ATTACHMENT C

CONDENSATE TANK OIL AND GAS ACTIVITIES
CONDENSATE TANK OIL AND GAS 

ACTIVITIES

FINAL REPORT

Prepared for:

Texas Commission on Environmental Quality

Air Quality Division

Prepared by:

Eastern Research Group, Inc.

October 10, 2012
ERG N0. 0292.01.011.001

Condensate Tank Oil and Gas Activities

FINAL REPORT

Prepared for:

Miles Whitten

Texas Commission on Environmental Quality

P. O. Box 13087

Austin, TX 78711-3087

Prepared by:

Mike Pring

Eastern Research Group, Inc.

1600 Perimeter Park Dr., Suite 200

Morrisville, NC 27560

October 10, 2012
i

Table of Contents

Executive Summary...........................................................................................................v

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

2.0 VOC Emissions From Condensate Storage Tanks............................................. 2-1

2.1 Condensate Production........................................................................... 2-1

2.2 Literature Review....................................................................................2-2

2.2.1 Emissions Data Derived from Testing ......................................... 2-3

2.2.2 Comparisons of Emissions Data Derived from Testing with 

Emissions Estimates Derived from Models/Software Programs........... 2-5

2.2.3 Emissions Estimates Derived Solely from Models/Software 

Programs ............................................................................................... 2-10

2.2.4 Other Studies.............................................................................. 2-12

2.3 Emission Factor Development Using the Barnett Shale Area Special 

Inventory, Phase II (2009) ................................................................... 2-13

2.4 Phone Survey of Area Sources .............................................................. 2-16

2.4.1 Analysis of Data Collected via Phone Survey............................. 2-18

2.4.2 Use of Vapor Recovery and Controls to Reduce Emissions ......2-20

2.4.3 Self-Selection Bias ...................................................................... 2-21

2.4.4 Innovative Practices that Lower Area Emissions ...................... 2-21

2.5 Weighting the Data ...............................................................................2-22

2.5.1 Weighting Data based on Method..............................................2-22

2.5.2 Weighting Data based on Production........................................2-23

2.6 Regional Emission Factors ...................................................................2-24

2.7 Accounting for the Effect of Recovery and Control Devices ................ 2-35

2.7.1 Barnett Shale .............................................................................. 2-35

2.7.2 HGB, BPA, and Haynesville Shale ............................................. 2-35

2.7.3 Calculation of Control Factor.....................................................2-36

2.7.4 ERG 2012 Survey........................................................................ 2-37

2.8 Summary of Findings and Recommended Emission Factors ..............2-39

3.0 Hazardous Air Pollutant Emissions from Condensate Storage Tanks.............. 3-1

3.1 BTEX Emissions Data Derived from Testing ......................................... 3-1

3.2 BTEX Emissions Data Derived from the Barnett Shale Area Special 

Inventory, Phase II (2009) ..................................................................... 3-3
ii

3.3 BTEX Emissions Data Derived from E&P TANK Reports Submitted in 

Response to the ERG Survey ..................................................................3-4

3.4 Summary of Findings and Recommended Regional BTEX Emission 

Factors.....................................................................................................3-8

4.0 Recommendations for Future Condensate Tank Investigations....................... 4-1

5.0 Natural Gas Composition Data Collection and Analysis ....................................5-1

Attachment A Survey Letter

Attachment B Survey Materials – Word Table and Excel Spreadsheet

Attachment C Condensate Tank Emissions Data (Condensate_Tank_Data.xlsx)

Attachment D County-Level Average Natural Gas Composition Profiles 

(NG_Composition_Profiles.xlsx)

List of Tables

Table E-1. County-Level VOC Emission Factors............................................................. v

Table E-2. Basin-Level and State-Level Average Natural Gas Stream Composition 

Profiles ................................................................................................................... xii

Table 2-1. Condensate Tank Emission Data from the HARC 2006 Study ................2-5

Table 2-2. Operating Parameters, Production, and Measured Emissions ................2-7

Table 2-3. Comparison of Estimated Emissions with Measured Emissions............ 2-8

Table 2-4. Ratio Between Estimated Emissions and Measured Emissions ............. 2-9

Table 2-5. Condensate Tank Emission Factors from the TCEQ 2010 Study........... 2-11

Table 2-6. Producer-Supplied VOC Emission Estimates for Condensate Tank 

Batteries in Haynesville Shale Area .................................................................2-12

Table 2-7. Condensate Tank VOC Emission Factors by Method – Barnett Shale 

Inventory ............................................................................................................2-14

Table 2-8. Condensate Tank VOC Emission Factors by County – Barnett Shale 

Inventory ............................................................................................................ 2-15

Table 2-9. Target Survey Counties ..............................................................................2-16

Table 2-10. Survey Results Using all Valid Survey Data Estimated with Preferred 

Estimation Methods ..........................................................................................2-19

Table 2-11. Weighting Factors by Emissions Estimation Method........................... 2-23

Table 2-12. Average Regional VOC Emission Factors Derived from Testing Data.2-25

Table 2-13. Average Regional VOC Emission Factors Derived from Estimation 

Methods ..............................................................................................................2-25

Table 2-14. Average Regional VOC Emission Factors from ERG Survey Data and 

Barnett Shale Inventory Data .......................................................................... 2-26
iii

List of Tables (Continued)

Table 2-15. Average Regional VOC Emission Factors .............................................. 2-26

Table 2-16. County-Level VOC Emission Factors ..................................................... 2-29

Table 2-17. Percentage of Surveyed Production with Tank Emissions Controlled in 

the HGB, BPA, and Haynesville Shale Areas ................................................. 2-38

Table 2-18. Surveyed Production, Total Production, Percent of Surveyed Production 

Controlled, and Control Factor, by Region .....................................................2-41

Table 3-1. VOC and BTEX Content in the Vent Gas ....................................................3-1

Table 3-2. VOC and BTEX Emission Factors ...............................................................3-2

Table 3-3. Condensate Tank BTEX Emission Factor Estimates Using Data from the 

Barnett Shale Phase II 2009 Inventory.............................................................3-4

Table 3-4. Condensate Tank BTEX Emission Factor Estimates Using Data from E&P 

TANK Reports Submitted for ERG Survey........................................................3-5

Table 3-5. Production-Weighted Average Regional BTEX Emission Factors, from 

Testing Data, Barnett Shale Inventory, and Survey Data ............................... 3-8

Table 3-6. Arithmetic Average Regional BTEX Emission Factors, from Testing Data, 

Barnett Shale Inventory, and Survey Data....................................................... 3-8

Table 5-1. Counties Included in the Natural Gas Composition Analysis...................5-2

Table 5-2. List of Counties Located in Marathon Thrust Belt Basin and Palo Duro 

Basin......................................................................................................................5-3

Table 5-3. Basin-Level and State-Level Average Natural Gas Stream Composition 

Profiles ..................................................................................................................5-4

Table 5-4. Average Natural Gas Composition Profile Allocation Scheme.................5-6

List of Figures

Figure 2-1. Condensate Producing Regions in Texas ......................................................2-1

Figure 2-2. Target Survey Counties ............................................................................... 2-17

Figure 2-3. Relationship between Production and Emission Factor ........................... 2-24

Figure 2-4. Condensate Tank Emission Data Sources by County.................................2-27

Figure 2-5. Average Regional Emission Factors, Before Controls ............................... 2-28

Figure 5-1. Natural Gas Methane Composition Distribution across Texas Counties ....5-11
iv

List of Acronyms

Acronym Definition

API American Petroleum Institute

BBL Barrel

BPA Beaumont-Port Arthur 

BTEX Benzene, Toluene, Ethylbenzene, Xylene

CENRAP Central Regional Air Planning Association

CO2 Carbon Dioxide

EPA U.S. Environmental Protection Agency

ERG Eastern Research Group

GOR Gas/Oil Ratio

HAP Hazardous Air Pollutants

HARC Houston Advanced Research Center

HGB Houston-Galveston-Brazoria

IPAMS Independent Petroleum Association of Mountain States

lbs Pounds

NSPS New Source Performance Standard

psig pounds per square inch gauge

QA Quality Assurance

RRC Texas Railroad Commission

TCEQ Texas Commission on Environmental Quality

TERC Texas Environmental Research Consortium

VOC Volatile Organic Compound

VRU Vapor Recovery Unit

WRAP Western Regional Air Partnership
v

Executive Summary

This report is a deliverable for Texas Commission on Environmental Quality (TCEQ) 

Work Order No. 582-11-99776-FY12-11 to improve area source emission estimates for 

the oil and gas sector. Improvements will be gained through this effort by the 

development of refined emission factors for volatile organic compound (VOC) and 

hazardous air pollutant (HAP) emissions from condensate storage tanks, as well as 

improved gas speciation profiles for different gas formations on a county-by-county 

basis.

Under this project, a review of available literature was conducted for data on emissions 

testing and emissions estimates for condensate tanks in Texas. In addition, data 

collected in the Barnett Shale Area Special Inventory conducted by TCEQ was evaluated, 

a phone survey of Texas condensate producers was conducted, and additional data on 

emissions estimates was obtained from several recent studies evaluating condensate 

storage tank emissions. ERG evaluated this data for its relevance and quality, and 

derived region-specific emission factors for eight geographic regions in the state. These 

emission factors are presented in Table E-1 below.

Table E-1. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Anderson East Texas/Haynesville Shale 4.22 5.92

Andrews Permian 7.07 5.90

Angelina East Texas/Haynesville Shale 4.22 5.92

Aransas Western Gulf 11.0 14.8

Archer Fort Worth/Barnett Shale 9.76 16.0

Armstrong Palo Duro 7.61 9.75

Atascosa Eagle Ford Shale 10.5 10.0

Austin Western Gulf 11.0 14.8

Bailey Palo Duro 7.61 9.75

Bandera Fort Worth/Barnett Shale 9.76 16.0

Bastrop Western Gulf 11.0 14.8

Baylor Fort Worth/Barnett Shale 9.76 16.0

Bee Eagle Ford Shale 10.5 10.0

Bell Western Gulf 11.0 14.8

Bexar Western Gulf 11.0 14.8

Blanco Fort Worth/Barnett Shale 9.76 16.0

Borden Permian 7.07 5.90

Bosque Fort Worth/Barnett Shale 9.76 16.0

Bowie East Texas/Haynesville Shale 4.22 5.92

Brazoria Western Gulf 11.0 14.8

Brazos Eagle Ford Shale 10.5 10.0

Brewster Marathon Thrust Belt 7.61 9.75
vi

Table E-1. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Briscoe Palo Duro 7.61 9.75

Brooks Western Gulf 11.0 14.8

Brown Fort Worth/Barnett Shale 9.76 16.0

Burleson Eagle Ford Shale 10.5 10.0

Burnet Fort Worth/Barnett Shale 9.76 16.0

Caldwell Western Gulf 11.0 14.8

Calhoun Western Gulf 11.0 14.8

Callahan Fort Worth/Barnett Shale 9.76 16.0

Cameron Western Gulf 11.0 14.8

Camp East Texas/Haynesville Shale 4.22 5.92

Carson Anadarko 3.15 5.87

Cass East Texas/Haynesville Shale 4.22 5.92

Castro Palo Duro 7.61 9.75

Chambers Western Gulf 11.0 14.8

Cherokee East Texas/Haynesville Shale 4.22 5.92

Childress Palo Duro 7.61 9.75

Clay Fort Worth/Barnett Shale 9.76 16.0

Cochran Permian 7.07 5.90

Coke Permian 7.07 5.90

Coleman Fort Worth/Barnett Shale 9.76 16.0

Collin Fort Worth/Barnett Shale 9.76 16.0

Collingsworth Palo Duro 7.61 9.75

Colorado Western Gulf 11.0 14.8

Comal Western Gulf 11.0 14.8

Comanche Fort Worth/Barnett Shale 9.76 16.0

Concho Fort Worth/Barnett Shale 9.76 16.0

Cooke Fort Worth/Barnett Shale 9.76 16.0

Coryell Fort Worth/Barnett Shale 9.76 16.0

Cottle Palo Duro 7.61 9.75

Crane Permian 7.07 5.90

Crockett Permian 7.07 5.90

Crosby Permian 7.07 5.90

Culberson Permian 7.07 5.90

Dallam Palo Duro 7.61 9.75

Dallas Fort Worth/Barnett Shale 9.76 16.0

Dawson Permian 7.07 5.90

Deaf Smith Palo Duro 7.61 9.75

Delta East Texas/Haynesville Shale 4.22 5.92

Denton Fort Worth/Barnett Shale 9.76 16.0

DeWitt Eagle Ford Shale 10.5 10.0

Dickens Permian 7.07 5.90

Dimmit Eagle Ford Shale 10.5 10.0

Donley Palo Duro 7.61 9.75

Duval Western Gulf 11.0 14.8
vii

Table E-1. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Eastland Fort Worth/Barnett Shale 9.76 16.0

Ector Permian 7.07 5.90

Edwards Permian 7.07 5.90

El Paso Permian 7.07 5.90

Ellis Fort Worth/Barnett Shale 9.76 16.0

Erath Fort Worth/Barnett Shale 9.76 16.0

Falls East Texas/Haynesville Shale 4.22 5.92

Fannin East Texas/Haynesville Shale 4.22 5.92

Fayette Eagle Ford Shale 10.5 10.0

Fisher Permian 7.07 5.90

Floyd Palo Duro 7.61 9.75

Foard Fort Worth/Barnett Shale 9.76 16.0

Fort Bend Western Gulf 11.0 14.8

Franklin East Texas/Haynesville Shale 4.22 5.92

Freestone East Texas/Haynesville Shale 4.22 5.92

Frio Eagle Ford Shale 10.5 10.0

Gaines Permian 7.07 5.90

Galveston Western Gulf 11.0 14.8

Garza Permian 7.07 5.90

Gillespie Fort Worth/Barnett Shale 9.76 16.0

Glasscock Permian 7.07 5.90

Goliad Western Gulf 11.0 14.8

Gonzales Eagle Ford Shale 10.5 10.0

Gray Anadarko 3.15 5.87

Grayson Fort Worth/Barnett Shale 9.76 16.0

Gregg East Texas/Haynesville Shale 4.22 5.92

Grimes Eagle Ford Shale 10.5 10.0

Guadalupe Western Gulf 11.0 14.8

Hale Palo Duro 7.61 9.75

Hall Palo Duro 7.61 9.75

Hamilton Fort Worth/Barnett Shale 9.76 16.0

Hansford Anadarko 3.15 5.87

Hardeman Fort Worth/Barnett Shale 9.76 16.0

Hardin Western Gulf 11.0 14.8

Harris Western Gulf 11.0 14.8

Harrison East Texas/Haynesville Shale 4.22 5.92

Hartley Palo Duro 7.61 9.75

Haskell Fort Worth/Barnett Shale 9.76 16.0

Hays Western Gulf 11.0 14.8

Hemphill Anadarko 3.15 5.87

Henderson East Texas/Haynesville Shale 4.22 5.92

Hidalgo Western Gulf 11.0 14.8

Hill Fort Worth/Barnett Shale 9.76 16.0

Hockley Permian 7.07 5.90
viii

Table E-1. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Hood Fort Worth/Barnett Shale 9.76 16.0

Hopkins East Texas/Haynesville Shale 4.22 5.92

Houston East Texas/Haynesville Shale 4.22 5.92

Howard Permian 7.07 5.90

Hudspeth Permian 7.07 5.90

Hunt East Texas/Haynesville Shale 4.22 5.92

Hutchinson Anadarko 3.15 5.87

Irion Permian 7.07 5.90

Jack Fort Worth/Barnett Shale 9.76 16.0

Jackson Western Gulf 11.0 14.8

Jasper Western Gulf 11.0 14.8

Jeff Davis Permian 7.07 5.90

Jefferson Western Gulf 11.0 14.8

Jim Hogg Western Gulf 11.0 14.8

Jim Wells Western Gulf 11.0 14.8

Johnson Fort Worth/Barnett Shale 9.76 16.0

Jones Fort Worth/Barnett Shale 9.76 16.0

Karnes Eagle Ford Shale 10.5 10.0

Kaufman East Texas/Haynesville Shale 4.22 5.92

Kendall Fort Worth/Barnett Shale 9.76 16.0

Kenedy Western Gulf 11.0 14.8

Kent Permian 7.07 5.90

Kerr Fort Worth/Barnett Shale 9.76 16.0

Kimble Fort Worth/Barnett Shale 9.76 16.0

King Permian 7.07 5.90

Kinney Western Gulf 11.0 14.8

Kleberg Western Gulf 11.0 14.8

Knox Fort Worth/Barnett Shale 9.76 16.0

La Salle Eagle Ford Shale 10.5 10.0

Lamar East Texas/Haynesville Shale 4.22 5.92

Lamb Palo Duro 7.61 9.75

Lampasas Fort Worth/Barnett Shale 9.76 16.0

Lavaca Eagle Ford Shale 10.5 10.0

Lee Eagle Ford Shale 10.5 10.0

Leon Eagle Ford Shale 10.5 10.0

Liberty Western Gulf 11.0 14.8

Limestone East Texas/Haynesville Shale 4.22 5.92

Lipscomb Anadarko 3.15 5.87

Live Oak Eagle Ford Shale 10.5 10.0

Llano Fort Worth/Barnett Shale 9.76 16.0

Loving Permian 7.07 5.90

Lubbock Permian 7.07 5.90

Lynn Permian 7.07 5.90

Madison Western Gulf 11.0 14.8
ix

Table E-1. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Marion East Texas/Haynesville Shale 4.22 5.92

Martin Permian 7.07 5.90

Mason Fort Worth/Barnett Shale 9.76 16.0

Matagorda Western Gulf 11.0 14.8

Maverick Eagle Ford Shale 10.5 10.0

McCulloch Fort Worth/Barnett Shale 9.76 16.0

McLennan Fort Worth/Barnett Shale 9.76 16.0

McMullen Eagle Ford Shale 10.5 10.0

Medina Western Gulf 11.0 14.8

Menard Fort Worth/Barnett Shale 9.76 16.0

Midland Permian 7.07 5.90

Milam Eagle Ford Shale 10.5 10.0

Mills Fort Worth/Barnett Shale 9.76 16.0

Mitchell Permian 7.07 5.90

Montague Fort Worth/Barnett Shale 9.76 16.0

Montgomery Western Gulf 11.0 14.8

Moore Anadarko 3.15 5.87

Morris East Texas/Haynesville Shale 4.22 5.92

Motley Palo Duro 7.61 9.75

Nacogdoches East Texas/Haynesville Shale 4.22 5.92

Navarro East Texas/Haynesville Shale 4.22 5.92

Newton Western Gulf 11.0 14.8

Nolan Permian 7.07 5.90

Nueces Western Gulf 11.0 14.8

Ochiltree Anadarko 3.15 5.87

Oldham Palo Duro 7.61 9.75

Orange Western Gulf 11.0 14.8

Palo Pinto Fort Worth/Barnett Shale 9.76 16.0

Panola East Texas/Haynesville Shale 4.22 5.92

Parker Fort Worth/Barnett Shale 9.76 16.0

Parmer Palo Duro 7.61 9.75

Pecos Permian 7.07 5.90

Polk Western Gulf 11.0 14.8

Potter Palo Duro 7.61 9.75

Presidio Permian 7.07 5.90

Rains East Texas/Haynesville Shale 4.22 5.92

Randall Palo Duro 7.61 9.75

Reagan Permian 7.07 5.90

Real Fort Worth/Barnett Shale 9.76 16.0

Red River East Texas/Haynesville Shale 4.22 5.92

Reeves Permian 7.07 5.90

Refugio Western Gulf 11.0 14.8

Roberts Anadarko 3.15 5.87

Robertson Eagle Ford Shale 10.5 10.0
x

Table E-1. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Rockwall East Texas/Haynesville Shale 4.22 5.92

