17 Table D-6a. Summary of Data for Emission Factor Development – Coke Calcining Controlled by Spray Dryer and Fabric Filter (continued)

Substance CARB Rating Emission Factor (lb/ton coke)

Tests RSD, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
Furan:5F 23478 A3-v0 1.25E-11 1.38E-1 1 1.46E-11 9.10E-12 1 23.87 27.01 0.63
Furan:5F Other A3-v0 1.20E-10 9.47E-1 1 1.79E-10 8.70E-11 1 42.57 48.17 0.74
Furan:6F 123478 A3-v0 2.44E-11 2.49E-1 1 2.71E-11 2.12E-11 1 12.27 13.89 1.00
Furan:6F 123678 A3-v0 2.21E-11 2.19E-1 1 3.13E-11 1.31E-11 1 41.02 46.42 1.00
Furan:6F 123789 A3-v0 9.19E-12 8.96E-1 2 1.20E-11 6.64E-12 1 29.03 32.85 0.67
Furan:6F 234678 A3-v0 2.01E-11 2.04E-1 1 2.04E-11 1.96E-11 1 2.55 2.88 1.00
Furan:6F Other A3-v0 1.52E-10 1.31E-1 0 2.36E-10 9.04E-11 1 49.18 55.66 1.00
Furan:7F 1234678 A3-v0 1.50E-10 1.42E-1 0 1.76E-10 1.32E-10 1 15.51 17.55 1.00
Furan:7F 1234789 A3-v0 2.56E-11 2.56E-1 1 2.99E-11 2.12E-11 1 17.09 19.33 0.72
Furan:7F Other A3-v0 5.16E-11 5.16E-1 1 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-v 0 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 Manganese 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-0 5 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 35.15 39.78 1.00

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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
Acrolein 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. 56E-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 2.85E-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
Furan:4F Other A3-v0 4.35E-10 4.51E- 10 5.97E-10 2.56E-10 1 39.34 44.51 1.00 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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-v0 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-v 0 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
Nickel 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-20 Table D-7a. Summary of Data for Emission Fact or Development – Heaters Firing Natural Gas

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 A3-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-v 0 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-v 0 1.25E-06 1.18E-06 1.42E-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-v 0 1.14E-06 1.15E-06 1.18E-06 1.08E-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-v 0 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
Phenanthrene 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 7.47E -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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-21 Table D-7b. Summary of Data for Emission Factor Development – Heaters Firing Natural Gas

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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-v 0 1.11E-09 1.13E-09 1.16E-09 1.05E-09 1 4.76 5.39 0.00 Benzo(g,h,i)perylene A3-v 0 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 27.63 31.27 0.44 Dibenz(a,h)anthracene A3-v 0 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-v 0 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 1.14E -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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-22 Table D-8a. Summary of Data for Emission Factor Development – Heaters Firing Natural Gas and Refinery Fuel Gas

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 1.00 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 6.67E- 06 1.10E-05 5.25E-07 1 86.79 98.21 0.97 Benzo(b)fluoranthene A3-v 0 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 6.59E-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-v 0 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)anthracene 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. 66 108.24 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-24 Table D-9a. Summary of Data for Emission Factor Development – Heaters Firing Fuel Oil

Substance CARB Rating Emission Factor (lb/Mgal)

Tests RSD, % Uncertainty,

% 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
Arsenic 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-v 0 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- 02 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 C3-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-08 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 5.94E-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 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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-v 1 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 Naphthalene 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum Acenaphthene C3-v1 1.22E-08 1.53E-08 2.09E-08 4.76E-10 1 86.27 97.62 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 7.79E-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-v 0 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 Chrysene 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
Furan:6F 123678 C3-v2 4.27E-11 2.07E-12 1.25E-10 1.04E-12 1 166. 91 188.87 0.02 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-27 Table D-9b. Summary of Data for Emission Factor Development – Heaters Firing Fuel Oil (continued)

