ATTACHMENT B

CHARACTERIZATION OF OIL AND GAS PRODUCTION EQUIPMENT 

AND DEVELOP A METHODOLOGY TO ESTIMATE STATEWIDE 

EMISSIONS
ERG No. 0227.03.026 

TCEQ Contract No. 582-7-84003 

Work Order No. 582-7-84003-FY10-26 

Characterization of Oil and Gas Production Equipment and Develop a 

Methodology to Estimate Statewide Emissions 

FINAL REPORT 

TCEQ Contract No. 582-7-84003 

Work Order No. 582-7-84003-FY10-26 

Prepared by: 

Mike Pring, Daryl Hudson, Jason Renzaglia, 

Brandon Smith, and Stephen Treimel 

Eastern Research Group, Inc. 

1600 Perimeter Park Drive 

Morrisville, NC 27560 

Prepared for: 

Martha Maldonado 

Texas Commission on Environmental Quality 

Air Quality Division 

November 24, 2010 
i 

TABLE OF CONTENTS 

Section Page No. 

EXECUTIVE SUMMARY ........................................................................................................iv 

1.0 INTRODUCTION ...................................................................................................... 1-1 

2.0 AVAILABLE EMISSIONS ESTIMATION METHODOLOGY REVIEW................. 2-1 

3.0 IDENTIFICATION OF OIL AND GAS OWNERS/OPERATORS AND SURVEY 

DEVELOPMENT ................................................................................................................... 3-1 

4.0 EMISSIONS CALCULATION METHODOLOGY.................................................... 4-1 

4.1 Compressor Engines ........................................................................................ 4-1 

4.2 Artificial Lift (Pumpjack) Engines ................................................................. 4-15

4.3 Dehydrators ................................................................................................... 4-20 

4.3.1 Dehydrator Flash Vessels and Regenerator Vents ............................... 4-21 

4.3.2 Glyol Regenerator Boilers .................................................................. 4-23 

4.3.3 Dehydrator Emission Control Device ................................................. 4-24 

4.4 Oil and Condensate Storage Tanks................................................................. 4-27 

4.5 Oil and Condensate Loading .......................................................................... 4-30

4.6 Well Completions .......................................................................................... 4-35 

4.7 Wellhead Blowdowns .................................................................................... 4-39 

4.8 Pneumatic Devices......................................................................................... 4-43 

4.9 Fugitive Emissions (Equipment Leaks) .......................................................... 4-47 

4.10 Heaters and Boilers ........................................................................................ 4-51 

5.0 RESULTS................................................................................................................... 5-1 

6.0 FORMATTED TexAER FILES .................................................................................. 6-1 

7.0 CONCLUSIONS AND RECOMMENDATIONS ....................................................... 7-1 

8.0 REFERENCES ........................................................................................................... 8-1 

Appendix A – Task 2 Memorandum 

Appendix B – Task 3 Memorandum 

Appendix C – VOC and PM HAP Speciation Data 

Appendix D – Compressor Engine Workbook 

Appendix E – Texas Oil and Gas Emissions Inventory 

Appendix F – Formatted TexAer Files 
ii 

LIST OF TABLES 

Tables Page No. 

Table E-1. State-wide Emissions Inventory for 2008 by Source Category................................. vii 

Table E-2. State-wide Emissions Inventory for 2008 by County.................................................ix 

Table 1-1. Upstream Oil and Gas Production Source Types..................................................... 1-1 

Table 1-2. State-wide Emissions Inventory for 2008 by Source Category................................ 1-4 

Table 1-3. State-wide Emissions Inventory for 2008 by County .............................................. 1-6 

Table 4-1. Fraction of Wells >1 Year Old................................................................................ 4-3 

Table 4-2. Engine Count by Survey......................................................................................... 4-4 

Table 4-3. Emission Factor Data for Texas Attainment Areas.................................................. 4-6 

Table 4-4. Emission Factor Data for Dallas Nonattainment Areas ........................................... 4-8 

Table 4-5. Emission Factor Data for Houston Nonattainment Areas ........................................ 4-9 

Table 4-6. Average Compression Requirements (Hp-hr/Mscf) .............................................. 4-11 

Table 4-7. Distribution of Compressor Engine Emissions by SCC for Texas Attainment Counties

............................................................................................................................................. 4-13 

Table 4-8. Distribution of Compressor Engine Emissions by SCC for Dallas Nonattainment 

Counties................................................................................................................................ 4-13 

Table 4-9. Distribution of Compressor Engine Emissions by SCC for Houston Nonattainment 

Counties................................................................................................................................ 4-14 

Table 4-10. Compressor Engine SCC Definitions.................................................................. 4-14 

Table 4-11. Common Pumpjack Engine Emission Factors..................................................... 4-18 

Table 4-12. Statewide Emission Factors for VOC, Benzene, Toluene, Ethylbenzene, and Xylene 

from Dehydrator Flash Vessels and Regenerator Vents in Texas ........................................... 4-22 

Table 4-13. Emission Factors for NOx and CO Emissions from Dehydrator Regenerator Boilers

............................................................................................................................................. 4-23 

Table 4-14. Emission Factors for NOx and CO Emissions from Dehydrator Controls (Flares) 4-26 

Table 4-15. Emission Factors for VOC, Benzene, Toluene, Ethylbenzene, and Xylene from Oil 

Storage Tanks and Condensate Storage Tanks in Texas......................................................... 4-29

Table 4-16. Molecular Weight and True Vapor Pressure of Selected Petroleum Liquids........ 4-32 

Table 4-17. Emission Factors for Benzene, Toluene, Ethylbenzene, and Xylene from Oil and 

Condensate Loading in Texas................................................................................................ 4-34 

Table 4-18. 2008 CENRAP Data for Volume of Gas Vented per Completion........................ 4-36 

Table 4-19. 2008 CENRAP Data for Volume of Gas Vented per Blowdown per Wellhead ... 4-40 

Table 4-20. 2008 CENRAP Data for Wellhead Blowdown Frequency................................... 4-41 

Table 4-21. CENRAP Basin-Level Data for Pneumatic Devices at Gas Wells ....................... 4-45 

Table 4-22. AP-42 Emissions Factors for Fugitive Components ............................................ 4-48 

Table 4-23. CENRAP Basin-Level Data for Fugitives at Gas Wells ...................................... 4-49 

Table 4-24. CENRAP Basin-Level Data for Fugitives at Oil Wells ....................................... 4-49 

Table 4-25. AP-42 Emissions Factors for Natural Gas Fired Heaters..................................... 4-53 

Table 4-26. CENRAP Basin-Level Data for Heaters at Gas Wells......................................... 4-55 

Table 4-27. CENRAP Basin-Level Data for Heaters at Oil Wells .......................................... 4-55 

Table 5-1. State-wide Emissions Inventory for 2008 by Source Category................................ 5-2 

Table 5-2. State-wide Emissions Inventory for 2008 by County .............................................. 5-4 

Table 5-3. State-wide Speciated HAP Emissions by Source Category .................................. 5-14 
iii 

List of Acronyms 

Acronym Definition 

BBL Barrels 

CENRAP Central Regional Air Planning Association 

CO Carbon Monoxide 

DFW Dallas-Fort Worth 

EPA U.S. Environmental Protection Agency 

EPRI Electric Power Research Institute

ERG Eastern Research Group 

HAP Hazardous Air Pollutants 

HARC Houston Advanced Research Center 

Hp-Hr Horsepower Hour 

Hp Horsepower 

hr/yr Hours per year 

lbs Pounds 

MMBtu/hr Million British Thermal Units per hour 

MMscf Million standard cubic feet 

Mscf Thousand standard cubic feet 

NEI National Emissions Inventory 

NIF NEI Input Format 

NOx Nitrogen Oxides 

NSCR Non selective catalytic reduction 

NSPS New Source Performance Standard 

PM2.5 particulate matter with an aerodynamic diameter less than or 

equal to 2.5 microns 

PM10 particulate matter with an aerodynamic diameter less than or 

equal to 10 microns 

RVP Reid Vapor Pressure 

SCC Source Classification Code 

scf Standard cubic feet 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

STP Standard temperature and pressure 

TAC Texas Administrative Code 

TCEQ Texas Commission on Environmental Quality 

TERC Texas Environmental Research Consortium 

TexAER Texas Air Emissions Repository 

TOC Total Organic Carbon 

TRC Texas Railroad Commission 

VOC Volatile Organic Compound 
iv 

EXECUTIVE SUMMARY 

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

Work Order No. 582-07-84003-FY10-26 to better identify and characterize area source 

emissions from upstream onshore oil and gas production sites that operated in Texas in 2008, and 

to develop a 2008 base year air emissions inventory from these sites. On an individual basis, 

emissions from any single oil and gas production site are likely minimal as there may only be a 

few pieces of equipment at any one site. This equipment could include storage tanks, 

dehydrators, oil and gas piping, or small natural gas fired engines. However, with over 90,000 

gas wells and 150,000 oil wells in Texas, the cumulative magnitude of these emissions may be 

significant. In particular, due to recent advancements in exploration and production technology 

such as the hydraulic fracturing of natural gas wells, this activity is increasingly taking place in 

populated areas, including ozone nonattainment areas. Therefore, closer scrutiny and evaluation 

of this area source category is warranted. 

 Emissions estimates developed from this inventory project may be used for improved 

input data to photochemical air quality dispersion modeling, emissions sensitivity analyses, State 

Implementation Plan (SIP) development, and other agency activities. 

 The emissions inventory developed under this project addresses area source criteria 

pollutant emissions of volatile organic compounds (VOC), nitrogen oxides (NOx), carbon 

monoxide (CO), particulate matter with an aerodynamic diameter less than or equal to 10 microns 

(PM10), particulate matter with an aerodynamic diameter less than or equal to 2.5 microns 

(PM2.5), and sulfur dioxide (SO2); certain Hazardous Air Pollutant (HAPs) emissions such as 

benzene, toluene, ethylbenzene, and xylene from dehydrators, oil and condensate storage tanks, 

and oil and condensate loading racks; and a variety of HAPs from combustion sources. 

 This study builds on three previous studies ERG conducted for TCEQ to estimate 

emissions from oil and gas exploration and production activities. The first, implemented in 

2007, focused on compiling a state-wide emissions inventory (including both onshore and 

offshore sources) for oil and gas exploration and production for a 2005 base year (TCEQ, 2007). 

The second study, conducted in 2009 for a 2008 base year, focused only on emissions from 

onshore oil and gas well drilling rig engines (TCEQ, 2009). The third study, which was just 
v 

completed, developed an emissions inventory for offshore oil and gas platforms (TCEQ, 2010). 

In contrast, this current study addresses onshore area sources (those not included in the Texas 

point source inventory). Collectively, these studies provide a comprehensive emissions 

inventory from onshore area sources, offshore oil and gas platforms, and onshore drilling rig 

activities. 

 In addition to compiling the emissions inventory, other objectives of this project were to 

identify the emission source types operating at oil and gas production sites, to develop a 

methodology for estimating area source emissions from oil and gas production sites based on the 

oil and gas produced at the county level, to develop survey materials that may be used to obtain 

detailed information needed to estimate emissions, and to identify the producers of oil and gas 

for each county. In conjunction with these activities, an emissions calculator was developed in 

Microsoft Excel that will allow TCEQ to update the emissions inventory for future years by 

providing updated county-level activity data. Finally, the emissions inventory was compiled into 

National Emissions Inventory Input Format (NIF) 3.0 text files for import into the Texas Air 

Emissions Repository (TexAER). 

 ERG was able to compile the 2008 area source emissions inventory from upstream 

onshore oil and gas production sites by obtaining both county-level activity data, and specific 

emissions and emission factor data for each source type. This data was obtained from a variety 

of sources, including existing databases (such as the Texas Railroad Commission (TRC) oil and 

gas production data), point source emissions inventory reports submitted to TCEQ (for 

dehydrators), vendor data (for compression engines and pumpjack engines), and published 

emission factor and activity data from the Houston Advanced Research Center (HARC), the 

Central Regional Air Planning Association (CENRAP), and the U.S. Environmental Protection 

Agency (EPA). 

 Table E-1 presents a state-wide summary of criteria pollutant (and total HAP) emissions 

by source category, and Table E-2 presents a summary of criteria pollutant (and total HAP) 

emissions for each county. As can be seen in these tables, emissions from area source upstream 

oil and gas production sites on a state-wide basis are significant with over 200,000 tons of NOx, 

1,500,000 tons of VOC, and 30,000 tons of HAPs emitted in 2008. The main source of NOx
vi 

emissions are compressor engines, while the main source of VOC and HAP emissions are oil and 

condensate storage tanks. 

 It should be noted that the emission estimates provided in this report were based on 

available data and do not take into account more specific emission information such as countyspecific gas composition data, or the extent that control devices that may be used on certain 

source types (such as well completions) to reduce emissions. More accurate emissions estimates 

would require a comprehensive survey of upstream oil and gas site operators to obtain 

information such as county-level gas composition data, quantification of the use of control 

devices, updated equipment profiles (such as the number and size of heater treaters used on a 

typical well pad), and updated equipment characteristics and counts. 
vii 

Table E-1. State-wide Emissions Inventory for 2008 by Source Category 

SCC Source Category Description 

CO 

(tons/yr) 

NOx

(tons/yr) 

PM10

(tons/yr)

PM2.5

(tons/yr) 

SO2

(tons/yr)

(

2310000330 Artificial Lift 23,169.14 46,369.72 154.04 154.04 9.56 2310011020 Storage Tanks: Crude Oil 22310011100 Heater Treater 9,267.25 11,032.44 838.47 838.47 21.32 2310011201

Tank Truck/Railcar Loading: Crude Oil 

2310011450 Wellhead 12310011501 Fugitives: Connectors 2310011502 Fugitives: Flanges 2310011503 Fugitives: Open Ended Lines 2310011504 Fugitives: Pumps 2310011505 Fugitives: Valves 2310011506 Fugitives: Other 2310020600 Compressor Engines 133.77 464.56 13.58 13.58 0.21 2310021010 Storage Tanks: Condensate 82310021030

Tank Truck/Railcar Loading Condensate 

2310021100 Gas Well Heaters 7,564.83 9,005.75 684.44 684.44 0.04 2310021101

Natural Gas Fired 2-Cycle Lean Burn Compressor Engines <50 Hp 140.52 209.25 9.72 9.72 0.16 

2310021102

Natural Gas Fired 2-Cycle Lean Burn Compressor Engines 50 To 499 Hp 2,907.93 13,776.30 352.37 352.37 5.71 

2310021203

Natural Gas Fired 4-Cycle Lean Burn Compressor Engines 500+ Hp 14,746.41 27,288.73 76.95 76.95 15.94 

2310021301

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines <50 Hp 93.37 1,175.69 3.86 3.86 0.25 
viii 

Table E-1. State-wide Emissions Inventory for 2008 by Source Category (Cont.) 