Runnels Fort Worth/Barnett Shale 9.76 16.0

Rusk East Texas/Haynesville Shale 4.22 5.92

Sabine East Texas/Haynesville Shale 4.22 5.92

San Augustine East Texas/Haynesville Shale 4.22 5.92

San Jacinto Western Gulf 11.0 14.8

San Patricio Western Gulf 11.0 14.8

San Saba Fort Worth/Barnett Shale 9.76 16.0

Schleicher Permian 7.07 5.90

Scurry Permian 7.07 5.90

Shackelford Fort Worth/Barnett Shale 9.76 16.0

Shelby East Texas/Haynesville Shale 4.22 5.92

Sherman Anadarko 3.15 5.87

Smith East Texas/Haynesville Shale 4.22 5.92

Somervell Fort Worth/Barnett Shale 9.76 16.0

Starr Western Gulf 11.0 14.8

Stephens Fort Worth/Barnett Shale 9.76 16.0

Sterling Permian 7.07 5.90

Stonewall Permian 7.07 5.90

Sutton Permian 7.07 5.90

Swisher Palo Duro 7.61 9.75

Tarrant Fort Worth/Barnett Shale 9.76 16.0

Taylor Fort Worth/Barnett Shale 9.76 16.0

Terrell Marathon Thrust Belt 7.61 9.75

Terry Permian 7.07 5.90

Throckmorton Fort Worth/Barnett Shale 9.76 16.0

Titus East Texas/Haynesville Shale 4.22 5.92

Tom Green Permian 7.07 5.90

Travis Western Gulf 11.0 14.8

Trinity Western Gulf 11.0 14.8

Tyler Western Gulf 11.0 14.8

Upshur East Texas/Haynesville Shale 4.22 5.92

Upton Permian 7.07 5.90

Uvalde Western Gulf 11.0 14.8

Val Verde Permian 7.07 5.90

Van Zandt East Texas/Haynesville Shale 4.22 5.92

Victoria Western Gulf 11.0 14.8

Walker Western Gulf 11.0 14.8

Waller Western Gulf 11.0 14.8

Ward Permian 7.07 5.90

Washington Western Gulf 11.0 14.8

Webb Eagle Ford Shale 10.5 10.0

Wharton Western Gulf 11.0 14.8

Wheeler Anadarko 3.15 5.87
xi

Table E-1. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Wichita Fort Worth/Barnett Shale 9.76 16.0

Wilbarger Fort Worth/Barnett Shale 9.76 16.0

Willacy Western Gulf 11.0 14.8

Williamson Western Gulf 11.0 14.8

Wilson Eagle Ford Shale 10.5 10.0

Winkler Permian 7.07 5.90

Wise Fort Worth/Barnett Shale 9.76 16.0

Wood East Texas/Haynesville Shale 4.22 5.92

Yoakum Permian 7.07 5.90

Young Fort Worth/Barnett Shale 9.76 16.0

Zapata Western Gulf 11.0 14.8

Zavala Eagle Ford Shale 10.5 10.0

Updated natural gas speciation profiles were developed through evaluation of GLYCalc 

emissions inventory reports submitted to TCEQ as part of the annual point source 

emissions inventory compilation. ERG reviewed TCEQ emissions inventory files and 

obtained GLYCalc data for 157 sites located in 64 counties across Texas. Using this 

information, average county natural gas composition profiles were developed. The 

64 counties for which data were available were then grouped by basins (Anadarko, Bend 

Arch-Forth Worth, East Texas, Permian, and Western Gulf Basins), and basin-level 

average natural gas composition (wet and dry) profiles were calculated. Basin-level 

average natural gas composition profile and state-level average profiles were then 

allocated to counties with no data based on which basin the county was located in. For 

two basins, the Marathon Thrust Belt and Palo Duro, no data was available so a statelevel average profile was developed. Table E-2 presents the basin-level and state-level 

average natural gas stream composition profiles for both wet and dry natural gas 

streams.
xii

Table E-2. Basin-Level and State-Level Average Natural Gas Stream Composition Profiles

Composition in % 

Volume

Anadarko Basin Bend Arch-Fort 

Worth Basin East Texas Basin Permian Basin Western Gulf State Profile

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Water 0.04 0.13 0.01 0.12 0.01 0.12 0.01 0.15 0.01 0.12 0.01 0.12

Carbon Dioxide 0.64 0.65 1.74 1.74 1.72 1.71 0.95 0.90 1.13 1.14 1.43 1.44

Hydrogen Sulfide 0.03 0.03 0.001 0.001 0.0004 0.0004 0.11 0.11 0.0003 0.25 0.03 0.09

Nitrogen 1.35 1.34 1.74 1.73 0.88 0.87 2.14 2.18 0.51 0.49 1.20 1.19

Methane 90.76 90.68 87.91 87.59 91.73 91.49 80.43 78.53 90.07 89.94 88.67 88.36

Ethane 3.99 3.98 5.23 5.21 3.57 3.64 9.02 9.07 4.51 4.51 5.03 5.00

Propane 1.74 1.74 2.14 2.18 1.04 1.06 4.48 5.39 2.04 2.05 2.13 2.21

Isobutane 0.26 0.26 0.31 0.32 0.28 0.29 0.51 0.61 0.48 0.48 0.38 0.40

n-Butane 0.54 0.54 0.62 0.68 0.31 0.32 1.19 1.63 0.51 0.51 0.58 0.64

Isopentane 0.16 0.16 0.20 0.22 0.15 0.17 0.35 0.40 0.24 0.24 0.22 0.23

n-Pentane 0.17 0.17 0.27 0.29 0.11 0.12 0.32 0.44 0.17 0.17 0.20 0.22

Cyclopentane 0.01 0.01 0.03 0.04 0.04 0.04 0.01 0.02 0.03 0.02 0.02 0.03

n-Hexane 0.10 0.06 0.05 0.12 0.05 0.05 0.16 0.18 0.05 0.06 0.06 0.09

Cyclohexane 0.01 0.01 0.04 0.03 0.03 0.03 0.09 0.11 0.05 0.06 0.04 0.05

Other Hexanes 0.14 0.14 0.07 0.06 0.10 0.11 0.24 0.29 0.17 0.15 0.13 0.13

Heptanes 0.06 0.06 0.08 0.08 0.06 0.07 0.14 0.14 0.07 0.09 0.08 0.08

Methylcyclohexane 0.02 0.02 0.02 0.02 0.01 0.02 0.04 0.04 0.04 0.04 0.03 0.04

Benzene 0.01 0.01 0.01 0.01 0.02 0.03 0.07 0.08 0.01 0.02 0.02 0.02

Toluene 0.01 0.01 0.003 0.003 0.01 0.01 0.04 0.04 0.01 0.02 0.01 0.01

Ethylbenzene 0.001 0.001 0.0005 0.001 0.001 0.001 0.01 0.01 0.001 0.002 0.001 0.002

Xylenes 0.003 0.01 0.002 0.003 0.002 0.005 0.01 0.01 0.003 0.01 0.003 0.005

C8+ Heavies 0.04 0.04 0.03 0.03 0.03 0.04 0.07 0.07 0.11 0.11 0.06 0.06
1-1

1.0 Introduction

Under contract with the Texas Commission on Environmental Quality (TCEQ), Eastern 

Research Group, Inc. (ERG) developed refined emission factors for volatile organic 

compound (VOC) and hazardous air pollutant (HAP) emissions from condensate tanks,

as well as improved gas speciation profiles for different gas formations on a county-bycounty basis. This information will be used to improve area source emissions inventory 

estimates for the oil and gas sector. This report describes ERG’s findings relative to an 

analysis of existing condensate tank emissions data, survey efforts to collect additional 

condensate tank emissions data, and development of natural gas speciation profiles in 

Texas.
2-1

2.0 VOC Emissions From Condensate Storage Tanks

A review of available literature was conducted for data on emissions testing and 

emissions estimates for condensate tanks in Texas. In addition, data collected in the 

Barnett Shale Area Special Inventory was evaluated, a phone survey of Texas condensate 

producers was conducted, and additional data on emissions estimates was obtained 

from TCEQ as available. ERG evaluated this data for its relevance and quality, and 

derived region-specific emission factors for eight geographic regions in the state. These 

eight regions are shown in Figure 2-1.

Figure 2-1. Condensate Producing Regions in Texas

2.1 Condensate Production

Condensate, for purposes of this survey, is defined as a hydrocarbon liquid produced at 

an oil or gas well and having an American Petroleum Institute (API) gravity greater than 
2-2

40 degrees.1 The API gravity of crude oil/condensate can vary from 20 to 70 degrees. 

In practice, most producers do not distinguish between oil and condensate, calling any 

petroleum liquid “oil”. However, the API gravity of produced liquid is important, as a 

petroleum liquid with a higher API gravity will generally command a premium in the 

market.2

TCEQ’s area source emissions estimate is based upon county-level oil and condensate 

production as reported on the RRC website. When creating an area source emissions 

estimate, it is important to distinguish between the emissions from petroleum liquid 

storage tanks located at ‘oil’ wells, and the emissions from petroleum liquid storage 

tanks located at ‘gas’ wells because the VOC emission factor for tanks at oil wells 

(1.6 pounds (lbs) VOC/barrel (bbl)) is significantly lower than the emission factor 

historically used for tanks at gas wells (33.3 lbs VOC/bbl).

API gravity is also important in determining what calculation method should 

be used to estimate the VOC emissions associated with the production of a hydrocarbon 

liquid. The Texas Railroad Commission (RRC) distinguishes between oil and 

condensate, with ‘oil’ being the liquid produced at oil wells and ‘condensate’ being the

hydrocarbon liquid produced at gas wells.

3

The RRC county level production data shows that the majority of petroleum-producing 

counties produce both ‘oil’ and ‘condensate’. This is usually due to the fact that, within 

the geographic boundary of many counties, there may be two or more petroleum 

producing formations stacked atop one another at different depths below ground. One 

of the formations may produce oil, while the other may produce gas, while perhaps a 

third formation yields gas from shale. Therefore, the estimates of emissions from any 

particular county or region could reflect the emissions from wells tapping one, two, or 

more petroleum-producing formations underground.

Given the difference in these 

estimates, it is important to distinguish between oil and condensate.

2.2 Literature Review

ERG reviewed the current literature for existing studies and other sources that evaluated 

emissions from oil and condensate tanks in Texas. These studies included emissions

measured via testing, emissions estimated through the use of software programs using 

 1 The American Petroleum Institute (API) does not define condensate in terms of its API gravity. The State of 

Colorado defines condensate as a hydrocarbon liquid that has an API gravity greater than or equal to 40° API at 

60°F. Colorado Department of Public Health and Environment, PS Memo 05-01, Oil and Gas Atmospheric 

Condensate Storage Tank Batteries, Regulatory Definitions and Permitting Guidance, October 1, 2009. 

http://www.cdphe.state.co.us/ap/down/ps05-01.pdf 2 Well Servicing Magazine, “Crude Oil Testing”, Andy Maslowski, September/October 2009, 

http://wellservicingmagazine.com/crude-oil-testing 3 These emission factors were used for estimating emissions from upstream area sources in the oil and gas industry 

in the report “Characterization of Oil and Gas Production Equipment and Develop a Methodology to Estimate 

Statewide Emissions”, TCEQ, 11/24/2010. The emission factors were first developed in the 2006 HARC study 

“VOC Emissions From Oil and Condensate Storage Tanks”.
2-3

equations-of-state, and comparisons of measured emissions with estimated emissions. 

The data in these studies were analyzed for their validity and utility, and a refined 

emission factor for estimating emissions from condensate storage tanks was developed. 

A brief description follows of the available literature, the information they contain, and 

the information from the study used in developing updated emission factors.

2.2.1 Emissions Data Derived from Testing

This section examines studies where emissions data was generated via direct 

measurement (testing) of emissions from oil and condensate tanks. 

“VOC Emissions from Oil and Condensate Storage Tanks” (Houston Advanced 

Research Center (HARC), 2006, and Texas Environmental Research Consortium

(TERC), 2009).4

This study is widely referred to as the “HARC” or “HARC H051C” study. In this study, 

researchers examined 2 oil and 13 gas (condensate) sites in the Fort Worth basin, and 9 

oil and 9 gas sites in the Western Gulf basin. This study measured oil and condensate 

tank emissions from each site and includes information such as API gravity and 

separator pressure. The HARC 2006 study noted that the emission estimates had a high 

uncertainty, due in part to the very low condensate production rates at well sites in 

Parker and Denton counties. The HARC 2006 study also noted that these 

measurements were taken during a period when recorded daytime high temperatures 

ranged from 98 to 107 degrees Fahrenheit at the nearby Dallas-Fort Worth Airport. The 

VOC emission factor of 33.3 lbs VOC/bbl condensate and the HAP emission factors

used in TCEQ’s 2008 upstream oil and gas area source inventory are derived from this 

report.

API provided comments5 to the U.S. Environmental Protection Agency (EPA) on the 

derivation of this emission factor in their comments on EPA’s proposed changes to the 

New Source Performance Standard (NSPS) for Oil and Gas Production (Subpart OOOO)

on November 30, 2011.6

 4 Houston Advanced Research Center, VOC Emissions from Oil and Condensate Storage Tanks, October

API called into question the validity of two of the data points 

used in developing the emission factor. API also questioned the use of emissions data 

from several sites where the measured condensate production was minimal. API noted 

in their comments that the 24-hour production measurement methodology used in the 

HARC study (manual gauging of oil level in the tank) may be subject to error, as the 

onsite measurements for two barrels of production would require accurately 

31, 2006. http://files.harc.edu/Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf 5 The API comments relative to condensate storage tank emissions were made by Dr. Ed Ireland of the Barnett Shale 

Energy Education Council.

6 American Petroleum Institute, API Comments on the Proposed Rulemaking – Oil and Gas Sector Regulations, 

November 30, 2011, http://www.api.org/Newsroom/testimony/upload/2011-11-30-API-Oil-and-Gas-Rule-FinalComments-Text.pdf
2-4

determining a difference of 0.71 to 1.2 inches in oil level via manual gauging of these 

300 bbl condensate tanks.7

API also questioned the presumption that emissions are solely a function of throughput 

and presented evidence that the VOC emissions per barrel of condensate produced are a 

non-linear function, dependent primarily upon separator pressure, and, to a lesser 

extent, API gravity. The comments suggest that each well/tank combination has unique 

emissions, based on: the composition of the liquids and gas produced, the API gravity of 

the liquid, the types of separator equipment in use, and the operating parameters of the 

separator. In general, liquids with a higher API gravity tend to have higher flash 

emissions per barrel than liquids with a lower API gravity. Also, the larger the pressure 

drop at the last stage of liquid-gas separation prior to moving the liquid to the storage 

tank, the higher the flash emissions. Therefore, any emission factor that is dependent 

solely upon production and does not take these other factors into account may not 

accurately estimate emissions for a specific well/tank combination. 

 However, in the 2009 revisions to the original report, the 

study authors noted that daily average production rates during the sampling period 

were obtained from site operating logs, not manual measurement as first erroneously 

reported. 

While such a multivariate approach is feasible for estimating point source emissions at 

any individual location, this approach would be impractical for estimating county-level, 

area source emissions where site-specific operating data is not readily available. The 

approach used by this study overcomes these limitations and provides a reasonably 

accurate means for estimating emissions from the condensate-producing regions of 

Texas by developing regional emission factors based on testing data and emissions 

estimates developed using TCEQ’s published preferred methodologies.

ERG re-examined the data from all 33 oil and condensate sites examined in the HARC 

2006 study. Although 27 sites produce liquids having an API gravity of 40 degrees or 

greater, only data from the 22 sites designated as producing condensate have been

considered in this analysis. In this re-analysis, three additional data points were 

removed from the data set. Data for tank 17 was removed because the calculated flash 

emissions (145 pounds VOC per barrel condensate produced (lbs/bbl)) indicated that 

55% of the condensate flashed when reduced in pressure from 200 pounds per square 

inch gauge (psig). Data for tank 25 was removed because the calculated flash emissions 

(215 lbs/bbl) indicated that 82% of the condensate flashed when reduced in pressure 

from 200 psig. According to API, neither of these flash emission values is possible at 

this separator pressure.6 Data for tank 26 was also removed from the dataset, as the 

recorded emissions (1,217.6 lbs/bbl) seem to indicate an equipment failure (such as a 

 7 Information in Appendix A of the study report indicates that, for the sites having production of two or less barrels

of condensate per day, condensate was stored in a single 300 BBL capacity tank. 300 BBL oil tanks typically come 

in 12 foot and 15.5 foot diameters, and have capacities of 1.68 bbl/inch and 2.8 bbl/inch, respectively.
2-5

separator dump valve stuck in the open position) or a measurement error as a 42 gallon 

barrel of condensate weighs approximately 270 pounds. An emission factor for each of 

the remaining 19 sites was calculated. Table 2-1 shows the emissions measurement data 

from the HARC 2006 study.

Table 2-1. Condensate Tank Emission Data from the HARC 2006 Study

Tank 

Battery County Region API Gravity

Separator 

Discharge 

Pressure 

(psi)

VOC 

(lbs/day)

Production 

(bbl/day)

VOC 

Emission 

Factor 

(lbs/bbl)

2 Montgomery Western Gulf 42 41 383.2 105 3.65

3 Montgomery Western Gulf 41 38 688.9 87 7.92

4 Montgomery Western Gulf 40 34 93.7 120 0.78

5 Montgomery Western Gulf 43 46 67.4 100 0.67

6 Montgomery Western Gulf 39 33 384.7 130 2.96

13 Denton Fort Worth 61 200 78.5 2 39.25

14 Denton Fort Worth 59 200 118 4 29.50

15 Denton Fort Worth 61 200 60 5 12.00

16 Denton Fort Worth 61 200 121.2 2 60.60

18 Denton Fort Worth 58 200 73.4 10 7.34

19 Denton Fort Worth 58 200 26.3 2 13.15

20 Denton Fort Worth 59 200 304.3 10 30.43

23 Parker Fort Worth 48 39 150.2 27 5.56

24 Parker Fort Worth 41 36 4.2 1 4.20

27 Denton Fort Worth 59 200 28.8 2 14.40

28 Brazoria Western Gulf 46 38 125.2 30 4.17

29 Brazoria Western Gulf 42 41 2,055 61 33.69

30 Brazoria Western Gulf 42 36 91.6 15 6.11

32 Galveston Western Gulf 48 121 9,016 142 63.49

The production-weighted average emission factor for these 19 condensate tanks is 

16.22 lbs/bbl, whereas the arithmetic average is 17.89 lbs/bbl. The production-weighted 

approach reduces the effect of measurement error (as noted in the API comments) on 

the emissions estimate, as the error attributable to measurement error from tanks with 

very low production has minimal ‘weight’ in the computation of the overall estimate. 

2.2.2 Comparisons of Emissions Data Derived from Testing with Emissions 

Estimates Derived from Models/Software Programs

There is only a small amount of data from testing available at present. Emission 

estimates derived through use of emissions estimation software utilizing equations-ofstate can provide useful information in developing regional emission factors. Therefore, 
2-6

emissions data estimated with software and models were used to supplement the 

existing testing data. 

This section examines two studies where researchers conducted emissions testing on

tanks and then generated emission estimates for those same tanks using models or 

software programs.

“Upstream Oil and Gas Storage Tank Project Flash Emissions Models Evaluation” 

(TCEQ, 2009) 

This 2009 study conducted by Hy-Bon Engineering for TCEQ compared actual 

measured emissions from 30 test sites to estimated emissions from those same sites. 

Emissions estimates were created using onsite data and several different emissions 

estimating models and software8

This report concludes that the calculated emissions using the E&P Tank – AP 42 model 

typically overestimated measured emissions in 85.7% of the cases, while the E&P Tank -

RVP model overestimated emissions for 82.1% of the cases. Calculated emissions using 

HYSYS Process Simulation software overestimated measured emissions in 64.3% of the 

cases. Therefore, it was assumed that emissions estimated using E&P Tank – AP 42, 

E&P Tank – RVP, or HYSYS may over-estimate emissions, and are conservative. This 

same study showed that the Gas/Oil Ratio (GOR) method in combination with Tanks 

4.09 underestimated flashing, breathing and working emissions in 76.7% of the cases. 

