December 2009 

Emission Estimation Protocol 

for Petroleum Refineries 

Version 1.0 

Review Draft – Do not cite or quote 

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 
Version 1.0 Table of Contents 

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ii

Table of Contents 

1. Introduction ......................................................................................................................................... 1-1

1.1 Completeness ............................................................................................................................ 1-1

1.2 Data Quality .............................................................................................................................. 1-9

1.3 Calculations and Significant Digits ........................................................................................ 1-10

2. Equipment Leaks ................................................................................................................................. 2-1

2.1 Methodology Rank 1 for Equipment Leaks.............................................................................. 2-2

2.2 Methodology Ranks 2 and 3 for Equipment Leaks .................................................................. 2-3

2.2.1 Speciating Equipment Leak Emissions ....................................................................... 2-7

2.2.2 Calculating Annual Equipment Leak Emissions......................................................... 2-8

2.3 Methodology Ranks 4 and 5 for Equipment Leaks ................................................................ 2-10

3. Storage Tanks ...................................................................................................................................... 3-1

3.1 Methodology Rank 1 for Storage Tanks ................................................................................... 3-1

3.2 Methodology Rank 2 for Storage Tanks ................................................................................... 3-2

3.3 Methodology Rank 3 for Storage Tanks ................................................................................... 3-3

4. Stationary Combustion Sources .......................................................................................................... 4-1

4.1 Methodology Rank 1 for Stationary Combustion Sources ....................................................... 4-2

4.2 Methodology Rank 2 for Stationary Combustion Sources ....................................................... 4-4

4.3 Methodology Rank 3A for Stationary Combustion Sources .................................................... 4-8

4.4 Methodology Rank 3B for Stationary Combustion Sources .................................................. 4-10

4.5 Methodology Rank 4 for Stationary Combustion Sources ..................................................... 4-11

4.5.1 Default Emissions Factors for Process Heaters ........................................................ 4-13

4.5.2 Default Emissions Factors for Boilers ...................................................................... 4-18

4.5.3 Default Emissions Factor for Internal Combustion Engines ..................................... 4-23

4.5.4 Default Emissions Factor for Turbines ..................................................................... 4-30

5. Process Vents ...................................................................................................................................... 5-1

5.1 Catalytic Cracking Units .......................................................................................................... 5-1

5.1.1 Methodology Ranks 1 and 2 for Catalytic Cracking Units ......................................... 5-2

5.1.2 Methodology Ranks 3 and 4 for Catalytic Cracking Units ......................................... 5-2

5.1.4 Methodology Rank 5B for Catalytic Cracking Units .................................................. 5-9

5.2 Fluid Coking Units ................................................................................................................. 5-11

5.2.1 Methodology Ranks 1 and 2 for Fluid Coking Units ................................................ 5-12

5.2.2 Methodology Ranks 3 and 4 for Fluid Coking Units ................................................ 5-12

5.2.3 Methodology Rank 5 for Fluid Coking Units ........................................................... 5-12

5.3 Delayed Coking Units ............................................................................................................ 5-12

5.3.1 Methodology Ranks 1 and 2 for Delayed Coking Units ........................................... 5-13

5.3.2 Methodology Ranks 3 and 4 for Delayed Coking Units ........................................... 5-13

5.3.3 Methodology Rank 5 for Delayed Coking Units ...................................................... 5-13

5.4 Catalytic Reforming Units ...................................................................................................... 5-14

5.4.1 Emissions Estimation Methodology for Catalytic Reforming Units ........................ 5-15

5.5 Sulfur Recovery Plants ........................................................................................................... 5-16

5.5.1 Methodology Ranks 1 and 2 for Sulfur Recovery Plants .......................................... 5-17

5.5.2 Methodology Ranks 3 and 4 for Sulfur Recovery Plants .......................................... 5-17

5.5.3 Methodology Rank 5 for Sulfur Recovery Plants ..................................................... 5-18

5.6 Other Miscellaneous Process Vents ....................................................................................... 5-18

5.6.1 Hydrogen Plant Vents ............................................................................................... 5-18

5.6.2 Asphalt Plant Vents ................................................................................................... 5-18
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5.6.3 Coke Calcining.......................................................................................................... 5-21

5.6.4 Blowdown Systems ................................................................................................... 5-23

5.6.5 Vacuum Producing Systems ..................................................................................... 5-24

6. Flares ................................................................................................................................................... 6-1

6.1 Methodology Rank 1 for Flares ................................................................................................ 6-2

6.2 Methodology Rank 2 for Flares ................................................................................................ 6-3

6.3 Methodology Rank 3 for Flares ................................................................................................ 6-4

6.4 Methodology Rank 4 for Flares ................................................................................................ 6-6

6.5 Methodology Ranks 5 and 6 for Flares .................................................................................... 6-7

7. Wastewater Collection and Treatment Systems .................................................................................. 7-1

7.1 Methodology Rank 1 for Covered and Vented Units ............................................................... 7-2

7.2 Methodology Rank 2 for Uncovered Units .............................................................................. 7-2

7.2.1 Primary Weirs ............................................................................................................. 7-4

7.2.2 Junction Boxes and Lift Stations ................................................................................ 7-4

7.2.3 Oil-Water Separators .................................................................................................. 7-5

7.2.4 Dissolved Air Flotation Units ..................................................................................... 7-5

7.2.5 Equalization Tanks ...................................................................................................... 7-6

7.2.6 Biological Treatment Units ......................................................................................... 7-6

7.2.7 Polishing Ponds ........................................................................................................... 7-7

7.2.8 Site-Specific Factors ................................................................................................... 7-8

7.2.9 Model Validation ........................................................................................................ 7-8

7.3 Methodology Rank 3 for Uncovered Units .............................................................................. 7-8

7.3.1 Engineering Estimates Based on Wastewater Treatment Plant Load ......................... 7-8

7.3.2 Engineering Estimates Based on Process Capacities .................................................. 7-9

8. Cooling Towers ................................................................................................................................... 8-1

8.1 Methodology Ranks 1 and 2 for Cooling Towers .................................................................... 8-2

8.2 Methodology Rank 3 for Cooling Towers ................................................................................ 8-6

8.3 Methodology Rank 4 for Cooling Towers ................................................................................ 8-8

8.4 Methodology Rank 5 for Cooling Towers .............................................................................. 8-10

8.4.1 VOC and Organic HAP ............................................................................................ 8-10

8.4.2 Particulate Matter Emissions .................................................................................... 8-12

8.4.3 Chlorine Emissions ................................................................................................... 8-14

9. Product Loading Operations ................................................................................................................ 9-1

9.1 Data Available on Product Composition and Properties .......................................................... 9-2

9.2 Methodology Rank 1 for Product Loading Operations ............................................................ 9-2

9.3 Methodology Ranks 2 and 3 for Product Loading Operations ................................................. 9-2

9.4 Methodology Rank 4 for Product Loading Operations ............................................................ 9-4

9.4.1 AP-42 Emissions Factors for ―Product‖ or ―Total Hydrocarbon‖ Emissions ............. 9-4

9.4.2 Estimate Controlled or Uncontrolled Emissions and Speciate ................................... 9-5

9.4.3 Capture Efficiency ...................................................................................................... 9-6

9.4.4 Control Efficiency ....................................................................................................... 9-7

10. Fugitive Dust Sources ....................................................................................................................... 10-1

11. Startup and Shutdown ....................................................................................................................... 11-1

11.1 Gaseous Process Vessel Depressurization and Purging ......................................................... 11-1

11.2 Liquid Process Vessel Depressurization and Purging ............................................................ 11-2
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12. Malfunctions ...................................................................................................................................... 12-1

12.1 Control Device Malfunctions ................................................................................................. 12-1

12.2 Vessel Overpressurization ...................................................................................................... 12-2

12.3 Spills ....................................................................................................................................... 12-3

13. References ......................................................................................................................................... 13-1

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

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

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

Appendix D—Emission Factors from Air Toxic Emission Factors for Combustion Sources Using 

Petroleum Based Fuels – Final Report, Volume 2 – Development of Emission Factors Using 

CARB Approach ................................................................................................................................. D-1
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List of Figures 

7-1 Typical refinery wastewater treatment system. ............................................................................. 7-1

7-2 Simplified drawing of a constituent mass balance in a biological treatment unit. ........................ 7-3

List of Tables 

1-1 Summary of Pollutants and Emissions Sources Inclusion in a Petroleum Refinery’s 

Emissions Inventory...................................................................................................................... 1-2

2-1 Summary of Equipment Leak Emissions Estimates ..................................................................... 2-2

2-2 Equipment Leak Rate for Refinery Equipment Components ....................................................... 2-4

2-3 Refinery Screening Ranges Emission Factorsa ............................................................................. 2-5

2-4 Median Equipment Leak Component Counts for Small Model Processes ................................. 2-12

2-5 Median Equipment Leak Component Counts for Large Model Processes ................................. 2-13

2-6 Refinery Average Component Emissions Factors ...................................................................... 2-14

2-7 Concentration of Benzene in Refinery Process Unit Streams ..................................................... 2-14

3-1 Summary of Typical Hierarchy of Storage Tank Emissions Estimates ........................................ 3-1

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

4-1 Summary of Typical Hierarchy of Stationary Combustion Source Emissions Estimates ............ 4-2

4-2 Molar Exhaust Volumes and Molar Heat Content of Refinery Fuel Gas Constituents ................ 4-5

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

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

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

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

4-7 Summary of Emissions Factors for Turbines Firing Various Fuels ............................................ 4-30

4-8 Summary of Emissions Factors for Turbines Firing Various Fuels ............................................ 4-33

5-1 Summary of Typical Hierarchy of Process Vent Emissions Estimates ........................................ 5-1

5-2 Default Size Distribution for Filterable PM from CCU ................................................................ 5-5

5-3 Default Ratio of Metal HAP Composition of CCU Fines ............................................................ 5-8

5-4 Organic HAP Emissions Factors for CCU Catalyst Regenerator Vent ...................................... 5-10

5-5 Average Vent Concentrations and Emissions Factors for Delayed Coking Unit Vents ............. 5-13

5-6 Emissions Factors for CRU Catalyst Regeneration Vent ........................................................... 5-16

5-7 Emissions Factors for Sulfur Recovery Plants ............................................................................ 5-18

5-8 Emission Factors for Asphalt Blowing (U.S. EPA, 1995a) ........................................................ 5-19

5-9 Asphalt Blowing – Nonmethane Volatile Organic Compounds Speciation ............................... 5-20

5-10 Summary of Emissions Factors for Controlled Asphalt Blowing ............................................... 5-20

5-11 Summary of Emissions Factors for Controlled Coke Calcining ................................................. 5-21

5-12 Default Emissions Factors for Blowdown Systems .................................................................... 5-24

5-13 Default Emissions Factor for Vacuum Producing Systems ........................................................ 5-24

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

6-2 Flare Energy Consumption-Based Emissions Factors .................................................................. 6-5

6-3 TCEQ Energy Consumption-Based Emissions Factors for Flares ............................................... 6-5

6-4 Emissions Factors for Soot from Flares ........................................................................................ 6-7

6-5 Flare General Emissions Factors .................................................................................................. 6-8

7-1 Summary of Wastewater Treatment Emissions Estimates............................................................ 7-2

7-2 Critical Inputs, Variables, and Chemical Properties Specific to Primary Weir Air 

Emissions Calculations ................................................................................................................. 7-4

7-3 Critical Inputs, Variables, and Chemical Properties Specific to Junction Box and Lift 

Station Air Emissions Calculations .............................................................................................. 7-4
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7-4 Critical Inputs, Variables, and Chemical Properties Specific to Oil-Water Separators Air 

Emissions Calculations ................................................................................................................. 7-5

7-5 Critical Inputs, Variables, and Chemical Properties Specific to DAF Air Emissions 

Calculations .................................................................................................................................. 7-5

7-6 Critical Inputs, Variables, and Chemical Properties Specific to Equalization Tank Air 

Emissions Calculations ................................................................................................................. 7-6

7-7 Critical Inputs, Variables, and Chemical Properties Specific to Biological Treatment Unit 

Air Emissions Calculations ........................................................................................................... 7-7

7-8 Model Process Unit Characteristics for Petroleum Refinery Wastewater .................................... 7-9

7-9 Refinery Wastewater Contaminant Concentrations as a Ratio to Benzene ................................ 7-10

7-10 Default Mass Emissions Factors for Refinery Wastewater Collection and Treatment 

Systems ....................................................................................................................................... 7-10

8-1 Summary of Cooling Tower Emissions Estimation Methodologies ............................................. 8-1

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

8-3 Data Requirements for Speciated Compound Emissions, Methodology Rank 3 .......................... 8-7

8-4 Data Requirements for Speciated Compound Emissions, Methodology Rank 4 .......................... 8-9

8-5 Data Requirements for VOC or Speciated VOC Emissions, Methodology Rank 5 ................... 8-11

9-1 Summary of Product Loading Operations Emissions Estimates................................................... 9-1

9-2 Data Requirements for VOC or Speciated Emissions, Methodology Rank 1 or 2 ....................... 9-3

9-3 Saturation Factors ......................................................................................................................... 9-5

9-4 VOC Emissions Factors for Marine Vessel Loading of Gasoline at Marine Terminals ............... 9-5

9-5 Capture Efficiencies for Vapor Collection Systems ..................................................................... 9-6

9-6 Sample Calculation Methodology Rank 4—Summary of Emissions (When Property Data 

Are Not Available) ...................................................................................................................... 9-10

10-1 Default Values for Fugitive Dust Emission Estimates ................................................................ 10-1

12-1 Control Device Efficiency and Multiplier Factors for Control Device Malfunctions ................ 12-2
Version 1.0 List of Acronyms 

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List of Acronyms and Abbreviations 

μg/L micrograms per liter

acfm actual cubic feet per minute 

API American Petroleum Institute 

atm atmosphere

atm/in. of Hg atmospheres per inch of mercury

bbl/cd

bbl/sd

barrels per calendar day

barrels per stream day

bbl/hr barrels per hour 

BID Background Information Document 

BOX test aerated reactor test 

Btu/mol British thermal units per mole 

Btu/scf British thermal units per standard cubic feet 

BWON Benzene Waste Operations NESHAP

CARB California Air Resources Board 

CCU catalytic cracking unit

CEMS continuous emission monitoring system

CERMS continuous emission rate monitoring system 

CFR Code of Federal Regulations

CH4 methane

Cl2 chlorine

CO carbon monoxide

COS carbonyl sulfide 

Cr+6 hexavalent chromium 

CRU crude distillation unit 

CS2 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
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ESP electrostatic precipitators

FCCU fluid catalytic cracking unit

FCU fluid coking unit

FID flame ionization detection 

g/hr grams per hour

g/mol grams per mole 

gal/bbl gallons of wastewater per barrel of capacity at a given process unit

GC gas chromatograph

GC/MS gas chromatography/mass spectrometry

GHG greenhouse gases

H2S 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

in. inches

kg TOC/hr kilograms of TOC per hour

kg/hr kilograms per hour

kg/hr/source kilograms per hour per source

kg/kg-mol kilogram per kilogram mole 

kg/yr kilograms per year 

kPa kilopascals 

lb/dscf pounds per standard cubic foot 

lb/lb-mol pounds per pound mole 

lb/lton pounds per long ton

lb/Mgal pounds per thousand gallons

lb/MMbbl pounds per million barrels

lb/MMBtu pounds per million British thermal unit 

lb/MMcf pounds per million cubic feet

lb/ton pounds per ton 

lb/ton coke pounds per ton of petroleum coke

LDAR leak detection and repair 
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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

NMOC nonmethane organic compounds 

NMVOC nonmethane volatile organic compounds

NO nitric oxide

NO2 nitrogen dioxide

NOx nitrogen oxides

NSPS new source performance standards

O2 oxygen

OCDD octachloro-dibenzo-p-dioxin

OCDF octachloro-dibenzo-furan 

OVA organic vapor analyzer 

PAH polycyclic aromatic hydrocarbons 

PCB polychlorinated biphenyls 

PM particulate matter

PM10 PM emissions that are 10 μm in diameter or less

PM10-FIL filterable (or front-half catch) portion of the PM emissions that are 10 μm in 

diameter or less

PM10-PRI ―primary‖ PM emissions that are 10 μm in diameter or less

PM2.5 PM emissions that are 2.5 μm in diameter or less

PM2.5-FIL filterable (or front-half catch) portion of the PM emissions that are 2.5 μm in 

diameter or less

PM2.5-PRI ―primary‖ PM emissions that are 2.5 μm in diameter or less

PM-CON condensable PM (or back-half catch)

POM polycyclic organic matter 

POTW publicly owned treatment works 
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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

SO2 sulfur dioxide 

SRU sulfur recovery unit 

SSM startup, shutdown, or malfunction 

SV screening value 

TCCU thermal catalytic cracking unit 

TCDD tetrachlorodibenzo-p-dioxin 

TDS total dissolved solids 

TEQ toxic equivalents

THC total hydrocarbon

TOC total organic compound

tons/hr tons per hour 

tons/kg tons per kilogram

tons/yr tons per year

VOC 

vol%

volatile organic compounds

volume percent

WebFIRE Internet version of the Factor Information Retrieval (FIRE) data system

WF weight fraction

WSPA Western States Petroleum Association

wt% weight percent

°C degrees Celsius

°F

°R

degrees Fahrenheit

degrees Rankine
Version 1.0 Section 1—Introduction 

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1-1 

1. Introduction 

This Refinery Emissions Protocol document is intended to provide guidance and instructions to petroleum 

refinery owners and operators and to federal, state, and local agencies for the purpose of improving 

emissions inventories for the petroleum refining industry. This document presents a hierarchy of 

emissions measurement or estimation methods for various petroleum refinery emissions sources and 

provides a listing of pollutants for which emissions are anticipated for each source type. 

For each emission source, the various emissions measurement of estimation methods specific to that 

source are ranked in order of preference, with ―Methodology Rank 1‖ being the preferred method, 

followed by ―Methodology Rank 2,‖ and so on. Refinery owners and operators and other inventory 

developers are requested to use the highest ranked method (with Methodology Rank 1 being the highest) 

for which data are available. Methodology Rank 1 or 2 generally rely on continuous emissions 

measurements. When continuous measurement data are not available, engineering calculations or sitespecific emissions factors (Methodology Ranks 3 and 4) are specified; these methods generally need 

periodic, site-specific measurements. When site-specific measurement or test data are not available, 

default emissions factors (Methodology Rank 5) are provided. 

In the development of this Refinery Emissions Protocol document, the U.S. Environmental Protection 

Agency (EPA) reviewed available source test data to verify or refine existing emissions factors and 

develop new emissions factors for sources that currently do not have default emissions factors. EPA also 

provided guidance on characterizing and quantifying emissions associated with startup, shutdown, and 

malfunction events. While many of the emission factors presented in this document have not undergone 

full review for the incorporation of these emission factors into AP-42 (U.S. EPA, 1995a) or WebFIRE 

(the internet version of the Factor Information Retrieval (FIRE) data system), the emission factors 

provided in this Refinery Emissions Protocol document should be used for refinery emissions sources. 

Efforts are on-going to update the AP-42 emission factors for petroleum refineries. As these emission 

factors are updated, it is EPA’s intent to revise this document to include the updated AP-42 emission 

factors. As such, the EPA website (http://www.epa.gov/ttn/chief/efpac/esttools.html) should be checked 

prior to preparing the emissions inventory to ensure the most recent Refinery Emissions Protocol 

document is used. 

1.1 Completeness 

Emission estimates should be provided for each emission source at the refinery. While this Refinery 

Emissions Protocol document attempts to identify and provide methodologies for each emissions source, 

there are sources included in this Refinery Emissions Protocol document for which no emissions data are 

available to provide default (Rank 5) methods. Additionally, there may be certain sources at the refinery 

that have not been included in this version of the Refinery Emissions Protocol document. Emission 

estimates should be provided for EVERY emission source at the refinery, even for emissions sources that 

have not yet been included in this Refinery Emissions Protocol document or for which default 

methodologies are not currently provided. Similarly, emissions should be provided for each pollutant 

[except for greenhouse gases (GHG), which are required to be reported under the Mandatory Greenhouse 

Gas Emissions Reporting Rule (Final Rule, 74 Federal Register [FR] 56260)] emitted from each emission 

source. 

Table 1-1 provides a listing of the pollutants expected to be emitted by various sources described in this 

protocol document. Filled circles indicate compound/emission source pairings for which emission 

estimates should be developed. Hollow circles indicate pairings for which data may be reported (if the 

chemical is present or if data are available to speciate to that extent), but the inventory can be deemed 

complete without these estimates. In general, speciation of volatile organic compound (VOC) emissions is 

preferred to overall VOC emission measurement methods via EPA Methods 25, 25A-E, or 305. 
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1-2 

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

in a Petroleum Refinery’s Emissions Inventory

CAS 

Number or 

Pollutant 

Code Substance

Equipment LeaksStorage TanksStationary Combustion

Process Vents

Catalytic Cracking UnitFluid Coking UnitDelaFlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownMalfunctions

yed Coking 

UnitCatalytic Reforming UnitSulfur Recovery PlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdown SystemsVacuum Systems

Criteria Pollutants

630-08-0 Carbon monoxide ● ● ● ● ● ● ○ ○

7439-92-1 Lead ● ● ● ● ○ ○

PM10-PRI Particulate matter (PM) ≤ 

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

PM10-FIL Filterable PM ≤ 10 μm ● ● ● ● ● ● ● ● ● ○ ○

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

PM25-FIL Filterable PM ≤ 2.5 μm ● ● ● ● ● ● ● ● ● ○ ○

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

10102-44-0 Nitrogen dioxide ● ● ● ● ● ● ○ ○

NOX Nitrogen oxides ● ● ● ● ● ● ○ ○

7449-09-5 Sulfur dioxide ● ● ● ● ● ● ● ●

VOC Volatile organic 

compounds ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

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

74-85-1 Ethylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

74-86-2 Acetylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

74-98-9 Propane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

115-07-1 Propylene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

463-49-0 Propadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

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

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

160-98-9 1-Butene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

107-07-7 2-Butene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

115-11-7 Isobutene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

590-19-2 1,2-Butadiene ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

109-66-0 n-pentane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

78-8-4 2-Methylbutane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

(continued)
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1-3 

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

in a Petroleum Refinery’s Emissions Inventory (continued)

CAS 

Number

or 

Pollutant 

Code Substance

Equipment LeaksStorage TanksStationary Combustion

Process Vents

FlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownCatalytic Cracking UnitFluid Coking UnitDelayed Coking UnitCatalytic Reforming UnitSulfur Recovery PlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdown SystemsVacuum SystemsMalfunctions

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 ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

251-13-7 Trimethylbenzene(s) ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

Hazardous Air Pollutants (HAP)

Volatile Organic HAP

75-07-0 Acetaldehyde ○ ○ ● ● ● ● ● ○ ● ● ● ○ ○ ● ○ ○ ○ ○ ○

107-02-8 Acrolein ○ ○ ● ● ● ● ● ○ ○ ○ ● ○ ○ ● ○ ○ ○ ○ ○

62-53-3 Analine ○ ○ ● ● ● ● ● ○ ○ ○ ● ○ ○ ● ○ ○ ○ ○ ○

71-43-2 Benzene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

74-83-9 Bromomethane ○ ○ ○

106-99-0 1,3-Butadiene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

75-00-3 Chloroethane ○ ○ ○ ○

67-66-3 Chloroform ○ ○ ● ○

74-87-3 Chloromethane ○ ○ ○ ○

98-82-8 Cumene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

(continued)
Version 1.0 Section 1—Introduction 

Review Draft – Do not cite or quote 

1-4 

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

in a Petroleum Refinery’s Emissions Inventory (continued)

CAS 

Number

or 

Pollutant 

Code Substance

Equipment LeaksStorage TanksStationary Combustion

Process Vents

FlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownCatalytic Cracking UnitFluid Coking UnitDelayed Coking UnitCatalytic Reforming UnitSulfur Recovery PlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdown SystemsVacuum SystemsMalfunctions

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 Hexane ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

67-56-1 Methanol ● ● ○

108-10-1 Methyl isobutyl ketone ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

1634-04-4 Methyl tert-butyl ether ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

100-42-5 Styrene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

79-34-5 1,1,2,2-Tetrachloroethane ○ ○ ● ○

127-18-4 Tetrachloroethylene ○ ○ ● ○

108-88-3 Toluene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

79-00-5 1,1,2-Trichloroethane ○ ○ ● ○

79-01-6 Trichloroethylene ○ ○ ● ○

121-44-8 Triethylamine ● ● ● ○ ○ ○

540-84-1 2,2,4-Trimethylpentane ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

593-60-2 Vinyl bromide ○ ○ ○ ○

75-01-4 Vinyl chloride ○ ○ ● ○

95-47-6 o-Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

(continued)
Version 1.0 Section 1—Introduction 

Review Draft – Do not cite or quote 

1-5 

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

in a Petroleum Refinery’s Emissions Inventory (continued)

CAS 

Number

or 

Pollutant 

Code Substance

Equipment LeaksStorage TanksStationary Combustion

Process Vents

FlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownCatalytic Cracking UnitFluid Coking UnitDelayed Coking UnitCatalytic Reforming UnitSulfur Recovery PlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdown SystemsVacuum SystemsMalfunctions

108-38-3 m-Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

106-42-3 p-Xylene ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

1330-20-7 Xylenes (total) ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ●

Semi-Volatile and Non-Volatile Organic HAP (except dioxins, furans, and polychlorinated biphenyls [PCB])

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) fluoranthenePOM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

192-97-2 Benzo(e)pyrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

191-24-2 Benzo(g,h,i)perylenePOM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

207-08-9 Benzo(k)fluoranthenePOM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

92-52-4 Biphenyl POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

117-81-7

Bis(2-ethyl hexyl) 

phthalate ○ ● ● ○

91-58-7 2-ChloronaphthalenePOM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

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)anthracenePOM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

84-74-2 di-n-Butyl phthalate ○ ● ● ○

84-66-2 Diethyl-phthalate ○ ● ● ○

57-97-6

7,12-Dimethylbenz(a) 

anthracene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

(continued)
Version 1.0 Section 1—Introduction 

Review Draft – Do not cite or quote 

1-6 

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

in a Petroleum Refinery’s Emissions Inventory (continued)

CAS 

Number

or 

Pollutant 

Code Substance

Equipment LeaksStorage TanksStationary Combustion

Process Vents

FlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownCatalytic Cracking UnitFluid Coking UnitDelayed Coking UnitCatalytic Reforming UnitSulfur Recovery PlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdown SystemsVacuum SystemsMalfunctions

206-44-0 Fluoranthene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

86-73-7 Fluorene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

193-39-5

Indeno(1,2,3-cd)

pyrenePOM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

56-49-5 3-MethylchloranthrenePOM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

91-57-6 2-Methylnaphthalene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

218-01-9 Chrysene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

91-20-3 Naphthalene POM ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ○ ● ●

198-55-0 Perylene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

85-01-8 Phenanthrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

108-95-2 Phenol ● ● ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ● ● ●

129-00-0 Pyrene POM ● ○ ● ● ● ● ● ○ ○ ● ● ○ ● ● ● ● ○ ○ ● ●

Dioxin/Furans/PCB

1746-01-6 Dioxin: 4D 2378j● ● ● ● ● ○ ○ ○

40321-76-4 Dioxin: 5D 12378j○ ○ ○ ○ ○ ○ ○ ○

39227-28-6 Dioxin: 6D 123478j○ ○ ○ ○ ○ ○ ○ ○

57653-85-7 Dioxin: 6D 123678j○ ○ ○ ○ ○ ○ ○ ○

19408-74-3 Dioxin: 6D 123789j○ ○ ○ ○ ○ ○ ○ ○

35822-46-9 Dioxin: 7D 1234678j○ ○ ○ ○ ○ ○ ○ ○

3268-87-9 Dioxin: 8Dj○ ○ ○ ○ ○ ○ ○ ○

132-64-9 Dibenzofurans ● ● ● ● ● ○ ○ ○

51207-31-9 Furan: 4F 2378k○ ○ ○ ○ ○ ○ ○ ○

57117-41-6 Furan: 5F 12378k○ ○ ○ ○ ○ ○ ○ ○

57117-31-4 Furan: 5F 23478k○ ○ ○ ○ ○ ○ ○ ○

70648-26-9 Furan: 6F 123478k○ ○ ○ ○ ○ ○ ○ ○

57117-44-9 Furan: 6F 123678k○ ○ ○ ○ ○ ○ ○ ○

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

(continued)
Version 1.0 Section 1—Introduction 

Review Draft – Do not cite or quote 

1-7 

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

in a Petroleum Refinery’s Emissions Inventory (continued)

CAS 

Number

or 

Pollutant 

Code Substance

Equipment LeaksStorage TanksStationary Combustion

Process Vents

FlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownCatalytic Cracking UnitFluid Coking UnitDelayed Coking UnitCatalytic Reforming UnitSulfur Recovery PlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdown SystemsVacuum SystemsMalfunctions

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

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

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

39001-02-0 Furan: 8Fk○ ○ ○ ○ ○ ○ ○ ○

1336-36-3

Polychlorinated biphenyls 

(total) ● ● ● ● ● ○ ○ ○

Metal HAP

7440-36-0 Antimony ● ● ● ○

7440-38-2 Arsenic ● ● ● ○

7440-41-7 Beryllium ● ● ● ○

7440-43-9 Cadmium ● ● ● ○

18540-29-9 Chromium (hexavalent) ● ● ● ○

7440-47-3 Chromium (total) ● ● ● ○

7440-48-4 Cobalt ● ● ● ○

7439-92-1 Lead ● ● ● ○

7439-96-5 Manganese ● ● ● ○

7439-97-6 Mercury ● ● ● ○

7440-02-0 Nickel ● ● ● ○

7782-49-2 Selenium ● ● ● ○

Other Inorganic HAP

75-15-0 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 ○ ○ ○

7723-14-0 Phosphorus ○ ○ ○

(continued)
Version 1.0 Section 1—Introduction 

Review Draft – Do not cite or quote 

1-8 

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

in a Petroleum Refinery’s Emissions Inventory (continued)

CAS 

Number

or 

Pollutant 

Code Substance

Equipment LeaksStorage TanksStationary Combustion

Process Vents

FlaresWastewaterCooling TowersProduct LoadingFugitive Dust SourcesStartup/ShutdownCatalytic Cracking UnitFluid Coking UnitDelayed Coking UnitCatalytic Reforming UnitSulfur Recovery PlantsHydrogen PlantAsphalt PlantCoke CalciningBlowdown SystemsVacuum SystemsMalfunctions

Other Compounds of Interest

75-07-0 Ammonia ○ ○ ○ ● ● ○ ○ ○

75-07-0 Ethane ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○ ○

7783-06-4 Hydrogen sulfide ● ○ ○ ○ ○ ● ● ○ ○ ○ ● ○ ○ ○

7440-39-3 Barium ○ ○ ○ ○

7440-50-8 Copper ○ ○ ○ ○

7439-98-7 Molybdenum ○ ○ ○ ○

7440-62-2 Vanadium ○ ● ● ○

7440-66-6 Zinc ○ ○ ○ ○

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

○ Designates compound/source pairings for which emissions estimates may be developed depending on the available data.

POM Designates compounds t that meet the HAP definition of polycyclic organic matter (POM).

j

The listed HAP is 2,3,7,8-Tetrachlorodibenzo-p-dioxin (2378-TCDD); other dioxin isomers are listed as they can be used to 

calculate a 2378 TCDD toxicity equivalence. 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-Hexachlorodibenzop-dioxin; 6D 123678 = 1,2,3,6,7,8-Hexachlorodibenzo-p-dioxin; 6D 123789 = 1,2,3,7,8,9-Hexachlorodibenzo-p-dioxin; 7D 

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

k

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

Carbon dioxide, methane, and nitrous oxide are GHG expected to be emitted from petroleum refineries, 

but are not listed in this table. The Mandatory Greenhouse Gas Emissions Reporting Rule (74 FR 56260) 

requires detailed GHG emissions reporting from a variety of industry sectors and emission sources, 

including petroleum refineries and stationary combustion sources (40 Code of Federal Regulations (CFR) 

Part 98, Subparts Y and C, respectively). Consequently, this Refinery Emissions Protocol document 

focuses primarily on criteria and toxic air pollutants (i.e., the pollutants listed in Table 1-1). Emission 

estimates for GHG should be calculated and reported according to the methodologies and requirements in 

the GHG reporting rule. Note that the ―tiers‖ used in 40 CFR Part 98 Subpart C are listed in opposite 

order from the ―ranks‖ used in this Refinery Emissions Protocol document. That is, the Tier 4 method for 

stationary combustion sources is equivalent to Methodology Rank 1 for combustion sources in this 

protocol document; Tier 3 method is equivalent to Methodology Rank 2, and so on. 

Some criteria pollutants such as PM10 or PM2.5 have special reporting nomenclatures to indicate the 

fraction of the PM emissions that are filterable or condensable (see PM Emissions Inventory 

Nomenclature text box). Other criteria pollutants, such as nitrogen dioxide (NO2), are often determined or 
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regulated as a combination of chemicals. For example, nitrogen oxides (NOX), is the sum of NO2 and 

nitric oxide (NO) emissions. The inclusion of these additional nomenclatures or groupings in Table 1-1 is 

not intended to suggest that these compounds are criteria pollutants, but these ―pollutants‖ should be 

included in the refinery emissions inventory. 

While Table 1-1 is intended to provide a comprehensive list of pollutants for each emission source for 

which emissions estimates should be provided, there may be pollutants released from some sources for 

which we have little or no information. If there is credible information that emissions of other pollutants 

are released from a given emissions source, than emissions estimates for these additional pollutants 

should also be provided. 

1.2 Data Quality 

The consistent use of standardized methods and procedures is essential in the compilation of reliable 

emissions inventories. Quality assurance (QA) and quality control (QC) of an emissions inventory are 

accomplished through a set of procedures that ensure the quality and reliability of data collection and 

analysis. These procedures include the use of appropriate emissions estimation techniques, applicable and 

reasonable assumptions, accuracy/logic checks of computer models, and checks of calculations and data 

reliability. Depending upon the technical approach used to estimate emissions, a checklist with all of the 

particular data needs should be prepared to verify that each piece of information is used accurately and 

appropriately. 

Appropriate metadata (data about the data) should be maintained and reported to assist data users with 

assessing the accuracy of the reported emissions. For example, the methodology (or Methodology Rank) 

used to estimate the emissions should be reported. If the emissions estimates rely on activity data (e.g., 

process throughput for emission factors based on process throughput), the activity data should also be 

reported. QA/QC and other metadata records should also be maintained to allow verification of the 

reported emissions. For measured emissions, these metadata include manufacturer’s design specifications 

for accuracy, initial calibrations, periodic calibration checks, and other QA/QC procedures used to ensure 

the accuracy of the measurement device(s). For source tests used to develop site-specific emissions 

factors, the metadata include results of field and laboratory blanks, duplicate analyses, method detection 

limits, isokinetic and cyclonic flow checks (if applicable), and key process operating data (e.g., 

throughput, temperature, material processed, etc.). For some pollutants, there may be different methods 

by which the emissions can be determined. For example, VOC emissions may be determined using a 

―total organics‖ method (e.g., using EPA Method 25, 25A through 25E, or 305) or by speciating 

individual VOC and summing the emissions of these compounds to determine the overall VOC 

emissions. When reporting VOC emissions, therefore, it should be clearly indicated if the emissions are 

determined ―as methane‖ (or ―as‖ whatever compound was used to calibrate the total organic analyzer) or 

if the emissions are determined by summing emissions of individual VOC constituents. These metadata 

assist users of the inventory data and help to ensure that the inventory data are correctly and consistently 

used when performing subsequent analyses. 

PM Emissions Inventory Nomenclature

PM emissions inventories have their own nomenclature and structure. A complete PM emissions inventory 

includes the following components:

 PM10-PRI: ―Primary‖ PM emissions that are 10 μm in diameter or less. PM10-PRI = PM10-FIL + PM-CON.

 PM10-FIL: Filterable (or front-half catch) portion of the PM emissions that are 10 μm in diameter or less.

 PM-CON: Condensable PM (or back-half catch). All condensable PM is assumed to be less than 2.5 microns 

(μm) in diameter (PM2.5).

 PM2.5-PRI: ―Primary‖ PM emissions that are 2.5 μm in diameter or less. PM2.5-PRI = PM25-FIL + PM-CON.

 PM2.5-FIL: Filterable (or front-half catch) portion of the PM emissions that are 2.5 μm in diameter or less.
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1.3 Calculations and Significant Digits 

The methodology ranking presented in this Refinery Emission Protocol document is designed to highlight 

and promote those methods that are expected to yield the most accurate emissions data. We recognize that 

the Rank 5 methodologies may only provide emission estimates that are within a factor of 2 or 3 from the 

actual emissions rate. Nonetheless, the emission factors presented in this document are generally 

presented with 2 significant digits. The two significant digits should not be construed as an expectation 

that these emission factors are more accurate. The emission factors are provided with two significant 

digits because it is recommended that all calculations be performed carrying at least one additional 

significant digit to minimize round-off errors. The emissions calculated using a default emission factors 

may be rounded to one significant digit when reporting the emissions, but you should carry at least two 

significant digits in the calculations. For Methodology Rank 1 or other methods that may have 

uncertainties in the range of ±10 percent, at least 3 significant digits should be carried when performing 

the calculations, even though the final emission estimate may only warrant 2 significant digits. 
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2. Equipment Leaks 

Equipment leaks are small emission sources that occur throughout the process area of the refinery from 

various equipment components and connections that develop leaks that allow process fluids to escape into 

the atmosphere. Leaks are typically identified using EPA Method 21 (via an organic vapor analyzer or 

―OVA‖) or using optical leak imaging techniques; other remote sensing techniques can also be used to 

identify leaks. Although direct measurement methods provide the most accurate means of quantifying 

equipment leak emissions, few, if any, refineries have or will implement direct measurement of 

equipment leak emissions. Instead, mass emissions for several types of equipment can be estimated using 

correlation equations that relate mass emissions to leak concentrations that are obtained using an OVA. In 

the absence of concentration measurements, mass emissions can also be estimated using the number of 

equipment components and emission factors. Typically, these procedures estimate either total organic 

compound (TOC) or non-methane organic compound mass emissions. To estimate either total VOC or 

constituent-specific emissions, the process streams being monitored must be characterized. 

The most common optical leak imaging technique illuminates a scene with infrared laser light of a 

wavelength that is strongly absorbed by the gas of interest, and the backscattered infrared light is 

converted to a real-time video image of the emissions plume. Although this technology is very useful for 

quickly and easily identifying the presence of leaks, particularly large leaks, it has not yet developed to 

the point of being able to quantify emissions. Therefore, it must be combined with other techniques as 

described below to quantify emissions. Other remote sensing techniques include Differential Absorption 

Light Detection and Ranging (LIDAR) and Solar Occultation Flux. These techniques measure either the 

volumetric or mass concentrations of a compound or mixture of compounds in a vertical cut through a 

plume downwind of its source. Combining these data with wind speed can be used to estimate mass flux. 

However, these remote sensing techniques are not yet approved by EPA as a method of quantifying 

emissions from equipment leaks or any other sources. Furthermore, because the measurement is 

conducted some distance downwind from a source, the techniques alone are not practical for identifying 

specific leaking equipment components. When appropriate, we will update this document to include 

methodologies for any optical leak imaging or other remote sensing techniques that develop to the point 

of being able to quantify equipment leak emissions. 

It is generally assumed that all leaks, even liquid leaks, will eventually evaporate so that 100% of the leak 

will be emitted into the atmosphere, so direct stream composition is used to estimate equipment leak 

emissions. For heavy liquids (such as residual fuel oils or bitumen), the assumption of 100% emissions 

may overstate actual emissions, especially if the liquid is cleaned up using oil socks or other similar 

techniques. These heavy liquids may contain significant amounts of polycyclic aromatic hydrocarbons

(PAH). As such, using the 100% emissions assumption, equipment leaks of heavy liquids can be a 

significant source of PAH emissions. Currently, there is no method for correcting emissions estimates for 

liquid component leaks that contain heavy organic material (e.g., hydrocarbon compounds with 15 or 

more carbon atom, i.e., C15 hydrocarbons). However, if the liquid material is cleaned up so that it is not 

available for subsequent emissions, it may be assumed that only 10% of the C15 or heavier organics are 

emitted due to the leak. 

Table 2-1 summarizes the hierarchy of equipment leak emissions estimation techniques. The methods are 

ranked in terms of anticipated accuracy. Within a given measurement method (or rank), there may be 

alternative methods for determining the constituent-specific emissions; these compositional analysis 

methods are also provided in order of accuracy. It is anticipated that each refinery will use a mixture of 

different methods. For example, Methodology Rank 2 for equipment leaks may be used for components 

that are monitored using Method 21, but Methodology Ranks 4 or 5 for equipment leaks may be used to 

estimate emissions from other components that are not routinely monitored. The remainder of this section 

provides additional details and guidance regarding the ways to implement these methods. Most of the 

methods outlined in this section are based on the revised equipment leak protocol developed specifically 
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for the petroleum refinery industry. For more information regarding the way in which the correlations 

were developed, please refer to EPA’s document, Protocol for Equipment Leak Emission Estimates (U.S. 

EPA, 1995b). 

Table 2-1. Summary of Equipment Leak Emissions Estimates 

Rank Measurement Method

Correlation Equations 

or Emissions Factor Compositional Analysis Dataa

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 

emissions 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 

emissions 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 measurement methods: the bagging method and high-volume 

sampling. Typically, EPA Method 21 would be used to initially screen and identify leaking components, 

and then one of these methods would be used to quantify the mass emissions rate of the leak. Direct leak 

rate measurement, using either of these techniques, is accurate within ±15% (U.S. EPA, 2003). 

In the bagging method, 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 bag, and the TOC concentration of the sample is 

measured. That collected gas can also be analyzed for individual compound concentrations. The mass 

emissions rate is calculated from the measured concentrations of the bag sample and the flow rate of the 

carrier gas. Although bagging techniques are useful for the direct measurement of larger leaks, bagging 

may not be possible for equipment components that are inaccessible, unusually shaped, or very large, and 

it is a relatively slow process (i.e., only two or three samples per hour). 

High-volume samplers are essentially vacuums that capture all of the emissions from a leaking 

component to accurately quantify leak emissions rates. Leak emissions and a large-volume sample of the 

air around the leaking component are pulled into the instrument through a vacuum sampling hose. Highvolume samplers are equipped with dual hydrocarbon detectors, which measure the concentration of 

hydrocarbon gas in the captured sample and the concentration of ambient hydrocarbon gas. Sample 

measurements are corrected for the ambient hydrocarbon concentration, and a mass leak rate is calculated 

by multiplying the flow rate of the measured sample by the difference between the ambient gas 

concentration and the gas concentration in the measured sample. Chemical speciation of the leak, using 

vacuum canisters or similar methods, can be used to apportion the TOC emissions rate to individual 

constituents. High-volume samplers measure leak rates up to 0.23 cubic meters per minute (m3/min), 
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which is a rate equivalent to 330 cubic meters per day (m3/day), and can be used to quantify 10 to 20 

sources per hour. Leak rates greater than 0.23 m3/min must be measured using bagging techniques (U.S. 

EPA, 2003). 

2.2 Methodology Ranks 2 and 3 for Equipment Leaks 

Most leak detection and repair (LDAR) programs require periodic monitoring using EPA Method 21 to 

identify leaking components. The preferred methodology for estimating equipment leak emissions rates 

directly from EPA Method 21 data (Methodology Rank 2 for equipment leaks) is to use the screening 

value correlations in the right column of Table 2-2 (U.S. EPA, 1995b) for each individual component as 

screened via EPA Method 21. When a screening value of 0 is registered, the default zero value in the 

second column in Table 2-2 is used to estimate TOC emissions. If the monitoring instrument measures 

concentrations only up to 10,000 ppmv or 100,000 ppmv, then the applicable values for pegged emissions 

rates in Table 2-2 are used to estimate emissions. Many refineries or monitoring specialists use software 

programs that directly record the TOC reading (or screening value) for each component. Many of these 

software programs will directly calculate the TOC emissions for each component using the screening 

value correlations and will even calculate component-specific emissions rates when composition data are 

entered for the components. The TOC rates calculated by the correlation equation (and the default zero 

and pegged emission rate values) include non-VOC organic compounds, primarily methane and ethane. 

To calculate VOC emissions, the TOC emissions must be multiplied by the ratio of the weight percent of 

VOC to weight percent of TOC (i.e., (wt% TOC-wt% methane and ethane)/wt% TOC). The uncertainty 

of the correlations for any single measurement may be as much as a factor of 3 higher or a factor of 10 

lower than the actual emissions for that component, but when summed over thousands of components, the 

uncertainty in the cumulative total emissions is expected to be approximately ±30%. 

In some older LDAR programs, the only information that is recorded is whether a leak was found. For 

these LDAR programs, leaks were defined as screening value readings greater than 10,000 parts per 

million by volume (ppmv). In these cases, generally the available data are the number of components of 

each type at the plant and the number of components of each type found with TOC readings less than 

10,000 ppmv and the number of components of each type with TOC readings greater than or equal to 

10,000 ppmv. Methodology Rank 3 for equipment leaks estimates the emissions rate using these data and 

the screening ranges emission factors in Table 2-3 (U.S. EPA, 1995b). If the number of components and 

the number of leakers are recorded by process, then this provides a more accurate method for using 

process-specific compositional data to estimate constituent-specific emissions rates (Methodology ranks 

2a and 2b). Alternatively, the average percentage of leakers facility-wide can be used, and these data can 

be coupled with process-specific component counts to estimate emissions by process (Methodology rank 

2c). The uncertainty of the default leak rates for any single measurement may be as much as a factor of 3 

higher or a factor of 10 or more lower, but when summed over thousands of components, the uncertainty 

in the cumulative total emissions is expected to be approximately ± 40%. 

To apply the screening ranges emission factor approach, use Equation 2-1 to calculate the total annual 

TOC emissions per type of equipment for which Methodology Rank 3 is used, and then use Equation 2-2 

to calculate the VOC emissions. Note that Equation 2-1 adjusts the emission factors for methane because 

when the factors were developed, methane was subtracted out of the organic total. Therefore, apply the 

equation separately to groups of equipment in streams with significantly different methane weight 

fractions. 

 ETOC = {[FG × (WFTOC/(WFTOC – WFm)) × NG] + [FL × (WFTOC/(WFTOC – WFm)) × NL]} × H (Eq. 2-1) 

where: 

 ETOC = Emissions rate of TOC for a specific type of equipment (kilograms per year [kg/yr]) 
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 FG = Applicable emission factor for specific type of equipment type with screening values 

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

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

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

WFTOC = Average weight fraction of TOC in the stream 

WFm = Average weight fraction of methane in the stream 

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

than or equal to 10,000 ppmv 

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

10,000 ppmv 

 H = Operating hours per year 

EVOC = ETOC × (WFVOC/WFTOC) (Eq. 2-2)

where: 

 EVOC = Emissions rate of VOC for a specific type of equipment (kg/yr) 

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

ethane) 

When an optical gas imaging camera is used to identify leaks, the emissions can be quantified under 

Methodology Rank 2 only if both of the following conditions are met: (1) the equipment is monitored in 

accordance with the procedures in §63.11(e) and (2) all leaks identified by the camera are monitored 

before repair using Method 21. For equipment found to be leaking when monitoring with the camera, use 

the subsequent Method 21 screening values in the applicable correlation equation to estimate the 

emissions. For all equipment not found to be leaking when monitoring with the camera, estimate 

emissions using the screening values obtained when conducting the annual Method 21 monitoring 

required by §63.11(e) in the applicable correlation equations. For any other situation when an optical gas 

imaging camera is used to identify leaks, quantify emissions using Methodology Rank 4 or Methodology 

Rank 5. 

Table 2-2. Equipment Leak Rate for Refinery Equipment Componentsa

Equipment Type

(All Services)

Default Zero 

Emissions Rate 

(kg/hr/source)

Pegged Emissions Rates 

(kg/hr/source) Correlation Equationb

10,000 ppmv 100,000 ppmv (kg/hr/source)

Valve 7.8E-06 0.064 0.140 2.29E-06×SV0.746

Pump 2.4E-05 0.074 0.160 5.03E-05×SV0.610

Otherc4.0E-06 0.073 0.110 1.36E-05×SV0.589

Connector 7.5E-06 0.028 0.030 1.53E-06×SV0.735

Flange 3.1E-07 0.085 0.084 4.61E-06×SV0.703

Open-ended line 2.0E-06 0.030 0.079 2.20E-06×SV0.704

Note: kg/hr/source = kilograms 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 instruments, loading arms, pressure relief devices, stuffing 

boxes, vents, compressors, dump lever arms, diaphragms, drains, hatches, meters, and polished rods. This 

―other‖ equipment type should be applied to any equipment other than connectors, flanges, open-ended lines, 

pumps, or valves.
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Table 2-3. Refinery Screening Ranges Emission Factorsa

Equipment type Service

≥10,000 ppmv emission 

factor (kg/hr/source)b

<10,000 ppmv emission 

factor (kg/hr/source)b

Valves Gas 0.2626 0.0006

Light liquid 0.0852 0.0017

Heavy liquid 0.00023 0.00023

Pump and agitator seals Light liquid 0.437 0.0120

Heavy liquid 0.3885 0.0135

Compressor seals All 1.608 0.0894

Pressure relief valves All 1.691 0.0447

Connectors All 0.0375 0.00006

Open-ended lines All 0.01195 0.00150

a Data reported in U.S. EPA, 1995b.

b

These factors are for non-methane organic compound emissions.
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Example 2-1: Calculation for Methodology Rank 2 for Equipment Leaks

A refinery reforming unit operating 8,000 hours per year (hr/yr) has 600 valves. To keep the 

example simple, assume Method 21 monitoring registers the screening value readings in the 

following table, and assume the average weight percents of methane and ethane in each stream 

are known or estimated to be equal to 3 percent and 1 percent of the TOC, respectively. Also 

assume the TOC content of each stream is 100 percent. Using Methodology Rank 2 for 

equipment leaks (correlation approach), what is the cumulative hourly VOC emissions rate 

from the valves in this process unit at the time the monitoring is conducted? What is the 

annual emissions rate?

To calculate the emissions, the default zero value for valves on Table 2-2 (7.8E-06) is used to 

estimate the TOC emissions from the 580 valves with a screening value of 0 ppmv. The 

pegged emission rate for valves in Table 2-2 (0.140) is used to estimate the TOC emission 

rate for the 2 valves with pegged readings. The correlation equation for valves in Table 2-2

(2.29E-06 x SV^0.746) is used to estimate the emissions for each of the valves with a 

measured screening value. In each case, the calculated TOC emissions are multiplied by (100-

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

8,000 hr/yr).

Number of 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

0.29
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2.2.1 Speciating Equipment Leak Emissions 

Table 1-1 lists the specific organic compounds that should be included in an inventory of equipment leak 

emissions. The following equation (Equation 2-3) is used to speciate emissions from a single equipment 

piece:

Ei = EVOC × (WFi/WFVOC) (Eq. 2-3) 

where: 

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

[kg/hr]) 

 EVOC = VOC mass emissions from the equipment (kg/hr) 

WFi = Concentration of organic chemical ―i‖ in the equipment in (weight fraction)

WPVOC = VOC concentration in the equipment in (weight fraction) 

Example 2-2: Calculation for Methodology Rank 3 for Equipment Leaks

For the valves in the same reforming unit described in Example 2-1, what is the cumulative 

hourly VOC emissions rate when Methodology Rank 3 is used? What are the annual VOC 

emissions? Assume the distribution of valves in gas, light liquid, and heavy liquid service is as 

shown in the table below.

To calculate hourly TOC emissions for valves in gas service with screening values less than 

10,000 ppmv, use the second half of Equation 2-1. 

ETOC = [FL × (WFTOC/(WFTOC – WFm)) × NL]

= [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 2-2 to calculate the VOC emissions from these 

valves.

EVOC = ETOC × (WFVOC/WFTOC)

= 0.675 × (100-4)/100

= 0.648 kg VOC/hr

Use the same procedure with the first half of equation 2-1 to estimate TOC emissions of 1.076 

kg/hr from the valves with screening values equal to or greater than 10,000 ppmv, and apply 

equation 2-2 to calculate VOC emissions of 1.033 kg/hr. Total annual emissions are calculated 

to be 13,400 kg VOC/yr (1.68 kg/hr x 8,000 hr/yr).

Screening 

Value, 

ppmv

Number of Valves by Type 

of Service

Emission Factors, 

kg/hr/source TOC

Emissions, 

kg/hr

VOC 

Emissions,

Gas kg/hr

Light 

Liquid

Heavy 

Liquid Gas

Light 

Liquid

Heavy 

Liquid

<10,000 236 293 65 0.0006 0.0017 0.00023 0.675 0.648

≥10,000 3 3 0 0.2626 0.0852 0.00023 1.076 1.033

1.68
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To the extent that compositional data are available for individual process streams, each equipment 

component associated with that process stream should be tagged with the average composition of that 

process stream (Methodology Rank 2a or 3a for equipment leaks). Although an ideal situation would be if 

chemical speciation data were available for each equipment component (i.e., each process stream 

associated with each equipment component), in many cases, this level of detail may not be available. 

Alternatively, average compositional data may be determined for a specific process unit, such as at the 

crude distillation unit or the CRU, and all equipment components associated with that process unit would 

be tagged with that concentration profile (Methodology Rank 2b or 3b for equipment leaks). As a last 

resort, a single, overall average process stream composition can be estimated for a refinery (Methodology 

Rank 2c or 3c for equipment leaks). Methodology Rank 2c or 3c of equipment leak emissions is very easy 

to implement in that the VOC emissions can be aggregated for all components first, and then the 

chemical-specific emissions can be calculated from the cumulative VOC emissions. However, this 

method greatly reduces the accuracy of the chemical-specific emissions rates. With the automated 

software programs that are now available for logging equipment leak readings and calculating equipment 

leak emissions, most refineries should be able to implement Methodology Rank 2a or 2b for equipment 

leaks. 

2.2.2 Calculating Annual Equipment Leak Emissions 

The emissions estimated based on EPA Method 21 measurement data (i.e., Methodology Rank 2 or 3 for 

equipment leaks) represent the emissions rate at the time when the measurements were made. The first 

time an LDAR program is implemented, the emissions estimates from the component screening 

measurements should be used as the emissions rate for the facility (or an individual component or set of 

components) for all periods prior to the screening measurements (i.e., the portions of the inventory year 

Example 2-3: Calculation for Speciating Equipment Leak Emissions

For Example 2-1 the measured composition of the process stream associated with one of the 

valves (Methodology Rank 2a) for which a screening value of 7,000 ppmv was obtained is:

Hexane 10 wt% 

Toluene 8 wt%

Benzene 2 wt%

Other volatile organic compounds (VOC) 60 wt%

Methane and ethane 4 wt%

Nitrogen 10 wt%

Water 5 wt%

Hydrogen 1 wt%

The TOC weight fraction is calculated as the sum of all of the organic compounds. The VOC 

weight fraction is the sum of all of the organic compounds, minus methane and ethane, as 

shown in the following equation:

WFVOC = %Hexane + %Toluene + %Benzene +% Other VOC)/100% 

= (10 + 8 + 2 + 60)/100 = 0.80

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

2-3 is used to attribute these emissions to individual components as follows:

EHexane = 0.81 × (0.1/0.8) = 0.10 g/hr

EToluene = 0.81 × (0.08/0.8) = 0.08 g/hr

EBenzene = 0.81 × (0.02/0.8) = 0.02 g/hr

EOtherVOC = 0.81 × (0.60/0.8) = 0.61 g/hr
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prior to the screening measurements). However, most equipment components at a refinery are expected to 

be monitored for leaks on a routine basis (i.e., monthly, quarterly, or semiannually) as part of an ongoing 

LDAR program. Leaks greater than a certain threshold are required to be repaired within certain time 

frames (although many LDAR programs allow some repairs to be delayed). After repairs are made, the 

repaired components should be re-screened to verify that the leak has been repaired and to provide a new 

starting emissions rate for that component. During the next routine monitoring period, new screening 

values will be determined for each component, providing new instantaneous emissions rate estimates for 

each component. For the purposes of developing an average emissions rate, it can be assumed that the 

initial reading represents the emissions rate for the first half of the period between monitoring events and 

that the subsequent reading represents the emissions rate for the second half of the period between 

monitoring events. For leaks that are repaired, the ―leak‖ monitor reading is used from the time the leak is 

detected to the time it is repaired (i.e., re-screened). 
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2.3 Methodology Ranks 4 and 5 for Equipment Leaks 

Methodology Ranks 4 and 5 for equipment leaks should be used only for components that are not being 

routinely monitored for leaks. For refineries, this might be processes that have low HAP and low VOC 

content, or it might be specific types of components that are either classified as unsafe to monitor (e.g., 

certain pumps and valves) or are not subject to the monitoring requirements (e.g., connectors) in the new 

source performance standards (NSPS) or Petroleum Refinery Maximum Achievable Control Technology 

(MACT) I rules. Facility- or process-specific component counts (Methodology Rank 4 for equipment 

leaks) are preferred over default component counts (Methodology Rank 5 for equipment leaks), but the 

emissions estimation procedure is similar in both cases. When using Methodology Ranks 4 and 5, 

speciated emissions are calculated using the same procedures described in section 2.2.1 of this document. 

Example 2-4: Calculation for Annual Emissions

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×SV0.610) to calculate the emissions 

rate in Column 3 when the OVA reading is greater than 0, and the default zero rate is used 

when the OVA reading is 0. The hours between intervals were calculated; half of the hours 

were assigned to the first reading and half were assigned to the second reading, except for 

periods before repair, which were assigned the ―leak‖ emissions rate. 

1

Date and Time

2

OVA Reading

(ppm)

3

TOC Emissions 

Rate

(kg/hr)

4

Hoursa

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 emissions rate applies over half of the hours since the previous screening and over half of the hours 

until the next screening. For example, the results from the July 2 measurement apply to half of the hours 

since the June 2 measurement and to half of the hours before the next measurement on August 2. The 

July 2 measurements occur 30 days (720 hours) after the June 2 measurement and 31 days (744 hours) 

before the August 2 measurements. Therefore, the July 2 results apply to 732 hours during the year 

(720/2 + 744/2 = 732). 

b

Indicates special Method 21 measurement reading to verify repair.
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The median equipment component counts for small refineries (those less than 50,000 barrels per calendar 

day [bbl/cd])1

 and large refineries (greater than 50,000 bbl/cd) as presented in EPA’s document, Locating 

and Estimating Air Emissions from Sources of Benzene (U.S. EPA, 1998a), are presented in Tables 2-4 

and 2-5, respectively. The default emissions factor per component for uncontrolled or unmonitored 

components is provided in EPA’s document, Protocol for Equipment Leak Emission Estimates (U.S. 

EPA, 1995b). These emissions factors are summarized in Table 2-6. 

EPA’s document, Locating and Estimating Air Emissions from Sources of Benzene, also presents average 

process stream benzene concentrations based on the stream type or ―service‖ (i.e., if the process stream is 

a gas, a light liquid, or a heavy liquid). These data are presented in Table 2-7. Preferably, facility- or 

process-specific compositional analyses would be available to develop constituent-specific emissions 

estimates. 