SCC Source Category Description 

CO 

(tons/yr) 

NOx

(tons/yr) 

PM10

(tons/yr)

PM2.5

(tons/yr) 

SO2

(tons/yr)

(

2310021302

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50 To 499hp 38,988.69 86,462.54 226.24 226.24 14.83 

2310021400 Gas Well Dehydrators 904.59 293.36 2310021402

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50-499hp W/ Nscr 767.55 3,321.00 35.02 35.02 2.05 

2310021403

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 500+ Hp W/ Nscr 29,646.80 47,837.57 175.33 175.33 11.26 

2310021501 Fugitives: Connectors 2310021502 Fugitives: Flanges 2310021503 Fugitives: Open Ended Lines 2310021504 Fugitives: Pumps 2310021505 Fugitives: Valves 2310021506 Fugitives: Other 2310021600 Gas Well Venting 2310121700

Gas Well Completion: All Processes 

2310111700

Oil Well Completion: All Processes 

2310121401 Gas Well Pneumatic Pumps 1

Total: 128,330.85 247,236.91 2,570.01 2,570.01 81.34 1,5
ix 

Table E-2. State-wide Emissions Inventory for 2008 by County 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Anderson 241.28 444.72 5.31 5.31 0.16 2,85Andrews 1,825.99 3,291.18 49.14 49.14 1.57 31,69Angelina 161.97 311.11 2.15 2.15 0.08 62Aransas 165.25 317.00 2.28 2.28 0.09 6,57Archer 614.91 1,088.88 18.74 18.74 0.58 2,7Armstrong 0.00 0.00 0.00 0.00 0.00 Atascosa 321.56 578.81 8.71 8.71 0.27 2,23Austin 127.18 237.83 2.42 2.42 0.07 2,04Bailey 0.00 0.00 0.00 0.00 0.00 Bandera 0.21 0.37 0.01 0.01 0.00 Bastrop 74.21 128.49 2.56 2.56 0.06 1,28Baylor 26.78 47.39 0.82 0.82 0.03 18Bee 581.15 1,101.85 9.42 9.42 0.31 4,7Bell 0.00 0.00 0.00 0.00 0.00 Bexar 531.99 941.46 16.28 16.28 0.51 2,12Blanco 0.00 0.00 0.00 0.00 0.00 Borden 166.31 300.48 4.40 4.40 0.14 4,10Bosque 3.45 6.30 0.08 0.08 0.00 Bowie 5.13 9.25 0.14 0.14 0.00 14Brazoria 207.73 199.95 6.59 6.59 0.28 14,00Brazos 240.26 444.10 5.18 5.18 0.16 3,78Brewster 0.00 0.00 0.00 0.00 0.00 Briscoe 0.00 0.00 0.00 0.00 0.00 Brooks 690.71 1,318.85 10.17 10.17 0.35 16,24Brown 204.73 339.96 8.55 8.55 0.14 1,62Burleson 366.21 669.08 8.80 8.80 0.28 3,88Burnet 0.00 0.00 0.00 0.00 0.00 
x 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Caldwell 676.24 1,197.43 20.61 20.61 0.64 3,45Calhoun 189.99 360.25 3.07 3.07 0.10 7,47Callahan 182.61 321.30 5.76 5.76 0.16 98Cameron 1.68 3.12 0.03 0.03 0.00 Camp 30.41 55.01 0.79 0.79 0.03 25Carson 569.73 1,021.51 15.74 15.74 0.41 1,95Cass 54.95 98.13 1.55 1.55 0.04 66Castro 0.00 0.00 0.00 0.00 0.00 Chambers 84.76 94.63 2.75 2.75 0.11 4,42Cherokee 364.58 682.18 6.78 6.78 0.18 2,9Childress 1.69 2.99 0.05 0.05 0.00 5Clay 231.82 409.65 7.14 7.14 0.21 1,47Cochran 445.16 791.68 13.17 13.17 0.41 6,16Coke 109.55 200.99 2.54 2.54 0.08 1,0Coleman 173.73 295.58 6.51 6.51 0.13 1,36Collin 0.00 0.00 0.00 0.00 0.00 Collingsworth 50.04 76.34 2.77 2.77 0.02 74Colorado 319.38 601.84 5.54 5.54 0.16 4,98Comal 0.00 0.00 0.00 0.00 0.00 Comanche 34.22 53.57 1.76 1.76 0.02 43Concho 72.58 128.12 2.23 2.23 0.06 82Cooke 495.43 884.64 14.25 14.25 0.45 3,46Coryell 0.00 0.00 0.00 0.00 0.00 Cottle 95.67 180.55 1.63 1.63 0.05 2,37Crane 1,739.98 3,208.47 38.61 38.61 1.26 17,27Crockett 2,274.88 4,015.15 68.61 68.61 1.15 28,50Crosby 85.55 151.51 2.61 2.61 0.08 1,05
xi 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Culberson 72.79 137.98 1.20 1.20 0.04 28Dallam 0.00 0.00 0.00 0.00 0.00 Dallas 28.04 80.04 0.21 0.21 0.02 2Dawson 275.48 492.78 7.84 7.84 0.25 5,34Deaf Smith 0.00 0.00 0.00 0.00 0.00 Delta 0.00 0.00 0.00 0.00 0.00 Denton 1,763.52 4,690.36 29.51 29.51 1.14 13,25Dewitt 676.49 1,300.83 9.00 9.00 0.35 11,6Dickens 49.70 88.22 1.49 1.49 0.05 1,44Dimmit 197.89 353.20 5.65 5.65 0.15 2,5Donley 0.53 0.77 0.03 0.03 0.00 Duval 1,111.17 2,101.02 18.70 18.70 0.63 12,89Eastland 285.26 476.94 11.51 11.51 0.18 3,65Ector 1,798.24 3,277.22 44.40 44.40 1.47 26,2Edwards 270.78 492.35 6.60 6.60 0.13 1,37El Paso 0.00 0.00 0.00 0.00 0.00 Ellis 51.17 144.09 0.47 0.47 0.04 5Erath 161.14 295.43 3.68 3.68 0.07 1,55Falls 4.01 7.09 0.12 0.12 0.00 2Fannin 0.00 0.00 0.00 0.00 0.00 Fayette 356.62 659.40 7.64 7.64 0.23 5,60Fisher 107.82 193.50 2.99 2.99 0.09 1,36Floyd 0.42 0.75 0.01 0.01 0.00 Foard 27.94 43.90 1.42 1.42 0.01 4Fort Bend 169.68 171.80 5.51 5.51 0.22 8,07Franklin 69.40 127.99 1.52 1.52 0.05 1,38Freestone 3,821.60 7,289.51 56.95 56.95 1.93 9,85
xii 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Frio 139.12 246.28 4.21 4.21 0.12 1,39Gaines 1,165.52 2,133.47 27.65 27.65 0.92 27,78Galveston 86.46 76.28 2.61 2.61 0.12 17,47Garza 445.72 790.41 13.45 13.45 0.42 6,13Gillespie 0.00 0.00 0.00 0.00 0.00 Glasscock 416.67 761.54 10.00 10.00 0.32 5,43Goliad 731.21 1,386.08 11.85 11.85 0.37 7,85Gonzales 51.40 92.76 1.37 1.37 0.04 57Gray 825.55 1,440.69 27.11 27.11 0.64 4,16Grayson 201.98 365.62 5.22 5.22 0.16 1,70Gregg 1,423.90 2,592.32 34.92 34.92 1.00 10,98Grimes 334.10 638.29 4.87 4.87 0.17 1,26Guadalupe 402.11 711.73 12.29 12.29 0.38 2,57Hale 62.99 114.67 1.57 1.57 0.05 2,69Hall 0.00 0.00 0.00 0.00 0.00 Hamilton 3.12 5.33 0.11 0.11 0.00 3Hansford 377.68 676.20 10.32 10.32 0.17 2,60Hardeman 52.13 92.68 1.54 1.54 0.05 1,23Hardin 258.68 348.83 7.85 7.85 0.30 22,64Harris 176.00 181.67 5.65 5.65 0.23 8,80Harrison 1,879.59 3,514.48 35.19 35.19 0.93 25,38Hartley 39.06 70.27 1.04 1.04 0.02 39Haskell 53.83 95.30 1.64 1.64 0.05 44Hays 0.00 0.00 0.00 0.00 0.00 Hemphill 2,092.63 3,936.72 37.08 37.08 1.03 32,77Henderson 453.75 854.13 7.99 7.99 0.24 2,53Hidalgo 3,264.69 6,276.64 43.49 43.49 1.68 56,55
xiii 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Hill 308.20 597.97 3.53 3.53 0.16 23Hockley 1,004.10 1,795.93 28.58 28.58 0.91 22,0Hood 926.80 1,777.59 12.89 12.89 0.47 9,9Hopkins 20.84 37.79 0.53 0.53 0.02 29Houston 164.62 308.00 3.11 3.11 0.10 1,58Howard 803.87 1,436.74 23.00 23.00 0.73 9,90Hudspeth 0.12 0.17 0.01 0.01 0.00 Hunt 0.00 0.00 0.00 0.00 0.00 Hutchinson 903.43 1,601.32 27.09 27.09 0.72 4,03Irion 531.51 961.89 13.77 13.77 0.40 5,87Jack 646.65 1,121.02 21.80 21.80 0.42 6,70Jackson 303.15 569.09 5.55 5.55 0.17 9,87Jasper 205.58 394.00 2.87 2.87 0.11 6,40Jeff Davis 0.00 0.00 0.00 0.00 0.00 Jefferson 287.19 182.64 8.05 8.05 0.46 55,65Jim Hogg 266.50 500.41 4.83 4.83 0.14 4,02Jim Wells 127.37 226.90 3.61 3.61 0.06 1,57Johnson 4,495.48 12,647.53 43.01 43.01 3.19 5,20Jones 167.32 296.69 5.05 5.05 0.16 1,27Karnes 171.32 323.25 2.95 2.95 0.10 3,45Kaufman 4.50 8.03 0.14 0.14 0.00 6Kendall 0.00 0.00 0.00 0.00 0.00 Kenedy 665.44 1,286.34 8.13 8.13 0.35 4,08Kent 203.51 375.70 4.48 4.48 0.16 4,30Kerr 0.00 0.00 0.00 0.00 0.00 Kimble 2.94 4.50 0.16 0.16 0.00 4King 112.59 198.82 3.47 3.47 0.10 2,0
xiv 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Kinney 0.00 0.00 0.00 0.00 0.00 Kleberg 494.21 948.96 6.71 6.71 0.25 8,84Knox 46.18 81.72 1.41 1.41 0.04 35La Salle 259.22 470.95 6.38 6.38 0.13 4,07Lamar 0.00 0.00 0.00 0.00 0.00 Lamb 15.10 27.13 0.42 0.42 0.01 68Lampasas 0.16 0.20 0.01 0.01 0.00 Lavaca 924.67 1,764.89 13.68 13.68 0.47 12,27Lee 307.30 564.26 7.08 7.08 0.23 2,65Leon 1,079.72 2,070.29 15.01 15.01 0.58 5,73Liberty 331.40 341.24 9.92 9.92 0.45 27,3Limestone 1,393.87 2,655.14 21.17 21.17 0.71 4,37Lipscomb 1,125.34 2,104.13 21.36 21.36 0.58 17,10Live Oak 378.16 709.70 6.91 6.91 0.20 6,80Llano 0.00 0.00 0.00 0.00 0.00 Loving 1,567.71 3,023.10 20.15 20.15 0.89 6,34Lubbock 89.19 158.04 2.71 2.71 0.08 1,82Lynn 18.52 33.00 0.54 0.54 0.02 35Madison 117.26 216.26 2.56 2.56 0.07 1,29Marion 96.78 174.38 2.56 2.56 0.06 1,40Martin 596.73 1,088.02 14.69 14.69 0.49 10,92Mason 0.00 0.00 0.00 0.00 0.00 Matagorda 609.79 1,168.96 8.47 8.47 0.32 19,09Maverick 182.47 323.89 5.42 5.42 0.15 3,7McCulloch 14.65 25.47 0.50 0.50 0.01 10McLennan 8.65 15.30 0.26 0.26 0.01 2McMullen 493.90 900.42 11.92 11.92 0.29 6,02
xv 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Medina 275.72 487.25 8.50 8.50 0.26 1,23Menard 27.00 47.52 0.85 0.85 0.02 26Midland 1,610.04 2,951.97 37.75 37.75 1.27 20,93Milam 218.91 387.83 6.65 6.65 0.21 1,2Mills 0.36 0.51 0.02 0.02 0.00 Mitchell 502.49 890.13 15.28 15.28 0.48 6,64Montague 551.48 987.06 15.59 15.59 0.49 3,44Montgomery 73.56 81.80 2.86 2.86 0.08 2,89Moore 744.02 1,343.19 19.29 19.29 0.40 3,50Morris 0.21 0.37 0.01 0.01 0.00 Motley 3.80 6.72 0.12 0.12 0.00 5Nacogdoches 1,527.76 2,897.04 24.29 24.29 0.77 12,72Navarro 170.24 301.61 5.16 5.16 0.16 1,44Newton 78.50 145.69 1.63 1.63 0.05 1,60Nolan 133.50 240.21 3.63 3.63 0.11 1,93Nueces 605.47 1,127.23 11.99 11.99 0.31 15,74Ochiltree 561.88 1,020.35 13.94 13.94 0.31 5,76Oldham 5.68 10.02 0.17 0.17 0.00 24Orange 67.79 71.25 2.06 2.06 0.09 8,46Palo Pinto 455.72 785.82 15.70 15.70 0.21 7,03Panola 3,784.21 7,052.88 73.18 73.18 1.82 50,36Parker 1,225.52 3,294.01 19.49 19.49 0.80 9,84Parmer 0.00 0.00 0.00 0.00 0.00 Pecos 4,534.56 8,670.50 66.30 66.30 2.63 21,76Polk 415.68 797.76 5.69 5.69 0.22 29,65Potter 350.79 632.33 9.25 9.25 0.21 1,79Presidio 0.00 0.00 0.00 0.00 0.00 
xvi 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Rains 59.61 115.43 0.71 0.71 0.03 3Randall 0.00 0.00 0.00 0.00 0.00 Reagan 1,209.82 2,204.56 29.89 29.89 0.99 11,80Real 1.91 3.34 0.06 0.06 0.00 Red River 9.57 16.96 0.29 0.29 0.01 15Reeves 575.50 1,077.94 10.88 10.88 0.36 3,14Refugio 652.55 1,218.19 12.72 12.72 0.40 9,67Roberts 881.18 1,659.43 15.47 15.47 0.45 15,29Robertson 3,591.03 6,960.37 41.87 41.87 1.90 4,20Rockwall 0.00 0.00 0.00 0.00 0.00 Runnels 145.66 262.06 3.96 3.96 0.12 1,17Rusk 2,394.04 4,447.78 48.27 48.27 1.34 26,42Sabine 2.04 3.67 0.06 0.06 0.00 San Augustine 159.66 309.99 1.77 1.77 0.09 45San Jacinto 182.43 350.28 2.47 2.47 0.09 6,46San Patricio 303.08 570.53 5.36 5.36 0.16 12,72San Saba 0.00 0.00 0.00 0.00 0.00 Schleicher 297.16 521.39 9.30 9.30 0.15 3,97Scurry 920.14 1,696.28 20.52 20.52 0.72 16,74Shackelford 446.66 787.83 13.87 13.87 0.39 2,58Shelby 788.21 1,506.84 11.24 11.24 0.40 4,68Sherman 382.36 689.34 9.93 9.93 0.17 2,22Smith 600.16 1,117.21 11.83 11.83 0.32 6,75Somervell 69.05 132.73 0.93 0.93 0.04 26Starr 1,801.98 3,435.69 27.08 27.08 0.92 39,90Stephens 548.00 962.55 17.22 17.22 0.36 6,02Sterling 507.62 898.57 15.24 15.24 0.35 5,04
xvii 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Stonewall 125.21 222.61 3.72 3.72 0.12 1,64Sutton 1,536.07 2,640.40 53.45 53.45 0.57 14,70Swisher 0.00 0.00 0.00 0.00 0.00 Tarrant 4,070.91 11,441.36 39.54 39.54 2.88 4,92Taylor 92.16 163.25 2.80 2.80 0.09 69Terrell 890.56 1,697.22 13.46 13.46 0.45 4,55Terry 217.93 388.12 6.39 6.39 0.20 5,1Throckmorton 221.50 393.95 6.55 6.55 0.20 1,24Titus 42.19 74.68 1.29 1.29 0.04 50Tom Green 170.07 304.64 4.76 4.76 0.14 1,94Travis 3.37 5.97 0.10 0.10 0.00 Trinity 10.94 19.88 0.27 0.27 0.01 19Tyler 463.76 896.18 5.69 5.69 0.25 57,95Upshur 604.48 1,126.42 11.73 11.73 0.30 10,58Upton 1,602.98 2,998.03 30.90 30.90 1.09 32,83Uvalde 0.20 0.26 0.02 0.02 0.00 Val Verde 210.53 394.38 3.90 3.90 0.10 62Van Zandt 193.81 352.82 4.81 4.81 0.15 1,20Victoria 287.47 535.68 5.67 5.67 0.16 3,29Walker 13.49 24.74 0.31 0.31 0.01 8Waller 88.01 106.67 2.83 2.83 0.11 2,85Ward 1,288.64 2,381.97 28.00 28.00 0.94 9,58Washington 256.76 485.36 4.31 4.31 0.14 2,5Webb 3,123.82 5,806.41 62.66 62.66 1.48 28,27Wharton 692.11 1,309.84 11.43 11.43 0.37 15,98Wheeler 2,223.92 4,231.74 34.40 34.40 1.15 40,67Wichita 1,185.96 2,099.33 36.23 36.23 1.13 5,04
xviii 

Table E-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/y

Wilbarger 174.53 308.95 5.33 5.33 0.17 1,14Willacy 353.53 681.05 4.59 4.59 0.19 8,27Williamson 9.07 16.05 0.28 0.28 0.01 5Wilson 129.98 230.01 3.98 3.98 0.12 75Winkler 917.14 1,698.44 19.52 19.52 0.63 7,8Wise 2,749.59 5,099.17 55.75 55.75 1.35 24,22Wood 239.16 438.82 5.52 5.52 0.18 4,20Yoakum 1,074.18 1,960.14 26.21 26.21 0.88 25,64Young 556.32 978.60 17.57 17.57 0.50 3,39Zapata 4,438.24 8,472.07 65.54 65.54 2.24 13,38Zavala 64.75 114.70 1.94 1.94 0.05 1,0

Total: 128,330.85 247,236.91 2,570.01 2,570.01 81.34 1,568,52
1-1 

1.0 INTRODUCTION 

This study was implemented for the Texas Commission on Environmental Quality 

(TCEQ) to identify and characterize area source emissions from upstream oil and gas production 

sites that operated in Texas in 2008, and to provide county level emission estimates for each of 

these source types. 

 This study was divided into four primary technical work tasks: 

• Identification and review of existing studies pertaining to estimating emissions from oil 

and gas production sites and recommendation of a preferred emission estimation 

approach for each identified emissions source type; 

• Development of survey materials that may be used to obtain detailed information needed 

to estimate emissions, and identification of the producers of oil and gas for each county; 

• Development of a methodology and calculator to estimate county-level emissions from 

each identified source type; and 

• Performance of emissions estimation calculations for a 2008 base year, including the 

preparation of emissions inventory calculation spreadsheets (including activity data and 

emission factors) and documentation of data, procedures, and results in a final project 

report. Additionally, the final emissions inventory was imported into National Emissions 

Inventory Input Format (NIF) 3.0 text files for import into the Texas Air Emissions 

Repository (TexAER). 