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
Furan:6F 123789 C3-v0 3.46E-12 4.15E- 12 4.17E-12 2.08E-12 1 34.70 39.26 0.00
Furan: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-v 1 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 7.73E-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 1 123.75 140.04 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-28 Table D-10a. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### )

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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
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-v 0 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-v 3 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 7 103. 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
Selenium C3-v0 2.20E-05 2.28E-05 2.85E-05 1.48E-05 1 31.23 35.34 0.78 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-29 Table D-10a. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### ) (continued)

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-30 Table D-10b. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### )

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 2.74E-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-v 0 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-v 3 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
Selenium C3-v0 1.96E-08 2.03E-08 2.54E-08 1.32E-08 1 31.23 35.34 0.78 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-31 Table D-10b. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Non-Catalytic Reduction (NO x 

### ) (continued)

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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
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-v 0 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-v 3 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 7 103. 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
Selenium C3-v0 2.20E-05 2.28E-05 2.85E-05 1.48E-05 1 31.23 35.34 0.78 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 2.74E-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-v 0 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-v 3 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
Selenium C3-v0 1.96E-08 2.03E-08 2.54E-08 1.32E-08 1 31.23 35.34 0.78 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-36 Table D-12a. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Catalytic Reduction

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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
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-v 0 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-v 3 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 7 103. 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
Selenium C3-v0 2.20E-05 2.28E-05 2.85E-05 1.48E-05 1 31.23 35.34 0.78 (continued)

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-37 Table D-12a. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Catalytic Reduction (continued)

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum
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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-38 Table D-12b. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Catalytic Reduction

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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 2.74E-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-v 0 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-39 Table D-12b. Summary of Data for Emission F actor Development – Heaters Firing Refinery Fuel Gas Controlled with Selective Catalytic Reduction (continued)

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-40 Table D-13a. 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, % Uncertainty,

% 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-03 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
Benzene 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-v 0 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-v 0 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-v 0 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-v 0 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
Toluene 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 62.56 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 Benzo(b)fluoranthene C3-v 0 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-v 0 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 0.76 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-v 0 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-v0 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-v 0 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 C3-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-v 0 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-v 1 6.78E-05 5.89E-05 1.55E-04 1.17E-05 2 71.76 57.42 0.43 Benzo(k)fluoranthene C3-v 0 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-v 0 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 1.00
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-v 1 6.43E-05 4.08E-05 1.32E-04 7.77E-06 2 83.82 67.07 0.30 Naphthalene 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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 (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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 Acetaldehyde 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-v 0 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-v 1 4.87E-07 4.24E-07 1.12E-06 8.43E-08 2 72.27 57.82 0.43 Benzo(k)fluoranthene C3-v 0 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-v 0 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-v 1 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
Phenanthrene 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum 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+0 0 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-v 0 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-v 0 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-v 0 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-v 0 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 63.00 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 1.49E-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 Benzo(b)fluoranthene A3-v 0 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-v 0 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-v 0 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-v0 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-v 0 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 40.10 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-46 Table D-16a. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion E ngines Firing Field Gas, Lean

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 E ngines Firing Field Gas, Lean

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-47 Table D-17a. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion E ngines Firing Field Gas, Rich

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 Xylene (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 E ngines Firing Field Gas, Rich

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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. 90E-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 1.00

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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+0 0 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-05 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-v 0 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 38.56 16.49 1.00 Indeno(1,2,3-cd)pyrene A3-v 1 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 8.63E-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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 7.29E- 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-v 0 1.04E-08 1.05E-08 1.40E-08 6.63E-09 1 35.41 40.07 1.00
Fluoranthene 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-v 1 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 Propylene 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum Minimum Acetaldehyde A3-v0 1.71E+00 1.70E+0 0 1.82E+00 1.60E+00 1 6.46 7.31 1.00
Acrolein A3-v2 5.40E-01 4.16E-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, % Uncertainty,

% 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 1.00 Xylene (o) A3-v0 2.06E-04 2.06E-04 2.11E-04 2.02E-04 1 3.29 4.56 1.00