 

1

 Barrels per calendar day is the amount of crude that a refinery can process under usual operating conditions and is 

expressed in terms of actual capacity during a 24-hour period (i.e., actual annual capacity divided by 365 days). The 

other typical capacity measure, barrels per stream day (bbls/sd), is the maximum number of barrels of crude that a 

refinery can process within a 24-hour period when running at full capacity. 
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Table 2-4. Median Equipment Leak Component Counts for Small Model Processesa

Process Unit

Valves Pumps

Compressors

Pressure Relief Valves Flanges OpenEnded 

Lines

Sampling 

Gas Connections

Light 

Liquid

Heavy 

Liquid

Light 

Liquid

Heavy 

Liquid Gas 

Light 

Liquid

Heavy 

Liquid Gas 

Light 

Liquid

Heavy 

Liquid

Crude distillation 75 251 216 8 8 2 6 6 5 164 555 454 39 10

Alkylation (sulfuric acid) 278 582 34 18 10 1 12 15 4 705 1,296 785 20 16

Alkylation (HF) 102 402 62 13 3 2 12 13 0 300 1,200 468 26 8

Catalytic reforming 138 234 293 8 5 3 5 3 3 345 566 732 27 6

Hydrocracking 300 375 306 12 9 2 9 4 4 1,038 892 623 25 10

Hydrotreating/hydrorefining 100 208 218 5 5 2 5 3 5 290 456 538 20 6

Catalytic cracking 186 375 450 13 14 2 8 8 7 490 943 938 8 8

Thermal cracking (visbreaking) 206 197 0 7 0 0 4 0 0 515 405 0 0 4

Thermal cracking (coking) 148 174 277 9 8 2 7 16 13 260 322 459 13 8

Hydrogen plant 168 41 0 3 0 2 4 2 0 304 78 0 8 4

Asphalt plant 120 334 250 5 8 2 5 10 9 187 476 900 16 6

Product blending 67 205 202 6 11 1 10 6 22 230 398 341 33 14

Sulfur plant 58 96 127 6 6 3 3 88 15 165 240 345 50 3

Vacuum distillation 54 26 84 6 6 2 2 5 2 105 121 230 16 4

Full-range distillation 157 313 118 7 4 2 5 4 6 171 481 210 20 6

Isomerization 270 352 64 9 2 2 7 10 1 432 971 243 7 8

Polymerization 224 563 15 12 0 1 10 5 3 150 450 27 5 7

MEK dewaxing 145 1,208 200 35 39 3 10 14 4 452 1,486 2,645 19 17

Other lube oil processes 153 242 201 7 5 2 5 5 5 167 307 249 60 6

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

50,000 bbl/cd.
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Table 2-5. Median Equipment Leak Component Counts for Large Model Processesa

Process Unit

Valves Pumps

Compressors

Pressure Relief Valves Flanges OpenEnded 

Lines

Sampling 

Gas Connections

Light 

Liquid

Heavy 

Liquid

Light 

Liquid

Heavy 

Liquid Gas

Light 

Liquid

Heavy 

Liquid Gas 

Light 

Liquid

Heavy 

Liquid

Crude distillation 204 440 498 15 14 2 7 5 12 549 982 1,046 75 9

Alkylation (sulfuric acid) 192 597 0 21 0 2 13 4 0 491 1,328 600 35 6

Alkylation (HF) 104 624 128 13 8 1 9 11 1 330 1,300 180 40 14

Catalytic reforming 310 383 84 12 2 3 8 11 0 653 842 132 48 9

Hydrocracking 290 651 308 22 12 2 10 12 0 418 1,361 507 329 28

Hydrotreating/hydrorefining 224 253 200 7 6 2 9 4 8 439 581 481 49 8

Catalytic cracking 277 282 445 12 12 2 11 9 13 593 747 890 59 15

Thermal cracking (visbreaking) 110 246 130 7 6 1 6 3 15 277 563 468 30 7

Thermal cracking (coking) 190 309 250 12 11 1 8 5 10 627 748 791 100 10

Hydrogen plant 301 58 0 7 360 3 4 139 0 162 148 0 59 21

Asphalt plant 76 43 0 4 0 0 3 7 0 90 90 0 24 24

Product blending 75 419 186 10 10 2 9 16 6 227 664 473 24 8

Sulfur plant 100 125 110 8 3 1 4 4 4 280 460 179 22 7

Vacuum distillation 229 108 447 2 12 1 5 1 4 473 136 1,072 0 7

Full-range distillation 160 561 73 14 2 2 7 8 2 562 1,386 288 54 6

Isomerization 164 300 78 9 5 2 15 5 2 300 540 265 36 7

Polymerization 129 351 82 6 2 0 7 12 28 404 575 170 17 9

MEK dewaxing 419 1,075 130 29 10 4 33 6 18 1,676 3,870 468 0 7

Other lube oil processes 109 188 375 5 16 3 8 6 20 180 187 1,260 18 9

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

50,000 bbl/cd.
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Table 2-6. Refinery Average Component Emissions Factorsa

Equipment Type Service

Emissions Factor

(kg/hr/source)b

Valves Gas 0.0268

Light liquid 0.0109

Heavy liquid 0.00023

Pump sealscLight liquid 0.114

Heavy liquid 0.021

Compressor seals Gas 0.636

Pressure relief valves Gas 0.16

Connectors All 0.00025

Open-ended lines All 0.0023

Sampling connections All 0.0150

Note: kg/hr/source = kilograms per hour per source

a

Source: U.S. EPA, 1995b.

b

These factors are for non-CH4 organic compound emissions rates.

c

The light liquid pump seal factor can be used to estimate the leak rate from agitator seals.

Table 2-7. Concentration of Benzene in Refinery Process Unit Streamsa

Process Unit

Weight Percent of Benzene in Stream Type

Gas Light Heavy Liquid

Crude 1.3 1.21 0.67

Alkylation (sulfuric acid) 0.1 0.23 0.23

Catalytic reforming 2.93 2.87 1.67

Hydrocracking 0.78 1.09 0.1

Hydrotreating/hydrorefining 1.34 1.38 0.37

Catalytic cracking 0.39 0.71 0.2

Thermal cracking (visbreaking) 0.77 1.45 1.45

Thermal cracking (coking) 0.24 0.85 0.18

Product blending 1.2 1.43 2.15

Full-range distillation 0.83 1.33 1.08

Vacuum distillation 0.72 0.15 0.22

Isomerization 2.49 2.49 0.62

Polymerization 0.1 0.1 0.1

MEK dewaxing 0.36 Not reported Not reported

Other lube oil processing 1.2 1.2 0.1

a Source: U.S. EPA, 1998a.

To apply the average emissions factors, use Equation 2-4 to estimate VOC mass emissions from all of the 

equipment in a stream of a given equipment type. Note that the emission factors in Table 2-6 were 

developed to estimate emissions of non-methane organic compounds. Therefore, to estimate VOC 

emissions, the emission factor must be multiplied by the ratio of the VOC-to-NMOC weight fractions. 

Also note that the emission factors apply to streams that are 100 percent TOC. To calculate VOC 

emissions from equipment in contact with a stream that contains both organic compounds and other 
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2-15 

compounds like nitrogen or water vapor, the emission factor must be multiplied by the TOC weight 

fraction in the stream. As a result, TOC, methane, and ethane weight fractions must be known or 

estimated in order to calculate the VOC emissions: 

 EVOC = FA × (WFTOC - WFethane - WFmethane)/(WFTOC - WFmethane) × WFTOC × N × H (Eq. 2-4) 

where: 

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

(kg/yr)

FA = Applicable average non-methane organic compounds emissions factor for the 

equipment type (kg/hr/source) 

WFTOC = Average weight fraction of TOC in the stream 

WFethane = Average weight fraction of ethane in the stream 

WFmethane = Average weight fraction of methane in the stream 

 N = Number of pieces of equipment of the applicable equipment type in the stream 

 H = Hours per year in component service 

If a process stream contains no ethane, the non-methane organic fraction is equal to the VOC fraction, 

which means the emission factor can be used without the correction ratios noted above, and the equation 

simplifies to Equation 2-5: 

EVOC = FA × WFTOC × N × H (Eq. 2-5) 

Two guidelines when correcting the ―FA‖ term when applied to refineries are as follows: 

– The correction should only be applied to equipment containing a mixture of organics and CH4.

– The maximum correction for the CH4 weight fraction should not be greater than 0.10, even if the 

equipment contains greater than 10 weight percent of CH4. (This reflects that the equipment for 

which the average emissions factors in Table 2-6 were developed typically contained 10 weight 

percent or less of CH4).

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

Emissions Factors

At a refinery, if there are 100 gas valves in a stream that, on average, contains 80 weight 

percent non-CH4 organic compounds, 10 weight percent water vapor, 10 weight percent CH4,

and no ethane (thus, the TOC weight percent would be 90). If the process operates 8,000 hours 

per year, what are the cumulative VOC emissions from the 100 gas valves?

Because the process stream contains no ethane, the VOC emissions can be calculated using 

the applicable emission factor from Table 2-5 and Equation 2-5.

EVOC = FA × WFTOC × N × H

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

= 19,300 kg/yr of VOC from gas valves in the stream
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3-1 

3. Storage Tanks 

Storage tanks (also known as storage vessels) are used in refineries for storing and dispensing various 

liquids used in the refining process. These various liquids are typically organic liquids, also known as 

petroleum liquids, which are a mixture of hydrocarbons, such as gasoline and crude oil. Depending on the 

specific design and construction of the tank and the characteristics of the petroleum liquids, storage tanks 

may emit significant levels of VOC and HAP during typical operation, venting, and tank filling or 

dispensing. 

The basic designs for storage tanks include horizontal and vertical fixed roof tanks, external floating roof 

tanks, internal floating roof tanks, and domed external floating roof tanks. Chapter 7.1 (Organic Liquid 

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 emissions estimation methods for storage tanks are presented in Table 3-1. These methods are ranked 

according to anticipated accuracy. There are three primary estimation methods: (1) direct measurement, 

(2) tank-specific modeling, and (3) default tank emissions factors. Direct measurements can only be taken 

from process units that are covered and vented to a control device. Tank-specific modeling can be 

accomplished with emissions equations, such as those presented in AP-42 or by computer-based models 

designed to implement these equations (e.g., TANKS v4.09D; U.S. EPA, 2006). Most refinery owners 

and operators will have sufficient data to use the tank-specific modeling approach and this method should 

be used for most refinery storage vessels. In rare cases when tank-specific data are not available, 

engineering estimates can be made using actual or estimated production quantities and default emissions 

factors. 

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

Rank

Methodology 

Description Application Data Requirements

1 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 

3a Default tank modeling Common petroleum liquid 

storage tanks

Site-specific crude throughput, specific 

product production rates

3b Default tank modeling Common petroleum liquid 

storage tanks

Crude throughput and production capacities 

(from the U.S. Energy Information 

Administration or other similar source)

3.1 Methodology Rank 1 for Storage Tanks 

Emissions from fixed roof storage tanks may be purged (e.g., tanks under a nitrogen blanket) and vented 

to a control device; these emissions can be directly measured at the outlet of the control device using the 

direct measurement methods for process vents or combustion sources as described in Sections 4,

Stationary Combustion Sources, and 5, Process Vents, of this Refinery Emissions Protocol document. It is 

likely that the control device will serve a group of tanks; it is acceptable to report the cumulative 

emissions from the group of storage tanks if this is the case. 

For some control devices, such as flares, it may be possible to measure the concentration of the gas 

upstream of the control device and estimate the emissions using an assumed control device efficiency (for 
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3-2 

more details on these types of methods, see Section 4, Stationary Combustion Sources, and/or Section 6, 

Flares). This method is also recommended as a means to estimate storage tank emissions when the 

emissions from the storage tank(s) are routed to a control device that also serves other refinery emission 

sources. In this case, the concentration and flow rate of the storage tank off-gas can be measured prior to 

combining the stream with other non-storage tank emissions. The resulting constituent mass flow rates 

can be corrected for the control device efficiency using the methods described in Chapter 6 (Flares) to 

estimate the emissions associated with the storage tank(s) that are released to the atmosphere. 

There are other direct measurement methods that have been used to measure emissions from storage tanks 

even when the emissions from the tank are not vented (i.e., DIAL [Differential Absorption Light 

Detection and Ranging (LIDAR)] techniques); however, these methods do not provide continuous 

monitoring and have additional limitations (requiring consistent wind direction, etc.). Therefore, at the 

present time they are not recommended as primary techniques for emissions estimation. However, they 

can be used to verify and assess the accuracy and uncertainties associated with tank-specific modeling. 

If direct measurement methods are used, emissions from the tank during degassing, cleaning, or drained 

idle periods may or may not be included, depending on how these gases are vented. If these gases are 

routed to the same control device as used during normal operations, the measured emissions will account 

for these periods. If these emissions are not controlled in the same manner as normal operations, the 

emissions should be estimated separately for these periods using the methods provided in Section 

7.1.3.2.2 of the 2006 update of Section 7.1.

3.2 Methodology Rank 2 for Storage Tanks 

Except for the limited number of storage tanks whose emissions are collected and controlled external to 

the storage tank, EPA recommends that the emissions estimation procedures detailed in Chapter 7.1 of 

AP-42 (U.S. EPA, 1995a) be used to calculate air pollutant emissions from organic liquid storage tanks. 

There are many tools available, such as TANKS v4.09D emissions estimation software that can be used to 

perform the necessary calculations. TANKS v4.09D software can be downloaded for free at: 

http://www.epa.gov/ttnchie1/software/tanks/index.html under the How to Get TANKS 4.09D link. 

Because TANKS v4.09D is widely used, Appendix C of this Refinery Emissions Protocol document 

provides tips and insights on using the TANKS program. 

Key things to consider when estimating emissions from storage tanks (whether using the AP-42 equations 

directly or when using TANKS v4.09D or other software packages) include: 

1. Each tank should be modeled individually using site-specific conditions. There may be 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 should be limited to situations where the tanks, contents, 

and throughputs are effectively identical. In all other cases, it is recommended that individual 

tank data be entered into the TANKS program (or other similar software), and the emissions 

results for individual tanks be reported. 

2. For the internal floating roof tank, the external floating roof tank, and the domed external floating 

roof tank, the tank fittings should be selected to represent the specific characteristics of each 

individual storage tank. You should not use the ―default‖ fitting settings when using TANKS 

v4.09D, unless these settings exactly match (by number and type) the fittings actually present on 

the individual storage tank being modeled. 

3. The storage tanks should be modeled using monthly parameters, including average monthly 

measured tank liquid temperatures, when available. In TANKS, selecting the city will set the 

meteorological data that will be used in the calculations. Even if you select the monthly 

calculation option, the liquid temperature remains at the annual average. As such, the TANKS 
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3-3 

program will not adequately account for the monthly variations in emissions. Also, for 

intermediate process tanks with floating roofs that store liquids that are generally warmer than 

ambient temperature, TANKS will underestimate the emissions.2 Therefore, for storage tanks 

with throughputs that vary significantly with the seasons and floating roof tanks that store warm 

process fluids, the equations in Chapter 7.1 of AP-42 should be used directly to more accurately 

estimate the annual emissions. 

4. Special calculations should be performed to account for tank roof landings, tank degassing, and 

tank cleaning, and these estimates should be included in the final annual emissions reported for 

each tank. The TANKS model does not currently contain algorithms for estimating emissions 

from tank roof landings. These emissions should be estimated separately for each landing event 

using the methods provided in Section 7.1.3.2.2 of the 2006 update of Section 7.1. 

5. Emission estimates should be calculated and reported for individual pollutants. The TANKS 

program typically provides total hydrocarbon emissions estimates, but can also provide estimates 

for individual pollutants. 

3.3 Methodology Rank 3 for Storage Tanks 

Refinery owners and operators are expected to have tank-specific information and should use 

Methodology Rank 2 for storage tanks; however, state and local agency staff may not have access to this 

information. When tank-specific information is not available, default emissions factors can be used. The 

emissions factors presented in this section are primarily based on model external floating roof tanks for 

various petroleum refinery liquids (e.g., crude oil, gasoline, jet fuel). These default emissions factors 

required assumptions regarding the typical fitting controls and the average composition of crude oil, 

gasoline, and other products at the refinery. The heavy distillate and aromatics emissions factors were 

developed based on the permit applications, which were generally based on TANKS modeling. The 

reported emissions, which were normalized by production capacity, were then averaged across a limited 

number of storage tanks to develop the default emissions factors that are provided in Table 3-2. 

Additional details regarding the assumptions used to develop these emissions factors are found in two 

publications (i.e., RTI, 2002; Lucas, 2007). These emission factors typically provide emission estimates 

within a factor of 2 of tank-specific modeling approach, but will be less accurate if most of the tanks are 

internal floating roof tanks and/or external floating roof tanks with domed covers. 

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

CAS

Number Chemical Name

Emissions Factors for Petroleum Liquid Storage Tanks 

(lb/MMbbl)

Crude Oil

Gasoline 

and Other 

Light 

Distillates

Diesel Fuel 

and Other 

Middle 

Distillates

Asphalt, 

Lube Oils, 

and Heavy

Distillates Aromatics

71432 Benzene 10. 70. 54 40 a

108883 Toluene 7.5 180 100 29 a

1330207 Xylene 6.2 140 70 26 a

100414 Ethylbenzene 1.6 31 18 5.3

100425 Styrene 0 66 0

98828 Cumene 0.5 15 10 0.4

95636 1,2,4-Trimethyl benzene 0.7 0 0 5.9

(continued)

 

2 The TANKS program includes an algorithm for calculating emissions from heated tanks, but it is only applicable to 

tanks with horizontal or vertical fixed roofs. 
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3-4 

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

CAS

Number Chemical Name

Emissions Factors for Petroleum Liquid Storage Tanks 

(lb/MMbbl)

Crude Oil

Gasoline 

and Other 

Light 

Distillates

Diesel Fuel 

and Other 

Middle 

Distillates

Asphalt, 

Lube Oils, 

and Heavy

Distillates Aromatics

1634044 Methyl tertiary-butyl ether 0 310 0 0

106990 1,3 Butadiene 0 1.8 0 0

110543 Hexane 84 420 480 13

540841 2,2,4-Trimethylpentane 3.4 140 22 0

78933 Methyl ethyl ketone 0.3 0.33 0

108101 Methyl isobutyl ketone 320 320 0

67561 Methanol 3.8 3.8 0

108952 Phenol 0.9 0.9 0.67 0

1319773 Cresol 0.6 13 0.19 0

91203 Naphthalene 0.6 7.6 4 5.77

91576 2-Methyl naphthalene 3.5 3.5 0

92524 Biphenyl 0.2 0.17 0 0.7

POM Polycyclic organic matter/

polynuclear aromatics/PAH

0 0 17

120127 Anthracene 0.24 0.24 0

218019 Chrysene 0.21 0.21 0

86737 Fluorene 0.36 0.36 0

85018 Phenanthrene 1.5 1.5 0

129000 Pyrene 0.39 0.39 0

Sum VOC 1,350 8,800 5,300 120 15,000

Note: lb/MMbbl = pounds per million barrels

a Use ―Sum VOC‖ emissions factor and apply it to the production of each aromatic produced.

When facility-specific production data are available, these data should be used with the default emissions 

factors to estimate emissions. When these data are not available, crude distillation capacity and 

production capacities, as presented in the Refinery Capacity Report 2009 (EIA, 2009), can be used to 

estimate these production rates as follows: 

 The crude oil processing rate can be assumed to be the atmospheric crude oil distillation capacity. 

If a refinery does not have atmospheric crude distillation columns, then the sum of the vacuum 

distillation and coking capacities can be used as the crude oil processing rate. 

 The aromatics production capacity is provided in the Refinery Capacity Report 2009 (EIA, 2009); 

however, the specific aromatics produced cannot be determined. As a default assumption, equal 

production of benzene, toluene, and xylenes can be assumed. 

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

production, and coke production. 

 Light distillate production can be estimated as 60% of the difference of the crude oil processing 

rate minus the aromatics and heavy distillate production (0.6 × [Crude − Aromatics − Heavy]).

 Middle distillate production can be estimated as 40% of the difference of the crude oil processing 

rate minus the aromatics and heavy distillate production (0.4 × [Crude − Aromatics − Heavy]).
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4-1 

4. Stationary Combustion Sources 

Petroleum refineries include numerous stationary combustion sources, the most common of which are: 

process heaters, boilers, internal combustion engines (including turbines), and coke gasification units. 

These combustion sources are vent (point) sources that occur throughout the process area of the refinery. 

The size of the vent stack varies with the size of the source (typically measured in terms of the rate that 

fuel is burned). Process heaters are used to indirectly preheat feedstock or process fluids for a given 

process or to heat distillation columns (the latter are often termed ―reboilers‖). These emissions sources 

are typically localized at or near the process requiring the heater (or reboiler). Boilers are used to generate 

steam for various refinery operations and to raise the temperature of feedstocks and process streams. 

Nearly all petroleum refinery process heaters and boilers combust refinery fuel gas, which is a mixture of 

uncondensable overhead gases from distillation columns (also referred to as ―still gas‖) and natural gas, as 

the primary fuel, but other fuels (e.g., natural gas only, fuel oil, or residual oil) can also be used. Internal 

combustion engines have a variety of uses, including cogeneration, powering fire suppression systems, 

and supplying emergency back-up power. Internal combustion engines generally combust natural gas, 

gasoline, or diesel fuel oil. 

In addition to refinery fuel gas, some petroleum refineries also produce petroleum coke. The petroleum 

coke produced by a coking unit is generally referred to as green petroleum coke. Some refineries may use 

green petroleum coke (also referred to as fuel grade coke) as fuel in boilers to produce steam or 

electricity. Green petroleum coke is expected to contain relatively high concentrations of sulfur and 

metals when compared with other fuels used at a refinery. Green petroleum coke may be purified in a 

calcining unit for use in industrial applications, most often as anode material in the manufacture of 

aluminum. Consequently, calcined petroleum coke is often referred to as anode grade coke. Emissions 

from coke calcining are described in more detail in Section 5.6.3, Coke Calcining, of this Refinery 

Emissions Protocol document. Alternatively, green petroleum coke may be gasified with steam and either 

air or oxygen (O2) to form a low (using air) to medium (using O2) heating value synthesis gas (or syngas) 

for subsequent use as a fuel gas. There are no direct emissions from the coke gasification process; 

emissions from the combustion of syngas can be estimated using the methods provided in this section. 

Table 4-1 summarizes the hierarchy of emissions estimation methods for stationary combustion sources. 

Each refinery may use a combination of different methods, such as Methodology Rank 1 for criteria 

pollutants such as sulfur dioxide (SO2) and NOx, and Methodology Rank 2 or 3 to estimate emissions of 

organic or metal compounds. It is also important to note that the selection of Methodology Rank 3A or 

Methodology Rank 3B will depend on factors such as whether the pollutant being estimated has a reduced 

form (e.g., reduced sulfur compounds form SO2 when oxidized) that can be continuously monitored, the 

variability of the combustion source, and the date of the most recent stack test. The remainder of this 

section provides additional detail and guidance regarding the implementation of these methods. 

A complete inventory for combustion sources will include emissions estimates for PM, SO2, NOx, VOC,3

carbon monoxide (CO), and CO2. Depending on the fuel combusted, a complete inventory will also 

include emissions estimates for hydrogen sulfide; metals, including but not limited to arsenic, chromium, 

mercury, lead, and selenium; organic compounds, including but not limited to benzene, formaldehyde, 

1,3-butadiene, and naphthalene and other polycyclic organic matter; and dioxins and furans. It is 

important to note that this list is not exhaustive; if there is evidence that a combustion source at a refinery 

emits a pollutant, an emissions estimate should be included in a complete inventory, even if that pollutant 

is not specifically identified in this document. 

 

3

 Total hydrocarbon [THC] may be estimated as a surrogate for VOC. 
Version 1.0 Section 4—Stationary Combustion Sources 

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4-2 

Table 4-1. Summary of Typical Hierarchy of Stationary Combustion Source Emissions Estimates 

Rank Measurement Method Additional Data Needed

1 Direct 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 emissions factors)

3A Fuel analysis/mass balance  Fuel usage

 Assumed destruction efficiency

3B Source-specific stack testing to calculate sourcespecific emissions correlations or factors

 Fuel usage

 Heat content of fuel (depending on units of 

source-specific emissions factors) 

4 Default emissions factors  Fuel use records

There are many sources that describe emissions methodologies for combustion sources, particularly 

boilers and internal combustion sources, including Chapter 2 in the Emission Inventory Improvement 

Program Technical Report Series (ERG, 2001), 2008 Emissions Inventory Guidelines (TCEQ, 2009), and 

A Customized Approach for Quantifying Emissions for the Electric Power Generation Sector in Mexico

(The United States–Mexico Foundation for Science, 2008). These documents include many examples and 

sample calculations for liquid and solid fuels and should be consulted for more information if needed. 

4.1 Methodology Rank 1 for Stationary Combustion Sources 

Many stationary combustion sources will have a continuous emission monitoring system (CEMS) for 

NOx and/or SO2. A CEMS is a comprehensive unit that continually determines gas or PM concentrations 

or emissions rates using pollutant analyzer measurements and a conversion equation, graph, or computer 

program to produce results in the desired units. A CEMS that includes a flow rate monitor, which is 

needed to determine mass emissions rates, such as those needed for an emissions inventory, is also 

referred to as a continuous emission rate monitoring system (CERMS). The CEMS or CERMS 

continually determines the flow rate of the exhaust gas, analyzes the composition or specific pollutant 

concentration in the exhaust gas, and records the results. There are two main types of CEMS: in-situ and 

extractive. An in-situ CEMS measures and analyzes the emissions directly in a stack. There is less sample 

loss associated with the in-situ CEMS compared to the extractive CEMS because the sample lines of an 

extractive system can leak, freeze, or clog, or pollutants can be lost because of adsorption, scrubbing 

effects, or condensation. In an extractive CEMS, the sample gas is extracted from the gas stream and 

transported to a gas analyzer for the measurement of the contaminant concentration. Because an 

extractive CEMS is located outside the stack, the sampling instruments are not affected by stack 

conditions, maintenance and replacement are generally simpler, and the cost is lower than with an in-situ 

CEMS, although extra costs are incurred for the sampling and conditioning system for an extractive 

CEMS (Levelton Consultants, 2005). 

The pollutant concentration recorded by a CEMS is generally on a concentration basis, such as parts per 

million. The CEMS may also include a diluent monitor (e.g., O2) for correcting the concentrations to a 

fixed excess air concentration. For in-situ CEMS, these measurements are made at stack conditions so 

that the concentrations would be determined on a ―wet basis.‖ That is, the concentrations are based on the 

total amount of gas, including water vapor. For extractive CEMS, the gas is often conditioned to remove 

water vapor before analysis, so the concentrations are commonly determined on a ―dry basis.‖ Gas flow 

measurements are made at stack conditions, so the flow rate will be in terms of actual gas volume on a 

wet basis. If the gas composition is determined on a dry basis, then a moisture content measurement is 
Version 1.0 Section 4—Stationary Combustion Sources 

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4-3 

needed to convert the flow rate to a dry basis (or convert the composition to a wet basis) so that both 

measurements are on the same basis, and many gas flow monitors contain temperature and pressure 

monitors to allow conversion of the flow to standard conditions for this purpose. It is important to note 

that care must be taken to ensure that the gas and flow measurements are made on the same basis and in 

the same terms as the permitted limits, if applicable, or that appropriate ancillary measurements are made 

to perform the necessary unit conversions. 

The following general equation (Equation 4-1) is used for determining a mass emissions rate from CEMS: 

     

 

100%

1

1

 20



















  































     

N

n

N

o

n

n

i n i o

i n H n

 M K

P

P

T

T

MVC

C M W

E Q f

 (Eq. 4-1) 

where: 

 Ei = Emissions rate of pollutant ―i‖ (tons per year [tons/yr]).

 N = Number of measurement periods per year (e.g., for hourly measurements, N = 8,760). 

 n = Index for measurement period. 

 (Q)n = Volumetric flow rate for measurement period ―n‖ (actual cubic feet per minute [acfm]).

If the flow rate meter automatically corrects for temperature and pressure, then replace 

―To ÷ Tn × Pn ÷ Po‖ with ―1.‖ If the pollutant concentration is determined on a dry basis 

and the flow rate meter automatically corrects for moisture content, replace the term 

[1-(fH20)n] with 1. 

(fH2O)n = Moisture content of exhaust gas during measurement period ―n,‖ volumetric basis 

(cubic feet water per cubic feet exhaust gas). 

(Ci)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−(fH20)n] with 1. 

MWi = 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). 

 To = Temperature at ―standard conditions‖ (528 °R).

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

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

 Po = Average pressure at ―standard conditions‖ (1 atm). 

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

be calculated by dividing 525,600 minutes per year (min/yr) by the number of 

measurement periods per year (―N‖).

 K = Conversion factor = 2.2046/2,000 (tons per kilogram [tons/kg] = 0.0011023 tons/kg. 

A CEMS records multiple measurements per hour; the frequency depends on the pollutant being 

measured and the type of CEMS. For example, a CEMS monitoring benzene concentration using gas 

chromatography may only sample and record a measurement every 15 minutes, while a CEMS 

monitoring SO2 concentration may record a measurement every minute. These individual measurements 

can be used to calculate annual emissions in two ways. The most common method is for the CEMS to 

average the measurements within each hour and develop 8,760 hourly average concentrations and flow 

rates that can be summed. Example 4-1 demonstrates the calculation of NOx emissions for 1 hour for a 

combustion unit firing refinery fuel gas based on an hourly average concentration and flow rate. This 

method is best suited for measurements that are fairly consistent and stable over the course of an hour. 

The other method is to determine the emissions rate for each recorded measurement based on the 

concentration and flow rate for that measurement. In other words, if the CEMS records measurements 

every minute, then the emissions rate is determined per minute and hourly emissions are determined by 

summing the 60 applicable emissions rates; if the CEMS records measurements every 5 minutes, then the 
Version 1.0 Section 4—Stationary Combustion Sources 

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4-4 

emissions rate is determined for each 5-minute interval and hourly emissions are determined by summing 

the 12 applicable emissions rates. This method may be more accurate than hourly averages if the 

combustion source’s flow rate varies significantly within an hour. 

4.2 Methodology Rank 2 for Stationary Combustion Sources 

Because the emissions standards for stationary combustion sources are often provided on a concentration 

basis or on a mass per heating–value basis, many stationary combustion sources will have a CEMS for 

pollutant concentrations, but may not directly measure exhaust gas flow. In these cases, fairly accurate 

exhaust gas flow rates can be calculated from the refinery fuel gas composition and fuel flow 

measurements. This method is commonly referred to as the ―F factor‖ method, and procedures for 

conducting a fuel analysis and calculating estimated emissions are described in EPA Method 19 (40 CFR 

Part 60, Appendix A-7). 

EPA Method 19 includes many equations that can be used to calculate emissions depending on moisture 

measurements and whether pollutant concentrations and O2 or CO2 content are measured on a wet or dry 

basis, and each equation uses one of three different types of F factors. The calculation of the different F 

factors is described in Section 12.3.2 of Method 19. In lieu of this calculation, Table 19-2 of EPA Method 

Example 4-1: Calculation of NOx Emissions Using a CEMS

The following example shows the calculation for 1 hour (60 minutes); the total emissions 

during any period (i.e., day, month, quarter, or year) may be calculated as the sum of the 

hourly emissions determined by the CEMS. In terms of Equation 4-1, ―i‖ is NOx and the index 

for the period in this example is 1, so the result ―E‖ is in tons per hour.

Calculate hourly NOX 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 NOx concentration calculated by the CEMS for this hour is 60 parts 

per million (ppm), 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:

     

 

 M K

P

P

T

T

MVC

C M W

E Q f

N

n

N

o

n

n

NOx n NOx o

NOx  n H n



















        

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 

emissions 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. 
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-5 

19 includes default F factors for some fuel common types that could be used; however, F factors for 

refinery fuel gas are not included in Table 19-2. 

Refinery fuel gas generally includes many different components; therefore, one equation that can be used 

to calculate the F factor in this situation is an adapted version of Equation 19-16 in EPA Method 19 for 

multiple fuels. In Equation 4-2, the dry F factor, Fd, is calculated assuming both the pollutant 

concentration and the O2 content are measured on a dry basis: 

 

 



























 









n

i

i i

n

i

i i

d

X MHC

X MEV

F K

1

1

(Eq. 4-2) 

where: 

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

per million British thermal unit [dscf/MMBtu]) 

 K = Conversion factor, 106 (Btu/MMBtu) 

 n = Number of fuels or fuel components 

i = Index for fuels or fuel components 

 Xi = Mole or volume fraction of each component in the refinery fuel gas 

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

 MHCi = Molar heat content (British thermal units per mole [Btu/mol]) 

Table 4-2 includes values for the molar exhaust volume and molar heat content for common 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 MEVa(dscf/mol) MHCb(Btu/mol)

Methane (CH4) 7.28 842

Ethane (C2H6) 12.94 1,475

Hydrogen (H2) 1.61 269

Ethene (C2H4) 11.34 1,335

Propane (C3H8) 18.61 2,100

Propene (C3H6) 17.01 1,947

Butane (C4H10) 24.28 2,717

Butene (C4H8) 22.67 2,558

Inerts 0.85 0

a MEV = molar exhaust volume (dry standard cubic feet per mole [dscf/mol])

b MHC = molar heat content (Btu per mole [Btu/mol]); higher heating value basis

The F factor can be used to calculate emissions in one of two ways. In the first option, the F factor, the 

amount of fuel combusted, and the heat content of the fuel can be used to calculate the volumetric flow 

rate of the exhaust gas, (Q)n, using the following equation. 
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-6 

(20.9 % )

20.9

2d

n d f

O

Q F Q HHV



   

(Eq. 4-3) 

where: 

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

[dscfm]) 

 Fd = Volume of combustion components per unit of heat content (dscf/MMBtu) 

 Qf = Volumetric flow rate of fuel (dscfm) 

HHV = Higher heating value of fuel (million British thermal units per standard cubic foot 

[MMBtu/scf]) 

%O2d = Concentration of O2 on a dry basis (percent) 

Once the volumetric flow rate is known, emissions can be calculated using Equation 4-1 as in 

Methodology Rank 1 for stationary combustion sources. It is important to note that when using the F 

factor method as indicated here, the exhaust gas flow rate will be in units of dry standard cubic feet per 

minute, so the temperature and pressure correction terms are not needed. A moisture correction term is 

not needed when the concentration measurement is also made on a dry basis. If the concentration 

measurements are made on a wet basis, then they must be corrected to a dry basis by dividing by the 

[1−(fH20)n] term. 

In the second option, the F factor can be used to calculate an emissions factor (Equation 4-4) that can then 

be multiplied by the higher heating value of the fuel to estimate emissions (Equation 4-5). 

(20.9 % )

20.9

2d

i d d O

EF C F





(Eq. 4-4) 

where: 

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

 Cd = Pollutant concentration, dry basis (pounds per standard cubic foot [lb/dscf]) 

 Fd = Volume of combustion components per unit of heat content (dscf/MMBtu) 

%O2d = Concentration of O2 on a dry basis (percent) 

Ei EFi 60 Qf

 HHV

(Eq. 4-5) 

where: 

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

EFi = Emissions rate of pollutant (lb/MMBtu) 

 Qf = 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 emissions estimate, then 

the calculation process should be repeated for each hour in the year, or 8,760 times. For example, the 

hourly pollutant and O2 concentrations from the CEMS should be used in Equation 4-4 to calculate an 

emissions factor for each hour in the year. That emissions factor and the hourly measurements of the fuel 

flow rate should then be used in Equation 4-5 to determine the hourly emissions for each hour in the year. 

The sum of all of those hourly emissions estimates is the annual emissions estimate. 
Version 1.0 Section 4—Stationary Combustion Sources 

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4-7 

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

From Example 4-2, the F factor is 8,809 dscf/MMBtu. The measured SO2 concentration is 20 

ppmv (dry basis), the measured O2 concentration is 6% (dry basis), the higher heating value is 

1,300 Btu/scf, and the fuel flow rate is 500 dscfm. Equation 4-3 should be used to calculate 

the exhaust flow rate from F factor as follows:

(20.9 % )

20.9

2d

n d f

O

Q F Q HHV



   

Qn = (8,809) × (500) × (1,300 ÷ 106[Btu/MMBtu]) × (20.9 ÷ (20.9 – 6))

Qn = 8,031 dscfm

Use this value of Qn in Equation 4-1 without the temperature, pressure, and moisture 

correction terms to estimate hourly emissions as follows:

     

 

 M K

MVC

M W

%

C

E Q f N

i n i

SO n H n

      

100 2

1 20

ESO2= 8,031 × 1 × (20 ÷ 1,000,000) × 64.06 ÷ 849.5 × 60 × 2.2046 = 1.6 lb/hr

Example 4-2: Calculation of Fuel-Specific F Factor

The CEMS measures SO2 and O2 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 Fd factor 

(scf/MMBtu). The Fd 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 Fd as follows: 

         

       

         

       ]

[

]

[

3 6 3 6 4 1 0 4 1 0 4 8 4 8

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

3 6 3 6 4 1 0 4 1 0 4 8 4 8

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

C H C H C H C H C H C H inerts inerts

CH CH C H C H H H C H C H C H C H

C H C H C H C H C H C H inerts inerts

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

X 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

F K X MEV X MEV X MEV X MEV X MEV

      

         

       

           

Fd = 106× [(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)]

= 106× 12.55 ÷ 1425

= 8,809 dscf/MMBtu 
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-8 

4.3 Methodology Rank 3A for Stationary Combustion Sources 

Fuel analysis can be used to predict emissions of pollutants such as SO2 by examining the compounds in 

the fuel being combusted. Given a known concentration of a compound, either a pollutant or pollutant 

precursor (e.g., hydrogen sulfide [H2S] or other reduced sulfur compounds for purposes of estimating SO2

emissions), emissions of the pollutant can be calculated by assuming that all of that compound is emitted 

(e.g., all of the reduced sulfur is oxidized to SO2). Alternatively, if some of the compound is not 

combusted (i.e., is in a different physical or chemical state such as ash or unburned hydrocarbons), then 

based on the laws of mass conservation, less than 100% of the pollutant is emitted as air emissions (ERG, 

2001). In this case, it may be possible to determine the emissions actually resulting from combustion by 

considering the uncombusted compounds in a mass balance analysis. 

As mentioned in the introduction to Section 4, Methodology Rank 3A for stationary combustion sources 

is considered a more accurate method of emissions estimation than Methodology Rank 3B for stationary 

combustion sources for certain pollutants, namely SO2, 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 emissions factor developed at one set of operating 

conditions. For example, a test of NOx emissions from a process heater performed at high capacity may 

Example 4-4: Calculation of Emissions Factor from F Factor

Given the same measurements as Example 4-3, calculate hourly SO2 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 SO2 concentration in ppm by 1.660 × 10-7

to convert to lb/scf [see also Equation 4-7 of this section]):

Cd = 20 ppm × (1.660 × 10-7) lb/scf/ppm

Cd = 3.322 × 10-6lb/scf

Second, Equation 4-4 should be used to calculate the emissions factor:

(20.9 % )

20.9

2

2

d

SO d d O

EF C F





EFSO2= (3.322 × 10-6) × (8,809) × (20.9 ÷ (20.9 – 6))

EFSO2= 0.041 lb/MMBtu

Finally, Equation 4-5 should be used to calculate the hourly emissions (the fuel flow rate is 

500 dscfm, or 30,000 dscf/hr [500 dscfm × 60 minutes per hour (min/hr)])

ESO  EFSO Qf HHV

2 2

ESO2= (0.041) × (30,000) × (1,300 ÷ 106[Btu/MMBtu])

ESO2= 1.6 lb/hr

If the combustion source operated steadily and continuously for an entire year and the 

emissions rate remained perfectly constant over that year, then the annual emissions would be 

1.6 lb/hr × 8,760 hr/yr ÷ 2,000 lb/ton = 7.0 tons/yr.
Version 1.0 Section 4—Stationary Combustion Sources 

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4-9 

not apply when the process heater is firing at a lower rate. As the heater firing rate decreases, the operator 

increases the oxygen content to ensure stable operation, and this increase in oxygen content leads to 

higher concentrations of NOx. 

Equation 4-6 is a general equation used to determine a mass emissions estimate from fuel analysis data 

for gaseous fuels (for fuel analysis of liquid and solid fuels, see the documents referenced in the 

introduction to Section 4). 

  



















f

i

i f f MW

MW E Q C

(Eq. 4-6) 

where (assuming gaseous fuel): 

 Ei = Emissions estimate of pollutant ―i‖ (lb/hr) 

 Qf = Fuel flow rate (scf/hr) 

 Cf = Content of pollutant in fuel (lb/scf) 

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

MWf = Molecular weight of pollutant in the fuel (lb/lb-mol) 

As previously explained, to calculate yearly emissions, this type of calculation must be repeated for each 

hour in the year, or 8,760 times. Also, as described in Example 4-1, if the combustion source did not 

operate for part of an hour, then the emissions estimates for that hour should be multiplied by the fraction 

of the hour that it did operate. 

If the compound concentration is measured in parts per million or as a percentage rather than pounds per 

cubic feet, then Equation 4-7 will be needed. Equation 4-7 provides a methodology for calculating 

compound-specific conversion factors such as the values shown in Table 19-1 of EPA Method 19 for NOx

and SO2. 

   

385.3





K

C MW C

c i

f

(Eq. 4-7) 

where: 

 Cf = Content of pollutant in fuel (lb/scf) 

 Cc = Volumetric concentration of pollutant in fuel (ppm or percentage) 

MWi = Molecular weight of pollutant ―i‖ emitted (lb/lb-mole) 

 K = Conversion constant: 106 if units of Cc are ppm; 102 if units of Cc are a percentage 

 385.3 = Conversion constant for ideal gases (standard cubic feet per pound mole [scf/lb-mol]) 
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-10 

4.4 Methodology Rank 3B for Stationary Combustion Sources 

Source testing can provide useful data for developing site-specific emissions correlations or emissions 

factors. Source testing provides a measurement of the emissions at a particular point in time, and most 

tests are performed at conditions representative of normal operation, in which case the emissions 

measurement can provide an estimate of emissions at similar operating conditions. Emissions factors are 

developed by dividing the emissions rate by a process parameter such as fuel usage. It is important to note 

that this methodology will be less reliable when the unit is operating at conditions other than those tested. 

Generally, one source test consisting of three runs is performed at a specific set of conditions, and the 

results for each run can be averaged to determine an emissions factor that is assumed to apply at all heat 

input rates. Example 4-5 demonstrates a sample emissions factor calculation based on one test with three 

test runs. Section 5.1.2 of this document, Methodology Ranks 3 and 4 for Catalytic Cracking Units, also 

provides details on calculating one emissions factor based on three test runs. That section also includes a 

detailed description of the ways in which source tests and analyses for PM may need to be handled 

differently than other pollutants. 

Example 4-5: Fuel Analysis

Calculate hourly emissions from a combustion source burning refinery fuel gas given:

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

– Sulfur content of the fuel = 160 ppm

– Molecular weight of sulfur = 32 lb/lb-mole; molecular weight of SO2 = 64 lb/lb-mole

Convert the concentration of sulfur in the fuel to the correct units using Equation 4-7:

   

385.3





K

C MW C

c S

f

Cf = (160) × (32) ÷ (106) ÷ (385.3)

Cf = 1.33 × 10-5lb/scf

Then, use Equation 4-6 to calculate the hourly mass emissions:

  



















S

SO

SO f f MW

MW

E Q C

2

2

ESO2= (30,000) × (1.33 × 10-5) × (64) ÷ (32)

ESO2= 0.80 lbs SO2/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 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-11 

A more complex methodology for developing a correlation rather than one emissions factor is provided in 

Section 2.1.2 of A Customized Approach for Quantifying Emissions for the Electric Power Generation 

Sector in Mexico (The United States–Mexico Foundation for Science, 2008). Section 2.1.2 provides a 

detailed explanation of a methodology for developing a correlation between NOx emissions and heat input 

to the source (fuel use multiplied by heat content of fuel) that is based on EPA’s Optional NOx Emissions 

Estimation Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units (40 CFR Part 75, Appendix 

E). This methodology allows the operator to account for lower mass emissions per heat input for lower 

operating loads. The methodology calls for stack measurements at three load levels, ideally 50%, 75%, 

and 100% firing rates. The test results at each firing rate are used to calculate an emissions factor in units 

of mass per heat input (or mass per amount of fuel combusted, assuming a constant heat content of fuel). 

Following the development of this correlation, hourly emissions can be calculated based on hourly 

measurements of fuel combusted and calculations of the heat content of the fuel (or constant heating value 

of the fuel). Section 2.1.2 also includes a detailed set of sample calculations in Exhibit 2.1-3 to 

demonstrate this procedure. 

4.5 Methodology Rank 4 for Stationary Combustion Sources 

When direct emissions monitoring or site-specific emissions factors are not available, then default 

emissions factors may be the only way to estimate emissions. The EPA has developed emissions factors 

for various types of combustion sources, which are compiled in AP-42. Emissions factors for process 

heaters, boilers, and other types of external combustion sources are included Chapter 1 of the Compilation 

of Air Pollutant Emission Factors. Volume 1: Stationary Point and Area Sources, and emissions factors 

for internal combustion sources are presented in Chapter 3 of this same document (U.S. EPA, 1995a). It is 

important to note that AP-42 does not include emissions factors for all fuels (notably refinery fuel gas and 

coke). The emissions factors in AP-42 are the recommended default emission factors, and AP-42 should 

be consulted to obtain the appropriate emissions factors for criteria pollutants such as SO2, NOx, PM, and 

CO.

In addition, the American Petroleum Institute (API), in conjunction with the Western States Petroleum 

Association (WSPA), has conducted emissions source tests of combustion sources and has compiled 

emissions factors that may be used for refinery combustion sources if AP-42 does not include an 

applicable emissions factor (Hansell and England, 1998). Separate emissions factors were developed for 

different combustion sources based on the type of source and fuel used. Appendix D presents the full data 

Example 4-6: Site-Specific Emissions Factor

During the most recent source test, three test runs were conducted to determine the NOx

emission rate for a 50 MMBtu/hr process heater. The NOx emissions rate measured during the 

source tests were 1.92, 1.51, and 1.76 lbs/hr for tests 1, 2, and 3, respectively. The process 

heater was firing at 95% capacity during all three test runs.

First, calculate the appropriate emissions factor for each individual run, and then average the 

emissions factors with the following calculations:

– Run 1: Emissions/throughput = 1.92 [lbs/hr] ÷ (50 × 0.95) [MMBtu/hr] = 0.040 lbs 

NOx/MMBtu

– Run 2: Emissions/throughput = 1.51 [lbs/hr] ÷ (50 × 0.95) [MMBtu/hr] = 0.032 lbs

NOx/MMBtu

– Run 3: Emissions/throughput = 1.76 [lbs/hr] ÷ (50 × 0.95) [MMBtu/hr] = 0.037 lbs

NOx/MMBtu

– Average: Emissions/throughput = (0.040 + 0.032 + 0.037) ÷ 3 = 0.036 lbs NOx/MMBtu
Version 1.0 Section 4—Stationary Combustion Sources 

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4-12 

analysis summary for combustion sources of interest as presented in Hansell and England’s Appendices A 

and B (1998), including the California Air Resources Board (CARB) emissions factor rating; the mean, 

median, maximum, and minimum emission factors; number of tests analyzed; standard deviation; 

uncertainty; and percent of test run results at or above the detection limit. 

The following tables present the recommended emissions factors for a variety of metals and organic 

compounds. The emissions factors in these tables are either the applicable emissions factors as presented 

in AP-42 or the mean emissions factors compiled by Hansell and England (1998). (Additional details on 

the rating and quality of these emissions factors are located in the original document for AP-42 emissions 

factors and in Appendix D for the emissions factors compiled by Hansell and England (1998).) Emissions 

factors for process heaters using various fuels are presented in Table 4-3. Emissions factors for boilers 

using fuel oil and refinery fuel gas are presented in Table 4-4. Emissions factors for reciprocating internal 

combustion engines using a variety of fuels are presented in Tables 4-5 and 4-6. Emissions factors for 

turbines using a variety of gaseous fuels are presented in Tables 4-7 and 4-8. 

To use any of these emissions factors appropriately, the refinery must monitor or keep records of the 

amount of fuel combusted (for the emissions factors with volumetric flow rates in the denominator) or the 

heat input (for emissions factors with heating values in the denominator). 

It is important to note that the bold italic emissions factor values in Tables 4-3 through 4-8 from Hansell 

and England (1998) are based on method detection limits and are likely biased high. For example, the 

hexavalent chromium (Cr+6) emissions factor for process heaters combusting refinery fuel gas, which is 

based on non-detect values, is higher than the emissions factor for total chromium. Therefore, additional 

data are needed to develop accurate emissions factors for the compounds that were below the detection 

limits for this particular test (RTI, 2002). The footnotes to Tables 4-3 through 4-6 explain any 

differences if a recommended emissions factor is derived from another emissions factor. 

It is also important to note that this document does not include emissions factors for refinery combustion 

sources combusting either green or calcined petroleum coke. In addition, while emissions from the 

combustion of syngas (gas produced by coke gasification) can be estimated using the methods provided in 

this section, this document does not include emissions factors for syngas as a fuel. Emissions factors for 

these fuels will need to be developed from future emissions testing and analysis. 
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-13 

4.5.1 Default Emissions Factors for Process Heaters 

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

CAS Number Substance

Emissions Factor for Fuel Typea,b

Natural Gas 

(lb/MMcf)

Natural Gas 

(lb/MMBtu)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMcf)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMBtu)

Oil 

(lb/Mgal)

Oil 

(lb/MMBtu)

Refinery 

Fuel Gas 

(lb/MMcf)c

Refinery 

Fuel Gas 

(lb/MMBtu)c

83-32-9 Acenaphthene 1.4E-06 1.4E-09 7.5E-06 4.1E-09 1.8E-06 1.2E-08 2.3E-06 2.4E-09

208-96-8 Acenaphthylene 1.2E-05 1.2E-08 5.9E-05 3.2E-08 8.0E-08 5.6E-10 1.5E-06 1.6E-09

75-07-0 Acetaldehyde 4.6E-03 4.5E-06 1.5E-02 7.0E-06 5.4E-04 3.8E-06 2.0E-02 1.5E-05

107-02-8 Acrolein 4.5E-03 4.4E-06 2.3E-03 1.1E-06 6.0E-04 4.2E-06 -- --

120-12-7 Anthracene 1.6E-06 1.6E-09 1.0E-05 5.6E-09 6.6E-08 4.6E-10 2.8E-06 2.9E-09

7440-36-0 Antimony -- -- -- -- -- -- 5.8E-04 5.2E-07

7440-38-2 Arsenic -- -- -- -- 8.3E-04 5.8E-06 9.5E-04 8.5E-07

7440-39-3 Barium -- -- -- -- -- -- 6.5E-03 5.8E-06

71-43-2 Benzene 2.3E-03 2.3E-06 2.1E-02 1.0E-05 8.5E-03 5.9E-05 8.4E-02 6.5E-05

56-55-3 Benzo(a)anthracene 1.4E-06 1.4E-09 9.6E-06 5.2E-09 3.8E-06 2.7E-08 3.7E-05 3.2E-08

50-32-8 Benzo(a)pyrene 1.1E-06 1.1E-09 6.1E-06 3.2E-09 9.8E-08 6.8E-10 9.9E-05 9.0E-08

205-99-2 Benzo(b)fluoranthene 1.1E-06 1.1E-09 2.6E-06 1.4E-09 8.0E-07 5.6E-09 4.6E-05 4.0E-08

192-97-2 Benzo(e)pyrene -- -- -- -- 5.5E-07 3.9E-09 -- --

191-24-2 Benzo(g,h,i)perylene 1.3E-06 1.2E-09 4.1E-07 2.2E-10 2.1E-06 1.5E-08 1.2E-06 1.2E-09

207-08-9 Benzo(k)fluoranthene 1.1E-06 1.1E-09 1.5E-06 7.6E-10 3.4E-08 2.4E-10 2.7E-05 2.4E-08

7440-41-7 Beryllium -- -- -- -- 7.8E-05 5.4E-07 2.9E-04 2.6E-07

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-14 

Table 4-3. Summary of Emissions Factors for Process Heaters Firing Various Fuels (continued)

CAS Number Substance

Emissions Factor for Fuel Typea,b

Natural Gas 

(lb/MMcf)

Natural Gas 

(lb/MMBtu)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMcf)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMBtu)

Oil 

(lb/Mgal)

Oil 

(lb/MMBtu)

Refinery 

Fuel Gas 

(lb/MMcf)c

Refinery 

Fuel Gas 

(lb/MMBtu)c

106-99-0 1,3-Butadiene -- -- -- -- 2.0E-02 1.4E-04 -- --

7440-43-9 Cadmium -- -- -- -- 8.2E-04 5.7E-06 1.1E-03 9.9E-07

67-66-3 Chloroform -- -- -- -- 8.6E-03 6.0E-05 -- --

91-58-7 2-Chloronaphthalene -- -- -- -- 1.2E-05 8.2E-08 -- --

18540-29-9 Chromium (hexavalent) -- -- -- -- 2.9E-04 2.0E-06 2.4E-04d2.2E-07d

7440-47-3 Chromium (total) -- -- -- -- 2.5E-03 1.8E-05 1.2E-03 1.1E-06

218-01-9 Chrysene 1.4E-06 1.4E-09 7.9E-07 4.3E-10 1.1E-05 7.8E-08 1.7E-06 1.6E-09

7440-50-8 Copper -- -- -- -- 2.6E-03 1.8E-05 4.7E-03 4.2E-06

53-70-3 Dibenz(a,h)anthracene 1.1E-06 1.1E-09 1.4E-07 7.5E-10 1.8E-06 1.2E-08 1.1E-05 1.0E-08

1746-01-6 Dioxin: 4D 2378e-- -- -- -- 5.0E-10 3.5E-12 -- --

40321-76-4 Dioxin: 5D 12378e-- -- -- -- 2.5E-09 1.7E-11 -- --

39227-28-6 Dioxin: 6D 123478e-- -- -- -- 2.2E-09 1.5E-11 -- --

57653-85-7 Dioxin: 6D 123678e-- -- -- -- 3.0E-09 2.1E-11 -- --

19408-74-3 Dioxin: 6D 123789e-- -- -- -- 4.8E-09 3.3E-11 -- --

35822-46-9 Dioxin: 7D 1234678e-- -- -- -- 1.3E-08 9.3E-11 -- --

3268-87-9 Dioxin: 8De-- -- -- -- 4.7E-08 3.3E-10 -- --

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-15 

Table 4-3. Summary of Emissions Factors for Process Heaters Firing Various Fuels (continued)

CAS Number Substance

Emissions Factor for Fuel Typea,b

Natural Gas 

(lb/MMcf)

Natural Gas 

(lb/MMBtu)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMcf)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMBtu)

Oil 

(lb/Mgal)

Oil 

(lb/MMBtu)

Refinery 

Fuel Gas 

(lb/MMcf)c

Refinery 

Fuel Gas 

(lb/MMBtu)c

100-41-4 Ethylbenzene 2.3E-03 2.2E-06 -- -- -- -- 3.0E-02 3.0E-05

206-44-0 Fluoranthene 1.2E-05 1.2E-08 1.8E-05 9.7E-09 2.0E-06 1.4E-08 3.1E-06 3.1E-09

86-73-7 Fluorene 4.6E-06 4.5E-09 6.5E-04 3.5E-07 7.5E-05 5.2E-07 1.1E-05 1.1E-08

50-00-0 Formaldehyde 4.8E-03 4.6E-06 4.3E-02 2.2E-05 3.8E-03 2.7E-05 1.5E-01 1.1E-04

51207-31-9 Furan: 4F 2378f-- -- -- -- 8.9E-08 6.2E-10 -- --

57117-41-6 Furan: 5F 12378f-- -- -- -- 8.6E-09 6.0E-11 -- --

57117-31-4 Furan: 5F 23478f-- -- -- -- 1.5E-08 1.1E-10 -- --

70648-26-9 Furan: 6F 123478f-- -- -- -- 1.9E-08 1.3E-10 -- --

57117-44-9 Furan: 6F 123678f-- -- -- -- 6.1E-09 4.3E-11 -- --

72918-21-9 Furan: 6F 123789f-- -- -- -- 5.0E-10 3.5E-12 -- --

60851-34-5 Furan: 6F 234678f-- -- -- -- 8.8E-09 6.1E-11 -- --

67562-39-4 Furan: 7F 1234678f-- -- -- -- 2.0E-08 1.4E-10 -- --

55673-89-7 Furan: 7F 1234789f-- -- -- -- 1.2E-09 8.3E-12 -- --

39001-02-0 Furan: 8Ff-- -- -- -- 1.0E-08 7.29E-11 -- --

7783-06-4 Hydrogen sulfide -- -- -- -- -- -- 4.1E-01 2.9E-04

193-39-5 Indeno(1,2,3-cd)pyrene 1.1E-06 1.1E-09 4.6E-07 2.5E-10 1.8E-06 1.3E-08 1.2E-04 1.0E-07

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-16 

Table 4-3. Summary of Emissions Factors for Process Heaters Firing Various Fuels (continued)

CAS Number Substance

Emissions Factor for Fuel Typea,b

Natural Gas 

(lb/MMcf)

Natural Gas 

(lb/MMBtu)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMcf)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMBtu)

Oil 

(lb/Mgal)

Oil 

(lb/MMBtu)

Refinery 

Fuel Gas 

(lb/MMcf)c

Refinery 

Fuel Gas 

(lb/MMBtu)c

7439-92-1 Lead -- -- -- -- 3.0E-04 2.1E-06 5.5E-03 4.9E-06

7439-96-5 Manganese -- -- -- -- 1.9E-03 1.3E-05 7.7E-03 6.8E-06

7439-97-6 Mercury -- -- -- -- 1.7E-05 1.2E-07 2.0E-04 1.8E-07

91-57-6 2-Methylnaphthalene -- -- -- -- 3.6E-05 2.5E-07 -- --

91-20-3 Naphthalene 2.4E-04 2.3E-07 2.3E-03 1.2E-06 8.5E-04 5.9E-06 3.0E-04 3.1E-07

7440-02-0 Nickel -- -- -- -- 3.5E-01 2.4E-03 1.1E-02 9.4E-06

198-55-0 Perylene -- -- -- -- 7.4E-08 5.2E-10 -- --

85-01-8 Phenanthrene 3.4E-05 3.3E-08 2.1E-04 1.1E-07 2.5E-05 1.7E-07 1.4E-05 1.5E-08

108-95-2 Phenol -- -- 1.7E-03 9.2E-07 -- -- 7.0E-03 5.6E-06

7723-14-0 Phosphorus -- -- -- -- -- -- 7.2E-04 6.4E-07

115-07-1 Propylene 4.6E-01 4.5E-04 1.2E-02 5.8E-06 1.5E-02 1.1E-04 2.1E-03 2.2E-06

129-00-0 Pyrene 5.6E-06 5.5E-09 1.3E-05 4.1E-09 1.3E-05 9.2E-09 2.8E-06 2.8E-09

7782-49-2 Selenium -- -- -- -- 4.6E-03 3.2E-05 2.2E-05 2.0E-08

7440-22-4 Silver -- -- -- -- -- -- 1.8E-03 1.6E-06

7440-28-0 Thallium -- -- -- -- -- -- 6.5E-03 5.8E-06

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-17 

Table 4-3. Summary of Emissions Factors for Process Heaters Firing Various Fuels (continued)

CAS Number Substance

Emissions Factor for Fuel Typea,b

Natural Gas 

(lb/MMcf)

Natural Gas 

(lb/MMBtu)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMcf)

Natural Gas 

and 

Refinery 

Fuel Gas 

(lb/MMBtu)

Oil 

(lb/Mgal)

Oil 

(lb/MMBtu)

Refinery 

Fuel Gas 

(lb/MMcf)c

Refinery 

Fuel Gas 

(lb/MMBtu)c

108-88-3 Toluene 3.2E-02 3.2E-05 2.6E-02 1.3E-05 1.0E-02 7.0E-05 1.4E-01 1.1E-04

1330-20-7 Xylene (total) 1.9E-02 1.8E-05 3.0E-02 1.5E-05 1.9E-02 1.3E-04 3.7E-02 3.7E-05

7440-66-6 Zinc -- -- -- -- 8.9E-03 6.2E-05 2.3E-02 2.1E-05

Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds per million cubic feet, lb/MMBtu = pounds per million British thermal units

a

Bold italic values indicate that all test runs were below detection limit; underlined values indicate that more than 75% of the test runs were below the detection 

limit.

b

Source: Hansell and England, 1998.

c

The same mean emissions factors were provided specifically for heaters with no control device, heaters with selective catalytic reduction, and heaters with 

selective non-catalytic reduction.

d Hexavalent chromium was not detected. The Hansell and England emissions factor based on the detection limits was approximately twice the emissions 

factor for total chromium; therefore, the reported emissions factor for hexavalent chromium was not included in this table. Instead, twenty percent of the total 

chromium emissions factor is assumed for the hexavalent chromium emissions factor. (The hexavalent chromium emissions factors for turbines is between 10 

and 15 percent of the total chromium emissions factor, and the hexavalent chromium emissions factor for boilers firing fuel oil is about 30 percent of the total 

chromium emissions factor, so 20 percent is a conservative approximation for hexavalent chromium emissions from refinery fuel gas.)

e

4D 2378 = 2,3,7,8-Tetrachlorodibenzo-p-dioxin; 5D 12378 = 1,2,3,7,8-Pentachlorodibenzo-p-dioxin; 6D 123478 = 1,2,3,4,7,8-Hexachlorodibenzo-p-dioxin; 6D 

123678 = 1,2,3,6,7,8-Hexachlorodibenzo-p-dioxin; 6D 123789 = 1,2,3,7,8,9-Hexachlorodibenzo-p-dioxin; 7D 1234678 = 1,2,3,4,6,7,8-Heptachlorodibenzo-pdioxin; 8D = Octachlorodibenzo-p-dioxin.