Therefore, any information obtained that utilizes the GOR method to estimate emissions 

will be, on average, an underestimate of the actual emissions. TCEQ has issued 

guidance

. At each test site, extensive data was taken on tanks 

and equipment, operating parameters, environmental conditions, and liquids 

production. Liquid and gas samples were taken for lab analysis and direct 

measurements were taken of vapors vented. The measured emissions from the 30 test 

sites were then compared to the estimated emissions from those same sites. 

9

There are eleven sites out of the thirty whose API gravity is less than 40 degrees, the 

lower bound for condensate in this study. Therefore, data from these eleven sites will 

stating that testing, the various process simulation software packages, E&P 

Tank, and GOR, in combination with site sampling and analysis, are the preferred 

methods for estimating flash emissions, in order of most preferred to least preferred.

 8 The emissions estimation methods used in this study include: E&P TANK 2.0, AspenTech HYSYS 2006.5, GRIHapCalc 3.0, the Environmental Consultant Research (EC/R) Algorithm, Vasquez-Beggs Correlation, Gas-Oil Ratio 

(GOR), and Valko-McCain Correlation. TANKS 4.09 was used to estimate breathing and working emissions for the 

GOR, Vasquez-Beggs, and Valko-McCain methods, which only calculate flash emissions. 9 “Calculating Volatile Organic Compounds (VOC) Flash Emissions from Crude Oil and Condensate Tanks at Oil 

and Gas Production Sites”, APDG 5942, May 2012, 

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/guidance_flashemission.pdf
2-7

not be considered. Emissions measurement data from the 19 remaining sites in this 

report are shown in Table 2-2.

The production-weighted average emission factor from testing for all of these sites is 

4.59 lbs/bbl of condensate, whereas the arithmetic average is 11.0 lbs/bbl. The emission 

measurement tests on these tanks were conducted during the months of July, August, 

and September.

Table 2-2. Operating Parameters, Production, and Measured Emissions

Site ID # County Region API Gravity 

(deg.)

Separator 

Pressure 

(psia)

Liquid 

Production 

(bbl/day)

VOC 

Emissions 

(ton/yr)

VOC 

Emission 

Factor 

(lbs/bbl)

WTB# 1 Ector Permian 43.7 83.82 976 1134.9 6.37

WTB# 4 Terrell Permian 50 88.82 34 12.6 2.03

WTB# 5 Terrell Permian 48.3 103.82 18 53 16.1

WTB# 11 Crane Permian 42.8 33.82 250 72 1.58

WTB# 15 Martin Permian 40.6 30.82 332 98.8 1.63

WTB# 17 Martin Permian 41.4 35.82 166 13.1 0.43

WTB# 19 Ector Permian 42.8 73.82 1979 1790 4.96

WTB# 23 Andrews Permian 43.3 53.82 327 93.5 1.57

NTB# 1 Ochiltree Anadarko 44.8 62.14 69 36.7 2.91

NTB# 2 Hansford Anadarko 45.3 48.44 74 8.3 0.62

NTB# 3 Hansford Anadarko 42.3 40.44 98 6.9 0.386

NTB# 5 Ochiltree Anadarko 67.5 44.44 50 154.8 17.0

NTB# 6 Denton Fort Worth 55.7 158.44 13 19.3 8.14

NTB# 7 Wise Fort Worth 58.6 161.44 34 38.1 6.14

NTB# 8 Wise Fort Worth 58.9 139.44 16 100.3 34.3

NTB# 9 Wise Fort Worth 55.2 167.44 12 38.6 17.6

NTB# 11 Wise Fort Worth 63.7 245.44 5 71.5 78.4

NTB# 12 Wise Fort Worth 63.7 239.44 14 14.8 5.79

NTB# 13 Wise Fort Worth 56.2 139.44 62 39.3 3.47

Table 2-3 shows the estimated emission factors for the 19 test sites using the methods 

preferred by TCEQ. The emissions factor based on measured emissions is also included 

for comparison purposes.
2-8

Table 2-3. Comparison of Estimated Emissions with Measured Emissions

Site ID # County

Liquid 

Production 

(bbl/day)

VOC Emission Factors (lbs/bbl)

Testing E&P TANK - 

AP 42 LPO

E&P TANK 

- RVP LPO HYSYS GOR + TANKS 4.09

WTB# 1 Ector 976 6.37 24.67 37.41 13.42 1.99

WTB# 4 Terrell 34 2.03 14.83 17.89 8.70 9.15

WTB# 5 Terrell 18 16.13 12.48 14.61 8.16 6.03

WTB# 11 Crane 250 1.58 8.90 19.66 8.97 0.48

WTB# 15 Martin 332 1.63 13.04 18.07 6.88 0.61

WTB# 17 Martin 166 0.43 20.76 35.35 15.72 0.86

WTB# 19 Ector 1979 4.96 30.52 55.26 22.69 4.51

WTB# 23 Andrews 327 1.57 46.60 55.48 42.44 1.79

NTB# 1 Ochiltree 69 2.91 9.69 26.13 11.91 1.23

NTB# 2 Hansford 74 0.62 9.70 17.92 7.26 0.32

NTB# 3 Hansford 98 0.39 12.52 26.50 4.98 1.59

NTB# 5 Ochiltree 50 16.96 53.81 59.84 4.71 13.63

NTB# 6 Denton 13 8.14 13.49 24.03 12.64 2.74

NTB# 7 Wise 34 6.14 8.22 17.57 1.77 1.43

NTB# 8 Wise 16 34.35 15.07 26.37 3.77 4.28

NTB# 9 Wise 12 17.63 37.44 72.60 4.57 27.03

NTB# 11 Wise 5 78.36 12.60 17.53 8.77 4.60

NTB# 12 Wise 14 5.79 18.79 24.27 2.74 9.00

NTB# 13 Wise 62 3.47 25.98 30.58 0.53 8.15

It is instructive to see how much the various emissions estimation methods overestimate or under-estimate emissions when compared to measured emissions values. 

This can help place the estimates generated via emissions estimation methods in context 

with the measured emissions, and give a sense of their value in estimating actual 

emissions from condensate tanks. Table 2-4 shows the ratio that the various estimation 

models over- or under- estimated emissions. The ratio is presented as (estimated 

emission/measured emission). A ratio of 1 indicates the estimate is in perfect 

agreement with the measurement, whereas a ratio of 10 indicates the estimated 

emission rate is ten times higher than the measured emission rate. A ratio of 0.5 

indicates the estimated emissions are half of the measured emissions, while a ratio of 0.1 

indicates the estimated emissions are 1/10th of the measured emissions. For simplicity, 

some values have been rounded.
2-9

Table 2-4. Ratio Between Estimated Emissions and Measured 

Emissions

Site ID #

Emission Factor 

From 

Measurement 

(lbs/bbl)

Ratio of Over Estimate or Under Estimate

E&P TANK - 

AP 42 LPO

E&P TANK -

RVP LPO HYSYS GOR + Tank 4.09

WTB# 1 6.37 4.0 6.0 2.0 0.3 

WTB# 4 2.03 7.0 9.0 4.3 4.5 

WTB# 5 16.13 0.8 0.9 0.5 0.4 

WTB# 11 1.58 5.6 12.5 5.7 0.3 

WTB# 15 1.63 8.0 11 4.0 0.4 

WTB# 17 0.43 48 82 36 2.0 

WTB# 19 4.96 6.0 11 4.6 0.9 

WTB# 23 1.57 30 35 27 1.1 

NTB# 1 2.91 3.3 9.0 4.0 0.4 

NTB# 2 0.62 16 29 12 0.5 

NTB# 3 0.39 32 69 13 4.0 

NTB# 5 16.96 3.0 3.5 0.3 0.8 

NTB# 6 8.14 1.7 3.0 1.6 0.3 

NTB# 7 6.14 1.3 3.0 0.3 0.2 

NTB# 8 34.35 0.4 0.8 0.1 0.1 

NTB# 9 17.63 2.0 4.0 0.3 1.5 

NTB# 11 78.36 0.2 0.2 0.1 0.1 

NTB# 12 5.79 3.0 4.0 0.5 1.6 

NTB# 13 3.47 7.5 9.0 0.2 2.3 

Average 9.5 15.9 6.1 1.1 

As can be seen in the table, the discrepancy between the estimated emissions and 

measured emissions is quite high. Only 18% of these estimates are within the range of 

half to twice (0.5 to 2) of the actual measured value. In this comparison, the emissions 

estimation models are shown to be inconsistent.

“Upstream Oil and Gas Tank Emission Measurements” (TCEQ, 2010)

This 2010 study conducted by TCEQ examined 7 gas wells/condensate tank sites in the 

Barnett Shale. This study compared actual measured emissions to estimated emissions 

using an emissions estimations model (E&P TANK). The research team collected 

extensive information on the equipment, operating parameters, production, and vented 

emissions. Vented emissions were measured with both a thermal mass flow meter and 

an ultrasonic flow meter. Samples of vent gas were collected and analyzed at two 

different labs. Production of water and condensate were measured. VOC emission rates 

and emission factors were calculated using this data. Liquid samples were collected 
2-10

from the pressurized separators and analyzed in a lab. The lab data on the pre-flash 

liquid composition and equipment operating parameter data were used as inputs to E&P 

TANK software, and emissions were estimated. 

This study is notable for its duplication of all critical measurements and analyses. 

However, only three of the wells produced condensate during the study period. One of 

those wells produced only one barrel of condensate, and this production was measured 

with manual gauging of two tanks of unknown size operating in parallel. The accuracy 

of this measurement could be subject to the same questions about measurement 

precision noted by API in their comments on the 2006 HARC study.10

In Table 2-5, the VOC emissions are calculated for the three tanks having condensate 

production. This table shows the emissions measured using the production data from 

the thermal mass flow meter and the ultrasonic flow meter. The emissions estimated 

using E&P TANK are also shown. 

The other four 

wells produced no condensate, but VOC emissions were measured from the associated 

produced water tanks at two of these sites. The study was conducted in July 2010, and 

the average ambient temperatures recorded on the sites ranged from 74.8 to 86.3 

degrees Fahrenheit.

If the emissions data from the three sites that produced condensate are averaged using a 

production-weighted average of the data from the two measurement methods, the 

average emission factor from both the measurement methods is 12.11 lbs VOC/bbl 

condensate, whereas the arithmetic average for these three sites from both the 

measurement methods is 17.52 lbs VOC/bbl condensate. In this study, the estimates of 

emissions produced with the E&P TANK model varied significantly from the values for 

actual measured emissions.

2.2.3 Emissions Estimates Derived Solely from Models/Software Programs

This section examines a study which provided a set of emission estimates that were 

generated using only models or software programs.

“Control of VOC Flash Emissions from Oil and Condensate Storage Tanks in East 

Texas” (TCEQ, 2010) 

This 2010 study conducted by TCEQ assessed the impact of Title 30 Texas 

Administrative Code 115.112(d)(5) on the implementation of VOC control devices on oil 

and condensate tanks in the Houston-Galveston-Brazoria (HGB) ozone nonattainment 

area. In this study, producers in the target areas were surveyed to assess the number of 

 10 American Petroleum Institute, API Comments on the Proposed Rulemaking – Oil and Gas Sector Regulations, 

November 30, 2011, http://www.api.org/Newsroom/testimony/upload/2011-11-30-API-Oil-and-Gas-Rule-FinalComments-Text.pdf
2-11

Table 2-5. Condensate Tank Emission Factors from the TCEQ 2010 Study

Tank 

Battery County Region API Gravity 

Separator 

Pressure (psi) 

Production 

(bbl/day)

Measured with Thermal 

Mass Flow Meter

Measured with Ultrasonic 

Mass Flow Meter

Estimated 

with E&P 

TANK

VOC 

Emissions 

(lbs/day) 

VOC 

Emission 

Factor 

(lbs/bbl)

VOC 

Emissions 

(lbs/day) 

VOC 

Emission 

Factor 

(lbs/bbl)

VOC 

Emission 

Factor 

(lbs/bbl)

Gage Pitts Wise Fort 

Worth 61.2 171 58.5 717.9 12.3 639.9 10.9 11.5

Waggoner 

Crystelle Wise Fort 

Worth 61.2 119 3.34 12.7 3.8 105.3 31.5 7.6

First Baptist 

Church 

Slidell No.1

Wise Fort 

Worth 51 NR 1 11.3 11.3 35.3 35.3 0.7
2-12

tanks that were controlled and the type of controls installed. Although this report does 

not include any new emissions measurements, it is valuable as it contains E&P TANK

and HYSYS reports for 21 condensate batteries in the Haynesville Shale area. One 

company provided a summary of VOC emissions calculated using E&P TANK run with 

site-specific sampling inputs for 13 condensate tank batteries in the Haynesville Shale 

area. 

Another company provided emissions estimated using the HYSYS Version 2006.5 

process simulator for eight natural gas condensate tank batteries in the Haynesville 

Shale. These estimates are shown in Table 2-6. As no production figures were given, a 

production-weighted average cannot be calculated. The arithmetic average is 5.80 lbs

VOC/ bbl condensate.

Table 2-6. Producer-Supplied VOC Emission Estimates for Condensate Tank 

Batteries in Haynesville Shale Area

Site 

Number Region

Separator 

Pressure 

(psig)

Separator 

Temperature 

(°F)

API Gravity @ 

60°F

Estimation 

Model

VOC 

Emissions 

(lbs/bbl)

1

Haynesville 

Shale 

45 80 50.6 E&P TANK 2.67

2 40 80 49.6 E&P TANK 8.45

3 25 86 54.2 E&P TANK 5.38

4 95 89 55.4 E&P TANK 1.67

5 16 97 59.5 E&P TANK 1.09

6 30 70 55.3 E&P TANK 1.45

7 60 78 64.6 E&P TANK 8.91

8 120 89 55.0 E&P TANK 10.24

9 95 80 55.0 E&P TANK 11.97

10 60 75 52.4 E&P TANK 4.62

11 80 72 57.0 E&P TANK 3.98

12 120 85 55.0 E&P TANK 11.97

13 60 77 53.8 E&P TANK 3.49

14 40 85 N/A HYSYS 1.16

15 108 98 N/A HYSYS 0.31

16 752 82 N/A HYSYS 15.84

17 76 90 N/A HYSYS 0.32

18 110 80 N/A HYSYS 0.85

19 690 70 N/A HYSYS 14.79

20 560 98 N/A HYSYS 0.73

21 230 90 N/A HYSYS 11.83

Average 5.80

2.2.4 Other Studies

The following study was evaluated for its utility in contributing estimates for the 

regional emission factors being developed in this study.
2-13

“Recommendations for Improvements to the CENRAP State’s Oils and Gas Emissions 

Inventories” (Central Regional Air Planning Association (CENRAP), 2008)

This report contains emission factors for flashing, working, and breathing emissions for 

condensate tanks in the Anadarko basin. The CENRAP 2008 report states that this 

emission factor (13.86 lbs VOC/bbl) was obtained from the Independent Petroleum 

Association of Mountain States (IPAMS)/Western Regional Air Partnership (WRAP)

Phase III work (Bar-Ilan, et al, 2008). The IPAMS/WRAP Phase III report states that 

the emission factors were derived from producer surveys conducted in 2008, but this 

information and the emission factor could not be verified. The CENRAP 2008 report 

also contains an emission factor for flashing, working, and breathing emissions from 

condensate tanks in the East Texas, Western Gulf, Fort Worth, and Permian basins. 

However, as this emission factor (33.3 lbs VOC/bbl) was taken from the HARC H051C 

study, it will not be used. Therefore, the emission factors from the CENRAP 2008 

report will not be used.

2.3 Emission Factor Development Using the Barnett Shale Area Special 

Inventory, Phase II (2009)

TCEQ provided ERG with data from the “Barnett Shale Area Special Inventory, Phase II 

2009” (Barnett Shale Inventory) information in spreadsheet format. The Barnett Shale 

Inventory data contains 2,268 records with reported condensate production rates and 

calculated VOC emissions. The VOC emissions were estimated using a variety of 

methods, including direct measurement of tank emissions, test data, and flash emission 

and working and breathing emissions models. ERG analyzed this data and developed 

emission factors for condensate tanks in the Bend-Arch-Fort Worth and Barnett Shale 

counties. 

The original data from 4 separate spreadsheet pages was uploaded into an Access 

database so that data for individual facilities could be joined into one record. The data 

was then downloaded back into Excel for analysis. Records were sorted to remove: all 

records using non-preferred emission estimations methods (Vasquez-Beggs equation, 

derived emission factors, and HARC H051C emission factor), all records where 

condensate tank emissions were equal to zero, and all records where annual throughput 

of condensate was equal to zero. Individual records were examined for internal 

consistency, and were rejected if the recorded site values for annual throughput were 

not equal to condensate production. Emission factors were calculated using the values 

for emissions and throughput. All records with emission factors above 140 lbs/bbl were 

rejected, as it was deemed that emissions above 50% of the weight of produced 

condensate were indicative of equipment malfunction or an error in the data, estimating 

method, or record. The records were then sorted by estimation method. Records in 

which the estimation method was not noted were not analyzed, as these records lacked 
2-14

critical information for determining their usefulness and accuracy. Both a productionweighted average and an arithmetic average emission factor, before controls, were

calculated for each of the emission estimation methods. The percent of total production 

that is reported in the special inventory as controlled was also calculated. The results 

are presented in Table 2-7. 

The production-weighted average of the emission factors developed using the estimation 

methods preferred by TCEQ is 6.77 lbs/bbl, before the effect of controls. The arithmetic 

average of the emission factors developed using the estimation methods preferred by 

TCEQ is 12.95 lbs/bbl, before the effect of controls. As discussed in the report 

“Upstream Oil and Gas Storage Tank Project Flash Emissions Models Evaluation”, the 

E&P TANK and the Process Simulator models tended to produce higher emission 

estimates, while the GOR method produced lower estimates. This is reflected in the 

Barnett Shale Inventory data; the emission estimates generated with E&P TANK (6.58, 

6.71, and 10.13 lbs/bbl) and process simulator models (7.51 lbs/bbl) are generally, but 

not always, higher than the emission estimates generated using the GOR method (3.96 

and 8.12 lbs/bbl). 

Table 2-7. Condensate Tank VOC Emission Factors by Method – Barnett Shale 

Inventory

Flash Emission 

Calculation 

Method

Working and 

Breathing 

Emission 

Calculation 

Method

Total 

Production 

(bbl)

Number 

of Sources 

(Count)

ProductionWeighted 

Emission 

Factor 

(lbs/bbl)

Arithmetic 

Average 

Emission Factor 

(lbs/bbl)

% of 

Production 

Controlled

Process 

Simulator 

Models

EPA TANKS 

Program 62,112 32 7.51 10.8 0%

E&P TANK Other: 112,651 142 6.58 23.3 7.7%

E&P TANK EPA TANKS 

Program 94,544 29 6.71 13.5 15.2%

E&P TANK E&P TANK 947,655 918 10.13 12.9 0.26%

GOR Method EPA TANKS 

Program 74,652 36 8.12 9.60 6.71%

GOR Method E&P TANK 1,175,194 407 3.96 9.87 25.8%

Direct 

Measurement 

of Emissions

Other: 12,601 11 7.82 13.3 0%

Preferred 

Methods Totals 2,479,409 1,575 6.77 12.95 13.5%
2-15

One survey respondent indicated that they used direct measurement to estimate 

emissions, but, since no other details were given, these data points were treated as being 

calculated by a preferred method.

The Barnett Shale Inventory data was also sorted by county, and emission factors for 

condensate tanks were developed at the county level. The data analysis was similar to 

that done for the entire Barnett Shale region. Emission factors were created using the 

values for emissions and throughput. The records were then sorted by estimation 

method, and only records using the preferred estimation methods for flashing emissions 

(direct measurement, process simulator, E&P Tank, GOR) were analyzed. Records in 

which the estimation method was unknown were not analyzed. Records were then

sorted by county. A production-weighted average emission factor, and an arithmetic 

average of the emission factors, before controls, was calculated for each of the counties. 