 This project required compilation of data for each emission source type found at 

upstream oil and gas production sites. Table 1-1 presents a list of each source type, including 

their associated Source Classification Code (SCC). 

Table 1-1. Upstream Oil and Gas Production Source Types 

SCC Source Category Description 

2310021101 Natural Gas Fired 2-Cycle Lean Burn Compressor Engines <50 Hp 

2310021102 Natural Gas Fired 2-Cycle Lean Burn Compressor Engines 50 TO 499 Hp 

2310020600 Natural Gas Fired 2-Cycle Rich Burn Compressor Engines 

2310021203 Natural Gas Fired 4-Cycle Lean Burn Compressor Engines 500+ Hp 

2310021301 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines <50 Hp 

2310021302 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50 TO 499 Hp 

2310021402 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50-499 Hp W/ NSCR 

2310021403 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 500+ Hp W/ NSCR 

2310000330 Oil and Gas Exploration and Production Artificial Lift Engines 

2310021400 Dehydrators 

2310011020 Oil Storage Tanks 
1-2 

Table 1-1. Upstream Oil and Gas Production Source Types (Cont.) 

SCC Source Category Description 

2310021010 Condensate Storage Tanks 

2310011201 Oil Loading 

2310021030 Condensate Loading 

2310111700 Oil Well Completions 

2310121700 Gas Well Completions 

2310011450 Oil Wellhead Blowdowns 

2310021600 Gas Wellhead Blowdowns 

2310121401 Pneumatic Devices 

2310011505 Fugitives - Oil Well Valves 

2310011504 Fugitives - Oil Well Pumps 

2310011506 Fugitives - Oil Wells Other 

2310011501 Fugitives - Oil Well Connectors 

2310011502 Fugitives - Oil Well Flanges 

2310011503 Fugitives - Oil Well Open Ended Lines 

2310021505 Fugitives - Gas Well Valves 

2310021504 Fugitives - Gas Well Pumps 

2310021506 Fugitives - Gas Wells Other 

2310021501 Fugitives - Gas Well Connectors 

2310021502 Fugitives - Gas Well Flanges 

2310021503 Fugitives - Gas Well Open Ended Lines 

2310011100 Heaters - Oil Wells 

2310021100 Heaters - Gas Wells 

 Section 2 of this report provides a summary of the literature review task undertaken to 

identify existing studies pertaining to oil and gas production area sources. Section 3 provides a 

summary of the efforts implemented to identify oil and gas source operators and owners in each 

county, and the development of survey materials that may be used to obtain detailed information 

needed to estimate emissions. Section 4 presents detailed information on the emissions 

calculation method used for each category, including a discussion of all variables used in the 

emissions calculation and how data for each variable were obtained. The quantitative results of 

this project are presented in Section 5, discussion of preparation of TexAER input files is 

provided in Section 6, conclusions and recommendations based on the results of this project are 

presented in Section 7, and Section 8 provides a reference list of information sources used to 

prepare this report and the emissions inventory. 

 Table 1-2 presents a state-wide summary of criteria pollutant (and total HAP) emissions 

by source category, and Table 1-3 presents a summary of criteria pollutant (and total HAP) 
1-3 

emissions for each county. As can be seen in these tables, emissions in 2008 from this area 

source category on a state-wide basis are significant with over 200,000 tons of NOx, 1,500,000 

tons of VOC, and 30,000 tons of HAP. The main source of NOx emissions are compressor 

engines, while the main source of VOC and HAP emissions are oil and condensate storage tanks. 
1-4 

Table 1-2. State-wide Emissions Inventory for 2008 by Source Category 

SCC Source Category Description 

CO 

(tons/yr) 

NOx

(tons/yr) 

PM10

(tons/yr)

PM2.5

(tons/yr) 

SO2

(tons/yr)

V

(to

2310000330 Artificial Lift 23,169.14 46,369.72 154.04 154.04 9.56 2310011020 Storage Tanks: Crude Oil 282310011100 Heater Treater 9,267.25 11,032.44 838.47 838.47 21.32 2310011201 

Tank Truck/Railcar Loading: Crude Oil 2

2310011450 Wellhead 112310011501 Fugitives: Connectors 2310011502 Fugitives: Flanges 2310011503 Fugitives: Open Ended Lines 2310011504 Fugitives: Pumps 2310011505 Fugitives: Valves 2310011506 Fugitives: Other 12310020600 Compressor Engines 133.77 464.56 13.58 13.58 0.21 2310021010 Storage Tanks: Condensate 862310021030 

Tank Truck/Railcar Loading Condensate 

2310021100 Gas Well Heaters 7,564.83 9,005.75 684.44 684.44 0.04 2310021101 

Natural Gas Fired 2-Cycle Lean Burn Compressor Engines <50 Hp 140.52 209.25 9.72 9.72 0.16 

2310021102 

Natural Gas Fired 2-Cycle Lean Burn Compressor Engines 50 To 499 Hp 2,907.93 13,776.30 352.37 352.37 5.71 

2310021203 

Natural Gas Fired 4-Cycle Lean Burn Compressor Engines 500+ Hp 14,746.41 27,288.73 76.95 76.95 15.94 

2310021301 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines <50 Hp 93.37 1,175.69 3.86 3.86 0.25 
1-5 

Table 1-2. State-wide Emissions Inventory for 2008 by Source Category (Cont.) 

SCC Source Category Description 

CO 

(tons/yr) 

NOx

(tons/yr) 

PM10

(tons/yr)

PM2.5

(tons/yr) 

SO2

(tons/yr)

V

(to

2310021302 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50 To 499hp 38,988.69 86,462.54 226.24 226.24 14.83 

2310021400 Gas Well Dehydrators 904.59 293.36 2310021402 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50-499hp W/ Nscr 767.55 3,321.00 35.02 35.02 2.05 

2310021403 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 500+ Hp W/ Nscr 29,646.80 47,837.57 175.33 175.33 11.26 

2310021501 Fugitives: Connectors 2310021502 Fugitives: Flanges 2310021503 Fugitives: Open Ended Lines 2310021504 Fugitives: Pumps 2310021505 Fugitives: Valves 2310021506 Fugitives: Other 2310021600 Gas Well Venting 2310121700 

Gas Well Completion: All Processes 1

2310111700 

Oil Well Completion: All Processes 1

2310121401 Gas Well Pneumatic Pumps 16

Total: 128,330.85 247,236.91 2,570.01 2,570.01 81.34 1,56
1-6 

Table 1-3. State-wide Emissions Inventory for 2008 by County 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Anderson 241.28 444.72 5.31 5.31 0.16 2,858.2Andrews 1,825.99 3,291.18 49.14 49.14 1.57 31,691.4Angelina 161.97 311.11 2.15 2.15 0.08 629.3Aransas 165.25 317.00 2.28 2.28 0.09 6,574.0Archer 614.91 1,088.88 18.74 18.74 0.58 2,719.0Armstrong 0.00 0.00 0.00 0.00 0.00 0.0Atascosa 321.56 578.81 8.71 8.71 0.27 2,237.2Austin 127.18 237.83 2.42 2.42 0.07 2,040.5Bailey 0.00 0.00 0.00 0.00 0.00 0.0Bandera 0.21 0.37 0.01 0.01 0.00 5.1Bastrop 74.21 128.49 2.56 2.56 0.06 1,286.1Baylor 26.78 47.39 0.82 0.82 0.03 189.3Bee 581.15 1,101.85 9.42 9.42 0.31 4,717.4Bell 0.00 0.00 0.00 0.00 0.00 0.0Bexar 531.99 941.46 16.28 16.28 0.51 2,120.8Blanco 0.00 0.00 0.00 0.00 0.00 0.0Borden 166.31 300.48 4.40 4.40 0.14 4,107.3Bosque 3.45 6.30 0.08 0.08 0.00 17.4Bowie 5.13 9.25 0.14 0.14 0.00 148.7Brazoria 207.73 199.95 6.59 6.59 0.28 14,003.4Brazos 240.26 444.10 5.18 5.18 0.16 3,781.1Brewster 0.00 0.00 0.00 0.00 0.00 5.8Briscoe 0.00 0.00 0.00 0.00 0.00 12.3Brooks 690.71 1,318.85 10.17 10.17 0.35 16,242.0Brown 204.73 339.96 8.55 8.55 0.14 1,626.8Burleson 366.21 669.08 8.80 8.80 0.28 3,881.3
1-7 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Burnet 0.00 0.00 0.00 0.00 0.00 0.0Caldwell 676.24 1,197.43 20.61 20.61 0.64 3,452.6Calhoun 189.99 360.25 3.07 3.07 0.10 7,473.4Callahan 182.61 321.30 5.76 5.76 0.16 983.4Cameron 1.68 3.12 0.03 0.03 0.00 10.2Camp 30.41 55.01 0.79 0.79 0.03 259.2Carson 569.73 1,021.51 15.74 15.74 0.41 1,954.7Cass 54.95 98.13 1.55 1.55 0.04 662.4Castro 0.00 0.00 0.00 0.00 0.00 0.0Chambers 84.76 94.63 2.75 2.75 0.11 4,424.0Cherokee 364.58 682.18 6.78 6.78 0.18 2,911.3Childress 1.69 2.99 0.05 0.05 0.00 57.4Clay 231.82 409.65 7.14 7.14 0.21 1,476.8Cochran 445.16 791.68 13.17 13.17 0.41 6,168.3Coke 109.55 200.99 2.54 2.54 0.08 1,010.2Coleman 173.73 295.58 6.51 6.51 0.13 1,363.8Collin 0.00 0.00 0.00 0.00 0.00 0.0Collingsworth 50.04 76.34 2.77 2.77 0.02 742.6Colorado 319.38 601.84 5.54 5.54 0.16 4,980.6Comal 0.00 0.00 0.00 0.00 0.00 0.0Comanche 34.22 53.57 1.76 1.76 0.02 438.4Concho 72.58 128.12 2.23 2.23 0.06 821.0Cooke 495.43 884.64 14.25 14.25 0.45 3,467.0Coryell 0.00 0.00 0.00 0.00 0.00 3.1Cottle 95.67 180.55 1.63 1.63 0.05 2,376.4Crane 1,739.98 3,208.47 38.61 38.61 1.26 17,274.9
1-8 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Crockett 2,274.88 4,015.15 68.61 68.61 1.15 28,501.9Crosby 85.55 151.51 2.61 2.61 0.08 1,056.1Culberson 72.79 137.98 1.20 1.20 0.04 284.4Dallam 0.00 0.00 0.00 0.00 0.00 0.0Dallas 28.04 80.04 0.21 0.21 0.02 24.6Dawson 275.48 492.78 7.84 7.84 0.25 5,344.5Deaf Smith 0.00 0.00 0.00 0.00 0.00 0.0Delta 0.00 0.00 0.00 0.00 0.00 0.0Denton 1,763.52 4,690.36 29.51 29.51 1.14 13,254.5Dewitt 676.49 1,300.83 9.00 9.00 0.35 11,617.0Dickens 49.70 88.22 1.49 1.49 0.05 1,446.4Dimmit 197.89 353.20 5.65 5.65 0.15 2,515.1Donley 0.53 0.77 0.03 0.03 0.00 15.8Duval 1,111.17 2,101.02 18.70 18.70 0.63 12,897.2Eastland 285.26 476.94 11.51 11.51 0.18 3,654.8Ector 1,798.24 3,277.22 44.40 44.40 1.47 26,211.1Edwards 270.78 492.35 6.60 6.60 0.13 1,377.0El Paso 0.00 0.00 0.00 0.00 0.00 0.0Ellis 51.17 144.09 0.47 0.47 0.04 52.4Erath 161.14 295.43 3.68 3.68 0.07 1,556.9Falls 4.01 7.09 0.12 0.12 0.00 21.4Fannin 0.00 0.00 0.00 0.00 0.00 11.8Fayette 356.62 659.40 7.64 7.64 0.23 5,607.6Fisher 107.82 193.50 2.99 2.99 0.09 1,365.5Floyd 0.42 0.75 0.01 0.01 0.00 2.9Foard 27.94 43.90 1.42 1.42 0.01 414.3
1-9 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Fort Bend 169.68 171.80 5.51 5.51 0.22 8,072.5Franklin 69.40 127.99 1.52 1.52 0.05 1,389.5Freestone 3,821.60 7,289.51 56.95 56.95 1.93 9,858.7Frio 139.12 246.28 4.21 4.21 0.12 1,393.7Gaines 1,165.52 2,133.47 27.65 27.65 0.92 27,788.3Galveston 86.46 76.28 2.61 2.61 0.12 17,475.4Garza 445.72 790.41 13.45 13.45 0.42 6,133.8Gillespie 0.00 0.00 0.00 0.00 0.00 0.0Glasscock 416.67 761.54 10.00 10.00 0.32 5,431.2Goliad 731.21 1,386.08 11.85 11.85 0.37 7,851.7Gonzales 51.40 92.76 1.37 1.37 0.04 578.1Gray 825.55 1,440.69 27.11 27.11 0.64 4,163.8Grayson 201.98 365.62 5.22 5.22 0.16 1,707.0Gregg 1,423.90 2,592.32 34.92 34.92 1.00 10,980.4Grimes 334.10 638.29 4.87 4.87 0.17 1,264.1Guadalupe 402.11 711.73 12.29 12.29 0.38 2,576.4Hale 62.99 114.67 1.57 1.57 0.05 2,698.3Hall 0.00 0.00 0.00 0.00 0.00 0.0Hamilton 3.12 5.33 0.11 0.11 0.00 36.4Hansford 377.68 676.20 10.32 10.32 0.17 2,601.0Hardeman 52.13 92.68 1.54 1.54 0.05 1,230.3Hardin 258.68 348.83 7.85 7.85 0.30 22,648.6Harris 176.00 181.67 5.65 5.65 0.23 8,801.2Harrison 1,879.59 3,514.48 35.19 35.19 0.93 25,383.9Hartley 39.06 70.27 1.04 1.04 0.02 399.5Haskell 53.83 95.30 1.64 1.64 0.05 443.8
1-10 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Hays 0.00 0.00 0.00 0.00 0.00 0.0Hemphill 2,092.63 3,936.72 37.08 37.08 1.03 32,774.7Henderson 453.75 854.13 7.99 7.99 0.24 2,535.1Hidalgo 3,264.69 6,276.64 43.49 43.49 1.68 56,554.9Hill 308.20 597.97 3.53 3.53 0.16 233.6Hockley 1,004.10 1,795.93 28.58 28.58 0.91 22,011.8Hood 926.80 1,777.59 12.89 12.89 0.47 9,914.4Hopkins 20.84 37.79 0.53 0.53 0.02 298.7Houston 164.62 308.00 3.11 3.11 0.10 1,587.9Howard 803.87 1,436.74 23.00 23.00 0.73 9,904.9Hudspeth 0.12 0.17 0.01 0.01 0.00 3.2Hunt 0.00 0.00 0.00 0.00 0.00 0.0Hutchinson 903.43 1,601.32 27.09 27.09 0.72 4,039.6Irion 531.51 961.89 13.77 13.77 0.40 5,877.2Jack 646.65 1,121.02 21.80 21.80 0.42 6,701.9Jackson 303.15 569.09 5.55 5.55 0.17 9,879.6Jasper 205.58 394.00 2.87 2.87 0.11 6,405.7Jeff Davis 0.00 0.00 0.00 0.00 0.00 1.2Jefferson 287.19 182.64 8.05 8.05 0.46 55,659.2Jim Hogg 266.50 500.41 4.83 4.83 0.14 4,021.1Jim Wells 127.37 226.90 3.61 3.61 0.06 1,576.6Johnson 4,495.48 12,647.53 43.01 43.01 3.19 5,209.1Jones 167.32 296.69 5.05 5.05 0.16 1,277.9Karnes 171.32 323.25 2.95 2.95 0.10 3,454.1Kaufman 4.50 8.03 0.14 0.14 0.00 62.8Kendall 0.00 0.00 0.00 0.00 0.00 0.0
1-11 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Kenedy 665.44 1,286.34 8.13 8.13 0.35 4,087.7Kent 203.51 375.70 4.48 4.48 0.16 4,304.1Kerr 0.00 0.00 0.00 0.00 0.00 0.0Kimble 2.94 4.50 0.16 0.16 0.00 41.2King 112.59 198.82 3.47 3.47 0.10 2,010.4Kinney 0.00 0.00 0.00 0.00 0.00 0.0Kleberg 494.21 948.96 6.71 6.71 0.25 8,845.8Knox 46.18 81.72 1.41 1.41 0.04 354.8La Salle 259.22 470.95 6.38 6.38 0.13 4,078.6Lamar 0.00 0.00 0.00 0.00 0.00 0.0Lamb 15.10 27.13 0.42 0.42 0.01 686.8Lampasas 0.16 0.20 0.01 0.01 0.00 4.2Lavaca 924.67 1,764.89 13.68 13.68 0.47 12,277.6Lee 307.30 564.26 7.08 7.08 0.23 2,650.7Leon 1,079.72 2,070.29 15.01 15.01 0.58 5,733.4Liberty 331.40 341.24 9.92 9.92 0.45 27,316.7Limestone 1,393.87 2,655.14 21.17 21.17 0.71 4,377.5Lipscomb 1,125.34 2,104.13 21.36 21.36 0.58 17,104.9Live Oak 378.16 709.70 6.91 6.91 0.20 6,807.9Llano 0.00 0.00 0.00 0.00 0.00 0.0Loving 1,567.71 3,023.10 20.15 20.15 0.89 6,348.5Lubbock 89.19 158.04 2.71 2.71 0.08 1,825.3Lynn 18.52 33.00 0.54 0.54 0.02 350.4Madison 117.26 216.26 2.56 2.56 0.07 1,290.5Marion 96.78 174.38 2.56 2.56 0.06 1,407.0Martin 596.73 1,088.02 14.69 14.69 0.49 10,928.6
1-12 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Mason 0.00 0.00 0.00 0.00 0.00 0.0Matagorda 609.79 1,168.96 8.47 8.47 0.32 19,098.2Maverick 182.47 323.89 5.42 5.42 0.15 3,715.5McCulloch 14.65 25.47 0.50 0.50 0.01 109.6McLennan 8.65 15.30 0.26 0.26 0.01 27.4McMullen 493.90 900.42 11.92 11.92 0.29 6,027.4Medina 275.72 487.25 8.50 8.50 0.26 1,235.7Menard 27.00 47.52 0.85 0.85 0.02 266.8Midland 1,610.04 2,951.97 37.75 37.75 1.27 20,938.2Milam 218.91 387.83 6.65 6.65 0.21 1,216.8Mills 0.36 0.51 0.02 0.02 0.00 6.3Mitchell 502.49 890.13 15.28 15.28 0.48 6,645.6Montague 551.48 987.06 15.59 15.59 0.49 3,448.9Montgomery 73.56 81.80 2.86 2.86 0.08 2,890.5Moore 744.02 1,343.19 19.29 19.29 0.40 3,502.8Morris 0.21 0.37 0.01 0.01 0.00 2.0Motley 3.80 6.72 0.12 0.12 0.00 52.7Nacogdoches 1,527.76 2,897.04 24.29 24.29 0.77 12,723.3Navarro 170.24 301.61 5.16 5.16 0.16 1,444.5Newton 78.50 145.69 1.63 1.63 0.05 1,601.9Nolan 133.50 240.21 3.63 3.63 0.11 1,931.6Nueces 605.47 1,127.23 11.99 11.99 0.31 15,740.1Ochiltree 561.88 1,020.35 13.94 13.94 0.31 5,760.6Oldham 5.68 10.02 0.17 0.17 0.00 247.2Orange 67.79 71.25 2.06 2.06 0.09 8,467.8Palo Pinto 455.72 785.82 15.70 15.70 0.21 7,033.4
1-13 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Panola 3,784.21 7,052.88 73.18 73.18 1.82 50,362.9Parker 1,225.52 3,294.01 19.49 19.49 0.80 9,840.7Parmer 0.00 0.00 0.00 0.00 0.00 0.0Pecos 4,534.56 8,670.50 66.30 66.30 2.63 21,760.8Polk 415.68 797.76 5.69 5.69 0.22 29,650.9Potter 350.79 632.33 9.25 9.25 0.21 1,799.2Presidio 0.00 0.00 0.00 0.00 0.00 0.0Rains 59.61 115.43 0.71 0.71 0.03 38.4Randall 0.00 0.00 0.00 0.00 0.00 0.0Reagan 1,209.82 2,204.56 29.89 29.89 0.99 11,808.6Real 1.91 3.34 0.06 0.06 0.00 16.7Red River 9.57 16.96 0.29 0.29 0.01 159.7Reeves 575.50 1,077.94 10.88 10.88 0.36 3,146.2Refugio 652.55 1,218.19 12.72 12.72 0.40 9,671.0Roberts 881.18 1,659.43 15.47 15.47 0.45 15,296.5Robertson 3,591.03 6,960.37 41.87 41.87 1.90 4,202.1Rockwall 0.00 0.00 0.00 0.00 0.00 0.0Runnels 145.66 262.06 3.96 3.96 0.12 1,177.5Rusk 2,394.04 4,447.78 48.27 48.27 1.34 26,428.9Sabine 2.04 3.67 0.06 0.06 0.00 19.2San Augustine 159.66 309.99 1.77 1.77 0.09 452.6San Jacinto 182.43 350.28 2.47 2.47 0.09 6,462.6San Patricio 303.08 570.53 5.36 5.36 0.16 12,721.0San Saba 0.00 0.00 0.00 0.00 0.00 0.0Schleicher 297.16 521.39 9.30 9.30 0.15 3,975.1Scurry 920.14 1,696.28 20.52 20.52 0.72 16,745.6
1-14 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Shackelford 446.66 787.83 13.87 13.87 0.39 2,584.6Shelby 788.21 1,506.84 11.24 11.24 0.40 4,681.4Sherman 382.36 689.34 9.93 9.93 0.17 2,226.5Smith 600.16 1,117.21 11.83 11.83 0.32 6,759.0Somervell 69.05 132.73 0.93 0.93 0.04 261.3Starr 1,801.98 3,435.69 27.08 27.08 0.92 39,905.7Stephens 548.00 962.55 17.22 17.22 0.36 6,028.2Sterling 507.62 898.57 15.24 15.24 0.35 5,045.8Stonewall 125.21 222.61 3.72 3.72 0.12 1,647.7Sutton 1,536.07 2,640.40 53.45 53.45 0.57 14,703.0Swisher 0.00 0.00 0.00 0.00 0.00 0.0Tarrant 4,070.91 11,441.36 39.54 39.54 2.88 4,929.9Taylor 92.16 163.25 2.80 2.80 0.09 693.0Terrell 890.56 1,697.22 13.46 13.46 0.45 4,554.0Terry 217.93 388.12 6.39 6.39 0.20 5,118.1Throckmorton 221.50 393.95 6.55 6.55 0.20 1,242.0Titus 42.19 74.68 1.29 1.29 0.04 506.6Tom Green 170.07 304.64 4.76 4.76 0.14 1,945.3Travis 3.37 5.97 0.10 0.10 0.00 14.4Trinity 10.94 19.88 0.27 0.27 0.01 193.3Tyler 463.76 896.18 5.69 5.69 0.25 57,953.3Upshur 604.48 1,126.42 11.73 11.73 0.30 10,582.5Upton 1,602.98 2,998.03 30.90 30.90 1.09 32,833.5Uvalde 0.20 0.26 0.02 0.02 0.00 4.3Val Verde 210.53 394.38 3.90 3.90 0.10 620.7Van Zandt 193.81 352.82 4.81 4.81 0.15 1,204.5
1-15 

Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Victoria 287.47 535.68 5.67 5.67 0.16 3,296.0Walker 13.49 24.74 0.31 0.31 0.01 85.2Waller 88.01 106.67 2.83 2.83 0.11 2,859.2Ward 1,288.64 2,381.97 28.00 28.00 0.94 9,588.8Washington 256.76 485.36 4.31 4.31 0.14 2,513.6Webb 3,123.82 5,806.41 62.66 62.66 1.48 28,275.4Wharton 692.11 1,309.84 11.43 11.43 0.37 15,986.4Wheeler 2,223.92 4,231.74 34.40 34.40 1.15 40,674.0Wichita 1,185.96 2,099.33 36.23 36.23 1.13 5,040.0Wilbarger 174.53 308.95 5.33 5.33 0.17 1,147.9Willacy 353.53 681.05 4.59 4.59 0.19 8,274.5Williamson 9.07 16.05 0.28 0.28 0.01 53.2Wilson 129.98 230.01 3.98 3.98 0.12 757.5Winkler 917.14 1,698.44 19.52 19.52 0.63 7,815.4Wise 2,749.59 5,099.17 55.75 55.75 1.35 24,225.5Wood 239.16 438.82 5.52 5.52 0.18 4,200.3Yoakum 1,074.18 1,960.14 26.21 26.21 0.88 25,649.4Young 556.32 978.60 17.57 17.57 0.50 3,394.2Zapata 4,438.24 8,472.07 65.54 65.54 2.24 13,384.8Zavala 64.75 114.70 1.94 1.94 0.05 1,016.7

Total: 128,330.85 247,236.91 2,570.01 2,570.01 81.34 1,568,522.7
2-1 

2.0 AVAILABLE EMISSIONS ESTIMATION METHODOLOGY 

REVIEW

 One of the objectives of this project was to conduct a literature review of available 

studies, reports, and research activities relevant to the development of a 2008 base year area 

source emissions inventory for upstream oil and gas production sites. From this review, a 

preferred emission estimation approach for each category was selected. In the project Work 

Plan, this work was referred to as Task 2. The existing studies which were reviewed, and a 

summary of the available and recommended emission estimation approaches for each source 

type were presented in a memo submitted to TCEQ on April 26, 2010. This memo included 

summaries of the data required to implement the preferred approach, and ERG’s 

recommendations how best to obtain the needed data. In addition, any data gaps identified that 

impacted the ability to develop a 2008 inventory estimate for each source type were described 

and possible methods for addressing the data gaps (through the use of existing or default data) 

were presented. 

 Appendix A contains a copy of this memo summarizing the activities conducted under 

this part of the project. 
3-1 

3.0 IDENTIFICATION OF OIL AND GAS OWNERS/OPERATORS AND 

SURVEY DEVELOPMENT 

 As mentioned above, one of the objectives of this project was the development of survey 

materials that may be used to obtain the detailed, source-specific data needed to estimate countylevel emissions for each source type. Additionally, identification of the producers of oil and gas 

for each county was needed to assist in possible future implementation of a field survey to obtain 

the required data. In the project Work Plan, this work was referred to as Task 3. Both of these 

objectives were met and this information was provided to TCEQ in a memo submitted on July 9, 

2010. 

 Appendix B contains a copy of this memo summarizing the activities conducted under 

this part of the project. 
4-1 

4.0 EMISSIONS CALCULATION METHODOLOGY 

 This section presents a discussion of each source type included in the 2008 baseline area 

source emissions inventory of upstream oil and gas production sites. Each source type is 

discussed separately, including a process description, a description of the emissions estimation 

methodology used to calculate emissions, a description of the derivation of all activity data and 

input parameters used in the calculation, presentation of all data used in the calculation, the 

equations used to calculate emissions for each source type, and an example calculation for each 

source type. 

4.1 Compressor Engines 

 Natural gas fueled spark-ignited internal combustion engines are normally used to drive 

gas field compressors. The compressors are used to boost the pressure of well-head natural gas 

so that it can be injected into higher pressure gathering lines. These compressor engines burn 

well-head natural gas and can represent a significant NOx area emissions source category as they 

generally operate 8,760 hours per year with minimum down-time. 

 Emissions from compressor engines were calculated using a methodology similar to that 

employed in the Houston Advanced Research Council’s (HARC) study “Natural Gas 

Compressor Engine Survey and Engine NOx Emissions at Gas Production Facilities” (HARC, 

2005).1 For this 2008 inventory, the calculation methodology uses annual natural gas production 

by county along with vender-derived county-level emission factors to determine emissions from 

compressor engines at gas production facilities. ERG combined engine data from the HARC 

study with two 2007 TCEQ engine surveys conducted on the counties located in the Dallas -

Forth Worth (DFW) metropolitan area and Southeast Texas. The two TCEQ surveys were 

completed as efforts to amend the state clean air plan for ozone. Engine operators reported 

engine models and sizes, and other data to TCEQ. Using these data, ERG calculated countylevel emissions from compressor engines with the following equation: 

 

1

 The HARC 2005 report was updated in 2006 to include more engine size categories and to add the year 2000 to the 

previous inventory; however, these updates did not change the calculation methodology used in the original 2005 

report. 
4-2 

where: 

Eik is the emissions for county i, and pollutant k [tons/yr] 

TGPi is the total gas production in county i [Mscf/yr] 

F1i is the fraction of wells requiring compression in county i 

F2j is the fraction of compression load represented by engines of type j 

EFjk is the emission factor for engine type j, and pollutant k [g/Hp-hr]

Ci is the compression requirements for county i [Hp-hr/Mscf] 

907,180 is the conversion factor from grams to tons of emissions 

Total gas production in county i, TGPi:

 Natural gas production data by county (TGPi) was provided for 2008 by the TRC for 241 

counties. Burnet, Castro, Collin, Comal, Dallam, Deaf Smith, Delta, El Paso, Gillespie, Hall, 

Kendall, Lamar, Llano, Mason, Parmer, Presidio, Randall, San Saba, and Swisher counties had 

no gas or oil production in 2008. 

Fraction of wells requiring compression in county i, F1i:

 Upon initial well completion, not all wells require compression. Therefore, the fraction 

of wells requiring compression (F1i) was estimated in the HARC study as the fraction of active 

wells greater than one year old. Using the same assumption for this 2008 inventory, ERG 

determined the fraction of wells active in 2008 that were greater than one year old using the 

following equation: 

















> = −

(TotalActive Wells on February 5, 2008)

(Wells Completed in 2007) Fraction of Wells 1Year Old 1 

 For each Texas Railroad Commission (TRC) District, results are shown in Table 4-1. 

ERG determined the number of wells completed in 2007 using TRC annual drilling, completion, 

and plugging summaries which are available at: 

http://www.rrc.state.tx.us/data/drilling/drillingsummary/index.php. Total active wells by district 

for January 1, 2008 are not readily available from the TRC website; therefore, in order to 

determine total active wells, ERG used gas well distribution data showing the number of regular 

producing gas wells by county. Gas well distribution data by county is only available from the 

TRC website on a bi-annual (February and September) basis and can be found at: 















 ∗ ∗ ∗

= ×

907,180

1i 2 j jk i

ik i

F F EF C

E TGP
4-3 

http://www.rrc.state.tx.us/data/wells/wellcount/index.php. Using the February 2008 TRC report, 

ERG summed the county specific numbers for regular producing gas wells by TRC district. 

 The fraction of wells greater than one year old are likely to be slightly different than what 

is shown below because each well that was completed in 2007 could have been completed on 

any day of that year. Using the methodology explained above, ERG has assumed that all wells 

completed in 2007 were completed on February 5, 2007. ERG applied the fractions shown in the 

Table 4-1 to the counties in each respective district. 

Table 4-1. Fraction of Wells >1 Year Old 

TRC 

District 

Wells Completed 

in 2007 

Total Active Wells 

on February 5, 2008 

Fraction of Wells 

>1 Year Old (F1i) 

1 176 2,513 0.9300 

2 515 3,293 0.8436 

3 317 3,977 0.9203 

4 1,070 13,098 0.9183 

5 644 7,008 0.9081 

6 1,957 13,706 0.8572 

7B 121 6,769 0.9821 

7C 947 13,101 0.9277 

8 225 3,909 0.9424 

8A 36 265 0.8642 

9 1,781 7,739 0.7699 

10 854 12,647 0.9325 

Total 8,643 88,025 0.9018 

Fraction of compression load represented by engines of type j, F2j:

 Fraction of compression load by engine type (F2j) was determined by the HARC report 

for eight engine types (i.e. 2-cycle lean, 50-499 Hp; 4-cycle lean, 50-499 Hp; etc.) in three areas 

categorized by their attainment status, including the Texas attainment areas, the Houston 

nonattainment area, and the Dallas nonattainment area. For this 2008 inventory, in an effort to 

achieve more accurate emissions data results, ERG combined data from the two 2007 TCEQ 

engine surveys with the HARC survey data and determined the distribution or fraction of 

compression load by engine type for the most reported engines (comprising 80% of the 

population) for each of the three categories used in the HARC report. 
4-4 

 In order to prevent duplication, 103 engines from the HARC study were removed prior to 

combining the data with the two 2007 TCEQ engine surveys. These engines were removed 

because they were located in thirteen counties (Austin, Ellis, Hardin, Houston, Jasper, Jefferson, 

Newton, Polk, San Augustine, San Jacinto, Trinity, Tyler, and Walker) that overlapped with the 

2007 survey data. The 2007 data had a greater population (335) of engines for these counties 

than the HARC study. ERG also removed the following engines from the two 2007 TCEQ 

engine survey data sets: 

• Fifty-five engines from the DFW survey and two engines from the Southeast survey that 

lacked engine characteristic data; 

• Two engines from the HARC study that were labeled as electric motors; 

• Three engines from the HARC study that were identified as not being located at a gas 

well; and 

• One engine from the DFW survey identified as no longer operational. 

 After combining the data sets (and removing certain engines as discussed above), a total 

of 2,880 engines were included for the analysis as detailed in Table 4-2 below. 

Table 4-2. Engine Count by Survey 

Specific Survey Number of Engines 

HARC Survey 1,252 

2007 TCEQ DFW Survey 1,321 

2007 TCEQ SE Survey 307 

Total 2,880 

 In order to ensure engines were grouped appropriately, ERG performed extensive internet 

research as well as phone interviews with engine manufactures to standardize engine make and 

model naming conventions. Additionally, some assumptions were made such as all Caterpillar 

engines reported in the survey data are natural gas fired (many respondents had reported engine 

models without using the term “G” in front of the model number which defines the engine as a 

natural gas fired engine). ERG also assumed that any potential (future) engines identified in the 

2007 DFW survey would be located in the Dallas nonattainment area. Minor gap-filling was 

also performed on the combined dataset which included completing any empty “Engine Cycle (2 

or 4)” data fields based on the known engine make and model. 