f

4F 2378 = 2,3,7,8-Tetrachlorodibenzofuran; 5F 12378 = 1,2,3,7,8-Pentachlorodibenzofuran; 5F 23478 = 2,3,4,7,8-Pentachlorodibenzofuran; 6F 123478 = 

1,2,3,4,7,8-Hexachlorodibenzofuran; 6F 123678 = 1,2,3,6,7,8-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.
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-18 

4.5.2 Default Emissions Factors for Boilers 

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

CAS Number Substance

Emissions Factor for Fuel Typea

Natural Gas 

(lb/MMcf)b,c

Natural Gas 

(lb/MMBtu)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas 

(lb/MMcf)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas

(lb/MMBtu)b,c

Fuel Oil 

(lb/Mgal)b

Fuel Oil 

(lb/MMBtu)b

Distillate 

Oil 

(lb/MMBtu)g

Refinery 

Fuel Gas 

(lb/MMcf)b,d

Refinery 

Fuel Gas 

(lb/MMBtu)b,d

83-32-9 Acenaphthene < 1.8E-06e-- 1.0E-06 1.1E-09 2.1E-05f6.0E-09 -- 5.9E-06 4.9E-09

208-96-8 Acenaphthylene < 1.8E-06e-- 2.7E-06 2.7E-09 2.5E-07 f2.1E-09 -- 2.6E-06 2.1E-09

75-07-0 Acetaldehyde 1.6E-02 1.7E-05 1.1E-02 1.9E-05 1.0E-03 7.0E-06 -- 4.0E-03 3.0E-06

107-02-8 Acrolein 1.8E-02 2.0E-05 1.1E-02 1.7E-05 2.2E-03 1.5E-05 -- -- --

120-12-7 Anthracene < 2.4E-06e-- 2.1E-06 2.2E-09 1.2E-06f2.1E-09 -- 2.3E-05 1.9E-08

7440-36-0 Antimony -- -- -- -- 5.3E-03f-- -- -- --

7440-38-2 Arsenic 2.0E-04e-- -- -- 1.3E-03f9.8E-06 4E-06 7.0E-04 5.9E-07

7440-39-3 Barium 4.4E-03e-- -- -- 2.6E-06f-- -- -- --

71-43-2 Benzene 2.1E-03e3.9E-06 3.3E-03 4.5E-06 2.1E-04f 3.2E-05 -- 2.1E-01 1.7E-04

56-55-3 Benzo(a)anthracene < 1.8E-06e-- 1.2E-06 1.3E-09 4.0E-06f1.3E-09 -- 1.8E-05 1.5E-08

50-32-8 Benzo(a)pyrene < 1.2E-06e-- 6.9E-07 7.1E-10 2.1E-07 1.4E-09 -- 3.4E-06 2.9E-09

205-99-2 Benzo(b)fluoranthene < 1.8E-06e-- 2.0E-06 2.0E-09 1.5E-06f,h 8.1E-09 -- 6.8E-06 5.7E-09

192-97-2 Benzo(e)pyrene -- -- -- -- 8.5E-07 5.8E-09 -- -- --

191-24-2 Benzo(g,h,i)perylene < 1.2E-06e-- 9.8E-07 1.0E-09 2.3E-06f6.7E-09 -- 3.9E-06 3.2E-09

207-08-9 Benzo(k)fluoranthene < 1.8E-06e-- 8.2E-07 8.4E-10 f,h 1.3E-09 -- 2.7E-06 2.1E-09

7440-41-7 Beryllium < 1.2E-05e-- -- -- 2.8E-05f4.3E-07 3E-06 1.6E-04 1.3E-07

106-99-0 1,3-Butadiene -- -- -- -- 6.2E-03 4.2E-05 -- -- --

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-19 

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

CAS Number Substance

Emissions Factor for Fuel Typea

Natural Gas 

(lb/MMcf)b,c

Natural Gas 

(lb/MMBtu)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas 

(lb/MMcf)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas

(lb/MMBtu)b,c

Fuel Oil 

(lb/Mgal)b

Fuel Oil 

(lb/MMBtu)b

Distillate 

Oil 

(lb/MMBtu)g

Refinery 

Fuel Gas 

(lb/MMcf)b,d

Refinery 

Fuel Gas 

(lb/MMBtu)b,d

106-97-8 Butane 2.1E+00e-- -- -- -- -- -- -- --

7440-43-9 Cadmium 1.1E-03e-- -- -- 4.0E-04f5.8E-06 3E-06 2.4E-03 2.0E-06

16887-00-6 Chloride -- -- -- -- 3.5E-01f-- -- -- --

67-66-3 Chloroform -- -- -- -- 4.7E-03 3.4E-05 -- -- --

91-58-7 2-Chloronaphthalene -- -- -- -- 2.3E-08 1.5E-10 -- -- --

18540-29-9 Chromium (hexavalent) -- -- -- -- 2.5E-04f7.8E-06 -- 2.6E-03i2.0E-06i

7440-47-3 Chromium (total) 1.4E-03e-- -- -- 8.5E-04f3.3E-05 3E-06 1.3E-02 1.0E-05

218-01-9 Chrysene < 1.8E-06e-- 1.6E-06 1.6E-09 2.4E-06f2.6E-08 -- 3.4E-06 2.9E-09

7440-48-4 Cobalt 8.4E-05e-- -- -- 6.0E-03f-- -- -- --

7440-50-8 Copper 8.5E-04e-- -- -- 1.8E-03f2.6E-05 6E-06 6.3E-03 5.3E-06

53-70-3 Dibenz(a,h)anthracene < 1.2E-06e-- 5.3E-07 5.5E-10 1.7E-06f4.7E-09 -- 2.6E-06 2.1E-09

25321-22-6 Dichlorobenzene 1.2E-03e-- -- -- -- -- -- -- --

57-97-6

7,12-Dimethylbenz(a) 

anthracene < 1.6E-05e

-- -- -- -- -- -- -- --

1746-01-6 Dioxin: 4D 2378j-- -- -- -- 6.3E-10 4.3E-12 -- -- --

40321-76-4 Dioxin: 5D 12378j-- -- -- -- 3.7E-10 2.5E-12 -- -- --

39227-28-6 Dioxin: 6D 123478j-- -- -- -- 3.7E-10 2.5E-12 -- -- --

57653-85-7 Dioxin: 6D 123678j-- -- -- -- 3.7E-10 2.5E-12 -- -- --

19408-74-3 Dioxin: 6D 123789j-- -- -- -- 3.7E-10 2.5E-12 -- -- --

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-20 

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

CAS Number Substance

Emissions Factor for Fuel Typea

Natural Gas 

(lb/MMcf)b,c

Natural Gas 

(lb/MMBtu)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas 

(lb/MMcf)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas

(lb/MMBtu)b,c

Fuel Oil 

(lb/Mgal)b

Fuel Oil 

(lb/MMBtu)b

Distillate 

Oil 

(lb/MMBtu)g

Refinery 

Fuel Gas 

(lb/MMcf)b,d

Refinery 

Fuel Gas 

(lb/MMBtu)b,d

35822-46-9 Dioxin: 7D 1234678j-- -- -- -- 3.1E-09 2.1E-11 -- -- --

3268-87-9 Dioxin: 8Dj-- -- -- -- 3.1E-09f5.1E-10 -- -- --

74-84-0 Ethane 3.1E+00e-- -- -- -- -- -- -- --

100-41-4 Ethylbenzene -- -- 9.2E-03 9.6E-06 6.4E-05f-- -- -- --

206-44-0 Fluoranthene 3.0E-06e-- 3.7E-06 3.7E-09 4.8E-06f5.3E-08 -- 4.3E-05 3.6E-08

86-73-7 Fluorene 2.8E-06e-- 5.6E-06 5.7E-09 4.5E-06f3.1E-08 -- 9.8E-06 8.2E-09

16984-48-8 Fluoride -- -- -- -- 3.7E-02f-- -- -- --

50-00-0 Formaldehyde 7.5E-02e3.1E-05 1.6E-02 2.5E-05 3.3E-02f4.5E-05 -- 1.6E-02 1.3E-05

51207-31-9 Furan: 4F 2378k-- -- -- -- 8.2E-10 5.5E-12 -- -- --

57117-41-6 Furan: 5F 12378k-- -- -- -- 4.6E-10 3.1E-12 -- -- --

57117-31-4 Furan: 5F 23478k-- -- -- -- 4.6E-10 3.1E-12 -- -- --

70648-26-9 Furan: 6F 123478k-- -- -- -- 3.6E-10 2.5E-12 -- -- --

57117-44-9 Furan: 6F 123678k-- -- -- -- 2.7E-10 1.9E-12 -- -- --

72918-21-9 Furan: 6F 123789k-- -- -- -- 3.7E-10 2.5E-12 -- -- --

60851-34-5 Furan: 6F 234678k-- -- -- -- 5.5E-10 3.7E-12 -- -- --

67562-39-4 Furan: 7F 1234678k-- -- -- -- 1.4E-09 9.8E-12 -- -- --

55673-89-7 Furan: 7F 1234789k-- -- -- -- 4.6E-10 3.2E-12 -- -- --

39001-02-0 Furan: 8Fk-- -- -- -- 7.2E-09 4.9E-11 -- -- --

110-54-3 Hexane 1.8E+00e-- -- -- -- -- -- -- --

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-21 

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

CAS Number Substance

Emissions Factor for Fuel Typea

Natural Gas 

(lb/MMcf)b,c

Natural Gas 

(lb/MMBtu)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas 

(lb/MMcf)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas

(lb/MMBtu)b,c

Fuel Oil 

(lb/Mgal)b

Fuel Oil 

(lb/MMBtu)b

Distillate 

Oil 

(lb/MMBtu)g

Refinery 

Fuel Gas 

(lb/MMcf)b,d

Refinery 

Fuel Gas 

(lb/MMBtu)b,d

7783-06-4 Hydrogen sulfide -- -- 1.5E-01 1.6E-04 -- -- -- 2.7E-01 2.2E-04

193-39-5 Indeno(1,2,3-cd)pyrene < 1.8E-06e-- 1.2E-06 1.2E-09 2.1E-06f3.1E-09 -- 2.6E-06 2.1E-09

7439-92-1 Lead -- -- -- -- 1.5E-03f1.1E-05 9E-06 2.4E-03 2.1E-06

7439-96-5 Manganese 3.8E-04e-- -- -- 3.0E-03f4.0E-05 6E-06 2.4E-03 2.0E-06

7439-97-6 Mercury 2.6E-04e-- -- -- 1.1E-04f7.0E-08 3E-06 3.23E-04 2.7E-07

56-49-5 3-Methylchloranthrene < 1.8E-06e-- -- -- -- -- -- -- --

91-57-6 2-Methylnaphthalene 2.4E-05e-- -- -- 1.1E-05 7.4E-08 -- -- --

7439-98-7 Molybdenum 1.1E-03e-- -- -- 7.9E-04f-- -- -- --

91-20-3 Naphthalene 6.1E-04e-- 2.9E-04 2.9E-07 1.1E-02f4.0E-07 -- 2.1E-04 1.7E-07

7440-02-0 Nickel 2.1E-03e-- -- -- 8.5E-02f2.3E-03 3E-06 5.6E-03 4.7E-06

109-66-0 Pentane 2.6E-00e-- -- -- -- -- -- -- --

198-55-0 Perylene -- -- -- -- 1.1E-07 7.4E-10 -- -- --

85-01-8 Phenanthrene 1.7E-05e-- 1.6E-05 1.7E-08 1.1E-05f7.4E-08 -- 5.6E-05 4.7E-08

108-95-2 Phenol -- -- -- -- -- -- -- 2.2E-03 1.8E-06

7723-14-0 Phosphorus -- -- -- -- 9.5E-03f-- -- -- --

74-98-6 Propane 1.6E+00e-- -- -- -- -- -- -- --

115-07-1 Propylene 1.1E-01 1.2E-04 1.8E-01 2.3E-04 2.2E-02 1.5E-04 -- -- --

129-00-0 Pyrene 5.0E-06e-- 6.0E-06 6.0E-09 4.3E-06f2.7E-08 -- 6.0E-05 5.0E-08

7782-49-2 Selenium < 2.4E-05e-- -- -- 6.8E-04f2.0E-05 1.5E-05 2.1E-03 1.7E-06

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-22 

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

CAS Number Substance

Emissions Factor for Fuel Typea

Natural Gas 

(lb/MMcf)b,c

Natural Gas 

(lb/MMBtu)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas 

(lb/MMcf)b,c

Natural Gas 

and Casing 

Vapor 

Recovery 

Gas

(lb/MMBtu)b,c

Fuel Oil 

(lb/Mgal)b

Fuel Oil 

(lb/MMBtu)b

Distillate 

Oil 

(lb/MMBtu)g

Refinery 

Fuel Gas 

(lb/MMcf)b,d

Refinery 

Fuel Gas 

(lb/MMBtu)b,d

71-55-6 1,1,1-Trichloroethane -- -- -- -- 2.4E-04f-- -- -- --

108-88-3 Toluene 3.4E-03e1.2E-05 1.4E-02 1.7E-05 6.2E-03f3.9E-05 -- 8.4E-01 7.2E-04

7440-62-2 Vanadium 2.3E-03e-- -- -- 3.2E-02f-- -- -- --

95-47-6 Xylene (o) -- -- -- -- 1.1E-04f-- -- -- --

1330-20-7 Xylene (total) 2.8E-02 2.8E-05 1.9E-02 2.7E-05 1.1E-02 7.5E-05 -- -- --

7440-66-6 Zinc 2.9E-02e-- -- -- 2.9E-02f1.1E-04 4E-06 3.4E+00 2.8E-03

Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds per million cubic feet, lb/MMBtu = pounds per million British thermal units 

a Bold italic values indicate that all test runs were below detection limit; underlined values indicate that 75% or more of the test runs were below the detection limit.

b Source: Hansell and England, 1998, unless otherwise specified.

c

The emissions factors were provided specifically for steam generators firing natural gas.

d

The same emissions factors were provided specifically for boilers with no control device and boilers with selective catalytic reduction.

e Source: U.S. EPA, 1995a, Table 1.4-3 and Table 1.4-4. Emissions factors were provided for natural gas combustion sources. Emissions factors preceded with a less than symbol 

are based on method detection limits.

f Source: U.S. EPA, 1995a, Table 1.3-9 and Table 1.3-11. Emissions factors were provided specifically for residual oil (mostly No. 6) fired boilers. For boilers firing other fuel oils, 

the emissions factors presented in Appendix D may be applicable.

g Source: U.S. EPA, 1995a, Table 1.3-10. Emissions factors were provided specifically for distillate oil-fired boilers.

h Emission factor includes both benzo(b)fluoranthene and benzo(k)fluoranthene.

i Hexavalent chromium was not detected. The reported emissions factors based on detection limits are expected to overstate hexavalent chromium emissions. Twenty percent of 

the total chromium emissions factor is assumed for the hexavalent chromium emissions factor. (The hexavalent chromium emissions factors for turbines is between 10 and 15 

percent of the total chromium emissions factor, and the hexavalent chromium emissions factor for boilers firing fuel oil is about 30 percent of the total chromium emissions factor, 

so 20 percent is a conservative approximation for hexavalent chromium emissions from refinery fuel gas.)

j

4D 2378 = 2,3,7,8-Tetrachlorodibenzo-p-dioxin; 5D 12378 = 1,2,3,7,8-Pentachlorodibenzo-p-dioxin; 6D 123478 = 1,2,3,4,7,8-Hexachlorodibenzo-p-dioxin; 6D 123678 = 

1,2,3,6,7,8-Hexachlorodibenzo-p-dioxin; 6D 123789 = 1,2,3,7,8,9-Hexachlorodibenzo-p-dioxin; 7D 1234678 = 1,2,3,4,6,7,8-Heptachlorodibenzo-p-dioxin; 8D = 

Octachlorodibenzo-p-dioxin.

k

4F 2378 = 2,3,7,8-Tetrachlorodibenzofuran; 5F 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
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-23 

4.5.3 Default Emissions Factor for Internal Combustion Engines 

The emissions from reciprocating internal combustion engines were dependent on: (1) the type of fuel 

used (diesel fuel, field gas [associated gases at production fields; use field gas factors for refinery fuel 

gas], or natural gas), (2) the type of engine used (two-stroke versus four-stroke engines), and (3) the fuelto-air ratio. As shown in Tables 4-5 and 4-6, high air rates (or lean fuel mixtures) tend to have higher 

emissions of acetaldehyde and formaldehyde, whereas lean gas mixtures tend to have higher emissions of 

benzene, toluene, and xylenes. Tables 4-7 and 4-8 present emission factors for turbines. 
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-24 

Table 4-5. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuelsa

CAS 

Number Substance

Emissions Factor for Engine and Fuel Typeb

Diesel,

O2 < 13% 

(lb/Mgal)

Diesel,

O2 > 13% 

(lb/Mgal)

Field Gas,

Lean (2-

Stroke)

(lb/MMcf)

Field Gas,

Lean (4-

Stroke)

(lb/MMcf)

Field Gas,

Rich (4-

Stroke)

(lb/MMcf)

Natural Gas,

Lean (4-

Stroke)

(lb/MMcf)

Natural Gas,

Rich (4-

Stroke)

(lb/MMcf)

83-32-9 Acenaphthene 6.4E-04 2.0E-04 7.4E-04 -- -- 7.2E-04 --

208-96-8 Acenaphthylene 1.3E-03 7.0E-04 1.1E-02 -- -- 7.6E-03 --

75-07-0 Acetaldehyde 3.5E-03 1.1E-01 8.8E+00 -- -- 4.0E+00 1.7E+00

107-02-8 Acrolein 1.1E-03 1.3E-02 2.0E+00 -- -- 1.6E+00 5.4E-01

120-12-7 Anthracene 1.7E-04 2.6E-04 4.5E-03 -- -- 2.6E-04 --

100-52-7 Benzaldehyde -- 1.3E-02 -- -- -- -- --

71-43-2 Benzene 1.0E-01 1.2E-01 7.7E+00 1.7E+00 1.1E+01 1.2E+00 9.9E+00

56-55-3 Benzo(a)anthracene 8.7E-05 2.3E-04 9.0E-04 -- -- 7.8E-05 --

50-32-8 Benzo(a)pyrene 3.5E-05 2.6E-05 8.8E-04 -- -- 3.6E-05 --

205-99-2 Benzo(b)fluoranthene 1.5E-04 2.6E-05 1.5E-04 -- -- 3.3E-04 --

191-24-2 Benzo(g,h,i)perylene 7.7E-05 6.8E-05 9.4E-05 -- -- 1.0E-04 --

207-08-9 Benzo(k)fluoranthene 3.0E-05 4.1E-05 4.6E-03 -- -- 5.3E-04 --

106-99-0 1,3-Butadiene -- 5.4E-03 -- -- -- -- --

218-01-9 Chrysene 2.1E-04 4.9E-05 1.7E-03 -- -- 9.6E-05 --

53-70-3 Dibenz(a,h)anthracene 4.8E-05 8.1E-05 7.7E-05 -- -- 1.1E-05 --

206-44-0 Fluoranthene 5.6E-04 1.1E-03 1.7E-04 -- -- 2.5E-04 --

86-73-7 Fluorene 1.8E-03 4.1E-03 2.4E-03 -- -- 4.6E-04 --

50-00-0 Formaldehyde 1.1E-02 1.7E-01 5.1E+01 4.2E+01 5.1E+00 2.9E+01 5.3E+00

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-25 

Table 4-5. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuelsa(continued)

CAS 

Number Substance

Emissions Factor for Engine and Fuel Typeb

Diesel,

O2 < 13% 

(lb/Mgal)

Diesel,

O2 > 13% 

(lb/Mgal)

Field Gas,

Lean (2-

Stroke)

(lb/MMcf)

Field Gas,

Lean (4-

Stroke)

(lb/MMcf)

Field Gas,

Rich (4-

Stroke)

(lb/MMcf)

Natural Gas,

Lean (4-

Stroke)

(lb/MMcf)

Natural Gas,

Rich (4-

Stroke)

(lb/MMcf)

193-39-5 Indeno(1,2,3-cd)pyrene 5.7E-05 6.4E-05 1.4E-04 -- -- 1.2E-04 --

91-20-3 Naphthalene 1.8E-02 1.2E-02 2.2E-01 -- -- 1.2E-01 --

85-01-8 Phenanthrene 5.6E-03 4.1E-03 4.9E-03 -- -- 8.9E-04 --

115-07-1 Propylene 3.9E-01 3.6E-01 2.5E+01 1.6E+01 3.0E+00 1.9E+01 4.0E+01

129-00-0 Pyrene 5.1E-04 6.7E-04 2.4E-04 -- -- 1.2E-04 --

108-88-3 Toluene 3.7E-02 5.5E-02 2.9E+00 7.7E-01 3.4E+00 4.1E-01 2.5E+00

108-38-3, 

106-42-3

Xylene (m,p) -- 2.2E-02 6.0E-01 3.0E-01 5.4E-01 8.6E-02 4.4E-01

95-47-6 Xylene (o) -- 2.1E-02 2.9E-01 9.0E-02 2.7E-01 4.9E-02 2.2E-01

1330-20-7 Xylene (total) 2.7E-02 3.6E-02 -- -- -- -- --

Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds per million cubic feet

a

Source: Hansell and England, 1998.

b

Bold italic values indicate that all test runs were below detection limit.
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-26 

Table 4-6. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuelsa

CAS 

Number Substance

Emissions Factor for Engine and Fuel Typeb

Diesel,

O2 < 13% 

(lb/MMBtu)

Diesel,

O2 > 13% 

(lb/MMBtu)

Diesel,

O2 not 

specified 

(lb/MMBtu)c

Field Gas,

Lean (2-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (2-

Stroke) 

(lb/MMBtu)d

Field Gas,

Lean (4-

Stroke) 

(lb/MMBtu)

Field Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (4-

Stroke) 

(lb/MMBtu)e

Natural 

Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

83-32-9 Acenaphthene 4.5E-06 1.4E-06 < 1.4E-06f7.1E-07 1.3E-06g-- -- 1.3E-06h i

208-96-8 Acenaphthylene 9.0E-06 5.1E-06 < 5.1E-06f1.1E-05 3.2E-06g-- -- 5.5E-06h i

75-07-0 Acetaldehyde 2.4E-05 7.6E-04 7.7E-04 8.4E-03 7.8E-03 -- -- 8.4E-03 2.8E-03j

107-02-8 Acrolein 7.6E-06 9.4E-05 < 9.3E-05 1.9E-03 7.8E-03 -- -- 5.1E-03 2.6E-03j

120-12-7 Anthracene 1.2E-06 1.9E-06 1.9E-06f4.3E-06 7.2E-07g-- -- 2.4E-07a,h i

100-52-7 Benzaldehyde -- 9.0E-05 -- -- -- -- -- -- --

71-43-2 Benzene 7.1E-04 8.8E-04 9.3E-04 7.5E-03 1.9E-03 1.64E-03 1.05E-02 4.4E-04 1.6E-03j

56-55-3 Benzo(a)anthracene 6.1E-07 1.7E-06 1.7E-06f8.5E-07 3.4E-07g-- -- 7.4E-08a,h i

50-32-8 Benzo(a)pyrene 2.5E-07 1.9E-07 < 1.9E-07f8.3E-07 5.7E-09g-- -- 3.4E-08a,h i

205-99-2 Benzo(b)fluoranthene 1.1E-06 1.9E-07 < 9.9E-08f1.4E-07 8.5E-09g-- -- 1.7E-07h i

192-97-2 Benzo(e)pyrene -- -- -- -- 2.3E-08g-- -- 4.2E-07h i

191-24-2 Benzo(g,h,i)perylene 5.4E-07 4.9E-07 < 4.9E-07f9.0E-08 2.5E-08g-- -- 4.1E-07h i

207-08-9 Benzo(k)fluoranthene 2.1E-07 3.0E-07 < 1.6E-07f4.4E-06 4.3E-09g-- -- 5.0E-07a,h i

92-52-4 Biphenyl -- -- -- -- 4.0E-06 -- -- 2.1E-04 --

106-99-0 1,3-Butadiene -- 3.9E-05 < 3.9E-05 -- 8.2E-04 -- -- 2.7E-04 6.6E-04j

106-97-8 Butane -- -- -- -- 4.8E-03 -- -- 5.4E-04 --

Butyr/Isobutyraldehyde -- -- -- -- 4.8E-04 -- -- 1.0E-04 4.9E-05j

56-23-5 Carbon tetrachloride -- -- -- -- 6.1E-05 -- -- < 3.7E-05 < 1.8E-05j

108-90-7 Chlorobenzene -- -- -- -- 4.4E-05 -- -- < 3.0E-05 < 1.3E-05j

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-27 

Table 4-6. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuelsa(continued)

CAS 

Number Substance

Emissions Factor for Engine and Fuel Typeb

Diesel,

O2 < 13% 

(lb/MMBtu)

Diesel,

O2 > 13% 

(lb/MMBtu)

Diesel,

O2 not 

specified 

(lb/MMBtu)c

Field Gas,

Lean (2-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (2-

Stroke) 

(lb/MMBtu)d

Field Gas,

Lean (4-

Stroke) 

(lb/MMBtu)

Field Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (4-

Stroke) 

(lb/MMBtu)e

Natural 

Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

75-00-3 Chloroethane -- -- -- -- -- -- -- 1.9E-06 --

67-66-3 Chloroform -- -- -- -- 4.7E-05 -- -- < 2.9E-05 < 1.4E-05j

218-01-9 Chrysene 1.5E-06 3.5E-07 3.5E-07f1.6E-06 6.7E-07g-- -- 6.9E-07h i

110-82-7 Cyclohexane -- -- -- -- 3.1E-04 -- -- -- --

287-92-3 Cyclopentane -- -- -- -- 9.5E-05 -- -- 2.3E-04 --

53-70-3 Dibenz(a,h)anthracene 3.5E-07 5.8E-07 < 5.8E-07f7.3E-08 g-- -- 1.0E-08a,h i

75-34-3 1,1-Dichloroethane -- -- -- -- 3.9E-05 -- -- < 2.4E-05 < 1.1E-05j

107-06-2 1,2-Dichloroethane -- -- -- -- 4.2E-05 -- -- < 2.4E-05 < 1.1E-05j

78-87-5 1,2-Dichloropropane -- -- -- -- 4.5E-05 -- -- -- < 1.3E-05j

542-75-6 1,3-Dichloropropene -- -- -- -- 4.4E-05 -- -- < 2.6E-05 < 1.3E-05j

74-84-0 Ethane -- -- -- -- 7.1E-02 -- -- 1.1E-01 7.0E-02j

100-41-4 Ethylbenzene -- -- -- -- 1.1E-04 -- -- 4.0E-05 < 2.5E-05j

106-93-4 Ethylene dibromide -- -- -- -- 7.3E-05 -- -- < 4.4E-05 < 2.1E-05j

206-44-0 Fluoranthene 3.9E-06 7.6E-06 7.6E-06f1.6E-07 3.6E-07g-- -- 1.1E-06h i

86-73-7 Fluorene 1.3E-05 2.9E-05 2.9E-05f2.3E-06 4.7E-06g-- -- 5.7E-06h i

50-00-0 Formaldehyde 7.7E-05 1.2E-03 1.2E-03 4.9E-02 5.5E-02 3.95E-02 4.81E-03 5.3E-02 2.1E-02j

110-54-3 n-Hexane -- -- -- -- 4.5E-04 -- -- 1.1E-03 --

193-39-5 Indeno(1,2,3-cd)pyrene 4.0E-07 4.6E-07 < 3.8E-07f1.3E-07 9.9E-09g-- -- 1.1E-07a,h i

75-28-5 Isobutane -- -- -- -- 3.8E-03 -- -- -- --

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

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4-28 

Table 4-6. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuelsa(continued)

CAS 

Number Substance

Emissions Factor for Engine and Fuel Typeb

Diesel,

O2 < 13% 

(lb/MMBtu)

Diesel,

O2 > 13% 

(lb/MMBtu)

Diesel,

O2 not 

specified 

(lb/MMBtu)c

Field Gas,

Lean (2-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (2-

Stroke) 

(lb/MMBtu)d

Field Gas,

Lean (4-

Stroke) 

(lb/MMBtu)

Field Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (4-

Stroke) 

(lb/MMBtu)e

Natural 

Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

67-56-1 Methanol -- -- -- -- 2.5E-03 -- -- 2.5E-03 3.1E-03j

108-87-2 Methylcyclohexane -- -- -- -- 3.4E-04 -- -- 1.2E-03 --

75-09-2 Methylene chloride -- -- -- -- 1.5E-04 -- -- 2.0E-05 4.1E-05j

91-57-6 2-Methylnaphthalene -- -- -- -- 2.1E-05g-- -- 3.3E-05h i

91-20-3 Naphthalene 1.3E-04 8.5E-05 8.5E-05f2.1E-04 9.6E-05g-- -- 7.4E-05h< 9.7E-05I,j

111-84-2 n-Nonane -- -- -- -- 3.1E-05 -- -- 1.1E-04 --

111-65-9 n-Octane -- -- -- -- 7.4E-05 -- -- 3.5E-04 --

109-66-0 n-Pentane -- -- -- -- 1.5E-03 -- -- 2.6E-03 --

198-55-0 Perylene -- -- -- -- 5.0E-09g-- --

h i

85-01-8 Phenanthrene 4.0E-05 2.9E-05 2.9E-05f4.7E-06 3.5E-06g-- -- 1.0E-05h i

108-95-2 Phenol -- -- -- -- 4.2E-05 -- -- 2.4E-05 --

74-98-6 Propane -- -- -- -- 2.9E-02 -- -- 4.2E-02 --

115-07-1 Propylene 2.7E-03 2.6E-03 2.6E-03 2.4E-02 -- 1.5E-02 2.9E-03 1.8E-02a3.8E-02

129-00-0 Pyrene 3.6E-06 4.8E-06 4.8E-06f2.3E-07 5.8E-07g-- -- 1.4E-06h i

100-42-5 Styrene -- -- -- -- 5.5E-05 -- -- < 2.4E-05 < 1.2E-05j

79-34-5 1,1,2,2-Tetrachloroethane -- -- -- -- 6.6E-05 -- -- < 4.0E-05 2.5E-05j

108-88-3 Toluene 2.6E-04 4.0E-04 4.1E-04 2.7E-03 9.6E-04 7.3E-04 3.3E-03 4.1E-04 5.6E-04j

79-00-5 1,1,2-Trichloroethane -- -- -- -- 5.3E-05 -- -- < 3.2E-05 < 1.5E-05j

526-73-8 1,2,3-Trimethylbenzene -- -- -- -- 3.5E-05 -- -- 2.3E-05

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

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4-29 

Table 4-6. Summary of Emissions Factors for Internal Combustion Engines Firing Various Fuelsa(continued)

CAS 

Number Substance

Emissions Factor for Engine and Fuel Typeb

Diesel,

O2 < 13% 

(lb/MMBtu)

Diesel,

O2 > 13% 

(lb/MMBtu)

Diesel,

O2 not 

specified 

(lb/MMBtu)c

Field Gas,

Lean (2-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (2-

Stroke) 

(lb/MMBtu)d

Field Gas,

Lean (4-

Stroke) 

(lb/MMBtu)

Field Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

Natural 

Gas,

Lean (4-

Stroke) 

(lb/MMBtu)e

Natural 

Gas,

Rich (4-

Stroke) 

(lb/MMBtu)

95-63-6 1,2,4-Trimethylbenzene -- -- -- -- 1.1E-04 -- -- 1.4E-05 --

108-67-8 1,3,5-Trimethylbenzene -- -- -- -- 1.8E-05 -- -- 3.4E-05 --

540-84-1 2,2,4-Trimethylpentane -- -- -- -- 8.5E-04 -- -- 2.5E-04 --

75-01-4 Vinyl chloride -- -- -- -- 2.5E-05 -- -- 1.5E-05 < 7.2E-06j

108-38-3, 

106-42-3

Xylene (m,p) -- 1.5E-04 -- 5.8E-04 -- 2.9E-04 5.1E-04 8.2E-05a4.2E-04

95-47-6 Xylene (o) -- 1.5E-04 -- 2.7E-04 -- 8.6E-05 2.6E-04 4.7E-05a2.1E-04

1330-20-7 Xylene (total) 1.9E-04 2.6E-04 2.9E-04 -- 2.7E-04 -- -- 1.8E-04 2.0E-04j

Note: lb/MMBtu = pounds per million British thermal units

a Source: Hansell and England, 1998, unless otherwise specified.

b Bold italic values indicate that all test runs were below detection limit.

c Source: U.S. EPA, 1995a, Table 3.3-2. Emissions factors are for uncontrolled sources. Emissions factors preceded with a less than symbol are based on method detection limits.

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

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

f

The emissions factor for total polycyclic aromatic hydrocarbons (PAH) in U.S. EPA, 1995a, Table 3.3-2 is 1.7E-04 lb/MMBtu.

g

The emissions factor for total PAH in U.S. EPA, 1995a, Table 3.2-1 is 1.3E-04 lb/MMBtu.

h

The emissions factor for total PAH in U.S. EPA, 1995a, Table 3.2-2 is 2.7E-05 lb/MMBtu.

i

The emissions factor for total PAH in U.S. EPA, 1995a, Table 3.2-3 is 1.4E-04 lb/MMBtu.

j Source: U.S. EPA, 1995a, Table 3.2-3. Emissions factors are for uncontrolled sources. Emissions factors preceded with a less than symbol are based on method detection limits.
Version 1.0 Section 4—Stationary Combustion Sources 

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4-30 

4.5.4 Default Emissions Factor for Turbines 

Table 4-7. Summary of Emissions Factors for Turbines Firing Various Fuelsa

CAS Number Substance

Emissions Factor for Turbine and Fuel Typeb

Natural Gas, No 

Duct Burners 

(lb/MMcf)c

Natural Gas, Duct 

Burners (lb/MMcf)

d

Natural Gas and 

Refinery Fuel Gas, 

Duct Burners 

(lb/MMcf)

e

Natural Gas, 

Refinery Fuel Gas, 

and Liquefied 

Petroleum Gas;

Duct Burners 

(lb/MMcf)e

Refinery Fuel Gas, 

No Duct Burners 

(lb/ MMcf)f

83-32-9 Acenaphthene 3.4E-06 -- 2.4E-05 -- --

208-96-8 Acenaphthylene 3.0E-06 -- 1.2E-05 -- --

75-07-0 Acetaldehyde 4.0E-02 -- 4.5E-03 -- 2.2E-02

107-02-8 Acrolein 1.8E-02 -- -- -- --

120-12-7 Anthracene 3.5E-05 -- 2.7E-05 -- --

7440-38-2 Arsenic -- -- -- 1.7E-02 4.1E-03

71-43-2 Benzene 1.2E-02 -- 1.7E-01 -- 1.5E-01

56-55-3 Benzo(a)anthracene 2.9E-06 -- 1.6E-05 -- --

50-32-8 Benzo(a)pyrene 2.1E-06 -- 1.0E-05 -- --

205-99-2 Benzo(b)fluoranthene 3.4E-06 -- 2.7E-05 -- --

191-24-2 Benzo(g,h,i)perylene 2.5E-06 -- 2.1E-05 -- --

207-08-9 Benzo(k)fluoranthene 2.7E-06 -- 1.3E-05 -- --

7440-41-7 Beryllium -- -- -- 3.4E-03 2.1E-03

7440-43-9 Cadmium -- -- 2.1E-03 7.4E-03 7.4E-03

18540-29-9 Chromium (hexavalent) -- -- 7.5E-03 -- 2.0E-03

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

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4-31 

Table 4-7. Summary of Emissions Factors for Turbines Firing Various Fuelsa(continued)

CAS Number Substance

Emissions Factor for Turbine and Fuel Typeb

Natural Gas, No 

Duct Burners 

(lb/MMcf)c

Natural Gas, Duct 

Burners (lb/MMcf)

d

Natural Gas and 

Refinery Fuel Gas, 

Duct Burners 

(lb/MMcf)

e

Natural Gas, 

Refinery Fuel Gas, 

and Liquefied 

Petroleum Gas;

Duct Burners 

(lb/MMcf)e

Refinery Fuel Gas, 

No Duct Burners 

(lb/ MMcf)f

7440-47-3 Chromium (total) -- -- 5.4E-02 -- 1.8E-02

218-01-9 Chrysene 5.1E-06 -- 1.2E-04 -- --

7440-50-8 Copper -- -- 1.9E-03 4.1E-02 5.8E-02

53-70-3 Dibenz(a,h)anthracene 2.1E-06 -- 7.1E-06 -- --

100-41-4 Ethylbenzene 1.5E-02 -- -- -- --

206-44-0 Fluoranthene 1.2E-05 -- 1.1E-04 -- --

86-73-7 Fluorene 1.6E-05 -- 1.9E-04 -- --

50-00-0 Formaldehyde 2.1E-02 6.2E+00 1.7E-01 -- 8.4E-01

7783-06-4 Hydrogen sulfide -- -- 1.7E-01 -- 1.6E-01

193-39-5 Indeno(1,2,3-cd)pyrene 2.4E-06 -- 9.8E-06 -- --

7439-92-1 Lead -- -- -- 6.8E-02 4.0E-02

7439-96-5 Manganese -- -- 3.5E-03 1.8E-01 1.8E-01

7439-97-6 Mercury -- -- 4.6E-03 -- 2.2E-02

91-20-3 Naphthalene 7.5E-04 -- 4.0E-02 -- --

7440-02-0 Nickel -- -- 8.2E-03 2.8E-01 2.3E-01

85-01-8 Phenanthrene 6.7E-05 -- 6.9E-04 -- --

108-95-2 Phenol -- -- 1.5E-02 5.8E-02 9.4E-03

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

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4-32 

Table 4-7. Summary of Emissions Factors for Turbines Firing Various Fuelsa(continued)

CAS Number Substance

Emissions Factor for Turbine and Fuel Typeb

Natural Gas, No 

Duct Burners 

(lb/MMcf)c

Natural Gas, Duct 

Burners (lb/MMcf)

d

Natural Gas and 

Refinery Fuel Gas, 

Duct Burners 

(lb/MMcf)

e

Natural Gas, 

Refinery Fuel Gas, 

and Liquefied 

Petroleum Gas;

Duct Burners 

(lb/MMcf)e

Refinery Fuel Gas, 

No Duct Burners 

(lb/ MMcf)f

115-07-1 Propylene 1.7E+00 -- -- -- --

129-00-0 Pyrene 2.3E-05 -- 1.3E-04 -- --

7782-49-2 Selenium -- -- -- 1.7E-02 5.4E-03

108-88-3 Toluene 7.2E-02 -- 1.8E-01 -- 1.1E+00

1330-20-7 Xylene (total) 3.6E-02 -- 4.1E-01 -- 3.1E+00

7440-66-6 Zinc -- -- 1.7E-02 4.1E-01 7.0E+00

Note: lb/Mgal = pounds per thousand gallons, lb/MMcf = pounds per million cubic feet

a

Source: Hansell and England, 1998.

b

Bold italic values indicate that all test runs were below detection limit.

c

The same emissions factors were provided specifically for turbines with no control device and turbines with selective catalytic reduction and carbon monoxide 

oxidation catalyst.

d

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

e

The emissions factors were provided specifically for turbines with selective catalytic reduction and carbon monoxide oxidation catalyst.

f

The emissions factors were provided specifically for turbines with carbon monoxide oxidation catalyst.
Version 1.0 Section 4—Stationary Combustion Sources 

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4-33 

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

CAS 

Number Substance

Emissions Factor for Turbine and Fuel Type

a

Distillate Oil

(lb/MMBtu)

c

Natural Gas, 

No Duct 

Burners 

(lb/MMBtu)

d

Natural Gas, 

Duct Burners 

(lb/MMBtu)

e

Natural Gas, 

Type not 

specified

(lb/MMBtu)

f

Natural Gas 

and Refinery 

Fuel Gas, 

Duct Burners 

(lb/MMBtu)

g

Natural Gas, 

Refinery Fuel 

Gas, and 

Liquefied 

Petroleum 

Gas; Duct 

Burners 

(lb/MMBtu)

g

Refinery Fuel 

Gas, No Duct 

Burners 

(lb/MMBtu)

h

83-32-9 Acenaphthene i3.3E-09 --

j

2.2E-08 -- --

208-96-8 Acenaphthylene i2.9E-09 --

j

1.1E-08 -- --

75-07-0 Acetaldehyde -- 3.8E-05 -- 4.0E-05 4.1E-06 -- 1.6E-05

107-02-8 Acrolein -- 1.7E-05 -- 6.4E-06 -- -- --

120-12-7 Anthracene i3.4E-08 --

j

2.5E-08 -- --

7440-38-2 Arsenic < 1.1E-05 -- -- -- -- 9.0E-06 2.9E-06

71-43-2 Benzene 5.5E-05 1.2E-05 -- 1.2E-05 1.5E-04 -- 1.1E-04

56-55-3 Benzo(a)anthracene i2.8E-09 --

j

1.5E-08 -- --

50-32-8 Benzo(a)pyrene i

2.1E-09 --

j

9.5E-09 -- --

205-99-2 Benzo(b)fluoranthene i3.3E-09 --

j

2.5E-08 -- --

191-24-2 Benzo(g,h,i)perylene i2.4E-09 --

j

1.9E-08 -- --

207-08-9 Benzo(k)fluoranthene i2.6E-09 --

j

1.3E-08 -- --

7440-41-7 Beryllium < 3.1E-07 -- -- -- -- 1.8E-06 1.5E-06

106-99-0 1,3-Butadiene < 1.6E-05 -- -- < 4.3E-07 -- -- --

7440-43-9 Cadmium 4.8E-06 -- -- -- 1.9E-06 3.9E-06 5.3E-06

18540-29-9 Chromium (hexavalent) -- -- -- -- 7.0E-06 -- 1.5E-06

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-34 

Table 4-8. Summary of Emissions Factors for Turbines Firing Various Fuelsa(continued)

CAS 

Number Substance

Emissions Factor for Turbine and Fuel Typea

Distillate Oil

(lb/MMBtu)

c

Natural Gas, 

No Duct 

Burners 

(lb/MMBtu)

d

Natural Gas, 

Duct Burners 

(lb/MMBtu)

e

Natural Gas, 

Type not 

specified

(lb/MMBtu)

f

Natural Gas 

and Refinery 

Fuel Gas, 

Duct Burners 

(lb/MMBtu)

g

Natural Gas, 

Refinery Fuel 

Gas, and 

Liquefied 

Petroleum 

Gas; Duct 

Burners 

(lb/MMBtu)

g

Refinery Fuel 

Gas, No Duct 

Burners 

(lb/MMBtu)

h

7440-47-3 Chromium (total) 1.1E-05 -- -- -- 5.0E-05 -- 1.3E-05

218-01-9 Chrysene i4.9E-09 --

j

1.1E-07 -- --

7440-50-8 Copper -- -- -- -- 1.8E-06 2.1E-05 4.1E-05

53-70-3 Dibenz(a,h)anthracene i

2.1E-09 --

j

6.6E-09 -- --

100-41-4 Ethylbenzene -- 1.5E-05 -- 3.2E-05 -- -- --

206-44-0 Fluoranthene i1.2E-08 --

j

9.9E-08 -- --

86-73-7 Fluorene i1.5E-08 --

j

1.8E-07 -- --

50-00-0 Formaldehyde 2.8E-04 2.0E-05 6.0E-03 7.1E-04 1.5E-04 -- 6.0E-04

7783-06-4 Hydrogen sulfide -- -- -- -- 1.5E-04 -- 1.2E-04

193-39-5 Indeno(1,2,3-cd)pyrene i2.3E-09 --

j

9.1E-09 -- --

7439-92-1 Lead 1.4E-05 -- -- -- -- 3.6E-05 2.8E-05

7439-96-5 Manganese 7.9E-04 -- -- -- 3.3E-06 9.2E-05 1.3E-04

7439-97-6 Mercury 1.2E-06 -- -- -- 4.4E-06 -- 1.5E-05

91-20-3 Naphthalene 3.5E-05j7.3E-07 -- 1.3E-06j3.7E-05 -- --

7440-02-0 Nickel < 4.6E-06 -- -- -- 7.6E-06 1.5E-04 1.7E-04

85-01-8 Phenanthrene i6.5E-08 --

j

6.4E-07 -- --

(continued)
Version 1.0 Section 4—Stationary Combustion Sources 

Review Draft – Do not cite or quote 

4-35 

Table 4-8. Summary of Emissions Factors for Turbines Firing Various Fuelsa(continued)

CAS 

Number Substance

Emissions Factor for Turbine and Fuel Typea

Distillate Oil

(lb/MMBtu)

c

Natural Gas, 

No Duct 

Burners 

(lb/MMBtu)

d

Natural Gas, 

Duct Burners 

(lb/MMBtu)

e

Natural Gas, 

Type not 

specified

(lb/MMBtu)

f

Natural Gas 

and Refinery 

Fuel Gas, 

Duct Burners 

(lb/MMBtu)

g

Natural Gas, 

Refinery Fuel 

Gas, and 

Liquefied 

Petroleum 

Gas; Duct 

Burners 

(lb/MMBtu)

g

Refinery Fuel 

Gas, No Duct 

Burners 

(lb/MMBtu)

h

108-95-2 Phenol -- -- -- -- 1.4E-05 3.1E-05 6.7E-06

115-07-1 Propylene -- 1.6E-03 -- -- -- -- --

129-00-0 Pyrene i2.3E-08 --

j

1.2E-07 -- --

7782-49-2 Selenium < 2.5E-05 -- -- -- -- 9.0E-06 3.7E-06

108-88-3 Toluene -- 7.0E-05 -- 1.3E-04 1.6E-04 -- 7.8E-04

1330-20-7 Xylene (total) -- 3.5E-05 -- 6.4E-05 3.7E-04 -- 2.2E-03

7440-66-6 Zinc -- -- -- -- 1.5E-05 2.2E-04 5.0E-03

Note: lb/MMBtu = pounds per million British thermal units

a

Source: Hansell and England, 1998 unless otherwise specified.

b

Bold italic values indicate that all test runs were below detection limit.

c

Source: U.S. EPA, 1995a, Table 3.1-4 and Table 3.1-5. Emissions factors are based on an average distillate oil heating value (HHV) of 139 MMBtu/Mgal.

d

The same emissions factors were provided specifically for turbines with no control device and turbines with selective catalytic reduction and carbon monoxide 

oxidation catalyst.

e

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

f

Source: U.S. EPA, 1995a, Table 3.1-3. Emissions factors based on an average natural gas heating value (HHV) of 1020 Btu/scf at 60°F.

g

The emissions factors were provided specifically for turbines with selective catalytic reduction and carbon monoxide oxidation catalyst.

h

The emissions factors were provided specifically for turbines with carbon monoxide oxidation catalyst.

i

The emissions factor for total polycyclic aromatic hydrocarbons (PAH) is 4.0E-05 lb/MMBtu.

j

The emissions factor for total PAH is 2.2E-06 lb/MMBtu.
Version 1.0 Section 4—Stationary Combustion Sources 

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4-36 

[This page intentionally left blank.] 
Version 1.0 Section 5—Process Vents 

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5-1 

5. Process Vents 

There are a variety of processes and equipment at petroleum refineries that may release pollutants directly 

into the atmosphere through process vents. Many of these process vents may be controlled using a flare, 

thermal incinerator, or other air pollution control techniques. This section describes the key process vents 

and emissions estimation procedures considering controls. At some facilities, the process gases may be 

routed to the refinery’s fuel gas system rather than directly to a control device to the atmosphere. These 

gases would then be combusted with the fuel gas in either a stationary combustion unit (process heater or 

boiler) or in a flare. As such, emissions from these gases are expected to be included in the emissions 

estimated for stationary combustion sources (see Section 4) or for flares (see Section 6). The methods in 

this section should be used for process vent gases other than those recovered into the refinery’s fuel gas 

system. Particularly, this section provides methods for estimating the emissions associated with catalytic 

cracking units (CCUs), coking units, CRUs, sulfur recovery plants, and other process vents (e.g., from 

hydrogen (H2) plants, asphalt blowing stills, coke calcining units, blowdown system, and vacuum 

generating units).

Table 5-1 summarizes the general hierarchy of process vent emissions measurement or estimation 

methods, which are ranked in terms of anticipated accuracy. Within a given measurement method (or 

rank), there may be alternative methods for determining the constituent-specific emissions. Methodology 

Ranks 1 and 2 for process vents (i.e., the use of CEMS) have been previously described in Section 4, 

Stationary Combustion Sources. Although Section 5 will note these methods, where applicable, for 

individual process vents, Section 4 should be reviewed for sample calculations and other important 

considerations when using CEMS to determine mass emissions rates. 

Table 5-1. Summary of Typical Hierarchy of Process Vent Emissions Estimates 

Rank Flow Estimate Method Compositional Analysis Data

1 Continuous flow meter Continuous gas composition analyzer

2 Engineering estimates (e.g., F factor) Continuous gas composition analyzer

3 Engineering estimates Occasional grab samples

4 Measured process rates Site-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 largest emissions vent at the refinery. The CCU is a 

catalytic process used to upgrade (crack) heavy distillates to form lighter, more useful distillates such as 

heating oils or gasoline. The CCU system consists of a reactor, a catalyst regenerator (commonly referred 

to as the ―regenerator‖), vent gas process equipment for energy recovery and emissions control, and an 

exhaust stack. Nearly all refinery CCU systems operate as fluidized-bed reactors and use air or oil gas 

flow to transport the very small catalyst particles between the CCU reactor and regenerator. These 

fluidized CCU systems are commonly referred to as fluid catalytic cracking units (FCCU). There are two 

or three refineries that use larger catalyst pellets in moving bed-type reactor system, which is commonly 

referred to as a thermal catalytic cracking unit (TCCU). Nearly all of the available emissions data are 

specific to FCCU. Consequently, the emissions inventory methods presented in this section are based 

primarily on FCCU operation and emissions data. Although most of these methods presented in this 

section were not developed for TCCU systems, apply these emissions inventory methods for TCCU 

systems unless direct emissions data are available. 

The CCU catalyst regenerator vent releases a wide variety of pollutants, including PM, SO2, NOx, carbon 

monoxide (CO), VOC, metal HAP, organic HAP, and ammonia. As a by-product of the cracking 
Version 1.0 Section 5—Process Vents 

Review Draft – Do not cite or quote 

5-2 

reactions, coke is deposited on the catalyst particles. The coke reduces the activity of the catalyst, and the 

spent catalyst that is returned from the CCU reactor is regenerated continuously by burning off coke in 

the CCU catalyst regenerator. There are two basic types of CCU regenerators: complete combustion 

regenerators and partial combustion regenerators. In a complete combustion regenerator, the regenerator 

is typically operated at approximately 1,200°F to 1,400°F with excess O2 and low levels (< 500 ppmv) of 

CO in the exhaust flue gas. In a partial (or incomplete) combustion regenerator, the regenerator is 

typically operated at approximately 1,000°F to 1,200°F under O2-limited conditions and relatively high 

levels (1% to 5%) of CO. Prior to exiting the regenerator, catalyst particles entrained with the flue gases 

are initially removed by internal cyclone separators and returned to the regenerator catalyst bed for 

recirculation to the reactor. 

On a routine basis, a small portion of the circulating catalyst, commonly referred to as equilibrium 

catalyst (E-cat), is removed from the system and fresh catalyst is added to maintain catalyst activity and 

replace catalyst lost or removed from the system. Various other additives may also be included with the 

catalyst additions to reduce NOx or SO2 emissions or promote complete combustion (thereby reducing CO 

emissions). Although the CCU vent is the primary emissions source associated with the CCU, fugitive 

dust emissions associated with handling the fresh catalyst or spent E-cat should also be calculated and 

included in the emissions inventory for CCU systems. 

After the flue gas exits the CCU regenerator, a variety of energy recovery or emissions control systems 

may be used to reduce pollutant releases. For complete combustion CCU, a waste heat boiler is often used 

to recover the latent heat of the flue gas. The energy recovery system also serves to cool the flue gas prior 

to PM or other add-on control systems. The most common control systems for CCU are electrostatic 

precipitators (ESP) or wet scrubbers. For partial combustion CCU, the first control system is typically a 

CO boiler used to combust the remaining CO in the flue gas to CO2 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 SO2, NOx, CO, and CO2, it is anticipated that most CCUs will have CEMS for measuring the 

composition of the exhaust gas. Gas flow rate may be directly monitored, but in many cases, the exhaust 

flow rate will be calculated based on air blast rates and composition monitors (similar to F factors based 

on coke burn-off rates). Equations in 40 CFR Part 63 Subpart UUU can be used to estimate flow rates 

based on gas composition analyzers that are typically used to monitor the regenerator combustion 

parameters. When CEMS or direct-flow monitors are present, these data should be used to calculate 

annual pollutant emissions. The GHG Mandatory Reporting Rule (40 CFR Part 98, Subpart Y) presents 

appropriate Methodology Ranks 1 or 2 for CCU to calculate CO2 emissions from the CCU during coke 

burn-off. 

5.1.2 Methodology Ranks 3 and 4 for Catalytic Cracking Units 

For VOC, PM, and specific HAP, it is anticipated that many refineries will have performed source tests of 

their CCUs. Generally, testing will be conducted infrequently so the testing results represent an emissions 

rate at a given point in time and production level. Rather than assuming that the mass emissions rate 

measured during the test occurs continuously for all process operating hours, the resulting source test data 

are most appropriately used for developing a site-specific emissions factor. This type of emissions factor 

is the measured emissions rate (lb/hr) divided by the processing rate (throughput per hr). Generally, the 

emissions from the CCU catalyst regenerator vent are best correlated with coke burn-off rates; however, if 

CCU feed and operating conditions do not vary significantly, then throughput-based emissions factors 

may be used. Generally, the most recently performed source test should be used to develop the sitespecific emissions factor. 
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Although site-specific emissions factors can be developed for PM, VOC, organic HAP species, or metal 

HAP species using source test data, there are some unique nomenclature and reporting practices for PM 

emissions that deserve additional guidance. Additionally, a quasi Methodology Rank 4 for CCU metal 

HAP emissions estimates based on a site-specific PM emissions rate has been developed and requires 

additional explanation. The following subsections discuss additional guidance on providing a complete 

PM emissions estimate and on estimating metal HAP emissions from PM source test information. 

5.1.2.1 PM Emissions Inventory and Test Method Considerations 

PM emissions inventories have their own nomenclature and structure. To correctly report PM emissions, 

an understanding of the reporting nomenclature and the PM testing methods is needed. This subsection 

provides guidance and background information regarding PM emissions, with a focus on the PM test 

methods, particularly those methods commonly used when testing the CCU vent. 

Example 5-1: Development of Site-Specific Emissions Factor 

A source test was performed to 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, respectively. The processing rates during the three runs were 

1,600; 1,700; and 1,500 barrels per hour (bbl/hr) and the coke burn-off rates were 25,000; 

29,000; and 23,000 lb/hr for tests 1, 2, and 3, respectively. An appropriate emissions factor for 

the CCU can be developed to project annual emissions. 

First, the emissions factor for each individual run should be calculated, and then the emissions 

factors should be averaged. Emissions factors can be assessed using different normalizing 

factors, such as throughput and coke burn-off rates, as follows:

– Run 1: Emissions/throughput = 20.2 (lb/hr) ÷ 1,600 (bbls/hr) = 0.0126 lb/bbl = 12.6 pounds per 

thousands of barrels (lb/Mbbl)

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

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

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

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

Emissions/coke burn-off = 17.6 (lb/hr) ÷ 23 (1,000 lb/hr) = 0.765 lb/1,000 lbs 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 which emissions factor is most appropriate. One 

method is to compare the range of the test runs compared to the three-run average. For the 

throughput-based emissions factors, the highest single-run emissions factor is 14% (100% × 

[14.8 − 13] ÷ 13) higher than the average, and the lowest single-run emissions factor is 10% 

lower than the average. For the coke burn-off rate emissions factors, the highest single-run 

emissions factor is 6.5% (100% × [0.866 − 0.813] ÷ 0.813) higher than the average, and the 

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

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

emissions by coke burn-off accounts for more of the differences in the observed emissions than 

does throughput. Consequently, the average coke burn-off emissions factor would be preferred 

to the throughput-based emissions factor in this example.
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EPA Methods 5, 5B, and 5F are the most commonly used test methods for measuring PM emissions from 

CCUs. A typical Method 5 sampling train consists of a sampling probe, a heated line and filter, and a 

series of impingers that are kept in an ice bath. Method 5, 5B, or 5F sampling measures PM that is 

contained in the sampling probe and filter, which is often referred to as the ―front-half‖ or ―filterable‖ PM 

catch. PM that condenses in the impinger section of the sampling train is often referred to as the ―back 

half‖ catch or the ―condensable‖ PM. 

One of the main differences between EPA Method 5, 5B, and 5F is that the sampling line and filter are 

maintained at 250°F for Method 5 compared to 325°F for Methods 5B and 5F. Although generally not 

used for the CCU, there are other EPA test methods for PM. EPA Method 17 is similar to Method 5, 

except that the filter in the Method 17 sampling probe is within the stack so that the ―filterable‖ PM 

content is measured at the stack temperature. EPA Methods 201 and 201A are similar to Method 17, 

except that there is also a cyclone or other sizing device to remove particles greater than 10 μm in 

diameter prior to the filter so that Methods 201 and 201A determine PM10-FIL directly. 

Any of the Method 5, 17, or 201 variant methods describe only the procedures to determine the front-half 

or filterable PM catch. EPA Method 202 specifies the procedures to determine the mass of PM that 

condenses in the impingers (i.e., PM-CON). Although Method 202 generally references the use of 

Method 17 (or 201 or 201A) sampling trains, it may also be used in conjunction with EPA Methods 5, 

5B, or 5F. As the filter temperature in Method 5 is different from Methods 5B or 5F and also likely 

different from the filter temperature when using Method 17, the fraction of PM that is filterable versus 

condensable, which is a function of the sampling temperature, will also vary depending on the PM 

sampling method used. Because most of the data available for CCU were collected using EPA Methods 

5B or 5F, the condensable PM default emissions factor is most suitable to filterable data collected using 

Methods 5B or 5F, but may also be used in conjunction with Method 5 sampling data. If Method 202 is 

used, then the back-half catch can be considered PM-CON for the purposes of inventory reporting, 

regardless of the PM sampling method (i.e., sampling temperature) used. 

To summarize, Method 5 (including 5B or 5F) provides a measure of PM-FIL and Method 202 provides a 

measure of PM-CON. One important caveat to this is that, in Method 5F, ammonia sulfate particulates are 

determined and subtracted from the total PM catch to determine the non-sulfate PM emissions. Although 

the non-sulfate PM value may be used for compliance purposes (for the Petroleum Refinery NSPS or for 

Refinery MACT II), emissions reported for the inventory should include the total filterable PM catch. 

That is, the total PM catch before subtracting the sulfate PM emissions should be used to determine PMFIL for the purposes of reporting for the emissions inventory. The sulfate particulate PM should be 

considered to be 100% PM fine (i.e., PM2.5, which it PM that is 2.5 μm in diameter or less). Additional 

guidance on typical CCU particle size distributions is provided in the following subsection. 

5.1.2.2 PM Size Distribution Estimates for Catalytic Cracking Units 

AP-42 does not contain PM size distribution data for uncontrolled CCU PM emissions, but it does contain 

typical control device default control efficiencies for different types of PM emissions control devices. A 

PM Emissions Inventory Nomenclature

A complete PM emissions inventory includes the following components:

 PM10-PRI: ―Primary‖ PM emissions that are 10 μm in diameter or less. PM10-PRI = PM10-FIL + PM-CON.

 PM10-FIL: Filterable (or front-half catch) portion of the PM emissions that are 10 μm in diameter or less.

 PM-CON: Condensable PM (or back-half catch). All condensable PM is assumed to be less than 2.5 microns 

(μm) in diameter (PM2.5).

 PM2.5-PRI: ―Primary‖ PM emissions that are 2.5 μm in diameter or less. PM2.5-PRI = PM25-FIL + PM-CON.

 PM2.5-FIL: Filterable (or front-half catch) portion of the PM emissions that are 2.5 μm in diameter or less.
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limited number of particle size distribution studies 

were available in the docket to the Refinery MACT 

2 rule (40 CFR Part 63 Subpart UUU; Docket No. 

A-97-36, Item No. IV-D-19, Attachments 3, 6, and 

9). From these data, the mass fraction of total 

filterable PM (front-half catch) that is less than 2.5 

and 10 μm in diameter were determined and 

representative values are provided in Table 5-2. 

Table 5-2 also provides PM size distribution default 

values for controlled CCU. The default distribution 

factors for controlled CCU are based on the 

uncontrolled PM distributions and the control device 

default control efficiencies from AP-42. Because the projected size distribution of PM from different 

control devices was similar, one single set of distribution factors for controlled CCU are provided for 

controlled units. Control devices considered include tertiary cyclones, wet scrubbers, venturi scrubbers, 

ESP, and fabric filters. All PM-CON is assumed to be less than 2.5 μm. The size distribution data 

guidance presented here is specific to FCCU. Although catalyst size distribution for TCCU is expected to 

be different, use these same default factors TCCU unless site-specific size distribution data are available. 