The results are presented in Table 2-8. 

Table 2-8. Condensate Tank VOC Emission Factors by County – Barnett Shale 

Inventory

Emission 

Calculation 

Methods

County

Total 

Production 

(bbl)

Number 

of 

Sources 

(Count)

ProductionWeighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

% of 

Production 

Controlled

Flash Emissions: 

Process 

Simulator 

Models, E&P 

Tank, Direct 

Measurement, 

GOR

Working and 

Breathing 

Emissions: E&P 

Tank, EPA 

TANKS Program, 

Other

Clay 6,404 3 3.83 7.10 0.0%

Cooke 155,352 41 4.15 4.53 35.7%

Denton 180,295 226 9.51 13.98 2.6%

Erath 35,520 72 16.88 18.75 0.0%

Hood 199,738 183 7.70 12.10 1.9%

Jack 62,590 40 4.86 8.57 0.0%

Johnson 62,207 71 9.77 16.74 3.5%

Montague 588,385 135 3.55 5.39 42.1%

Palo Pinto 333,620 53 2.25 5.14 0.2%

Parker 164,973 231 10.70 13.58 5.6%

Somervell 6,753 23 10.24 16.50 0.0%

Stephens 4,156 4 3.96 3.96 0.0%

Tarrant 42,517 81 11.09 12.39 6.0%

Wise 636,347 411 9.75 15.58 0%

For certain counties, sufficient data may be available to develop a county-specific 

emission factor based only on the data available for that particular county. However, a 

careful examination of these county-specific emission factors (see Attachment C) shows 

that they vary widely within any one region. This may be indicative of the variation in 

properties of the condensate produced, or it may be due to an inadequate sample size. 

Due to the variation observed in the county-specific factors and the uncertainties 

associated with these factors, the regional emission factors presented in Table 2-15 (see 
2-16

discussion below) are recommended for developing the state-wide area source 

inventory.

2.4 Phone Survey of Area Sources

ERG attempted to contact 54 producers operating in the six regions of interest and 

request condensate tank emissions data. The companies selected were identified by a 

search of the RRC website11 as major producers of condensate in the six regions of 

interest for the survey. The six regions of interest were the Anadarko, East Texas, 

Permian, and Western Gulf basins and the Haynesville and Eagle Ford shales. Table 2-9

and Figure 2-2 show the counties within each of the regions that were targeted. These 

counties were chosen due to their high condensate production relative to all of the 

counties in that region.12

Table 2-9. Target Survey Counties

 

Anadarko Permian East Texas Western Gulf Eagle Ford 

Shale

Haynesville 

Shale

Hemphill, 

Lipscomb, 

Ochiltree, 

Roberts, and 

Wheeler

Crane, Crockett, 

Loving, 

Midland, Pecos, 

Upton, and 

Ward

Anderson, Cass, 

Cherokee, 

Franklin, 

Freestone, 

Henderson, 

Houston, 

Limestone, 

Navarro, Smith, 

and Upshur 

Brazoria, Brooks, 

Galveston, Hardin, 

Harris, Hidalgo, 

Jasper, Jefferson, 

Liberty, Matagorda, 

Newton, Nueces, 

Orange, Polk, San 

Jacinto, San Patricio, 

Starr, Tyler, and 

Wharton

DeWitt, 

Dimmit, 

Fayette, 

Karnes, 

LaSalle, 

Lavaca, Leon, 

Live Oak, 

McMullen, 

and Webb 

Gregg, Harrison, 

Marion, 

Nacogdoches, 

Panola, Rusk, 

San Augustine, 

and Shelby

 11 Railroad Commission of Texas, Statewide Production data Query System, 

http://www.rrc.state.tx.us/data/online/index.php

12 Condensate production data at the county level was mapped in ARC GIS, and the top-producing counties in each 

region were identified. The RRC database was then queried for operators of gas wells in these top-producing 

counties in each region. Operator production data was compiled for each region and the top producers were 

identified. These companies were contacted.
2-17

Figure 2-2. Target Survey Counties

The Bend Arch-Fort Worth basin and Barnett Shale were not surveyed, as adequate data 

on condensate tank emissions had already been gathered during the Barnett Shale Area 

Special Inventory.13

Letters were sent to a total of 61 regional offices at 54 separate companies. Letters were 

sent to 116 contacts at these companies explaining the survey and requesting 

cooperation in gathering data. The letter requested data on county, separator pressure, 

API gravity, 2011 condensate production, 2011 VOC emissions, emissions estimation 

method, control technology, and control efficiency. This letter is shown in 

 As the survey progressed, it became apparent that much of the 

condensate produced in the counties designated as Haynesville Shale was actually being 

produced from another petroleum formation (Cotton Valley Group) located in the same 

counties as the Haynesville Shale. Therefore, for purposes of calculating emissions, the 

East Texas and Haynesville Shale regions were merged into one region.

 13 Texas Commission on Environmental Quality (TCEQ), Barnett Shale Area Special Inventory, Phase Two, 

http://www.tceq.texas.gov/airquality/point-source-ei/psei.html#barnett2
2-18

Attachment A. The initial contact list was obtained from RigData© as it provided the 

names of people involved in the production (drilling) operation for the respective 

companies. In most cases, each contact was called 3 or 4 times in order to get a referral 

to someone in the environmental department of the company. Once phone contact was 

made with a person in a position to provide the requested information, ERG explained 

the purpose of the survey and requested participation. ERG obtained email addresses 

and sent survey materials via email directly to the contact person. The survey materials 

explained the background and purpose of the survey in greater detail, asked for the 

voluntary participation of the company, and stated that information would be held 

confidential. Since many of the companies surveyed only had production in one or two 

regions, the survey materials were tailored for each company to provide a specific and 

detailed listing of the region(s) and counties of interest. These materials included a 

Word document with a table for reporting the data, and an Excel spreadsheet with 

individual tabs for reporting data from each of the regions. The intent with providing 

these user-friendly survey materials was to make response as easy as possible and also 

to gather the data in a format that could be easily copied into spreadsheets for data 

analysis. These survey materials are shown in Attachment B. Once survey materials 

had been sent, a follow-up phone call was made a week later to ask if there were any 

questions and to determine if the company was willing to participate in the survey. 

Active survey outreach efforts spanned a six-week period, and included sending the 

initial contact letters, calling sources to establish contact, sending follow-up letters to 

the proper contact as needed, making follow-up phone calls, sending emails with survey 

materials, and making phone calls/sending emails to determine if companies would be 

willing to participate. Fifteen companies participated in the survey, providing

information on more than 251 separate wells/tanks. 

2.4.1 Analysis of Data Collected via Phone Survey

Fifteen companies responded to the survey, and provided data from more than 

251 separate wells/tank batteries. One company sent data for nine representative wells 

that represented production from 140 separate wells. Other companies sent data for a 

few sites that were representative of their other wells in that region. 

Certain data received in the survey were not used in the analysis. One company 

provided data for ten wells but no estimates of VOC emissions, and several companies 

sent data for wells with API gravity less than 40 degrees. Several companies also 

provided data for wells with a final separator pressure less than 5 psig; this data was not 

used in the calculations as these low separator pressures are more indicative of wells 

producing oil and were not consistent with the separator pressures observed in the 

survey results for the primary condensate producing regions in Texas. Finally, the 

emissions data generated using non-preferred methods was not included in the analysis. 
2-19

The raw data collected in the ERG survey, along with notes on which data was excluded 

from the analysis, is provided in Attachment C. 

Data was collected from a sufficient number of tank batteries in each target region. ERG

developed a region-wide emission factor for each of the five gas-producing regions 

targeted in the phone survey. This data was sorted by region. Emission factors were 

calculated for each of the regions. The survey also requested information on any 

recovery or control methods used at each well. A very high percentage of respondents 

indicated that they used recovery or control methods on their wells/tanks. For purposes 

of comparing the survey results with the test results and emission estimates from earlier 

studies, emission factors for the emissions before the effect of any controls were 

calculated.

The producers who responded to this survey used a variety of calculation models 

(testing, E&P Tank, ProMax, WinSim, VMGSim, HYSYS, GOR, and Vasquez Beggs) for 

estimating flash emissions. ERG examined these results in light of the evaluation of the 

accuracy of these models presented in “Upstream Oil and Gas Storage Tank Project 

Flash Emissions Models Evaluation” (TCEQ, 2009)14 and TCEQ’s guidance on 

calculating flash emissions15

Table 2-10 summarizes the findings from the survey. The data show a clear difference in 

the emission factors by region.

. ERG used only records where the flash emissions 

calculation method was one of the methods preferred by TCEQ. One producer sent test 

results for three tanks. Since only the results and no underlying data or test reports 

were submitted, these three data points were treated as being calculated by a preferred 

method.

Table 2-10. Survey Results Using all Valid Survey Data Estimated with 

Preferred Estimation Methods

Region

Total Production 

Represented in 

Survey (bbl)

Data 

Points

ProductionWeighted VOC 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average VOC 

Emission 

Factor 

(lbs/bbl)

Percent of 

Surveyed 

Production 

Controlled

Anadarko 533,419 18 1.63 7.47 99.4%

Eagle Ford 10,538,273 41 11.3 9.41 92.2%

 14 Texas Commission on Environmental Quality, Upstream Oil and Gas Storage Tank Project Flash Emissions 

Models Evaluation, 2009, 

http://www.tceq.texas.gov/assets/public/implementation/air/am/contracts/reports/ei/20090716-ergiUpstreamOilGasTankEIModels.pdf

15 “Calculating Volatile Organic Compounds (VOC) Flash Emissions from Crude Oil and Condensate Tanks at Oil 

and Gas Production Sites”, APDG 5942, May 2012, 

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/guidance_flashemission.pdf
2-20

Table 2-10. Survey Results Using all Valid Survey Data Estimated with 

Preferred Estimation Methods

Region

Total Production 

Represented in 

Survey (bbl)

Data 

Points

ProductionWeighted VOC 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average VOC 

Emission 

Factor 

(lbs/bbl)

Percent of 

Surveyed 

Production 

Controlled

East Texas 518,691 83 5.91 5.75 82.1%

Permian 245,545 5 10.75 8.13 79.5%

Western Gulf 182,349 28 1.84 5.32 46.5%

2.4.2 Use of Vapor Recovery and Controls to Reduce Emissions

The ERG survey data indicates that companies are installing vapor recovery units (VRU) 

or control devices (flares or combustors) on their highest producing wells. VRUs may be 

installed for economic reasons as any vapor recovery equipment installed on a highproducing well will deliver a higher return of saleable product per dollar invested in 

equipment. Similarly, for companies using flares or combustors to control emissions, 

these control devices are being used on the highest-producing wells. 

Survey data indicated that surveyed companies have installed vapor recovery or control 

devices on 34% of their wells/tanks, representing 91.1% of their total production. The 

data indicate that the emissions before controls for nearly all of the wells/tanks that had 

recovery devices or controls installed is greater than 25 tons per year of VOC. Producers 

reported that emissions from 5.7% of surveyed production were recovered with VRUs, 

and emissions from 85.4% of surveyed production were controlled with flares or 

combustors, and the average percent reduction was 97.6%.

This level of control is much higher than the results reported in the 2010 TCEQ study 

“Control of VOC Flash Emissions from Oil and Condensate Storage Tanks in East 

Texas”, in which survey respondents reported that 72% of surveyed production in the 

Beaumont-Port Arthur (BPA) counties were controlled, 25% of surveyed production in 

the HGB area were controlled, and 9% of surveyed production in the Haynesville Shale 

counties were controlled. The survey data also shows a much higher percentage of 

control than was observed in the Barnett Shale Area Special Inventory, where 13.2% of 

total surveyed production was reported as recovered or controlled.16

 16 These data are shown in Table 17 of this report.

This may be due to 

the differences in production in the Barnett Shale and Haynesville Shale versus the 

other regions of Texas. The Barnett Shale and Haynesville Shale both produce a ‘dry’ 

gas, with limited condensate production. Therefore, it may not have been economically 
2-21

feasible or necessary from a regulatory standpoint at the time this survey was taken to 

control the emissions from the condensate tanks in the Barnett and Haynesville Shale.

The higher level of control observed in the ERG survey may also be due to the increasing 

awareness and implementation of recovery and control technologies over time, and the 

effect of new regulations. The Barnett Shale Inventory and the TCEQ surveys were 

conducted in 2009, whereas the ERG survey was conducted in 2012 and covers 

production and emissions in 2011. Title 30 Texas Administrative Code 106.352, Permit 

by Rule for Oil and Gas Handling and Production Facilities17

2.4.3 Self-Selection Bias

, became effective on 

February 2, 2012, which may account for the higher control percentages observed 

during this survey.

For any survey, the researchers need to consider if the respondents have given them 

data that is representative of all of their operations. ERG specifically requested in the 

survey materials and phone conversations that companies submit a random, 

representative sampling of their wells. ERG has no direct knowledge that any of the 

companies who responded to this survey biased the data that they submitted. However, 

the percent of surveyed production with emissions being recovered or controlled (91.1%) 

is very high when compared to the results obtained from the Barnett Shale Area Special 

Inventory and other studies. In reviewing the differences in the percentage of 

production that was reported as recovered or controlled in the ERG survey, versus the 

amount that was reported as controlled in the Barnett Shale Area Special Inventory, it 

must be noted that the results of the ERG survey were obtained voluntarily, whereas the 

Barnett Shale Area Special Inventory was a mandatory survey of all producers operating 

in that region. ERG collected survey data from 15 large and medium sized companies. A 

significant portion of the larger companies operate the highest producing wells in many 

regions. Also, larger companies may have the capital to purchase and install control

devices, and may also have more resources to respond to surveys.

2.4.4 Innovative Practices that Lower Area Emissions

Two innovative practices in use that have the effect of lowering emissions were 

identified as part of the survey. During initial phone conversations, two companies 

declared that they had no tank emissions at upstream sites (well pads) because they no 

longer routinely used tanks in the field for their day to day operations. While these 

companies would install a portable liquids tank during the initial phase of well 

completion, the tank would soon be replaced with piping that collected all gas and 

condensate from multiple wells in an area and route them to a single gathering station. 

All gas and liquids would be processed at that station, which utilized vapor recovery and 

 17 Texas Commission on Environmental Quality, Rules, http://www.tceq.state.tx.us/rules/indxpdf.html
2-22

control equipment such that condensate tank emissions were negligible. This company 

replaced the traditional tank at the well site with piping and a centralized processing 

facility.

Another company submitted data with very low emission factors, despite the fact that 

tank emissions were uncontrolled. When questioned, the company official stated that 

the emissions factors were low as a result of their operating practices. This company 

captures as much flash gas as possible and has designed their facilities such that when 

liquids reach the tanks the pressure has been released to 2 psi [above ambient] allowing 

flash gas in the liquids to be released prior to the tank, captured by a vapor recovery 

system, and sent to the gas pipeline. This company also routes the vapors from their 

storage tanks to a flare. Finally, the emissions from the trucks loading liquids from the 

field tanks is sent back to the storage tank with vapor balance piping and routed to the 

flare. 

Both of these practices lower the emissions from storage tanks substantially, as they 

recover or control nearly 100% of the VOC that would normally be emitted in an 

uncontrolled operation. Ultimately, these potential survey participants did not provide 

data as part of this survey as they had no upstream tanks and no tank emissions. 

2.5 Weighting the Data

2.5.1 Weighting Data based on Method

This study compiled emissions data produced by both testing and emissions estimation 

methods, with the data coming from four published studies, one TCEQ inventory, and 

the survey associated with this report. All of this data was evaluated for its accuracy and 

relative merit in compiling regional and county-specific emission factors. TCEQ’s 

guidance “Calculating Volatile Organic Compounds (VOC) Flash Emissions from Crude 

Oil and Condensate Tanks at Oil and Gas Production Sites”18

Table 2-11 shows the weighting factors applied to each estimation method.

was used as the basis for 

weighting the data obtained from testing and the various emissions estimation methods. 

Data obtained from testing is considered the most accurate source of emissions data, 

and is weighted the highest. Emissions estimates produced through use of process 

simulation models, E&P TANK, and the Gas-Oil-Ratio method are weighted in 

decreasing order of preference, consistent with the TCEQ guidance.

 18 “Calculating Volatile Organic Compounds (VOC) Flash Emissions from Crude Oil and Condensate Tanks at Oil 

and Gas Production Sites”, APDG 5942, May 2012, 

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/guidance_flashemission.pdf
2-23

Table 2-11. Weighting Factors by Emissions Estimation 

Method

Emissions Estimation Method Weight

Testing 4

Process Simulator (HYSIM, HYSIS, VMG, PROMAX) 2

E&P TANK 1.5

Gas-Oil-Ratio 1

The equation used to derive the regional emission factors is shown below:

Regional Emission Factor (lbs/bbl)Region i = [(EF Region i TESTING × 4) + (EF Region i PROCESS 

SIMULATOR × 2) + (EF Region i E&P TANK × 1.5) + (EF Region i GAS-OIL-RATIO × 1)]/(4+2+1.5+1)

(Eq. 2-1)

Where:

EF Region i TESTING = emission factor for the region based on testing 

(lbs/bbl)

EF Region i PROCESS SIMULATOR = emission factor for the region based on process 

simulator (lbs/bbl)

EF Region i E&P TANK = emission factor for the region based on E&P Tank 

(lbs/bbl)

EF Region i GAS-OIL-RATIO = emission factor for the region based on the GOR 

method (lbs/bbl)

2.5.2 Weighting Data based on Production

In addition to the method weighting discussed above, a production weighted average

was used to assess the average emission rate for the wells/tanks in each particular 

county or region. This approach more accurately reflects the overall total emissions in a 

region containing a mix of high and low production sites and is appropriate for area 

source emissions estimation. 

For example, if a region contains ten well sites, and there are 5 sites each producing 

2 barrels of condensate per day and having measured emissions of 40 lbs/ bbl, and there 

are another 5 sites each producing 130 barrels per day and having measured emissions 

of 4 lbs/bbl, by using a production-weighted approach, the average emissions from 

these 10 wells/tanks is:

(5 × 2 × 40 + 5 × 130 × 4)/(5 × 2 + 5 × 130) = 4.55 lbs VOC/bbl
2-24

The straight arithmetic average for these sites is 22 lbs/bbl. The actual total VOC 

emissions from the ten sites in this region are 3,000 pounds per day, and the total 

production from the ten sites in the region is 660 barrels. On a region-wide basis, the 

actual emissions are 3,000/660 = 4.55 lbs/bbl.

A scatter plot of the data points compiled in this report provides a useful visual 

depiction of the relationship between emissions on a per barrel basis and production at 

a given well. Figure 2-3 shows the production for each tank on the x-axis and the VOC 

emission factor for each tank on the y-axis. The data show a clear relationship between 

low production and high per-barrel emission factors, yet most of the production in any 

region comes from the wells with high production, which typically have lower per barrel 

emission factors.

Figure 2-3. Relationship between Production and Emission Factor

2.6 Regional Emission Factors

A two-step process was used in compiling the emissions data into regional emission 

factors for VOC and HAP. First, data was separated into subgroups by region. 

Subsequently, data records from each regional subgroup were separated into categories 

by the estimation method used (testing, process simulator, E&P Tank, GOR). A 

production weighted average emission factor was calculated for each subgroup for each 

region. The production-weighted average emission factors for each region were then 

combined into a single regional emission factor using the weighting factors shown in 

Table 2-11 as described above.
2-25

The compiled results of the testing data and estimates from the studies and surveys are 

shown in the Tables 2-12 through 2-16. Table 2-12 shows the compiled average of 

emission factors derived from testing. The test results are grouped by region, and a 

production-weighted average and arithmetic average is calculated for each region. 

These emission factors show the emissions before the effect of any controls.