 Using the combined dataset, ERG determined an average size (horsepower) for each 

specific engine model and then calculated the fraction of compression load by engine type (F2j) 
4-5 

for three categories (Texas attainment areas, the Dallas nonattainment area, and the Houston 

nonattainment area) as shown in Tables 4-3 through 4-5. Due to minimal engine data in the 

Jefferson, Hardin, and Orange nonattainment counties, these counties were combined into the 

Houston nonattainment area. 

Emission factor for engine type j, and pollutant k, EFjk:

 Emission factors for each unique engine make and model (based on approximately the 

top 80% most reported engines in each of the three attainment status categories) are shown in 

Tables 4-3 through 4-5. The NOx, CO, and VOC emission factors for the engines located in 

attainment counties (Table 4-3) were each determined through extensive internet research as well 

as phone interviews with specific engine manufactures. Manufacture emissions data was 

averaged across all performance data given for a specific engine. 

 NOx emission factors for the engines located in nonattainment counties (Table 4-5) are 

based on Texas’s rules for the Houston-Galveston-Brazoria eight-hour ozone nonattainment area 

(30 TAC, Chapter 117, Subchapter D, Division 1 and 2). These rules regulate certain minor 

sources of NOx, including some stationary, gas-fired reciprocating internal combustion engines. 

Considering the Houston-Galveston-Brazoria rule, all stationary, gas-fired reciprocating internal 

combustion engines greater than 50 horsepower are restricted to 0.5 g/Hp-hr. Considering the 

Dallas-Fort Worth rule, rich burn engines greater than 50 horsepower are restricted to 0.5 g/Hphr, lean burn engines installed or moved before June 1, 2007 are limited to 0.7 g/Hp-hr, and lean 

burn engines installed or moved after June 1, 2007 are limited to 0.5 g/Hp-hr. ERG calculated 

that ~16% percent of lean burn engines operating in DFW counties in 2008 could have 

potentially been installed after June 1, 2007. Therefore, an adjusted NOx emission factor of 0.67 

g/Hp-hr [(0.50 * .16) + (0.70 * .84)] was applied to any lean burn engines in Table 4-4. 

However, the compliance date for the Dallas-Fort Worth rule was not until after 2008, therefore 

the attainment area NOx emission factor in Table 4-3 was used for these counties for this 2008 

base year inventory. 

 CO and VOC emission factors for the engines located in nonattainment counties (Tables 

4-4 and 4-5) were determined through extensive internet research as well as phone interviews 

with specific engine manufactures. However, ERG assumed any four stroke rich burn engine, 

greater than 50 Hp and located in a nonattainment area, would have non-selective catalytic 
4-6 

Table 4-3. Emission Factor Data for Texas Attainment Areas 

Emission Fact

Engine Make & Model SCC 

Number of 

Engines 

[Lean / Rich] 

Engine 

Horsepower 

(Hp) 

Compression 

Load by Engine 

Type (F2j) 

Fuel Consumption 

(MMBtu/Hp-hr) PM NOx 

CAT G3306 NA 2310021302 0 / 165 145 8.98% 0.007775 3.35E-02 13.48 1CAT G3304 NA 2310021302 0 / 130 95 4.64% 0.007567 3.26E-02 21.08 

Wauk VRG330 2310021302 0 / 107 68 2.73% 0.008038 3.46E-02 12.951 1

CAT G3306 TA 2310021302 0 / 67 203 5.11% 0.008098 3.49E-02 16.57 1

Wauk F817 G 2310021302 0 / 42 87 1.37% 0.007253 3.13E-02 16.0 

AJAX DPC-60 2310021102 39 / 0 58 0.85% 0.009000 1.57E-01 4.4 

AJAX DPC-115 2310021102 /2310020600 31 / 2 110 1.36% 0.009000 1.57E-01 4.4 

Wauk F1197 G 2310021302 0 / 32 183 2.20% 0.007253 3.13E-02 20.0 

CAT G3406 NA (3) 2310021302 0 / 31 290 3.37% 0.007407 3.19E-02 23.2267 

CAT G3516 TALE 2310021203 30 / 0 1245 14.02% 0.007365 2.58E-04 2.0 1

CAT G3306 NA HCR (4) 2310021302 0 / 29 145 1.58% 0.007775 3.35E-02 13.48 1

AJAX DPC-360 2310021102 /2310020600 27 / 1 346 3.64% 0.008400 1.46E-01 6.3 AJAX DPC-180 2310021102 28 / 0 173 1.82% 0.008400 1.46E-01 6.3 AJAX DPC-140 2310021102 26 / 0 134 1.31% 0.008200 1.43E-01 10.5 AJAX DPC-280 2310021102 25 / 0 269 2.52% 0.008200 1.43E-01 11.4 

Wauk VRG220 (5) 2310021301 0 / 24 45 0.41% 0.008038 3.46E-02 12.951 1

AJAX DPC-80 2310021102 22 / 0 77 0.64% 0.008900 1.55E-01 4.4 

CAT G342 NA (6) 2310021302 0 / 21 225 1.77% 0.008588 3.70E-02 0.101 0

AJAX C-42 2310021101 /2310020600 19 / 1 40 0.30% 0.009900 1.72E-01 4.4 

GEMINI G26 2310021301 0 / 19 26 0.19% 0.008038 3.46E-02 12.951 1

Wauk L7042 GL (7) 2310021203 19 / 0 1357 9.68% 0.007238 2.53E-02 1.0 

CAT G342 TA (6) 2310021302 0 / 16 225 1.35% 0.008588 3.70E-02 0.101 0

Wauk VRG310 (5) 2310021302 0 / 16 68 0.41% 0.008038 3.46E-02 12.951 1

CAT G399 TA (10) 2310021403 0 / 16 802 4.82% 0.008710 3.75E-02 0.7756 0

Wauk L7042 GSI (10) 2310021403 0 / 15 1357 7.64% 0.007558 3.26E-02 1.6 

CAT G398 TA (9, 10) 2310021403 0 / 15 605 3.41% 0.008710 3.75E-02 0.7756 0

CAT G3406 TA 2310021302 0 / 14 290 1.52% 0.007407 3.19E-02 23.2267 

CAT G3512 TALE 2310021203 14 / 0 932 4.90% 0.007385 2.58E-04 2.0 

CAT G3406 (11) 2310021302 0 / 14 290 1.52% 0.007407 3.19E-02 23.2267 

Wauk L7042 G (10) 2310021403 0 / 14 961 5.05% 0.007180 3.09E-02 1.6 
4-7 

Table 4-3. Emission Factor Data for Texas Attainment Areas (Cont.) 

Emission Fact

Engine Make & Model SCC 

Number of 

Engines 

[Lean / Rich] 

Engine 

Horsepower 

(Hp) 

Compression 

Load by Engine 

Type (F2j) 

Fuel Consumption 

(MMBtu/Hp-hr) PM NOx 

AJAX DPC-230 2310021102 /2310020600 10 / 1 221 0.91% 0.008700 1.52E-01 4.4 

TOTAL -- 1082 -- 100% Weighted Average EFs 0.04 7.57 

1. Non-Methane Hydrocarbon. 2. Total Hydrocarbon. 3. There is no emission factor data available distinguishing CAT G4306 NA from G3406 TA, thus it was assumed that emission factors were the same for both models. 

4. There is no emission factor data available distinguishing CAT G3306 NA HCR from G3306 NA, thus it was assumed that emission factors were the same for both models. 

5. Based on discussions with Waukesha, the VRG220 and VRG310 models have the same emission factors as the VRG330. 

6. Emissions data based on AP-42 background document with no HAP control. Emission factor data did not differentiate between a G342 TA or NA engine, thus same emission factor

7. No emission factor data could be found for this engine. Because it is a 4-stroke and has similar horsepower to the Wauk VRG220, it was assumed that emission factors were the sam

8. Assumed to be equal to CAT G342 NA. 9. No emission factor data could be found for this engine. Since it is a similar model manufactured in the same time period, it was assumed that emission factors were the same as CAT 10. Engines are documented as having non-selective catalytic reduction (NSCR) control technology. ERG has applied a 90% reduction to the emission factors for CO and VOC for th

11. There is some ambiguity in the survey data as to whether this engine is a CAT G3406 NA or TA; however, the emissions are the same for the G3406 TA and NA versions. 
4-8 

Table 4-4. Emission Factor Data for Dallas Nonattainment Areas 

Emission F

Engine Make & Model SCC 

Number of 

Engines 

[Lean / Rich] 

Engine 

Horsepower 

(Hp) 

Fraction of 

Compression 

Load by 

Engine Type 

(F2j) 

Fuel 

Consumption 

(MMBtu/Hp-hr) PM NOx (1) 

CAT G3306 NA 2310021402 0 / 281 145 6.10% 0.007775 3.35E-02 0.50 

CAT G3304 NA HCR (2) 2310021402 0 / 72 95 1.02% 0.007567 3.26E-02 0.50 

Cummins G8.3 2310021402 0 / 64 112 1.07% 0.008228 3.55E-02 0.50 

CAT G3516 TALE 2310021203 60 / 0 1245 11.18% 0.007364 2.58E-04 0.67 

CAT G3606 TALE LCR (4) 2310021203 59 / 0 1835 16.21% 0.006612 2.31E-04 0.67 

CAT G3306 NA HCR (5) 2310021402 0 / 58 145 1.26% 0.007775 3.35E-02 0.50 

Wauk L7044 GSI 2310021403 0 / 50 1540 11.53% 0.007665 3.30E-02 0.50 Wauk L5794 GSI 2310021403 0 / 49 1265 9.28% 0.007430 3.20E-02 0.50 

CAT G3304 NA 2310021402 0 / 46 95 0.65% 0.007567 3.26E-02 0.50 

Wauk L7042 GSI 2310021403 37 / 0 1357 7.52% 0.007557 2.64E-04 0.67 

CAT G3516 2310021203 0 / 29 1050 4.56% 0.007700 3.32E-02 0.50 

CAT G3516 TALE AFRC (7) 2310021203 29 / 0 1245 5.41% 0.007364 2.58E-04 0.67 

Cummins 8.3 GTA 2310021402 0 / 28 183 0.77% 0.007380 3.18E-02 0.50 

CAT G3608 TALE 2310021203 28 / 0 2408 10.09% 0.006592 2.31E-04 0.67 CAT G3606 TALE 2310021203 26 / 0 1835 7.14% 0.006612 2.31E-04 0.67 

Cummins G5.9 2310021402 0 / 25 84 0.31% 0.007914 3.41E-02 0.50 

AJAX DPC-180 2310021102/ 2310020600 7 / 17 173 0.62% 0.008400 1.46E-01 0.55 CAT G3306 TA 2310021402 0 / 19 203 0.58% 0.008098 3.49E-02 0.50 

CAT G3508 TALE 2310021203 17 / 0 670 1.71% 0.007510 2.63E-04 0.67 CAT G3512 TALE 2310021203 17 / 0 932 2.37% 0.007385 2.58E-04 0.67 

AJAX DPC-140 2310021102/ 2310020600 3 / 11 134 0.28% 0.008200 1.43E-01 0.54 AJAX DPC-115 2310021102/ 2310020600 5 / 8 110 0.21% 0.009000 1.57E-01 0.57 

Wauk VRG330 2310021402 0 / 12 68 0.12% 0.008038 3.46E-02 0.50 

TOTAL -- 1048 -- 100% Weighted Average EFs 0.02 7.57 

1. ERG assumed any four stroke rich burn engine, greater than 50 Hp and located in a nonattainment area, would have non-selective catalytic reduction (NSCR) control technoto the emission factors for CO and VOC for these engines. As the compliance date for 30 TAC, Chapter 117, Subchapter D Division 2 is not until after 2008, the attainment ar2. There is no emission factor data available distinguishing CAT G3304 NA HCR from G3304 NA, thus it was assumed that emission factors were the same for both models. 

3. Non-Methane Hydrocarbon. 4. There is no emission factor data available distinguishing CAT G3606 TALE LCR from G3606 TALE, thus it was assumed that emission factors were the same for both mod

received from the 2007 DFW survey reported the CAT G3606 TALE LCR model has a rich burn engine; based on further research, ERG determined that this engine is a lean 5. There is no emission factor data available distinguishing CAT G3306 NA HCR from G3306 NA, thus it was assumed that emission factors were the same for both models. 

6. Value is estimated because no data is available.7. There is no emission factor data available for this model engine with an air fuel ratio control, thus emission factors were assumed to be the same as the CAT G3516 TALE. engines were reported as rich burn in the data received from the 2007 DFW survey; however, based on further research, ERG determined that this engine can only be a lean bu
4-9 

Table 4-5. Emission Factor Data for Houston Nonattainment Areas 

Emission Factor (E

Engine Make & Model SCC 

Number of 

Engines 

[Lean / Rich] 

Engine 

Horsepower 

(Hp) 

Fraction of 

Compression 

Load by 

Engine Type 

(F2j) 

Fuel 

Consumption 

(MMBtu/Hp-hr) PM NOx (1) CO (1

CAT G3304 NA 2310021402 0 / 26 95 5.49% 0.007567 3.26E-02 0.50 0.16 CAT G3306 NA 2310021402 0 / 24 145 7.73% 0.007775 3.35E-02 0.50 1.346 

Wauk VRG330 2310021402 0 / 23 68 3.47% 0.008038 3.46E-02 0.50 0.110

CAT G379 NA (3) 2310021402 0 / 14 327 10.17% 0.008710 3.75E-02 0.50 0.159

Wauk F1197 G 2310021402 0 / 13 183 5.28% 0.007253 3.13E-02 0.50 0.1 

CAT G3306 TA 2310021402 0 / 13 203 5.86% 0.008098 3.49E-02 0.50 1.657 

CAT G342 NA (5) 2310021402 0 / 10 225 5.00% 0.008588 3.70E-02 0.101 0.031

CAT G3406 TA 2310021402 0 / 9 290 5.80% 0.007407 3.19E-02 0.50 0.614 

Wauk F817 G 2310021402 0 / 7 87 1.35% 0.007253 3.13E-02 0.50 0.1 

AJAX C-42 2310021101 5 / 0 40 0.44% 0.009900 1.72E-01 4.4 (8) 3.3 

CAT G398 TA (3) 2310021403 0 / 5 605 6.72% 0.008710 3.75E-02 0.50 0.159

AJAX DPC-140 2310021102 5 / 0 134 1.49% 0.008200 1.43E-01 0.50 1.3 

SUPERIOR 8GTLB 2310021203 4 / 0 1100 9.77% 0.008788 3.07E-04 0.50 3.6 

CAT G379 TA (3) 2310021402 0 / 4 417 3.70% 0.008710 3.75E-02 0.50 0.159

CAT G3516 TALE 2310021203 3 / 0 1245 8.30% 0.007364 2.58E-04 0.50 1.805 

Wauk F11 G 2310021402 0 / 3 119 0.79% 0.007600 3.27E-02 0.50 0.079 

CAT G3306 2310021402 0 / 3 183 1.22% 0.007579 3.27E-02 0.50 0.146 

Wauk VRG220 (7) 2310021301 0 / 3 45 0.30% 0.008038 3.46E-02 12.951 (8) 1.104 

Wauk VRG330 TA 2310021402 0 / 3 100 0.67% 0.007307 3.15E-02 0.50 0.158

Wauk L7042 GL 2310021203 3 / 0 1357 9.04% 0.007237 2.53E-04 0.50 2.85 

Wauk L7042 G 2310021403 0 / 3 961 6.40% 0.007180 3.09E-02 0.50 1.3 

CAT G342 TA (5) 2310021402 0 / 2 225 1.00% 0.008588 3.70E-02 0.101 0.031

TOTAL 199 100% Weighted Average EFs 0.03 0.53 1.17 

1. NOx emission factors were adjusted for 30 TAC, Chapter 117, Subchapter D, Division 2 nonattainment rule. Also, ERG assumed any four stroke rich burn engine, greater t

nonattainment area, would have non-selective catalytic reduction (NSCR) control technology. ERG has applied a 90% reduction to the emission factors for CO and VOC for t

2. Non-Methane Hydrocarbon. 3. No emission factors could be found for these engines. Since they are similar models manufactured in the same time period, it was assumed that emission factors were the sa4. Assumed to be equal to CAT G342 NA. 5. Emission factors are based on AP-42 background document testing with no HAP emission control. Emissions data did not differentiate between a G342 TA or NA engine, s

the same emission factors. No control device is needed since NOx emissions are below Texas mandated emission standards. 

6. Total Hydrocarbon. 7. Based on discussions with Waukesha, the VRG220 and VRG310 models have the same emission factors as the VRG330. 8. The AJAX C-42 and Wauk VRG220 engines are less than 50 Hp and therefore are not subject to 30 TAC, Chapter 117, Subchapter D, Division 2.
4-10 

reduction (NSCR) control technology. AP-42 Section 3.2 (US EPA, 2000) recommends 

applying an efficiency of 90% to the uncontrolled emissions of CO for engines equipped with 

NSCR technology; other studies (EPRI 2005) state the technology can also achieve 85 to 90% 

reduction of VOCs. Therefore, the CO and VOC emission factors in Tables 4-4 and 4-5 reflect a 

90% control efficiency adjustment. 