Table 5-2. Default Size Distribution for Filterable PM from CCU 

Source Description

Fraction PM-FIL Less 

Than 2.5 μm

Fraction PM-FIL Less 

Than 10 μm

CCU, no post-regenerator PM control device 0.30 0.50

CCU, with post-regenerator PM control device (tertiary 

cyclone, wet scrubber, ESP, or fabric filter)

0.80 0.97

PM fine versus CCU fine

Fine particles that escape from the CCU regenerator 

are often referred to as ―fines‖ or ―FCCU fines‖ by 

refinery personnel. In this Refinery Emissions 

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 

―PM2.5‖ 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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5.1.3 Methodology Rank 5A for CCU Metal HAP Emissions Estimates 

During CCU processing, metals deposit on the catalyst particles and slowly deactivate the catalyst. Also 

during processing, the catalyst particles may slowly break into finer particles, which can no longer be 

recovered by the CCU regenerator internal cyclones. To maintain the desired catalyst activity, a portion of 

the recirculating catalyst (i.e., E-cat) is regularly withdrawn from the process and new (fresh) catalyst is 

added. New catalyst particles often have irregularities (spurs) that break off during catalyst recirculation. 

Consequently, the CCU fines that escape from the CCU regenerator typically have a slightly higher 

proportion of fresh catalyst than does the E-cat. This is significant because fresh catalyst will have less 

metal deposits than a catalyst that has been recirculating for days or weeks. Available paired observations 

of E-cat and CCU fines data indicate that the metal HAP concentration on the CCU fines are consistently 

Example 5-2: PM Emissions Inventory Calculations

The following information is available for a 50,000 barrels/calendar day (bbl/cd) CCU 

controlled with an ESP. On average, the CCU burned 36,000 pounds of coke per hour and 

operated for 8,700 hours in the reporting year. During the most recent source test using EPA 

Method 5F, the CCU had non-sulfate PM emissions of 0.7 pound per 1,000 pounds of coke 

burn-off and PM emissions (including sulfates) of 0.9 pound per 1,000 pounds of coke burnoff. The ―back-half‖ catch was also analyzed and was determined to be 0.45 pounds per 1,000 

pounds of coke burn-off. 

PM-FIL = 0.9 (lb/1,000 lb 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 for the sulfate PM, because all of this PM is 

expected to be less than 2.5 μm. For Method 5 or 5B, PM10-FIL = (fraction < 10 μm from 

Table 5-2) × PM-FIL. For Method 5F, PM10-FIL = (fraction < 10 μm from Table 5-2) × 

PMnon-sulfate + PMsulfate. Similar consideration is needed for the PM2.5-FIL calculation. 

Because the CCU is controlled, the appropriate fractions from Table 5-2 are 0.97 for the 

PM10-FIL calculation and 0.80 for the PM2.5-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

PM10-FIL = fraction < 10 μm from Table 5-2] × PMnon-sulfate + PMsulfate

= 0.97 × 109.6 + 31.3 = 137.6 tons/yr

PM10-PRI = PM10-FIL + PM-CON = 137.6 + 70.5 = 208.1 tons/yr

PM2.5-FIL = (fraction < 2.5 μm from Table 5-2) × PMnon-sulfate + PMsulfate

= 0.8 × 109.6 + 31.3 = 119.0 tons/yr

PM2.5-PRI = PM2.5-FIL + PM-CON = 119.0 +70.5 = 189.5 tons/yr
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lower than on the E-cat, supporting the hypothesis that the CCU fines contain a higher fraction of fresh 

catalyst than does the E-cat. 

If metal HAP emissions tests are performed, then site-specific metal HAP emissions factors should be 

determined (using the methods provided in Section 5.1.2, Methodology Ranks 3 and 4 for Catalytic 

Cracking Units,) and used directly to assess metal HAP emissions rates as a Rank 4 method. However, 

few facilities are expected to have performed metal HAP speciation emissions tests for their CCU. On the 

other hand, nearly all facilities have their equilibrium catalyst (i.e., the catalyst within the CCU, 

commonly referred to as ―E-cat‖) tested regularly for certain metal contaminants to monitor catalyst 

activity and replacement needs. Some facilities also have their CCU fines tested occasionally for metal 

HAP concentrations. 

If a facility has a site-specific PM emissions factor, then either CCU fines or E-cat analysis can be used as 

a means to calculate a site-specific HAP emissions rate using the methodology described in this section. 

This Methodology Rank 5A for CCU metal HAP emissions estimates is expected to be more 

representative than a default emissions factor, but not as good as a directly measured HAP-specific 

emissions factor. This method involves using the site-specific (non-sulfate, if available) PM emissions 

rate, and estimating the concentration of metal HAP on the emitted PM based on the concentration of 

metal HAP on the CCU fines or E-cat using to the procedures provided in this section. This method is not 

applicable for mercury (Hg) because it assumes the metals are associated with the catalyst particles and 

are not in the vapor phase. 

If metal HAP concentrations of CCU fines are available, then these data should be used (preferentially to 

E-cat data) to estimate the metal HAP concentration of the emitted PM. It is assumed that the emitted PM 

has the same metal HAP concentration as the CCU fines. If metal HAP concentrations for CCU fines are 

not available, then the metal HAP composition of the emitted PM can be estimated as 80% of the E-cat 

concentration. 

It is expected that CCU fine or E-cat concentration data will be available for nickel (Ni) and vanadium 

because these are the primary metals that poison CCU catalyst activity, but concentration data may be 

available for other metals as well. Table 5-3 lists metal HAP generally present in CCU fines. If the 

concentrations of these metal HAP are not determined for the CCU fines or E-cat, then they should be 

estimated using the measured Ni concentration and the concentration ratios for these other metal HAP as 

provided in Table 5-3. 

Equation 5-1 is a basic equation used to calculate metal HAP emissions based on the PM emissions rate 

and CCU fines metal HAP concentrations. 

mg k g

C

E PM FIL i

i

1,000,000 /

  

(Eq. 5-1) 

where: 

 Ei = Emissions rate of metal HAP ―i‖ (tons/yr)

PM-FIL = Filterable PM emissions rate from site-specific PM emissions factor; if EPA Method 

5F is used, then use PMnon-sulfate rather than PM-FIL (ton/yr) 

 Ci = Concentration of metal HAP ―i‖ on the CCU fines (milligrams per kilogram [mg/kg]) 

 = 0.8 × CE-cat,i, if only E-cat concentration are available 

 = CNickel × (factor from Table 5-3), if other metal HAP concentrations are not available 

Note that Ei = ENickel × (factor from Table 5-3) when other metal HAP concentration data are not 

available. 
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Table 5-3. Default Ratio of Metal HAP Composition of CCU Finesa

Metal HAP

Ratio of Metal HAP

to Nickel Concentration

Antimony 0.065

Arsenic 0.010

Beryllium 0.003

Cadmium 0.013

Chromium (total)b0.25b

Cobalt 0.052

Lead 0.08

Manganese 0.13

Nickel 1.00

Selenium 0.025c

a Concentration ratios are based on average 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 are 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. 
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5-9 

Although total chromium emissions have been found above detectable concentrations in the CCU 

regenerator vent, very few tests have been performed to determine Cr+6 emissions. The few tests that have 

been performed have not found Cr+6 above detection limits, but the detection limits have been comparable 

to the detected total chromium emissions. Based on these limited data, it is recommended that, for the 

CCU vent, Cr+6 emissions be estimated as 10% of the total chromium emissions. Thus, in the example 

calculation provided, Cr+6 emissions would be estimated to be 0.0026 tons/yr. 

Emissions of Hg should be estimated for the CCU; however, Hg emissions are not expected to be 

correlated with the PM emissions because very little, if any, of the Hg emissions are expected to be 

particulate bound. Mercury emissions are more likely correlated with the CCU throughput or coke burnoff rate. Thus, Hg emissions should be estimated independently of other HAP metals. If Hg emissions 

data are available based on source test data for the site, then the source test data can be used, as a 

Methodology Rank 4 for metal HAP emissions estimates, to develop a site-specific emissions factor. 

Otherwise, Hg emissions should be estimated using a default (Rank 5B) emissions factor rather than 

using this Rank 5A method. 

5.1.4 Methodology Rank 5B for Catalytic Cracking Units 

For most organic HAP (e.g., formaldehyde, benzene, benzo[a]pyrene, dioxin/furans) and other pollutants 

such as hydrogen cyanide and Hg, default emissions factors may be all that are available. When direct 

Example 5-3: Methodology Rank 5A for Metal HAP Emissions Estimates

Following the previous example, PMnon-sulfate emissions were calculated to be 109.6 

tons/yr. If only Ni concentration for E-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: 

CNickel = 0.8 × 1,200 = 960 mg/kg

The following equation should be used to calculate the emissions rate of Ni from the PM 

emissions rate on estimated Ni concentration:

ENickel = 109.6 tons/yr × (960 mg/kg) ÷ (1,000,000 mg/kg) = 0.105 tons/yr

The following equations should be used to estimate the emissions rate of other metal HAP 

from the emissions rate of Ni: 

EAntimony = 0.105 tons/yr × 0.065 = 0.0068 tons/yr

EArsenic = 0.105 tons/yr × 0.010 = 0.00105 tons/yr

EBeryllium = 0.105 tons/yr × 0.003 = 0.0003 tons/yr 

ECadmium = 0.105 tons/yr × 0.013 = 0.0014 tons/yr

EChromium = 0.105 tons/yr × 0.25 = 0.026 tons/yr

ECobalt = 0.105 tons/yr × 0.052 = 0.0055 tons/yr

ELead = 0.105 tons/yr × 0.08 = 0.0084 tons/yr 

EManganese = 0.105 tons/yr × 0.13 = 0.014 tons/yr

ESelenium = 0.105 tons/yr × 0.025 = 0.0026 tons/yr
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5-10 

emissions monitoring or site-specific emissions factors are not available, then the default emissions 

factors presented in Table 5-4 should be used to calculate the emissions from the CCU regenerator vent. 

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

CAS No. Compound 

Emissions Factor

(lb/MMbbl)a

106-99-0 1,3-Butadiene 0.025

75-07-0 Acetaldehyde 25

71-43-2 Benzene 19

57-12-5 Cyanide 32

50-00-0 Formaldehyde 480

74-90-8 Hydrogen cyanide 100

108-95-2 Phenol 21

108-88-3 Toluene 1.4

1330-20-7 Xylene 3.2

100-41-4 Ethylbenzene 0.24

67-64-1 Acetone 4.8

107-02-8 Acrolein 1.0

74-83-9 Bromo-methane 2.1

75-15-0 Carbon disulfide 0.56

75-09-2 Methylene chloride 6.7

75-69-4 Trichloro-fluoro-methane 2.4

57117-31-4 Polychlorinated dibenzofurans 5.5E-07

57117-44-9 Hexachlorodibenzofuran 1.1E-06

7647-01-0 Hydrogen chloride 140

83-32-9 Acenaphthene 0.0033

208-96-8 Acenaphthylene 0.13

120-12-7 Anthracene 0.10

56-55-3 Benzo(a)anthracene 0.0011

50-32-8 Benzo(a)pyrene 0.0106

205-99-2 Benzo(b)fluoranthene 0.0035

192-97-2 Benzo(e)pyrene 0.00085

191-24-2 Benzo(g,h,i)perylene 0.0046

207-08-9 Benzo(k)fluoranthene 0.0027

218-01-9 Chrysene 0.0033

53-70-3 Dibenz(a,h)anthracene 0.0042

206-44-0 Fluoranthene 0.22

86-73-7 Fluorene 0.058

193-39-5 Indeno(1,2,3-cd)pyrene 0.0044

91-20-3 Naphthalene 1.1

85-01-8 Phenanthrene 0.35

129-00-0 Pyrene 0.0033

91-57-6 2-Methylnaphthalene 0.026

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

Regenerator Vent (continued)

CAS No. Compound 

Emissions Factor

(lb/MMbbl)a

65-85-0 Benzoic acid 79

117-81-7 Bis(2-ethyl hexyl) phthalate 2.8

84-74-2 di-n-Butyl phthalate 2.0

84-66-2 Diethyl-phthalate 0.28

7439-97-6 Mercury 0.25

a Emissions factors for CCU controlled for organics in pounds per million barrels of CCU 

capacity.

Based on the lack of data for PAH and furan emissions, the emissions estimates for these compounds 

have high uncertainties, likely an order-of-magnitude either high or low. The California Air Resources 

Board (CARB), with EPA’s support, conducted an emissions source test at a complete combustion FCCU 

(without a post-combustion device). The only dioxin isomer detected in all runs was octachloro-dibenzop-dioxin (OCDD); octachloro-dibenzo-furan (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 polychlorinated biphenyls (PCBs) isomers were below 

detection limits. This additional source test was not included in the development of the Petroleum 

Refinery MACT II emissions factors, but it confirms low emissions of dioxins/furans and PCBs from the 

CCU catalyst regenerator vent. 

5.2 Fluid Coking Units 

Coking units use heat to thermally crack heavy hydrocarbon streams to form lighter, more useful 

distillates such as heating oils or gasoline. There are three basic types of coking units: traditional fluid 

coking units, flexicoking units, and delayed coking units. Traditional fluid coking units are one of the 

largest vent emissions sources at a refinery, being comparable to emissions from the CCU regenerator. 

However, there are only a handful of traditional fluid coking units currently in operation in the United 

States. Flexicoking units, which are also rare, do not have a direct atmospheric vent. Instead, these units 

produce a low heating value content syngas that can be subsequently used as fuel in process heaters or 

boilers. Emissions from the combustion of flexicoking syngas should be determined using the methods 

described in Section 4, Stationary Combustion Sources. Nearly all new coking units being built at 

refineries are delayed coking units, which are discussed further in Section 5.3. 

Fluid coking units have several similarities to a CCU. The coking unit contains a burner section and a 

reactor section. In the burner section, heat for the coking reaction is supplied by burning a portion of the 

coke that is produced. In the reactor, fine coke particles are produced as a result of the thermal cracking 

process. Prior to exiting the coking unit, coke particles entrained with the flue gases are removed by 

internal cyclone separators and recovered as a product, with a portion of the produced coke recycled to 

the burner section. The coke burner is operated with limited air—enough to combust the diverted coke (to 

provide heat for the coking reaction)—but limited enough to prevent O2 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 SO2 in the flue gas. The 

fluid coking unit vent releases a wide variety of pollutants, including PM, SO2, NOx, CO, VOC, metal 

HAP, organic HAP, and ammonia. 

Special considerations should be taken to estimate the amount of total sulfur compounds present in fuel 

gas generated from the fluid coking unit. Coking units have been found to produce appreciable quantities 
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of methyl mercaptans and other reduced sulfur compounds that are not efficiently removed from the sour 

gas as H2S. Consequently, SO2 emissions from fuel gas combustion devices receiving fuel gas generated 

from a fluid coking unit should account for this additional sulfur that is not measured by H2S monitors 

(see Section 4, Stationary Combustion Sources, for further details). 

Note also that fluid coking units, in particular, may have significant fugitive PM emissions from the 

handling of the produced coke. Methodologies for these fugitive PM emissions are described in Section 

11, Fugitive Dust Sources. 

5.2.1 Methodology Ranks 1 and 2 for Fluid Coking Units 

For SO2, NOx, CO, and CO2, it is anticipated that most units will have CEMS for measuring the 

composition of the exhaust gas. Gas flow rate may be directly monitored, but in many cases, the exhaust 

flow rate will be calculated based on air blast rates and composition monitors (similar to F factors). 

5.2.2 Methodology Ranks 3 and 4 for Fluid Coking Units 

Source tests should be available for PM (and perhaps SO2 and NOx, if not continuously monitored) so that 

site-specific emissions factors should be available. It is anticipated that the pollutant emissions will 

primarily be a function of the coke burn rates; however, limited data are available to assess this 

hypothesis. 

5.2.3 Methodology Rank 5 for Fluid Coking Units 

We do not have data to provide default emissions factors for fluid coking units. 

5.3 Delayed Coking Units 

Coking units use heat to thermally crack heavy hydrocarbon streams to form lighter, more useful 

distillates such as heating oils or gasoline. Most of the coking units in operation within the United States 

are delayed coking units. Unlike most other refinery operations that are continuous, delayed coking units 

are operated in a semi-batch system. Most delayed coking units consist of a large process heater, typically 

two coking drums, a single product distillation column, and coke cutting equipment. The process heater 

heats the heavy feed oil to near cracking temperatures, and then the oil is fed to one of the coking drums. 

As the cracking reactions occur, coke is produced in the drum and begins to fill the drum with sponge-like 

solid coke material. Once filled, the feed is diverted to the second coke drum. The full coke drum is 

cooled by slowly adding water to the vessel, which quickly turns to steam, and the steam helps to cool 

and purge organics in the coke matrix. After the coke drum is sufficiently cooled, the drum is opened and 

the coke is removed from the vessel using high-pressure water. Once the coke is cut out of the drum, the 

drum is closed, and prepared to go back online. A typical coke drum cycle is typically 14 to 18 hours 

from start of feed to start of feed. 

During the reaction process, the delayed coking unit is a closed system. When the coke drum is taken offline, the initial steaming process gas is also recovered through the unit’s product distillation column. As 

the steaming cycle continues, the gas is sent to a blowdown system to recover the liquids. The gas is 

typically sent to a flare or other control device but may be released to the atmosphere. Near the end of the 

steaming process, a vent is opened to allow the remaining steam and vapors to be released into the 

atmosphere prior to opening the drum. Emissions from delayed coking units are primarily CH4 and 

ethane, but include a variety of volatile and semi-volatile organics. 

Although this section primarily addresses the vent emissions from the delayed coking unit, fugitive 

emissions are also released from the delayed coking unit when the coke drum is opened and the coke is 

cut from the drum. During this cutting process, hydrocarbons that were retained in the internal coke pores 

will be released into the atmosphere. The cutting water will absorb some hydrocarbons, so this water will 

also become a source of organic emissions. PM emissions from the coke cutting operations and 
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subsequent coke storage and handling facilities should be estimated using the methodologies described in 

Section 11, Fugitive Dust Sources. Organic emissions from impoundments or ponds used to store the 

cutting liquids should be estimated using the methodologies described in Section 7.2.5, Equalization 

Tanks. 

As with fluid coking units, special considerations should be taken to estimate the amount of total sulfur 

compounds that are present in fuel gas generated from delayed coking units. Coking units have been 

found to produce appreciable quantities of methyl mercaptans and other reduced sulfur compounds that 

are not efficiently removed from the sour gas as H2S. Consequently, SO2 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 H2S monitors (for more detail, see Section 4, Stationary 

Combustion Sources). 

5.3.1 Methodology Ranks 1 and 2 for Delayed Coking Units 

Delayed coking units vent periodically and only for relatively short periods of time during 

depressurization of the unit after the coking cycle. As such, delayed coking units are not expected to use 

CEMS. If CEMS are used, Methodology Rank 1 for process vents could be used. The gas flow rate 

cannot be estimated using F factors, so Methodology Rank 2 for process vents is not applicable to the 

delayed coking unit vent. 

5.3.2 Methodology Ranks 3 and 4 for Delayed Coking Units 

A limited number of source tests have recently been performed on delayed coking unit vents. For 

facilities that have performed source tests, site-specific emissions factors can be developed and used. It is 

anticipated that the pollutant emissions will be a function of coking vessel void volume and initial vent 

pressure; however, for a particular delayed coking unit, these variables are fairly constant and a per cycle 

emissions rate from the source test can be used. 

5.3.3 Methodology Rank 5 for Delayed Coking Units 

Source test data are available for five delayed coking units (SCAQMD, 2004a, 2004b, 2004c, and 2004d; 

URS Corporation, 2008). From these data, average concentrations and emissions factors were developed 

(see Table 5-5). While the emissions are expected to be higher for units that start to depressure at higher 

coke drum pressures, the emissions were also dependent on the time steaming occurred prior to 

depressurization and the temperature of the drum (how much additional steam was generated after the 

steam vent was opened. Due to the complexities of the delayed coking unit steam vent and the limited test 

data available, correlations to account for different process variables (venting pressure, drum temperature 

and steaming time prior to venting) are not currently available, and the default emissions factors in 

Table 5-5 should be used when site-specific measurement or test data are not available. 

Table 5-5. Average Vent Concentrations and Emissions Factors for Delayed Coking Unit Vents 

CAS No. Compound

Vent Concentration

(ppmv, wet basis)

Emissions Factor 

(lb/cycle)

a

106-99-0 Methane 7,600 200

75-07-0 Ethane 1,800 42

VOC Nonmethane/nonethane VOC 1,600 57

71-43-2 Benzene 9.4 0.1

108-88-3 Toluene 24 5.6

100-41-4 Ethylbenzene 1.7 0.03

1330-20-7 Xylene 15 0.24

(continued)
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Table 5-5. Average Vent Concentrations and Emissions Factors for Delayed Coking Unit Vents 

(continued)

CAS No. Compound

Vent Concentration

(ppmv, wet basis)

Emissions Factor 

(lb/cycle)

a

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 0.64

83-32-9 Acenaphthene 0.070

208-96-8 Acenaphthylene 0.004

120-12-7 Anthracene 0.15

56-55-3 Benzo(a)anthracene 0.031

50-32-8 Benzo(a)pyrene 0.027

205-99-2 Benzo(b)fluoranthene 0.007

191-24-2 Benzo(g,h,i)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.

5.4 Catalytic Reforming Units 

The CRU is a series of catalytic reactors that turn naphtha 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: 

continuous, cyclic, and semi-regenerative. Continuous CRU catalyst regenerators operate continuously 

with a small slip stream of catalyst being re-circulated between the CRU and the regenerator. In cyclic 

CRU, there is essentially an extra CRU reactor. When regeneration is needed, one reactor is cycled offline 

and regenerated. The regeneration of the offline reactor is a batch process. When complete, the reactor is 

returned to service, and the next reactor is cycled offline and regenerated. This process continues until all 

reactors are regenerated. In a cyclic CRU, regeneration may occur for 1,000 to 4,000 hours per year. The 

semi-regenerative CRU operates without regeneration for 8 to 18 months, then the entire unit is brought 

offline, and the entire unit is regenerated. The overall regeneration cycle typically takes 1 to 2 weeks. 

During regeneration, there are several potential atmospheric vents. Although the location of the emission 

points might vary depending on whether catalyst regeneration is continuous, cyclic, or semi-regenerative, 

there are three times or locations during the regeneration process that emissions can occur regardless of 

the regenerator type. For continuous regeneration, venting occurs from three distinct vents as follows: (1) 

the initial depressurization and purge vent; (2) the coke burn pressure control vent; and (3) the final 
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catalyst purge vent. For cyclic and semi-regenerative units, the initial depressurization and purge vent is 

often a distinct release point, but the coke burn and final catalyst purge emissions are commonly released 

at different times during the regeneration cycle from a single atmospheric vent. 

The initial depressurization and purge cycle removes the hydrocarbons from the catalyst prior to CRU 

catalyst regeneration. The vent gases from this initial purge may have high levels of organic HAP such as 

benzene, toluene, xylene, and hexane. The gases generated from the initial depressurization and purge 

cycles are typically vented to the refinery fuel gas system or directly to a combustion device (e.g., flare or 

process heater). The coke burn cycle is typically the largest (in terms of gas volume) emissions source of 

the overall catalyst regeneration cycle. The primary HAP contained in the CRU coke burn vent are 

hydrogen chloride (HCl) and chlorine (Cl2), which are produced when the water formed during 

combustion leaches chloride atoms from the CRU catalyst. The final purge and reduction cycle removes 

O2 and any remaining chlorination agent from the system and reduces the catalyst prior to returning the 

CRU catalyst to the reforming process or bringing the unit back online. The vent gases from this final 

purge may have low levels of the chlorinating agent (usually an organic HAP such as trichloroethene of 

perchloroethene) and residual HCl or Cl2 remaining in the system. The final purge gases are typically 

vented into the atmosphere or to the refinery fuel gas system depending on the O2 content of the purge 

gases (safety considerations restrict the venting of O2-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 emissions from the CRU catalyst regeneration vent because 

venting is infrequent, the vent flow rates are slow and usually variable, and the vents have small 

diameters. All of these factors make traditional source testing difficult. Most of the available data are for 

HCl and Cl2 emissions from uncontrolled coke burn (20 data points are available for HCl emissions; 10 

data points are available for Cl2). Few data were available for a limited number of organic chemicals. 

These data are compiled in the Background Information Document (BID) for the proposed Petroleum 

Refinery MACT II rule (U.S. EPA, 1998b). During the Petroleum Refinery MACT II project, CARB, 

with funding assistance from EPA, conducted a source test of a continuous CRU catalyst regenerator 

coke-burn vent for dioxins/furans, PCBs, and PAHs. The results from this source test, which were not 

available at the time for inclusion into the Petroleum Refinery MACT II BID, were used to develop 

emissions factors for these compounds. The emissions factors used for the uncontrolled coke burn 

emissions are presented in Table 5-6. These emissions factors are normalized by the CRU process 

throughput and are assumed to apply equally for all types of CRU regenerators. 

The most prevalent control device used in association with the coke-burn vent is a wet scrubber. The 

dioxin/furan emissions source tests and the volatile organics were performed on a system controlled by a 

wet scrubber. Because of the limited solubilities of these chemicals and the scrubbing medium 

recirculation rate used for wet scrubbers on this vent stream, the scrubber is assumed to be ineffective at 

reducing the emissions of these chemicals. Therefore, the same emissions factor is recommended for 

these chemicals for both controlled and uncontrolled CRU. The wet scrubbers are expected to reduce the 

emissions of HCl and Cl2. The wet scrubbers used for these vents were characterized into two classes: 

single-stage scrubbers and multiple-stage scrubbers. Single-stage scrubbers are estimated to reduce HCl 

and Cl2 emissions by 92%, and the multiple-stage scrubbers are estimated to reduce HCl and Cl2 

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. 
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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)b5.7E-09

1336-36-3 Total polychlorinated biphenylsc2.6E-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 4.2d

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-dioxin used for risk 

analysis; specific dioxin/furan isomer emissions data are available.

c Sum total of all chlorinated biphenyl emissions 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 pollutants.

5.5 Sulfur Recovery Plants 

All crude oils contain some sulfur compound impurities. Sulfur compounds in crude oil are converted to 

H2S in the cracking and hydrotreating processes of the refinery. The H2S in the generated gas streams is 

removed from the process vapors using amine scrubbers. The amine scrubbing solution is subsequently 

heated to release the H2S to form an H2S rich ―acid gas‖ that is treated in the sulfur recovery plant to yield 

high-purity sulfur that is then sold as product. Most sulfur recovery plants use the Claus reaction and are 

commonly referred to as Claus units or Claus sulfur recovery plants. There are a couple of other types of 

sulfur recovery plants at smaller refineries, but all larger sulfur recovery plants employ Claus units. The 

exhaust gas from the sulfur recovery unit (SRU) is commonly referred to as ―tail gas.‖ The sulfur 
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5-17 

recovery plant consists of one or more SRU operated in parallel and may also contain one or more 

catalytic tail gas treatment units and/or a thermal oxidizer to combust the tail gas. 

The primary HAP components of the final sulfur plant vent are carbonyl sulfide (COS) and carbon 

disulfide (CS2). 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 H2S 

may also be released during the process. Sulfur recovery plant vents are commonly controlled by a 

thermal oxider to oxidize unreacted H2S or H2S in sweep gas from the sulfur pits to SO2. When the sulfur 

recovery plant is in operation, the sulfur plant vent flow rate is fairly small so that the SO2 emissions from 

the sulfur recovery plant are also relatively small. If the sulfur recovery plant must be taken offline due to 

an upset or malfunction, the sour gas may be temporarily directed to a flare or to the thermal oxidizer. 

Under these cases, the SO2 emissions can be very large. As such, it is critical to include accurate 

accounting of SO2 emissions during startup, shutdown, or malfunction (SSM) events associated with the 

sulfur recovery plant. The sulfur plant sour gas feed may also contain small amounts of light organics. 

Therefore, it is important to account for the hydrocarbons in the sulfur recovery plant feed when 

estimating emissions from the sulfur recovery plant, particularly from Lo-Cat® or other sulfur recovery 

plants that may have atmospheric vents without thermal destruction. 

5.5.1 Methodology Ranks 1 and 2 for Sulfur Recovery Plants 

It is anticipated that most sulfur recovery plants, particularly Claus sulfur recovery plants, will have 

continuous SO2 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 H2S 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 H2S to SO2), 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 H2S or reduced sulfur compound 

concentrations instead of SO2. Again, H2S emissions estimates should be provided for sulfur recovery 

plants. 

5.5.2 Methodology Ranks 3 and 4 for Sulfur Recovery Plants 

Emissions estimates can be made from inlet flow measurements and assumed recovery efficiencies. For 

most Claus units, especially those with tail gas treatment/recovery units, a mass balance approach for 

sulfur is expected to yield emissions estimates with high uncertainties (e.g., when two large numbers are 

subtracted so that the difference is only a few percentages of the original values, the uncertainties in the 

original values may be as large as the difference). A three-stage Claus unit is expected to have sulfur 

recovery efficiencies of 95% to 97%. Combining a three-stage Claus unit with a tail gas treatment unit, 

sulfur recovery efficiencies are expected to be 99.7% to 99.9%. With these types of recovery efficiencies, 

the mass balance approach (i.e., calculating SO2 or other sulfur compound emissions from the difference 

of the sulfur feed rate to the SRU and the sulfur produced) will have significant uncertainty. 

Consequently, measurement of the mass feed rate of sulfur to the sulfur recovery plant and an assumed 

sulfur recovery efficiency (based on the number of Claus reactors in series and the presence or absence of 

a tail gas treatment unit) are likely to be more accurate than using a mass balance approach when 

calculating sulfur compound emissions from the sulfur recovery plant. A similar approach can be used to 

calculate CO2 emissions from the sulfur recovery plant, particularly in systems controlled with a flare or 

thermal oxidizer. Because nearly all of the CO2 or hydrocarbons introduced to the sulfur recovery plant 

will exit as CO2, measuring inlet C content and flow rate of gases to the sulfur recovery plant can be used 

to accurately estimate CO2 emissions. 
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5-18 

Given the high uncertainty expected in engineering/mass-balance calculations for sulfur recovery plants, 

site-specific emissions factors may be as or more useful than using an engineering/mass-balance approach 

for calculating emissions from sulfur recovery plants, particularly sulfur compound emissions. Sitespecific emissions factors are also recommended for reductive tail gas treatment units not followed by an 

incinerator and for non-Claus sulfur recovery plants. Evaluation of light hydrocarbons should be 

addressed in these systems. For example, Lo-Cat® systems use an oxidation tank in which H2S is 

chemically oxidize to SO2. Any light hydrocarbons entrained in the sour gas are expected to be released in 

the vent from the oxidation tank. The emissions from this oxidation tank should be characterized and 

reported for the sulfur recovery plant. 

5.5.3 Methodology Rank 5 for Sulfur Recovery Plants 

The Petroleum Refinery MACT II BID (U.S. EPA, 1998b) presents a range of total sulfur HAP 

compounds emissions factors for SRU controlled by an incinerator. Based on the data presented and 

additional concentration data submitted by the National Petrochemical and Refiners Association, it was 

assumed that 75% of the sulfur HAP emitted was COS and 25% was CS2. 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 5.85b

75-15-0 Carbon disulfide 0.040 2.00b

Note: lb/lton = pounds 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; however, there are limited data for these vents, so 

default emissions factors are not available. For these process vents, this section provides a brief 

description of the process, the vent source, and the primary pollutants associated with the process vent. 

For all of these sources, the general hierarchy of methods as presented in Table 5-1 in the introduction to 

this chapter is applicable. The purpose of this section is to provide default emission factors for 

Methodology Rank 5 for these particular process vents. 

5.6.1 Hydrogen Plant Vents 

Steam CH4 reforming is the primary means by which H2 is produced at a petroleum refinery. Refinery 

fuel gas is typically used as the feedstock to the H2 plant. The feedstock is combined with steam in a 

reactor at high temperatures (750°C to 800°C) to produce a mixture of H2 and CO. A water–gas shift 

reaction occurs in a series of catalytic reactors to convert the CO and steam to CO2 and H2. Finally, the 

CO2 is removed from the H2 product using either a liquid absorption system or pressure swing absorption. 

The H2 plant vent contains relatively high levels of methanol and may also contain formaldehyde and 

other light hydrocarbons; however, no default emission factors are available at this time for the hydrogen 

plant vent. 

5.6.2 Asphalt Plant Vents 

Asphalt blowing is used for polymerizing and stabilizing asphalt to improve its weathering characteristics. 

Air-blown asphalts are used in the production of asphalt roofing products and certain road asphalts. Air 
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5-19 

blowing of asphalt may be conducted at petroleum refineries, asphalt processing plants, and asphalt 

roofing plants. Asphalt blowing involves the oxidation of asphalt flux by bubbling air through liquid 

asphalt flux at 260°C (500°F) for 1 hour to 10 hours. The amount of time depends on the desired 

characteristics of the product, such as the softening point and the penetration rate. Shorter periods are 

typically used for road asphalt; longer periods are used for roofing asphalt. Asphalt blowing results in an 

exothermic reaction that requires cooling. The emissions from a blowing still are primarily organic 

particulate with a fairly high concentration of gaseous hydrocarbon and polycyclic organic matter. The 

blowing still gas is commonly controlled with a wet scrubber to remove sour gas, entrained oil, 

particulates, and condensable organics and/or a thermal oxidizer to combust the hydrocarbons and sour 

gas to CO2 and SO2. 

Overall PM and TOC emissions factors for asphalt blowing are provided in Section 11.2 of AP-42 (U.S. 

EPA, 1995a); these emission factors are also presented here in Table 5-8. 

Table 5-8. Emission Factors for Asphalt Blowing (U.S. EPA, 1995a) 

Operation

Filterable PMaTOCb

Emission Factor (Data Quality Rating)

(lb/ton asphalt processed)

Uncontrolled

Saturant asphalt c6.6 (E) 1.3 (E)

Coating asphalt d24 (E) 3.4 (E)

Controlled

Saturant asphalt c0.27 (D) 0.0043 (D)

Coating asphalt d0.81 (D) 0.017 (D)

a

Filterable (front-half) particulate matter catch using EPA Method 5A sampling at 108°F.

b

Total organic compounds measured using EPA Method 25A.

c

Saturant blow of 1.5 hours.

d Coating blow of 4.5 hours.

Tumbore (1998) provided an additional summary and evaluation of emissions from controlled asphalt 

blowing. Some key findings from this review were: 

 The AP-42 emission factors ignore emissions of SO2, which are usually the largest emissions 

from the process. For gas fired control systems, H2S resulting from the asphalt blowing reaction 

accounted for 70 to 80 % of the SO2 emissions, with the remainder attributable to entrained or 

condensed oil. 

 The AP-42 emission factors ignore emissions of HCl, which are important when ferric chloride is 

used as a catalyst in the process. 

The Emission Inventory Guidebook 2006 (EMEP/CORINAIR, 2006) provides the following speciation 

profile for organic emissions from asphalt blowing (see Table 5-9). Although not specified, it is assumed 

that this speciation profile in Table 5-9 represents uncontrolled asphalt blowing emissions. 
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5-20 

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

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 Factora

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

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-03 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

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

CAS Number Substance

Mean Emissions Factora

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

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 fumes, lb/MMBtu = pounds per million British thermal units

a

Bold italic values indicate that all test runs were below detection limit.

b

Source: Hansell and England, 1998.

5.6.3 Coke Calcining 

Coke calcining is one of the processes tested by API and WSPA for which emissions factors were 

developed (Hansell and England, 1998). The average emissions factors for a coke calcining unit 

controlled with a spray dryer and fabric filter are presented in Table 5-11. 

Table 5-11. Summary of Emissions Factors for Controlled Coke Calcining 

CAS Number Substance

Mean Emissions Factora

lb/ton cokeblb/MMBtub

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

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)anthracene 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

(continued)
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5-22 

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

CAS Number Substance

Mean Emissions Factora

lb/ton cokeblb/MMBtub

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

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

(continued)
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5-23 

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

CAS Number Substance

Mean Emissions Factora

lb/ton cokeblb/MMBtub

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

6D 123478 = 1,2,3,4,7,8-Hexachlorodibenzo-p-dioxin; 6D 123678 = 1,2,3,6,7,8-Hexachlorodibenzo-p-dioxin; 6D 

123789 = 1,2,3,7,8,9-Hexachlorodibenzo-p-dioxin; 7D 1234678 = 1,2,3,4,6,7,8-Heptachlorodibenzo-p-dioxin; 8D 

= Octachlorodibenzo-p-dioxin; 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-Heptachlorodibenzofuran; 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; underlined 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 compressed and recovered for use as fuel gas or 

they may be vented to a thermal destruction device (thermal oxidizer or flare). Either of these scenarios 

would be considered a ―controlled‖ blowdown system. In an ―uncontrolled‖ blowdown system, the 

uncondensed gases are vented directly to the atmosphere. For blowdown gases that are recovered as fuel 

gas, the emissions from these gases would be accounted for in the emissions projected for stationary 

combustion devices (see Section 4). 

AP-42 (U.S. EPA, 1995a) contains a default emission factors uncontrolled blowdown systems as well as 

blowdown systems that recover the vapors for destruction in a flare. For systems controlled by a flare, the 

measurement methodologies provided in Section 6, Flares, should be used preferentially over these 

default emission factors, but these factors may provide an estimate of the portion of the flare’s emissions 

originate from blowdown gases. The AP-42 default emission factors for blowdown systems are provided 

in Table 5-12. 
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5-24 

Table 5-12. Default Emissions Factors for Blowdown Systems 

Process Description Pollutant

Emissions Factora

(lb/103barrel of refinery 

feed) Rating

Uncontrolled blowdown Total hydrocarbonsb580 C

Blowdown System with 

vapor recovery and flaring

Carbon monoxide 4.3 C

Nitrogen oxides 19 C

Sulfur dioxide 27 C

Total hydrocarbonsb0.8 C

a

Source: U.S. EPA, 1995a.

b Total hydrocarbon may be estimated as a surrogate for VOC. (Overall, less than 1 weight % of total hydrocarbon 

emissions is methane.)

5.6.5 Vacuum Producing Systems 

Vacuum producing systems include reciprocating, rotary or centrifugal blower or compressors, or any jet 

ejector or device that takes suction from a pressure below atmospheric and discharges against atmospheric 

pressure. Depending on the vacuum producing system design, gases from the system may be released 

directly to the atmosphere or may be condensed, to the extent possible, using a condenser. The condensed 

liquid is gathered in a ―hot well‖ or ―accumulator‖ and the uncondensed gases are discharged to a control 

device or directly to the atmosphere. The vacuum producing system associated with the vacuum 

distillation column is typically the largest vacuum producing system at a petroleum refinery; vacuum 

producing systems may also be used to evacuate reactor vessels or vacuum trucks. AP-42 provides a total 

hydrocabon emission factor for the vacuum distillation column condenser. Speciation of the gases can be 

estimated based on the composition in the condensed liquids and assuming the gases are saturated (in 

equilibrium) with the condensed liquid. If the emissions are controlled, a control device efficiency 

correction can be used to estimate the controlled emissions. 

Table 5-13. Default Emissions Factor for Vacuum Producing Systems 

Process Description Pollutant

Emissions Factora

(lb/103barrel

of vacuum feed) Rating

Vacuum producing system 

on vacuum distillation 

column, uncontrolled

Total hydrocarbonsb50 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 1.0 Section 6—Flares 

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6-1 

6. Flares 

Flares are point sources used at petroleum refineries to destroy organic compounds in excess refinery fuel 

gas, purged products, or waste gases released during startups, shutdowns, and malfunctions. Most flares 

have a natural gas pilot flame and use the fuel value of the gas routed to the flare to sustain combustion. If 

the heating value of the flare gas falls below certain values (for steam or air assisted flares, typically 300 

British thermal units per standard cubic feet [Btu/scf]), then natural gas may be added to the flare gas to 

maintain the appropriate heating value for good combustion. Emissions from flares consist of a fraction of 

the hydrocarbons in the flare gas (e.g., CH4, CO, VOC, and specific organic HAP) that are not combusted 

in the flare; SO2 resulting from the oxidation of sulfur compound impurities, such as H2S, in the gas 

stream; and CO2 from the combustion process. Flares are also expected to produce NOx emissions and 

may produce PM (soot) if combustion conditions are not adequate. A complete emissions inventory will 

include estimates for all these compounds (the specific organic HAP will vary based on the composition 

of the gas being flared). 

Accurate estimates of emissions from flares are difficult to obtain because they do not lend themselves to 

conventional emissions-testing techniques, and only a few attempts have been made to characterize flare 

emissions. Therefore, to date, there are limited direct emissions test data for flares. Recent developments 

in testing protocols, such as the DIAL technique, provide a direct emissions measurement technique for 

flares. However, DIAL measurements provide only a snapshot in time. Unless the flow and composition 

of the flare gas is highly stable, inaccuracies build as these measurements are extrapolated to annual 

emissions rates. Continuous monitoring of the gas stream prior to combustion in the flare is generally the 

most accurate means of assessing flare emissions. One difficulty with this approach is that flare gas 

composition and flow are highly variable, and the monitors are calibrated to detect compositions or flows 

within a certain range or span, so if the flow or composition is outside the instrument’s range, then 

inaccuracies in the measurement data result. In addition, because the monitors are evaluating the stream 

of gas going to the flare, assumptions must be made regarding flare efficiency to determine the emissions 

following combustion. Engineering calculations are another methodology that can be used to assess 

certain release events. For example, if a pressure relief valve on a tank opens, then the volume of gas 

released can be calculated based on the pressure at which the valve opens, the pressure at which the valve 

recloses, and the volume of the tank. Product knowledge of the material in the tank can be used to 

estimate the composition of the gas vented. Some emissions factors are available, but these have high 

uncertainty. EPA concludes that direct measurement methods are best used to develop site- or flarespecific emissions factors or to verify the combustion efficiency of a specific flare under certain 

conditions; however, they are not particularly useful in developing an emissions inventory for flares. 

Table 6-1 summarizes the hierarchy of flare emissions estimation techniques. Within a given 

measurement method (or rank), there may be alternative methods for determining the constituent-specific 

emissions; these compositional analysis methods are provided in order of accuracy. Each refinery will 

likely use a mixture of different methods. For example, Methodology Rank 1 for flares may be used for 

events that are directly monitored and are fairly routine releases, but Methodology Rank 4 for flares may 

have to be used to estimate emissions for unusual events. The remainder of this section provides 

additional detail and guidance regarding the implementation of these methods. 
Version 1.0 Section 6—Flares 

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6-2 

Table 6-1. Summary of Flare Emissions Estimate Methodologies 

Rank Measurement Method Additional Data Needed

1 Continuous composition and flow rate

monitoring of the gas sent to the flare

 Combustion efficiency (based on results of a direct 

measurement test, if available, or a default 

assumption)

2 Continuous flow rate monitoring and periodic 

compositional analysis

 Representative sample (grab or integrated)

 Assumed combustion efficiency

3 Continuous flow rate and heating value 

monitoring

 Emissions factors based on heating value

4 Engineering calculations  Process knowledge of units connected to flare (e.g., 

volume, composition of process streams)

 Temperature and pressure monitoring data or other 

process operating data as needed

 Assumed combustion efficiency

5 Emissions factors based on energy 

consumption

 Flow estimates (not continuous)

 Heat value estimates (not continuous)

6 Default emissions factors based on refinery 

or process throughput

 Refinery or process throughput

6.1 Methodology Rank 1 for Flares 

Methodology Rank 1 for flares includes continuously measuring composition and flow of gas sent to the 

flare. For a flare, the most likely pollutants to be estimated using Methodology Rank 1 are SO2 and total 

hydrocarbons (or VOC). For example, a reduced sulfur or total sulfur monitor can be used to characterize 

the sulfur content of the gas being combusted in the flare. Similarly, monitoring of the total hydrocarbon, 

VOC, or specific organic HAP content in the flare gas can be used to assess the emissions of these 

pollutants. However, because these monitors measure the concentrations in the gas sent to the flare rather 

than the gas exiting the flare, the other piece of information needed to estimate emissions from the flare is 

the flare efficiency (Feff). For the example of sulfur content above, the portion of the sulfur that is 

oxidized to SO2 emissions during the combustion of the flare gas will be dependent on the combustion 

efficiency. For emissions of compounds that are emitted as a result of incomplete combustion, such as 

reduced sulfur compounds and uncombusted hydrocarbons, one minus the assumed flare efficiency (1-

Feff) is used to estimate the emissions rate. 

As noted above, direct measurement methods are available and can be used to confirm the efficiency of a 

flare. If efficiency information is available for a specific flare at a refinery under certain conditions, that 

information should be used to estimate emissions for that flare where appropriate. For other flares, 

Section 13.5 of Compilation of Air Pollutant Emission Factors notes that the flare combustion efficiency 

for properly operated flares is at least 98% (U.S. EPA, 1995a). It is important to note that only flares that 

operate consistent with the criteria of 40 CFR 60.18 should be assumed to be ―properly operating‖ and 

achieving 98% combustion efficiency. It should also be noted that recent efforts to better characterize 

flare emissions include efforts to determine whether this combustion efficiency continues to be 

appropriate for properly operated flares. At this time, sufficient data have not yet been collected and 

evaluated to support revising this efficiency estimate. 

Most gas composition monitors measure the concentration on a volume basis (and generally on a dry 

basis), although some will provide the concentration on a mass basis. Most flow monitors measure 

volumetric flow rate in actual cubic feet. Many flow monitoring systems are equipped with temperature 

and pressure monitors to automatically convert the flow to standard conditions. If the gas composition is 

determined on a dry basis, which is typical for extractive monitoring systems, then it is important to also 
Version 1.0 Section 6—Flares 

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6-3 

correct the flow to be on a dry basis. The total volumetric flow of the pollutant can be converted to a mass 

emissions rate using the molecular weight of the pollutant and/or the ideal gas law, as appropriate. An 

emissions estimate can be calculated using Equation 6-1, which is a variation of Equation 4-1 for CEMS: 

     

 

100%

1

1

 20



















  































      

N

n

N

o

n

n

i n i o

i eff n H n

M K

P

P

T

T

MVC

C M W

E K Q f

 (Eq. 6-1) 

where: 

 Ei = Emissions rate of pollutant ―i‖ (tons per year [tons/yr]).

 N = Number of measurement periods per year (e.g., for hourly measurements, N = 8,760). 

 n = Index for measurement period. 

 Keff = Factor to account for the efficiency of the flare. Keff is equal to the flare efficiency Feff

for pollutants created by combustion, such as SO2. Keff is equal to one minus the flare 

efficiency (1 – Feff) for pollutants in uncombusted gas, such as VOC, reduced sulfur, 

and specific HAP. 

 (Q)n = Volumetric flow rate of gas being combusted for measurement period ―n‖ (actual cubic 

feet per minute [acfm]). If the flow rate meter automatically corrects for temperature 

and pressure, then replace ―(T)o ÷ (T)n × (P)n ÷ (P)o‖ with ―1.‖ If the pollutant 

concentration is determined on a dry basis and the flow rate meter automatically 

corrects for moisture content, replace the term [1-(fH20)n] with 1. 

(fH2O)n = Moisture content of exhaust gas during measurement period ―n,‖ volumetric basis 

(cubic feet water per cubic feet exhaust gas). 

(Ci)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−(fH20)n] with 1. 

MWi = Molecular weight of pollutant ―i‖ (kilogram per kilogram mole [kg/kg-mol]). 

 MVC = Molar volume conversion factor = 849.5 standard cubic feet per kilogram mole 

(scf/kg-mol) at 60°F (520°R) and 1 atmosphere (atm). 

 To = Temperature at ―standard conditions‖ (520 °R).

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

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

 Po = Average pressure at ―standard conditions‖ (1 atm). 

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

be calculated by dividing 525,600 minutes per year (min/yr) by the number of 

measurement periods per year (―N‖).

 K = Conversion factor = 2.2046/2,000 (tons per kilogram [tons/kg] = 0.0011023 tons/kg. 

As explained in Section 4-1, a continuous monitor records multiple measurements per hour, and the 

individual measurements can be used to calculate annual emissions in two ways. For a flare, the selection 

of an hourly average approach or heavier reliance on individual measurements will depend on the 

duration of the flare’s operation (particularly for flares that operate only intermittently) and the 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 determining composition by continuously monitoring a 

―surrogate‖ component, and then using sampling or other data to periodically check a correlation between 

the surrogate and the pollutant. For a flare, the most likely pollutants to be estimated using Methodology 

Rank 2 for flares are SO2 and specific HAP. A continuous monitor for H2S can be used to estimate SO2
Version 1.0 Section 6—Flares 

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6-4 

emissions similar to the process described for Methodology Rank 1, but because H2S is only one of 

several sulfur compounds potentially present in the flare gas, it is important to periodically characterize 

the total sulfur content of the gas so as not to underestimate SO2 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 H2S monitoring data to determine an average total sulfur-toH2S ratio of the flare gas. This average total sulfur-to-H2S ratio, expressed in SO2 equivalence, can be 

used to adjust the H2S concentration measured by the continuous monitor to provide a more accurate and 

complete assessment of SO2 emissions from the flare. Similarly, sampling can be used to determine the 

relative concentration of specific HAP present in the flare gas. These sampling data can be used in 

conjunction with total hydrocarbon monitoring data to estimate HAP emissions from the flare. As with 

the Methodology Rank 1 for flares, the generation or destruction of pollutants in the flare will depend on 

the flare combustion efficiency. As mentioned previously, the current default flare combustion efficiency 

for properly operating flares is 98% (U.S. EPA, 1995a). 

6.3 Methodology Rank 3 for Flares 

Methodology Rank 3 for flares includes continuous monitoring of flare gas flow as in Methodology 

Rank 1 for flares, continuous monitoring of the heating value of the fuel, and emissions factors based on 

the heating value. The most likely pollutants estimated using Methodology Rank 3 for flares are CO, 

NOx, and total hydrocarbons (surrogate for VOC). A general equation for Methodology Rank 3 for flares 

is as follows: 

 

1



   

N

n

Ei HVn FRn M N EFi

(Eq. 6-2) 

 Ei = Emissions rate of pollutant ―i‖ (tons/yr).

 N = Number of measurement periods per year (e.g., for hourly measurements, N = 8,760). 

 n = Index for measurement period. 

HVn = Heating value of gas being flared during measurement period ―n‖ (MMBtu/scf). 

(Heating value for flares is usually determined on a lower (net) heating value (LHV) 

basis.) 

FRn = Flow rate of gas being flared for measurement period ―n‖ (scfm). 

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

be calculated by dividing 525,600 min/yr by the number of measurement periods per 

year (―N‖).

EFi = Emissions factor for pollutant ―i‖ (lb/MMBtu).

Values for ―EFi‖ are presented in Tables 6-2 and 6-3 below. It is important to note that both sets of 

emissions factors are intended for use with properly operating flares meeting the criteria of 40 CFR 60.18; 

therefore, the flare efficiency is already included in these emissions factors. It is also important to note 

that the number of components for which emissions factors are available is limited because these 

emissions factors are based on general combustion characteristics and limited emissions tests. For 

example, the emissions factors for NOx are generally based on the amount of nitrogen in the air during 

combustion, so if there are constituents containing nitrogen in the fuel gas, such as ammonia, additional 

calculations are needed to account for all NOx emissions (based on Methodology Rank 2 for flares, 

particularly if flow rate is monitored continuously.) 

The emissions factors in Table 6-2 are from Section 13.5 of EPA’s Compilation of Air Pollutant 

Emission Factors (U.S. EPA, 1995a) and have an emissions factor rating of ―B‖ (U.S. EPA, 1995a, for 

details on the emissions factor rating system). These flare emissions factors are based on limited EPA 

tests conducted decades ago. Although AP-42 does not specify, it is common practice that the heating 
Version 1.0 Section 6—Flares 

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6-5 

value for flares is determined on a LHV basis. As such, it is recommended that these emissions factors be 

used with LHV heat content measurements. 

Table 6-2. Flare Energy Consumption-Based Emissions Factors 

Component

Emissions Factora

(lb/106 Btu)

Total hydrocarbonsb0.14

Carbon monoxide (CAS No. 630-08-0) 0.37

Nitrogen oxides 0.068

a

Source: U.S. EPA, 1995a.

b Measured as methane equivalent.

The emissions factors in Table 6-3 are from Technical Supplement 4 of TCEQ’s 2008 Emissions 

Inventory Guidelines (TCEQ, 2009). The emissions factor rating for these emissions factors is not 

specified. These flare emissions factors are intended to be used with LHV, or net heating value, heat 

content measurements. 

Table 6-3. TCEQ Energy Consumption-Based Emissions Factors for Flares 

Component Assist Type

Waste Gas Stream Net 

Heating Valuea

Emissions Factor

(lb/MMBtu)

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.
Version 1.0 Section 6—Flares 

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6-6 

6.4 Methodology Rank 4 for Flares 

Methodology Rank 4 for flares includes a variety of estimation methods based on engineering 

calculations. Estimates of nearly all pollutants from flares can be calculated using this rank based on 

process knowledge of units connected to the flare, including process unit volume, process stream 

compositions, temperature, and pressure. Any of this information used in conjunction with periodic 

sampling also constitutes Methodology Rank 4. The specific methods used will vary based on the ways in 

which the flare is used and the units the flare serves. Estimating emissions from flares with routine flow, 

such as those used for controlling blowdown from delayed coking units or other routine discharges, may 

rely on key process operating parameters that can be defined in advance. For process upsets or 

malfunctions, the estimation methods used may be very event-focused and are likely to rely on 

engineering judgment as much as actual monitoring data. Estimation methods may also be needed from 

flares with monitoring systems when an upset or malfunction causes the concentration or flow to exceed 

the calibrated span of the monitor. A few examples are described in this section, but many others are 

possible, given the complexity of refineries and differences between them. When emissions are estimated 

using Methodology Rank 4 for flares, a description of the methodology, assumptions, and specific pieces 

of data should be recorded and kept for future reference, both to document the emissions calculation 

methodology and to ensure consistency from one estimate to the next for a particular process. 

For routine or planned releases from flares not equipped with a continuous monitor, the refiner should 

know the quantity and composition of the gas being released. If the gas is excess fuel gas that has been 

amine-treated and mixed in a central drum, then the H2S concentration of the gas being flared should be 

the same as the concentration going to any fuel gas combustion device (e.g., process heater, boiler) at the 

refinery. (As noted previously, it is important to note that H2S may not be the only reduced sulfur 

compound contributing to SO2 emissions.) Alternatively, if a fuel gas combustion device has an 

instrument for measuring SO2 emissions, then the SO2 emissions from the flare can be calculated based on 

Example 6-1: Calculation of CO Emissions from a Flare with Continuous Monitors for 

Flow Rate and Heating Value

Calculate hourly emissions from a refinery flare given:

– The flaring event is from one source at the refinery and lasts several hours, so emissions 

can be estimated using the hourly average flow rate and heat content measurements

– The average flow rate to the flare during a certain hour is 250 scfm

– The higher heating value of the flow to the flare during that hour is 1200 Btu/scf, or 

1.2E-03 MMBtu/scf (1200 Btu/scf × 1E-06Btu/MMBtu)

Calculate hourly emissions using Equation 6-2:

 

1



   

N

n

ECO HVn FRn M N EFCO

ECO = (1.2E-03) × (250) × (60) × (0.37)

ECO = 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 

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 SO2 emissions would be measured 

directly.) As another example, if a refiner is emptying a tank and combusting the vapors, VOC and HAP 

emissions can be calculated based on the composition of the tank contents and the size of the tank. 

For emergency flares and flares with flare gas recovery systems (or otherwise equipped with water seals 

intended to prevent gases from going to the flare during normal operations), an alternative method of 

estimating flow rate for non-routine flaring events is to monitor the pressure drop across the flare water 

seal drum. A limited number of flow measurements can be made at different flare gas and water seal 

differential pressures (or water heights) to develop a flow rate correlation with the measured pressure 

drop. The water seal differential pressure or water height is routinely measured to determine the flow to 

the flare. Alternatively, the pressure in the flare line can also be monitored using a direct pressure monitor 

installed at the final liquid knock-out drum prior to the water seal. Concentrations of specific compounds 

are estimated by sampling and analysis of the flare gases (preferred, if possible) or calculations based on 

the composition of the gases in the process unit(s) contributing to the flaring event. Emissions are then 

calculated using those concentrations, the calculated flow rate, and an assumed flare efficiency. Some 

refiners that use this method for flares with a flare gas recovery system also monitor the recovery system 

to ensure that gases are not sent to the flare during normal operation. 

6.5 Methodology Ranks 5 and 6 for Flares 

As previously mentioned, flares are difficult to test, so only a few emissions factors have been developed 

for flares. Most of the available emissions factors were provided in Tables 6-2 and 6-3 for use with 

continuous flow and heat content monitoring. Methodology Rank 5 for flares consists of using these 

emissions factors Additional emissions factors for soot (PM) appear in Section 13.5 of EPA’s 

Compilation of Air Pollutant Emission Factors (U.S. EPA, 1995a) and are also provided here in 

Table 6-4. As mentioned previously, these flare emissions factors are based on limited EPA tests 

conducted decades ago and have an emissions factor rating of ―B.‖ Methodology Rank 5 for flares 

consists of using the emissions factors in Tables 6-2, 6-3, or 6-4 with estimates of the energy 

consumption of each flare in British thermal units and constitute Methodology Rank 5 for flares. The total 

hydrocarbon emissions factor could be used with knowledge of the components in the flare gas to 

estimate HAP emissions. 

Table 6-4. Emissions Factors for Soot from Flares 

Flare Operation

Emissions Factora

(μg/L)

Nonsmoking flares 0

Lightly smoking flares 40

Average smoking flares 177

Heavily smoking flares 274

a

Source: U.S. EPA, 1995a.

Note: μg/L = micrograms per liter

Methodology Rank 6 for flares includes emissions factors for HAP that were developed for the Petroleum 

Refinery Source Characterization and Emission Model for Residual Risk Assessment (RTI, 2002) based 

on the State of Louisiana’s title V permit applications data. The original emissions factors presented in 

RTI’s document (2002) were based on arithmetic averages. However, the arithmetic average is 

occasionally skewed by one high estimate. The log-mean average emissions factors from the State of 

Louisiana’s title V permit applications data were calculated and are provided in Table 6-5. These 
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6-8 

emissions factors yield a cumulative emissions estimate from all flares (not per flare) for the refinery 

based on the total refinery crude capacity in barrels per calendar day (bbl/cd). It is uncertain how the 

permit application estimates were developed and whether these estimates include SSM events, but it is 

likely that these factors would not include emissions released during significant SSM events. As such, 

these emissions factors are very general and are not recommended unless no other information is 

available. Refineries are expected to have more source-specific information for estimating flare 

emissions, but these factors may be used for the purposes of modeling or for general emissions estimates. 

Table 6-5. Flare General Emissions Factorsa

CAS Number Component

Emissions 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 emissions factors is straightforward, using Equation 6-3. 

Ei Cap  EFi

(Eq. 6-3) 

where: 

 Ei = Mass emissions per year of pollutant ―i‖ (tons/yr) 

 Cap = Crude capacity of refinery (bbl/cd) 

EFi = Emissions factor for pollutant ―i‖ (tons/yr/bbl/cd) 

Example 6-2 shows the calculation of emissions from flares at a refinery with a given crude capacity. 

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 (C6H6) emissions can be calculated from flares at the refinery as follows:

C6H6 C6H6

E  Cap  EF

EC6H6 = (100,000) × (9E-06)

EC6H6 = 0.9 tons/yr
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7. Wastewater Collection and Treatment Systems 

Industrial wastewater collection and treatment operations range from simple pre-treatment operations that 

discharge to publicly owned treatment works (POTW) to a full-scale treatment systems. Full-scale 

treatment systems include the collection of process and/or storm water that is treated to a quality that is 

acceptable for discharge to a receiving water body or for re-use. 

Wastewater collection systems differ among facilities, but they generally include drains, manholes, 

trenches, lift stations, sumps, junction boxes, and/or weirs. As water passes through each of these system 

components, emissions may occur by volatilization of organic compounds at the water/air interface. 

The overall objectives of wastewater treatment at refineries are to: (1) equalize flow and pollutant load by 

buffering flow surges in large tanks, (2) separate free and emulsified oils and solids from the wastewater 

by oil/water separators and flotation unit operations (e.g., dissolved air flotation [DAF], induced air 

flotation [IAF], dissolved nitrogen flotation [DNF]), and (3) oxidize organic molecules and remove or 

transform nutrients through biodegradation. Figure 7-1 shows a typical full-scale refinery wastewater 

treatment scheme. 