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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 (Total) 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, % Uncertainty,

% Detect Ratio 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% 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-v 0 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-v 0 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-v 0 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-v 0 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 18.55 0.23

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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, % Uncertainty,

% Detect Ratio Mean Median Maximum 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 1.28E-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-v 0 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-v 0 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-v 0 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-09 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-v 0 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 Pyrene 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-54 Table D-22a. Summary of Data for Emission Factor Development – Gas Turbines with No Duct Burners Firing Natural Gas

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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-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-v 0 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-v 0 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-v 0 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-v 0 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 Xylene (Total) A3-v0 3.63E-02 4.11E- 02 6.26E-02 9.70E-03 2 52.17 41.75 0.38

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-55 Table D-22b. Summary of Data for Emission Factor Development – Gas Turbines with No Duct Burners Firing Natural Gas

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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-v 0 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-v 0 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-v 0 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
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 1.65E-05 1 29.80 33.72 0.45 Indeno(1,2,3-cd)pyrene A3-v 0 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-56 Table D-23a. Summary of Data for Emission Factor Development – Gas 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, % Uncertainty,

% 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-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-v 0 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-v 0 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-v 0 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-v 0 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 Xylene (Total) A3-v0 3.63E-02 4.11E- 02 6.26E-02 9.70E-03 2 52.17 41.75 0.38

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-57 Table D-23b. Summary of Data for Emission Factor Development – Gas 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, % Uncertainty,

% 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-v 0 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-v 0 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-v 0 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
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 1.65E-05 1 29.80 33.72 0.45 Indeno(1,2,3-cd)pyrene A3-v 0 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-58 Table D-24a. Summary of Data for Emission Factor Development – Gas Turbines with Duct Burners Firing Natural Gas Controlled with Selective Catalytic Reduction

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 – Gas Turbines with Duct Burners Firing Natural Gas Controlled with Selective Catalytic Reduction

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-59 Table D-25a. Summary of Data for Emission Factor Development – Gas 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/MMcf)

Tests RSD, % Uncertainty,

% 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 C3-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-v 0 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-v 0 2.06E-05 2.00E-05 2.71E-05 1.45E-05 1 30.62 34.65 0.00 Benzo(k)fluoranthene C3-v 0 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 1.04E-03 1 42.72 48.34 1.00 Dibenz(a,h)anthracene C3-v 0 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-v 0 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-03 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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-60 Table D-25b. Summary of Data for Emission Factor Development – Gas 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, % Uncertainty,

% 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 4.11E-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-v 0 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-v 0 1.91E-08 1.86E-08 2.52E-08 1.35E-08 1 30.62 34.65 0.00 Benzo(k)fluoranthene C3-v 0 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 Dibenz(a,h)anthracene C3-v 0 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-v 0 9.14E-09 9.85E-09 1.10E-08 6.61E-09 1 24.76 28.02 0.00 Manganese A3-v0 3.25E-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 E3-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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-61 Table D-26a. Summary of Data for Emission Factor Development – Gas 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, % Uncertainty,

% 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
Nickel 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 – Gas 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, % Uncertainty,

% 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 9.00E-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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-62 Table D-27a. Summary of Data for Emission Factor Development – Gas Turbines with No Duct Burners Firing Refinery Fuel Gas Controlled with Carbon Monoxide Oxidation Catalyst

Substance CARB Rating Emission Factor (lb/MMcf)

Tests RSD, % Uncertainty,

% 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 Formaldehyde 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 6.99E+00 8.23E+00 9. 17E+00 3.56E+00 1 42.95 48.60 1.00

### Version 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

D-63 Table D-27b. Summary of Data for Emission Factor Development – Gas Turbines with No Duct Burners Firing Refinery Fuel Gas Controlled with Carbon Monoxide Oxidation Catalyst

Substance CARB Rating Emission Factor (lb/MMBtu)

Tests RSD, % Uncertainty,

% 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 1.46E-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 2.1.1 Final ICR Version – Corrected Appendix D—Emission Factors for Combustion Sources

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