 All PM and SO2 emission factors were obtained from AP-42 Section 3.2 (US EPA, 

2000). PM emission factors are based on whether each engine is a 2 or 4 stroke lean-burn engine 

or a 4 stroke rich-burn engine. The PM emission factor represents both PM10 and PM2.5. The 

SO2 emission factor assumes the sulfur content in natural gas is 0.002 grams per standard cubic 

foot. 

 By applying the emissions data (EFjk) in Tables 4-3 through 4-5 to the fraction of 

compression load by engine type (F2j), a single set of weighted emission factors was calculated 

for each pollutant in each attainment status category. 

Compression requirements for county i, Ci: 

 A compressor’s operating behavior is generally dependent on the relationship between 

pressure ratio and volume or mass flow rate. In particular, the operating behavior for a 

compressor engine located at a gas well is based on the compressor suction and discharge 

pressures required to convey the natural gas from the well head to the gathering lines. These 

pressures, or the compression ratio, along with the natural gas flow-rate through the compressor, 

define the engine load in terms of the amount of mechanical work that is required to compress 

the natural gas produced by the well. This mechanical work, in terms of horsepower-hour (Hphr), is directly proportional to the volume of fuel, in terms of thousand cubic feet (Mscf), that 

must be burned by the compressor engine and the relationship is termed a compression 

requirement (Hp-hr/Mscf). Special compressor calculators can be used to convert inlet and 

outlet pressures into compression requirements which can then be used to determine emissions 

created by compressor engines. Because of this direct relationship of mechanical work to 

volume of fuel burned, one would expect a 100 Hp engine to burn almost an equal amount of 

fuel as two (2) 50 Hp engines when compressing the same volume of natural gas produced by the 

same well. Therefore, it is not necessary to know the specific numbers of engines, or their 

individual sizes when calculating emissions from compressors at the county level.
4-11 

 The 2005 HARC report developed compression requirements ranging between 3.1 and 

3.5 (Hp-hr/Mscf) for three distinct districts in eastern Texas, including one attainment area and 

two nonattainment areas (Houston and Dallas) by obtaining typical well pressures and gathering 

line pressures through a field study. The engines in this particular field survey were operated at 

loads ranging from about 10% to 70% of full load, and averaged 40% load. Additionally, 

compression requirements deduced from two Pollution Solutions studies are relatively in-line 

with the compression requirements used in the 2005 HARC report. More specifically, a 191 

Hp-day/Mscf compression requirement determined in a 2005 Pollutions Solutions study, when 

adjusted2

 for the findings in a 2008 Pollution Solutions study, yields a compression requirement 

of 2.97 (Hp-hr/Mscf). 

 Compression requirements calculated by specific Texas studies are shown in Table 4-6. 

Those compression requirements were applied to counties in each respective TRC District and an 

average was calculated for application to the rest of Texas. 

Table 4-6. Average Compression Requirements (Hp-hr/Mscf) 

Study TRC District 2 TRC District 3 TRC District 6 All Other 

Texas Areas 

HARC 2005 3.5 3.1 3.1 -- 

2005 and 2008 

Pollution 

Solutions (1) 

-- -- 2.97 -- 

Final 3.5 3.1 3.03 3.21 (2)

1. Included Gregg, Harrison, Rusk, Smith, Upshur, and Panola Counties. 

2. TRC districts 2, 3, and 6 averaged together. 

 

2

 In a 2002 emissions inventory (Pollution Solutions, 2005) entitled “Tyler/Longview/Marshall Flexible Attainment 

Region Emission Inventory”, the author developed a compression requirement (Hp-day/MSCF) through survey data 

assuming the compressor engines were operating under full load or maximum installed horsepower. This 

assumption caused an overestimation of the amount of fuel that was consumed by the compressor engines and 

consequently overestimated the amount of emissions from these engines. A more recent study by Pollution 

Solutions (2008) entitled “2005 and 2007 Compressor Engine Emissions and Load Factors Report” determined 

average load factors for three engine categories, all of which were less than 100%. For engines less than 240 Hp, the

load factor was 70%. For engines between 240-500 Hp, the load factor was 69%. For engines greater than 500 Hp, 

the load factor was 58%. Applying the load factors reduced the estimated 2005 emissions of NOx by 34% and 

similar reductions were seen for VOC and CO. 
4-12 

HAP Emissions for Compressor Engines

 HAP emissions from compressor engines were calculated using VOC and PM speciation 

data as follows: 

EVOC-HAP = EVOC x (E%VOC-HAP /100) 

where: 

EVOC-HAP = Speciated VOC-HAP emissions [tons/yr] 

EVOC = VOC emissions [tons/yr] 

E%VOC-HAP = % HAP composition of VOC emissions 

and 

EPM-HAP = EPM x (E%PM-HAP /100) 

where: 

EPM-HAP = Speciated PM-HAP emissions [tons/yr] 

EPM = PM emissions [tons/yr] 

E%PM-HAP = % HAP composition of PM emissions 

 Appendix C contains the VOC and PM HAP speciation data. 

Emissions for county i, and pollutant k, EFik:

 Appendix D presents county-level emissions for compressor engines corresponding to 

county-level natural gas production, based on the input variables discussed above. Tables 4-7 

through 4-9 depict the distribution of emissions for various engine types by Source Classification 

Code (SCC) as found in the Texas attainment areas, the Houston nonattainment area, and the 

Dallas nonattainment area. ERG applied these distributions in order to determine compressor 

engine emissions by SCC and county (see Appendix D). Table 4-10 defines each SCC used for 

Compressor Engines. 
4-13 

Table 4-7. Distribution of Compressor Engine Emissions by SCC for Texas Attainment 

Counties 

SCC PM NOx CO VOC SO2

2310020600 1.10% 0.16% 0.11% 0.75% 0.34% 

2310021101 1.15% 0.13% 0.17% 0.59% 0.36% 

2310021102 44.40% 9.21% 3.80% 29.00% 13.93% 

2310021103 0% 0% 0% 0% 0% 

2310021201 0% 0% 0% 0% 0% 

2310021202 0% 0% 0% 0% 0% 

2310021203 7.23% 4.76% 11.53% 37.84% 26.92% 

2310021301 0.48% 0.77% 0.12% 0.08% 0.61% 

2310021302 28.83% 58.22% 51.62% 21.66% 36.53% 

2310021303 0% 0% 0% 0% 0% 

2310021401 0% 0% 0% 0% 0% 

2310021402 0% 0% 0% 0% 0% 

2310021403 16.81% 26.75% 32.64% 10.08% 21.30% 

Table 4-8. Distribution of Compressor Engine Emissions by SCC for Dallas Nonattainment 

Counties 

SCC PM NOx CO VOC SO2

2310020600 5.93% 0.72% 0.46% 2.39% 0.92% 

2310021101 0% 0% 0% 0% 0% 

2310021102 2.42% 0.29% 0.20% 0.99% 0.38% 

2310021103 0% 0% 0% 0% 0% 

2310021201 0% 0% 0% 0% 0% 

2310021202 0% 0% 0% 0% 0% 

2310021203 24.14% 63.66% 49.49% 87.85% 56.38% 

2310021301 0% 0% 0% 0% 0% 

2310021302 0% 0% 0% 0% 0% 

2310021303 0% 0% 0% 0% 0% 

2310021401 0% 0% 0% 0% 0% 

2310021402 20.38% 9.82% 4.88% 0.75% 12.77% 

2310021403 47.13% 25.51% 44.97% 8.02% 29.55% 
4-14 

Table 4-9. Distribution of Compressor Engine Emissions by SCC for Houston 

Nonattainment Counties 

SCC PM NOx CO VOC SO2

2310020600 0% 0% 0% 0% 0% 

2310021101 2.79% 3.68% 1.25% 2.03% 0.55% 

2310021102 7.76% 1.40% 1.65% 5.96% 1.54% 

2310021103 0% 0% 0% 0% 0% 

2310021201 0% 0% 0% 0% 0% 

2310021202 0% 0% 0% 0% 0% 

2310021203 0.27% 25.54% 64.67% 84.77% 26.66% 

2310021301 0.38% 7.32% 0.28% 0.09% 0.30% 

2310021302 0% 0% 0% 0% 0% 

2310021303 0% 0% 0% 0% 0% 

2310021401 0% 0% 0% 0% 0% 

2310021402 72.39% 49.69% 24.15% 5.90% 57.84% 

2310021403 16.41% 12.36% 8.00% 1.25% 13.11% 

Table 4-10. Compressor Engine SCC Definitions 

SCC Definition 

2310020600 GENERIC NATURAL GAS FIRED COMPRESSOR ENGINES (All 2-CYCLE RICH BURN) 

2310021101 Natural Gas Fired 2-Cycle Lean Burn Compressor Engines <50 Hp 

2310021102 Natural Gas Fired 2-Cycle Lean Burn Compressor Engines 50 To 499 Hp 

2310021103 Natural Gas Fired 2-Cycle Lean Burn Compressor Engines 500+ Hp 

2310021201 Natural Gas Fired 4-Cycle Lean Burn Compressor Engines <50 Hp 

2310021202 Natural Gas Fired 4-Cycle Lean Burn Compressor Engines 50-499 Hp 

2310021203 Natural Gas Fired 4-Cycle Lean Burn Compressor Engines 500+ Hp 

2310021301 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines <50 Hp 

2310021302 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50 To 499 Hp 

2310021303 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 500+ Hp 

2310021401 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines <50 Hp W/ Nscr 

2310021402 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50-499 Hp W/ Nscr 

2310021403 Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 500+ Hp W/ Nscr 

Example Calculation for Compressor Engines

 Using the equation provided above, ERG calculated NOx emissions in Anderson County 

from natural gas fired 2-cycle lean burn compressor engines less than 50 Hp as follows: 

where: 

Eik = NOx emissions in Anderson County [tons/year] 

TGPi = 12,044,998 (the total gas production in Anderson County) [Mscf/yr] 

F1i = 0.8572 (the fraction of wells requiring compression in Anderson County) 

F2j = 0.0013 (the fraction of compression load represented by natural gas fired 2-cycle 

lean burn compressor engines) 















 ∗ ∗ ∗

= ×

907,180

1i 2 j jk i

ik i

F F EF C

E TGP
4-15 

EFjk = 7.57 (the NOx emission factor for natural gas fired 2-cycle lean burn compressor 

engines) [g/Hp-hr]

Ci = 3.03 (the compression requirements for Anderson County) [Hp-hr/Mscf] 

907,180 is the conversion factor from grams to tons of emissions 

Therefore: 

Eik = 12,044,998 [Mscf] x ((0.8572 * 0.0013 * 7.57 [g NOx/Hp-hr] * 3.03 [Hphr/Mscf])/907,180) 

Eik = 0.339373 [tons NOx/yr] 

4.2 Artificial Lift (Pumpjack) Engines 

 A pumpjack is used to mechanically lift liquid out of the well if there is not enough 

bottom hole pressure for the liquid to flow all the way to the surface. The pumpjack tends to be 

driven by an electric motor; however, in isolated locations without access to electricity, 

combustion engines are used. The most common “off-grid” pumpjack engines run on casing gas 

produced from the well, but pumpjacks have been run on many types of fuel, such as propane 

(LPG) and diesel. Generally, pumpjacks have smaller engines than wellhead compressor 

engines. 

 Emissions from pumpjack engines were calculated using a methodology similar to that 

employed in a 2008 CENRAP study entitled: “Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emission Inventories” (Bar-Ilan, et al., 2008). For this 2008 

inventory, ERG calculated county-level emissions from pumpjack engines with the following 

equation: 

where: 

Eik is the emissions for county i, and pollutant k [tons/yr] 

Wi is the total number of active oil wells in county i [wells] 

fpumpjack is the fraction of oil wells with artificial lift engines 

epumpjack is the fraction of artificial lift engines that are electrically operated 

EFk is the emission factor for pollutant k [g/Hp-hr] 

HP is the horsepower of the engine [Hp] 

LF is the load factor of the engine while operating 

tannual is the annual number of hours the engine is used [hr/yr] 

907,180 is the conversion factor from grams to tons of emissions 

( ) 









 ∗ ∗ ∗

= × × − ×

907,180

1

k annual

ik i pumpjack pumpjack

EF HP LF t

E W f e
4-16 

Total number of active oil wells in county i, Wi:

 Total active oil wells by county for the full 2008 year are not readily available from the 

TRC website. However, oil well distribution data by county is available from the TRC website 

on a bi-annual (February and September) basis and can be found at: 

http://www.rrc.state.tx.us/data/wells/wellcount/index.php. ERG used the September 2008 TRC 

report to get a count of regular producing oil wells by county. 

Fraction of oil wells with artificial lift engines, fpumpjack:

 The fraction of oil wells requiring artificial lift was estimated as the fraction of active oil 

wells greater than one year old. Typically, oil wells in their first year of existence do not require

an artificial lift engine because the wells have enough bottom hole pressure for the oil to flow 

freely all the way to the surface. This trend was confirmed through phone interviews with five 

companies specializing in artificial lift engines (four engineering consultants with expertise in oil 

and gas production, and one company that sells, installs, and repairs pumpjacks and pumpjack 

engines). It was the general consensus among the interviewees that the majority of oil wells 

located in Texas are older than one year and thus would require some sort of artificial lift engine. 

 ERG determined the fraction of oil wells active in 2008 that were greater than one year 

old using the following equation: 

















> = −

(TotalActive Oil Wells on February 5, 2008)

(Oil Wells Completed in 2007) Fraction of Oil Wells 1Year Old 1 

 ERG determined the number of oil wells completed in 2007 using TRC annual drilling, 

completion, and plugging summaries which are available at: 

http://www.rrc.state.tx.us/data/drilling/drillingsummary/index.php. ERG used oil well 

distribution data showing the number of regular producing oil wells by county. Oil well 

distribution data by county is only available from the TRC website on a bi-annual (February and 

September) basis and can be found at: http://www.rrc.state.tx.us/data/wells/wellcount/index.php. 

Using the February 2008 TRC report, ERG summed the county specific numbers for regular 

producing oil wells. 
4-17 

 The fraction of oil wells greater than one year old was determined to be 0.967 (1 – (5,084 

/ 153,831) = 0.967). The actual fraction may be slightly different because each oil well that was 

completed in 2007 could have been completed on any day of that year. However, using the 

methodology explained above, ERG has assumed that all wells completed in 2007 were 

completed on February 5, 2007. 

Fraction of artificial lift engines that are electrically operated, epumpjack:

 ERG assumed that 70% of the artificial lift systems located in Texas operate with an 

electric motor as opposed to a fuel driven engine. This assumption was based on phone 

interviews with four companies specializing in artificial lift engines, three of which were 

engineering consultants with expertise in oil and gas production, and one company that sells, 

installs, and repairs pumpjacks and pumpjack engines. From these interviews, it was ascertained 

that it is most common to run pumpjack engines on electricity as this is the most cost effective 

option, thus if an oil well has access to electricity, electricity would typically be used to power 

the artificial lift engine. Fractions of artificial lift engines that are electrically operated ranged 

from 50 to 90 percent among interviewees. Therefore, ERG used a conservative estimate of 

70%. 

Emission factor for pollutant k, EFk:

 Through various phone interviews, ERG determined that the most popular pumpjack 

engines located in Texas are those in the Arrow C series. These engines burn natural gas and 

range from about 5 to 32 horsepower (depending on the model number). Criteria pollutant 

emission factors for the Arrow C engine models were provided by the manufacturer and are 

shown in Table 4-11. A single set of averaged emission factors was calculated for each pollutant 

assuming equal fuel usage by each engine size for all pollutants. 

 The New Source Performance Standard (NSPS), Subpart JJJJ limits emissions of NOx, 

CO, and VOC from stationary spark ignition internal combustion engines less than 500 

horsepower that were manufactured after July 1, 2008. Also, stationary spark ignition engines 

that were modified or reconstructed after June 12, 2006 are subject to the rule. As a conservative 

estimate, ERG assumed all pumpjack engines were manufactured prior to July 1, 2008 and/or 
4-18 

were not modified or reconstructed after June 12, 2006. Therefore, no pumpjack engines in this 

analysis are considered subject to the emission limitations of NSPS, Subpart JJJJ. 

 All PM and SO2 emission factors were obtained from AP-42 Section 3.2 (US EPA, 

2000). The PM emission factor is 9.50E-03 lb/MMBtu (based on a 4 stroke rich-burn engine). 

The PM emission factor represents both PM10 and PM2.5. The SO2 emission factor is 5.88E-04 

lb/MMBtu and assumes the sulfur content in natural gas is 0.002 grams per standard cubic foot. 

Both of these emission factors have been converted to g/Hp-hr using the fuel consumption rate of 

the engine. 

Table 4-11. Common Pumpjack Engine Emission Factors 

Emission Factor for Engine Type j, and Pollutant k 

(g/Hp-hr) (EFjk) 

Arrow 

C Series 

Model 

Horsepower 

(Hp) 

Fuel 

Consumption 

(MMBtu/Hp-hr) PM NOx CO VOC SO2 

C-46 11 0.0126 0.054 9.26 20.19 0.006 3.36E-03 

C-66 15.8 0.0117 0.050 14.54 4.03 0.332 3.12E-03 

C-96 21.4 0.0121 0.052 11.87 5.05 0.142 3.23E-03 

C-106 34 0.0092 0.040 23.32 0.222 0.094 2.46E-03 

Average 20.55 0.21 0.049 14.75 7.37 0.14 3.04E-03 

Horsepower of the engine, HP:

 ERG determined an average horsepower per pumpjack engine (20.55 Hp) by assuming 

that all pumpjack engines located in Texas were of the Arrow C series types listed in Table 4-11, 

with the engine population distributed evenly across the four engine models. 