Equalization Tank Oil-Water Separator Dissolved Air Flotation Unit

Slop Oil Tank

Aeration Tank

Clarifier Sludge to Coker, Land Treatment, or Disposal

Return Sludge

Polishing Pond Return to Crude Processing Discharge

Process Wastewater In

Collection System

Figure 7-1. Typical refinery wastewater treatment system. 

Tanks or treatment units upstream of any benzene removal or destruction systems (e.g., stream strippers, 

enhanced biodegradation units) at most petroleum refineries are regulated under BWON (Benzene Waste 

Operations NESHAP) and thus should be covered and vented to appropriate control devices. Equalization 

tanks, oil/water separators, and flotation units typically fall into this category; however, in the event these 

units are not covered because they do not contain high benzene quantities, emissions estimation methods 

are presented in this Refinery Emissions Protocol document. Biological treatment units are typically the 

first uncovered process in the wastewater treatment system and thus the first air emissions source. Limited 

data are available to characterize emissions from unsealed process drains and other uncovered or unsealed 

processes in the wastewater treatment system, and emissions from these processes are not addressed at 

this time. 
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Table 7-1 lists the emissions estimation methods for wastewater treatment systems. The methods are 

ranked according to anticipated reliability. There are three primary estimation methods: (1) direct 

measurement, (2) predictive modeling, and (3) engineering estimates. Direct measurements can only be 

taken from process units that are covered and vented to a control device. Predictive modeling can be 

accomplished with using analytical equations, such as those presented in AP-42, by computer-based fate 

and transport models (e.g., WATER9, TOXCHEM, BASTE) or by using the simplified refinery 

wastewater emissions tool presented in this Refinery Emissions Protocol document. Engineering 

estimates can be made using emissions factors based on crude throughput or wastewater load. 

Table 7-1. Summary of Wastewater Treatment Emissions Estimates 

Rank Measurement Method Application Data Requirements

1 Direct measurement Covered and 

vented units

 Constituent load and speciation of collected 

gas samples

2a Predictive modeling with 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 factorsUncovered units  Constituent load and speciation of process

wastewaters

3a Engineering estimates based on 

wastewater treatment plant load

Uncovered units  Constituent load and speciation of process 

wastewaters

3b Engineering estimates based on 

crude throughput

Uncovered units  Crude throughput

7.1 Methodology Rank 1 for Covered and Vented Units 

Emissions from covered and vented process units and drainage system components can be estimated by 

the methods summarized in Section 5, Process Vents, of this Refinery Emissions Protocol document. 

Although there are direct measurement methods for uncovered units (i.e., off gas collectors and DIAL 

techniques), these methods do not provide continuous monitoring data. Therefore, these methods are not 

recommended as primary techniques for emissions estimations, but are reasonable for predictive 

modeling validation. 

7.2 Methodology Rank 2 for Uncovered Units 

Air emissions estimation modeling techniques use mathematical equations to predict the fate and 

transport of specific constituents in wastewater. Figure 7-2 is a simplified drawing illustrating the mass 

balance of a wastewater constituent as it passes through a biological treatment unit. With the appropriate 

information, such as constituent concentration and physical properties, reaction kinetics, and flow-in and 

flow-out of the control volume, predictive models can estimate air emissions without direct measurement. 

Specifically, factors that impact volatilization and thus air emissions in a biological treatment unit are: (1) 

gas and liquid-phase mass transfer coefficients for quiescent water surfaces, (2) gas and liquid-phase mass 

transfer coefficients for turbulent water surface, (3) constituent biodegradation rate, (4) the type of 

aeration used (diffused or mechanical), and (5) adsorption of the constituent to the biomass. The general 

steps in predictive modeling for each process unit are to determine: 

1. The overall liquid-phase mass transfer coefficient 
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7-3 

2. The overall gas-phase mass transfer coefficient 

3. The overall oil-phase mass transfer coefficient (for oil-water separators) 

4. The overall mass transfer coefficient 

5. The air emissions 

6. The effluent concentration of each unit. 

Biological Treatment Unit Reactions and Absorption Constituent In (Wastewater) Constituent Out (Wastewater) Constituent Out (Air) Constituent Out (Sludge) Figure 7-2. Simplified drawing of a constituent mass balance in a biological treatment unit. 

Although successful use of the available predictive models has been demonstrated, reporting facilities 

have expressed concerns regarding complexity, user friendliness, and accuracy; therefore, a simplistic 

refinery wastewater emissions tool has been developed as part of this document to address these issues. 

This tool is designed to help the user identify critical model inputs for each process unit, recognize 

variables and constants that may be site-specific, and calculate air emissions and constituent effluent 

concentrations. Additionally, constituent effluent concentrations from a treatment unit can be used as 

inputs for the next downstream unit when processes are linked in a series (e.g., oil-water separator 

effluent data equals input data for the DAF unit). 

The ―Critical Inputs‖ section of the refinery wastewater emissions tool includes data that is required to 

estimate air emissions from the specific process unit. The ―Variables with Default Values‖ section 

includes inputs that may be site-specific or unknown to the user. Default values are taken from AP-42, but 

they can be changed if more accurate data are known or determined. The Chemical Properties sheet 

contains the best available chemical, physical, and biodegradation information on the 30 organic HAP 

listed in the Petroleum Refinery MACT I. However, if more accurate or site-specific data are available, 

then these data can be inserted in the Site-Specific Table on the Chemical Properties sheet, and the model 

will override the default values. Detailed instructions for use and application are provided in the refinery 

wastewater emissions tool. 

Since reliable variables to estimate emissions for all volatile organic compounds (VOC) are not available, 

air emission estimates for compounds not listed in the MACT I can be made using surrogate compounds. 

Butane is the surrogate compound used for C2 – C4 VOC and octane for C4 – C9 in the refinery 

wastewater emissions tool. Air emission estimates for compounds not listed and considered non-volatile 

(e.g., > C9 and Henry’s law constant > 10-3 atm-m3/gmol) can be made using the ―Compound A, B, or C 

rows in the tool. The following list of chemical, physical, and biological degradation properties for each 

compound are required to reliably estimate air emissions: 
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7-4 

1. Molecular weight 

2. Vapor pressure 

3. Henry’s law constant

4. Diffusivity in water 

5. Diffusivity in air 

6. Octanol-water partitioning coefficient 

7. Maximum biorate constant 

8. Half saturation biorate constant 

[Insert link to refinery wastewater emissions tool here]

The calculations used in the refinery wastewater emissions tool and variable definitions are based on 

those presented in AP-42 and included in the Appendix B, Wastewater Treatment System Equations, of 

this section and alternatively can be used to manually calculate emissions. 

7.2.1 Primary Weirs 

Weirs can serve as open-channel dams and utilized in settling basins to discharge cleaner effluent. As 

previously stated, these components of the wastewater collection system are typically covered and vented; 

therefore, open-air emissions estimations are not required. However, if the treatment units are uncovered, 

then the refinery wastewater emissions tool can be used to estimate air emissions. Table 7-2 lists the 

critical inputs, variables with default values, and chemical properties specific to weirs. 

Table 7-2. Critical Inputs, Variables, and Chemical Properties Specific 

to Primary Weir Air Emissions Calculations 

Critical Inputs Variables with Default Values Chemical Properties

Wastewater flow rate (Q) Diffusivity of oxygen in water (DO2,w) Diffusivity of constituent in water 

(Dw)

Constituent influent concentration 

(C0)

Weir height (h)

7.2.2 Junction Boxes and Lift Stations 

Junction boxes and lift stations collect and equalize wastewater prior to pumping to the wastewater 

treatment system. As previously mentioned, these treatment units are typically covered and vented; 

therefore, open-air emissions estimations are not required. However, if the treatment units are uncovered, 

then the refinery wastewater emissions tool can be used to estimate air emissions. Table 7-3 lists the 

critical inputs, variables with default values, and chemical properties specific to junction boxes and lift 

stations. 

Table 7-3. Critical Inputs, Variables, and Chemical Properties Specific 

to Junction Box and Lift Station Air Emissions Calculations 

Critical Inputs Variables with Default Values Chemical Properties

Surface area (A) Density of water (ρL) Diffusivity of constituent in air (Da)

Temperature (T) Viscosity of water (μL) Diffusivity of constituent in water (Dw)

(continued)
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Table 7-3. Critical Inputs, Variables, and Chemical Properties Specific

to Junction Box and Lift Station Air Emissions Calculations (continued)

Critical Inputs Variables with Default Values Chemical Properties

Wind speed (U10) Density of air (ρair) Henry’s law constant

Wastewater flow rate (Q) Molecular weight of air (MWair)

Constituent influent concentration (C0) Viscosity of air (μa)

Turbulent surface area (AT) Universal gas constant (R)

Total power to aerators (Ptot) Rotational speed of impeller (w)

Oxygen transfer correction factor (Ot)

Oxygen transfer rating to surface area (J)

Impeller diameter (d)

7.2.3 Oil-Water Separators 

An oil-water separator is a treatment unit designed to separate oil and suspended solids from wastewater. 

As previously mentioned, these treatment units are typically covered and vented; therefore, open-air 

emissions estimations are not required. However, if the treatment units are uncovered, then the refinery 

wastewater emissions tool can be used to estimate air emissions. Table 7-4 lists the critical inputs, 

variables with default values, and chemical properties specific to oil-water separators. 

Table 7-4. Critical Inputs, Variables, and Chemical Properties Specific 

to Oil-Water Separators Air Emissions Calculations 

Critical Inputs Variables with Default Values Chemical Properties

Surface area (A) Flow of oil (Qoil) Diffusivity of constituent in air (Da)

Oil layer thickness (Olayer) Density of oil (ρoil) Octanol–water partitioning coefficient

(Kow)

Total pressure (P0) Molecular weight of oil (MWoil) Vapor pressure of constituent (P*)

Wastewater flow rate (Q) Density of air (ρair)

Constituent influent concentration (C0) Molecular weight of air (MWair)

Wind speed (U10) Viscosity of air (μa)

Fraction of volume that is oil (FO)

7.2.4 Dissolved Air Flotation Units 

DAF is a wastewater treatment unit that uses bubble flotation to remove suspended oil and solids from 

water. As previously mentioned, these treatment units are typically covered and vented to control devices. 

However, if the treatment units are uncovered, then the refinery wastewater emissions tool can be used to 

estimate air emissions. Table 7-5 lists the critical inputs, variables with default values, and chemical 

properties specific to DAF units.

Table 7-5. Critical Inputs, Variables, and Chemical Properties Specific 

to DAF Air Emissions Calculations 

Critical Inputs Variables with Default Values Chemical Properties

Surface area (A) Viscosity of water (μL) Diffusivity of constituent in air (Da)

Temperature (T) Density of water (ρL) Diffusivity of constituent in water (Dw)

Total pressure (P0) Molecular weight of water (MWL) Henry’s law constant (H)

(continued)
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Table 7-5. Critical Inputs, Variables, and Chemical Properties Specific

to DAF Air Emissions Calculations (continued)

Critical Inputs Variables with Default Values Chemical Properties

Wastewater flow rate (Q) Density of air (ρair)

Constituent influent concentration (C0) Molecular weight of air (MWair)

Diffused air flow rate (Qa) Viscosity of air (μa)

Wind speed (U10)

7.2.5 Equalization Tanks 

Equalization tanks dampen variations in wastewater flow rate and pollutant load to lessen negative 

impacts on downstream processes. As previously mentioned, these tanks should be covered and vented; 

however, if the treatment units are uncovered, then the refinery wastewater emissions tool can be used to 

estimate air emissions. Table 7-6 lists the critical inputs, variables with default values, and chemical 

properties specific to equalization tanks.

Table 7-6. Critical Inputs, Variables, and Chemical Properties Specific 

to Equalization Tank Air Emissions Calculations 

Critical Inputs Variables with Default Values Chemical Properties

Surface area (A) Density of water (ρL) Diffusivity of constituent in air (Da)

Temperature (T) Viscosity of water (μL) Diffusivity of constituent in water 

(Dw)

Total pressure (P0) Density of air (ρair) Henry’s law constant

Wastewater flow rate (Q) Molecular weight of air (MWair)

Constituent influent concentration 

(C0)

Viscosity of air (μa)

Wastewater depth (D) Rotational speed of impeller (w)

Total power to aerators (Ptot) Quiescent surface area (AQ)

Number of aerators (NI) Oxygen transfer correction factor 

(Ot)

Turbulent surface area (AT) Oxygen transfer rating to surface 

area (J)

Wind speed (U10) Impeller diameter (d)

7.2.6 Biological Treatment Units 

Biological treatment is an effective process to reduce, remove, or transform organic constituents and 

nutrients typically found in refinery wastewater to an acceptable form or concentration prior to discharge 

or re-use. However, biological treatment units are complex and vary greatly in design, operation, and 

treatment efficiency, resulting in units that are difficult to characterize. Multiple fate and transport 

mechanisms are often involved in the ultimate removal of a specific compound. Specifically, 

biodegradation, volatilization, adsorption, hydrolysis, and photo degradation are common mechanisms in 

wastewater treatment that may compete against each other. Additionally, biological systems are dynamic 

in nature, resulting in shifts in the dominant fate mechanism. Therefore, it is important to obtain and use 

site-specific variables when estimating emissions to obtain accurate results. 

The two primary classes of biological treatment units are suspended-growth and attached-growth systems. 

Suspended-growth systems maintain the biomass (flocs) in suspension by mechanical or aeration devices 

where biodegradation occurs. Examples of suspended-growth systems include activated sludge, aerated 

lagoons, sequencing batch reactors, and membrane bioreactors. Attached-growth systems establish 
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biofilms on fixed surfaces where biochemical reactions occur. Examples of attached-growth systems 

include trickling filters, rotating biological contactors, and fluidized-bed reactors. Regardless of the type 

of biological treatment used, the biochemical reactions are generally the same, with the oxidation of 

organic compounds and ammonia forming new cells, CO2, and water. 

To maintain the health of the microorganisms and ensure adequate biologically mediated oxidation of the 

organic compounds and ammonia, O2 must be introduced into the system. There are two basic methods 

for aerating wastewater: (1) introducing air or pure O2 into the wastewater through diffusers or other 

devices, and (2) agitating the water to increase surface area and promote the gaseous exchange with the 

atmosphere. However, the mechanisms that increase dissolved oxygen concentration in the water also 

increase the emissions rate of organic constituents through increased volatilization. The volatilization rate 

can be affected by the wastewater surface area, turbulence, and temperature; hydraulic retention; water 

depth; concentration and physical properties of the organic constituents (e.g., volatility, diffusivity, 

inhibitory mechanisms); and atmospheric conditions. 

As previously mentioned, the biological treatment unit will most likely be the first uncovered process in 

the wastewater treatment system. Accordingly, these units will be the most likely to have air emissions 

that require estimation. Table 7-7 lists the critical inputs, variables with default values, and chemical 

properties specific to biological treatment unit air emissions calculations. 

Table 7-7. Critical Inputs, Variables, and Chemical Properties Specific 

to Biological Treatment Unit Air Emissions Calculations 

Critical Inputs Variables with Default Values Chemical Properties

Surface area (A) Density of water (ρL) Diffusivity of constituent in air (Da)

Temperature (T) Viscosity of water (μL) Diffusivity of constituent in water 

(Dw)

Total pressure (P0) Density of air (ρair) Henry’s law constant

Wastewater flow rate (Q) Molecular weight of air (MWair) Maximum biodegradation rate 

constant (Kmax)

Constituent influent concentration 

(C0,X)

Viscosity of air (μa) Half saturation biorate constant (Ks)

Wastewater depth (D) Weight fraction of the total carbon in 

biomass (fOC)

Octanol-water partitioning 

coefficient (Kow)

Total power to aerators (Ptot) Quiescent surface area (AQ)

Number of aerators (NI) Oxygen transfer correction factor 

(Ot)

Mixed liquor volatile suspended 

solids (CMLVSS)

Oxygen transfer rating to surface 

area (J)

Influent BOD concentration (C0,BOD) Impeller diameter (d)

Wind speed (U10) Rotational speed of impeller (w)

Turbulent surface area (AT) Biomass volatile suspended solids 

yield from influent biochemical 

oxygen demand (Y)

Wasted sludge flow rate (Qw)

7.2.7 Polishing Ponds 

Although air emissions downstream of biological treatment should be minimal, ineffective treatment, 

constituent slugs, or hydraulic surges may lead to HAP contamination of tertiary treatment processes (i.e., 

polishing ponds). If air emissions estimates are needed for polishing ponds, then the equalization tank 

sheet of the refinery wastewater emissions tool can be used. Although polishing ponds may function as a 
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plug-flow reactor, the assumption can be made that volatilization is the major constituent fate mechanism. 

If the polishing pond is aerated and has significant active biomass (> 40 milligrams per liter [mg/L] 

volatile suspended solids), the biological treatment sheet of the model may be used. 

7.2.8 Site-Specific Factors 

There has been tremendous effort to compile default values for specific variables to estimate air 

emissions; however, site-specific data provide the most accurate results. The factors that can have the 

most dramatic impact on air emissions from a biological treatment unit are the ones impacting 

biodegradation. Compound-specific biodegradation rate constants (i.e., k0 and k1) and the half-saturation 

concentration (i.e., KS) can be determined by using the aerated reactor test (BOX test). The empirically 

derived values can then be used in a predictive model for more accurate results. Although time and cost 

are involved during this procedure, the facility is often awarded with lower emissions estimates. Moye 

and colleagues (2006) reported lower air emissions from a biological treatment unit compared to 

WATER9 predictions when site-specific biodegradation rates were determined and the constants were 

critically reviewed. The methods used to determine the fraction of organic constituent biodegraded are 

provided in 40 CFR Part 63, Appendix C (also available at: http://www.epa.gov/EPAAIR/2004/June/Day-30/a14826.htm).

Although these methods have been successfully used to estimate biodegradation rates, there are concerns. 

Specifically, it is argued that dosing the bioreactor with only one constituent of interest yields inaccurate 

biodegradation rates compared to those dosed with a mixture of compounds commonly encountered by 

the microorganisms. Preferential biodegradation, degradation by-products, and co-metabolism are 

important factors to consider when determining biodegradation rates that are not addressed in the 

recommended methods. Yerushalmi and Guiot (1998) reported biodegradation rates of benzene and 

toluene that were 62.9 and 16.4 times greater, respectively, when used as the sole substrate, versus a 

mixture of organic compounds. It is recommended that the constituent of interest be dosed in the 

appropriate ratio with organic compounds found in the real-world system (as described in Appendix C). 

Additionally, the methods do not distinguish between biodegradation, hydrolysis, and adsorption. Rather, 

the results of the BOX test are a summation of the three primary fate mechanisms common to aerated 

bioreactors. This fact is important to consider when assessing all the fate mechanisms involved in 

compound degradation. 

7.2.9 Model Validation 

To ensure that predictive model outputs are accurate, validation studies can be conducted to support the 

results. This task is accomplished by secondary direct or in-direct measurement techniques such as offgas 

collectors, DIAL, concentration-profile methods. Direct measurements are taken of a modeled process 

unit, and the results are compared. Favorable comparisons are indicative of accurate predictive modeling, 

whereas poor comparisons could be the result of incorrect assumptions or errors in the model. If 

corrective actions are necessary, a review of the constants and site-specific variables should be conducted. 

7.3 Methodology Rank 3 for Uncovered Units 

7.3.1 Engineering Estimates Based on Wastewater Treatment Plant Load 

If a facility only has benzene wastewater concentration data, then this method can be used to estimate the 

unknown HAP concentrations for use in the predictive modeling methods in Section 7.2, Methodology 

Rank 2 for Uncovered Units. The wastewater generation rates, benzene concentrations, and total HAP 

concentrations presented in Table 7-8 (U.S. EPA, 1998a) were combined with the total U.S. refinery 

processing and production capacities reported by EIA (2009) to calculate an average wastewater mixture 

to determine an average benzene and total HAP concentration of refinery wastewater. These data were 

evaluated using the average petroleum stream composition provided in Appendix B, Wastewater 

Treatment System Equations, of this Refinery Emissions Protocol document and an evaluation of the log 
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7-9 

octanol water partition coefficient to help speciate the total HAP concentration before and after oil 

removal. The results of this analysis (see Table 7-9) are relative concentrations of key pollutants as a ratio 

of the benzene concentration. If the benzene concentration of the refinery wastewater is known, then the 

concentration of other organics in the wastewater can be estimated using the ratios in Table 7-9. 

7.3.2 Engineering Estimates Based on 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 the specific HAP (and total HAP) 

concentrations of the wastewater. The generated data can then be used to estimate specific constituent 

wastewater loads (see Section 7.3.1, Engineering Estimates Based on Wastewater Treatment Plant Load) 

and used in the predictive modeling methods in Section 7.2, Methodology Rank 2 for Uncovered Units. If 

the wastewater treatment system design is unknown, then the default emissions factors in Table 7-10 can 

be used to estimate the fraction of the total constituent load to the wastewater treatment system 

(calculated using the factors in Tables 7-8 and 7-9) that is expected to be released into the atmosphere. 

Table 7-8. Model Process Unit Characteristics for Petroleum Refinery Wastewatera

Process Unit

Average Flow 

Factorb

(gal/bbl)

Average Benzene 

Concentrationc

(ppmw)

Average Organic 

HAP Concentration 

(ppmw) 

Crude distillation 2.9 21 140

Alkylation unit 6 3 6.9

Catalytic reforming 1.5 106 238

Hydrocracking unit 2.6 14 72

Hydrotreating/hydrorefining 2.6 6.3 32

Catalytic cracking 2.4 13 165

Thermal cracking/coking 5.9 40 75

Thermal cracking/visbreaking 7.1 40 75

Hydrogen plant 80d62 278

Asphalt plant 8.6 40 75

Product blending 2.9 24 1,810

Sulfur plant 9.7e0.8 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 capacity 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 ft3) of gas production

e

This flow factor is given in gal/ton of sulfur
Version 1.0 Section 7—Wastewater Collection and Treatment Systems 

Review Draft – Do not cite or quote 

7-10 

Table 7-9. Refinery Wastewater Contaminant Concentrations as a Ratio to Benzene 

CAS No. HAP

Mass Concentration Ratio of Compounds

to the Concentration of Benzene

Inlet to Oil-Water 

Separator or DAF Unit

Inlet to Biological 

Treatment Unit (After OilWater Separator)

540841 2,2,4-Trimethylpentane 1.97 0.022

71432 Benzene 1.00 1.00

92524 Biphenyl 0.034 0.0005

1319773 Cresols 0.25 0.38

98828 Cumene 0.37 0.013

100414 Ethylbenzene 0.88 0.086

110543 Hexane 3.50 0.047

1634044 Methyl tertiary-butyl ether 0.58 0.98

91203 Naphthalene 0.29 0.02

108952 Phenol 0.18 0.80

100425 Styrene 0.58 0.09

108883 Toluene 3.3 0.80

1330207 Xylene 3.6 0.33

106990 1,3-Butadiene 0.0006 0.0027

VOC Total VOCs 81 17

Table 7-10. Default Mass Emissions Factors for Refinery Wastewater Collection 

and Treatment Systems 

CAS No. HAP

Mass Fraction of Compound Emitted from 

Wastewater Collection and Treatment System Based 

on Total Wastewater Loading

Open Wastewater 

Collection and 

Treatment System

BWON-Compliant 

Wastewater Collection 

and Treatment System

540841 2,2,4-Trimethylpentane 0.25 0.001

71432 Benzene 0.45 0.08

92524 Biphenyl 0.10 0.001

1319773 Cresols 0.05 0.001

98828 Cumene 0.15 0.005

100414 Ethylbenzene 0.15 0.01

110543 Hexane 0.25 0.002

1634044 Methyl tertiary-butyl ether 0.60 0.15

91203 Naphthalene 0.02 0.005

108952 Phenol 0.04 0.01

100425 Styrene 0.10 0.02

108883 Toluene 0.20 0.02

1330207 Xylene 0.15 0.01

106990 1,3-Butadiene 1.00 0.5

VOC Total VOCs 0.25 0.05
Version 1.0 Section 7—Wastewater Collection and Treatment Systems 

Review Draft – Do not cite or quote 

7-11 

Example 7-1. Methodology Rank 3 for Wastewater

A refinery has the following processing and production rates. The average annual emissions of 

hexane, benzene, toluene, and xylene can be estimated from the wastewater collection 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 reforming 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 7-6 and the density of water (ρwater = 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/106

Benzene Mass 

Flow (lb/cd)

Atmospheric 

distillation

100,000 2.9 290,000 21 50.8

Vacuum 

distillation

50,000 3 150,000 12 15.0

Catalytic 

reforming

20,000 1.5 30,000 106 26.5

Catalytic 

cracking

40,000 2.4 96,000 13 10.4

Alkylation 10,000 6 60,000 3 1.5

Product 

blending

60,000 2.9 174,000 24 34.8

Tank 

drawdown

180,000 0.02 3,600 188 5.6

Totals 803,600 144.7

Use the factors in Table 7-7 to estimate the mass loading rate of other compounds and the 

BWON-compliant emissions factors in Table 7-8 to estimate the annual emissions.

Compound

(A)

Mass Ratio from 

Table 7-7

(B) = A×144.7

Mass Flow (lb/cd)

(C)

Emission Factor 

from Table 7-8

(D) = B×C×365/2000

Annual Emissions 

(tons/yr)

Hexane 3.5 506.5 0.002 0.18

Benzene 1.0 144.7 0.08 2.1

Toluene 3.34 483.3 0.02 1.8

Xylene 3.57 516.6 0.01 0.94
Version 1.0 Section 7—Wastewater Collection and Treatment Systems 

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7-12 

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Version 1.0 Section 8—Cooling Towers 

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8-1 

8. Cooling Towers 

Cooling water is used in refineries in heat exchange systems and condensers to cool or condense various 

product streams. The cooling water for a closed-loop recirculation system may be sent to a cooling tower, 

where it is cooled to near ambient temperature for reuse, and then is returned to the process or to 

refrigeration units for additional cooling. The cooling water for a once-through system may be cooled and 

sent to a receiving waterbody. This section focuses on cooling towers because these are used 

predominately in the petroleum refining industry. Some refineries use once-through cooling systems 

(emissions estimates for once-through cooling systems can be estimated using essentially the same 

techniques used for cooling towers). 

Organic HAP and VOC are picked up by cooling water when leaks occur in heat exchangers or 

condensers. Product on the high-pressure side leaks through cracks in the exchanger and contaminates the 

water. Organic HAP, VOC, PM-10, and chlorine are subsequently emitted from the water into the 

atmosphere due to stripping (i.e., active air and water contact) in the cooling tower and due to drift loss. 

Large emissions on the order of tons per year can occur for low levels of contamination or concentration 

because refineries use large volumes of cooling water. Generally, CH4 or other GHGs are not significant 

pollutants for cooling towers; however, if the cooling water is used on a high CH4 process stream, then 

CH4 emissions can be calculated using the same methods presented in this section for calculating volatile 

hydrocarbon emissions from cooling towers. The cooling tower emissions estimates require information 

on the cooling water flow rate and the composition of the process stream in the heat exchanger or in the 

condenser or refrigeration units. These emissions estimates are also dependent on the type of heat 

exchange monitoring system used. 

Table 8-1 summarizes the hierarchy of cooling tower emissions estimation techniques. The methods are 

ranked in terms of anticipated reliability. Within a given measurement method (or rank), there may be 

alternative methods for determining the constituent-specific emissions; these compositional analysis 

methods are also provided in order of reliability. The remainder of this section provides additional detail 

and guidance regarding the ways in which to implement these methods. In general, annual emissions from 

cooling towers should account for the full operating time of the cooling tower on an annual basis. Annual 

cooling tower emissions can be estimated using the measured concentrations for each monitoring period 

(whether the measured concentration constitutes a leak or not) and summing emissions over all 

monitoring periods or can be estimated using emission factors for the full annual operating time of the 

cooling tower. 

Table 8-1. Summary of Cooling Tower Emissions Estimation Methodologies 

Rank Measurement Method or Emissions Factor Compositional Analysis Data

1  Air stripping simulation using Appendix P, 

Modified El Paso methoda

 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 methoda, using a flame 

ionization detection analyzer

 Water recirculation rate

 Process-specific, service-specific concentrations

 Process-specific average concentrations

 Site-specific refinery average stream 

concentrations

 Default process compositions

(continued)
Version 1.0 Section 8—Cooling Towers 

Review Draft – Do not cite or quote 

8-2 

Table 8-1. Summary of Cooling Tower Emissions Estimation Methodologies (continued)

Rank Measurement Method or Emissions Factor Compositional Analysis Data

3  Direct water measurement by EPA Method 

8260Bbbefore and after exposure to the 

atmosphere (e.g., at the cooling tower return 

line and at the outlet of cooling tower)

 Water recirculation rate

 Speciation of collected water samples

4  Direct water measurement by EPA Method 

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 emissions factor

 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 hard-piped to an air-stripping 

column apparatus. Air flowing countercurrent to the cooling water in the apparatus strips VOC and 

organic HAP from the water. Concentrations of pollutants in the stripping are measured, along with the 

air and water flow rates in the apparatus, to determine the concentrations of strippable VOC in the cooling 

water. At the apparatus air outlet, the concentrations may be measured using an on-site FID analyzer to 

determine the total strippable VOC (Methodology Rank 2 for cooling towers) or an on-site portable gas 

chromatograph (GC); (Methodology Rank 1 for cooling towers), or the concentrations may be measured 

by collecting samples in sample canisters for off-site laboratory analysis for speciation of air 

contaminants (Compendium Method TO-14A, Compendium Method TO-15, or Method 18 [which are all 

Rank 1 methods]). 

The data necessary to implement Methodology Ranks 1 and 2 for cooling towers include speciated airstripped compounds concentration, operating parameters of the air-stripping apparatus, and the cooling 

water flow rate. Table 8-2 summarizes the data requirements for Methodology Ranks 1 and 2. 
Version 1.0 Section 8—Cooling Towers 

Review Draft – Do not cite or quote 

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)

 Assume the measured concentration has 

occurred for half of the time period since 

the last sampling date; if a leak occurs, 

then add the time period it takes to repair 

the leak

For cooling towers servicing process streams with multiple components, it is best to determine speciated 

compounds for air-strippable compounds from the cooling water. For cooling towers servicing process 

streams with single components, using the FID analyzer is likely adequate. (Equation 8-1) should be used 

to calculate the concentration of the air-strippable components in the cooling water from the concentration 

detected in the stripped air outlet: 

samplewaterflow

Air i stripairflow

Water i

R T a

C MW P PC b

C

*( 273)*

, * * * *

,





(Eq. 8-1) 

where: 

 CWater,i = Concentration of air strippable compound ―i‖ in the water matrix (parts per million by 

weight [ppmw]) 

 CAir,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) 

 bstripairflow = Stripping air flow rate of apparatus (milliliters per minute [mL/min]) 
Version 1.0 Section 8—Cooling Towers 

Review Draft – Do not cite or quote 

8-4 

 R = Universal gas constant (82.054 milliliters-atmospheres per mole-Kelvin [mL-atm/mol-K]) 

 T = Stripping chamber temperature (°C) 

asamplewaterflow = Sample water flow rate of apparatus (mL/min) 

When using the El Paso method (TCEQ, 2003), the calculated concentration of the compounds in the 

water matrix represents the concentration that was stripped and does not represent the total concentration 

of the compounds in the water matrix prior to stripping. As such, this calculated water concentration is 

referred to as the ―strippable pollutant concentration‖ in the cooling water. In general, when estimating 

the total VOC based on the FID analyzer, use the molecular weight (MW) of the calibration gas. 

Typically, CH4 is used for the calibration, so the MW for CH4 (16 g/mol) would be used to estimate the 

total VOC concentration in the water and the emissions rate (reported ―as CH4‖). Even when a different 

calibration gas is used, one may need to use the MW for CH4 in the event a leak threshold is defined in 

units of ppmw or ppmv as CH4. 

In general, when the process stream is a single component, then the concentration on a CH4 basis from the 

FID can be converted to specific compounds that are expected to be leaking by accounting for C (e.g., for 

benzene, Cair × 1 mol of CH4 × 1 mol of C/1 mol of CH4 × 1 mol of C6H6/6 mol of C). For a multicomponent process stream, it is better to determine speciated compounds using a portable GC/FID, TO14A, TO-15, or Method 18. For portable GC results, in addition to calibration with a standard compound 

(CH4 or propane), the response factor of the unit should be determined for typical compounds expected in 

the air-stripped stream. For speciated compound results from an off-site laboratory, the concentration in 

the water for specific compounds can be estimated using the MW for the respective compound (e.g., 

benzene MW is 78 g/mol). These speciated concentrations (calculated using the compound-specific MW) 

should be used when estimating emissions for the purposes of an emissions inventory. However, it is 

important to note that for specific regulatory purposes, these concentrations must be converted to a CH4

basis (using the MW of CH4) for comparison to a leak definition threshold that is on an ―as CH4‖ basis.)

The following equation (Equation 8-2) should be used to estimate emissions for air strippable total VOC 

from the cooling water: 

lb

ton H

gal

lb

hr

Flow

ppm

C

E CoolingWate r Year

Water i

i

2000

1

*8.34 * *

min * *60

106

,



 (Eq. 8-2) 

where: 

 Ei = Emissions of air strippable pollutant ―i‖ from the cooling water (tons/yr)

FlowCoolingWater = Flow rate of cooling water (gallons per minute [gal/min]) 

 HYear = Length of time of the monitoring period or the length of time a leak occurs (hr/yr) 

When Cair,i is based on total VOC results from an FID analyzer (Methodology Rank 2 for cooling towers), 

pollutant ―i‖ is simply VOC. 

When Cair,i is based on GC analysis results for individual species (Methodology Rank 1 for cooling 

towers) or based on site-specific or default species composition data (Methodology Rank 2 for cooling 

towers), pollutant ―i‖ will be the individual pollutant.

If monitoring or sampling events occur regularly or periodically (i.e., quarterly or monthly), then 

concentration measurements for consecutive monitoring events can be used to estimate the average 

emissions rate during the intervening period by assigning each concentration measurement to half of the 

time period between monitoring/sampling events. If significant concentrations of organics are detected in 

the cooling water (i.e., a ―leak‖ is detected), then the measured concentration is also attributed to the time 

span from when the leak was discovered until the time when it was repaired. This method is analogous to 
Version 1.0 Section 8—Cooling Towers 

Review Draft – Do not cite or quote 

8-5 

the method used to annualize equipment leak emissions when periodic monitoring is used (see Example 

2-4 in Section 2.2.2, Calculating Annual Average Equipment Leak Emissions, for additional details). 

When monitoring or sampling is not conducted regularly or periodically, any measured concentration 

should be used to calculate the average emissions rate from the cooling tower, assuming the concentration 

is constant for the entire year. In this situation, if the concentration measurement suggests a leak that is 

subsequently repaired, then use the initially determined ―leak‖ concentration for the entire reporting year 

up to the time when the leak was repaired. 

Example 8-1: Calculation for Methodology Rank 1 for Cooling Towers

Given: For hexane emissions from a cooling tower with a water recirculation rate of 32,000 

gal/min, a hexane concentration in the stripped air of 5.0 ppmv, a pressure of 29.9 in. of Hg, 

strippable air flow in the apparatus of 2,500 mL/min, a temperature of 32°C, a sample water 

flow rate in the apparatus of 125 mL/min, sampling that occurs quarterly, and the leak repair 

took 45 days to complete.

The following equation for CWater,i should be used to calculate the concentration of air 

strippable compound in the water:

ppmw Hexane ml

mole K

ml atm

ml

in Hg

atm in Hg

mole

lb

ppmv

CWaterSpecie s 0.34 ,

min

82.054 *(32 273) *125

min

* 2500

.

5.0 *86.17 * 29.9 . *0.03342











Thus, the 5 ppmv hexane concentration in the air stream translates to 0.34 ppmw ―strippable‖ hexane 

in the cooling water. The following equation should be used to calculate the emissions of hexane for 

the quarterly monitoring period: 

yr

tonHexane 5.9

2000 lb

1ton *

yr

hr * 2,175

gal

lb *8.34

hr

min *60

min

gal *32,000

10 ppm

0.34

6

Ei 

Based on a leak that occurs for 2,175 hours (i.e., one-half of a 3-month period [1,095 hours] 

plus 45 days to repair [1,080 hours]), the total emissions of hexane that were emitted into the 

atmosphere is 5.9 tons/yr.
Version 1.0 Section 8—Cooling Towers 

Review Draft – Do not cite or quote 

8-6 

8.2 Methodology Rank 3 for Cooling Towers 

Methodology Rank 3 is used to estimate emissions from cooling towers and involves using a mass 

balance approach based on sampling the cooling water before and after the cooling tower. Although 

Methodology Rank 3 has the potential to be as appropriately reliable as Methodology Ranks 1 or 2 for 

Example 8-2: Calculation for Methodology Rank 2 for Cooling Towers

Given: For VOC and C6H6 emissions from cooling water with a water recirculation rate of 

25,000 gal/min, a VOC concentration in the stripped air of 14 ppmv (as CH4), a pressure of 

29.9 in. of Hg, strippable air flow in the apparatus of 2,500 mL/min, a temperature of 32°C, a 

sample water flow rate in the apparatus of 125 mL/min, sampling occurs quarterly, and the 

leak repair took 30 days to complete.

The following equation (CWater,i) should be used to calculate the concentration of air strippable 

VOC compound in the water as CH4:

ppmwVOC ml

mole K

ml atm

ml

in Hg

atm in Hg

mole

lb

ppmv

CWater VOC 0.18

min

82.054 *(32 273) *125

min

* 2500

.

14 *16.04 * 29.9 . *0.03342

, 









The following equation should be used to calculate the quarterly emissions of VOC, Ei:

yr

tonVOC

lb

ton

yr

hr

gal

lb

hr

gal

ppm

EVOC 2.0

2000

1

*8.34 *1,815 *

min *60

min

* 25,000

10

0.18

6

 

The length of time of the leak was 1,815 hours (i.e., one-half of a 3-month period [1,095 

hours] plus 30 days to repair [720 hours]). The emissions of VOC emitted into the atmosphere 

are 2.0 tons/yr (based on CH4).

If C6H6 is expected to be leaking, to estimate the leak, convert the CH4 concentration to C6H6

(similar to the conversion example on p. 8-4) and use Eq. 8-1 for CWater,i to calculate the 

concentration of air strippable compound in the water:

ppmv asBenzene

moleC

moleC H

moleCH

moleC

CWater i ppmv moleCH 2.3 ,

6

1

*

1

1

14 * 1 *

6 6

4

, 4 

















ppmw as Benzene ml

mole K

ml atm

ml

in Hg

atm in Hg

mole

lb

ppmv

CWater i 0.145 ,

min

82.054 * (32 273) *125

min

* 2500

.

2.3 * 78.11 * 29.9 . * 0.03342

, 









Where: 14 ppmv of total air strippable VOC is equivalent to 2.3 ppmv of C6H6 in the air 

stream. The 2.3 ppmv C6H6 concentration in the air stream translates to 0.145 ppmw of 

―strippable‖ C6H6 in the cooling water.

The following equation (Eq. 8-2) should be used to calculate the quarterly emissions of C6H6, 

Ei: 

yr

tonBenzene

lb

ton

yr

hr

gal

lb

hr

gal

ppm

Ei 1.6

2000

1

*8.34 *1,815 *

min *60

min

* 25,000

10

0.145

6

 

The total emissions of C6H6 emitted into the atmosphere is 1.6 tons/yr.
Version 1.0 Section 8—Cooling Towers 

Review Draft – Do not cite or quote 

8-7 

large leakers, Rank 3 suffers from detection limit issues with water sampling techniques. Consequently, 

this monitoring approach will not detect the smaller leaks that could significantly contribute to VOC or 

HAP emissions. 

Cooling water typically has low concentrations of components and large volumes of flow rate, so direct 

water sampling typically requires analysis for low-level concentrations. A common method used for 

cooling water sampling is Method 8260B. In this method, the sample is introduced into a gas 

chromatography/mass spectrometry (GC/MS) system, the GC column is temperature programmed to 

separate the components, and the components are detected with MS. The results from the method are the 

concentrations of components in the cooling water. Typically, two cooling water samples are taken to 

estimate the emissions: one sample before and one sample after the cooling water has been exposed to the 

atmosphere. The change in the component concentration of the cooling water multiplied by the cooling 

water recirculation rate provides the quantity emitted into the atmosphere for the duration of the leak. 

The data necessary to implement Methodology Rank 3 for cooling towers include speciated compounds 

concentration in the cooling water and the cooling water flow rate. Table 8-3 summarizes the data 

requirements of Methodology Rank 3. 

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

Rank 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 cooling water before and after being exposed to the 

atmosphere is used, along with the cooling water recirculation rate, to estimate the emissions from the 

cooling water. The following equation (Equation 8-3) can be used to calculate the emissions of 

components from the cooling water. It is important to note that it is assumed that the drift loss and water 

make-up rates are small (in the range of 1% to 2%); therefore, flow ―in‖ is the same as flow ―out‖ and can 

be determined based on the water recirculation flow rate, regardless of where this measurement takes 

place. 

 

lb

ton H

gal hr

lb Flow

C C

E CoolingWate r Year

i I n i Out

i

2000

1

* *

min * *8.34 *60

106

,  ,



 (Eq. 8-3) 

where: 

 Ci,In = Concentration of component ―i‖ in the cooling water prior to exposure to the 

atmosphere (ppmw) 

 Ci,Out = Concentration of component ―i‖ in the cooling water after exposure to the atmosphere 

(ppmw) 
Version 1.0 Section 8—Cooling Towers 

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8-8 

As shown in Equation 8-4, the total emissions from the cooling water are the sum of all component 

species emitted and can be summed specifically for VOC or organic HAP: 

 

n

ETotal Ei

1

(Eq. 8-4) 

8.3 Methodology Rank 4 for Cooling Towers 

Methodology Rank 4, similar to Methodology Rank 3, uses direct cooling water samples for analysis of 

VOC and HAP contained in the cooling water, and a water sample is taken and sent for laboratory 

analysis. Under Methodology Rank 4 for cooling towers, only one sample is taken of the cooling water 

prior to being exposed to the atmosphere to estimate emissions. In this method, it is assumed that 100% of 

the compound is emitted at the cooling tower. As such, this methodology will likely overestimate the 

cooling water emissions, and would be a conservative (i.e., resulting in greatest emissions) estimate. 

The data necessary to implement Methodology Rank 3 for cooling towers include speciated compounds 

concentration in the cooling water and the cooling water flow rate. Table 8-4 summarizes the data 

requirements of Methodology Rank 4. 

Example 8-3: Calculation for Methodology Rank 3 for Cooling Towers

Given: Concentrations for C6H6 in the cooling water are 0.220 ppmw before exposure to the 

atmosphere and 0.080 ppmw after for a cooling tower with a cooling water recirculation rate 

of 55,000 gal/min, sampling occurs monthly, and the leak repair took 45 days to complete. For 

the following month, sampling showed C6H6 concentrations of 0.320 ppmw before and 0.100 

ppmw after the cooling tower.

The following equation (Eq. 8-3) should be used to calculate the emissions of C6H6, Ei for the 

first monitoring period (the length of time of the leak for this period is one half of 30 days 

[365 hours]): 

 

yr

ton Benzene

lb

ton

yr

hr

gal hr

gal lb Ei 0.70

2000

1

* 365 *

min *8.34 * 60

min

* 55,000

10

0.220 0.080

6







The following equation (Eq. 8-3) should be used to calculate the emissions of C6H6, Ei, for the 

second monitoring period plus remaining repair time (i.e., the length of time of the leak was 

1,095 hours based on 1 month [730 hours] plus 15 remaining days to repair (365 hours]): 

 

yr

ton Benzene

lb

ton

yr

hr

gal hr

gal lb Ei 3.3

2000

1

*1,095 *

min *8.34 * 60

min

* 55,000

10

0.320 0.100

6







So the total C6H6 emissions for this leak until repair are 4.0 tons (0.70 ton + 3.3 tons).
Version 1.0 Section 8—Cooling Towers 

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8-9 

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, rotameters, or similar 

methods

 Length of time of the monitoring period 

(hours)

 Assume the measured concentration has 

occurred for half of the time period since 

the last sampling date; if a leak occurs, 

then add the time period it takes to repair 

the leak

The component concentration in the cooling water before being exposed to the atmosphere is used with 

the cooling water flow rate to estimate the emissions from the cooling water. The following equation 

(Equation 8-5) should be used to calculate the emissions of components from the cooling water: 

 

lb

ton H

gal hr

lb Flow

C

E CoolingWate r Year

i I n

i

2000

1

* *

min * *8.34 *60

106

,



 (Eq. 8-5) 

where: 

 Ci,In = Concentration of component ―i‖ in the cooling water prior to exposure to the 

atmosphere (ppmw) 

As shown in Equation 8-6, the total emissions from the cooling water are the sum of all component 

species emitted and can be summed specifically for VOC or organic HAP: 

 

n

ETotal Ei

1

(Eq. 8-6) 
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8-10 

8.4 Methodology Rank 5 for Cooling Towers 

8.4.1 VOC and Organic HAP 

Methodology Rank 5 for cooling towers uses the uncontrolled VOC emissions factor given in AP-42 

(U.S. EPA, 1995a; Section 5.1) of 6 pounds of total VOC per million gallons of water (MM gal) 

(equivalent to a concentration in the water of 0.7 ppmw). The controlled emissions factor provided in AP42 should not be used. The controlled emissions factor only applies to refineries that directly monitor for 

hydrocarbons (and organic HAP) and repair leaks when they occur, in which case the refineries would 

have monitoring data to conduct emissions estimates under Methodology Ranks 1, 2, 3, or 4 for cooling 

towers. 

To estimate HAP emissions, refineries should use site-specific information on the composition of 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 a default average composition of all process streams 

at refineries was developed to estimate emissions for the Petroleum Refinery MACT I (40 CFR Part 63, 

Subpart CC). This default average composition for the refinery industry, given in Appendix A, Average 

Stream Compositions, Table A-1, may be used to speciate the VOC and generate HAP emissions 

estimates. 

The data necessary to implement the Methodology Rank 5 for cooling towers include the AP-42 

uncontrolled VOC emissions factor, the cooling water flow rate, and the process stream composition. 

Table 8-5 summarizes the data requirements of Methodology Ranks 1 and 2. 

Example 8-4: Calculation for Methodology Rank 4 for Cooling Towers

Given: Concentrations for C6H6 in the cooling water are 0.220 ppmw before exposure to the 

atmosphere for a cooling tower with a cooling water recirculation rate of 55,000 gal/min, 

sampling occurs monthly, and the leak repair took 45 days to complete. For the following 

month, sampling showed C6H6 concentrations of 0.320 ppmw before the cooling tower. 

The following equation (Eq, 8-5) should be used to calculate the emissions of C6H6, Ei, for the 

first monitoring period (the length of time of the leak for this period is one-half of 30 days 

[365 hours]): 

 

yr

ton Benzene

lb

ton

yr

hr

gal hr

gal lb Ei 1.1

2000

1

* 365 *

min *8.34 * 60

min

* 55,000

10

0.220

6

 

The following equation *Eq. 8-5) should be used to calculate the emissions of C6H6, Ei, for the 

second monitoring period plus remaining repair time (the length of leak for this period is 

1,095 hours based on 1 month [730 hours] plus 15 remaining days to repair [365 hours]): 

 

yr

ton Benzene

lb

ton

yr

hr

gal hr

gal lb Ei 4.8

2000

1

*1,095 *

min *8.34 * 60

min

* 55,000

10

0.320

6

 

So the total C6H6 emissions for this leak until repair are 5.9 tons (1.1 tons + 4.8 tons).
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8-11 

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

Rank Data That Must Be Collected The Way in Which Data Are Obtained

Rank 5—estimated 

speciated 

emissions

 AP-42 uncontrolled emissions 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, rotameters, or similar 

methods

 Length of time of the monitoring period 

(hours)

 Assume the leak occurs all year (8,760 

hr/yr)

The following equation (Equation 8-7) should be used to estimate VOC emissions: 

lb

ton H

hr

EVOC EFUnc FlowCoolingWate r Year 2000

1

* *

min

 * *60

(Eq. 8-7) 

where: 

EFUnc = Uncontrolled emissions factor for cooling towers of 6.0 pounds of VOC per 106

gallons of cooling water from AP-42 (Section 5.1) 

The following equation (Equation 8-8) should be used to estimate the emissions for a particular species 

component: 

lb

ton H

hr

Ei EFUnc WtFrac i FlowCoolingWate r Year 2000

1

* *

min

 * * *60

 (Eq. 8-8) 
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8-12 

8.4.2 Particulate Matter Emissions 

Methodology Rank 5 for cooling towers uses the total liquid drift emission factor given in AP-42 (U.S. 

EPA, 1995a; Section 13.4) of 1.7 lb of drift per 1,000 gallons of water (lb/103 gal) for induced draft 

cooling towers and the total dissolved solids (TDS) weight fraction to estimate PM-10 emissions. This is 

a conservative PM-10 emission factor in that it assumes that all TDS are in the PM-10 size range. The 

site-specific TDS fraction in the cooling water should be used when available, the site-specific TDS 

fraction can be estimated from the TDS of the makeup water and the cycles of concentration ratio (ratio of 

the measured parameter for the cooling tower water such as conductivity, calcium, chlorides, or 

phosphate, to the measured parameter for the makeup water), or if these data are not available, then use 

Example 8-5: Calculation for Methodology Rank 5 for Cooling Towers

Given: For VOC and HAP emissions from a cooling tower with a water recirculation rate of 

25,000 gal/min that is servicing a heat exchanger cooling a gasoline stream. Using the default 

average composition for the industry for gasoline (in liquid phase), the following equation 

(Eq. 8-7) should be used to calculate the annual emissions of VOC, EVOC:

yr

ton VOC

lb

ton

yr

hr

hr

gal

gal

lbVOC EVOC 39.4

2000

1

*8,760 *

min *60

min

* 25,000

10

6 6 

The following equation (Eq. 8-8) should be used to estimate the emissions for each HAP 

component in the gasoline stream. For example, to calculate the annual emissions of C6H6, Ei, 

the liquid composition of 1.61% of C6H6 in the default average gasoline composition (see 

Appendix A, Average Stream Compositions) should be used: 

yr

tonBenzene

lb

ton

yr

hr

hr

gal

gal

lbVOC Ei 0.63

2000

1

*8,760 *

min *60

min

*0.0161 * 25,000

10

6 6 

To estimate the default gasoline composition in liquid:

 1,3-Butadiene of 0.0037% by weight; emissions are 0.0015 ton/yr

 Trimethylpentane of 4.72% by weight; emissions are 1.9 tons/yr

 Benzene of 1.61% by weight; emissions are 0.63 ton/yr

 Biphenyl of 0.01% by weight; emissions are 0.0039 ton/yr

 Cresols of 0.789% by weight; emissions are 0.31 ton/yr.

 Cumene of 0.849% by weight; 0.33 ton/yr

 Ethylbenzene of 1.605% by weight; emissions are 0.63 ton/yr

 Hexane of 7.1% by weight; emissions are 2.8 tons/yr

 Methyl tertiary-butyl ether of 3.54% by weight; emissions are 1.4 tons/yr

 Naphthalene of 0.444% by weight; emissions are 0.18 ton/yr

 Phenol of 0.0551% by weight; emissions are 0.022 ton/yr

 Styrene of 3.5% by weight; emissions are 1.4 tons/yr

 Toluene of 7.21% by weight; emissions are 2.8 tons/yr

 Xylene of 7.17% by weight; emissions are 2.8 tons/yr

 Total HAP emissions are 15.2 tons/yr.

The total HAP emissions for this cooling tower are 15.2 ton total HAP per year. 
Version 1.0 Section 8—Cooling Towers 

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8-13 

the default average TDS fraction from AP-42, Table 13.4-2 of 20,600 ppmw. Other default average TDS 

fractions are provided for counter flow and cross flow cooling tower designs in AP-42 (U.S. EPA, 1995a; 

Section 13.4). 

lb

ton

H

hr

EPM EFDrift WtFrac TDS FlowCoolingWate r Year 2000

1

* *

min

10  * * 60

 (Eq. 8-9) 

Example 8-7: Calculation for Annual Emissions from Cooling Towers

Given: For PM-10 emissions from a cooling tower with a water recirculation rate of 25,000 

gal/min and that is sampled monthly for TDS. Using the site-specific TDS fraction and the 

operating hours between measurements, equation (Eq. 8-9) should be used to calculate the 

annual emissions of PM-10, EPM10. 

1

Date

2

TDS Concentration 

(ppmw)

3

Hours

4

Emissions 

(ton/month)

Jan 10 (startup Jan 1) 360 96 0.044

February 4 520 600 0.398

March 4 780 672 0.668

April 4 1,100 720 1.01

May 4 1,260 720 1.16

June 4 2,300 744 2.18

July 4 3,500 720 3.21

August 4 5,500 744 5.22

September 4 4,600 744 4.36

October 4 1,700 720 1.56

November 4 2,100 744 1.99

December (shutdown Dec 1 

- not operating in December)

(2,100 - Use value 

from previous month)

(648) 1.73

Total 7,872 24 ton/yr

Example 8-6: Calculation for Methodology Rank 5 for Cooling Towers

Given: For PM-10 emissions from a cooling tower with a water recirculation rate of 25,000 

gal/min, that is servicing a heat exchanger cooling a gasoline stream, and that is in service all 

year. Using the default average TDS weight fraction of 0.0206 (or 20,600 ppmw), the 

following equation (Eq. 8-9) should be used to calculate the annual emissions of PM-10, 

EPM10:

yr

ton PM

lb

ton

yr

hr

hr

gal

lb drift

lbTDS

gal

lb drift

EP M

10 230.

2000

1

*8,760 *

min * 60

min

* 0.0206 25,000

10

1.7 10 3



 
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8-14 

8.4.3 Chlorine Emissions 

Site-specific material balance may be one method of estimating chlorine emissions. Otherwise, limited 

information is available regarding chlorine emissions factors for cooling towers. EPA is currently 

reviewing available data to develop guidance for estimating chlorine emissions from cooling towers. To 

aid indeveloping that guidance, EPA is seeking additional data and suggestions for emissions estimation 

methologies. 

Example 8-8: Regulatory Note for Example Calculation for Methodology Rank 1 for 

Cooling Towers—How to Compare Speciated Concentration Results 

with Leak Definitions That Are Defined as Methane

In the case in which a facility conducts monitoring that provides speciated results, for 

regulatory purposes these concentrations must be converted to a CH4 basis for comparison to a

leak definition that is on a CH4 basis.

Given: For hexane emissions from a cooling tower with a water recirculation rate of 32,000 

gal/min, hexane concentration in the stripped air of 5 ppmv, a pressure of 29.9 in. of Hg, 

strippable air flow in the apparatus of 2,500 mL/min, a temperature of 32°C, a sample water 

flow rate in the apparatus of 125 mL/min, sampling that occurs quarterly, and a leak repair 

that took 45 days to complete.

In this example, hexane concentration in the stripped air was given as 5 ppmv. The following 

equation should be used to convert this concentration to CH4 basis:

4

4

6 14

30 ppmvCH

1moleC

1moleCH *

1moleC H

6 moleC

5 ppmvHexane * 















If the leak definition is 6.2 ppmv as CH4, then a leak has been detected because the hexane 

concentration is equivalent to 30 ppmv as CH4.
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9-1 

9. Product Loading Operations 

Product or commodity loading emissions occur when vapor is displaced by the liquid product when it is 

loaded into tank trucks, rail cars, and marine vessels (which include both ships and barges). The vapor 

may contain constituents from the material previously transported and from the product currently being 

loaded. HAP, VOC, and GHG are emitted from loading operations. Loading emissions estimates require 

information on the quantity of product loaded annually, the component composition of the product, vapor 

pressures of the components, the loading procedure, the type of vessel being loaded, and the effectiveness 

of the capture system and the controls used. Emissions from gasoline loading racks are regulated under 

the Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC) and are limited to 10 milligrams of TOCs 

per liter of gasoline (Subpart CC references Subpart R, which references some requirements for 40 CFR 

Part 60, Subpart XX). Emissions from marine vessel loading–operations for crude, gasoline, and other 

products are also regulated under the Petroleum Refinery MACT I (Subpart CC references the Marine 

Vessel Loading MACT in 40 CFR Part 63, Subpart Y) and are subject to a 97% emissions-reduction 

requirement for existing sources and 98% emissions-reduction requirement for new sources. 

Product loading emissions may be reduced by using submerged loading or bottom loading. Product 

loading emissions may be captured and controlled using a vapor collection system and an add-on air 

pollution control device. If an add-on air pollution control device or a vapor balance system is used to 

capture and control emissions, then capture and control efficiencies should be included in the emissions 

estimate. 

Control devices used for product loading operations typically include thermal or catalytic incinerators, 

adsorption systems, scrubbers, and flares. Vapor balancing systems are allowed as an option or an 

alternative for marine vessel loading operations under Subpart CC of the Petroleum Refinery MACT I. 

For loading racks subject to gasoline loading requirements, typically an EPA Method 25A or 25B 

performance test is conducted on the control device to collect outlet TOC concentration data and 

determine an outlet emissions factor based on the volume of gasoline loaded (i.e., meet the less than 10 

milligrams of total hydrocarbon per liter gasoline loaded [mg/L]). For marine vessel loading subject to 

requirements under Subpart CC MACT I, typically, a Method 25 performance test is conducted on the 

control devices to collect inlet and outlet TOC concentration data and determine a control efficiency. 

Table 9-1 summarizes the hierarchy of product loading operation emissions estimation techniques. 

Within a given measurement method (or rank), there may be alternative methods for determining the 

constituent-specific emissions; these compositional analysis methods are also provided in order of 

accuracy. The remainder of this section provides additional details and guidance regarding the ways in 

which to implement these methods. 

Table 9-1. Summary of Product Loading Operations Emissions Estimates 

Rank Measurement Method or Emissions Factor Compositional Analysis Data

1 Direct measurement (CEMS) for both flow rate 

and gas composition

 Pressure, temperature, and moisture content 

(depending on the monitoring system)

2 Direct measurement by EPA Method 18 (sitespecific emissions factor) and loading rate Not applicable

3 Direct measurement by EPA Method 25, 

Method 25A, or Method 25B (site-specific 

emissions factor) and loading rates

 Process-specific, service-specific concentrations

 Process-specific average concentrations

 Site-specific refinery average stream concentrations

 Default process compositions

(continued)
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9-2 

Table 9-1. Summary of Product Loading Operations Emissions Estimates (continued)

Rank Measurement Method or Emissions Factor Compositional Analysis Data

4 AP-42 emissions factor (default emissions 

factor) and loading rates

 Process-specific, service-specific concentrations

 Process-specific average concentrations

 Site-specific refinery average stream concentrations

 Default process compositions

9.1 Data Available on Product Composition and Properties 

To speciate the emissions into VOC or HAP, facilities should use site-specific information on the 

composition of product loaded if available (for more information, see Section 9.3.2, Estimate Controlled 

or Uncontrolled Emissions and Speciate). Data are often available on the product or commodity 

composition, sometimes for both the liquid and vapor phases and sometimes only for the liquid phase. 

Product-specific concentration, product-specific average concentration, or site-specific product 

concentrations should be used when available. If product-specific or site-specific data are not available, 

then a default average composition for products at refineries was developed to estimate emissions for the 

Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC). This default average composition for 

refineries may be used to speciate and generate VOC and HAP emissions factors, as shown in Table B-1

of Appendix B, Wastewater Treatment System Equations. 

Other properties such as the MW of the liquid, the MW of the vapor, and the vapor pressure of a 

multicomponent product or commodity are also often available. When these data are not readily available 

at the refinery, data from various references can be used or can be calculated using basic principles. For 

instance, property data are available in AP-42, Section 7.1 (Organic Liquid Storage Tanks), in Table 

7.1-2 for various petroleum fuels and in Table 7.1-3 for various petrochemicals (U.S. EPA, 1995a). 

If the weight composition of a commodity is available but other property data are not, estimates can be 

made. Appendix A presents equations that may be used for calculating estimates of the liquid vapor 

pressure, the molecular weight of the vapor, and the weight fraction of the vapor given a known liquid 

component composition. 

9.2 Methodology Rank 1 for Product Loading Operations 

For pollutants such as THC, it is anticipated that some loading operations may have CEMS for measuring 

the composition and the gas flow rate of the emissions from loading operations. If such monitors are 

present, the methods in Section 4.1, Methodology Rank 1 for Stationary Combustion Sources, should be 

used to calculate emissions. 