Table 2-12. Average Regional VOC Emission Factors Derived from Testing 

Data

Studies Region Count of 

Data Points

Production-Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic Average 

Emission Factor

(lbs/bbl)

Flasha Anadarko 4 3.89 5.22

HARC 51C, Flasha, 

Upstreamb Fort Worth 23 12.26 20.67

Flasha Permian 8 4.39 4.34

HARC 51C Western Gulf 9 16.34 13.72

a Upstream Oil & Gas Storage Tank Project Flash Emissions Models Evaluation (2009). b Upstream Oil & Gas Tank Emissions Measurement (2010).

Table 2-13 shows the compiled emission factors derived from the three studies 

referenced in this report. These emission factors (all based on E&P TANK, process 

simulation models, or GOR data) are grouped by region, and a production-weighted 

average and arithmetic average is calculated for each region. The averages for each 

region were developed using the weighting factors in Table 2-11. These emission factors 

show the emissions before the effect of any controls. 

Table 2-13. Average Regional VOC Emission Factors Derived from Estimation 

Methods

Studies Region Count of 

Data Points

Production-Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic Average 

Emission Factor

(lbs/bbl)

Flasha Anadarko 4 14.65 16.36

Control of VOC Flash 

Emissionsb East Texas 21 5.78 5.78

Upstreamc, Flasha Fort Worth 10 13.69 12.89

Flasha Permian 8 23.51 18.06 a Upstream Oil & Gas Storage Tank Project Flash Emissions Models Evaluation (2009). b Control of VOC Flash Emissions from Oil and Condensate Storage Tanks in East Texas (2010). c Upstream Oil & Gas Tank Emissions Measurement (2010).

Table 2-14 shows the compiled average emission factors derived from the ERG 2012 

survey responses and the 2009 Barnett Shale Special Area Inventory. In these surveys, 

producers used direct measurement and estimation methods (E&P TANK, process 

simulation models, GOR) to estimate emissions from their condensate tanks. However, 
2-26

for the testing data, only the test results and no underlying data or test reports were 

submitted. Therefore, the testing data were treated as being calculated by a preferred 

method and given a weight of 1.5 instead of 4.

These emission estimates are grouped by region, and a production-weighted average 

and arithmetic average is calculated for each region. The averages for each region were 

weighted according to the weighting factors in Table 2-11. These emission factors show 

the emissions before the effect of any controls. 

Table 2-14. Average Regional VOC Emission Factors from ERG Survey 

Data and Barnett Shale Inventory Data

Survey Region Count of 

Data Points

ProductionWeighted Emission 

Factor 

(lbs/bbl)

Arithmetic Average 

Emission Factor 

(lbs/bbl)

ERG 2012 survey Anadarko 18 2.49 6.45

ERG 2012 survey Eagle Ford 41 10.5 10.0

ERG 2012 survey East Texas 83 3.51 6.22

ERG 2012 survey Permian 5 6.25 6.08

ERG 2012 survey Western Gulf 28 4.95 16.1

Barnett Shale 

Inventory Fort Worth 1,575 7.54 12.2

Table 2-15 shows the compiled average emission factors when the data from the testing 

results (Table 2-12), studies (Table 2-13), and the ERG 2012 and Barnett Shale surveys 

(Table 2-14) is combined. The testing and emission estimate data is grouped by region, 

and a production-weighted average and an arithmetic average is determined for each 

region. The production-weighted average and arithmetic average for each region were 

weighted according to the weighting factors in Table 2-11. As there are no data available 

for the Palo Duro Basin and the Marathon Thrust Belt, a statewide average is used for 

these two regions. These emission factors show the emissions before the effect of any 

controls. 

Table 2-15. Average Regional VOC Emission Factors

Region Count of Data 

Points

Production-Weighted Emission 

Factor 

(lb/bbl)

Arithmetic Average 

Emission Factor 

(lb/bbl)

Anadarko 26 3.15 5.87

Eagle Ford Shale 41 10.5 10.0

East Texas/Haynesville Shale 104 4.22 5.92

Fort Worth/Barnett Shale 1,604 9.76 16.0

Permian 21 7.07 5.90
2-27

Table 2-15. Average Regional VOC Emission Factors

Region Count of Data 

Points

Production-Weighted Emission 

Factor 

(lb/bbl)

Arithmetic Average 

Emission Factor 

(lb/bbl)

Western Gulf 37 11.0 14.8

Palo Duroa N/A 7.61 9.75

Marathon Thrust Belta N/A 7.61 9.75 a Statewide average.

Figure 2-4 provides the geographical distribution of the data sources used to compile 

the regional emission factors in Table 2-15 on a county-basis. 

Figure 2-4. Condensate Tank Emission Data Sources by County
2-28

Figure 2-5 shows the results from Table 2-15 geographically. Determination of which 

counties are included in each region is from the United States Geological Survey.19

Counties in the Eagle Ford Shale were identified by the RRC.20

Figure 2-5. Average Regional Emission Factors, Before Controls

 For certain counties, 

there was sufficient data available to develop a county-specific emission factor based 

only on the data available for that particular county. However, a careful examination of 

these county-specific emission factors (see Attachment C) shows that they vary widely 

within any one region. This may be indicative of the variation in properties of the 

condensate produced, or it may be due to an inadequate sample size. Due to the 

variation observed in the county-specific factors and the uncertainties associated with 

these factors, the regional emission factors presented in Table 2-15 are recommended 

for developing the state-wide area source inventory.

 19 United States Geological Survey, National Oil and Gas Assessment, 

http://energy.usgs.gov/OilGas/AssessmentsData/NationalOilGasAssessment.aspx

20 Texas Railroad Commission, Eagle Ford Information, http://www.rrc.state.tx.us/eagleford/
2-29

The region-specific condensate tank emission factors can then be assigned on a county 

basis by allocating each county in the state to one of the regions identified in Table 2-15. 

The county-level VOC emission factor (both production weighted and arithmetic 

average) for each county in Texas is shown in Table 2-16.

Table 2-16. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Anderson East Texas/Haynesville Shale 4.22 5.92

Andrews Permian 7.07 5.90

Angelina East Texas/Haynesville Shale 4.22 5.92

Aransas Western Gulf 11.0 14.8

Archer Fort Worth/Barnett Shale 9.76 16.0

Armstrong Palo Duro 7.61 9.75

Atascosa Eagle Ford Shale 10.5 10.0

Austin Western Gulf 11.0 14.8

Bailey Palo Duro 7.61 9.75

Bandera Fort Worth/Barnett Shale 9.76 16.0

Bastrop Western Gulf 11.0 14.8

Baylor Fort Worth/Barnett Shale 9.76 16.0

Bee Eagle Ford Shale 10.5 10.0

Bell Western Gulf 11.0 14.8

Bexar Western Gulf 11.0 14.8

Blanco Fort Worth/Barnett Shale 9.76 16.0

Borden Permian 7.07 5.90

Bosque Fort Worth/Barnett Shale 9.76 16.0

Bowie East Texas/Haynesville Shale 4.22 5.92

Brazoria Western Gulf 11.0 14.8

Brazos Eagle Ford Shale 10.5 10.0

Brewster Marathon Thrust Belt 7.61 9.75

Briscoe Palo Duro 7.61 9.75

Brooks Western Gulf 11.0 14.8

Brown Fort Worth/Barnett Shale 9.76 16.0

Burleson Eagle Ford Shale 10.5 10.0

Burnet Fort Worth/Barnett Shale 9.76 16.0

Caldwell Western Gulf 11.0 14.8

Calhoun Western Gulf 11.0 14.8

Callahan Fort Worth/Barnett Shale 9.76 16.0

Cameron Western Gulf 11.0 14.8

Camp East Texas/Haynesville Shale 4.22 5.92

Carson Anadarko 3.15 5.87

Cass East Texas/Haynesville Shale 4.22 5.92

Castro Palo Duro 7.61 9.75

Chambers Western Gulf 11.0 14.8

Cherokee East Texas/Haynesville Shale 4.22 5.92

Childress Palo Duro 7.61 9.75

Clay Fort Worth/Barnett Shale 9.76 16.0
2-30

Table 2-16. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Cochran Permian 7.07 5.90

Coke Permian 7.07 5.90

Coleman Fort Worth/Barnett Shale 9.76 16.0

Collin Fort Worth/Barnett Shale 9.76 16.0

Collingsworth Palo Duro 7.61 9.75

Colorado Western Gulf 11.0 14.8

Comal Western Gulf 11.0 14.8

Comanche Fort Worth/Barnett Shale 9.76 16.0

Concho Fort Worth/Barnett Shale 9.76 16.0

Cooke Fort Worth/Barnett Shale 9.76 16.0

Coryell Fort Worth/Barnett Shale 9.76 16.0

Cottle Palo Duro 7.61 9.75

Crane Permian 7.07 5.90

Crockett Permian 7.07 5.90

Crosby Permian 7.07 5.90

Culberson Permian 7.07 5.90

Dallam Palo Duro 7.61 9.75

Dallas Fort Worth/Barnett Shale 9.76 16.0

Dawson Permian 7.07 5.90

Deaf Smith Palo Duro 7.61 9.75

Delta East Texas/Haynesville Shale 4.22 5.92

Denton Fort Worth/Barnett Shale 9.76 16.0

DeWitt Eagle Ford Shale 10.5 10.0

Dickens Permian 7.07 5.90

Dimmit Eagle Ford Shale 10.5 10.0

Donley Palo Duro 7.61 9.75

Duval Western Gulf 11.0 14.8

Eastland Fort Worth/Barnett Shale 9.76 16.0

Ector Permian 7.07 5.90

Edwards Permian 7.07 5.90

El Paso Permian 7.07 5.90

Ellis Fort Worth/Barnett Shale 9.76 16.0

Erath Fort Worth/Barnett Shale 9.76 16.0

Falls East Texas/Haynesville Shale 4.22 5.92

Fannin East Texas/Haynesville Shale 4.22 5.92

Fayette Eagle Ford Shale 10.5 10.0

Fisher Permian 7.07 5.90

Floyd Palo Duro 7.61 9.75

Foard Fort Worth/Barnett Shale 9.76 16.0

Fort Bend Western Gulf 11.0 14.8

Franklin East Texas/Haynesville Shale 4.22 5.92

Freestone East Texas/Haynesville Shale 4.22 5.92

Frio Eagle Ford Shale 10.5 10.0

Gaines Permian 7.07 5.90
2-31

Table 2-16. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Galveston Western Gulf 11.0 14.8

Garza Permian 7.07 5.90

Gillespie Fort Worth/Barnett Shale 9.76 16.0

Glasscock Permian 7.07 5.90

Goliad Western Gulf 11.0 14.8

Gonzales Eagle Ford Shale 10.5 10.0

Gray Anadarko 3.15 5.87

Grayson Fort Worth/Barnett Shale 9.76 16.0

Gregg East Texas/Haynesville Shale 4.22 5.92

Grimes Eagle Ford Shale 10.5 10.0

Guadalupe Western Gulf 11.0 14.8

Hale Palo Duro 7.61 9.75

Hall Palo Duro 7.61 9.75

Hamilton Fort Worth/Barnett Shale 9.76 16.0

Hansford Anadarko 3.15 5.87

Hardeman Fort Worth/Barnett Shale 9.76 16.0

Hardin Western Gulf 11.0 14.8

Harris Western Gulf 11.0 14.8

Harrison East Texas/Haynesville Shale 4.22 5.92

Hartley Palo Duro 7.61 9.75

Haskell Fort Worth/Barnett Shale 9.76 16.0

Hays Western Gulf 11.0 14.8

Hemphill Anadarko 3.15 5.87

Henderson East Texas/Haynesville Shale 4.22 5.92

Hidalgo Western Gulf 11.0 14.8

Hill Fort Worth/Barnett Shale 9.76 16.0

Hockley Permian 7.07 5.90

Hood Fort Worth/Barnett Shale 9.76 16.0

Hopkins East Texas/Haynesville Shale 4.22 5.92

Houston East Texas/Haynesville Shale 4.22 5.92

Howard Permian 7.07 5.90

Hudspeth Permian 7.07 5.90

Hunt East Texas/Haynesville Shale 4.22 5.92

Hutchinson Anadarko 3.15 5.87

Irion Permian 7.07 5.90

Jack Fort Worth/Barnett Shale 9.76 16.0

Jackson Western Gulf 11.0 14.8

Jasper Western Gulf 11.0 14.8

Jeff Davis Permian 7.07 5.90

Jefferson Western Gulf 11.0 14.8

Jim Hogg Western Gulf 11.0 14.8

Jim Wells Western Gulf 11.0 14.8

Johnson Fort Worth/Barnett Shale 9.76 16.0

Jones Fort Worth/Barnett Shale 9.76 16.0
2-32

Table 2-16. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Karnes Eagle Ford Shale 10.5 10.0

Kaufman East Texas/Haynesville Shale 4.22 5.92

Kendall Fort Worth/Barnett Shale 9.76 16.0

Kenedy Western Gulf 11.0 14.8

Kent Permian 7.07 5.90

Kerr Fort Worth/Barnett Shale 9.76 16.0

Kimble Fort Worth/Barnett Shale 9.76 16.0

King Permian 7.07 5.90

Kinney Western Gulf 11.0 14.8

Kleberg Western Gulf 11.0 14.8

Knox Fort Worth/Barnett Shale 9.76 16.0

La Salle Eagle Ford Shale 10.5 10.0

Lamar East Texas/Haynesville Shale 4.22 5.92

Lamb Palo Duro 7.61 9.75

Lampasas Fort Worth/Barnett Shale 9.76 16.0

Lavaca Eagle Ford Shale 10.5 10.0

Lee Eagle Ford Shale 10.5 10.0

Leon Eagle Ford Shale 10.5 10.0

Liberty Western Gulf 11.0 14.8

Limestone East Texas/Haynesville Shale 4.22 5.92

Lipscomb Anadarko 3.15 5.87

Live Oak Eagle Ford Shale 10.5 10.0

Llano Fort Worth/Barnett Shale 9.76 16.0

Loving Permian 7.07 5.90

Lubbock Permian 7.07 5.90

Lynn Permian 7.07 5.90

Madison Western Gulf 11.0 14.8

Marion East Texas/Haynesville Shale 4.22 5.92

Martin Permian 7.07 5.90

Mason Fort Worth/Barnett Shale 9.76 16.0

Matagorda Western Gulf 11.0 14.8

Maverick Eagle Ford Shale 10.5 10.0

McCulloch Fort Worth/Barnett Shale 9.76 16.0

McLennan Fort Worth/Barnett Shale 9.76 16.0

McMullen Eagle Ford Shale 10.5 10.0

Medina Western Gulf 11.0 14.8

Menard Fort Worth/Barnett Shale 9.76 16.0

Midland Permian 7.07 5.90

Milam Eagle Ford Shale 10.5 10.0

Mills Fort Worth/Barnett Shale 9.76 16.0

Mitchell Permian 7.07 5.90

Montague Fort Worth/Barnett Shale 9.76 16.0

Montgomery Western Gulf 11.0 14.8

Moore Anadarko 3.15 5.87
2-33

Table 2-16. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Morris East Texas/Haynesville Shale 4.22 5.92

Motley Palo Duro 7.61 9.75

Nacogdoches East Texas/Haynesville Shale 4.22 5.92

Navarro East Texas/Haynesville Shale 4.22 5.92

Newton Western Gulf 11.0 14.8

Nolan Permian 7.07 5.90

Nueces Western Gulf 11.0 14.8

Ochiltree Anadarko 3.15 5.87

Oldham Palo Duro 7.61 9.75

Orange Western Gulf 11.0 14.8

Palo Pinto Fort Worth/Barnett Shale 9.76 16.0

Panola East Texas/Haynesville Shale 4.22 5.92

Parker Fort Worth/Barnett Shale 9.76 16.0

Parmer Palo Duro 7.61 9.75

Pecos Permian 7.07 5.90

Polk Western Gulf 11.0 14.8

Potter Palo Duro 7.61 9.75

Presidio Permian 7.07 5.90

Rains East Texas/Haynesville Shale 4.22 5.92

Randall Palo Duro 7.61 9.75

Reagan Permian 7.07 5.90

Real Fort Worth/Barnett Shale 9.76 16.0

Red River East Texas/Haynesville Shale 4.22 5.92

Reeves Permian 7.07 5.90

Refugio Western Gulf 11.0 14.8

Roberts Anadarko 3.15 5.87

Robertson Eagle Ford Shale 10.5 10.0

Rockwall East Texas/Haynesville Shale 4.22 5.92

Runnels Fort Worth/Barnett Shale 9.76 16.0

Rusk East Texas/Haynesville Shale 4.22 5.92

Sabine East Texas/Haynesville Shale 4.22 5.92

San Augustine East Texas/Haynesville Shale 4.22 5.92

San Jacinto Western Gulf 11.0 14.8

San Patricio Western Gulf 11.0 14.8

San Saba Fort Worth/Barnett Shale 9.76 16.0

Schleicher Permian 7.07 5.90

Scurry Permian 7.07 5.90

Shackelford Fort Worth/Barnett Shale 9.76 16.0

Shelby East Texas/Haynesville Shale 4.22 5.92

Sherman Anadarko 3.15 5.87

Smith East Texas/Haynesville Shale 4.22 5.92

Somervell Fort Worth/Barnett Shale 9.76 16.0

Starr Western Gulf 11.0 14.8

Stephens Fort Worth/Barnett Shale 9.76 16.0
2-34

Table 2-16. County-Level VOC Emission Factors

County Region

Production 

Weighted 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average Emission 

Factor (lbs/bbl)

Sterling Permian 7.07 5.90

Stonewall Permian 7.07 5.90

Sutton Permian 7.07 5.90

Swisher Palo Duro 7.61 9.75

Tarrant Fort Worth/Barnett Shale 9.76 16.0

Taylor Fort Worth/Barnett Shale 9.76 16.0

Terrell Marathon Thrust Belt 7.61 9.75

Terry Permian 7.07 5.90

Throckmorton Fort Worth/Barnett Shale 9.76 16.0

Titus East Texas/Haynesville Shale 4.22 5.92

Tom Green Permian 7.07 5.90

Travis Western Gulf 11.0 14.8

Trinity Western Gulf 11.0 14.8

Tyler Western Gulf 11.0 14.8

Upshur East Texas/Haynesville Shale 4.22 5.92

Upton Permian 7.07 5.90

Uvalde Western Gulf 11.0 14.8

Val Verde Permian 7.07 5.90

Van Zandt East Texas/Haynesville Shale 4.22 5.92

Victoria Western Gulf 11.0 14.8

Walker Western Gulf 11.0 14.8

Waller Western Gulf 11.0 14.8

Ward Permian 7.07 5.90

Washington Western Gulf 11.0 14.8

Webb Eagle Ford Shale 10.5 10.0

Wharton Western Gulf 11.0 14.8

Wheeler Anadarko 3.15 5.87

Wichita Fort Worth/Barnett Shale 9.76 16.0

Wilbarger Fort Worth/Barnett Shale 9.76 16.0

Willacy Western Gulf 11.0 14.8

Williamson Western Gulf 11.0 14.8

Wilson Eagle Ford Shale 10.5 10.0

Winkler Permian 7.07 5.90

Wise Fort Worth/Barnett Shale 9.76 16.0

Wood East Texas/Haynesville Shale 4.22 5.92

Yoakum Permian 7.07 5.90

Young Fort Worth/Barnett Shale 9.76 16.0

Zapata Western Gulf 11.0 14.8

Zavala Eagle Ford Shale 10.5 10.0
2-35

2.7 Accounting for the Effect of Recovery and Control Devices

The effect of existing vapor recovery and control devices should be accounted for in 

determining emissions from area sources. However, there is limited information on the 

use of control devices in the condensate producing regions of Texas, and the quantity of 

the information varies. 