Load factor of the engine while operating, LF:

 A 2006 study entitled: “Ozone Precursors Emission Inventory for San Juan and Rio 

Arriba Counties, New Mexico” (Pollack, et al., 2006) assumed the maximum power delivered by 

a pumpjack engine to be 100 percent of available engine power and the minimum power to be a 

10 percent load representative of idling. With these bounds and the approximate form of the 

power curve, the report estimated an average loading of 71 percent. For this 2008 inventory, 

ERG also used 71 percent as the load factor. 
4-19 

Annual number of hours the engine is used, tannual:

 The 2006 New Mexico study assumed that pumpjack engines operate nearly without 

interruption year-round (8,760 hours per year). However, this assumption would likely be an 

over estimate for Texas pumpjack engines as many of the oil wells located in Texas have 

intermittent activity and are not producing oil 24 hours per day. For this reason, ERG assumed a 

pumpjack engine only runs half the year, or 4,380 hours. ERG also verified this assumption 

through phone interviews with companies specializing in artificial lit engines. For future work, 

ERG recommends surveying operators to verify this assumption. Another way to verify this 

assumption would be to use oil well production data from the TRC as well as individual oil well 

pumpjack engine size information (most likely from survey data) to estimate the amount of hours 

each engine would need to operate in order to pump the stated oil production. 

HAP Emissions for Pumpjack Engines:

 HAP emissions from pumpjack engines were calculated using VOC and PM speciation 

data as follows: 

EVOC-HAP = EVOC x (E%VOC-HAP /100) 

where: 

EVOC-HAP = Speciated VOC-HAP emissions [tons/yr] 

EVOC = VOC emissions [tons/yr] 

E%VOC-HAP = % HAP composition of VOC emissions 

and 

EPM-HAP = EPM x (E%PM-HAP /100) 

where: 

EPM-HAP = Speciated PM-HAP emissions [tons/yr] 

EPM = PM emissions [tons/yr] 

E%PM-HAP = % HAP composition of PM emissions 

 Appendix C contains the VOC and PM HAP speciation data. 

Emissions for county i, and pollutant k, Eik:

 Appendix E presents county-level pumpjack engine emissions corresponding to the 

number of active oil wells located in each county, based on the input variables discussed above. 
4-20 

Example Calculation for Pumpjack Engines

 Using the equation provided above, ERG calculated NOx emissions in Anderson County 

from pumpjack engines as follows: 

where: 

Eik = NOx emissions in Anderson County [tons/yr] 

Wi = 456 (the total number of active oil wells in Anderson County) [wells] 

fpumpjack = 1 (the fraction of oil wells in Anderson County with artificial lift engines) 

epumpjack = 0.70 (the fraction of artificial lift engines in Anderson County that are 

electrically operated) 

EFk = 14.75 (the emission factor for NOx) [g/Hp-hr] 

HP = 20.55 (the horsepower of the engine) [Hp] 

LF = 0.71 (the load factor of the engine while operating) 

tannual = 4,380 (is the annual number of hours the engine is used) [hr/yr] 

 907,180 is the conversion factor from grams to tons of emissions 

Therefore: 

 Eik = 456 x 1 x (1 - 0.70) x ((14.75 [g NOx/Hp-hr] x 20.55 [Hp] x 0.71 x 4,380 

 [hr/yr])/907,180)) 

 Eik = 142.14 [tons NOx/yr] 

4.3 Dehydrators 

 A dehydrator is used to remove moisture from produced raw natural gas prior to 

transferring it to the gas transmission pipeline. Dehydrators operate by contacting the natural gas 

with a hygroscopic liquid such as triethylene glycol. The water vapor in the gas stream becomes 

dissolved in the glycol liquid solvent, removing the water from the natural gas. During the 

absorption process, the glycol also absorbs some methane and VOC. The glycol is then 

depressurized in a flash vessel and the water vapor is removed from the glycol in a glycol 

regenerator. Some dehydrators do not employ a flash vessel. In those dehydrators, 

depressurization occurs in the regenerator. Methane, VOC, and HAPs are emitted from the 

dehydrator during both of these steps. 

 Depending upon the dehydrator equipment, these emissions may be recaptured and 

recycled, or controlled by flaring. Not all dehydrators are controlled. The glycol is normally 

circulated by use of electric pumps. The glycol regeneration process requires heating the glycol-

( ) 









 ∗ ∗ ∗

= × × − ×

907,180

1

k annual

ik i pumpjack pumpjack

EF HP LF t

E W f e
4-21 

water mixture in a glycol regenerator boiler. The regenerator boiler has similar emissions 

characteristics to typical combustion units. On-site gas is typically used as the fuel resulting in 

emissions of CO and NOx. 

4.3.1 Dehydrator Flash Vessels and Regenerator Vents 

 Emissions from dehydrator flash vessels and regenerator vents were calculated using a 

methodology similar to that employed in the 2008 CENRAP study (Bar-Ilan, et al., 2008). In 

place of the CENRAP emission factors, ERG derived estimates of dehydrator emission factors 

for VOC, benzene, toluene, ethylbenzene, and xylene from emissions data submitted to TCEQ 

by operators of dehydrators in use at point sources in Texas. For this 2008 inventory, ERG 

calculated county-level emissions from dehydrator flash vessel and glycol regenerator vent 

emissions with the following equation: 

where: 

Eik is the emissions for county i, and pollutant k [tons/yr] 

TGPi is the total production of natural gas from gas wells in county i [MMscf/yr] 

EFk is the emission factor for pollutant k [lb/MMscf] 

2,000 is the conversion factor from pounds to tons of emissions 

Total production of natural gas from gas wells in county i, TGPi:

 Natural gas production data by county (TGPi) was provided for 2008 by the TRC. 57 

counties had no gas production in 2008. 

Emission factor for pollutant k, EFk:

 In place of the CENRAP emission factors, ERG derived estimates of dehydrator emission 

factors for VOC, benzene, toluene, ethylbenzene, and xylene from emissions data submitted to 

TCEQ by operators of dehydrators in use at point sources in Texas. These emissions estimates 

were prepared by the operators using Gly-Calc software. Data on the presence of flash vessels, 

control devices, and control efficiencies was also derived from the TCEQ emissions data, 

indicating that a wide variety of equipment configurations, as well as control technologies, are in 

use for natural gas production in Texas. There were 82 complete samples in the dataset, 













= × ×

,2 000

1

Eik TGPi EFk
4-22 

spanning the full range of gas-producing regions in Texas. Statewide weighted averages for 

these five pollutants were derived from the emissions data, and are shown in Table 4-12 below. 

 These emission factors may produce emissions estimates that are lower than actual 

emissions at the area-source dehydrators in the state. TCEQ recognizes that the types of control 

technologies in use at dehydrators located at point sources may be different than the control 

technologies in use at dehydrators located at smaller area sources. Control requirements are 

different and incentives for recapturing and/or controlling VOC and HAP emissions may be 

different for operators of (larger) point sources and (smaller) area sources. However, this dataset 

of dehydrator emissions represents the full range of uncontrolled and controlled dehydrators in 

Texas and is a good composite representation of statewide dehydrator emissions. 

Table 4-12. Statewide Emission Factors for VOC, Benzene, Toluene, Ethylbenzene, and 

Xylene from Dehydrator Flash Vessels and Regenerator Vents in Texas 

Pollutant Emission Factor (lb/MMscf) Number of Samples 

VOC 1.63 82 

Benzene 0.38 68 

Toluene 0.20 64 

Ethylbenzene 0.02 45 

Xylene 0.75 60 

Emissions for county i, and pollutant k, Eik:

 Appendix E presents county-level dehydrator flash vessel and regenerator emissions 

corresponding to the production of natural gas at wells located in each county, based on the input 

variables discussed above. 

Example Calculation for Dehydrator Flash Vessels and Regeneration Vents

 Using the equation provided above, ERG calculated Benzene emissions in Anderson 

County from dehydrator flash vessels and regeneration vents as follows: 

where: 

Eik = (the Benzene emissions for Anderson County) [tons/yr] 

TGPi = 12,045 (the total production of natural gas from gas wells in Anderson County) 

[MMCF/yr] 

EFk = 0.38 (the emission factor for Benzene) [lb/MMscf] 













= × ×

,2 000

1

Eik TGPi EFk
4-23 

2,000 is the conversion factor from pounds to tons of emissions 

Therefore: 

Eik = 12,045 [MMCF/yr] x 0.38 [lb/MMscf] x (1/2,000) 

Eik = 2.29 [tons/yr] 

4.3.2 Glyol Regenerator Boilers 

 Emissions from glycol regenerator boilers were calculated using the methodology and 

emission factors employed in the 2008 CENRAP study (Bar-Ilan, et al., 2008). For this 2008 

inventory, ERG calculated county-level emissions from dehydrator regenerator boilers with the 

following equation: 

where: 

Eik is the emissions for county i, and pollutant k [tons/yr] 

TGPi is the total production of natural gas from gas wells in county i [MMscf/yr] 

EFk is the emission factor for pollutant k [lb/MMscf] 

2,000 is the conversion factor from pounds to tons of emissions 

Total production of natural gas from gas wells in county i, TGPi:

 Natural gas production data by county (TGPi) was provided for 2008 by the TRC. 57 

counties had no gas production in 2008. 

Emission factor for pollutant k, EFk:

 ERG used the CENRAP emission factors for regenerator boiler emissions. The 

CENRAP emission factors are in terms of pounds of pollutant emitted for each million cubic feet 

(MMscf) of gas produced. These emission factors are shown in Table 4-13 below. 

Table 4-13. Emission Factors for NOx and CO Emissions 

from Dehydrator Regenerator Boilers 

Pollutant Emission Factor (lb/MMscf)

NOx 0.052 

CO 0.105 













= × ×

,2 000

1

Eik TGPi EFk
4-24 

Emissions for county i, and pollutant k, Eik:

 Appendix E presents county-level dehydrator regenerator boiler emissions corresponding 

to the production of natural gas at wells located in each county, based on the input variables 

discussed above. 

Example Calculation for Glycol Regenerator Boilers:

 Using the equation provided above, ERG calculated NOx emissions in Anderson County 

from glycol regenerator boilers as follows:

where: 

Eik = NOx emissions in Anderson County [tons/yr] 

TGPi = 12,045 (the total production of natural gas from gas wells in Anderson County) 

[MMscf/yr] 

EFk = 0.052 (the emission factor for NOx) [lb/MMscf] 

2,000 is the conversion factor from pounds to tons of emissions 

Therefore: 

Eik = 12,045 [MMscf/yr] x 0.052 [lb/MMscf] x (1/2,000)

 Eik = 0.31 [tons NOx/yr] 

4.3.3 Dehydrator Emission Control Device 

 Emissions from dehydrator control devices were calculated using the basic methodology 

employed in the 2008 CENRAP study (Bar-Ilan, et al., 2008). Like the 2008 CENRAP study, 

ERG used the emission factors from AP 42, Chapter 13.5 for NOx and CO. ERG also used the 

heat value of the gas flared from the CENRAP study. ERG derived estimates of the amount of 

gas flared for each unit of gas produced from the emissions data submitted to TCEQ by operators 

of dehydrators in use at point sources in Texas. For this 2008 inventory, ERG calculated countylevel emissions from dehydrator emission control devices with the following equation: 

where: 

Eik is the emissions for county i, and pollutant k [tons/yr] 

TGPi is the total production of natural gas from gas wells in county i [MMscf/yr] 

Fflared is the fraction of produced gas that is flared [lbs flared/MMscf produced] 

D is the density of the gas flared [lbs/MMscf] 













= × ×

,2 000

1

Eik TGPi EFk

,2 000

1 1

ik = i × flared × × HV × EFk ×

D

E TGP f
4-25 

HV is the heat value of the gas flared [MMBtu/MMscf] 

EFk is the emission factor for pollutant k [lbs/MMBtu]

2,000 is the conversion factor from pounds to tons of emissions 

Total production of natural gas from gas wells in county i, TGPi:

 Natural gas production data by county (TGPi) was provided for 2008 by the TRC. 57 

counties had no gas production in 2008. 

Fraction of produced gas that is flared, Fflared:

 ERG derived estimates of the amount of gas flared for each unit of gas produced from the 

emissions data submitted to TCEQ by operators of dehydrators in use at point sources in Texas. 

The sum of the reported emissions from flash vessels and regenerator vents before controls, in 

tons of total hydrocarbons, was tallied for all 82 samples in the dataset. This figure was 

compared with the total production of natural gas reported in those 82 samples, producing a 

weighted average. Because emissions are reported in pounds, and production is reported in 

Millions of standard cubic feet (MMscf), the units for this fraction are pounds of gas flared per 

million standard cubic feet of gas produced (lbs flared/MMscf produced). The dehydrator 

emissions data indicated that 1 ton (2,000 pounds) of gas is flared for each 149.2 million 

standard cubic feet (MMscf) of gas produced. 

Density of the gas flared, D:

 ERG derived estimates of the density of the gas flared by assuming it was equivalent to 

the density of the dry gas produced by the dehydrator. This data was taken from the dehydrator 

emissions reports submitted to TCEQ. The amount of dry gas produced, in pounds per hour, was 

divided by the flow rate of gas produced, in cubic feet per hour, producing a density for dry gas 

in units of pounds per cubic foot. The sum of the amount of dry gas produced was tallied for all 

82 samples in the dataset, and was divided by the sum of the flow rate of gas produced, 

producing a weighted average, with units of pounds per standard cubic foot (lbs/scf). This figure 

was then multiplied by 106

 standard cubic feet per MMscf, to yield a factor with units of pounds 

per million standard cubic feet (lbs/MMscf). The dehydrator emissions data indicated that the 

density of the gas produced is 0.047 pounds per standard cubic foot or 46,952 (lbs/MMscf). 
4-26 

Heat value of the gas flared, HV:

 The heat value of the gas flared is taken from the 2008 CENRAP study. This value is 

equivalent to 1,209 Btu per standard cubic feet of gas (Btu/scf). 

Emission factor for pollutant k, EFk:

 ERG used the CENRAP emission factors for dehydrator control emissions. Although the 

dehydrator emissions data from TCEQ showed that a small percentage of dehydrator flash vessel 

and regenerator vent emissions are controlled by incinerators, the vast majority (over 90%) are 

burned in flares. ERG chose to use the simplifying assumption that all dehydrator flash vessel 

and regenerator vent emissions that are controlled by combustion are directed to flares. The 

emission factors for flares are taken directly from AP 42, Chapter 13.5. The emission factors are 

in terms of pounds of pollutant emitted for each million Btu (lbs/MMBtu) of gas flared. These 

emission factors are shown in Table 4-14 below. 

Table 4-14. Emission Factors for NOx and CO Emissions 

from Dehydrator Controls (Flares) 

Pollutant 

Emission Factor 

(lb/MMBtu) 

NOx 0.068 

CO 0.37 

Emissions for county i, and pollutant k, Eik:

 Appendix E presents county-level dehydrator control emissions corresponding to the 

production of natural gas at wells located in each county, based on the input variables discussed 

above. 

Example Calculation for Dehydrator Controls:

 Using the equation provided above, ERG calculated NOx emissions in Anderson County 

from dehydrator controls as follows: 

,2 000

1 1

ik = i × flared × × HV × EFk ×

D

E TGP f
4-27 

where: 

Eik = NOx emissions for Anderson County [tons/yr] 

TGPi = 12,045 (the total production of natural gas from gas wells in Anderson County) 

[MMscf/yr] 

Fflared = 13 (the fraction of produced gas that is flared) [lbs flared/MMscf produced] 

D = 46,952 (the density of the gas flared) [lbs/MMscf] 

HV = 1,209 (the heat value of the gas flared) [MMBtu/MMscf] 

EFk = 0.068 (the NOx emission factor) [lbs/MMBtu] 

2,000 is the conversion factor from pounds to tons of emissions 

Therefore: 

Eik = 12,045 [MMscf/yr] x 13.41 [lbs flared/MMscf produced] x (1/46,952 

 [lbs/MMscf]) x 1,209 [MMBtu/MMscf] x 0.068 [lbs/MMBtu] x (1/2,000) 

 Eik = 0.14 [tons NOx/yr] 

4.4 Oil and Condensate Storage Tanks 

 Storage tanks are used in a variety of applications in the oil and gas industry. An oil and 

gas well may produce oil, natural gas, or a mixture of the two. When oil and gas are brought to 

the surface, the liquids produced may contain a mixture of liquid and gaseous organic 

compounds, nitrogen, carbon dioxide, water, sand, and other impurities. The mixture is typically 

passed through a three-phase separator, which allows the water, oil and gas to separate. The 

liquid oil and water components are then piped to storage tanks. If the well produces gas, it is 

possible that liquids may condense out of the gas as the pressure is decreased. The hydrocarbon 

liquid produced at gas wells is known as condensate. Oil and condensate are piped to storage 

tanks until they can be transported offsite. Tanks are typically vented to the atmosphere. 