9.3 Methodology Ranks 2 and 3 for Product Loading Operations 

Performance testing conducted at the refinery may be used to develop site-specific emissions factors with 

emissions data correlated to throughput. These site-specific emissions factors may be used with 

throughput data to estimate the annual loading emissions. 

For gasoline loading activities regulated under Petroleum Refinery MACT I (40 CFR Part 63, Subpart CC 

and Subpart R), refineries have conducted periodic EPA Method 18, Method 25A, or Method 25B testing 

for speciated hydrocarbons or for outlet nonmethane organic compounds (NMOC); determined the flow 

rate based on EPA Method 2A or 2B testing; and measured and recorded the gasoline loading throughput 

during the testing. The outlet test results on a mass basis are correlated with the gasoline throughput 

during the test to demonstrate that the refinery is meeting the 10 mg/L gasoline emissions limitation. The 

test data could also be used to estimate the speciated hydrocarbons, total hydrocarbon, CH4, NMOC, or 

VOC loading emissions into the atmosphere based on the mass emissions per volume loaded factor 

developed during the performance test and the annual quantity of that product loaded. It is important to 
Version 1.0 Section 9—Product Loading Operations 

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9-3 

note that when NMOC is used, a CH4 emissions factor may also be developed. Additional information 

about speciation of the gasoline or product either as site-specific information or as defaults may be used 

to estimate individual species component emissions. 

For marine vessel loading regulated under the Marine Vessel Loading MACT (40 CFR Part 63, Subpart 

CC and Subpart Y), refineries have conducted EPA Method 2, 2A, 2C, or 2D flow rate testing and have 

conducted EPA Method 25 or 25A testing on the inlet and outlet streams of the control device to 

determine control device efficiency. The Marine Vessel Loading MACT requires initial performance 

testing of the control device, but it does not require ongoing or periodic testing. The outlet test data, along 

with the recorded product throughput during the testing, could also be used to estimate the total 

hydrocarbon, CH4, NMOC, or VOC loading emissions per volume loaded factor. This factor and the 

annual loading data of the product can be used to estimate emissions. It is important to note that when 

NMOC is used, a CH4 emissions factor may also be developed. Additional information on speciation of 

the gasoline or product either as site-specific information or as defaults may be used to estimate 

individual species component emissions. 

The data necessary to implement Methodology Ranks 1 and 2 for product loading operations include the 

emissions rate or emissions factor (either speciated by component or as total hydrocarbon, CH4, NMOC, 

or VOC) and throughput data of the products loaded. Table 9-2 summarizes the data requirements of 

Methodology Ranks 1 and 2. 

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

Rank Data That Must Be Collected The Way in Which Data Are Obtained

Rank 2—

speciated 

emissions

 Speciated component emissions 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 rates, gallons, or liters

Rank 3—

VOC or total 

hydrocarbon

emissions

 Total hydrocarbon or VOC emissions

factor for a product (mg/liter or lb/gal)

 Periodic EPA Method 25 or 25A 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 rates, gallons, or liters

Equation 9-1 should be used to estimate the emissions of each product using emissions rates or emissions 

factors developed from testing. 

2000 lb

1 ton ELi

 ERLi Thruput  (Eq. 9-1) 

where: 

 ELi = Emissions of component species ―i‖ (tons)

ERLi = Emissions rate of component species ―i‖ (lb/gal)

 Thruput = Throughput of product (gallons) 

When ERLi is based on total hydrocarbon, NMOC, or VOC, pollutant ―i‖ is simply the total hydrocarbon, 

NMOC, or VOC. When ERLi is based on single pollutant, pollutant ―i‖ will be the individual pollutant. 

When ERLi is based on total hydrocarbon, NMOC, or VOC (i.e., Method 25, 25A, or 25B testing), 

additional calculations are necessary to estimate individual pollutant emissions. To estimate the emissions 
Version 1.0 Section 9—Product Loading Operations 

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9-4 

of each pollutant, multiply Equation 9-1 for ELi by the vapor weight fraction of the component ―i‖, as 

shown in Equation 9-2. 

ELSpecies ERLi Thruput *WtfracSpecies 2000lb

1 ton

 * *

(Eq. 9-2) 

where: 

 ELSpecies = Emissions of component species ―i‖ (tons)

 WtfracSpecies = Vapor weight fraction of component species ―i‖ (fraction by weight)

9.4 Methodology Rank 4 for Product Loading Operations 

The emissions estimating methodology for loading operations is given in AP-42 (U.S. EPA, 1995a). In 

section 5.2 of AP-42, commodities are categorized into crude loading, gasoline loading, and what is 

termed ―other products‖ (i.e., not crude or gasoline). In the AP-42 methodology, there is one equation that 

is used for tanker trucks and rail cars for crude, gasoline, and other commodity products and for marine 

vessels for other commodity products (but not for crude or gasoline). In addition, Table 5.2-2 in AP-42 

presents other emissions factors that are used for marine vessels for gasoline. These equations provide the 

emissions for the ―product‖ or ―total hydrocarbon,‖ whether that product has multiple component species 

(e.g., gasoline) or whether that product is a single species (e.g., toluene). Depending on the commodity 

being loaded, the emissions factor (EFL) could be used for gasoline emissions, crude emissions, or other 

product emissions. The AP-42 methodology for gasoline and other products is summarized in the 

following sections. It is not expected that refineries will be loading crude for transport, but if so, the 

refiner should consult AP-42 for the emissions estimation methodology.

9.4.1 AP-42 Emissions Factors for ―Product‖ or ―Total Hydrocarbon‖ Emissions

9.4.1.1 Tanker Trucks (Any Commodity) and Marine Vessels (Products Other than 

Gasoline) 

Equation 9-3 should be used to estimate the emissions factor or the emissions rate for the product loaded, 

in terms of total hydrocarbon or the product: 

T

S P MW

ER Vap

L

* *

 12.46

(Eq. 9-3) 

where: 

ERL = Loading emissions factor or emissions rate for the product (or total hydrocarbon) 

loaded (in lb per 103 gallons of liquid loaded) 

S = Saturation factor (see Table 9-3) 

P = True vapor pressure of liquid loaded (pounds per square inch absolute [psia])4

MWVap = Molecular weight of vapors (lb/mol) 

T = Temperature of bulk liquid loaded (°R; °F + 460) 

 

4

 True vapor pressure is defined as the equilibrium partial pressure exerted by a volatile organic liquid as a function 

of temperature. It differs from the Reid vapor pressure, which is defined as the absolute vapor pressure exerted by a 

liquid at 100°F and is a common measure of the volatility of petroleum liquids. For a pure component at 100°F, the 

true vapor pressure is equivalent to the Reid vapor pressure. 
Version 1.0 Section 9—Product Loading Operations 

Review Draft – Do not cite or quote 

9-5 

Table 9-3. Saturation Factorsa 

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 emissions factors for marine vessels loading gasoline at 

marine terminals based on measurements of gasoline loading losses from ships and barges. Those 

emissions factors are presented in Table 9-4. (Table 5.2-2 of AP-42 also includes emissions factors in 

units of mg/L.) AP-42 does not provide ratings for these emissions factors. 

Table 9-4. VOC Emissions Factors for Marine Vessel Loading of Gasoline at Marine Terminalsa

Vessel Tank Condition Previous Cargo

Ships and Ocean Barges

(lb/103gal) Barges (lb/103gal)

Uncleaned Volatilec2.6 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 situationdAny cargo 1.8 3.4

a

Source: U.S. EPA, 1995a. The emissions factors for VOC (which excludes methane and ethane) may be used 

to 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 similar 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 pressure greater than 10 kilopascals (kPa) (1.5 psia).

d

Based on observation that 41% of tested ship compartments were uncleaned, 11% ballasted, 24% cleaned,

and 24% gas-freed. For barges, 76% were uncleaned.

9.4.2 Estimate Controlled or Uncontrolled Emissions and Speciate 

Using the emissions factor developed or identified from the methods previously discussed, the emissions 

can be estimated based on Equation 9-4: 

E ER Thruput L

L 

(Eq. 9-4) 
Version 1.0 Section 9—Product Loading Operations 

Review Draft – Do not cite or quote 

9-6 

where: 

 EL = Uncontrolled emissions (lb) of commodity 

ERL = Loading emissions rate (lb/103 gal of liquid loaded) 

 Thruput = Throughput of commodity (gallons) 

As previously discussed, depending on the commodity being loaded, the emissions rate ERL could be for 

gasoline, crude, or other product. Also as previously discussed, to speciate the emissions for specific 

components, the composition or concentration data available (i.e., product-specific, product-specific 

average, site-specific product, or default averages) can be used as shown in Equation 9-5. 

ELSpecies  ERL Thruput Wtfrac Species

(Eq. 9-5) 

where: 

 ELSpecies = Emissions (lb) of the component species ―i‖

 WtfracSpecies = 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 balance system is used to capture and control emissions, 

then capture and control efficiencies should be included in the emissions estimate. The capture efficiency 

is the portion of the total emissions that is captured by the vapor collection system. The effectiveness of 

the vapor collection system, or capture system, is dependent on the leak tightness of the truck tank, rail 

car, or marine vessel; the condition of the connection from the tanker or vessel collection header 

equipment to the vapor collection system; the leak tightness of the terminal’s vapor collection system; and 

the control device. For gasoline loading racks subject to Subpart CC, refineries are required to confirm 

and document the vapor tightness of the vehicles being loaded. For loading racks subject to gasoline 

loading requirements, an annual pressure and vacuum certification is required on the tanker truck (e.g., 

using EPA Method 27 in 40 CFR Part 60), a leak test using EPA Method 21 from 40 CFR Part 60 may be 

performed on the tanker truck, and a leak check using EPA Method 21 may be conducted on the 

terminal’s vapor collection system. In addition, the type of loading conducted (i.e., atmospheric, 

pressurized) and type of connection from the tank headspace to the vapor collection system and to the 

control device are factors. Typical capture efficiencies assumed for vapor collection procedures and 

systems are shown in Table 9-5. Capture efficiency for the vapor collection system can be applied based 

on the leak check conducted for the tanker truck, rail car, and marine vessel. 

Table 9-5. Capture Efficiencies for Vapor Collection Systemsa

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 tanker to the vapor collection system 

100%

 Pressure tank that is U.S. Department of Transportation certified

 Hard-piped bolted, flanged connection from tanker to the vapor collection system

100%

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

a

Source: TCEQ, 2000.
Version 1.0 Section 9—Product Loading Operations 

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9-7 

9.4.4 Control Efficiency 

The control efficiency represents the portion of the total captured emissions that are removed from the 

emissions stream by the add-on air pollution control device. The control efficiency determined for the 

control device should be applied based on performance testing, if available, or based on design efficiency 

and operating parameters. 

To estimate controlled emissions from loading, use Equations 9-6 and 9-7 to apply the capture efficiency 

and the control efficiency to the uncontrolled emissions: 

E ER Thruput ( Capture ) ( CE ) Cont

L   1  1 (9-6) 

E ER Thruput Wtfrac ( Capture ) ( CE ) ContSpecies

L   Species  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 1.0 Section 9—Product Loading Operations 

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9-8 

Example 9-1: Calculation for Rank 4—When Property Data Are Not Available

Calculate the VOC and HAP emissions for submerged loading of gasoline into dedicatedservice gasoline transport tank trucks (each with a volume of 8,000 gallons) based on the 

following information:

The refinery loads 210 tank trucks per year, with 100 tank trucks loading gasoline at a bulk 

temperature of 90°F, 55 loading at a bulk temperature of 77°F, and 55 loading at a bulk 

temperature of 40°F. Property data are available for liquid composition of the gasoline only; 

the properties are identical to those provided for gasoline in Example A-1 in Appendix A. 

First, the vapor pressure of gasoline and MWVAP 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 determined at the three loading temperatures using 

Antoine’s equation and Antoine’s coefficients, such as those provided in Table 7.1-5 of AP-42 

(U.S. EPA, 1995a).

From Example A-1 in Appendix A, at 90°F, the total system vapor pressure is 5.641 psia and 

the MW of the vapor, MWGasolineVAP, is 65.98 lb/lb-mol. Similar calculations for loading 

gasoline with bulk temperatures of 77°F and 40°F reveal the following (see Appendix A for 

further details):

Temperature Vapor Pressure MWGasolineVAP

77°F 4.40 psia 65.46 lb/lb-mol

40°F 2.03 psia 63.99 lb/lb-mol

The emissions rates at each temperature are calculated using Equation 9-3: 

 

5.059 lb/10 gal

90° F 460 ° R

lb mole

lb 0.60 5.641psia 65.98

12.46 3

90 





 

E RGasoline 

 

4.012 lb/10 gal

77 F 460 ° R

lb mole

lb 0.60 4.40psia 65.46

12.46 3

77 

 



 

E RGasoline 

 

1.939 lb/10 gal

40 F 460 ° R

lb mole

lb 0.60 2.03psia 63.99

12.46 3

40 

 



 

E RGasoline 

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

100 trucks 4,047 lb gasoline

truck

gal 8,000

1,000 gal

5.059 lb

90  











EGasoline   

55 trucks 1,765 lb gasoline

truck

gal 8,000

1,000 gal

4.012 lb

77  











EGasoline   

55 trucks 853 lb gasoline

truck

gal 8,000

1,000 gal

1.939 lb

40  











EGasoline   
Version 1.0 Section 9—Product Loading Operations 

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9-9 

Example 9-1 (continued): Calculation for Rank 4—When Property Data Are Not 

Available 

The individual VOC or HAP species at each bulk temperature can be estimated using the 

calculated gasoline vapor weight fraction for each species in Equation 9-5:

ELSpecies  EFL Thruput Wtfrac Species  Egasoline Wtfrac Species

See Table 9-6 for the emissions estimate summary for individual HAP species.

Finally, total emissions are estimated by summing the emissions estimates for each of the 

three bulk temperatures. Total gasoline emissions (VOC) are 6,700 lb (4,047 lb + 1,765 lb + 

853 lb), or 3.3 tons (6,700 lb ÷ 2,000 lb/ton).

Similarly, total emissions of each of the individual HAP species are estimated by summing the 

emissions estimates for each of the three bulk temperatures. The results are presented in 

Table 9-6.
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9-10 

Table 9-6. Sample Calculation Methodology Rank 4—Summary of Emissions (When Property Data Are Not Available) 

CAS 

Number Component ―i‖

At 90°F

Gasoline, 

Vapor, 

wt%

At 90°F

EGasoline = 4,047 lb

ELSpecies ―i‖ (lb)

At 77°F

Gasoline, 

Vapor, 

wt%

At 77°F

EGasoline = 1,765 lb

ELSpecies ―i‖ (lb)

At 40°F

Gasoline, 

Vapor, 

wt%

At 40°F

EGasoline = 853 lb

ELSpecies ―i‖ (lb)

Sum Total 

Annual 

Emissions 

(lb)

106-99-0 1,3-butadiene 4.56E-02 1.8 4.74E-02 0.84 5.30E-02 0.45 3.1

1634-04-4 Methyl tertiary butyl ether 3.16E+00 130 2.99E+00 53 2.44E+00 21 200

110-54-3 Hexane 6.91E+00 280 6.58E+00 120 5.52E+00 47 440

540-84-1 2,2,4-trimethylpentane 1.54E+00 62 1.42E+00 25 1.07E+00 9.2 96

71-43-2 Benzene 9.98E-01 40 9.33E-01 16 7.36E-01 6.3 63

108-88-3 Toluene 1.39E+00 56 1.25E+00 22 8.67E-01 7.4 86

1330-20-7 Xylene 4.44E-01 18 3.82E-01 6.7 2.31E-01 2.0 27

100-41-4 Ethylbenzene 1.08E-01 4.4 9.29E-02 1.6 5.62E-02 0.48 6.5

100-42-5 Styrene 1.65E-01 6.7 1.42E-01 2.5 8.50E-02 0.72 9.9

98-82-8 Cumene 2.83E-02 1.1 2.37E-02 0.42 1.30E-02 0.11 1.7

91-20-3 Naphthalene 9.26E-04 0.037 7.12E-04 0.013 3.02E-04 0.0026 0.053

92-52-4 Biphenyl 2.58E-06 0.00010 1.79E-06 0.000032 5.36E-07 0.0000046 0.00014

108-95-2 Phenol 1.68E-04 0.0068 1.18E-04 0.0021 3.55E-05 0.00030 0.0092

1319-77-3 Cresols 1.62E-03 0.066 1.11E-03 0.020 2.99E-04 0.0026 0.088

Total HAP 600 240 95 940
Version 1.0 Section 10—Fugitive Dust Sources 

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10-1

10. Fugitive Dust Sources 

There are three main sources of fugitive dust (or PM) at a petroleum refinery: roads (paved and unpaved); 

fluid catalytic cracking catalyst handling; and petroleum coke storage and handling. Petroleum refineries 

may also operate a landfill or land application unit, which would also be a source of fugitive PM 

emissions. There are no direct emissions measurement methodologies commonly employed for fugitive 

dust sources. Fugitive dust sources are described in Chapter 13 of AP-42 (U.S. EPA, 1995a). 

Unfortunately, none of the default factors for the fugitive dust emissions correlations are specific to 

petroleum refineries. Table 10-1 provides recommended default values for the correlations based on a 

review of the available data. The methodologies are detailed in Chapter 13 of AP-42 and basic guidance 

for applying the methodologies are provided below. 

 For paved roads, Equation 1 of Section 13.2.1.3 of AP-42 (U.S. EPA, 1995a) should be used with 

the silt loading recommended in Table 10-1; values for all other equation variables are provided 

in Section 13.2.1.3. 

 For unpaved roads, Equation 1a and 1b of Section 13.2.2.2 of AP-42 (U.S. EPA, 1995a) should 

be used with the silt content recommended in Table 10-1; values for all other equation variables 

are provided in Section 13.2.2.2. 

 For handling of FCCU catalyst or petroleum coke, use Equation 1 of Section 13.2.4.3 of AP-42 

(U.S. EPA, 1995a) with the moisture content recommended in Table 10-1; values for all other 

equation variables are provided in Section 13.2.4.3. 

Table 10-1. Default Values for Fugitive Dust Emission Estimates 

Source/Variable Description

Potential Range 

Value

Recommended 

Value

Paved road : silt loading, g/m20.4a– 120b10

Unpaved road : silt content % 1.8 – 25.2c7

FCCU catalyst ―drops‖: silt content % 50d

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 % 30f

Flexicoking or petroleum coke ash: silt content % 13g

Flexicoking or petroleum coke ash: moisture content % 7

g

a

Based on low average daily traffic (ADT) public road factor in Table 13.2.1-3 in AP-42.

b

Based in asphalt batching industrial facility factor in Table 13.2.1-4 in AP-42.

c

Based on range for industrial sites in Table 13.2.2-3 in AP-42.

d

Assumed based on median particle size of FCCU catalyst and equilibrium catalyst (E-cat) of 65 μm. 

e

Values for coke breeze assumed to apply.

f

Assumed value based on wet coke cutting techniques. 

g

Values for flue dust assumed to apply.

The methodologies outlined in Chapter 13 provide means of estimating PM10 and PM2.5 emissions. These 

emission are all filterable PM so that PM10-PRI = PM10-FIL and PM25-PRI = PM25-FIL. For FCCU 

catalyst handling emissions and for petroleum coke handling activities, emission estimates should also be 

provided metal HAP emissions. Concentrations of specific metal HAP are commonly determined for the 

FCCU equilibrium catalyst; these concentrations can be used time the PM10 emissions rate to determine 
Version 1.0 Section 10—Fugitive Dust Sources 

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10-2

the metal HAP emissions rate from FCCU catalyst and E-cat handling (external from the FCCU). 

Table 5-3 provides concentration ratios of various metal HAP to nickel on CCU fines. These 

concentration ratios can be used to augment the FCCU catalyst and E-cat metal HAP emissions estimates 

when only nickel concentrations are routinely determined. Compositional analysis of petroleum coke 

material or ash should also be determined so that the metal HAP emissions from petroleum coke or ash 

handling can be reported. 
Version 1.0 Section 11—Startup and Shutdown 

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11-1

11. Startup and Shutdown 

Except for the CEMS-based measurements (i.e., Methodology Rank 1), most of the emissions estimation 

methods provided in this Refinery Emissions Protocol document characterize the emissions during 

normal operating conditions. However, during startup and shutdown, the process operations are not 

normal. During startup, the reactor temperatures may not be sufficient for the necessary reactions to occur 

or the process flow rate may be well below typical operating conditions. Under these conditions, 

processes that do not typically have atmospheric emissions may have significant emissions. While most 

control devices will operate well at lower vent rates, some control devices, such as venturi scrubbers, 

require a minimum flow for effective operation. During startup and shutdown, the emissions 

characteristics of the processes may be significantly different than those during normal operations. When 

the emission estimation methodology relies on normal operating conditions (e.g., most site-specific and 

default emission factors), it is important to specifically estimate the emissions during startup and 

shutdown and include these emissions in the facility’s annual emissions 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 system. When a hydrotreater or hydrocracking unit is 

shutdown, this often leads to excess hydrogen being added to the fuel gas. This leads to higher NOX

emissions from process heaters. When certain energy intensive units, such as catalytic reforming units, 

are shutdown, the refinery may have excess fuel gas, which is subsequently flared. Depending on the 

methods used to estimate emissions from combustion sources and flares, these fuel gas fluctuations may 

already be fully accounted within the inventories for combustion sources and flares. However, if default 

estimates (or site-specific estimates based on source tests conducted under typical operating conditions) 

are used, then emissions during these significant fuel gas fluctuation events should be estimated and the 

emissions included in the annual emission values. 

It is beyond the scope of this protocol document to provide methods of estimating emissions during all 

startup or shutdown events. However, the primary emissions event during startup or shutdown is expected 

to be vessel depressurization and purging (or degassing). Methods are provided in this section to account 

for these events are described in this section. 

11.1 Gaseous Process Vessel Depressurization and Purging 

Process vessel depressurization for gaseous process can be estimated using Equation 11-1. This equation 

assumes ideal gas law; for gases that do not follow ideal gas law, compressibility factors can be included. 

The equation includes a void fraction term to account for inert material, such as packing material, 

distillation trays, and certain catalyst particles, that reduce the gaseous space. This equation may 

underestimate the emissions if the solid material in the vessel may adsorb certain gas constituents (e.g., 

petroleum coke or activated carbon), that can desorb at lower pressures and temperatures. 

 

 

















   









i

i

i void MF

MVC

MW

E f V

V

V V

T

528 R

14.7

P 14.7

 (Eq. 11-1) 

where: 

 Ei = Emissions of pollutant ―i‖ during depressurization event (lbs/event).

 PV = Gauge pressure of the vessel when depressurization gases are first routed to the 

atmosphere (pounds per square inch gauge, psig). 

 14.7 = Assumed atmospheric pressure (pounds per square inch, psi). 

 TV = Absolute temperature of the vessel when depressurization gases are first routed to the 

atmosphere (degrees Rankine, °R).
Version 1.0 Section 11—Startup and Shutdown 

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11-2

 528 = ―Standard‖ temperature used in the calculation (°R).

 VV = Volume of the vessel (cubic feet, ft3).

 fvoid = Volumetric void fraction of vessel. Use 1 unless packing material or trays are present 

in the vessel. 

MWi = Molecular weight of pollutant ―i‖ (lb/lb-mole). 

 MVC = Molar volume conversion factor (385.3 scf/ lb-mole). 

MFi = Volume fraction of pollutant ―i‖ in vessel gas (scf pollutant i/scf of gas). 

Typically, depressurization and purging occurs initially to a flare. Depending on the methodology used to 

estimate the emissions from the flare, these gas flows may be included in the flare emission estimates 

(e.g., when measuring flare gas volumes and composition). If the flare emissions methodology does not 

account for these flows (e.g., default factors), Equation 11-1 can be used to estimate the mass of gas sent 

to the flare (using initial depressurization temperatures and pressures) and these mass rates can be 

adjusted by the flare destruction efficiency to estimate the emissions during the flare venting period. The 

use of Equation 11-1 is illustrated in Example 11-1, Gaseous Depressurization Calculation. 

11.2 Liquid Process Vessel Depressurization and Purging 

For vessels that contain liquids, depressurization and purging emissions can be estimated based on the 

―heel‖ or fraction of the liquid that remains in the vessel prior to purging. This method assumes that the 

mass of liquid remaining in the tank will overwhelm the quantity of contaminants in the headspace. For 

systems operating with very volatile material (such as butane in gasoline), it may be necessary to consider 

the initial gaseous emissions for the most volatile components (using Equation 11-1) as well as the liquid 

heel. A heel fraction may be between 0.1 and 1 percent, depending on the viscosity of the liquid, the 

surface area of internals within the vessel, and the location of the drainage port or pump line (higher 

viscosities, higher internal surface areas, and higher drainage port locations will increase the heel 

fraction). Using the heel method, it is assumed all of the liquid heel is eventually volatilized. Knowledge 

of the process steam can be used to speciate the emissions. Again, some of the heel may be purged to a 

flare and a control efficiency for this portion is warranted, but some fraction will also be purged directly 

to the atmosphere. Example 11-2, Liquid Heel Emissions Calculation, illustrates this methodology. 
Version 1.0 Section 11—Startup and Shutdown 

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11-3

Example 11-1: Gaseous Depressurization Calculation

A catalytic reforming unit is depressurized and purged to a flare. After the purge sequence, no 

liquid materials are assumed to be present. The reactor is then depressurized and purged to the 

atmosphere. The total volume of the reactor vessels are 20,000 ft3and the catalyst occupies 

40% of the total reactor volume. The temperature and pressure of the vessel when first purged 

to the atmosphere are 250°C and 10 psig, respectively. The composition of the gas is in the 

reactor vessel after the flare purge is:

Benzene = 1.2 vol%

Hexane = 0.5 vol%

Toluene = 1.4 vol%

Xylenes = 0.8 vol%

Other VOC = 2.1 vol%

Nitrogen = 94 vol%

For use in Equation 10-1, the reactor vessel temperature must be converted to °R: 250°C = 

250×9/5 + 32 = 482°F = 482+460 = 942°R.

The void fraction is the volume fraction not occupied by catalyst particles: 1-0.4 = 0.6.

The molecular weight of the constituents listed range from 78 to 106 lb/lb-mol. It is assumed 

the ―other VOC‖ has similar molecular weight so a molecular weight for this unspecified 

material is estimated from, the weighted average molecular weight of the known organic 

constituents: MolWt ―other VOC‖ = (1.2×78+0.5×86+1.4×92+0.8×106)/4.9 = 90 lb/lb-mol.

Using benzene as the example, substituting into Equation 11-1 yields:

 

E   lbs tons i 0.01 27.5 0.014

385.3

78 20000 0.6

942

528 R

14.7

10 14.7

  











   









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, which is 158 lbs/event or 0.079 tons/event. If 

this event occurred twice during the year, the annual emission would be 0.16 tons VOC/yr.
Version 1.0 Section 11—Startup and Shutdown 

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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, the heel is assumed to be 0.5% of the liquid 

volume. The maximum liquid volume is 20,000 ft3× (1-0.4) = 12,000 ft3, so the volume of 

liquid in the reactor is estimated to be 60 ft3(12,000 × 0.005).

Appendix A contains average composition of various process fluids. Reformate composition is 

given as:

Benzene = 4.6 wt%

Hexane = 3.9 wt%

Toluene = 14.5 wt%

Xylenes = 13.8 wt%

Other VOC = 63.2 wt%

To calculate the potential mass emissions, a mass of liquid remaining must be calculated. 

Using a specific gravity of 0.8 for reformate, the mass of liquid remaining is estimated to be: 

60 ft3× 0.8 × 62.4 lb/ft3(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 material (VOC) is estimated to be emitted considering 

emissions from both the flare and atmospheric purging. 

Emissions of specific constituents are calculated based on the mass composition in the liquid:

Benzene = 354 ×0.046 = 16 lbs/event

Hexane = 354 ×0.039 = 14 lbs/event

Toluene = 354 ×0.145 = 51 lbs/event

Xylenes = 354 ×0.138 = 49 lbs/event

Other VOC = 354 ×0.632 = 224 lbs/event.
Version 1.0 Section 12—Malfunctions 

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12-1

12. Malfunctions 

Malfunctions may occur either within the process unit or to a control device used to reduce a source’s 

emissions. During malfunction events, emissions may be significantly higher than the emissions that 

occur under normal operating conditions. Except for the CEMS-based measurements (i.e., Methodology 

Rank 1), most of the emissions estimation methods provided in this Refinery Emissions Protocol 

document characterize the emissions during normal operating conditions. As such, malfunction events 

must be accounted for separately for malfunction events and these malfunction emissions must be added 

to the normal process emissions to accurately estimate annual emissions. 

Because of the myriad of potential malfunction events that could occur, it is impossible to provide 

specific guidance for all possible malfunction scenarios. However, because malfunction events are 

important to both annual and short-term emissions, the duration and emissions associated with each 

malfunction event should be recorded, and these emissions should be included in the emissions inventory. 

The following list provides specific events for which malfunction emissions estimates should be made to 

accurately account for these emissions. Again, this is not intended to be an exhaustive list, but rather 

representative examples. In some malfunction events, such as pressure relief valve opening to a flare 

during a system over-pressurization event, the emissions during the malfunction event may be adequately 

accounted for by the flare emissions methodology (i.e., when using continuous monitoring of gases is sent 

to a flare), but in other cases it may not (i.e., when using default factors). As such, emissions inventory 

developers will need to evaluate the malfunction events in light of their inventory methods to determine if 

it is appropriate to use special malfunction emissions calculations. Emissions estimates should be 

provided for the following malfunction events: 

1. Any instance when a control device is bypassed or is not functioning properly. 

2. Any instance when the amine scrubbing system and/or sulfur recovery plant is offline or not 

operating at normal efficiencies (generally affecting SO2 emissions estimates from combustion 

sources, flares, and/or sulfur recovery plants). 

3. Instances during startup or shutdown when units are vented directly into the atmosphere or when 

they are vented to a flare and the flare methodology does not account for these gases. 

4. Tank roof landings (for more information, see Section 3, Storage Tanks, of this Refinery 

Emissions Protocol document). 

5. Instances of over-steaming a flare. When gas is being sent to a flare, but no flame is visible, then 

it is likely the result of over-steaming. Fifty percent flare destruction efficiencies should be used 

during periods of over-steaming. 

6. Any instance when a spill or similar emergency release occurs. 

There are three types of malfunction events considered in this section: control device malfunctions; 

process vessel overpressurization; and spills. 

12.1 Control Device Malfunctions 

When a control device is used to reduce the emissions from a particular source, the site-specific emissions 

factors or other methodologies provided in this Refinery Emissions Protocol document account for these 

controls when the equipment is operating normally. However, when control systems are not operating 

normally or or bypassed the emissions may be orders of magnitude more than when these emissions are 

controlled. If a control device that normally achieves 99% control efficiency is offline for 3 days, then the 

emissions during these 3 days would equal the annual emissions projected for the controlled emissions 

source. 
Version 1.0 Section 12—Malfunctions 

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12-2

When there is a malfunction with a control device, the emissions from the source can be estimated based 

on the uncontrolled emission factor or by adjusting the controlled emissions base on the control device’s 

efficiency. It is important to note that the control device efficiency is often different for different 

pollutants. A wet scrubber on an FCCU may be 95% efficient at reducing SO2 emissions, 90% efficient 

for PM and metal HAPs, but has no real impact on VOC or NOX emissions. Similarly, oversteaming a 

flare that causes poor combustion efficiency will increase VOC and reduced sulfur emissions but reduce 

NOX and SO2 emissions. Table 12-1 provides default control efficiencies and correction factors for 

certain control device malfunctions. 

Table 12-1. Control Device Efficiency and Multiplier Factors for Control Device Malfunctions 

Source/Control Device 

DescriptionaPollutant Classb

Control Device 

Efficiencyc(%)

Controlled 

Emissions 

Multiplier

d

FCCU or FCU/wet scrubber PM, metal HAP 92 12.5

SO2 95 20

FCCU or FCU/ESP PM, Metal HAP 92 12.5

SO2, NOX, VOC, organic 

HAP, CO

0 1

FCCU or FCU/cyclone PM, Metal HAP 85 6.7

FCCU or FCU/CO boiler CO, VOC, most organic HAP 98% 1

NOX, PAH, Formaldehyde -100% 0.5

FCCU or FCU/SCR NOX 92 12.5

FCCU or FCU/SNCR NOX 60% 1.7

Sulfur plant malfunction with sour 

gas sent to flare

SO2 96 – 99.8% 25 - 500

H2S 0 – 98% 1– 50

Tail gas treatment malfunction with 

tail gas sent to flare

SO2 95% 20

H2S 0 – 95% 1 – 20

a

Abbreviations:

FCCU = fluid catalytic cracking unit

FCU = fluid coking unit

ESP = electrostatic precipitator

CO boiler = carbon monoxide boiler

SCR = selective catalytic reduction

SNCR = selective non-catalytic reduction

b

Pollutant class. Only pollutants affected by the control device are listed. For other pollutants, assume the 

control device efficiency is 0% and the controlled emissions multiplier is 1.

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

particular pollutant.

d Controlled emissions multiplier. Factor used to escalate the controlled emission factor to account for periods of 

control device malfunction = 1/(1-control device efficiency). 

12.2 Vessel Overpressurization 

Process malfunctions often result in temperature or pressure excursions that must be released from the 

vessel to prevent a catastrophic failure. Generally, these emergency releases will be sent to a flare. 

Depending on the methodology used to estimate the emissions from the flare, these gas flows may be 

included in the flare emission estimates (e.g., when measuring flare gas volumes and composition). If the 

flare emissions methodology does not account for these flows (e.g., default factors), Equation 11-1 

(presented in Section 11.1) can be used to estimate the mass of gas sent to the flare (using initial 
Version 1.0 Section 12—Malfunctions 

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12-3

depressurization temperatures and pressures); the calculated mass release rates must then be adjusted by 

the flare destruction efficiency to estimate the emissions during the emergency release event. 

12.3 Spills 

Generally, it can be assumed that 100% of the compounds spilled are emitted into the atmosphere. For 

heavier liquids, the mass transfer correlations for an oil layer (Koil) as provided in Appendix B, 

Wastewater Treatment System Equations, Section B.2.1, Oil Water Separators, of Section 7, Wastewater, 

can be used. Equation 12-1 can be used to estimate the emissions based on the quantity of material 

spilled, the area of the spill, and the time period from when the initial spill occurred to the final clean up: 

 

K At V

i i o

oil E VC e

/

,

1



   (Eq. 12-1) 

where: 

 Ei = Emissions estimate of pollutant ―i‖ (kilograms per spill event) 

ρ = Density of spilled liquid (kilograms per cubic meter) 

 V = Volume of spilled material (cubic meters) 

 Ci,o = Concentration of pollutant ―i‖ in spilled fluid prior to the spill event (mass fraction; 

kilogram per kilogram) 

 Koil = Mass transfer coefficient for an oil (organic) liquid (meters per second) 

t = Duration of the spill (seconds) 

 A = Area covered by the spill (square meters) 
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12-4

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Version 1.0 Section 13—References 

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13-1 

13. References 

Coburn, J. and M. Icenhour. 2008. Memorandum from J. Coburn and M. Icenhour, RTI, to Brenda Shine, 

EPA/SPPD. Preliminary Analysis of Short-term Variability in Storage Vessels Emissions. 

December 29. 

EIA (U.S. Energy Information Administration). 2009. Refinery Capacity Report 2009. Prepared by the 

Energy Information Administration, Washington, DC. June 25. 

EMEP/CORINAIR (European Monitoring and Evaluation Programme/COoRdination of Information on 

AIR emissions). 2006. Atmospheric Emission Inventory Guidebook 2006. Technical Report No. 

11/2006. Available at: http://www.eea.europa.eu/publications/EMEPCORINAIR4. 

ERG (Eastern Research Group, Inc). 2001. Emission Inventory Improvement Program Technical Report 

Series. Volume II, Chapter 2: ―Preferred and Alternative Methods for Estimating Air Emissions 

from Boilers.‖ Prepared for Point Sources Committee Emission Inventory Improvement Program. 

January. 

Hansell, D., and G. England. 1998. Air Toxic Emission Factors for Combustion Sources Using Petroleum 

Based Fuels, Volume 2: Development of Emission Factors Using CARB Approach. Prepared by 

EER for S. Folwarkow, Western States Petroleum Association, Concord, CA, and K. Ritter, 

American Petroleum Institute, Washington, DC. 

Levelton Consultants Ltd. 2005. Emission Monitoring and Reporting Strategy – Summary and 

Background. Prepared for Canadian Council of Ministers of the Environment and NFPRER 

Monitoring and Reporting Team. 

Lucas, B. 2007. Memorandum from B. Lucas, EPA/SPPD, to Project Docket File (EPA Docket No. EPAHQ-OAR-2003-0146). Storage Vessels: Control Options and Impact Estimates. August 3, 2007. 

Docket Item No. EPA-HQ-OAR-2003-0146-0014. 

Moye, D., V. Boero, and G. Everett. 2006. The whole plant approach to air emission modeling for 

NESHAP compliance. WEFTEC®.06:6685−6694. 

NYSERDA (New York State Energy Research and Development Authority). 2005. Hydrogen Fact Sheet. 

Hydrogen Production–Steam Methane Reforming (SMR). Available at: 

http://www.getenergysmart.org/Files/HydrogenEducation/6HydrogenProductionSteamMethaneR

eforming.pdf. 

RTI (Research Triangle Institute). 2002. Petroleum Refinery Source Characterization and Emission 

Model for Residual Risk Assessment. Prepared for U.S. Environmental Protection Agency, Office 

of Air Quality Planning and Standards, Research Triangle Park, NC. EPA Contract No. 68-D6-

0014. July. 

SCAQMD (South Coast Air Quality Management District). 2004a. Source Test Report 03-194 Conducted 

at Chevron/Texaco Refinery, El Segundo, California—Volatile Organic Compound (VOC), 

Carbon Monoxide (CO), and Particulate Matter (PM) Emissions from a Coke Drum Steam Vent. 

May 14. 

SCAQMD (South Coast Air Quality Management District). 2004b. Source Test Report 03-197 Conducted 

at Conoco-Phillips Refinery, Carson, California—Volatile Organic Compound (VOC), Carbon 

Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent. July 23. 
Version 1.0 Section 13—References 

Review Draft – Do not cite or quote 

13-2 

SCAQMD (South Coast Air Quality Management District). 2004c. Source Test Report 03-198 Conducted 

at Exxon Mobil Refinery, Torrance, California—Volatile Organic Compound (VOC), Carbon 

Monoxide (CO), and Particulate Matter (PM) Emissions From a Coke Drum Steam Vent. 

March 4. 

SCAQMD (South Coast Air Quality Management District). 2004d. Source Test Report 03-200 Conducted 

at Shell Oil Refinery, Wilmington, California—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 Quality). 2000. Air Permit Technical Guidance for 

Chemical Sources: Loading Operations. 

TCEQ (Texas Commission on Environmental Quality). 2003. Source Sampling Procedures Manual, 

Appendix P, Cooling Tower Monitoring, Air Stripping Method (Modified El Paso Method) for 

Determination of Volatile Organic Compound Emissions from Water Sources. January 31. 

TCEQ (Texas Commission on Environmental Quality). Air Quality Division. 2009. 2008 Emissions 

Inventory Guidelines. RG-360A/08. January. 

The United States – Mexico Foundation for Science. 2008. A Customized Approach for Quantifying 

Emissions for the Electric Power Generation Sector in Mexico. Prepared for: SEMARNAT and 

CFE. Revision 2, Revised by RTI International for U.S. Environmental Protection Agency Clean 

Air Markets Division and Climate Change Division. December. 

Tumbore, DC. 1998. The magnitude and source of air emissions from asphalt blowing operations. 

Environmental Progress 17(1):53–59. 

U.S. EPA (Environmental Protection Agency). 1995a. Compilation of Air Pollutant Emission Factors. 

Volume 1: Stationary Point and Area Sources. AP-42, Fifth Edition. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. 

U.S. EPA (Environmental Protection Agency). 1995b. Protocol for Equipment Leak Emission Estimates. 

EPA-453/R-95-017. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

U.S. EPA (Environmental Protection Agency). 1996. Method 8260B, Volatile Organic Compounds by 

Gas Chromatography/Mass Spectrometry. Revision 2, December. SW-846. 

U.S. EPA (Environmental Protection Agency). 1998a. Locating and Estimating Air Emissions from 

Sources of Benzene. EPA-454/R-98-011. Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. 

U.S. EPA (Environmental Protection Agency). 1998b. Petroleum Refineries—Background Information 

for Proposed Standards, Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, 

and Sulfur Recovery Units. EPA-453/R-98-003. Washington, DC: Government Printing Office. 

U.S. EPA (Environmental Protection Agency). 2006. TANKS Emissions Estimation Software, Version 

4.09D. Office of Air Quality Planning and Standards, Technology Transfer Network, 

Clearinghouse for Inventories and Emissions Factors, Available at 

http://www.epa.gov/ttnchie1/software/tanks/index.html. 

U.S. EPA (Environmental Protection Agency). 2009. Mandatory Reporting of Greenhouse Gases (Final 

Rule). Federal Register: 74 FR 56260. October 30. 
Version 1.0 Section 13—References 

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13-3 

URS Corporation. 2008. Source Test Report of the Coker Steam Vent. Prepared for Hovensa, LLC, St. 

Croix, U.S. Virgin Islands. September 8. 

Yerushalmi, L., and S.R. Guiot. 1998. Kinetics of biodegradation of gasoline and its hydrocarbon 

constituents. Appl Microbiol Biotechnol 49:475−481. 
Version 1.0 Section 13—References 

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Version 1.0 Appendix A—Average Stream Compositions 

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A-1 

Appendix A 

Average Stream Compositions 
Version 1.0 Appendix A—Average Stream Compositions 

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A-2 

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Version 1.0 Appendix A—Average Stream Compositions 

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A-3 

Table A-1. Refinery Average Stream Hazardous Air Pollutant Compositions—Default Values 

CAS 

Number HAP Component

Gasoline Alkylate Crude Oil Reformate Naphtha Avg. Conc. (wt%)

Wtd Avg. Conc. 

(wt%)

Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor Liquid Vapor

106-99-0 1,3-Butadiene 0.0037 0.0037

540-84-1 2,2,4-Trimethylpentane 4.72 0.953 35.4 9.4 0.263 0.247 0.799 0.355 8.51 2.29 2.27 0.679

71-43-2 Benzene 1.61 0.626 0.118 0.061 0.446 0.807 4.61 3.32 1.244 1.06 1.61 1.17 1.1546 1.028

92-52-4 Biphenyl 0.01 0 0 0 0.061 0.00002 0.025 0 0 0 0.02 0.000004 0.0396 1.15E-05

1319-77-3 Cresols 0.789 0.00065 0 0 0.218 0.0008 0.141 0.0002 0.0191 0.00003 0.23 0.0003 0.2905 0.0006074

98-82-8 Cumene 0.849 0.01565 0.004 0.0001 0.126 0.0108 0.968 0.033 0.91 0.0368 0.57 0.02 0.4258 0.01638

100-41-4 Ethylbenzene 1.605 0.0631 0.011 0.0006 0.346 0.0633 3.73 0.272 1.366 0.118 1.41 0.1 1.018 0.08803

110-54-3 Hexane 7.138 4.428 3.22 2.63 2.46 7.11 3.9 4.48 7.53 10.27 4.85 5.78 4.045 6.551

1634-04-4

Methyl tertiary-butyl 

ether 3.54 3.62 0 0 0 0 0 0 0 0 0.71 0.72 0.6669 0.68198

91-20-3 Naphthalene 0.444 0.0006 0.012 0.00002 0.219 0.00125 0.798 0.0018 0.399 0.0011 0.37 0.001 0.3322 0.001131

108-95-2 Phenol 0.0551 0.0001 0 0 0.323 0.0031 0.0276 0.0001 0.066 0.0003 0.09 0.0007 0.2066 0.001850

100-42-5 Styrene 3.528 0.0882 0 0 0 0 0.0907 0.0042 0 0 0.72 0.02 0.6737 0.01703

108-88-3 Toluene 7.21 0.842 0.503 0.077 0.878 0.477 14.54 3.14 5.05 1.295 5.64 1.17 3.862 0.8860

1330-20-7 Xylene 7.17 0.235 0.0212 0.0009 1.42 0.216 13.79 0.8367 5.49 0.395 5.58 0.34 4.125 0.2941

Sum of listed HAP 38.7 10.9 39.3 12.2 6.76 8.94 44.0 12.6 22.9 13.5 30.3 11.6 19.1 10.2
Version 1.0 Appendix A—Average Stream Compositions 

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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, and the weight fraction of the vapor can be estimated. 

The following steps and equations may be used for calculating these estimates: 

1. From the weight fraction values in the gasoline (liquid), Equation A-1 should be used to estimate 

the number of moles of component ―i.‖

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 partial pressure of each component ―i‖ in liquid.

i P(i )  P x (Eq. A-3) 

where: 

 P(i) = Partial pressure of component ―i‖ (psia)

 P = Vapor pressure of pure component ―i‖ at the liquid temperature (psia)

 xi = Liquid mole fraction 

4. To estimate the total pressure of the liquid, Equation A-4 should be used to estimate the average 

vapor pressure for the gasoline mixture by summing the partial pressure of each component ―i‖ 

(liquid). 

 

n

PtotalVP Pi

1

(Eq. A-4) 

5. From mole fraction of component ―i‖ (liquid), Equation A-5 should be used to estimate the mole 

fraction of component ―i‖ in the vapor using Raoult’s law.

totalVP

i

i

P

P

y 

(Eq. A-5) 

6. Equation A-6 should be used to estimate the MW of the gasoline vapor, MWVAP, using the mole 

fraction of vapor (yi) and the MW of the pure component ―i‖(MWi). 

  

n

Vap i MWi MW y

1

(Eq. A-6) 

where: 

MWVAP = Molecular weight of the vapor (lb/mol) 

MWi = Molecular weight of component ―i‖ (lb/mol)
Version 1.0 Appendix A—Average Stream Compositions 

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A-5 

7. Equation A-7 should be used to estimate the gasoline vapor weight fractions using the gasoline 

vapor mole fractions and the MWVAP. 

Vap

i i

vap MW

y MW Wtfrac



(Eq. A-7) 

Example A-1: Calculation of Vapor Pressure and Molecular Weight for Gasoline 

Loading Example

Calculate the vapor pressure of gasoline and MWVAP for submerged loading of gasoline into 

dedicated-service gasoline transport tank trucks (each with a volume of 8,000 gallons) based 

on the following information:

The refinery loads 100 tank trucks per year at a bulk temperature of 90°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, such as those provided in Table 7.1-5 of AP-42 

(U.S. EPA, 1995a).

Using Steps 1 through 7 from this Appendix A, the gasoline liquid mole fraction can be 

calculated from the weight fraction or weight percent component 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 P(i)  P * x

 Step 4. 

 

n

PtotalVP Pi

1

 Step 5. 

totalVP

i

i

P

P

y 

 Step 6. 

 

n

Vap i MWi MW y

1

*

 Step 7. 

Vap

i i

vap MW

y MW wtfrac*



See Table A-2 for the calculations of thee variables. At 90°F, the total system vapor pressure is 5.641 

psia and the MW of the vapor, MWGasolineVAP, is 65.984 lb/lb-mol.
Version 1.0 Appendix A—Average Stream Compositions 

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A-6 

Table A-2. Sample Calculation of Average Molecular Weight and Vapor Weight Fraction 

Step 1 Step 2 Step 3 Step 4 Step 5 Step 6 Step 7

A B C D=C/A E=D/(ΣD) F=E*B G=F/(ΣF) H=G*A

G=H/(ΣH)*

100%

CAS 

Number Compound MolWt

Pvap at 

90°F (psia)

Gasoline 

Liquid 

(wt%)

Gasoline 

Liquid 

(moles/ 100 

g)

Gasoline 

Liquid 

(mole 

fraction)

Gasoline 

Partial 

Pressure 

(psia)

Gasoline 

Vapor 

(mole 

fraction)

MolWt 

Contribution 

Gasoline 

Vapor (g/mol)

Gasoline 

Vapor 

(wt%)

106-99-0 1,3-butadiene 54.09 50.53 0.0037 6.840E-07 6.206E-05 3.136E-03 5.559E-04 3.007E-02 0.0456

1634-04-4 Methyl tertiary butyl ether 88.15 3.666 3.54 4.016E-04 3.643E-02 1.336E-01 2.368E-02 2.087E+00 3.16

110-54-3 Hexane 86.18 3.970 7.138 8.283E-04 7.514E-02 2.983E-01 5.288E-02 4.557E+00 6.91

540-84-1 2,2,4-Trimethylpentane 114.2 1.336 4.72 4.132E-04 3.749E-02 5.008E-02 8.878E-03 1.014E+00 1.54

71-43-2 Benzene 78.11 2.544 1.61 2.061E-04 1.870E-02 4.758E-02 8.434E-03 6.588E-01 0.998

108-88-3 Toluene 92.14 0.7911 7.21 7.825E-04 7.099E-02 5.615E-02 9.955E-03 9.172E-01 1.39

1330-20-7 Xylene 106.1 0.2542 7.17 6.755E-04 6.128E-02 1.558E-02 2.762E-03 2.931E-01 0.444

100-41-4 Ethylbenzene 106.2 0.2758 1.605 1.512E-04 1.371E-02 3.782E-03 6.704E-04 7.118E-02 0.108

100-42-5 Styrene 104.2 0.1921 3.528 3.387E-04 3.073E-02 5.904E-03 1.047E-03 1.090E-01 0.165

98-82-8 Cumene 120.2 0.1369 0.849 7.064E-05 6.408E-03 8.774E-04 1.555E-04 1.869E-02 0.0283

91-20-3 Naphthalene 128.2 0.008555 0.444 3.4642E-05 3.143E-03 2.689E-05 4.766E-06 6.109E-04 9.26E-04

92-52-4 Biphenyl 154.2 0.001059 0.01 6.485E-07 5.883E-05 6.231E-08 1.105E-08 1.703E-06 2.58E-06

108-95-2 Phenol 94.11 0.01253 0.0551 5.855E-06 5.311E-04 6.656E-06 1.180E-06 1.110E-04 1.68E-04

1319-77-3 Cresols 108.1 0.008422 0.789 7.296E-05 6.619E-03 5.574E-05 9.881E-06 1.069E-03 0.00162

74-98-6 Propane 44.1 162.5 0.001 2.268E-07 2.057E-05 3.342E-03 5.924E-04 2.613E-02 0.0396

106-97-8 n-Butane 58.12 43.79 4.7 8.087E-04 7.336E-02 3.213E+00 5.695E-01 3.310E+01 50.2

75-28-5 Isobutane 58.12 17.04 1.7 2.925E-04 2.654E-02 4.521E-01 8.015E-02 4.658E+00 7.06

109-66-0 n-Pentane 72.15 13.32 3.9 5.405E-04 4.904E-02 6.533E-01 1.158E-01 8.356E+00 12.7

78-78-4 Isopentane 72.15 4.920 7.9 1.095E-03 9.933E-02 4.888E-01 8.664E-02 6.251E+00 9.47

Other VOC 100.2 0.5531 43.13 4.304E-03 3.904E-01 2.159E-01 3.828E-02 3.836E+00 5.81

nT PtotalVP MWvap

Totals 100.0 1.102 1.000 5.641 1.000 65.98 100.0
Version 1.0 Appendix B—Wastewater Treatment System Equations 

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B-1 

Appendix B 

Wastewater Treatment System Equations 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

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B-2 

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Version 1.0 Appendix B—Wastewater Treatment System Equations 

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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 emissions tool and to correct errors found in the presentation of some of 

these equations as provided in Chapter 4.3 of AP-42 (EPA, 1995). 

B.1 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 mass transfer resistance. 

The liquid and gas phase mass transfer resistances are very different for turbulent surfaces compared to 

quiescent (laminar flow) surfaces. Therefore, the overall mass transfer coefficient is a composite of the 

overall mass transfer coefficient for the turbulent surface area and the overall mass transfer coefficient for 

the quiescent surface area based on an area weighted average as follows: 

A

K A K A

K

OL t t OL q q

OL

  



, ,

(Eq. B-1) 

where: 

 KOL = Overall mass transfer coefficient (m/s) 

 KOL,t = Overall mass transfer coefficient for turbulent surface areas (m/s) 

 At = Turbulent surface area = faer A, m2

 faer = Fraction of total surface area affected by aeration 

 KOL,q = Overall mass transfer coefficient for quiescent surface areas (m/s) 

 Aq = Quiescent surface area = (1-faer) A, m2 (Note: At + Aq must equal A) 

 A = Total surface area (m2) 

The overall mass transfer coefficient for turbulent surface areas based on the two resistance module is: 

1

, ,

,

1 1





















 

l t g t

OL t

k H k

K

(Eq. B-2) 

where: 

 kl,t = liquid phase mass transfer coefficient for turbulent surface areas (m/s) 

H' = dimensionless Henry's law constant = H/RTH

 H = Henry's law constant (atm-m3

/mol) 

 R = ideal gas law constant = 0.00008205 (atm-m3/mol-K)

 TH = temperature at which Henry's law constant was evaluated = 298 K. 

 kg,t = gas phase mass transfer coefficient for turbulent surface areas (m/s) 

Similarly, the overall mass transfer coefficient for quiescent surface areas is 

1

, ,

,

1 1





















 

l q g q

OL q

k H k

K

(Eq. B-3) 

where: 

 kl,q = Liquid phase mass transfer coefficient for quiescent surface areas (m/s) 

 kg,q = Gas phase mass transfer coefficient for quiescent surface areas (m/s). 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-4 

The mass transfer correlations used in this module to estimate the individual mass transfer coefficients are 

the same as those used in the WATER9 emissions model developed by EPA. The documentation of these 

mass transfer correlations can be accessed from EPA’s Web site at http://www.epa.gov/ttnchie1/software/ 

water. Only the basic equations are provided here. For a more detailed discussion of these mass transfer 

correlations, the reader is referred to Chapter 5 of the Air Emissions Models for Waste and Wastewater

report (U.S. EPA, 1994). 

B.1.1 Liquid Phase Mass Transfer Coefficient for Turbulent Surfaces 

The liquid phase, turbulent surface mass transfer coefficient is calculated as follows: 

 

0.5

2,

,

3 20

,

10.76

8.22 10 1.024

































 

     



 

O l

i l

t l

c f l

T

tot

l t D

D

A

J P O MW

k



 (Eq. B-4) 

where: 

 J = Oxygen transfer factor (lb/h/hp) 

 Ptot = Total power to the impellers (hp) 

 T = Water temperature in (C)

 Ocf = Oxygen correction factor 

MWl = Molecular weight of liquid (water) (g/mol) 

ρl = Density of liquid (water) (g/cm3 = Mg/m3) 

 Di,l = Diffusivity in liquid (water) (cm2/s) 

 DO2,l = Diffusivity of oxygen in liquid (water) (cm2/s) 

B.1.2 Gas Phase Mass Transfer Coefficient for Turbulent Surfaces 

The gas phase, turbulent surface mass transfer coefficient is calculated as follows: 

1

.

7 1.42 0.4 0.5 0.21

,

1.35 10 Re   

g t

  

g

 p  Scg Fr  Di a MWadimp k

 (Eq. B-5) 

where: 

Reg = Gas phase Reynolds number = (dimp

2 w ρg)/μg

ρg = Density of gas (air) (g/cm3) 

μg = Viscosity of gas (air) (g/cm-s)

 p = Power number = 0.85 (550 Ptot/Naer) gc,2 / [(62.428ρl )w3(dimp/30.48)5 ] 

 gc,2 = Gravitational constant = 32.17 lbm-ft/s2-lbf = 0.03283 gc

 Naer = Number of aerators 

 w = Rotational speed (rad/s) 

Scg = Gas phase Schmidt number = μg/(ρg Di,a) 

Fr = Froud number = [w2(dimp/30.48) ]/ gc,2

 Di,a = Diffusivity of constituent in air (cm2/s) 

MWa = Molecular weight of air (g/mol) 

 dimp = Impeller diameter (cm) 

 gc = Gravitational constant = 980 cm/s2

B.1.3 Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces 

The appropriate correlation to use to estimate the liquid phase mass transfer coefficient is dependent on 

the wind speed and the fetch-to-depth ratio of the impoundment. The fetch is the linear distance across the 

treatment unit, and it is calculated from the unit’s surface area, assuming a circular shape. That is, 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-5 

0.5

4

















A

F

(Eq. B-6) 

where: 

 F = Fetch (m) 

For wind speeds less than 3.25 m/s, the following correlation is used regardless of the fetch-to-depth ratio 

(F/dliq): 

3

2

6 ,

, 2.78 10 















 



ether

i l

l q D

D

k

(Eq. B-7) 

where: 

 kl,q = Liquid phase, quiescent surface mass transfer coefficient (m/s) 

 Di,l = Diffusivity of constituent in liquid (water) (cm2/s) 

 Dether = Diffusivity of ether in water = 8.5 × 10-6 cm2/s

For windspeeds greater than or equal to 3.25 m/s, the appropriate correlation is dependent on the fetch-todepth ratio as follows: 

  

6 4 * 0.5

14,

, 1.0 10 10   

     liq

b

l q

liq

k a U Sc

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 

Scliq = Liquid phase Schmidt number = μl/(ρl Di,l) 

μl = Viscosity of water (g/cm-s)

ρl = Density of water (g/cm3) 

3

2

9 7 2 ,

14 51.2,

, 2.605 10 1.277 10 































 

















   

 

ether

i l

liq

l q

liq D

D

U

d

F

k

d

F

For

(Eq. B-9) 

3

2

7 2 ,

51.2,

, 2.611 10 















  



ether

i l

l q

liq D

D

k U

d

F

For

(Eq. B-10) 

B.1.4 Gas Phase Mass Transfer Coefficient for Quiescent Surfaces 

The gas phase mass transfer coefficient for quiescent surface areas is estimated as follows: 

3 0.78 0.67 0.11

,

4.82 10  kg q  U  Scg F

(Eq. B-11) 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-6 

B.2 Collection Systems and Process Units 

B.2.1 Weirs 

Weirs are typically used in wastewater collection and treatment units as dams, allowing solids to settle in 

the quiescent areas. The first step in calculating air emissions is to calculate the volatilization-reaeration 

theory mass transfer coefficient (KD), using equation B-12. Air emissions (N) for each pollutant are 

calculated using equation B-13. 

0.75

2,

,

0.16 

















O l

i l

D D

D

K h

 (Eq. B-12) 

     0 N g /s  1 exp  K D QC

 (Eq. B-13) 

where: 

 Q = Volumetric flow rate (m3/s) 

Co = Initial constituent concentration (g/m3) 

 H = Weir height (ft) 

B.2.2 Junction Boxes and Lift Stations 

Junction boxes and lift stations collect and equalize wastewater prior to pumping to the wastewater 

treatment system. As previously mentioned, these components should be covered the vented; however, if 

uncovered, the following procedure can be used to estimate air emissions: 

 Step 1: Calculate the liquid phase mass transfer coefficient for turbulent surfaces (kl,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

i l

T

l t

A

V D

k

0.5

,

( 20)

,

0.184 1.024

(Eq. B-14) 

where: 

 V = Unit volume (m3) 

Default values: 

J = 3 (lb/h/hp) 

 Ocf = 0.83 

MWl = 18 (g/mol) 

 ρl = 1 (g/m3) 

 Ptot = 0.0264 (hp/m3) ×V 

 DO2,l = 2.4×10-5 (cm2/s) 

 Step 2: Calculate the gas phase mass transfer coefficient for quiescent surfaces (kg,q) as described 

in Section B.1.4, Gas Phase Mass Transfer Coefficient for Quiescent Surfaces. 

 Step 3: Calculate the overall mass transfer coefficient (K) with the following equation: 

 

  g q l t

l t g q

OL H k k

k H k

K

, ,

, ,

'

'





(Eq. B-15) 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-7 

 Step 4: Calculate the tank effluent concentration (CL) with the following equation: 

K A Q

QC C g m

OL

L





3 0

( / )

(Eq. B-16) 

 Step 5: Calculate the air emissions (N) with the following equation: 

Ng /s  KOLCL A

(Eq. B-17) 

B.2.3 Sumps 

Sumps typically collect and equalize wastewater from various collection systems prior to treatment. As 

previously mentioned, these components should be covered the vented; however, if uncovered, the 

following procedure can be used to estimate air emissions: 

 Step 1: Calculate the liquid phase mass transfer coefficient for quiescent surfaces (kl,q) as 

described in Section B.1.3, Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces. 

 Step 2: Calculate the gas phase mass transfer coefficient for quiescent surfaces (kg,q) as described 

in Section B.1.4, Gas Phase Mass Transfer Coefficient for Quiescent Surfaces. 