2.7.1 Barnett Shale

The TCEQ Barnett Shale Special Inventory data indicates whether condensate tank 

emissions are recovered or controlled at each site. This dataset contains 1,575 records 

covering the 14 counties listed in Table 2-8 above. The Barnett Shale Inventory data 

indicate that 13.2% of total surveyed production in these 14 counties was controlled, and 

the average percent reduction was 97.2%. The 2009 RRC condensate production data 

for these 14 counties is 2,680,019 bbl. The surveyed production (2,479,409 bbl from 

Table 2-8) represents 92.5% of total 2009 condensate production in these counties. 

Because the Barnett Shale Inventory was a mandatory survey of all producers in these 

counties, and had a very high response rate, we can assume that 12.2% (92.5% x 13.2%)

of total production in that region should be considered to be controlled by 97.2%, for an 

overall reduction of 11.8%. 

2.7.2 HGB, BPA, and Haynesville Shale

The 2010 study conducted by ENVIRON for TCEQ titled “Control of VOC Flash 

Emissions from Oil and Condensate Storage Tanks in East Texas” reported on control 

of emissions from oil and condensate storage tanks in three geographic regions of Texas.

This study investigated the effect on VOC emissions reductions in the HGB 

nonattainment area due to the implementation of requirements in Title 30 Texas 

Administrative Code 115.112(d)(5). The report investigated the possible effects should 

this same rule be implemented in the BPA area and the Haynesville Shale area. This 

report also considered the effect of the Texas Permit by Rule (Title 30 TAC 106.352) 

requirements, which allow a well/tank site with emissions less than 25 tons of VOC per 

year to qualify for a more streamlined permit. 21

This report included results from surveys of the HGB area, the BPA area, the 

Haynesville Shale, and a TCEQ Region 12 survey for the HGB area. 82 producers 

responded to these two surveys and submitted control information for 1,940 sites.22

 21 The Permit By Rule for Oil and Gas sites (Title 30 TAC 106.352) allows new or modified facilities that meet 

certain conditions and that emit less than 25 tons per year of VOC to be obtain authorization per rule requirements. 

It has the effect of encouraging larger oil and gas sources to install control devices on their oil and condensate tanks 

so as to limit emissions.

 

22 There is a small overlap in data collected for the HGB area (Table ES-3 of the report). It does not affect the 

results, as the overlap has been accounted for in analyzing the data.
2-36

The data collected for this report23

This study also requested information from producers about tank emissions controls. 

When this information is combined with production information, it gives an estimate of 

the percent of total surveyed production in each of the surveyed areas that is controlled. 

indicated that 25% of the surveyed production in the 

HGB area was controlled, 9% of the surveyed production in the Haynesville Shale area 

was controlled, and 72% of the surveyed production in the BPA area was controlled. The 

high surveyed percentage of controlled production in the BPA area can be attributed to a 

group of large condensate producing sites (accounting for more than 1000 bbl/day) 

equipped with a suite of control devices. These sites accounted for approximately half of 

the surveyed BPA area production and significantly contribute to the high percentage of

surveyed controlled production.

2.7.3 Calculation of Control Factor

Each region-specific or county-specific control factor should reflect the percentage of 

production in that region/county that was reported as controlled per the survey. For the 

percentage of production that was not reported in these surveys, instead of assuming 

this production is uncontrolled, a default control percentage is applied. The assumed 

default control factor for the production not reported in these surveys was developed 

from the TCEQ Barnett Shale Special Inventory data. The large sample size of this 

special inventory data combined with the characteristics of the Barnett Shale formation 

represents a conservative control estimate.

To calculate an overall control factor, a multi-step calculation was developed that 

accounts for reported versus unreported survey condensate production. This 

calculation is outlined for the HGB area in detail below; the same calculation was 

employed with area-specific data for the other areas. The calculation methodology was 

as follows:

1. 68 % of HGB condensate production was reported in the survey.

a. 25% of reported production is controlled at a 95% level

b. 75% of reported production is not controlled

2. 32 % of HGB production data was not reported in the survey

3. To account for the different categories of data, each category will be treated 

separately and the results summed to produce the control factor.

a. For the controlled category, category 1a, the basic formula is:

i. Portion of control factor = (percent of production represented by 

category) * (percent of controlled production) * (control efficiency)

ii. For category 1a, this equals: (0.680*0.25*0.95) = 0.161 or 16.1%

b. For the category where production was not reported, category 2, default 

data is assumed and the basic formula is:

 23 TCEQ provided ERG with three spreadsheets containing the survey data obtained from the ENVIRON surveys.
2-37

i. Portion of control factor = (percent of production represented by 

category) * (percent of controlled production, default from Barnett 

Shale special inventory) * (control efficiency, default from Barnett 

Shale special inventory)

ii. For category 2, this equals: (0.320*0.122*0.972) = 0.0379 or 3.8%

c. Total control for 100% of production in the HGB area is therefore the sum 

of portion of controls from categories 1a and 2, or (16.1+3.8) % or 19.9%.

Table 2-17 below presents the findings of this analysis and includes a recommended 

control factor for each region.

2.7.4 ERG 2012 Survey

The ERG 2012 survey collected data from 15 companies for 251 sites in 50 counties. 

Data from 175 of these sites was used in calculating results. The survey data show that 

emissions from 91.1% of all surveyed production was either recovered with a VRU or 

controlled with a flare or combustor, and the average percent reduction was 97.6%. 

These are exceptionally high percentages when compared with the amount of 

production reported as controlled in the Barnett Shale Inventory and the TCEQ 2010 

study above. The ERG 2012 survey data was voluntary, and may not be representative 

of all producers or other counties in the regions surveyed. This difference may also be 

due to the characteristics of the Barnett Shale and Haynesville Shale formations versus 

the other regions of Texas. The Barnett Shale and Haynesville Shale both produce a 

‘dry’ gas, with little condensate production. Therefore, it may not have been economical 

or necessary from a regulatory standpoint at the time this survey was taken to control 

the emissions from the condensate tanks in the Barnett and Haynesville Shale.

The higher level of control observed in the ERG survey may also be due to the increasing 

implementation of recovery and control technologies over time, and the effect of new 

regulations limiting air pollutant emissions in specific areas. The Barnett Shale 

Inventory and the TCEQ surveys were conducted in 2009, whereas the ERG survey was 

conducted in 2012 and covers production and emissions in 2011. Title 30 Texas 

Administrative Code 106.352, Permit by Rule for Oil and Gas Handling and Production 

Facilities24, became effective on February 2, 2012, which may account for the higher 

control percentages observed during this survey.

 24 Texas Commission on Environmental Quality, Rules, http://www.tceq.state.tx.us/rules/indxpdf.html
2-38

Table 2-17. Percentage of Surveyed Production with Tank Emissions Controlled in the HGB, BPA, and 

Haynesville Shale Areas

Region (counties)

2009 Total 

Production 

Reported to 

RRC a (bbl)

Number of 

Sites/Tank 

Batteries 

Surveyed b

Total 

Surveyed 

Production c

Total 

Controlled 

Production 

Reported in 

Survey d (bbl)

Percent of 

Reported 

Production That 

is Controlled d

(%)

Percent of 

Production 

Not Reported 

in the Survey e

(%)

Control 

Efficiency 

(%)

Control 

Factor (%)

Houston-GalvestonBrazoria

(Brazoria, Chambers, Fort 

Bend, Galveston, Harris, 

Liberty, Montgomery, 

Waller)

3,436,859 180 2,335,837 583,462 25.0 32.0 95 19.9

Beaumont - Port Arthur

(Hardin, Jefferson, Orange) 5,456,431 26 1,196,723 863,250 72.1 78.1 90 23.5

Haynesville Shale

(Gregg, Harrison, Marion, 

Nacogdoches, Panola, Rusk, 

San Augustine, Smith, 

Shelby, Upshur)

5,445,378 523 2,018,527 182,525 9.04 62.9 90 10.5

Barnett Shale

(Clay, Cooke, Denton, Erath, 

Hood, Jack, Johnson, 

Montague, Palo Pinto, 

Parker, Somervell, 

Stephens, Tarrant, Wise) f

2,680,019 1,575 2,478,858 326,545 13.2 7.5 97.2 11.8

a Data for 2009 condensate production from these counties is from a production data query at the Railroad Commission of Texas website. b Data for the number of sites/tank batteries surveyed in the HGB, BPA, and Haynesville Shale areas comes from Tables 14a and 14b of the “Control of VOC Flash 

Emissions from Oil and Condensate Storage Tanks in East Texas” (TCEQ, 2010) report. c Data for the total surveyed production for the HGB, BPA, and Haynesville Shale areas comes from Table 8 of the “Control of VOC Flash Emissions from Oil and 

Condensate Storage Tanks in East Texas” report. d Data for the total controlled production for the HGB, BPA, and Haynesville Shale areas comes from spreadsheets provided to ERG by TCEQ. e This percentage is derived from the 2009 total production reported to RRC (column 2) and the total surveyed production (column 4). f

The data for the Barnett Shale counties comes from the TCEQ Barnett Shale Special Inventory (Table 2-8 and Attachment C of this report).
2-39

In assessing whether the surveyed data is representative of all basin operations, ERG 

has no direct knowledge that any of the companies who responded to this survey biased 

the data that they submitted. However, as noted above, the percent of surveyed 

production with emissions being recovered or controlled (91.1%) is very high when 

compared to the results obtained from the Barnett Shale Area Special Inventory and 

other studies. ERG collected survey data from 15 large and medium sized companies. A 

significant portion of the larger companies operate the highest producing wells in many 

regions. Also, larger companies may have the capital to purchase and install control 

devices, and may also have more resources to respond to surveys.

The figures for surveyed production as a percentage of total production reported by the 

RRC also indicate that the survey counts as ‘condensate’ a significant percentage of 

liquids production that the RRC considers to be oil. Although ERG requested data for 

condensate production, data was also requested for wells producing liquids with an API 

gravity greater than 40 degrees. Since the RRC condensate production values are 

ultimately used for TCEQ area source emissions inventory development, survey data 

was reviewed and outlier data suspected of representing oil production (e.g., extremely 

low separator pressure) was not used for emissions and control factor development. 

The majority of outlier data appeared in the Permian Basin region, where oil production 

is at least 100 times greater than condensate production.25

Table 2-18 shows the control information developed from the ERG survey data.

Survey responses for certain 

basins in the state captured a limited amount of basin production. With the varying 

amount of data available for analysis, uncertainties exist about applying the control 

factor from the surveyed data to the remainder of condensate production in those 

counties and areas.

2.8 Summary of Findings and Recommended Emission Factors

Analysis of data from four studies and two surveys indicates that there exists a distinct 

regional variation in emissions from condensate storage tanks across the oil and gas 

producing regions of Texas. Emission estimates from testing and software models were 

considered and each of these data sources has limitations. 

Survey data indicate that producers are installing recovery and control devices on an 

increasing percentage of their condensate wells. The Barnett Shale Inventory data 

indicates that emissions from 12.2% of total surveyed production were controlled, and 

data from the 15 producers participating in the ERG 2012 survey indicated that 

emissions from 91.0% of their total production was recovered or controlled. Other 

innovative techniques, such as piping all production directly to a centralized processing 

facility, or using multi-stage separators with ultra-low final stage pressure drop, also 

 25 Railroad Commission of Texas, http://www.rrc.state.tx.us/permianbasin/index.php
2-40

reduce emissions from condensate production at area sources. An accurate assessment 

of area source emissions will need to account for the effect of these techniques, and for 

any increase in their implementation over time.

ERG recommends use of the uncontrolled, production-weighted VOC emission factors 

in Table 2-16 when calculating the emissions from area source condensate production. 

Application of the control factors to the percentage of surveyed, controlled condensate 

production presented in Table 2-17 is recommended for the HGB, BPA, Haynesville 

Shale, and Barnett Shale counties listed. Despite the availability of ERG 2012 survey 

data for other regions as shown in Table 2-18, the 11.8% control factor derived from the 

comprehensive Barnett Shale Inventory is recommended for the remainder of 

condensate production in these regions and throughout the state until additional data 

for a large number of producers in the other regions can be obtained. These emission 

reduction factors will capture the effect of emission recovery and control devices that 

producers have installed on their production equipment in the counties listed, while 

conservatively estimating emissions for the remainder of condensate production. 

Alternatively, the control factors presented in both Tables 2-17 and 2-18 can be applied 

to the percentage of surveyed, controlled condensate production for the counties in each 

region. For the remainder of production, application of the 11.8% control factor derived 

from the Barnett Shale Inventory is recommended.
2-41

Table 2-18. Surveyed Production, Total Production, Percent of Surveyed Production Controlled, and Control 

Factor, by Region

Region

Total Production 

Represented in 

Survey (bbl)

Total Annual 

Productiona

(bbl)

Percent of 2011 

Production 

Represented by the 

Survey 

Total 

Controlled 

Production 

Reported in 

Survey (bbl)

Percent of 

Surveyed 

Production 

Controlled

Control 

Efficiency 

(%)

Control 

Factor (%)b

Alternate 

Control 

Factor (%)c

Anadarko 533,419 8,609,960 6.2 530,324 99.4 97.9 6.03 17.1

Eagle Ford 10,538,273 24,343,253 43.3 9,716,987 92.2 98.5 39.3 46.0

East Texas 518,691 4,681,732 11.1 425,644 82.1 98.1 8.92 19.4

Permian 245,545 2,036,996 12.1 195,275 79.5 94.7 9.08 19.5

Western Gulf 182,349 18,241,171 1.0 84,785 46.5 98.0 0.46 12.2

a Data for 2009 condensate production from the Barnett Shale area and 2011 condensate production for the other five regions is from the RRC. b Control factor assumes that only the surveyed production is controlled.

c Control factor assumes that surveyed production is controlled at the surveyed control rate, and that the unsurveyed production is controlled at a default rate 

of 11.8 percent.
3-1

3.0 Hazardous Air Pollutant Emissions from Condensate 

Storage Tanks

As part of the study to refine the condensate tank VOC emission factor used in the TCEQ 

area source inventory, ERG accumulated a significant amount of data on emissions of 

benzene, toluene, ethylbenzene, and xylene (BTEX) from condensate storage tanks. 

This data was obtained from the 2006 HARC study, the Barnett Shale Area Special 

Inventory Phase II survey of producers, and E&P TANK report data submitted by 

producers in response to the ERG 2012 survey. ERG determined that the amount and 

quality of this data was sufficient to allow development of region-specific emission 

factors for BTEX emissions from storage tanks for four geographic regions in the state. 

These four regions are: Eagle Ford Shale, East Texas/Haynesville Shale, Bend Arch-Fort 

Worth/Barnett Shale, and Western Gulf. These regions are shown in Figure 2-1 above.

3.1 BTEX Emissions Data Derived from Testing

The researchers who conducted the study “VOC Emissions from Oil and Condensate 

Storage Tanks” (Houston Advanced Research Center, 2006, and Texas Environmental 

Research Consortium, 2009)26 also made measurements of BTEX content of the 

emissions from each of the oil and condensate storage tanks. The report provided data 

for the weight percent of benzene, toluene, ethylbenzene, and xylene in the tank vent 

gas; data on the weight percent of VOC in the tank vent gas; the liquid production in 

barrels per day; and the VOC emissions in pounds per day and pounds per barrel. ERG 

re-examined the data from the sites examined in the HARC 2006 study. Although 

27 sites produce liquids having an API gravity of 40 degrees or greater, only data from 

the 22 sites designated as being condensate is considered. In this analysis, three data 

points were removed from the data set as was done for the VOC emission factor 

development process as described above. An emission factor for each of the remaining 

19 sites was calculated. Table 2-1 (above) and Table 3-1 (below) show the measurement 

data from the HARC 2006 study for these 19 condensate tanks.

Table 3-1. VOC and BTEX Content in the Vent Gas

Tank Battery Weight % VOC Weight % 

Benzene

Weight % 

Toluene

Weight % 

Ethylbenzene

Weight % 

Xylene

2 47 0.34 0.53 0.04 0.21

3 62 0.63 1.10 0.06 0.46

4 57 0.57 1.02 0.06 0.41

5 70 0.75 1.32 0.07 0.55

6 65 0.49 0.56 0.03 0.14

13 81 0.19 0.40 0.01 0.14

14 53 0.13 0.33 0.02 0.16

 26 Houston Advanced Research Center, VOC Emissions from Oil and Condensate Storage Tanks, October

31, 2006. http://files.harc.edu/Projects/AirQuality/Projects/H051C/H051CFinalReport.pdf
3-2

Table 3-1. VOC and BTEX Content in the Vent Gas

Tank Battery Weight % VOC Weight % 

Benzene

Weight % 

Toluene

Weight % 

Ethylbenzene

Weight % 

Xylene

15 82 0.18 0.25 0.01 0.09

16 85 0.20 0.41 0.02 0.19

18 70 0.23 0.65 0.03 0.38

19 77 0.25 0.58 0.02 0.25

20 89 0.17 0.35 0.01 0.18

23 81 0.39 1.08 0.03 0.48

24 70 0.19 0.67 0.22 0.36

27 86 0.27 0.83 0.02 0.33

28 55 1.07 0.68 0.07 0.28

29 83 0.28 0.10 0.02 0.03

30 62 1.35 0.67 0.03 0.16

32 87 0.44 0.48 0.03 0.19

Emission factors in terms of lbs/bbl can be calculated with the following formula:

HAP Pollutanti (lbs/bbl) = (weight % HAP Pollutanti/weight % VOCi) × VOC Emissionsi

(lbs/bbl)

(Eq. 3-1)

Table 3-2 shows the VOC and BTEX emission factors for these 19 sites. As all data was 

obtained through testing, preferential weighting is not used to calculate the average 

emission factors.