 Step 3: Calculate the overall mass transfer coefficient (K) with the following equation: 

 

  g q l q

l q g q

OL H k k

k H k

K

, ,

, ,

'

'





 (Eq. B-18) 

 Step 8: Calculate the tank effluent concentration (CL) with the following equation: 

K A Q

QC C g m

OL

L





3 0

( / )

(Eq. B-19) 

 Step 9: Calculate the air emissions (N) with the following equation: 

Ng /s  KOLCL A

(Eq. B-20) 

B.2.4 Oil-Water Separators (API) 

An oil-water separator is a treatment unit designed to separate oil and suspended solids from wastewater. 

As previously mentioned, these units are typically covered and vented and thus open-air emissions 

estimations are not required. However, if the treatment units are uncovered, then the following procedure 

can be used to estimate air emissions. 

First, calculate the gas phase mass transfer coefficient for quiescent surfaces (kg,q) with Equation B-11. 

Next, calculate the overall mass transfer coefficient for oil (Koil) with the following equations: 

oil g qKeqoil K k ,

(Eq. B-21) 

where: 

oil a o

a oil

oil MW P

P MW

Keq





*



(Eq. B-22) 

Air emissions are determined from the following equations: 

Ng /s  KoilCL,oil A

(Eq. B-23) 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-8 

where: 

 

oil oil

oil oil

L oil K A Q

Q Co C g m





3

,

/

(Eq. B-24) 

If the oil layer is > 1cm, then use this equation: 

  oil oil ow

ow

oil f f K

K Co Co

 



1

(Eq. B-25) 

If the oil layer is < 1cm, then use this equation: 

oil

oil f

Co Co 

(Eq. B-26) 

Qoil  f

oilQ

(Eq. B-27) 

where: 

P* = Constituent vapor pressure (mm Hg)

MWoil = Molecular weight of oil (g/mol)

ρoil = Density of oil (g/m3) 

 P0 = Total pressure (atm) 

 Qoil = Volumetric flow rate of oil (m3/s) 

Cooil = Initial concentration of constituent in oil phase (g/m3) 

 Kow = Octanol-water partition coefficient 

 foil = 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 (kl,q) can be determined by the 

method described in Section B.1.3, Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces. 

Second, the gas phase mass transfer coefficient for quiescent surface (kg,q) can be calculated by the 

method described in Section B.1.4. Third, the overall mass transfer coefficient (KOL) can be determined 

by Equation B-1. Finally, the air emissions (N) can be calculated with the following equations: 

  KOLA QaH CL N(g /s)   

(Eq. B-28) 

where: 

K A Q Q H 

QC C g m

OL a

L

  



3 0

( / )

(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 mentioned, these tanks should be covered the vented; 

however, if these tanks are uncovered, then the following procedure can be used to estimate air emissions: 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-9 

 Step 1: Calculate the liquid phase mass transfer coefficient for turbulent surfaces (kl,t) with 

Equation B-4. 

 Step 2: Calculate the gas phase mass transfer coefficient for turbulent surfaces (kg,t) with Equation 

B-5. 

 Step 3: Calculate the liquid phase mass transfer coefficient for quiescent surfaces (kl,q) as 

described in Section B.1.3, Liquid Phase Mass Transfer Coefficient for Quiescent Surfaces. 

 Step 4: Calculate the gas phase mass transfer coefficient for quiescent surfaces (kg,q) as described 

in Section B.1.4, Gas Phase Mass Transfer Coefficient for Quiescent Surfaces. 

 Step 5: Calculate the overall mass transfer coefficient for turbulent surfaces (KOL,t) with Equation 

B-2. 

 Step 6: Calculate the overall mass transfer coefficient for quiescent surfaces (KOL,q) with Equation 

B-3. 

 Step 7: Calculate the overall mass transfer coefficient (KOL) with Equation B-1. 

 Step 8: Calculate the tank effluent concentration (CL) with the following equation: 

K A Q

QC C g m

OL

L





3 0

( / )

(Eq. B-30) 

 Step 9: Calculate the air emissions (N) with the following equation: 

Ng /s  KOLCL A

(Eq. B-31) 

B.2.7 Biological Treatment Unit (with a Known Wasting Rate) 

The determination of air emissions from biological treatment units is similar to equalization tanks with 

the addition of a biodegradation factor. Additionally, whereas turbulent and quiescent surface areas 

impact air emissions for mechanically aerated systems, the air volumetric flow rate impacts diffused 

aeration systems. Consequently, two slightly different methods are used to estimate air emissions. 

For mechanically aerated systems, follow Steps 1 through 7 of Section B.2.6 to determine the overall 

mass transfer coefficient (KOL). 

For diffused aeration systems, first calculate the average diffused air flow rate Qa,avg (m3/s): 

2

0

,

















a

a g

a avg

Q

P

Q P

Q

 (Eq. B-32) 

where: 

 Pg = Blow gauge pressure (lb/in2) 

 P0 = Atmospheric pressure (atm) × 14.696 (lb/in2atm)=(lb/in2) 

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 KL[NH4]a, kl,ta and kg,ta with the following equations: 

0.4

,

[ 4] 0.08 0.012 















 

t

a avg

L NH A

Q

K a

(Eq. B-33) 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-10 

where: 

 KL[NH4]a = Ammonium volumetric mass transfer coefficient (h-1) 

Note: make sure the units used are consistent (e.g., Q=m3/hr and A=m2) 

0.5

, 4

,

, [ 4] 

















l NH

i l

l t L NH D

D

k a K a

(Eq. B-34) 

where: 

 Dl,NH4 = Diffusivity of Ammonium in water (6.93×10-5 cm2/s) 

 kl,ta = Volumetric liquid phase mass transfer coefficient (hr-1) 

The kl,t values must then be calculated from the kl,ta value with the following equation: 

a

k a

k

l t

l t

3600

,

, 

(Eq. B-35) 

where: 

 kl,t = Liquid phase mass transfer coefficient (m/s) 

 a = Specific interfacial area based on liquid volume (m-1) = A/V 

 V = Aeration basin volume (m3) 

Note: kl,t (m/hr) divided by 3600 (s/hr) = (m/s) 

Hsieh et al. (1992) reported the ratio of kg/kl ranged from 2.2 to 3.6 for diffused aeration systems. 

Therefore, kg can be approximated by the following equation: 

g t l t

k k

,

 3

,

(Eq. B-36) 

where: 

 kg,t = Gas phase mass transfer coefficient (m/s) 

The KOL,t, KOL,q, and KOL are then calculated by using steps by using equations B-2, B-3, and B-1. 

Next, calculate the tank effluent concentration (CL) and the emissions rate (N) with the following 

equations. 

For mechanically aerated systems: 

Ng /s  KOLCL A

(Eq. B-37) 

For diffused aeration systems: 

    KOLA QaH CL N g /s   

(Eq. B-38) 

where: 

 

   

a

b b ac CL g m

2

4

/

0.5 2

3   



(Eq. B-39) 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-11 

For mechanically aerated systems: 

i

OL w abs WAS VSS e

Q

K A Q k C Q

a

 



,

 (Eq. B-40) 

  0

max

, C

Q

V C V

K A Q k C Q

Q

Ks b

i

MLVSS

O L w abs WAS VSS e

i

     (Eq. B-41) 

For diffused aerated systems: 

i

OL a avg w abs WAS VSS e

Q

K A Q H Q k C Q

a

   



, ,

(Eq. B-42) 

  0

max

, , C

Q

V C V

K A Q H Q k C Q

Q

Ks b

i

MLVSS

O L a avg w abs WAS VSS e

i

       (Eq. B-43) 

K C0c   S

(Eq. B-44) 

where: 

Qw = Wasted activated sludge flow rate (m3/s) 

Qe = Effluent flow rate (m3/s) 

Qi = Influent flow rate (m3/s) 

KS = Half saturation biorate constant (g/m3) 

 Vmax = Maximum biorate constant (g/s-g biomass) 

 CMLVSS = Mixed-liquor volatile suspended solids (g/m3) 

 CWAS,VSS = Wasted sludge volatile suspended solids (g/m3) 

 kabs = Partition coefficient for organic contaminant (m3/g) 

where: 

abs OC K OC k f

6

1 10  

(Eq. B-45) 

 fOC = Weight fraction of carbon in biomass (g C/g) (default value 0.33) 

KOC = Organic carbon partition coefficient (g/MgC/(g/ m

-3

)

1×10-6= unit conversion (megagrams per gram, Mg/g)

where: 

log KOC log KOW  0.32

(Eq. B-46) 

B.2.8 Biological Treatment Unit (with an Unknown Wasting Rate) 

Air emissions estimate calculations from aerated lagoons are very similar to those for activated sludge 

units. The difference is sludge is not wasted from the lagoon, rather it settles and accumulates on the 

lagoon bottom until dredging. The assumptions made in this document are: (1) at steady-state conditions 

the amount of sludge that settles and thus removed from the unit is equal to the biomass production rate, 

and (2) once the sludge and associated contaminants settle, they are considered removed from the system. 

Follow the procedure in Section B.2.7 to determine the overall mass transfer coefficient (KOL), the unit 

effluent concentration (CL), and the emissions rate (N). However, variables a, b, and c are determined by 

the following equations 
Version 1.0 Appendix B—Wastewater Treatment System Equations 

Review Draft – Do not cite or quote 

B-12 

For mechanically aerated systems: 

i

OL BODi i abs e

Q

K A C Q k Q

a

 



0.67

(Eq. B-47) 

  0

max 0.67 C

Q

V C V

K A C Q k Q

Q

Ks b

i

MLVSS

O L BODi i abs e

i

     (Eq. B-48) 

For diffused aerated system: 

i

OL a avg BODi i abs

Q

K A Q H C Q k

a

 ,

  0.67



(Eq. B-49) 

  0

max

, 0.67 C

Q

V C V

K A Q H C Q k

Q

Ks b

i

MLVSS

O L a avg BODi i abs

i

      (Eq. B-50) 

K C0c   S

(Eq. B-51) 

B.3 References 

Hsieh, C., R. Babcock, and M. Stenstrom. 1992. Estimating semi-volatile organic compound emission 

rates and oxygen transfer coefficients in diffused aeration. Presented at the 65th Water 

Environment Federation Conference, New Orleans, LA, September 20–24. 

Monteith, H., W. Parker, and H. Melcer. 1996. Impact of bubble-induced surface turbulence on gas-liquid 

mass transfer in diffused aeration systems. Presented at the Water Environment Federation’s 

Annual Technical Exhibition and Conference, Dallas, TX, October 5–9. 

U.S. EPA (Environmental Protection Agency). 1994. Air Emissions Models for Waste and Wastewater. 

EPA-453/R-94-080A. Office of Air Quality Planning and Standards, Research Triangle Park, NC. 

U.S. EPA (Environmental Protection Agency). 1995. Compilation of Air Pollutant Emission Factors. 

Volume 1: Stationary Point and Area Sources. AP-42, Fifth Edition. Office of Air Quality 

Planning and Standards, Research Triangle Park, NC. 
Version 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

C-1 

Appendix C 

Primer for TANKS Model Users 
Version 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

C-2 

[This page intentionally left blank.] 
Version 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

C-3 

C. Primer for TANKS Model Users 

In general, EPA recommends that the emissions estimation procedures detailed in Chapter 7.1 of AP-42 

(U.S. EPA, 1995a) be used to calculate air pollutant emissions from organic liquid storage vessels. There 

are many tools available, such as TANKS v4.09D emissions estimation software that can be used to 

perform the necessary calculations detailed in Chapter 7.1 of AP-42 (U.S. EPA, 1995a). TANKS v4.09D 

software can be downloaded for free at: http://www.epa.gov/ttnchie1/software/tanks/index.html (under 

the How to Get TANKS 4.09D link). Because TANKS v4.09D is widely used, this appendix is included to 

provide tips and insights on using the TANKS program. This appendix will also highlight some potential 

enhancements to the modeling of storage tank emissions that may be implemented when using the AP-42 

equations directly (or potentially other software packages) that are not currently afforded by TANKS 

v4.09D. 

The calculations in the TANKS program are specific to the type of tank, and the results will be highly 

dependent on the type of liquid stored. Each individual storage tank should be modeled separately. There 

may be instances in which a set of tanks have identical properties and materials and very similar 

throughputs so that the emissions from a single storage tank can be modeled and used as the emissions for 

each tank in the set. However, this type of ―model tank‖ analysis should be used and generally be limited 

to situations in which limited data are available (i.e., if throughput is only measured by product and not by 

individual tank, then modeling a group of identical tanks used to store that product may be necessary). 

For inventories developed by the petroleum refinery or storage tank operators, it is recommended that 

individual tank data be entered into the TANKS program (or other similar software), and the emissions 

results for individual tanks be reported in the emissions inventory. For some uses of the emissions 

inventory data, specific emissions location and source characteristics data are needed. These data become 

lost or less accurate when emissions from a group of tanks (e.g., those that would be assigned to the same 

source classification code [SCC]) are aggregated when reporting to the emissions inventory. 

To enter a new tank, first select the tank type from the drop-down menu labeled ―Create a New Tank 

Record.‖ There are five basic tank types: horizontal fixed roof tanks; vertical fixed roof tanks; external 

floating roof tanks; internal floating roof tanks; and domed external floating roof tanks. Next, fill out the 

information in the Identification, Physical Characteristics, Site Selection, Tank Contents, and Monthly 

Calculations tabs with the appropriate information. Tables C-1 and C-2 show the required input by tank 

orientation. These inputs may either be from a drop-down list based on the TANKS database for location, 

tank color, and other tank-specific information or taken directly from process data. In TANKS, selecting 

the city will set the meteorological data that will be used in the calculations. After entering all of the 

requested data, the tank information can be saved by pressing the Save button at the bottom of the gray 

window. 
Version 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

C-4 

Table C-1. TANKS Inputs by Tank Configuration-Tank Dimensions and Characteristics 

Horizontal 

Tank

Vertical 

Fixed-Roof 

Tank

Internal 

Floating 

Roof

External 

Floating 

Roof

Domed 

External 

Floating 

Roof

Identification number     

Description     

State     

City     

Company     

Dimensions and Characteristics

Shell height (feet [ft])  

Diameter (shell diameter, ft)   

Volume  

Maximum liquid height  

Average liquid height  

Working volume (gallons)  

Turnovers per year    

Net throughput (gallons per year 

[gal/yr])

  

Is tank heated?  

Is tank underground? 

Self-supporting roof 

Number of columns 

Effective column diameter 

Roof type  

Roof fitting category  

Tank construction  
Version 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

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     

(External) shell/paint shell condition     

Internal shell condition 

Rim Seal 

Primary seal   

Secondary seal   

Deck Characteristics

Deck type 

Deck fitting category 

Breather Vent Settings

Vacuum setting (psig)  

Pressure setting (psig)  

Roof Characteristics

Color/shade  

Condition 

Type 

Height (ft) 

Roof paint condition 

Site Selection

Nearest major city     

Daily average ambient temperature     

Annual average maximum temperature     

Annual average minimum temperature     

Average wind speed     

Annual average solar insulation factor 

(Btu/(ft × ft ×day)     

Atmospheric pressure (pounds of force 

per square inch absolute [psia])

    

Tank Contents

Chemical category of liquid     

Single or multi-component liquid     

Mixture properties, if applicable     

Throughput by month     
Version 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

C-6 

For the internal floating roof tank, the external floating roof tank, and the domed external floating roof 

tank, it is possible to define the fitting type to represent specific characteristics of the tanks at your 

facility. Using facility-specific tank information will ensure that the calculated emissions estimates are as 

accurate as possible. The fittings information can be entered under the Physical Characteristics tab by 

selecting the View/Add Fittings button and providing the fitting type and status. Table C-3 contains a list 

of the different fitting types and status options. Using the information provided in Tables C-1 through 

C-3, the tanks program estimates the anticipated emissions specifically for the particular location, tank 

type, and process characteristics. 

Once a tank is entered, you can use or import that tank as a starting point for adding new tanks. To copy 

data from an existing tank to a new tank, select DATA, then TANKS, and then New Record from the 

TANKS 4.0 main menu or by selecting the appropriate acronym from the toolbar on the main screen. 

Click on the Copy button at the bottom of the tank pop-up screen. Then click on the tank that you want to 

copy from a dropdown menu, and then select whether you want to copy just the Tank Data, just the 

Liquid Data, or both (―All Data‖). Simply opening an existing tank and changing the name does not 

create a new tank record, it only renames and replaces the old record. 

Because TANKS uses preloaded meteorological data, year-to-year variations in emissions will only result 

from differing throughput or tank service (storing different material than in previous years). If 

accommodated in other software packages, meteorological data that are specific to the reporting year 

should be used because this information will provide more accurate emissions values. Studies have 

indicated that emissions may vary by up to 25% from year to year depending on the meteorological 

conditions for that year (Coburn and Icenhour, 2008). Also, if accommodated in other software packages, 

directly measured liquid temperatures or monthly average ambient temperatures should be used for the 

bulk liquid temperatures, and these values should be used to calculate monthly average emissions rates. In 

TANKS, even when using the monthly calculations option, unfortunately the annual average liquid 

temperature is still used. As such, unless there are extreme differences in throughputs by month, the 

monthly calculation procedures used in TANKS are unlikely to significantly alter the annual emissions 

estimates. Based on limited model analyses, monthly variations in liquid temperature may be significant 

and may influence the annual average emissions if monthly emissions are estimated more rigorously (i.e., 

by accounting for variations in bulk liquid temperature) (Coburn and Icenhour, 2008).

The TANKS program typically provides total hydrocarbon emissions estimates. TANKS is also designed 

to calculate the individual component emissions from known mixtures and to estimate emissions from 

typical refined petroleum products. More than 100 organic liquids are included in the TANKS chemical 

database, but it is also designed to analyze other substances based on their chemical properties and the 

parameters shown in Table C-4. If you store a component or mixture in the storage tanks and have 

available property data (i.e. chemical database inputs), then these can be added to the TANKS program. 

In addition to the analysis of individual chemicals, the TANKS program also has the capability to 

calculate the characteristics of defined mixtures. When the ―Multiple‖ option is selected for the ―Singleor Multi-Component Liquid‖ option, and ―Full Speciation‖ is selected for the ―Speciation‖ option, then 

the full chemical profile can be created using the ―View/Add Components‖ button. Any defined chemical, 

including those defined using the criteria in Table C-4, can be included in the mixture as a component as 

long as the percentage of total liquid weight or relative weight is known. With the chemical components 

and their relative percentages and/or weights entered, the menu can be closed, and the mixture properties 

can be calculated by clicking on the Calculate Mixture Properties button. 
Version 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

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, sliding 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, without float, gasketed

Sliding cover, with 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 1.0 Appendix C—Primer for TANKS Model Users 

Review Draft – Do not cite or quote 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

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D-2 

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Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

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D-3 

D. Emission Factors from Air Toxic Emission Factors for Combustion Sources 

Using Petroleum Based Fuels – Final Report, Volume 2 – Development of 

Emission Factors Using CARB Approach 

 Detect Ratio: Ratio of detected values to the sum of detected and nondetected values. 

 RSD: 100 times the standard deviation divided by the arithmetic average. 

 Uncertainty: 100 times the 95% confidence interval divided by the arithmetic average. 

Dioxin Acronyms 

4D 2378 2,3,7,8-Tetrachlorodibenzo-p-dioxin.

4D Other Tetrachlorodibenzo-p-dioxin other.

4D Total Tetrachlorodibenzo-p-dioxin total.

5D 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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

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 

Mean Median Maximum Minimum Ratio

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+00 2.07E+00 2.07E+00 1 0.00 0.00 0.00

Lead D3-v- 5.25E-02 5.25E-02 5.25E-02 5.25E-02 1 0.00 0.00 0.00

Manganese D3-v- 1.23E-01 1.23E-01 1.23E-01 1.23E-01 1 0.00 0.00 1.00

Mercury A3-v- 9.07E-03 9.07E-03 9.07E-03 9.07E-03 1 0.00 0.00 1.00

Nickel D3-v- 6.65E-02 6.65E-02 6.65E-02 6.65E-02 1 0.00 0.00 0.00

Phenol C3-v- 7.57E-02 7.57E-02 7.57E-02 7.57E-02 1 0.00 0.00 1.00

Selenium D3-v- 1.31E-02 1.31E-02 1.31E-02 1.31E-02 1 0.00 0.00 0.00

Xylene (Total) E3-v- 8.61E-01 8.61E-01 8.61E-01 8.61E-01 1 0.00 0.00 0.00

Zinc D3-v- 8.41E-01 8.41E-01 8.41E-01 8.41E-01 1 0.00 0.00 1.00
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

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 

Mean Median Maximum Minimum Ratio

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

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 

Mean Median Maximum Minimum Ratio

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+00 1.83E+00 1.83E+00 1 0.00 0.00 0.00

Lead D3-v- 4.65E-02 4.65E-02 4.65E-02 4.65E-02 1 0.00 0.00 0.00

Manganese D3-v- 2.07E-01 2.07E-01 2.07E-01 2.07E-01 1 0.00 0.00 1.00

Mercury A3-v- 8.53E-03 8.53E-03 8.53E-03 8.53E-03 1 0.00 0.00 1.00

Nickel D3-v- 6.01E-02 6.01E-02 6.01E-02 6.01E-02 1 0.00 0.00 0.00

Phenol C3-v- 4.64E-02 4.64E-02 4.64E-02 4.64E-02 1 0.00 0.00 1.00

Selenium D3-v- 1.16E-02 1.16E-02 1.16E-02 1.16E-02 1 0.00 0.00 0.00

Xylene (Total) E3-v- 7.62E-01 7.62E-01 7.62E-01 7.62E-01 1 0.00 0.00 0.00

Zinc D3-v- 5.35E-01 5.35E-01 5.35E-01 5.35E-01 1 0.00 0.00 1.00
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-7 

Table D-2b. Summary of Data for Emission Factor Development –

Asphalt Blowing with No Blow Cycle and a Thermal Oxidizer 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acetaldehyde C3-v- 4.07E-06 4.07E-06 4.07E-06 4.07E-06 1 0.00 0.00 1.00

Arsenic D3-v- 1.09E-05 1.09E-05 1.09E-05 1.09E-05 1 0.00 0.00 0.00

Benzene E3-v- 2.64E-04 2.64E-04 2.64E-04 2.64E-04 1 0.00 0.00 0.00

Beryllium D3-v- 2.19E-06 2.19E-06 2.19E-06 2.19E-06 1 0.00 0.00 0.00

Cadmium D3-v- 4.37E-06 4.37E-06 4.37E-06 4.37E-06 1 0.00 0.00 0.00

Chromium (Hex) C3-v- 3.09E-06 3.09E-06 3.09E-06 3.09E-06 1 0.00 0.00 0.00

Chromium (Total) C3-v- 1.34E-05 1.34E-05 1.34E-05 1.34E-05 1 0.00 0.00 0.00

Copper D3-v- 3.56E-05 3.56E-05 3.56E-05 3.56E-05 1 0.00 0.00 1.00

Ethylbenzene E3-v- 7.17E-04 7.17E-04 7.17E-04 7.17E-04 1 0.00 0.00 0.00

Formaldehyde C3-v- 1.22E-05 1.22E-05 1.22E-05 1.22E-05 1 0.00 0.00 1.00

HCl C3-v- 7.74E-07 7.74E-07 7.74E-07 7.74E-07 1 0.00 0.00 1.00

Hydrogen Sulfide A3-v- 1.73E-03 1.73E-03 1.73E-03 1.73E-03 1 0.00 0.00 0.00

Lead D3-v- 4.38E-05 4.38E-05 4.38E-05 4.38E-05 1 0.00 0.00 0.00

Manganese D3-v- 1.95E-04 1.95E-04 1.95E-04 1.95E-04 1 0.00 0.00 1.00

Mercury A3-v- 8.03E-06 8.03E-06 8.03E-06 8.03E-06 1 0.00 0.00 1.00

Nickel D3-v- 5.65E-05 5.65E-05 5.65E-05 5.65E-05 1 0.00 0.00 0.00

Phenol C3-v- 4.37E-05 4.37E-05 4.37E-05 4.37E-05 1 0.00 0.00 1.00

Selenium D3-v- 1.09E-05 1.09E-05 1.09E-05 1.09E-05 1 0.00 0.00 0.00

Xylene (Total) E3-v- 7.17E-04 7.17E-04 7.17E-04 7.17E-04 1 0.00 0.00 0.00

Zinc D3-v- 5.04E-04 5.04E-04 5.04E-04 5.04E-04 1 0.00 0.00 1.00
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-8 

Table D-3a. Summary of Data for Emission Factor Development – Boilers Firing Fuel Oil

Substance

CARB

Rating

Emission Factor (lb/Mgal)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-9 

Table D-3a. Summary of Data for Emission Factor Development – Boilers Firing Fuel Oil

(continued)

Substance

CARB

Rating

Emission Factor (lb/Mgal)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Furan: 6F 123678 C3-v0 2.73E-10 2.73E-10 2.86E-10 2.61E-10 1 4.51 5.10 0.33

Furan: 6F 123789 C3-v0 3.68E-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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-10 

Table D-3b. Summary of Data for Emission Factor Development – Boilers Firing Fuel Oil 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acenaphthene B3-v0 6.00E-09 5.71E-09 1.06E-08 2.14E-09 2 69.26 55.42 0.87

Acenaphthylene B3-v0 2.09E-09 2.16E-09 2.29E-09 1.59E-09 2 12.32 9.86 0.00

Acetaldehyde A3-v1 6.99E-06 3.33E-06 2.28E-05 1.79E-06 2 117.49 94.01 0.75

Acrolein A3-v0 1.48E-05 1.19E-05 2.28E-05 9.69E-06 1 47.31 53.53 0.00

Anthracene B3-v1 2.07E-09 1.83E-09 4.76E-09 1.29E-10 2 98.24 78.60 0.94

Arsenic B3-v0 9.76E-06 9.76E-06 1.14E-05 8.10E-06 1 17.00 19.24 0.00

Benzene A3-v0 3.15E-05 3.17E-05 3.24E-05 3.04E-05 1 3.26 3.69 0.00

Benzo(a)anthracene B3-v1 1.32E-09 1.44E-09 2.29E-09 2.03E-10 2 77.09 61.68 0.00

Benzo(a)pyrene B3-v0 1.36E-09 1.46E-09 2.29E-09 3.13E-10 2 71.84 57.48 0.00

Benzo(b)fluoranthene B3-v0 8.11E-09 6.77E-09 1.60E-08 2.14E-09 2 75.81 60.66 0.40

Benzo(e)pyrene C3-v0 5.80E-09 7.00E-09 7.60E-09 2.80E-09 1 45.15 51.09 0.00

Benzo(g,h,i)perylene B3-v0 6.72E-09 5.69E-09 1.50E-08 2.14E-09 2 79.36 63.50 0.00

Benzo(k)fluoranthene B3-v1 1.34E-09 1.55E-09 2.29E-09 2.03E-10 2 75.32 60.26 0.00

Beryllium B3-v0 4.28E-07 4.32E-07 4.78E-07 3.74E-07 1 12.22 13.83 0.00

1,3-Butadiene B3-v1 4.18E-05 4.04E-05 8.00E-05 5.74E-06 2 94.58 75.68 0.00

Cadmium B3-v0 5.82E-06 4.47E-06 8.58E-06 4.40E-06 1 41.15 46.57 0.00

Chloroform A3-v0 3.37E-05 3.40E-05 3.47E-05 3.25E-05 1 3.26 3.69 0.00

2-Chloronaphthalene C3-v0 1.54E-10 1.58E-10 1.94E-10 1.11E-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

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-11 

Table D-3b. Summary of Data for Emission Factor Development – Boilers Firing Fuel Oil

(continued)

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Furan:6F 123678 C3-v0 1.86E-12 1.86E-12 1.94E-12 1.77E-12 1 4.51 5.10 0.33

Furan:6F 123789 C3-v0 2.50E-12 1.86E-12 3.88E-12 1.77E-12 1 47.67 53.94 0.00

Furan:6F 234678 C3-v0 3.74E-12 3.88E-12 5.57E-12 1.77E-12 1 50.85 57.54 0.50

Furan:7F 1234678 C3-v0 9.79E-12 7.76E-12 1.42E-11 7.43E-12 1 38.89 44.01 1.00

Furan:7F 1234789 C3-v0 3.15E-12 1.86E-12 5.82E-12 1.77E-12 1 73.43 83.10 0.00

Furan:8F C3-v0 4.86E-11 4.85E-11 7.06E-11 2.66E-11 1 45.27 51.23 1.00

Indeno(1,2,3-cd)pyrene B3-v0 3.05E-09 2.28E-09 5.32E-09 1.97E-09 2 46.19 36.96 0.00

Lead B3-v0 1.06E-05 5.84E-06 2.26E-05 3.32E-06 1 98.91 111.92 0.00

Manganese B3-v0 3.95E-05 1.92E-05 8.29E-05 1.63E-05 1 95.34 107.89 1.00

Mercury B3-v0 7.02E-08 6.15E-08 1.00E-07 4.89E-08 1 38.06 43.07 0.00

2-Methylnaphthalene C3-v0 7.40E-08 7.25E-08 8.32E-08 6.63E-08 1 11.52 13.04 1.00

Naphthalene B3-v0 4.04E-07 4.11E-07 5.52E-07 2.73E-07 2 28.11 22.49 1.00

Nickel B3-v0 2.27E-03 2.08E-03 2.76E-03 1.97E-03 1 18.95 21.44 1.00

Perylene C3-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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-12 

Table D-4a. Summary of Data for Emission Factor Development –

Boilers Firing Refinery Fuel Gas 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty,

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 2.56E-06 2.59E-06 2.59E-06 2.50E-06 1 2.04 2.31 0.00 

Lead D3-v0 2.42E-03 2.42E-03 2.49E-03 2.36E-03 1 3.87 5.36 1.00

Manganese D3-v0 2.39E-03 2.39E-03 3.14E-03 1.64E-03 1 44.52 61.70 1.00

Mercury D3-v0 3.23E-04 3.18E-04 3.82E-04 2.70E-04 1 17.33 19.60 0.00 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-13 

Table D-4b. Summary of Data for Emission Factor Development –

Boilers Firing Refinery Fuel Gas 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 5.65E-09 6.11E-09 6.99E-09 3.84E-09 1 28.79 32.57 1.00 

Benzo(g,h,i)perylene A3-v0 3.22E-09 3.28E-09 4.36E-09 2.02E-09 1 36.33 41.11 0.78 

Benzo(k)fluoranthene A3-v0 2.13E-09 2.19E-09 2.19E-09 2.02E-09 1 4.43 5.01 0.00 

Beryllium D3-v0 1.31E-07 1.31E-07 1.32E-07 1.29E-07 1 1.35 1.87 1.00 

Cadmium D3-v0 2.00E-06 1.70E-06 2.64E-06 1.67E-06 1 27.60 31.23 1.00 

Chromium (Hex) C3-v0 6.32E-06 6.29E-06 8.78E-06 3.89E-06 1 38.70 43.79 0.00 

Chromium (Total) C3-v1 1.04E-05 4.51E-06 2.49E-05 1.80E-06 1 121.39 137.36 1.00 

Chrysene A3-v0 2.86E-09 2.19E-09 4.36E-09 2.02E-09 1 45.70 51.71 0.50 

Copper D3-v0 5.32E-06 5.32E-06 6.51E-06 4.13E-06 1 31.59 43.78 1.00 

Dibenz(a,h)anthracene A3-v0 2.13E-09 2.19E-09 2.19E-09 2.02E-09 1 4.43 5.01 0.00 

Fluoranthene A3-v0 3.56E-08 2.62E-08 6.11E-08 1.94E-08 1 62.95 71.23 1.00 

Fluorene A3-v0 8.19E-09 4.65E-09 1.53E-08 4.59E-09 1 75.53 85.46 1.00 

Formaldehyde C1-v1 1.32E-05 1.16E-05 3.62E-05 2.81E-06 5 66.84 33.82 1.00 

Hydrogen Sulfide A1-v1 2.21E-04 1.69E-04 5.93E-04 5.01E-05 5 92.80 45.47 0.00 

Indeno(1,2,3-cd)pyrene A3-v0 2.13E-09 2.19E-09 2.19E-09 2.02E-09 1 4.43 5.01 0.00 

Lead D3-v0 2.05E-06 2.05E-06 2.10E-06 1.99E-06 1 3.87 5.36 1.00 

Manganese D3-v0 2.02E-06 2.02E-06 2.65E-06 1.38E-06 1 44.52 61.70 1.00 

Mercury D3-v0 2.72E-07 2.69E-07 3.22E-07 2.24E-07 1 18.19 20.58 0.00 

Naphthalene A3-v0 1.72E-07 1.63E-07 2.03E-07 1.49E-07 1 16.13 18.25 1.00 

Nickel D3-v0 4.72E-06 4.72E-06 5.94E-06 3.51E-06 1 36.33 50.35 1.00 

Phenanthrene A3-v0 4.71E-08 3.63E-08 7.43E-08 3.06E-08 1 50.50 57.15 1.00 

Phenol C2-v0 1.83E-06 7.04E-07 4.91E-06 5.45E-07 4 99.84 56.49 0.85 

Pyrene A3-v0 5.00E-08 4.36E-08 6.99E-08 3.63E-08 1 35.35 40.00 1.00 

Selenium D3-v0 1.73E-06 1.99E-06 2.39E-06 8.11E-07 1 47.44 53.68 0.16 

Toluene E2-v2 7.23E-04 7.25E-05 4.37E-03 3.59E-05 3 193.00 126.09 0.97 

Zinc D3-v2 2.83E-03 3.22E-04 8.10E-03 7.83E-05 1 161.02 182.20 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-14 

Table D-5a. Summary of Data for Emission Factor Development – Boilers Firing Refinery 

Fuel Gas Controlled with Selective Catalytic Reduction (NOx) 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 2.56E-06 2.59E-06 2.59E-06 2.50E-06 1 2.04 2.31 0.00

Lead D3-v0 2.42E-03 2.42E-03 2.49E-03 2.36E-03 1 3.87 5.36 1.00

Manganese D3-v0 2.39E-03 2.39E-03 3.14E-03 1.64E-03 1 44.52 61.70 1.00

Mercury D3-v0 3.23E-04 3.18E-04 3.82E-04 2.70E-04 1 17.33 19.60 0.00

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-15 

Table D-5b. Summary of Data for Emission Factor Development – Boilers Firing Refinery 

Fuel Gas Controlled with Selective Catalytic Reduction (NOx) 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 5.65E-09 6.11E-09 6.99E-09 3.84E-09 1 28.79 32.57 1.00 

Benzo(g,h,i)perylene A3-v0 3.22E-09 3.28E-09 4.36E-09 2.02E-09 1 36.33 41.11 0.78 

Benzo(k)fluoranthene A3-v0 2.13E-09 2.19E-09 2.19E-09 2.02E-09 1 4.43 5.01 0.00 

Beryllium D3-v0 1.31E-07 1.31E-07 1.32E-07 1.29E-07 1 1.35 1.87 1.00 

Cadmium D3-v0 2.00E-06 1.70E-06 2.64E-06 1.67E-06 1 27.60 31.23 1.00 

Chromium (Hex) C3-v0 6.32E-06 6.29E-06 8.78E-06 3.89E-06 1 38.70 43.79 0.00 

Chromium (Total) C3-v1 1.04E-05 4.51E-06 2.49E-05 1.80E-06 1 121.39 137.36 1.00 

Chrysene A3-v0 2.86E-09 2.19E-09 4.36E-09 2.02E-09 1 45.70 51.71 0.50 

Copper D3-v0 5.32E-06 5.32E-06 6.51E-06 4.13E-06 1 31.59 43.78 1.00 

Dibenz(a,h)anthracene A3-v0 2.13E-09 2.19E-09 2.19E-09 2.02E-09 1 4.43 5.01 0.00 

Fluoranthene A3-v0 3.56E-08 2.62E-08 6.11E-08 1.94E-08 1 62.95 71.23 1.00 

Fluorene A3-v0 8.19E-09 4.65E-09 1.53E-08 4.59E-09 1 75.53 85.46 1.00 

Formaldehyde C1-v1 1.32E-05 1.16E-05 3.62E-05 2.81E-06 5 66.84 33.82 1.00 

Hydrogen Sulfide A1-v1 2.21E-04 1.69E-04 5.93E-04 5.01E-05 5 92.80 45.47 0.00 

Indeno(1,2,3-cd)pyrene A3-v0 2.13E-09 2.19E-09 2.19E-09 2.02E-09 1 4.43 5.01 0.00 

Lead D3-v0 2.05E-06 2.05E-06 2.10E-06 1.99E-06 1 3.87 5.36 1.00 

Manganese D3-v0 2.02E-06 2.02E-06 2.65E-06 1.38E-06 1 44.52 61.70 1.00 

Mercury D3-v0 2.72E-07 2.69E-07 3.22E-07 2.24E-07 1 18.19 20.58 0.00 

Naphthalene A3-v0 1.72E-07 1.63E-07 2.03E-07 1.49E-07 1 16.13 18.25 1.00 

Nickel D3-v0 4.72E-06 4.72E-06 5.94E-06 3.51E-06 1 36.33 50.35 1.00 

Phenanthrene A3-v0 4.71E-08 3.63E-08 7.43E-08 3.06E-08 1 50.50 57.15 1.00 

Phenol C2-v0 1.83E-06 7.04E-07 4.91E-06 5.45E-07 4 99.84 56.49 0.85 

Pyrene A3-v0 5.00E-08 4.36E-08 6.99E-08 3.63E-08 1 35.35 40.00 1.00 

Selenium D3-v0 1.73E-06 1.99E-06 2.39E-06 8.11E-07 1 47.44 53.68 0.16 

Toluene E2-v2 7.23E-04 7.25E-05 4.37E-03 3.59E-05 3 193.00 126.09 0.97 

Zinc D3-v2 2.83E-03 3.22E-04 8.10E-03 7.83E-05 1 161.02 182.20 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-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 

Mean Median Maximum Minimum Ratio

Acenaphthene A3-v0 1.46E-08 1.38E-08 1.64E-08 1.37E-08 1 10.68 12.08 1.00 

Acenaphthylene A3-v0 1.83E-08 1.69E-08 2.81E-08 9.87E-09 1 50.39 57.02 1.00 

Acetaldehyde A3-v0 1.02E-03 1.16E-03 1.22E-03 6.77E-04 1 29.23 33.07 1.00 

Acrolein A3-v0 3.36E-04 3.41E-04 3.60E-04 3.08E-04 1 7.79 8.82 0.00 

Anthracene A3-v0 1.82E-08 1.84E-08 1.97E-08 1.64E-08 1 9.02 10.20 1.00 

Antimony C3-v0 4.61E-05 4.64E-05 4.79E-05 4.41E-05 1 4.04 4.57 0.34 

Arsenic C3-v0 4.66E-06 4.64E-06 4.92E-06 4.41E-06 1 5.42 6.13 0.00 

Barium C3-v0 1.95E-05 1.99E-05 2.46E-05 1.39E-05 1 27.51 31.13 1.00 

Benzene C3-v0 3.24E-04 4.06E-04 4.50E-04 1.15E-04 1 56.20 63.60 1.00 

Benzo(a)anthracene A3-v0 8.71E-09 8.25E-09 1.02E-08 7.67E-09 1 15.15 17.15 0.39 

Benzo(a)pyrene A3-v0 8.05E-09 8.22E-09 8.25E-09 7.67E-09 1 4.04 4.57 0.00 

Benzo(b)fluoranthene A3-v0 8.05E-09 8.22E-09 8.25E-09 7.67E-09 1 4.04 4.57 0.00 

Benzo(g,h,i)perylene A3-v0 8.05E-09 8.22E-09 8.25E-09 7.67E-09 1 4.04 4.57 0.00 

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-07 7.17E-07 5.45E-07 1 13.63 15.42 1.00 

Chromium (Total) C3-v0 2.05E-05 2.04E-05 2.09E-05 2.01E-05 1 1.82 2.06 1.00 

Chrysene A3-v0 1.28E-08 1.18E-08 1.84E-08 8.25E-09 1 40.02 45.28 0.79 

Copper C3-v0 9.32E-06 9.27E-06 9.84E-06 8.84E-06 1 5.34 6.04 0.00 

Dibenz(a,h)anthracene A3-v0 8.05E-09 8.22E-09 8.25E-09 7.67E-09 1 4.04 4.57 0.00 

Dioxin:4D 2378 A3-v0 1.14E-11 1.18E-11 1.32E-11 9.05E-12 1 18.56 21.00 0.00 

Dioxin:4D Other A3-v0 1.44E-10 1.01E-10 2.99E-10 3.17E-11 1 96.53 109.23 1.00 

Dioxin:5D 12378 A3-v0 9.56E-12 9.20E-12 1.35E-11 6.01E-12 1 39.05 44.19 0.00 

Dioxin:5D Other A3-v0 8.45E-11 8.83E-11 1.02E-10 6.34E-11 1 23.10 26.14 0.40 

Dioxin:6D 123478 A3-v0 9.93E-12 9.24E-12 1.57E-11 4.83E-12 1 55.10 62.35 0.31 

Dioxin:6D 123678 A3-v0 1.38E-11 1.27E-11 2.04E-11 8.30E-12 1 44.48 50.33 0.69 

Dioxin:6D 123789 A3-v0 1.29E-11 1.45E-11 1.50E-11 9.20E-12 1 24.83 28.10 0.39 

Dioxin:6D Other A3-v0 6.36E-11 6.71E-11 8.96E-11 3.39E-11 1 44.09 49.89 0.65 

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-10 1.90E-10 9.72E-11 1 38.24 43.27 1.00 

Dioxin:8D A3-v0 1.77E-09 1.79E-09 2.76E-09 7.60E-10 1 56.40 63.82 1.00 

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-11 1.63E-11 1.18E-11 1 19.13 21.65 0.70 

Furan:4F Other A3-v0 1.39E-10 1.10E-10 2.15E-10 9.21E-11 1 47.70 53.98 1.00 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-17 

Table D-6a. Summary of Data for Emission Factor Development –

Coke Calcining Controlled by Spray Dryer and Fabric Filter (continued)

Substance

CARB

Rating

Emission Factor (lb/ton coke)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Furan:5F 12378 A3-v0 1.36E-11 1.43E-11 1.50E-11 1.16E-11 1 13.01 14.72 0.65 

Furan:5F 23478 A3-v0 1.25E-11 1.38E-11 1.46E-11 9.10E-12 1 23.87 27.01 0.63 

Furan:5F Other A3-v0 1.20E-10 9.47E-11 1.79E-10 8.70E-11 1 42.57 48.17 0.74 

Furan:6F 123478 A3-v0 2.44E-11 2.49E-11 2.71E-11 2.12E-11 1 12.27 13.89 1.00 

Furan:6F 123678 A3-v0 2.21E-11 2.19E-11 3.13E-11 1.31E-11 1 41.02 46.42 1.00 

Furan:6F 123789 A3-v0 9.19E-12 8.96E-12 1.20E-11 6.64E-12 1 29.03 32.85 0.67 

Furan:6F 234678 A3-v0 2.01E-11 2.04E-11 2.04E-11 1.96E-11 1 2.55 2.88 1.00 

Furan:6F Other A3-v0 1.52E-10 1.31E-10 2.36E-10 9.04E-11 1 49.18 55.66 1.00 

Furan:7F 1234678 A3-v0 1.50E-10 1.42E-10 1.76E-10 1.32E-10 1 15.51 17.55 1.00 

Furan:7F 1234789 A3-v0 2.56E-11 2.56E-11 2.99E-11 2.12E-11 1 17.09 19.33 0.72 

Furan:7F Other A3-v0 5.16E-11 5.16E-11 5.16E-11 5.16E-11 1 0.00 0.00 0.50 

Furan:8F A3-v1 1.46E-10 1.36E-10 2.86E-10 1.61E-11 1 92.60 104.78 1.00 

Indeno(1,2,3-cd)pyrene A3-v0 8.05E-09 8.22E-09 8.25E-09 7.67E-09 1 4.04 4.57 0.00 

Lead C3-v0 6.20E-05 4.92E-05 9.27E-05 4.41E-05 1 43.08 48.75 0.50 

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-05 3.79E-05 2.04E-05 1 29.89 33.82 0.22 

Xylene (o) C3-v0 4.49E-05 4.34E-05 4.79E-05 4.34E-05 1 5.72 6.47 0.00 

Zinc C3-v0 1.17E-04 1.04E-04 1.63E-04 8.37E-05 1 35.15 39.78 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-18 

Table D-6b. Summary of Data for Emission Factor Development –

Coke Calcining Controlled by Spray Dryer and Fabric Filter 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-19 

Table D-6b. Summary of Data for Emission Factor Development –

Coke Calcining Controlled by Spray Dryer and Fabric Filter (continued)

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Furan:4F Other A3-v0 4.35E-10 4.51E-10 5.97E-10 2.56E-10 1 39.34 44.51 1.00 

Furan:5F 12378 A3-v0 4.42E-11 4.16E-11 5.87E-11 3.23E-11 1 30.36 34.35 0.65 

Furan:5F 23478 A3-v0 4.09E-11 4.07E-11 5.66E-11 2.53E-11 1 38.39 43.44 0.63 

Furan:5F Other A3-v0 3.76E-10 3.89E-10 4.98E-10 2.42E-10 1 34.21 38.71 0.74 

Furan:6F 123478 A3-v0 7.88E-11 7.53E-11 1.02E-10 5.88E-11 1 27.77 31.43 1.00 

Furan:6F 123678 A3-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-v0 2.41E-08 2.42E-08 2.72E-08 2.08E-08 1 13.35 15.10 0.00 

Lead C3-v0 1.91E-04 1.56E-04 2.74E-04 1.42E-04 1 37.94 42.93 0.50 

Manganese C3-v0 1.44E-04 1.42E-04 2.42E-04 4.81E-05 1 67.22 76.06 0.88 

Mercury C3-v1 1.48E-04 4.81E-05 3.60E-04 3.43E-05 1 124.89 141.33 1.00 

Naphthalene A3-v0 7.29E-06 6.67E-06 1.04E-05 4.83E-06 1 38.67 43.75 1.00 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-20 

Table D-7a. Summary of Data for Emission Factor Development – Heaters Firing Natural Gas 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.14E-06 1.15E-06 1.18E-06 1.08E-06 1 4.76 5.39 0.00 

Benzo(g,h,i)perylene A3-v0 1.25E-06 1.18E-06 1.42E-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-v0 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-v0 1.14E-06 1.15E-06 1.18E-06 1.08E-06 1 4.76 5.39 0.00 

Naphthalene A3-v0 2.37E-04 2.37E-04 2.80E-04 1.94E-04 1 18.28 20.69 1.00 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-21 

Table D-7b. Summary of Data for Emission Factor Development – Heaters Firing Natural Gas 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acenaphthene A3-v0 1.36E-09 1.36E-09 1.58E-09 1.13E-09 1 16.72 18.92 0.72 

Acenaphthylene A3-v1 1.18E-08 2.77E-09 3.16E-08 1.13E-09 1 144.82 163.88 0.97 

Acetaldehyde A3-v0 4.50E-06 4.50E-06 4.71E-06 4.30E-06 1 4.47 5.06 0.32 

Acrolein A3-v0 4.40E-06 4.46E-06 4.53E-06 4.22E-06 1 3.66 4.14 0.00 

Anthracene A3-v0 1.57E-09 1.79E-09 1.80E-09 1.13E-09 1 24.62 27.86 0.76 

Benzene A3-v0 2.28E-06 1.61E-06 3.62E-06 1.61E-06 1 50.72 57.40 0.53 

Benzo(a)anthracene A3-v0 1.38E-09 1.16E-09 1.85E-09 1.13E-09 1 29.86 33.79 0.45 

Benzo(a)pyrene A3-v0 1.11E-09 1.13E-09 1.16E-09 1.05E-09 1 4.76 5.39 0.00 

Benzo(b)fluoranthene A3-v0 1.11E-09 1.13E-09 1.16E-09 1.05E-09 1 4.76 5.39 0.00 

Benzo(g,h,i)perylene A3-v0 1.22E-09 1.16E-09 1.39E-09 1.13E-09 1 11.81 13.36 0.38 

Benzo(k)fluoranthene A3-v0 1.11E-09 1.13E-09 1.16E-09 1.05E-09 1 4.76 5.39 0.00 

Chrysene A3-v0 1.36E-09 1.16E-09 1.79E-09 1.13E-09 1 27.63 31.27 0.44 

Dibenz(a,h)anthracene A3-v0 1.11E-09 1.13E-09 1.16E-09 1.05E-09 1 4.76 5.39 0.00 

Ethylbenzene A3-v0 2.20E-06 2.20E-06 2.20E-06 2.20E-06 1 0.00 0.00 0.00 

Fluoranthene A3-v0 1.16E-08 1.04E-08 1.75E-08 6.98E-09 1 46.07 52.14 1.00

Fluorene A3-v0 4.49E-09 4.39E-09 5.69E-09 3.38E-09 1 25.79 29.19 1.00 

Formaldehyde A3-v0 4.64E-06 4.50E-06 5.19E-06 4.22E-06 1 10.76 12.18 0.37 

Indeno(1,2,3-cd)pyrene A3-v0 1.11E-09 1.13E-09 1.16E-09 1.05E-09 1 4.76 5.39 0.00 

Naphthalene A3-v0 2.31E-07 2.31E-07 2.74E-07 1.89E-07 1 18.28 20.69 1.00 

Phenanthrene A3-v0 3.29E-08 3.24E-08 4.63E-08 2.00E-08 1 39.96 45.22 1.00 

Propylene A3-v0 4.53E-04 4.47E-04 5.98E-04 3.13E-04 1 31.59 35.74 1.00 

Pyrene A3-v0 5.47E-09 2.77E-09 1.14E-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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-22 

Table D-8a. Summary of Data for Emission Factor Development –

Heaters Firing Natural Gas and Refinery Fuel Gas 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty,

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 2.63E-06 1.91E-06 4.19E-06 1.79E-06 1 51.36 58.12 1.00 

Benzo(g,h,i)perylene A3-v0 4.13E-07 1.59E-07 9.55E-07 1.25E-07 1 113.74 128.71 0.77 

Benzo(k)fluoranthene A3-v0 1.46E-06 8.35E-07 3.18E-06 3.70E-07 1 103.06 116.62 0.92 

Chrysene A3-v0 7.91E-07 6.38E-07 1.24E-06 4.91E-07 1 50.32 56.94 0.52 

Dibenz(a,h)anthracene A3-v0 1.38E-07 1.07E-07 2.08E-07 1.01E-07 1 43.36 49.06 0.00 

Fluoranthene A3-v0 1.80E-05 1.03E-05 3.82E-05 5.49E-06 1 98.02 110.92 1.00 

Fluorene A3-v1 6.48E-04 1.50E-04 1.69E-03 1.01E-04 1 139.64 158.01 1.00 

Formaldehyde C3-v0 4.33E-02 2.38E-02 8.89E-02 1.73E-02 1 91.33 103.35 1.00 

Indeno(1,2,3-

cd)pyrene A3-v0 4.56E-07 4.04E-07 6.67E-07 2.96E-07 1 41.87 47.38 0.49 

Naphthalene A3-v1 2.31E-03 4.04E-04 6.18E-03 3.45E-04 1 145.12 164.21 1.00 

Phenanthrene A3-v0 2.06E-04 1.06E-04 4.30E-04 8.36E-05 1 93.74 106.07 1.00 

Phenol A3-v0 1.72E-03 1.82E-03 2.08E-03 1.26E-03 1 24.34 27.54 1.00 

Propylene A3-v0 1.20E-02 1.13E-02 1.38E-02 1.10E-02 1 13.02 14.73 0.00 

Pyrene A3-v0 1.25E-05 7.14E-06 2.62E-05 4.04E-06 1 96.40 109.08 1.00 

Toluene A3-v0 2.63E-02 2.46E-02 3.03E-02 2.41E-02 1 13.02 14.73 0.00 

Xylene (Total) A3-v0 3.03E-02 2.84E-02 3.49E-02 2.77E-02 1 13.02 14.73 0.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-23 

Table D-8b. Summary of Data for Emission Factor Development –

Heaters Firing Natural Gas and Refinery Fuel Gas 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty,

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.44E-09 1.03E-09 2.38E-09 9.21E-10 1 56.34 63.75 1.00 

Benzo(g,h,i)perylene A3-v0 2.22E-10 8.16E-11 5.13E-10 7.08E-11 1 113.71 128.67 0.77 

Benzo(k)fluoranthene A3-v0 7.64E-10 4.49E-10 1.63E-09 2.10E-10 1 99.78 112.91 0.92 

Chrysene A3-v0 4.27E-10 3.62E-10 6.67E-10 2.52E-10 1 50.33 56.95 0.52 

Dibenz(a,h)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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-24 

Table D-9a. Summary of Data for Emission Factor Development – Heaters Firing Fuel Oil 

Substance

CARB

Rating

Emission Factor (lb/Mgal)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 7.95E-07 6.37E-07 1.15E-06 5.98E-07 1 38.74 43.84 1.00 

Benzo(e)pyrene C3-v0 5.54E-07 5.30E-07 7.73E-07 3.60E-07 1 37.44 42.36 1.00 

Benzo(g,h,i)perylene C3-v1 2.12E-06 5.50E-07 5.57E-06 2.55E-07 1 140.55 159.04 1.00 

Benzo(k)fluoranthene C3-v0 3.36E-08 2.08E-08 6.81E-08 1.18E-08 1 90.02 101.86 1.00 

Beryllium D3-v0 7.78E-05 7.64E-05 8.66E-05 7.04E-05 1 10.51 11.89 0.00 

1,3-Butadiene A3-v0 1.95E-02 1.96E-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 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-25 

Table D-9a. Summary of Data for Emission Factor Development – Heaters Firing Fuel Oil

(continued)

Substance

CARB

Rating

Emission Factor (lb/Mgal)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Furan:6F 123478 C3-v2 1.92E-08 5.94E-10 5.68E-08 1.49E-10 1 169.85 192.20 0.01 

Furan:6F 123678 C3-v2 6.12E-09 2.97E-10 1.79E-08 1.49E-10 1 166.91 188.87 0.02 

Furan:6F 123789 C3-v0 4.96E-10 5.94E-10 5.97E-10 2.97E-10 1 34.70 39.26 0.00 

Furan:6F 234678 C3-v1 8.76E-09 8.91E-10 2.48E-08 5.95E-10 1 158.52 179.38 0.03 

Furan:7F 1234678 C3-v1 1.95E-08 1.19E-09 5.68E-08 5.95E-10 1 165.30 187.05 1.00 

Furan:7F 1234789 C3-v0 1.19E-09 5.94E-10 2.69E-09 2.97E-10 1 109.22 123.59 0.00 

Furan:8F C3-v1 1.04E-08 4.75E-09 2.54E-08 1.19E-09 1 125.10 141.57 1.00 

Indeno(1,2,3-cd)pyrene C3-v1 1.81E-06 1.55E-07 5.12E-06 1.48E-07 1 158.71 179.59 1.00 

Lead D3-v0 2.96E-04 1.79E-04 5.48E-04 1.62E-04 1 73.61 83.30 0.62 

Manganese D3-v0 1.89E-03 1.79E-03 2.22E-03 1.67E-03 1 15.12 17.11 0.39 

Mercury D3-v0 1.72E-05 1.29E-05 2.83E-05 1.04E-05 1 56.41 63.84 0.00 

2-Methylnaphthalene C3-v1 3.60E-05 1.06E-05 9.29E-05 4.54E-06 1 137.05 155.09 1.00 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-26 

Table D-9b. Summary of Data for Emission Factor Development – Heaters Firing Fuel Oil 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 5.55E-09 4.44E-09 8.02E-09 4.17E-09 1 38.74 43.84 1.00 

Benzo(e)pyrene C3-v0 3.87E-09 3.70E-09 5.39E-09 2.51E-09 1 37.44 42.36 1.00 

Benzo(g,h,i)perylene C3-v1 1.48E-08 3.84E-09 3.88E-08 1.78E-09 1 140.55 159.04 1.00 

Benzo(k)fluoranthene C3-v0 2.35E-10 1.45E-10 4.76E-10 8.27E-11 1 90.02 101.86 1.00 

Beryllium D3-v0 5.43E-07 5.33E-07 6.04E-07 4.92E-07 1 10.51 11.89 0.00 

1,3-Butadiene A3-v0 1.36E-04 1.37E-04 1.40E-04 1.32E-04 1 3.14 3.55 0.00 

Cadmium D3-v1 5.73E-06 8.28E-06 8.60E-06 2.99E-07 1 82.13 92.94 1.00 

Chloroform A3-v0 6.02E-05 6.03E-05 6.20E-05 5.83E-05 1 3.06 3.46 0.00 

2-Chloronaphthalene C3-v2 8.16E-08 3.72E-10 2.44E-07 2.49E-10 1 172.55 195.25 1.00 

Chromium (Hex) A3-v0 2.00E-06 2.14E-06 2.18E-06 1.67E-06 1 14.20 16.07 0.00 

Chromium (Total) A3-v0 1.77E-05 1.85E-05 1.91E-05 1.55E-05 1 11.14 12.60 1.00 

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 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-27 

Table D-9b. Summary of Data for Emission Factor Development – Heaters Firing Fuel Oil 

(continued) 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Furan:6F 123678 C3-v2 4.27E-11 2.07E-12 1.25E-10 1.04E-12 1 166.91 188.87 0.02 

Furan:6F 123789 C3-v0 3.46E-12 4.15E-12 4.17E-12 2.08E-12 1 34.70 39.26 0.00 

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-v1 1.26E-08 1.08E-09 3.58E-08 1.03E-09 1 158.71 179.59 1.00 

Lead D3-v0 2.07E-06 1.25E-06 3.83E-06 1.13E-06 1 73.61 83.30 0.62 

Manganese D3-v0 1.32E-05 1.25E-05 1.55E-05 1.17E-05 1 15.12 17.11 0.39 

Mercury D3-v0 1.20E-07 8.99E-08 1.98E-07 7.28E-08 1 56.41 63.84 0.00 

2-Methylnaphthalene C3-v1 2.51E-07 7.40E-08 6.49E-07 3.17E-08 1 137.05 155.09 1.00 

Naphthalene C3-v0 5.91E-06 7.28E-06 7.73E-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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-28 

Table D-10a. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Non-Catalytic Reduction (NOx) 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.17E-06 1.04E-06 1.41E-06 9.83E-07 4 16.09 9.51 0.00 

Benzo(k)fluoranthene A1-v2 2.72E-05 2.66E-06 3.40E-04 9.83E-07 9 309.39 118.92 0.96 

Beryllium C3-v0 2.88E-04 2.89E-04 2.95E-04 2.81E-04 1 2.45 2.78 0.00 

Cadmium C3-v0 1.11E-03 1.08E-03 1.33E-03 9.15E-04 1 18.76 21.23 1.00 

Chromium (Hex) C3-v0 2.43E-03 2.48E-03 2.51E-03 2.30E-03 1 4.62 5.23 0.00 

Chromium (Total) C3-v0 1.20E-03 7.38E-04 2.16E-03 7.03E-04 1 69.39 78.52 0.60 

Chrysene A2-v0 1.66E-06 1.29E-06 5.37E-06 9.83E-07 4 76.71 45.33 0.63 

Copper C3-v0 4.73E-03 2.16E-03 1.05E-02 1.48E-03 1 106.76 120.81 1.00 

Dibenz(a,h)anthracene A1-v2 1.06E-05 1.95E-06 1.31E-04 6.78E-07 9 262.22 100.79 0.00 

Ethylbenzene A2-v1 3.04E-02 1.74E-02 9.50E-02 2.53E-03 4 100.75 57.01 0.51 

Fluoranthene A2-v0 3.06E-06 3.03E-06 5.66E-06 1.72E-06 4 37.95 22.43 1.00 

Fluorene A2-v0 1.06E-05 8.55E-06 2.64E-05 3.33E-06 4 67.66 39.98 1.00 

Formaldehyde B1-v3 1.51E-01 3.03E-02 1.76E+00 7.92E-04 7 254.14 108.70 1.00 

Hydrogen Sulfide A1-v1 4.05E-01 3.27E-01 1.20E+00 1.82E-02 7 84.49 36.13 0.00 

Indeno(1,2,3-cd)pyrene A1-v3 1.15E-04 2.29E-06 1.55E-03 9.83E-07 9 342.12 131.50 0.99 

Lead C3-v0 5.49E-03 4.43E-03 8.43E-03 3.61E-03 1 47.03 53.22 1.00 

Manganese C3-v0 7.65E-03 7.03E-03 1.37E-02 2.21E-03 1 75.45 85.38 1.00 

Mercury C3-v0 2.02E-04 1.97E-04 2.17E-04 1.92E-04 1 6.49 7.34 0.36 

Naphthalene A2-v0 3.02E-04 2.43E-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 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-29 

Table D-10a. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Non-Catalytic Reduction (NOx) (continued) 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Selenium C3-v0 2.20E-05 2.28E-05 2.85E-05 1.48E-05 1 31.23 35.34 0.78 

Silver C3-v1 1.81E-03 1.48E-03 3.61E-03 3.53E-04 1 91.23 103.24 0.94 

Thallium C3-v0 6.49E-03 6.49E-03 6.64E-03 6.33E-03 1 2.45 2.78 0.00 

Toluene D1-v2 1.37E-01 7.81E-02 1.21E+00 3.71E-03 11 154.31 52.65 0.55 

Xylene (Total) A2-v1 3.74E-02 3.37E-02 9.90E-02 4.27E-03 4 95.86 54.24 0.60 

Zinc C3-v0 2.34E-02 2.89E-02 3.18E-02 9.52E-03 1 51.72 58.53 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-30 

Table D-10b. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Non-Catalytic Reduction (NOx) 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.17E-09 1.10E-09 1.40E-09 1.02E-09 4 11.55 6.82 0.00 

Benzo(k)fluoranthene A1-v2 2.41E-08 2.18E-09 2.96E-07 1.02E-09 9 310.01 119.16 0.96 

Beryllium C3-v0 2.57E-07 2.57E-07 2.63E-07 2.50E-07 1 2.45 2.78 0.00 

Cadmium C3-v0 9.88E-07 9.65E-07 1.18E-06 8.15E-07 1 18.76 21.23 1.00 

Chromium (Hex) C3-v0 2.17E-06 2.21E-06 2.24E-06 2.05E-06 1 4.62 5.23 0.00 

Chromium (Total) C3-v0 1.07E-06 6.57E-07 1.93E-06 6.26E-07 1 69.39 78.52 0.60 

Chrysene A2-v0 1.63E-09 1.23E-09 4.79E-09 1.02E-09 4 66.84 39.50 0.63 

Copper C3-v0 4.21E-06 1.93E-06 9.39E-06 1.31E-06 1 106.76 120.81 1.00 

Dibenz(a,h)anthracene A1-v2 1.02E-08 1.60E-09 1.37E-07 5.93E-10 9 279.09 107.28 0.00 

Ethylbenzene A2-v1 3.02E-05 1.79E-05 1.03E-04 2.72E-06 4 104.65 59.21 0.51 

Fluoranthene A2-v0 3.06E-09 3.14E-09 5.04E-09 1.85E-09 4 33.80 19.97 1.00 

Fluorene A2-v0 1.08E-08 8.77E-09 2.74E-08 2.96E-09 4 70.62 41.74 1.00 

Formaldehyde B1-v3 1.11E-04 1.90E-05 1.34E-03 7.67E-07 7 262.94 112.46 1.00 

Hydrogen Sulfide A1-v1 2.92E-04 2.46E-04 8.04E-04 1.76E-05 7 75.53 32.30 0.00 

Indeno(1,2,3-cd)pyrene A1-v3 1.03E-07 1.75E-09 1.42E-06 1.02E-09 9 343.01 131.85 0.99 

Lead C3-v0 4.89E-06 3.94E-06 7.51E-06 3.21E-06 1 47.03 53.22 1.00 

Manganese C3-v0 6.81E-06 6.26E-06 1.22E-05 1.97E-06 1 75.45 85.38 1.00 

Mercury C3-v0 1.80E-07 1.75E-07 1.93E-07 1.71E-07 1 6.49 7.34 0.36 

Naphthalene A2-v0 3.13E-07 2.61E-07 7.58E-07 1.19E-07 4 66.90 39.53 1.00 

Nickel C3-v1 9.42E-06 1.31E-06 2.57E-05 1.29E-06 1 149.30 168.95 0.95 

Phenanthrene A2-v0 1.46E-08 1.50E-08 2.25E-08 6.91E-09 4 32.60 19.27 1.00 

Phenol C1-v1 5.63E-06 3.14E-06 2.54E-05 2.84E-07 7 114.62 49.02 0.97 

Phosphorus C3-v0 6.42E-07 6.43E-07 6.57E-07 6.26E-07 1 2.45 2.78 0.00 

Propylene A2-v0 2.17E-06 2.22E-06 2.98E-06 1.08E-06 3 23.69 15.47 0.05 

Pyrene A2-v0 2.84E-09 2.72E-09 4.53E-09 1.87E-09 4 28.87 17.06 1.00 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-31 

Table D-10b. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Non-Catalytic Reduction (NOx) (continued) 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Selenium C3-v0 1.96E-08 2.03E-08 2.54E-08 1.32E-08 1 31.23 35.34 0.78 

Silver C3-v1 1.61E-06 1.31E-06 3.21E-06 3.14E-07 1 91.23 103.24 0.94 

Thallium C3-v0 5.78E-06 5.78E-06 5.92E-06 5.63E-06 1 2.45 2.78 0.00 

Toluene D1-v2 1.07E-04 7.00E-05 9.19E-04 4.04E-06 11 148.57 50.69 0.55 

Xylene (Total) A2-v1 3.73E-05 3.16E-05 1.08E-04 4.66E-06 4 99.32 56.19 0.60 

Zinc C3-v0 2.08E-05 2.58E-05 2.83E-05 8.48E-06 1 51.72 58.53 1.00
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-32 

Table D-11a. Summary of Data for Emission Factor Development –

Heaters Firing Refinery Fuel Gas 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.17E-06 1.04E-06 1.41E-06 9.83E-07 4 16.09 9.51 0.00 

Benzo(k)fluoranthene A1-v2 2.72E-05 2.66E-06 3.40E-04 9.83E-07 9 309.39 118.92 0.96 

Beryllium C3-v0 2.88E-04 2.89E-04 2.95E-04 2.81E-04 1 2.45 2.78 0.00 

Cadmium C3-v0 1.11E-03 1.08E-03 1.33E-03 9.15E-04 1 18.76 21.23 1.00 

Chromium (Hex) C3-v0 2.43E-03 2.48E-03 2.51E-03 2.30E-03 1 4.62 5.23 0.00 

Chromium (Total) C3-v0 1.20E-03 7.38E-04 2.16E-03 7.03E-04 1 69.39 78.52 0.60 

Chrysene A2-v0 1.66E-06 1.29E-06 5.37E-06 9.83E-07 4 76.71 45.33 0.63 

Copper C3-v0 4.73E-03 2.16E-03 1.05E-02 1.48E-03 1 106.76 120.81 1.00 

Dibenz(a,h)anthracene A1-v2 1.06E-05 1.95E-06 1.31E-04 6.78E-07 9 262.22 100.79 0.00 

Ethylbenzene A2-v1 3.04E-02 1.74E-02 9.50E-02 2.53E-03 4 100.75 57.01 0.51 

Fluoranthene A2-v0 3.06E-06 3.03E-06 5.66E-06 1.72E-06 4 37.95 22.43 1.00 

Fluorene A2-v0 1.06E-05 8.55E-06 2.64E-05 3.33E-06 4 67.66 39.98 1.00 

Formaldehyde B1-v3 1.51E-01 3.03E-02 1.76E+00 7.92E-04 7 254.14 108.70 1.00 

Hydrogen Sulfide A1-v1 4.05E-01 3.27E-01 1.20E+00 1.82E-02 7 84.49 36.13 0.00 

Indeno(1,2,3-cd)pyrene A1-v3 1.15E-04 2.29E-06 1.55E-03 9.83E-07 9 342.12 131.50 0.99 

Lead C3-v0 5.49E-03 4.43E-03 8.43E-03 3.61E-03 1 47.03 53.22 1.00 

Manganese C3-v0 7.65E-03 7.03E-03 1.37E-02 2.21E-03 1 75.45 85.38 1.00 

Mercury C3-v0 2.02E-04 1.97E-04 2.17E-04 1.92E-04 1 6.49 7.34 0.36 

Naphthalene A2-v0 3.02E-04 2.43E-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 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-33 

Table D-11a. Summary of Data for Emission Factor Development –

Heaters Firing Refinery Fuel Gas (continued) 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Selenium C3-v0 2.20E-05 2.28E-05 2.85E-05 1.48E-05 1 31.23 35.34 0.78 

Silver C3-v1 1.81E-03 1.48E-03 3.61E-03 3.53E-04 1 91.23 103.24 0.94 

Thallium C3-v0 6.49E-03 6.49E-03 6.64E-03 6.33E-03 1 2.45 2.78 0.00 

Toluene D1-v2 1.37E-01 7.81E-02 1.21E+00 3.71E-03 11 154.31 52.65 0.55 

Xylene (Total) A2-v1 3.74E-02 3.37E-02 9.90E-02 4.27E-03 4 95.86 54.24 0.60 

Zinc C3-v0 2.34E-02 2.89E-02 3.18E-02 9.52E-03 1 51.72 58.53 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-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 

Mean Median Maximum Minimum Ratio

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-v0 1.17E-09 1.10E-09 1.40E-09 1.02E-09 4 11.55 6.82 0.00 

Benzo(k)fluoranthene A1-v2 2.41E-08 2.18E-09 2.96E-07 1.02E-09 9 310.01 119.16 0.96 

Beryllium C3-v0 2.57E-07 2.57E-07 2.63E-07 2.50E-07 1 2.45 2.78 0.00 

Cadmium C3-v0 9.88E-07 9.65E-07 1.18E-06 8.15E-07 1 18.76 21.23 1.00 

Chromium (Hex) C3-v0 2.17E-06 2.21E-06 2.24E-06 2.05E-06 1 4.62 5.23 0.00 

Chromium (Total) C3-v0 1.07E-06 6.57E-07 1.93E-06 6.26E-07 1 69.39 78.52 0.60 

Chrysene A2-v0 1.63E-09 1.23E-09 4.79E-09 1.02E-09 4 66.84 39.50 0.63 

Copper C3-v0 4.21E-06 1.93E-06 9.39E-06 1.31E-06 1 106.76 120.81 1.00 

Dibenz(a,h)anthracene A1-v2 1.02E-08 1.60E-09 1.37E-07 5.93E-10 9 279.09 107.28 0.00 

Ethylbenzene A2-v1 3.02E-05 1.79E-05 1.03E-04 2.72E-06 4 104.65 59.21 0.51 

Fluoranthene A2-v0 3.06E-09 3.14E-09 5.04E-09 1.85E-09 4 33.80 19.97 1.00 

Fluorene A2-v0 1.08E-08 8.77E-09 2.74E-08 2.96E-09 4 70.62 41.74 1.00 

Formaldehyde B1-v3 1.11E-04 1.90E-05 1.34E-03 7.67E-07 7 262.94 112.46 1.00 

Hydrogen Sulfide A1-v1 2.92E-04 2.46E-04 8.04E-04 1.76E-05 7 75.53 32.30 0.00 

Indeno(1,2,3-cd)pyrene A1-v3 1.03E-07 1.75E-09 1.42E-06 1.02E-09 9 343.01 131.85 0.99 

Lead C3-v0 4.89E-06 3.94E-06 7.51E-06 3.21E-06 1 47.03 53.22 1.00 

Manganese C3-v0 6.81E-06 6.26E-06 1.22E-05 1.97E-06 1 75.45 85.38 1.00 

Mercury C3-v0 1.80E-07 1.75E-07 1.93E-07 1.71E-07 1 6.49 7.34 0.36 

Naphthalene A2-v0 3.13E-07 2.61E-07 7.58E-07 1.19E-07 4 66.90 39.53 1.00 

Nickel C3-v1 9.42E-06 1.31E-06 2.57E-05 1.29E-06 1 149.30 168.95 0.95 

Phenanthrene A2-v0 1.46E-08 1.50E-08 2.25E-08 6.91E-09 4 32.60 19.27 1.00 

Phenol C1-v1 5.63E-06 3.14E-06 2.54E-05 2.84E-07 7 114.62 49.02 0.97 

Phosphorus C3-v0 6.42E-07 6.43E-07 6.57E-07 6.26E-07 1 2.45 2.78 0.00 

Propylene A2-v0 2.17E-06 2.22E-06 2.98E-06 1.08E-06 3 23.69 15.47 0.05 

Pyrene A2-v0 2.84E-09 2.72E-09 4.53E-09 1.87E-09 4 28.87 17.06 1.00 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-35 

Table D-11b. Summary of Data for Emission Factor Development –

Heaters Firing Refinery Fuel Gas (continued) 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Selenium C3-v0 1.96E-08 2.03E-08 2.54E-08 1.32E-08 1 31.23 35.34 0.78 

Silver C3-v1 1.61E-06 1.31E-06 3.21E-06 3.14E-07 1 91.23 103.24 0.94 

Thallium C3-v0 5.78E-06 5.78E-06 5.92E-06 5.63E-06 1 2.45 2.78 0.00 

Toluene D1-v2 1.07E-04 7.00E-05 9.19E-04 4.04E-06 11 148.57 50.69 0.55 

Xylene (Total) A2-v1 3.73E-05 3.16E-05 1.08E-04 4.66E-06 4 99.32 56.19 0.60 

Zinc C3-v0 2.08E-05 2.58E-05 2.83E-05 8.48E-06 1 51.72 58.53 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-36 

Table D-12a. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Catalytic Reduction 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.17E-06 1.04E-06 1.41E-06 9.83E-07 4 16.09 9.51 0.00 

Benzo(k)fluoranthene A1-v2 2.72E-05 2.66E-06 3.40E-04 9.83E-07 9 309.39 118.92 0.96 

Beryllium C3-v0 2.88E-04 2.89E-04 2.95E-04 2.81E-04 1 2.45 2.78 0.00 

Cadmium C3-v0 1.11E-03 1.08E-03 1.33E-03 9.15E-04 1 18.76 21.23 1.00 

Chromium (Hex) C3-v0 2.43E-03 2.48E-03 2.51E-03 2.30E-03 1 4.62 5.23 0.00 

Chromium (Total) C3-v0 1.20E-03 7.38E-04 2.16E-03 7.03E-04 1 69.39 78.52 0.60 

Chrysene A2-v0 1.66E-06 1.29E-06 5.37E-06 9.83E-07 4 76.71 45.33 0.63 

Copper C3-v0 4.73E-03 2.16E-03 1.05E-02 1.48E-03 1 106.76 120.81 1.00 

Dibenz(a,h)anthracene A1-v2 1.06E-05 1.95E-06 1.31E-04 6.78E-07 9 262.22 100.79 0.00 

Ethylbenzene A2-v1 3.04E-02 1.74E-02 9.50E-02 2.53E-03 4 100.75 57.01 0.51 

Fluoranthene A2-v0 3.06E-06 3.03E-06 5.66E-06 1.72E-06 4 37.95 22.43 1.00 

Fluorene A2-v0 1.06E-05 8.55E-06 2.64E-05 3.33E-06 4 67.66 39.98 1.00 

Formaldehyde B1-v3 1.51E-01 3.03E-02 1.76E+00 7.92E-04 7 254.14 108.70 1.00 

Hydrogen Sulfide A1-v1 4.05E-01 3.27E-01 1.20E+00 1.82E-02 7 84.49 36.13 0.00 

Indeno(1,2,3-cd)pyrene A1-v3 1.15E-04 2.29E-06 1.55E-03 9.83E-07 9 342.12 131.50 0.99 

Lead C3-v0 5.49E-03 4.43E-03 8.43E-03 3.61E-03 1 47.03 53.22 1.00 

Manganese C3-v0 7.65E-03 7.03E-03 1.37E-02 2.21E-03 1 75.45 85.38 1.00 

Mercury C3-v0 2.02E-04 1.97E-04 2.17E-04 1.92E-04 1 6.49 7.34 0.36 

Naphthalene A2-v0 3.02E-04 2.43E-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 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-37 

Table D-12a. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Catalytic Reduction (continued) 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Selenium C3-v0 2.20E-05 2.28E-05 2.85E-05 1.48E-05 1 31.23 35.34 0.78 

Silver C3-v1 1.81E-03 1.48E-03 3.61E-03 3.53E-04 1 91.23 103.24 0.94 

Thallium C3-v0 6.49E-03 6.49E-03 6.64E-03 6.33E-03 1 2.45 2.78 0.00 

Toluene D1-v2 1.37E-01 7.81E-02 1.21E+00 3.71E-03 11 154.31 52.65 0.55 

Xylene (Total) A2-v1 3.74E-02 3.37E-02 9.90E-02 4.27E-03 4 95.86 54.24 0.60 

Zinc C3-v0 2.34E-02 2.89E-02 3.18E-02 9.52E-03 1 51.72 58.53 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-38 

Table D-12b. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Catalytic Reduction 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty,

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.17E-09 1.10E-09 1.40E-09 1.02E-09 4 11.55 6.82 0.00 

Benzo(k)fluoranthene A1-v2 2.41E-08 2.18E-09 2.96E-07 1.02E-09 9 310.01 119.16 0.96 

Beryllium C3-v0 2.57E-07 2.57E-07 2.63E-07 2.50E-07 1 2.45 2.78 0.00 

Cadmium C3-v0 9.88E-07 9.65E-07 1.18E-06 8.15E-07 1 18.76 21.23 1.00 

Chromium (Hex) C3-v0 2.17E-06 2.21E-06 2.24E-06 2.05E-06 1 4.62 5.23 0.00 

Chromium (Total) C3-v0 1.07E-06 6.57E-07 1.93E-06 6.26E-07 1 69.39 78.52 0.60 

Chrysene A2-v0 1.63E-09 1.23E-09 4.79E-09 1.02E-09 4 66.84 39.50 0.63 

Copper C3-v0 4.21E-06 1.93E-06 9.39E-06 1.31E-06 1 106.76 120.81 1.00 

Dibenz(a,h)anthracene A1-v2 1.02E-08 1.60E-09 1.37E-07 5.93E-10 9 279.09 107.28 0.00 

Ethylbenzene A2-v1 3.02E-05 1.79E-05 1.03E-04 2.72E-06 4 104.65 59.21 0.51 

Fluoranthene A2-v0 3.06E-09 3.14E-09 5.04E-09 1.85E-09 4 33.80 19.97 1.00 

Fluorene A2-v0 1.08E-08 8.77E-09 2.74E-08 2.96E-09 4 70.62 41.74 1.00 

Formaldehyde B1-v3 1.11E-04 1.90E-05 1.34E-03 7.67E-07 7 262.94 112.46 1.00 

Hydrogen Sulfide A1-v1 2.92E-04 2.46E-04 8.04E-04 1.76E-05 7 75.53 32.30 0.00 

Indeno(1,2,3-

cd)pyrene A1-v3 1.03E-07 1.75E-09 1.42E-06 1.02E-09 9 343.01 131.85 0.99 

Lead C3-v0 4.89E-06 3.94E-06 7.51E-06 3.21E-06 1 47.03 53.22 1.00 

Manganese C3-v0 6.81E-06 6.26E-06 1.22E-05 1.97E-06 1 75.45 85.38 1.00 

Mercury C3-v0 1.80E-07 1.75E-07 1.93E-07 1.71E-07 1 6.49 7.34 0.36 

Naphthalene A2-v0 3.13E-07 2.61E-07 7.58E-07 1.19E-07 4 66.90 39.53 1.00 

Nickel C3-v1 9.42E-06 1.31E-06 2.57E-05 1.29E-06 1 149.30 168.95 0.95 

Phenanthrene A2-v0 1.46E-08 1.50E-08 2.25E-08 6.91E-09 4 32.60 19.27 1.00 

Phenol C1-v1 5.63E-06 3.14E-06 2.54E-05 2.84E-07 7 114.62 49.02 0.97 

Phosphorus C3-v0 6.42E-07 6.43E-07 6.57E-07 6.26E-07 1 2.45 2.78 0.00

Propylene A2-v0 2.17E-06 2.22E-06 2.98E-06 1.08E-06 3 23.69 15.47 0.05 

(continued)
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-39 

Table D-12b. Summary of Data for Emission Factor Development – Heaters Firing Refinery 

Fuel Gas Controlled with Selective Catalytic Reduction (continued) 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty,

%

Detect 

Mean Median Maximum Minimum Ratio

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 

Silver C3-v1 1.61E-06 1.31E-06 3.21E-06 3.14E-07 1 91.23 103.24 0.94 

Thallium C3-v0 5.78E-06 5.78E-06 5.92E-06 5.63E-06 1 2.45 2.78 0.00 

Toluene D1-v2 1.07E-04 7.00E-05 9.19E-04 4.04E-06 11 148.57 50.69 0.55 

Xylene (Total) A2-v1 3.73E-05 3.16E-05 1.08E-04 4.66E-06 4 99.32 56.19 0.60 

Zinc C3-v0 2.08E-05 2.58E-05 2.83E-05 8.48E-06 1 51.72 58.53 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-40 

Table D-13a. Summary of Data for Emission Factor Development –

Internal Combustion Engines Firing Diesel Fuel, O2 < 13% 

Substance

CARB

Rating

Emission Factor (lb/Mgal)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.53E-04 1.41E-04 1.92E-04 1.26E-04 1 22.58 25.55 0.27 

Benzo(g,h,i)perylene C3-v0 7.69E-05 7.84E-05 8.30E-05 6.92E-05 1 9.17 10.37 1.00 

Benzo(k)fluoranthene C3-v0 3.02E-05 1.23E-05 6.92E-05 9.22E-06 1 111.67 126.37 0.76 

Chrysene C3-v0 2.11E-04 2.21E-04 2.28E-04 1.84E-04 1 11.03 12.48 1.00 

Dibenz(a,h)anthracene C3-v0 4.77E-05 4.61E-05 5.07E-05 4.61E-05 1 5.59 6.32 0.00 

Fluoranthene C3-v0 5.56E-04 5.47E-04 5.84E-04 5.37E-04 1 4.50 5.09 1.00 

Fluorene C3-v0 1.77E-03 1.76E-03 1.81E-03 1.72E-03 1 2.62 2.96 1.00 

Formaldehyde A3-v1 1.09E-02 4.64E-03 2.63E-02 1.74E-03 1 123.19 139.41 1.00 

Indeno(1,2,3-cd)pyrene C3-v0 5.69E-05 5.84E-05 6.61E-05 4.61E-05 1 17.72 20.05 0.34 

Naphthalene C3-v0 1.80E-02 1.81E-02 1.85E-02 1.72E-02 1 3.74 4.24 1.00 

Phenanthrene C3-v0 5.62E-03 5.65E-03 5.76E-03 5.47E-03 1 2.58 2.92 1.00 

Propylene A3-v0 3.85E-01 4.03E-01 4.03E-01 3.49E-01 1 8.06 9.12 1.00 

Pyrene C3-v0 5.11E-04 4.89E-04 5.60E-04 4.86E-04 1 8.16 9.24 1.00 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-41 

Table D-13b. Summary of Data for Emission Factor Development –

Internal Combustion Engines Firing Diesel Fuel, O2 < 13% 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.08E-06 9.98E-07 1.36E-06 8.89E-07 1 22.58 25.55 0.27 

Benzo(g,h,i)perylene C3-v0 5.42E-07 5.53E-07 5.85E-07 4.88E-07 1 9.17 10.37 1.00 

Benzo(k)fluoranthene C3-v0 2.13E-07 8.67E-08 4.88E-07 6.51E-08 1 111.67 126.37 0.76 

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-v0 3.36E-07 3.25E-07 3.58E-07 3.25E-07 1 5.59 6.32 0.00 

Fluoranthene C3-v0 3.92E-06 3.86E-06 4.12E-06 3.78E-06 1 4.50 5.09 1.00 

Fluorene C3-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-v0 4.01E-07 4.12E-07 4.66E-07 3.25E-07 1 17.72 20.05 0.34 

Naphthalene C3-v0 1.27E-04 1.28E-04 1.31E-04 1.21E-04 1 3.74 4.24 1.00 

Phenanthrene C3-v0 3.97E-05 3.98E-05 4.06E-05 3.86E-05 1 2.58 2.92 1.00 

Propylene A3-v0 2.71E-03 2.84E-03 2.84E-03 2.46E-03 1 8.06 9.12 1.00 

Pyrene C3-v0 3.61E-06 3.45E-06 3.95E-06 3.43E-06 1 8.16 9.24 1.00 

Toluene A3-v0 2.63E-04 2.61E-04 2.73E-04 2.57E-04 1 3.27 3.70 1.00 

Xylene (Total) A3-v0 1.89E-04 1.91E-04 1.95E-04 1.81E-04 1 3.85 4.36 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-42 

Table D-14a. Summary of Data for Emission Factor Development –

Internal Combustion Engines Firing Diesel Fuel, O2 > 13% 

Substance

CARB

Rating

Emission Factor (lb/Mgal)

Tests

RSD, 

%

Uncertainty,

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 2.59E-05 2.72E-05 3.88E-05 1.17E-05 1 52.68 59.61 0.50 

Benzo(b+k)fluoranthene C3-v0 1.44E-06 1.45E-06 1.46E-06 1.41E-06 1 1.90 2.14 0.00 

Benzo(g,h,i)perylene C3-v1 6.78E-05 5.89E-05 1.55E-04 1.17E-05 2 71.76 57.42 0.43 

Benzo(k)fluoranthene C3-v0 4.14E-05 4.27E-05 6.22E-05 1.94E-05 1 51.63 58.43 0.50 

1,3-Butadiene C3-v0 5.41E-03 5.41E-03 5.41E-03 5.41E-03 1 0.00 0.00 0.00 

Chrysene C3-v0 4.90E-05 5.23E-05 6.75E-05 2.72E-05 2 33.96 27.17 1.00 

Dibenz(a,h)anthracene C3-v0 8.12E-05 6.41E-05 1.44E-04 4.42E-05 2 50.80 40.65 0.35 

Fluoranthene C3-v1 1.06E-03 8.29E-04 2.70E-03 6.99E-05 2 90.38 72.32 1.00 

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-v1 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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-43 

Table D-14b. Summary of Data for Emission Factor Development –

Internal Combustion Engines Firing Diesel Fuel, O2 > 13% 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.87E-07 1.97E-07 2.81E-07 8.43E-08 1 52.68 59.61 0.50 

Benzo(b+k)fluoranthene C3-v0 1.03E-08 1.03E-08 1.04E-08 1.00E-08 1 1.90 2.14 0.00 

Benzo(g,h,i)perylene C3-v1 4.87E-07 4.24E-07 1.12E-06 8.43E-08 2 72.27 57.82 0.43 

Benzo(k)fluoranthene C3-v0 3.00E-07 3.09E-07 4.49E-07 1.40E-07 1 51.63 58.43 0.50 

1,3-Butadiene C3-v0 3.86E-05 3.86E-05 3.86E-05 3.86E-05 1 0.00 0.00 0.00 

Chrysene C3-v0 3.52E-07 3.76E-07 4.81E-07 1.97E-07 2 33.43 26.75 1.00 

Dibenz(a,h)anthracene C3-v0 5.84E-07 4.57E-07 1.04E-06 3.16E-07 2 51.34 41.08 0.35 

Fluoranthene C3-v1 7.59E-06 5.94E-06 1.93E-05 5.06E-07 2 90.02 72.03 1.00 

Fluorene C3-v1 2.90E-05 2.83E-05 5.40E-05 1.52E-06 2 87.31 69.86 0.99 

Formaldehyde A3-v0 1.19E-03 1.04E-03 2.39E-03 6.18E-04 2 55.30 44.25 1.00 

Indeno(1,2,3-cd)pyrene C3-v1 4.63E-07 2.91E-07 9.55E-07 5.62E-08 2 84.39 67.52 0.30 

Naphthalene C3-v0 8.48E-05 5.59E-05 2.20E-04 4.28E-05 2 80.69 64.56 1.00 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-44 

Table D-15a. Summary of Data for Emission Factor Development –

Two-Stroke Internal Combustion Engines Firing Field Gas, Lean 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acenaphthene A3-v0 7.41E-04 7.41E-04 1.08E-03 4.00E-04 1 65.08 90.19 0.00 

Acenaphthylene A3-v0 1.11E-02 1.11E-02 1.57E-02 6.44E-03 1 59.06 81.86 1.00 

Acetaldehyde A3-v0 8.77E+00 9.42E+00 1.14E+01 5.53E+00 1 33.90 38.37 1.00

Acrolein A3-v1 2.00E+00 1.44E+00 4.36E+00 2.00E-01 1 106.79 120.84 1.00 

Anthracene A3-v0 4.50E-03 4.50E-03 6.67E-03 2.34E-03 1 67.84 94.02 1.00 

Benzene A3-v0 7.85E+00 4.60E+00 1.36E+01 4.23E+00 2 60.68 53.19 1.00 

Benzo(a)anthracene A3-v0 8.97E-04 8.97E-04 9.11E-04 8.83E-04 1 2.17 3.01 1.00 

Benzo(a)pyrene A3-v0 8.75E-04 8.75E-04 1.53E-03 2.16E-04 1 106.44 147.52 0.00 

Benzo(b)fluoranthene A3-v0 1.48E-04 1.48E-04 1.71E-04 1.24E-04 1 22.41 31.05 0.00 

Benzo(g,h,i)perylene A3-v0 9.40E-05 9.40E-05 9.92E-05 8.89E-05 1 7.74 10.72 0.00 

Benzo(k)fluoranthene A3-v0 4.57E-03 4.57E-03 4.69E-03 4.44E-03 1 3.78 5.23 1.00 

Chrysene A3-v0 1.69E-03 1.69E-03 1.80E-03 1.58E-03 1 9.43 13.07 1.00 

Dibenz(a,h)anthracene A3-v0 7.70E-05 7.70E-05 8.29E-05 7.11E-05 1 10.86 15.06 0.00 

Fluoranthene A3-v0 1.66E-04 1.66E-04 2.16E-04 1.16E-04 1 42.96 59.53 0.00 

Fluorene A3-v0 2.44E-03 2.44E-03 3.61E-03 1.27E-03 1 67.90 94.10 0.00 

Formaldehyde A3-v1 5.09E+01 6.79E+01 8.53E+01 4.21E+00 2 69.80 55.85 1.00 

Indeno(1,2,3-cd)pyrene A3-v0 1.37E-04 1.37E-04 1.46E-04 1.29E-04 1 8.83 12.24 0.00 

Naphthalene A3-v0 2.19E-01 2.19E-01 2.22E-01 2.16E-01 1 1.88 2.61 1.00 

Phenanthrene A3-v0 4.91E-03 4.91E-03 6.49E-03 3.33E-03 1 45.46 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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-45 

Table D-15b. Summary of Data for Emission Factor Development –

Two-Stroke Internal Combustion Engines Firing Field Gas, Lean 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 1.41E-07 1.41E-07 1.63E-07 1.18E-07 1 22.41 31.05 0.00 

Benzo(g,h,i)perylene A3-v0 8.95E-08 8.95E-08 9.44E-08 8.46E-08 1 7.74 10.72 0.00 

Benzo(k)fluoranthene A3-v0 4.35E-06 4.35E-06 4.46E-06 4.23E-06 1 3.78 5.23 1.00 

Chrysene A3-v0 1.61E-06 1.61E-06 1.72E-06 1.50E-06 1 9.43 13.07 1.00 

Dibenz(a,h)anthracene A3-v0 7.33E-08 7.33E-08 7.90E-08 6.77E-08 1 10.86 15.06 0.00 

Fluoranthene A3-v0 1.58E-07 1.58E-07 2.06E-07 1.10E-07 1 42.96 59.53 0.00 

Fluorene A3-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-v0 1.31E-07 1.31E-07 1.39E-07 1.23E-07 1 8.83 12.24 0.00 

Naphthalene A3-v0 2.09E-04 2.09E-04 2.12E-04 2.06E-04 1 1.88 2.61 1.00 

Phenanthrene A3-v0 4.68E-06 4.68E-06 6.18E-06 3.17E-06 1 45.46 63.00 1.00 

Propylene A3-v0 2.37E-02 1.69E-02 3.82E-02 1.09E-02 2 56.74 49.73 1.00 

Pyrene A3-v0 2.27E-07 2.27E-07 2.92E-07 1.63E-07 1 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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-46 

Table D-16a. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion Engines Firing Field Gas, Lean 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Benzene A2-v0 1.72E+00 2.07E+00 2.24E+00 9.25E-01 3 35.58 28.47 1.00 

Formaldehyde A2-v1 4.15E+01 3.14E+01 9.78E+01 4.62E+00 3 76.73 50.13 1.00 

Propylene A2-v0 1.59E+01 1.84E+01 2.02E+01 9.48E+00 3 30.49 24.40 1.00 

Toluene A2-v0 7.68E-01 9.38E-01 1.17E+00 2.69E-01 3 51.12 40.90 1.00 

Xylene (m,p) A2-v1 3.02E-01 1.90E-01 9.03E-01 7.74E-02 3 99.71 79.78 1.00 

Xylene (o) A2-v0 8.97E-02 9.57E-02 1.22E-01 6.13E-02 3 25.60 20.49 1.00 

Table D-16b. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion Engines Firing Field Gas, Lean 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Benzene A2-v0 1.64E-03 1.97E-03 2.14E-03 8.81E-04 3 35.58 28.47 1.00 

Formaldehyde A2-v1 3.95E-02 2.99E-02 9.32E-02 4.40E-03 3 76.73 50.13 1.00 

Propylene A2-v0 1.52E-02 1.75E-02 1.92E-02 9.03E-03 3 30.49 24.40 1.00 

Toluene A2-v0 7.31E-04 8.94E-04 1.11E-03 2.56E-04 3 51.12 40.90 1.00 

Xylene (m,p) A2-v1 2.87E-04 1.81E-04 8.60E-04 7.37E-05 3 99.71 79.78 1.00 

Xylene (o) A2-v0 8.55E-05 9.11E-05 1.16E-04 5.84E-05 3 25.60 20.49 1.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-47 

Table D-17a. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion Engines Firing Field Gas, Rich 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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 Engines Firing Field Gas, Rich 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-48 

Table D-18a. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion Engines Firing Natural Gas, Lean 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acenaphthene A3-v0 7.17E-04 6.36E-04 9.60E-04 5.57E-04 1 29.79 33.71 1.00 

Acenaphthylene A3-v0 7.59E-03 7.65E-03 1.07E-02 4.40E-03 1 41.56 47.03 1.00 

Acetaldehyde A1-v0 3.99E+00 2.96E+00 9.94E+00 1.52E+00 5 64.91 32.85 1.00 

Acrolein A1-v1 1.63E+00 1.10E+00 5.48E+00 2.01E-01 5 92.02 48.20 1.00 

Anthracene A3-v0 2.56E-04 2.40E-04 3.69E-04 1.60E-04 1 41.20 46.62 1.00 

Benzene A1-v1 1.21E+00 1.22E+00 2.47E+00 2.47E-01 7 47.28 24.77 1.00 

Benzo(a)anthracene A3-v0 7.78E-05 7.83E-05 9.60E-05 5.91E-05 1 23.70 26.82 1.00 

Benzo(a)pyrene A3-v0 3.55E-05 2.93E-05 5.17E-05 2.54E-05 1 39.97 45.23 0.76 

Benzo(b)fluoranthene A3-v2 3.27E-04 4.43E-05 9.29E-04 6.26E-06 1 159.90 180.94 0.95 

Benzo(g,h,i)perylene A3-v1 1.03E-04 2.93E-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-v0 1.09E-05 1.11E-05 1.47E-05 6.96E-06 1 35.41 40.07 1.00 

Fluoranthene A3-v0 2.50E-04 2.64E-04 3.32E-04 1.53E-04 1 36.21 40.98 1.00 

Fluorene A3-v0 4.60E-04 4.16E-04 6.28E-04 3.37E-04 1 32.63 36.92 0.00 

Formaldehyde A1-v0 2.87E+01 2.77E+01 4.79E+01 9.68E+00 7 38.56 16.49 1.00 

Indeno(1,2,3-cd)pyrene A3-v1 1.20E-04 3.91E-05 2.95E-04 2.43E-05 1 127.40 144.16 1.00 

Naphthalene A3-v0 1.22E-01 1.60E-01 1.86E-01 1.99E-02 1 73.21 82.85 1.00 

Phenanthrene A3-v0 8.93E-04 8.31E-04 1.26E-03 5.91E-04 1 37.66 42.62 1.00 

Propylene A1-v1 1.87E+01 8.81E+00 5.85E+01 4.12E+00 7 109.05 57.12 0.97 

Pyrene A3-v0 1.23E-04 1.42E-04 1.62E-04 6.61E-05 1 41.10 46.51 1.00 

Toluene A1-v0 4.12E-01 3.96E-01 5.70E-01 1.65E-01 7 33.98 17.80 1.00 

Xylene (m,p) A1-v0 8.63E-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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-49 

Table D-18b. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion Engines Firing Natural Gas, Lean 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 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-v1 1.14E-07 3.73E-08 2.81E-07 2.32E-08 1 127.40 144.16 1.00 

Naphthalene A3-v0 1.16E-04 1.52E-04 1.77E-04 1.90E-05 1 73.21 82.85 1.00 

Phenanthrene A3-v0 8.50E-07 7.92E-07 1.20E-06 5.63E-07 1 37.66 42.62 1.00 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-50 

Table D-19a. Summary of Data for Emission Factor Development –

Four-Stroke Internal Combustion Engines Firing Natural Gas, Rich 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acetaldehyde A3-v0 1.71E+00 1.70E+00 1.82E+00 1.60E+00 1 6.46 7.31 1.00 

Acrolein A3-v2 5.40E-01 4.16E-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 

Mean Median Maximum Minimum Ratio

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-51 

Table D-20a. Summary of Data for Emission Factor Development –

Steam Generators Firing Natural Gas 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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 

Mean Median Maximum Minimum Ratio

Acetaldehyde A3-v0 1.66E-05 1.68E-05 1.77E-05 1.53E-05 1 7.27 8.22 1.00 

Acrolein A3-v0 1.96E-05 1.86E-05 2.37E-05 1.65E-05 1 18.73 21.19 1.00 

Benzene B3-v0 3.94E-06 3.93E-06 4.10E-06 3.78E-06 2 4.28 3.42 0.00 

Formaldehyde A3-v1 3.11E-05 1.87E-05 9.75E-05 3.87E-06 2 113.45 90.78 1.00 

Propylene C3-v0 1.16E-04 1.16E-04 1.17E-04 1.16E-04 1 0.36 0.41 0.00 

Toluene B3-v0 1.22E-05 1.22E-05 1.27E-05 1.17E-05 2 4.28 3.42 0.00 

Xylene (Total) B3-v0 2.81E-05 2.81E-05 2.94E-05 2.70E-05 2 4.28 3.42 0.00 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-52 

Table D-21a. Summary of Data for Emission Factor Development –

Steam Generators Firing Natural Gas and Casing Vapor Recovery Gas 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acenaphthene A3-v0 1.04E-06 7.23E-07 2.38E-06 4.12E-07 2 69.67 55.75 0.72 

Acenaphthylene A3-v1 2.70E-06 6.70E-07 1.03E-05 4.12E-07 2 144.60 115.70 0.85 

Acetaldehyde A2-v0 1.12E-02 1.02E-02 2.67E-02 5.02E-03 4 55.73 31.53 0.84 

Acrolein A2-v0 1.05E-02 1.07E-02 1.82E-02 5.02E-03 4 37.86 21.42 0.88 

Anthracene A3-v0 2.09E-06 2.28E-06 3.82E-06 4.12E-07 2 62.45 49.97 0.97 

Benzene B1-v0 3.33E-03 2.68E-03 6.21E-03 2.36E-03 5 44.41 22.47 0.00 

Benzo(a)anthracene A3-v0 1.22E-06 1.12E-06 2.16E-06 6.82E-07 2 40.32 32.26 0.45 

Benzo(a)pyrene A3-v0 6.86E-07 6.46E-07 1.33E-06 3.98E-07 2 49.51 39.61 0.32 

Benzo(b)fluoranthene A3-v0 2.00E-06 9.18E-07 4.78E-06 6.36E-07 2 95.49 76.41 0.84 

Benzo(g,h,i)perylene A3-v0 9.80E-07 6.70E-07 1.75E-06 4.12E-07 2 61.38 49.11 0.59 

Benzo(k)fluoranthene A3-v0 8.21E-07 6.70E-07 1.39E-06 4.12E-07 2 44.95 35.97 0.52 

Chrysene A3-v0 1.55E-06 1.83E-06 2.16E-06 6.82E-07 2 38.63 30.91 0.33 

Dibenz(a,h)anthracene A3-v0 5.30E-07 5.24E-07 6.82E-07 3.96E-07 2 26.65 21.32 0.00 

Ethylbenzene A3-v0 9.22E-03 7.34E-03 1.86E-02 3.69E-03 2 55.96 44.77 0.54 

Fluoranthene A3-v0 3.66E-06 1.71E-06 9.03E-06 1.01E-06 2 98.55 78.86 1.00 

Fluorene A3-v0 5.63E-06 2.47E-06 1.30E-05 1.77E-06 2 95.48 76.40 1.00 

Formaldehyde A2-v1 1.58E-02 9.51E-03 7.01E-02 5.02E-03 4 117.82 66.66 0.70 

Hydrogen Sulfide C3-v0 1.48E-01 1.43E-01 2.28E-01 7.39E-02 1 51.99 58.83 1.00 

Indeno(1,2,3-cd)pyrene A3-v0 1.17E-06 6.70E-07 2.38E-06 4.12E-07 2 76.13 60.92 0.66 

Naphthalene A3-v0 2.89E-04 2.24E-04 5.54E-04 1.50E-04 2 56.04 44.84 1.00 

Phenanthrene A3-v0 1.64E-05 1.21E-05 3.17E-05 6.59E-06 2 64.15 51.33 1.00 

Propylene C2-v1 1.83E-01 7.80E-02 6.30E-01 6.71E-03 4 117.13 66.27 0.72 

Pyrene A3-v1 6.00E-06 2.78E-06 1.74E-05 8.19E-07 2 109.69 87.77 1.00 

Toluene B1-v0 1.37E-02 9.47E-03 3.08E-02 7.33E-03 5 59.41 30.07 0.64 

Xylene (Total) B1-v0 1.85E-02 1.70E-02 4.03E-02 1.11E-02 5 36.66 18.55 0.23 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-53 

Table D-21b. Summary of Data for Emission Factor Development –

Steam Generators Firing Natural Gas and Casing Vapor Recovery Gas 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 2.01E-09 9.26E-10 4.71E-09 7.10E-10 2 92.63 74.12 0.84 

Benzo(g,h,i)perylene A3-v0 9.98E-10 7.14E-10 1.73E-09 4.06E-10 2 57.41 45.93 0.59 

Benzo(k)fluoranthene A3-v0 8.41E-10 7.14E-10 1.37E-09 4.06E-10 2 41.36 33.09 0.52 

Chrysene A3-v0 1.60E-09 1.80E-09 2.42E-09 7.12E-10 2 39.17 31.35 0.33 

Dibenz(a,h)anthracene A3-v0 5.54E-10 5.58E-10 7.15E-10 3.90E-10 2 31.29 25.04 0.00 

Ethylbenzene A3-v0 9.63E-06 7.23E-06 2.02E-05 4.02E-06 2 59.81 47.86 0.54 

Fluoranthene A3-v0 3.67E-09 1.78E-09 8.90E-09 1.07E-09 2 95.56 76.46 1.00 

Fluorene A3-v0 5.66E-09 2.64E-09 1.28E-08 1.85E-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-v0 1.18E-09 7.14E-10 2.34E-09 4.06E-10 2 72.24 57.80 0.66 

Naphthalene A3-v0 2.93E-07 2.33E-07 5.46E-07 1.57E-07 2 52.01 41.62 1.00 

Phenanthrene A3-v0 1.68E-08 1.34E-08 3.12E-08 6.50E-09 2 60.61 48.50 1.00 

Propylene C2-v1 2.29E-04 1.27E-04 6.83E-04 1.23E-05 4 94.36 53.39 0.72 

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-54 

Table D-22a. Summary of Data for Emission Factor Development –

Turbines with No Duct Burners Firing Natural Gas 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 3.40E-06 2.87E-06 8.93E-06 1.26E-06 2 83.26 66.62 0.44 

Benzo(g,h,i)perylene A3-v0 2.47E-06 2.87E-06 3.31E-06 1.26E-06 2 37.62 30.10 0.22 

Benzo(k)fluoranthene A3-v0 2.67E-06 2.87E-06 4.54E-06 1.26E-06 2 46.39 37.12 0.28 

Chrysene A3-v0 5.08E-06 5.99E-06 6.34E-06 2.89E-06 2 31.73 25.39 0.31 

Dibenz(a,h)anthracene A3-v0 2.13E-06 2.09E-06 3.17E-06 1.26E-06 2 43.24 34.60 0.00 

Ethylbenzene A3-v0 1.53E-02 1.52E-02 2.20E-02 9.49E-03 2 40.90 32.72 0.00 

Fluoranthene A3-v0 1.20E-05 1.21E-05 1.74E-05 5.78E-06 2 36.16 28.93 1.00 

Fluorene A3-v0 1.55E-05 1.42E-05 3.17E-05 8.05E-06 2 54.85 43.89 1.00 

Formaldehyde A3-v0 2.09E-02 1.73E-02 2.81E-02 1.73E-02 1 29.80 33.72 0.45 

Indeno(1,2,3-cd)pyrene A3-v0 2.38E-06 2.82E-06 3.17E-06 1.26E-06 2 35.90 28.73 0.20 

Naphthalene A3-v0 7.51E-04 8.01E-04 9.51E-04 4.56E-04 2 28.73 22.99 1.00 

Phenanthrene A3-v0 6.71E-05 4.95E-05 1.46E-04 2.62E-05 2 64.08 51.28 1.00 

Propylene A3-v0 1.71E+00 1.68E+00 2.00E+00 1.46E+00 1 15.66 17.72 1.00 

Pyrene A3-v0 2.31E-05 2.09E-05 4.23E-05 5.78E-06 2 63.17 50.55 1.00 

Toluene A3-v1 7.17E-02 5.89E-02 1.68E-01 8.22E-03 2 88.92 71.15 0.98 

Xylene (Total) A3-v0 3.63E-02 4.11E-02 6.26E-02 9.70E-03 2 52.17 41.75 0.38 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-55 

Table D-22b. Summary of Data for Emission Factor Development –

Turbines with No Duct Burners Firing Natural Gas 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acenaphthene A3-v0 3.25E-09 2.03E-09 8.46E-09 1.23E-09 2 87.69 70.16 0.67 

Acenaphthylene A3-v0 2.90E-09 2.74E-09 5.67E-09 1.23E-09 2 57.20 45.77 0.54 

Acetaldehyde A3-v0 3.78E-05 4.55E-05 5.14E-05 1.65E-05 1 49.40 55.90 0.85 

Acrolein A3-v0 1.72E-05 1.73E-05 1.73E-05 1.71E-05 1 0.68 0.77 0.00 

Anthracene A3-v1 3.43E-08 7.19E-09 1.50E-07 3.70E-09 2 168.94 135.17 1.00 

Benzene A3-v0 1.20E-05 1.19E-05 1.82E-05 6.64E-06 2 48.32 38.66 0.00 

Benzo(a)anthracene A3-v0 2.78E-09 2.31E-09 5.62E-09 1.80E-09 2 52.46 41.98 0.34 

Benzo(a)pyrene A3-v0 2.05E-09 2.01E-09 3.02E-09 1.23E-09 2 41.94 33.56 0.00 

Benzo(b)fluoranthene A3-v0 3.30E-09 2.74E-09 8.77E-09 1.23E-09 2 84.51 67.62 0.44 

Benzo(g,h,i)perylene A3-v0 2.38E-09 2.74E-09 3.25E-09 1.23E-09 2 37.17 29.74 0.22 

Benzo(k)fluoranthene A3-v0 2.58E-09 2.74E-09 4.46E-09 1.23E-09 2 46.68 37.35 0.28 

Chrysene A3-v0 4.93E-09 5.88E-09 6.05E-09 2.76E-09 2 32.43 25.95 0.31 

Dibenz(a,h)anthracene A3-v0 2.05E-09 2.01E-09 3.02E-09 1.23E-09 2 41.94 33.56 0.00 

Ethylbenzene A3-v0 1.49E-05 1.48E-05 2.16E-05 9.05E-06 2 42.21 33.78 0.00 

Fluoranthene A3-v0 1.16E-08 1.16E-08 1.71E-08 5.51E-09 2 36.82 29.47 1.00 

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-v0 2.29E-09 2.73E-09 3.02E-09 1.23E-09 2 35.08 28.07 0.20 

Naphthalene A3-v0 7.29E-07 7.77E-07 9.33E-07 4.35E-07 2 30.01 24.02 1.00 

Phenanthrene A3-v0 6.46E-08 4.86E-08 1.39E-07 2.57E-08 2 62.98 50.39 1.00 

Propylene A3-v0 1.63E-03 1.61E-03 1.90E-03 1.39E-03 1 15.66 17.72 1.00 

Pyrene A3-v0 2.25E-08 2.03E-08 4.15E-08 5.51E-09 2 64.16 51.34 1.00 

Toluene A3-v1 7.01E-05 5.75E-05 1.65E-04 7.85E-06 2 89.58 71.67 0.98 

Xylene (Total) A3-v0 3.52E-05 4.04E-05 5.97E-05 9.25E-06 2 51.95 41.57 0.38 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-56 

Table D-23a. Summary of Data for Emission Factor Development –

Turbines with No Duct Burners Firing Natural Gas Controlled with 

Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 3.40E-06 2.87E-06 8.93E-06 1.26E-06 2 83.26 66.62 0.44 

Benzo(g,h,i)perylene A3-v0 2.47E-06 2.87E-06 3.31E-06 1.26E-06 2 37.62 30.10 0.22 

Benzo(k)fluoranthene A3-v0 2.67E-06 2.87E-06 4.54E-06 1.26E-06 2 46.39 37.12 0.28 

Chrysene A3-v0 5.08E-06 5.99E-06 6.34E-06 2.89E-06 2 31.73 25.39 0.31 

Dibenz(a,h)anthracene A3-v0 2.13E-06 2.09E-06 3.17E-06 1.26E-06 2 43.24 34.60 0.00 

Ethylbenzene A3-v0 1.53E-02 1.52E-02 2.20E-02 9.49E-03 2 40.90 32.72 0.00 

Fluoranthene A3-v0 1.20E-05 1.21E-05 1.74E-05 5.78E-06 2 36.16 28.93 1.00 

Fluorene A3-v0 1.55E-05 1.42E-05 3.17E-05 8.05E-06 2 54.85 43.89 1.00 

Formaldehyde A3-v0 2.09E-02 1.73E-02 2.81E-02 1.73E-02 1 29.80 33.72 0.45 

Indeno(1,2,3-cd)pyrene A3-v0 2.38E-06 2.82E-06 3.17E-06 1.26E-06 2 35.90 28.73 0.20 

Naphthalene A3-v0 7.51E-04 8.01E-04 9.51E-04 4.56E-04 2 28.73 22.99 1.00 

Phenanthrene A3-v0 6.71E-05 4.95E-05 1.46E-04 2.62E-05 2 64.08 51.28 1.00 

Propylene A3-v0 1.71E+00 1.68E+00 2.00E+00 1.46E+00 1 15.66 17.72 1.00 

Pyrene A3-v0 2.31E-05 2.09E-05 4.23E-05 5.78E-06 2 63.17 50.55 1.00 

Toluene A3-v1 7.17E-02 5.89E-02 1.68E-01 8.22E-03 2 88.92 71.15 0.98 

Xylene (Total) A3-v0 3.63E-02 4.11E-02 6.26E-02 9.70E-03 2 52.17 41.75 0.38 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-57 

Table D-23b. Summary of Data for Emission Factor Development –

Turbines with No Duct Burners Firing Natural Gas Controlled with 

Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Acenaphthene A3-v0 3.25E-09 2.03E-09 8.46E-09 1.23E-09 2 87.69 70.16 0.67 

Acenaphthylene A3-v0 2.90E-09 2.74E-09 5.67E-09 1.23E-09 2 57.20 45.77 0.54 

Acetaldehyde A3-v0 3.78E-05 4.55E-05 5.14E-05 1.65E-05 1 49.40 55.90 0.85 

Acrolein A3-v0 1.72E-05 1.73E-05 1.73E-05 1.71E-05 1 0.68 0.77 0.00 

Anthracene A3-v1 3.43E-08 7.19E-09 1.50E-07 3.70E-09 2 168.94 135.17 1.00 

Benzene A3-v0 1.20E-05 1.19E-05 1.82E-05 6.64E-06 2 48.32 38.66 0.00 

Benzo(a)anthracene A3-v0 2.78E-09 2.31E-09 5.62E-09 1.80E-09 2 52.46 41.98 0.34 

Benzo(a)pyrene A3-v0 2.05E-09 2.01E-09 3.02E-09 1.23E-09 2 41.94 33.56 0.00 

Benzo(b)fluoranthene A3-v0 3.30E-09 2.74E-09 8.77E-09 1.23E-09 2 84.51 67.62 0.44 

Benzo(g,h,i)perylene A3-v0 2.38E-09 2.74E-09 3.25E-09 1.23E-09 2 37.17 29.74 0.22 

Benzo(k)fluoranthene A3-v0 2.58E-09 2.74E-09 4.46E-09 1.23E-09 2 46.68 37.35 0.28 

Chrysene A3-v0 4.93E-09 5.88E-09 6.05E-09 2.76E-09 2 32.43 25.95 0.31 

Dibenz(a,h)anthracene A3-v0 2.05E-09 2.01E-09 3.02E-09 1.23E-09 2 41.94 33.56 0.00 

Ethylbenzene A3-v0 1.49E-05 1.48E-05 2.16E-05 9.05E-06 2 42.21 33.78 0.00 

Fluoranthene A3-v0 1.16E-08 1.16E-08 1.71E-08 5.51E-09 2 36.82 29.47 1.00 

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-v0 2.29E-09 2.73E-09 3.02E-09 1.23E-09 2 35.08 28.07 0.20 

Naphthalene A3-v0 7.29E-07 7.77E-07 9.33E-07 4.35E-07 2 30.01 24.02 1.00 

Phenanthrene A3-v0 6.46E-08 4.86E-08 1.39E-07 2.57E-08 2 62.98 50.39 1.00 

Propylene A3-v0 1.63E-03 1.61E-03 1.90E-03 1.39E-03 1 15.66 17.72 1.00 

Pyrene A3-v0 2.25E-08 2.03E-08 4.15E-08 5.51E-09 2 64.16 51.34 1.00 

Toluene A3-v1 7.01E-05 5.75E-05 1.65E-04 7.85E-06 2 89.58 71.67 0.98 

Xylene (Total) A3-v0 3.52E-05 4.04E-05 5.97E-05 9.25E-06 2 51.95 41.57 0.38 
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-58 

Table D-24a. Summary of Data for Emission Factor Development – Turbines with Duct Burners 

Firing Natural Gas Controlled with Selective Catalytic Reduction 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Formaldehyde C3-v0 6.22E+00 6.09E+00 6.87E+00 5.71E+00 1 9.57 10.83 1.00

Table D-24b. Summary of Data for Emission Factor Development – Turbines with Duct Burners 

Firing Natural Gas Controlled with Selective Catalytic Reduction 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

Formaldehyde C3-v0 6.02E-03 5.89E-03 6.65E-03 5.52E-03 1 9.57 10.83 1.00
Version 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-59 

Table D-25a. Summary of Data for Emission Factor Development – Turbines with 

Duct Burners Firing Natural Gas and Refinery Fuel Gas Controlled with 

Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 2.69E-05 3.19E-05 3.44E-05 1.45E-05 1 40.14 45.42 0.82 

Benzo(g,h,i)perylene C3-v0 2.06E-05 2.00E-05 2.71E-05 1.45E-05 1 30.62 34.65 0.00 

Benzo(k)fluoranthene C3-v0 1.34E-05 1.21E-05 2.00E-05 8.05E-06 1 45.53 51.52 0.00 

Cadmium C3-v0 2.08E-03 1.06E-03 4.16E-03 1.03E-03 1 86.47 97.85 0.67 

Chromium (Hex) C3-v0 7.46E-03 7.08E-03 1.50E-02 1.53E-03 2 83.96 67.18 0.00 

Chromium (Total) C3-v1 5.35E-02 3.36E-02 1.84E-01 1.51E-02 2 121.46 97.19 1.00 

Chrysene C3-v0 1.16E-04 6.85E-05 2.43E-04 3.47E-05 1 96.95 109.70 1.00 

Copper A3-v0 1.89E-03 1.98E-03 2.64E-03 1.04E-03 1 42.72 48.34 1.00 

Dibenz(a,h)anthracene C3-v0 7.10E-06 8.12E-06 8.59E-06 4.58E-06 1 30.92 34.99 0.00 

Fluoranthene C3-v0 1.06E-04 1.07E-04 1.58E-04 5.53E-05 1 48.01 54.33 1.00 

Fluorene C3-v1 1.90E-04 8.02E-05 4.46E-04 4.26E-05 1 117.53 132.99 1.00 

Formaldehyde A3-v0 1.71E-01 9.23E-02 3.42E-01 7.76E-02 1 87.01 98.46 1.00 

Hydrogen Sulfide A3-v0 1.65E-01 1.64E-01 1.72E-01 1.59E-01 1 4.20 4.76 0.00 

Indeno(1,2,3-cd)pyrene C3-v0 9.83E-06 1.06E-05 1.18E-05 7.10E-06 1 24.76 28.02 0.00 

Manganese A3-v0 3.49E-03 2.36E-03 6.79E-03 1.32E-03 1 83.26 94.21 1.00 

Mercury A3-v0 4.63E-03 4.01E-03 8.27E-03 2.55E-03 2 51.31 41.05 1.00 

Naphthalene C3-v0 4.02E-02 3.98E-02 4.30E-02 3.79E-02 1 6.36 7.20 1.00 

Nickel C3-v0 8.18E-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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-60 

Table D-25b. Summary of Data for Emission Factor Development – Turbines with 

Duct Burners Firing Natural Gas and Refinery Fuel Gas Controlled with 

Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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-v0 2.50E-08 2.96E-08 3.20E-08 1.35E-08 1 40.14 45.42 0.82 

Benzo(g,h,i)perylene C3-v0 1.91E-08 1.86E-08 2.52E-08 1.35E-08 1 30.62 34.65 0.00 

Benzo(k)fluoranthene C3-v0 1.25E-08 1.13E-08 1.86E-08 7.49E-09 1 45.53 51.52 0.00 

Cadmium C3-v0 1.94E-06 9.84E-07 3.87E-06 9.55E-07 1 86.47 97.85 0.67 

Chromium (Hex) C3-v0 6.95E-06 6.60E-06 1.39E-05 1.45E-06 2 83.59 66.88 0.00 

Chromium (Total) C3-v1 4.99E-05 3.15E-05 1.71E-04 1.43E-05 2 120.88 96.72 1.00 

Chrysene C3-v0 1.07E-07 6.37E-08 2.26E-07 3.23E-08 1 96.95 109.70 1.00 

Copper A3-v0 1.75E-06 1.84E-06 2.46E-06 9.65E-07 1 42.72 48.34 1.00 

Dibenz(a,h)anthracene C3-v0 6.60E-09 7.55E-09 7.99E-09 4.26E-09 1 30.92 34.99 0.00 

Fluoranthene C3-v0 9.90E-08 9.92E-08 1.46E-07 5.14E-08 1 48.01 54.33 1.00 

Fluorene C3-v1 1.76E-07 7.46E-08 4.15E-07 3.96E-08 1 117.53 132.99 1.00 

Formaldehyde A3-v0 1.54E-04 8.36E-05 3.09E-04 7.03E-05 1 86.98 98.42 1.00 

Hydrogen Sulfide A3-v0 1.50E-04 1.49E-04 1.56E-04 1.44E-04 1 4.30 4.86 0.00 

Indeno(1,2,3-cd)pyrene C3-v0 9.14E-09 9.85E-09 1.10E-08 6.61E-09 1 24.76 28.02 0.00 

Manganese A3-v0 3.25E-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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-61 

Table D-26a. Summary of Data for Emission Factor Development – Turbines with 

Duct Burners Firing Natural Gas, Refinery Fuel Gas, and Liquefied Petroleum Gas 

Controlled with Selective Catalytic Reduction and Carbon Monoxide Oxidation Catalyst 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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 – 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 

Mean Median Maximum Minimum Ratio

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-62 

Table D-27a. Summary of Data for Emission Factor Development – Turbines with No Duct Burners 

Firing Refinery Fuel Gas Controlled with Carbon Monoxide Oxidation Catalyst 

Substance

CARB

Rating

Emission Factor (lb/MMcf)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-63 

Table D-27b. Summary of Data for Emission Factor Development – Turbines with No Duct Burners 

Firing Refinery Fuel Gas Controlled with Carbon Monoxide Oxidation Catalyst 

Substance

CARB

Rating

Emission Factor (lb/MMBtu)

Tests

RSD, 

%

Uncertainty, 

%

Detect 

Mean Median Maximum Minimum Ratio

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 1.0 – Appendix D—Emission Factors for Combustion Sources 

Review Draft – Do not cite or quote 

D-64 

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