Table 3-2. VOC and BTEX Emission Factors

Tank 

Battery 

Site #

Region

VOC 

Emission 

Factor 

(lbs/bbl)

Benzene 

Emission 

Factor 

(lbs/bbl)

Toluene 

Emission 

Factor 

(lbs/bbl)

Ethylbenzene 

Emission Factor 

(lbs/bbl)

Xylene 

Emission 

Factor 

(lbs/bbl)

2 Western Gulf 3.65 0.0264 0.0412 0.0031 0.0163

3 Western Gulf 7.92 0.0805 0.1405 0.0077 0.0588

4 Western Gulf 0.78 0.0078 0.0140 0.0008 0.0056

5 Western Gulf 0.67 0.0072 0.0126 0.0007 0.0053

6 Western Gulf 2.96 0.0223 0.0255 0.0014 0.0064

13 Fort Worth 39.23 0.0920 0.1937 0.0048 0.0678

14 Fort Worth 29.51 0.0724 0.1837 0.0111 0.0891

15 Fort Worth 11.99 0.0263 0.0366 0.0015 0.0132

16 Fort Worth 60.58 0.1425 0.2922 0.0143 0.1354

18 Fort Worth 7.34 0.0241 0.0682 0.0031 0.0398

19 Fort Worth 13.16 0.0427 0.0991 0.0034 0.0427

20 Fort Worth 30.43 0.0581 0.1197 0.0034 0.0615

23 Fort Worth 5.56 0.0268 0.0741 0.0021 0.0329
3-3

Table 3-2. VOC and BTEX Emission Factors

Tank 

Battery 

Site #

Region

VOC 

Emission 

Factor 

(lbs/bbl)

Benzene 

Emission 

Factor 

(lbs/bbl)

Toluene 

Emission 

Factor 

(lbs/bbl)

Ethylbenzene 

Emission Factor 

(lbs/bbl)

Xylene 

Emission 

Factor 

(lbs/bbl)

24 Fort Worth 4.22 0.0115 0.0404 0.0133 0.0217

27 Fort Worth 14.39 0.0452 0.1389 0.0033 0.0552

28 Western Gulf 4.17 0.0811 0.0516 0.0053 0.0212

29 Western Gulf 33.68 0.1136 0.0406 0.0081 0.0122

30 Western Gulf 6.11 0.1330 0.0660 0.0030 0.0158

32 Western Gulf 63.49 0.3211 0.3503 0.0219 0.1387

Production-Weighted Average Emission 

Factor (lbs/bbl) 0.0864 0.0981 0.0063 0.0387

Arithmetic Average Emission Factor 

(lbs/bbl) 0.0702 0.1047 0.0059 0.0442

3.2 BTEX Emissions Data Derived from the Barnett Shale Area Special 

Inventory, Phase II (2009)

TCEQ provided ERG with data from the “Barnett Shale Area Special Inventory, Phase II 

2009” (Barnett Shale Inventory) information in spreadsheet format. The Barnett Shale 

Inventory data contains records of condensate tanks with reported condensate 

production rates and calculated BTEX emissions. ERG analyzed the BTEX emissions 

data and developed emission factors for condensate tanks in the Bend-Arch-Fort Worth 

and Barnett Shale counties. The data analysis was similar to that done for VOC for the 

entire Barnett Shale region. All records with emission factors above 140 lbs/bbl were 

rejected. Only records using the preferred estimation methods for flashing emissions 

(direct measurement, process simulator, E&P TANK, GOR) were analyzed. A 

production-weighted average of the emission factors, before controls, was calculated for 

each HAP pollutant as shown in Table 3-3. The data is grouped by estimation method, 

and a production-weighted average and an arithmetic average is used in determining an 

emission factor for each estimation method. The production-weighted average and 

arithmetic average for each estimation method were weighted according to the 

weighting factors in Table 2-11. 
3-4

Table 3-3. Condensate Tank BTEX Emission Factor Estimates Using Data 

from the Barnett Shale Phase II 2009 Inventory

Emission 

Calculation 

Methods

Pollutant

Total 

Emissions 

(lbs)

Total 

Production 

(bbl)

ProductionWeighted Average 

Emission Factor 

(lbs/bbl)

Arithmetic 

Average 

Emission 

Factor 

(lbs/bbl)

Flash Emissions: 

Process Simulator 

Models, E&P TANK, 

Direct 

Measurement, GOR

Working and 

Breathing 

Emissions: E&P 

TANK, EPA TANKS 

Program, Other

Benzene 17,393 723,298 0.019 0.084

Toluene 28,926 734,626 0.042 0.13

Ethylbenzene 2,057 310,139 0.011 0.036

Xylene 20,047 730,722 0.067 0.20

3.3 BTEX Emissions Data Derived from E&P TANK Reports Submitted in 

Response to the ERG Survey

One respondent to the ERG Survey provided paper copies of the E&P Tank V 2.0 

Calculation Reports for 85 well/tank sites. The E&P TANK reports contain detailed 

information on a tank, its equipment, and its emissions, including: API gravity, 

separator pressure, separator temperature, and annual liquids production; and annual 

emissions of methane, non-methane volatile organic compounds, benzene, toluene, 

ethylbenzene, and xylene. As E&P TANK is one of the methods preferred by TCEQ for 

calculating flashing, working, and breathing emissions, this data was used in evaluating 

BTEX emissions in the three regions (Eagle Ford Shale, East Texas/Haynesville Shale, 

and Western Gulf) in which the tanks are located. Eight sites produced liquids having 

an API gravity of less than 40 degrees, so these sites were removed from the dataset. 

Data from the remaining 77 records is shown in Table 3-4.
3-5

Table 3-4. Condensate Tank BTEX Emission Factor Estimates Using Data from E&P TANK Reports 

Submitted for ERG Survey

Region County

API 

Gravity 

(deg.)

Separator 

Pressure 

(psig)

Condensate 

Production 

(bbl)

Emission Factors (lbs/bbl)

VOC Benzene Toluene Ethylbenzene Xylene

Eagle Ford Fayette 49.2 25.4 2,555 0.53 0.0039 0.0078 0.0008 0.0047

Eagle Ford Fayette 49.2 25.2 2,811 0.52 0.0043 0.0078 0.0007 0.0050

Eagle Ford Fayette 49.2 28.5 2,190 0.58 0.0046 0.0091 0.0009 0.0055

Eagle Ford Lavaca 40.8 35 949 0.27 0.6322 0.0358 0.0243 0.0084

Eagle Ford Leon 45.2 14 1,460 0.92 0.0288 0.0055 0.0014 0.0055

Eagle Ford Leon 45.2 52.9 219 1.28 0.0822 0.0183 0.0091 0.0183

Eagle Ford Leon 45.2 108.9 256 1.33 0.0783 0.0157 0.0078 0.0235

Eagle Ford Leon 45.2 64.1 146 1.51 0.1096 0.0274 0.0137 0.0274

Eagle Ford McMullen 54.7 48 14,856 1.51 0.0059 0.0125 0.0003 0.0040

Eagle Ford McMullen 54.7 48 8,322 1.80 0.0077 0.0166 0.0002 0.0053

Eagle Ford McMullen 59.3 38 220,570 3.91 0.0226 0.0336 0.0007 0.0156

Eagle Ford McMullen 59.3 38 86,943 3.94 0.0228 0.0340 0.0008 0.0157

Eagle Ford Webb 64.5 65 149,139 3.42 0.0139 0.0172 0.0003 0.0077

Eagle Ford Webb 64.5 200 276,816 3.47 0.0142 0.0176 0.0003 0.0079

East Texas Anderson 42 58.8 37 1.64 0.1644 0.1644 0.0205 0.1096

East Texas Cherokee 45.2 142.4 146 1.64 0.1096 0.0274 0.0137 0.0274

East Texas Cherokee 45.2 76.9 256 1.33 0.0783 0.0157 0.0078 0.0235

East Texas Cherokee 45.2 84.9 110 1.46 0.1096 0.0365 0.0183 0.0365

East Texas Freestone 60 205 4,271 12.96 0.1892 0.1321 0.0037 0.0239

East Texas Freestone 60 75.4 329 16.32 0.3592 0.2740 0.0061 0.0548

East Texas Freestone 60 69.3 1,679 14.71 0.2418 0.1739 0.0048 0.0322

East Texas Freestone 60 81.2 730 15.21 0.2767 0.2055 0.0055 0.0384

East Texas Freestone 60 77.6 1,971 14.50 0.2334 0.1674 0.0051 0.0315

East Texas Harrison 53.5 100 1,095 0.20 0.0091 0.0018 0.0004 0.0018

East Texas Henderson 50.4 40 219 0.46 0.0457 0.0183 0.0057 0.0091

East Texas Henderson 50.4 267.3 475 0.46 0.0253 0.0084 0.0032 0.0042

East Texas Henderson 50.4 78.1 3,650 0.36 0.0077 0.0027 0.0010 0.0011

East Texas Henderson 50.4 45.8 621 0.42 0.0193 0.0064 0.0024 0.0032

East Texas Henderson 50.4 34 730 0.44 0.0192 0.0082 0.0024 0.0027

East Texas Henderson 50.4 36 803 0.42 0.0174 0.0075 0.0022 0.0025
3-6

Table 3-4. Condensate Tank BTEX Emission Factor Estimates Using Data from E&P TANK Reports 

Submitted for ERG Survey

Region County

API 

Gravity 

(deg.)

Separator 

Pressure 

(psig)

Condensate 

Production 

(bbl)

Emission Factors (lbs/bbl)

VOC Benzene Toluene Ethylbenzene Xylene

East Texas Houston 50.6 40 219 0.18 0.0183 0.0091 0.0018 0.0051

East Texas Houston 50.6 146.5 256 0.23 0.0157 0.0078 0.0016 0.0043

East Texas Houston 50.6 54.5 183 0.22 0.0219 0.0110 0.0022 0.0061

East Texas Houston 50.6 59.2 621 0.19 0.0064 0.0032 0.0006 0.0018

East Texas Limestone 42 40 183 0.55 0.0767 0.0438 0.0015 0.0219

East Texas Limestone 42 69.8 73 1.10 0.1370 0.1096 0.0027 0.0548

East Texas Limestone 42 77.3 37 1.64 0.1644 0.1644 0.0033 0.1096

East Texas Limestone 42 66.2 110 0.91 0.1096 0.0731 0.0022 0.0365

East Texas Limestone 42 64.3 183 0.55 0.0767 0.0438 0.0015 0.0329

East Texas Marion 45.2 20 876 0.98 0.0365 0.0068 0.0023 0.0091

East Texas Marion 45.2 50 1,424 0.91 0.0281 0.0056 0.0014 0.0056

East Texas Marion 45.2 40 840 1.02 0.0381 0.0071 0.0024 0.0095

East Texas Marion 45.2 40 219 1.37 0.0822 0.0183 0.0091 0.0183

East Texas Nacogdoches 58.8 807 110 1.28 0.0548 0.0731 0.0183 0.0913

East Texas Navarro 46.3 38 6,023 3.22 0.0306 0.0186 0.0007 0.0040

East Texas Panola 45.2 76 1,497 0.88 0.0281 0.0053 0.0013 0.0053

East Texas Panola 45.2 102 4,709 0.76 0.0174 0.0030 0.0008 0.0038

East Texas Panola 45.2 99.5 1,314 0.91 0.0304 0.0061 0.0015 0.0061

East Texas Panola 45.2 90 2,044 0.88 0.0245 0.0039 0.0010 0.0049

East Texas Panola 45.2 40.2 1,825 0.91 0.0252 0.0044 0.0011 0.0055

East Texas Rusk 55.5 105 21,681 6.46 0.0540 0.0564 0.0017 0.0167

East Texas Rusk 55.5 40 183 6.36 0.0548 0.0548 0.0034 0.0219

East Texas San Augustine 58.8 168 146 1.10 0.0411 0.0548 0.0137 0.0685

East Texas Shelby 58.8 40 1,460 0.33 0.0082 0.0082 0.0014 0.0096

East Texas Upshur 55.6 230 1,095 20.31 0.2466 0.0731 0.0037 0.0511

East Texas Upshur 55.6 112.4 4,818 21.02 0.2665 0.0797 0.0037 0.0556

East Texas Upshur 55.6 233.2 730 19.78 0.2411 0.0712 0.0027 0.0493

East Texas Upshur 55.6 222.7 1,095 21.39 0.2612 0.0767 0.0037 0.0530

East Texas Upshur 55.6 215 3,030 20.73 0.2535 0.0753 0.0040 0.0522

Western Gulf Liberty 49.9 50 511 1.06 0.0352 0.0783 0.0039 0.0391
3-7

Table 3-4. Condensate Tank BTEX Emission Factor Estimates Using Data from E&P TANK Reports 

Submitted for ERG Survey

Region County

API 

Gravity 

(deg.)

Separator 

Pressure 

(psig)

Condensate 

Production 

(bbl)

Emission Factors (lbs/bbl)

VOC Benzene Toluene Ethylbenzene Xylene

Western Gulf Liberty 53.9 25 475 1.35 0.0126 0.0421 0.0042 0.0337

Western Gulf Newton 59.8 70 6,607 3.55 0.0061 0.0127 0.0009 0.0070

Western Gulf Newton 59.8 70 2,373 3.57 0.0059 0.0126 0.0008 0.0067

Western Gulf Nueces 49.2 20 6,789 0.36 0.0024 0.0044 0.0003 0.0027

Western Gulf Nueces 49.2 20 1,935 0.60 0.0052 0.0093 0.0010 0.0062

Western Gulf Nueces 51.9 35 3,723 0.59 0.0038 0.0064 0.0005 0.0043

Western Gulf Orange 40.9 40 35,770 0.18 0.0003 0.0008 0.0001 0.0004

Western Gulf Orange 40.9 40 1,351 0.47 0.0015 0.0044 0.0005 0.0030

Western Gulf San Patricio 58.1 20 61,466 58.03 0.4031 0.3360 0.0257 0.1990

Western Gulf Starr 49.2 213.8 438 1.05 0.0137 0.0320 0.0046 0.0183

Western Gulf Starr 49.2 213.8 1,095 0.69 0.0073 0.0146 0.0018 0.0091

Western Gulf Starr 49.2 215.7 949 0.74 0.0084 0.0148 0.0021 0.0105

Western Gulf Wharton 47.2 30 10,001 0.60 0.0052 0.0126 0.0004 0.0060

Western Gulf Wharton 47.2 32 2,519 0.85 0.0095 0.0222 0.0008 0.0111

Western Gulf Wharton 47.2 31 767 1.12 0.0183 0.0470 0.0026 0.0235

Western Gulf Wharton 47.2 27 3,650 0.75 0.0077 0.0181 0.0005 0.0088

Western Gulf Wharton 47.2 25 1,570 0.89 0.0115 0.0280 0.0013 0.0140

Arithmetic Average Emission Factor (lbs/bbl) 0.0772 0.0438 0.0040 0.0230

Production-Weighted Average Emission Factor (lbs/bbl) 0.0465 0.0441 0.0022 0.0227
3-8

3.4 Summary of Findings and Recommended Regional BTEX Emission 

Factors

ERG compiled emission factor data for each region for which data was available using 

the data from the testing results (Table 3-2), Barnett Shale Area Special Inventory 

(Table 3-3), and the E&P TANK reports from the ERG survey (Table 3-4). Table 3-5

shows the production-weighted average emission factors for each region, before the 

effect of any controls. Table 3-6 shows the arithmetic average emission factors for each 

region, before the effect of any controls. A statewide average emission factor can be 

used in estimating BTEX emissions from condensate tanks in the other regions of the 

state (Anadarko, Palo Duro, Permian, and Marathon Thrust Belt).

Table 3-5. Production-Weighted Average Regional BTEX Emission Factors, from 

Testing Data, Barnett Shale Inventory, and Survey Data

Region Number of Data 

Points

Production-Weighted Average Emission Factors (lbs/bbl)

Benzene Toluene Ethylbenzene Xylene 

Eagle Ford 14 0.0181 0.0238 0.0005 0.0108

East Texas 45 0.0914 0.0512 0.0023 0.0190

Fort Worth 537 0.0164 0.0351 0.0068 0.0433

Western Gulf 30 0.0866 0.0829 0.0063 0.0429

All Other Counties - 0.0385 0.0494 0.0063 0.0466

Table 3-6. Arithmetic Average Regional BTEX Emission Factors, from Testing 

Data, Barnett Shale Inventory, and Survey Data

Region Number of Data 

Points

Arithmetic Average Emission Factors (lbs/bbl)

Benzene Toluene Ethylbenzene Xylene 

Eagle Ford 14 0.0736 0.0185 0.0044 0.0110

East Texas 45 0.0968 0.0537 0.0044 0.0270

Fort Worth 537 0.0956 0.1574 0.0222 0.1571

Western Gulf 30 0.0562 0.0552 0.0041 0.0244

All Other Counties - 0.0998 0.1389 0.0161 0.1491
4-1

4.0 Recommendations for Future Condensate Tank 

Investigations

ERG makes the following recommendations with respect to future investigations.

• The timing of this survey coincided with the requirement for many producers to 

file information with EPA in compliance with Subpart W of the Greenhouse Gas 

rules. Based upon discussions with survey recipients, this had a negative impact 

on survey participation by producers. 

• If high participation rates are required, ERG recommends that the TCEQ 

consider collecting information from oil and gas producers through mandatory 

information collection requests. If mandatory surveys are not feasible, then any 

voluntary survey should be initiated with a list of the environmental contacts at 

each of the companies to be surveyed.

• A consistent definition of condensate based on API gravity should be developed 

by TCEQ in combination with the RRC so that the most appropriate emission 

factors are applied to tank liquids, including those tanks that store what 

operators consider to be a combination of oil and condensate.
5-1

5.0 Natural Gas Composition Data Collection and Analysis

In June of 2012, ERG staff visited TCEQ’s office in Austin to review annual point source 

emissions inventory reports submitted by facilities throughout Texas identified as 

having dehydrators on site. The purpose of this visit was to obtain copies of GLYCalc 

reports to obtain natural gas composition data. GLYCalc is a software tool used to 

estimate emissions from dehydrators. Required GLYCalc inputs include natural gas 

composition data, temperature, and pressure.

TCEQ originally identified a possible 368 facilities across the state with dehydrators. 

ERG reviewed these files and obtained approximately 240 inventory reports related to 

dehydrator emissions, including many GLYCalc reports. These reports were reviewed 

and all incomplete reports were flagged and set aside. These incomplete reports did not 

contain natural gas stream composition data, or contained data in a format inconsistent 

with the GLYCalc reporting or output forms and were not evaluated further.

Ultimately, ERG was able to compile complete GLYCalc data for 157 sites located in 

64 counties. Based on TCEQ’s initial identification of 368 facilities, there are 101 

counties in Texas that contain sites with dehydrators that submit an annual point source 

emissions inventory. 

The following constituents were available in the GLYCalc natural gas stream 

composition data (% volume): 

• Water, 

• Carbon Dioxide (CO2),

• Hydrogen Sulfide,

• Nitrogen,

• Methane,

• Ethane,

• Propane,

• Isobutane,

• n-Butane,

• Isopentane,

• n-Pentane,

• Cyclopentane,

• n-Hexane,

• Cyclohexane,

• Other Hexanes,

• Heptanes,

• Methylcyclohexane,

• Benzene,

• Toluene,
5-2

• Ethylbenzene,

• Xylenes, and

• C8+ Heavies

The natural gas stream composition data, both for dry stream and wet stream, were then 

transcribed into Microsoft Excel spreadsheets. This spreadsheet file consisted of 

composition data for 314 natural gas streams (wet and dry) in 64 counties. Once the 

data transcription was complete, these data were quality assured for accuracy and 

completeness. During the Quality Assurance (QA) steps, ERG staff identified a few data 

points that seemed indicative of a CO2 well instead of a natural gas well. The CO2

concentration for these streams was above 85% (by volume). These data points were 

present in Kent, Pecos, and Terrell counties. These data were excluded from further 

analysis. Also, the excluded data for Kent and Terrell counties were the only data points 

available for these two counties. Table 5-1, below, lists the number of GLYCalc reports 

used in the analysis by natural gas stream type and County.

Table 5-1. Counties Included in the Natural Gas Composition Analysis

County Dry Gas Stream Wet Gas Stream County Dry Gas Stream Wet Gas 

Stream

Anderson 2 2 Jack 1 1

Atascosa 1 1 Jefferson 1 1

Bastrop 1 1 Johnson 17 17

Brazoria 11 11 Kenedy 1 1

Brooks 3 3 Kent a 1 1

Caldwell 1 1 Liberty 7 7

Callahan 1 1 Martin 1 1

Camp 1 1 Matagorda 2 2

Carson 1 1 Montague 1 1

Cass 1 1 Nacogdoches 2 2

Chambers 1 1 Nueces 1 1

Clay 2 2 Orange 2 2

Coke 1 1 Palo Pinto 1 1

Crockett 4 4 Panola 2 2

De Witt 1 1 Parker 5 5

Denton 2 2 Pecos a 4 4

Eastland 2 2 Refugio 2 2

Erath 1 1 Robertson 1 1

Fort Bend 1 1 Rusk 2 2

Freestone 5 5 San Patricio 2 2

Gaines 1 1 Smith 3 3

Galveston 3 3 Sterling 2 2

Gray 1 1 Tarrant 12 12

Gregg 4 4 Terrell a 1 1

Hansford 1 1 Upshur 1 2

Hardin 2 2 Upton 1 0

Harris 6 6 Ward 1 1
5-3

Table 5-1. Counties Included in the Natural Gas Composition Analysis

County Dry Gas Stream Wet Gas Stream County Dry Gas Stream Wet Gas 

Stream

Harrison 3 3 Webb 1 1

Hemphill 1 1 Wheeler 1 1

Henderson 2 2 Wilbarger 1 1

Hood 1 1 Winkler 1 1

Houston 1 1 Wise 5 5

Irion 1 1 Young 1 1

Total 157 157 a As described above, the data for Kent and Terrell counties was not used and only 3 of the 4 records for Pecos 

county were used.

After all the QA checks were completed, average county profiles were developed for the 

counties for which natural gas composition data were available (listed in Table 5-1

above). Both wet and dry natural gas composition averages were calculated. The 

64 counties for which data were available were then grouped by basins (Anadarko, Bend 

Arch-Forth Worth, East Texas, Permian, and Western Gulf Basins). Basin-level average 

natural gas composition (wet and dry) profiles were calculated for all the basins where 

data was available at county level. No data were available for counties in Marathon 

Thrust Belt Basin and Palo Duro Basin. Table 5-2 lists the counties in Marathon Thrust 

Belt Basin and Palo Duro Basin. 

Table 5-2. List of Counties Located in Marathon Thrust Belt Basin and Palo 

Duro Basin

Basin Counties

Marathon Thrust Belt Brewster Terrell

Palo Duro Basin

Armstrong Hale

Bailey Hall

Briscoe Hartley

Castro Lamb

Childress Motley

Collingsworth Oldham

Cottle Parmer

Dallam Potter

Deaf Smith Randall

Donley Swisher

Floyd

Basin-level average natural gas composition profile and state-level average profile were 

then allocated to counties with no data based on which basin the county was located in. 

Except for the counties listed in Table 5-2, basin-level average profiles were allocated to 

all counties with no GLYCalc reports available. For the counties in Marathon Thrust 

Belt and Palo Duro basin, state-level average profile was allocated. Table 5-3 below 
5-4

Table 5-3. Basin-Level and State-Level Average Natural Gas Stream Composition Profiles

Composition in % 

Volume

Anadarko Basin Bend Arch-Fort 

Worth Basin East Texas Basin Permian Basin Western Gulf State Profile

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Water 0.04 0.13 0.01 0.12 0.01 0.12 0.01 0.15 0.01 0.12 0.01 0.12

Carbon Dioxide 0.64 0.65 1.74 1.74 1.72 1.71 0.95 0.90 1.13 1.14 1.43 1.44

Hydrogen Sulfide 0.03 0.03 0.001 0.001 0.0004 0.0004 0.11 0.11 0.0003 0.25 0.03 0.09

Nitrogen 1.35 1.34 1.74 1.73 0.88 0.87 2.14 2.18 0.51 0.49 1.20 1.19

Methane 90.76 90.68 87.91 87.59 91.73 91.49 80.43 78.53 90.07 89.94 88.67 88.36

Ethane 3.99 3.98 5.23 5.21 3.57 3.64 9.02 9.07 4.51 4.51 5.03 5.00

Propane 1.74 1.74 2.14 2.18 1.04 1.06 4.48 5.39 2.04 2.05 2.13 2.21

Isobutane 0.26 0.26 0.31 0.32 0.28 0.29 0.51 0.61 0.48 0.48 0.38 0.40

n-Butane 0.54 0.54 0.62 0.68 0.31 0.32 1.19 1.63 0.51 0.51 0.58 0.64

Isopentane 0.16 0.16 0.20 0.22 0.15 0.17 0.35 0.40 0.24 0.24 0.22 0.23

n-Pentane 0.17 0.17 0.27 0.29 0.11 0.12 0.32 0.44 0.17 0.17 0.20 0.22

Cyclopentane 0.01 0.01 0.03 0.04 0.04 0.04 0.01 0.02 0.03 0.02 0.02 0.03

n-Hexane 0.10 0.06 0.05 0.12 0.05 0.05 0.16 0.18 0.05 0.06 0.06 0.09

Cyclohexane 0.01 0.01 0.04 0.03 0.03 0.03 0.09 0.11 0.05 0.06 0.04 0.05

Other Hexanes 0.14 0.14 0.07 0.06 0.10 0.11 0.24 0.29 0.17 0.15 0.13 0.13

Heptanes 0.06 0.06 0.08 0.08 0.06 0.07 0.14 0.14 0.07 0.09 0.08 0.08

Methylcyclohexane 0.02 0.02 0.02 0.02 0.01 0.02 0.04 0.04 0.04 0.04 0.03 0.04

Benzene 0.01 0.01 0.01 0.01 0.02 0.03 0.07 0.08 0.01 0.02 0.02 0.02

Toluene 0.01 0.01 0.003 0.003 0.01 0.01 0.04 0.04 0.01 0.02 0.01 0.01

Ethylbenzene 0.001 0.001 0.0005 0.001 0.001 0.001 0.01 0.01 0.001 0.002 0.001 0.002

Xylenes 0.003 0.01 0.002 0.003 0.002 0.005 0.01 0.01 0.003 0.01 0.003 0.005

C8+ Heavies 0.04 0.04 0.03 0.03 0.03 0.04 0.07 0.07 0.11 0.11 0.06 0.06
5-5

presents the basin-level and state-level average natural gas stream composition profiles 

for both wet and dry natural gas streams.

Based on the basin and state level average natural gas composition profiles, the methane 

composition varies from 78% to 91%. However, individual GLYCalc reports indicated as 

high as 97.8% methane. Table 5-4 indicates the average natural gas composition profile 

allocation scheme that was adopted for counties where GLYCalc reports were not 

available. Figure 5-1 presents a distribution of methane concentrations across all Texas 

counties. Detailed county-level natural gas composition profile data are presented in 

Attachment D.
5-6

Table 5-4. Average Natural Gas Composition Profile Allocation Scheme

County Profile Allocation Basin County Profile Allocation Basin

Anderson Average County Karnes Average Basin Western Gulf

Andrews Average Basin Permian Basin Kaufman Average Basin East Texas Basin

Angelina Average Basin East Texas Basin Kendall Average Basin

Bend Arch-Fort 

Worth Basin

Aransas Average Basin Western Gulf Kenedy Average County

Archer Average Basin Bend Arch-Fort Worth Basin Kent1 Average Basin Permian Basin

Armstrong Average State Palo Duro Basin Kerr Average Basin

Bend Arch-Fort 

Worth Basin

Atascosa Average County Kimble Average Basin

Bend Arch-Fort 

Worth Basin

Austin Average Basin Western Gulf King Average Basin Permian Basin

Bailey Average State Palo Duro Basin Kinney Average Basin Western Gulf

Bandera Average Basin Bend Arch-Fort Worth Basin Kleberg Average Basin Western Gulf

Bastrop Average County Knox Average Basin

Bend Arch-Fort 

Worth Basin

Baylor Average Basin Bend Arch-Fort Worth Basin La Salle Average Basin Western Gulf

Bee Average Basin Western Gulf Lamar Average Basin East Texas Basin

Bell Average Basin Western Gulf Lamb Average State Palo Duro Basin

Bexar Average Basin Western Gulf Lampasas Average Basin

Bend Arch-Fort 

Worth Basin

Blanco Average Basin Bend Arch-Fort Worth Basin Lavaca Average Basin Western Gulf

Borden Average Basin Permian Basin Lee Average Basin Western Gulf

Bosque Average Basin Bend Arch-Fort Worth Basin Leon Average Basin East Texas Basin

Bowie Average Basin East Texas Basin Liberty Average County

Brazoria Average County Limestone Average Basin East Texas Basin

Brazos Average Basin Western Gulf Lipscomb Average Basin Anadarko Basin

Brewster Average State Marathon Thrust Belt Live Oak Average Basin Western Gulf

Briscoe Average State Palo Duro Basin Llano Average Basin

Bend Arch-Fort 

Worth Basin

Brooks Average County Loving Average Basin Permian Basin

Brown Average Basin Bend Arch-Fort Worth Basin Lubbock Average Basin Permian Basin

Burleson Average Basin Western Gulf Lynn Average Basin Permian Basin

Burnet Average Basin Bend Arch-Fort Worth Basin Madison Average Basin Western Gulf
5-7

Table 5-4. Average Natural Gas Composition Profile Allocation Scheme

County Profile Allocation Basin County Profile Allocation Basin

Caldwell Average County Marion Average Basin East Texas Basin

Calhoun Average Basin Western Gulf Martin Average County

Callahan Average County Mason Average Basin

Bend Arch-Fort 

Worth Basin

Cameron Average Basin Western Gulf Matagorda Average County

Camp Average County Maverick Average Basin Western Gulf

Carson Average County McCulloch Average Basin

Bend Arch-Fort 

Worth Basin

Cass Average County McLennan Average Basin

Bend Arch-Fort 

Worth Basin

Castro Average State Palo Duro Basin McMullen Average Basin Western Gulf

Chambers Average County Medina Average Basin Western Gulf

Cherokee Average Basin East Texas Basin Menard Average Basin

Bend Arch-Fort 

Worth Basin

Childress Average State Palo Duro Basin Midland Average Basin Permian Basin

Clay Average County Milam Average Basin Western Gulf

Cochran Average Basin Permian Basin Mills Average Basin

Bend Arch-Fort 

Worth Basin

Coke Average County Mitchell Average Basin Permian Basin

Coleman Average Basin Bend Arch-Fort Worth Basin Montague Average County

Collin Average Basin Bend Arch-Fort Worth Basin Montgomery Average Basin Western Gulf

Collingsworth Average State Palo Duro Basin Moore Average Basin Anadarko Basin

Colorado Average Basin Western Gulf Morris Average Basin East Texas Basin

Comal Average Basin Western Gulf Motley Average State Palo Duro Basin

Comanche Average Basin Bend Arch-Fort Worth Basin Nacogdoches Average County

Concho Average Basin Bend Arch-Fort Worth Basin Navarro Average Basin East Texas Basin

Cooke Average Basin Bend Arch-Fort Worth Basin Newton Average Basin Western Gulf

Coryell Average Basin Bend Arch-Fort Worth Basin Nolan Average Basin Permian Basin

Cottle Average State Palo Duro Basin Nueces Average County

Crane Average Basin Permian Basin Ochiltree Average Basin Anadarko Basin

Crockett Average County Oldham Average State Palo Duro Basin

Crosby Average Basin Permian Basin Orange Average County

Culberson Average Basin Permian Basin Palo Pinto Average County
5-8

Table 5-4. Average Natural Gas Composition Profile Allocation Scheme

County Profile Allocation Basin County Profile Allocation Basin

Dallam Average State Palo Duro Basin Panola Average County

Dallas Average Basin Bend Arch-Fort Worth Basin Parker Average County

Dawson Average Basin Permian Basin Parmer Average State Palo Duro Basin

De Witt Average County Pecos1 Average County

Deaf Smith Average State Palo Duro Basin Polk Average Basin Western Gulf

Delta Average Basin East Texas Basin Potter Average State Palo Duro Basin

Denton Average County Presidio Average Basin Permian Basin

Dickens Average Basin Permian Basin Rains Average Basin East Texas Basin

Dimmit Average Basin Western Gulf Randall Average State Palo Duro Basin

Donley Average State Palo Duro Basin Reagan Average Basin Permian Basin

Duval Average Basin Western Gulf Real Average Basin

Bend Arch-Fort 

Worth Basin

Eastland Average County Red River Average Basin East Texas Basin

Ector Average Basin Permian Basin Reeves Average Basin Permian Basin

Edwards Average Basin Permian Basin Refugio Average County

El Paso Average Basin Permian Basin Roberts Average Basin Anadarko Basin

Ellis Average Basin Bend Arch-Fort Worth Basin Robertson Average County

Erath Average County Rockwall Average Basin East Texas Basin

Falls Average Basin East Texas Basin Runnels Average Basin

Bend Arch-Fort 

Worth Basin

Fannin Average Basin East Texas Basin Rusk Average County

Fayette Average Basin Western Gulf Sabine Average Basin East Texas Basin

Fisher Average Basin Permian Basin San Augustine Average Basin East Texas Basin

Floyd Average State Palo Duro Basin San Jacinto Average Basin Western Gulf

Foard Average Basin Bend Arch-Fort Worth Basin San Patricio Average County

Fort Bend Average County San Saba Average Basin

Bend Arch-Fort 

Worth Basin

Franklin Average Basin East Texas Basin Schleicher Average Basin Permian Basin

Freestone Average County Scurry Average Basin Permian Basin

Frio Average Basin Western Gulf Shackelford Average Basin

Bend Arch-Fort 

Worth Basin

Gaines Average County Shelby Average Basin East Texas Basin

Galveston Average County Sherman Average Basin Anadarko Basin
5-9

Table 5-4. Average Natural Gas Composition Profile Allocation Scheme

County Profile Allocation Basin County Profile Allocation Basin

Garza Average Basin Permian Basin Smith Average County

Gillespie Average Basin Bend Arch-Fort Worth Basin Somervell Average Basin

Bend Arch-Fort 

Worth Basin

Glasscock Average Basin Permian Basin Starr Average Basin Western Gulf

Goliad Average Basin Western Gulf Stephens Average Basin

Bend Arch-Fort 

Worth Basin

Gonzales Average Basin Western Gulf Sterling Average County

Gray Average County Stonewall Average Basin Permian Basin

Grayson Average Basin Bend Arch-Fort Worth Basin Sutton Average Basin Permian Basin

Gregg Average County Swisher Average State Palo Duro Basin

Grimes Average Basin Western Gulf Tarrant Average County

Guadalupe Average Basin Western Gulf Taylor Average Basin

Bend Arch-Fort 

Worth Basin

Hale Average State Palo Duro Basin Terrell1 Average State Marathon Thrust Belt

Hall Average State Palo Duro Basin Terry Average Basin Permian Basin

Hamilton Average Basin Bend Arch-Fort Worth Basin Throckmorton Average Basin

Bend Arch-Fort 

Worth Basin

Hansford Average County Titus Average Basin East Texas Basin

Hardeman Average Basin Bend Arch-Fort Worth Basin Tom Green Average Basin Permian Basin

Hardin Average County Travis Average Basin Western Gulf

Harris Average County Trinity Average Basin Western Gulf

Harrison Average County Tyler Average Basin Western Gulf

Hartley Average State Palo Duro Basin Upshur Average County

Haskell Average Basin Bend Arch-Fort Worth Basin Upton2 Average County/Average Basin Permian Basin

Hays Average Basin Western Gulf Uvalde Average Basin Western Gulf

Hemphill Average County Val Verde Average Basin Permian Basin

Henderson Average County Van Zandt Average Basin East Texas Basin

Hidalgo Average Basin Western Gulf Victoria Average Basin Western Gulf

Hill Average Basin Bend Arch-Fort Worth Basin Walker Average Basin Western Gulf

Hockley Average Basin Permian Basin Waller Average Basin Western Gulf

Hood Average County Ward Average County

Hopkins Average Basin East Texas Basin Washington Average Basin Western Gulf

Houston Average County Webb Average County
5-10

Table 5-4. Average Natural Gas Composition Profile Allocation Scheme

County Profile Allocation Basin County Profile Allocation Basin

Howard Average Basin Permian Basin Wharton Average Basin Western Gulf

Hudspeth Average Basin Permian Basin Wheeler Average County

Hunt Average Basin East Texas Basin Wichita Average Basin

Bend Arch-Fort 

Worth Basin

Hutchinson Average Basin Anadarko Basin Wilbarger Average County

Irion Average County Willacy Average Basin Western Gulf

Jack Average County Williamson Average Basin Western Gulf

Jackson Average Basin Western Gulf Wilson Average Basin Western Gulf

Jasper Average Basin Western Gulf Winkler Average County

Jeff Davis Average Basin Permian Basin Wise Average County

Jefferson Average County Wood Average Basin East Texas Basin

Jim Hogg Average Basin Western Gulf Yoakum Average Basin Permian Basin

Jim Wells Average Basin Western Gulf Young Average County

Johnson Average County Zapata Average Basin Western Gulf

Jones Average Basin Bend Arch-Fort Worth Basin Zavala Average Basin Western Gulf 1

These counties had GLYCalc reports that were flagged as potential CO2 wells and excluded from further analysis. 2

Upton county had 1 GLYCalc report and that report did not include wet gas stream composition data.
5-11

Figure 5-1. Natural Gas Methane Composition Distribution across Texas 

Counties
Attachment A

Survey Letter
A-1

Dear [Owner/Operator Contact Name]: [Date]

Eastern Research Group (ERG), an independent research organization, is conducting a study on 

condensate storage tank emissions for the Texas Commission on Environmental Quality 

(TCEQ). The purpose of this study is to develop updated county- and region-specific emission 

factors for estimating condensate storage tank emissions for each of the regions in Texas. The 

study results will assist the TCEQ in refining the emission factors used to develop the Texas area 

source oil and gas air emissions inventory.

Condensate tank flashing, working, and breathing emissions of volatile organic compounds 

(VOC) are currently estimated using an emission factor from a 2006 Texas Environmental 

Research Consortium study entitled: “VOC Emissions from Oil and Condensate Storage Tanks”. 

TCEQ uses this emission factor to develop county-level area source VOC emissions estimates 

from condensate tanks at upstream oil and gas operations. To further increase the accuracy of 

the area source inventory, the TCEQ is seeking information from operators to assist in 

development of a refined county-specific condensate tank emission factor.

We are asking for your voluntary participation in this study of emissions from condensate tanks 

at gas wells in Texas that were in production during 2011. The study will involve sharing 

information regarding condensate production and measured or estimated emissions from 

condensate tank(s). Individual wells and tanks do not need to be identified. The information 

your company provides will be used for statistical purposes only in order to develop county-level 

and basin-level estimates and will not be republished or disseminated for other purposes. 

ERG will contact your company via phone to discuss this effort and collect any information you 

are willing to share. We are seeking basin-specific condensate tank emissions information for 

gas wells in the [Insert Basin_Specific_Text]. The specific information we are requesting for 

each condensate tank battery includes:

• County • Control technology

• 2011 VOC emissions • Control efficiency

• 2011 condensate production • API gravity

• Emissions estimation method • Separator pressure

A table on the reverse side of this letter shows the type of data we wish to collect.

We appreciate your assistance in this important study. Questions concerning the scope of this 

study or ERG’s relationship with TCEQ may be directed to the TCEQ Project Manager, Miles 

Whitten, at (512) 239-5479, or via email at miles.whitten@tceq.texas.gov. If you have any 

questions on the technical aspects of the study, please feel free to contact me at (919) 468-7902, 

or via email at stephen.treimel@erg.com.

Sincerely,

Stephen Treimel

Environmental Scientist

Eastern Research Group, Inc.
Attachment B

Survey Materials – Word Table and Excel Spreadsheet
B-1

Operator Name: [Insert Operator_Name]

Basin : [Insert Basin_Name_and_Counties]

County

Condensate 

API 

Gravity 

(degrees)

Separator 

Pressure 

(psig)

2011 

Condensate 

Production 

(bbl)

2011 VOC 

Emissions 

(tons)

Emissions Estimation 

Method

(Testing, E&P Tank, 

Process Simulation 

model, GOR, HARC 

051C, etc.)

Are Emissions 

vented, 

controlled, or 

recovered?

If controlled or 

recovered, 

what 

technology is 

used?

If controlled or 

recovered, 

what is the 

control or 

recovery 

efficiency?
B-2

Texas Commission on Environmental Quality - Condensate Tank Emissions Survey

Instructions: Provide the data listed below for up to ten separate condensate tank batteries located in the counties listed below. To 

avoid biasing the survey results, we ask that you please select the tanks at random from all of your producing wells in this region. 

Operator Name: 

Basin (Counties) : Anadarko basin (Hemphill, Lipscomb, Ochiltree, Roberts, and Wheeler counties). 

County

Condensate 

API Gravity 

(degrees)

Separator 

Pressure 

(psig)

2011 

Condensate 

Production 

(bbl)

2011 VOC 

Emissions

(tons) 

(flashing, 

working, & 

breathing)

Emissions 

Estimation 

Method Are 

Emissions 

vented, 

controlled, 

or 

recovered?

If controlled 

or recovered, 

what 

technology is 

used?

If controlled or 

recovered, 

what is the 

control or 

recovery 

efficiency?

(Testing, E&P 

Tank, Process 

Simulation model, 

GOR, HARC 051C, 

TANKS 4.0, etc)

Completed surveys can be emailed to me at stephen.treimel@erg.com or printed and mailed to: Eastern Research Group, 1600 

Perimeter Park Drive, Morrisville, NC 27560.
Attachment C

Condensate Tank Emissions Data

(Condensate_Tank_Data.xlsx)
Attachment D

County-Level Average Natural Gas Composition Profiles

(NG_Composition_Profiles.xlsx)