 Oil and condensate storage tank emissions at wellhead and gathering sites are composed 

of flashing losses, working losses, and breathing losses. Flashing losses occur when a produced 

liquid (crude oil or condensate) with entrained gases experiences a pressure drop, as during the 

transfer of liquid hydrocarbons from a wellhead or separator to a storage tank. As the pressure 

on the liquid drops, some of the lighter compounds dissolved in the liquid are released or 

“flashed”. Some compounds that are liquids at the initial pressure and temperature, change 

phase from a liquid to a gas and are also released or “flashed” from the liquid in the storage tank. 

Working losses occur when vapors are displaced from a tank during the filling and unloading 

cycles, and when the fluid is agitated during filling of the tank. Breathing losses (also called 

standing losses) occur due to the normal evaporation of liquid in a tank. Breathing losses are 

vapors that are produced in response to the daily temperature change. 
4-28 

 Emissions from oil and condensate storage tanks were calculated using the methodology 

and emission factor data developed in the 2009 TERC study “VOC Emissions From Oil and 

Condensate Storage Tanks” (TERC, 2009). These emission factors were multiplied by countyspecific oil and gas production data obtained from the TRC. The calculations assume that 

venting emissions are uncontrolled by flares or vapor recovery units. For this 2008 inventory, 

ERG calculated county-level emissions from oil storage tank and condensate storage tank vent 

emissions with the following equations: 

and 

where: 

Eik is the emissions for county i, and pollutant k [tons/yr] 

TOPi is the total production of oil from oil wells in county i [BBL/yr] 

TCPi is the total production of condensate from gas wells in county i [BBL/yr] 

EFik is the emission factor for county i, and pollutant k [lb/BBL] 

2,000 is the conversion factor from pounds to tons of emissions 

Total production of oil from oil wells in county i, TOPi:

 Oil production data by county (TOPi) was provided for 2008 by the TRC. 42 counties 

had no oil production in 2008. 

Total production of condensate from gas wells in county i, TCPi:

 Condensate production data by county (TOPi) was provided for 2008 by the TRC. 80 

counties had no condensate production in 2008. 

Emission factor for county i, and pollutant k, EFik:

 VOC Emission Factors: The VOC emission factors for oil storage tank batteries and 

condensate storage tank batteries are taken from the 2009 TERC study and are in units of pounds 

per barrel of oil/condensate produced and are shown in Table 4-15 below. 













= × ×

,2 000

1

Eik TOPi EFik













= × ×

,2 000

1

Eik TCPi EFik
4-29 

 HAP Emission Factors: Benzene, toluene, ethylbenzene, and xylene are a constituent of 

the vapors emitted from oil and condensate storage tanks. The benzene, toluene, ethylbenzene, 

and xylene emission factors are derived from the data published in the 2009 TERC study. Tables 

3-4 and 3-5 in the TERC study showed the measured vent gas speciation profiles for oil tanks 

and condensate tanks, respectively. This data was used in combination with the measured weight 

percent VOC data from those same tables and the VOC emission factors taken from that study to 

calculate emission factors for benzene, toluene, ethylbenzene, and xylene from both oil and 

condensate storage tanks in terms of lbs per barrel of oil or condensate produced. These 

emission factors are in units of pounds per barrel of oil/condensate produced and are shown in 

Table 4-15 below. 

Table 4-15. Emission Factors for VOC, Benzene, Toluene, 

Ethylbenzene, and Xylene from Oil Storage Tanks and 

Condensate Storage Tanks in Texas 

Pollutant Emission Factors (lb/BBL) 

Oil Condensate 

VOC 1.60 33.3 

Benzene 0.00533 0.187 

Toluene 0.0083 0.319 

Ethylbenzene 0.003 0.018 

Xylene 0.012 0.141 

Emissions for county i, and pollutant k, Eik:

 Appendix E present county-level oil storage tank and condensate storage tank vent 

emissions corresponding to the production of oil and condensate at oil wells and natural gas 

wells located in each county, based on the input variables discussed above. 

Example Calculation for Oil and Condensate Storage Tanks:

 Using the equation provided above, ERG calculated VOC emissions in Anderson County 

from oil storage tanks as follows: 

 

where: 

Eik = VOC emissions for Anderson County [tons/yr] 

TOPi = 678,901 (the total production of oil from oil wells in Anderson County) [BBL/yr] 

EFik = 1.60 (the VOC emission factor for Anderson County) [lb/BBL] 













= × ×

,2 000

1

Eik TOPi EFik
4-30 

2,000 is the conversion factor from pounds to tons of emissions 

Therefore: 

Eik = 678,901 [BBL/yr] x 1.6 [lb/BBL] x (1/2,000) 

Eik = 543 [tons/yr] 

4.5 Oil and Condensate Loading 

 Oil and condensate stored in field storage tanks is transferred to trucks and railcars and 

shipped to refineries for further processing. Fugitive VOC emissions are released from these 

loading processes as the vapors in the receiving vessel are displaced by the liquids from the 

storage tanks. These vapors are normally vented to the atmosphere. 

 Emissions from oil and condensate loading were calculated using the emission estimation 

methodology in the 2009 TCEQ study. This methodology is taken from AP 42, Chapter 5.2 - 

Transportation and Marketing of Petroleum Liquids. Emission factors for loading losses were 

calculated at the county level. These emission factors were multiplied by county-specific 2008 

oil and condensate production data obtained from the TRC to derive county-specific emission 

estimates. ERG obtained monthly temperature data for the counties in which the oil and 

condensate are produced. Per the 2007 TCEQ study, ERG used AP-42 data for crude oil (50 

lb/lb-mole) at 60 degrees F to approximate the molecular weight of tank vapors for oil. ERG 

used AP-42 data for gasoline (Reid Vapor Pressure (RVP) 7) (68 lb/lb-mole) at 60 degrees F to 

approximate the molecular weight of tank vapors for condensate. The AP-42 equation was used 

to calculate temperature-dependent emission factors for loadout losses for each county. Truck or 

railcar loading emissions were calculated by multiplying the emission factor by county-level oil 

and condensate production data. The calculations assume that venting emissions are 

uncontrolled by flares or vapor recovery units. The AP-42 equation to calculate loading 

emission factors is shown in the following equation. 
4-31 

 

where: 

LLik is the loading loss [lb/1,000 gal of liquid loaded] for county i, and pollutant k 

S is the saturation factor (based on type of loading operation) 

Pi is the true vapor pressure of liquid loaded [psia] for county i 

M is the molecular weight of tank vapors [lb/lb-mole] 

Ti is the temperature of bulk liquid loaded [oR] for county i 

Saturation factor, S:

 The saturation factor is taken from Table 5.2-1 of Chapter 5.2 of AP-42 and is based on 

submerged or splash loading of liquid with dedicated vapor balance service. This assumes that 

tank vapors from the truck or railcar being loaded are vented back into the tank being emptied. 

True vapor pressure of the liquid being loaded, for county i, Pi:

 The true vapor pressure for oil is estimated to be equivalent to the true vapor pressure for 

crude oil RVP 5. The true vapor pressure for condensate is estimated to be equivalent to the true 

vapor pressure for gasoline RVP 7. The true vapor pressure for these liquids at various 

temperatures are shown in Table 4-16 below. The true vapor pressure for the county-specific 

average temperature is calculated for oil loading with the equation. 

where: 

Pi is the true vapor pressure of liquid loaded [psia] for county i 

Ti is the temperature of bulk liquid loaded [oF] for county i 

 The true vapor pressure for the county-specific average temperature is calculated for 

condensate loading with the equation. 

 

where: 

Pi is the true vapor pressure of liquid loaded [psia] for county i 

Ti is the temperature of bulk liquid loaded [o

F] for county i 

 These formulas are derived from linear interpolation of the slope and intercept of the line 

formed between the values for the true vapor pressure of crude oil RVP 5 (representing oil) and 

gasoline RVP 7 (representing condensate) at 55 degrees Fahrenheit and 75 degrees Fahrenheit. 















 ∗ ∗

= ×

i

i

ik T

S P M

LL 12 46.

Pi = ( .0 057 ×Ti

)− 58.0

Pi = ( .0 077 ×Ti

) − 03.1
4-32 

Molecular weight of the tank vapors, M:

 The molecular weight of the tank vapors for oil is estimated to be equivalent to the 

molecular weight of crude oil RVP 5. The molecular weight of the tank vapors for condensate is 

estimated to be equivalent to the molecular weight of gasoline RVP 7. The molecular weight of 

these liquids at 60 degrees Fahrenheit are shown in Table 4-16 below. The data in Table 4-16 is 

taken directly from AP-42, Chapter 7.1. 

Table 4-16. Molecular Weight and True Vapor Pressure of Selected Petroleum Liquids 

Petroleum 

Liquid 

Molecular 

Weight at 60° 

F (lb/lb-mole) 

True Vapor Pressure (psia) 

 40° F 50° F 60° F 70° F 80° F 90° F 100° F 

Crude Oil RVP 5 50 1.8 2.3 2.8 3.4 4.0 4.8 5.7 

Gasoline RVP 7 68 2.3 2.9 3.5 4.3 5.2 6.2 7.4 

Temperature of the bulk liquid loaded, Ti: 

 The average 2008 temperature data, degrees Fahrenheit, for 115 Texas counties was 

obtained from the National Weather Service and from several state/local monitoring sites. These 

data were used to estimate the average temperature in the adjacent 139 counties. The average 

liquid temperature is assumed to be equivalent to the average ambient air temperature. 

Loading loss for county i, and pollutant k, LLik: 

 The loading loss is the county-specific emission factor and has units of pounds per 1,000 

gallons of oil or condensate loaded (lbs/1,000 gal). 

 For this 2008 inventory, ERG calculated county-level emissions from oil loading 

emissions and condensate loading emissions with the following equations: 

 

and 













= × × ×

,2 000

1

42 Eik TOPi LLk













= × × ×

,2 000

1

42 Eik TCPi LLik
4-33 

where: 

Eik is the loading emissions for county i, and pollutant k [tons/yr] 

TOPi is the total production of oil from oil wells in county i [BBL/yr] 

TCPi is the total production of condensate from gas wells in county i [BBL/yr] 

LLik is the loading loss (emission factor) for pollutant k [lb/1,000 gal loaded] 

42 is the conversion factor from barrels to gallons

2,000 is the conversion factor from pounds to tons of emissions 

Total production of oil from oil wells in county i, TOPi:

 Oil production data by county (TOPi) was provided for 2008 by the TRC. 42 counties 

had no oil production in 2008. 

Total production of condensate from gas wells in county i, TCPi:

 Condensate production data by county (TOPi) was provided for 2008 by the TRC. 80 

counties had no condensate production in 2008. 

Loading loss, LLik: 

 The loading loss is the emission factor calculated above and has units of pounds per 

1,000 gallons of oil or condensate loaded. 

 HAP Emission Factors: Benzene, toluene, ethylbenzene, and xylene are a constituent of 

the vapors emitted during oil and condensate loading. The benzene, toluene, ethylbenzene, and 

xylene emission factors for oil loading and condensate loading in all oil and gas producing basins 

in Texas are derived from the data published in the 2009 TERC study. Tables 3-4 and 3-5 in the 

TERC study showed the measured vent gas speciation profiles for oil tanks and condensate 

tanks, respectively. This data was used in combination with the measured weight percent VOC 

data from those same tables and the VOC emission factors taken from that study to calculate 

emission factors for benzene, toluene, ethylbenzene, and xylene from both oil and condensate 

loading. These emission factors are in terms of units of HAP emitted per units of VOC emitted. 

and are shown in Table 4-17 below. 
4-34 

Table 4-17. Emission Factors for Benzene, Toluene, Ethylbenzene, and Xylene from 

Oil and Condensate Loading in Texas 

All Texas Basins Emission Factors (lb HAP/lb VOC) 

Pollutant Oil Condensate 

Benzene 0.0033 0.2808 

Toluene 0.0052 0.479 

Ethylbenzene 0.00187 0.027 

Xylene 0.0075 0.212 

Loading emissions for county i, for pollutant k, Eik:

 Emissions for oil and condensate loading racks for each county are calculated by 

multiplying a county-specific loading loss factor by the county-specific oil and condensate 

production. Appendix E present county-level oil condensate loading rack emissions 

corresponding to the production of oil and condensate at oil wells and natural gas wells located 

in each county, based on the input variables discussed above. 

Example Calculation for Oil and Condensate Loading:

 Using the equations provided above, ERG calculated VOC emissions in Anderson 

County from oil loading as follows: 

 

where: 

LLik = (the loading loss [lb/1,000 gal of liquid loaded] for Anderson County, and 

 pollutant k) 

S = 1.00 (the saturation factor (based on type of loading operation)) 

Pi = 3.1 (the true vapor pressure of liquid loaded for Anderson County) [psia] 

M = 50 (the molecular weight of tank vapors) [lb/lb-mole] 

Ti = 524.27 (the temperature of bulk liquid loaded for Anderson County) [oR] 

where: 

Eik = loading VOC emissions for county i, and pollutant k [tons/yr] 

TOPi = 678,901 (the total production of oil from oil wells in Anderson County) [BBL/yr] 

LLik = the loading loss (emission factor) for VOC [lb/1,000 gal loaded] 

42 is the conversion factor from barrels to gallons

2,000 is the conversion factor from pounds to tons of emissions 















 ∗ ∗

= ×

i

i

ik T

S P M

LL 12 46.













= × × ×

,2 000

1

42 Eik TOPi LLk
4-35 

Therefore: 

 LLik = 12.46 x ((1.00 x 3.1 [psia] x 50 [lb/lb-mole])/524.27 [oR]) 

 LLik = 3.684 [lb/1,000 gal of liquid loaded] 

Eik = 678,901 [BBL/yr] x 3.684 [lb/1,000 gal of liquid loaded] x 42 x (1/2,000) 

 Eik = 52.52 [tons VOC/yr] 

4.6 Well Completions 

 Following drilling and casing, a well must be “completed.” Completion is the process 

which enables the well to produce oil or gas. To complete the production well, casing is 

installed and cemented and the drilling rig is removed from the site. As the well is completed, an 

initial mixture of gas, hydrocarbon liquids, water, sand, and other materials comes to the surface. 

Standard practice during the completion process has been to vent or flare the natural gas 

released, some of which is VOC. This category addresses VOC emissions associated with the 

completion process at oil and gas wells. County-level emissions from this source were estimated 

for the purpose of this inventory. 

 Emissions from well completions were calculated using the methodology from the 2008 

CENRAP study (Bar-Ilan, et al., 2008). Emissions from well completions are estimated on the 

basis of the volume of gas vented during completion and the average VOC content of that gas, 

obtained from a gas composition analyses. Emissions rates are evaluated at standard temperature 

and pressure (STP). 

The calculation methodology for completion emissions follows the following equations: 

( / ) .0 000035 907200

( )

,

i

gas

vented

completion i

f

R MW T

P V

E ×

















× ×

×

=

where: 

Ecompletion,i is the emissions of pollutant i from a single completion event [ton/event] 

P is atmospheric pressure [1 atm] 

Vvented is the volume of vented gas per completion [MCF/event] 

R is the universal gas constant [0.082 L-atm/mol-oK] 

MWgas is the molecular weight of the gas [g/mol] 

T is the atmospheric temperature [298 oK] 

0.000035 is the conversion factor from Mscf to liters 

fi is the mass fraction of pollutant i in the vented gas 

907,200 is the conversion factor from grams to tons of emissions 
4-36 

 The total emissions from all completions occurring in a county can be evaluated 

following: 

Ecompletion,TOTAL = Ecompletion,i × Scounty

where: 

Ecompletion,TOTAL are the total emissions county-wide from completions [tons/year] 

Ecompletion,i are the completion emissions from a single completion event [tons/event] 

Scounty is the county-wide new well and recompleted well count 

 No data were available to account for the number of completions that were completed 

using green completion or add-on control technologies. While these technologies exist and are 

used to reduce emissions, no data is currently available to estimate the extent at which they are 

employed in Texas. Also, the 2008 CENRAP study did not contain data on green completions or 

add-on control technologies. 

Volume of vented gas per completion, Vvented:

 ERG was unable to obtain estimates for the volume of vented gas per completion from 

the TRC. Therefore, ERG used the average volume vented presented in the 2008 CENRAP 

study. This data was presented on a basin-level basis. The data obtained is summarized in 

Table 4-18 below. 

Table 4-18. 2008 CENRAP Data for Volume of Gas Vented per Completion 

Basin 

Volume of Gas Vented 

per Completion 

(MCF/event) 

Anadarko 1,737 

Bend Arch-Fort Worth 637 

East Texas 2,417 

Palo Duro a 1,198 

Permian 0 

Perman/Marathon Thrust Belt a 1,198 

Western Gulf 1,200 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins 

were not included in the CENRAP study. These values are an 

average of the values from the other basins.
4-37 

 The data were applied to each county in Texas based on the county’s corresponding 

basin. 

Mass fraction for a single pollutant, fi:

 ERG used the average basin-level mass fraction for VOCs obtained from the 2008 

CENRAP study (3.6% for gas wells and 14.1% for oil wells). 

Number of completions controlled by flares, cflare and the number of green completions, cgreen:

 ERG was unable to obtain estimates for the number of completions controlled by flares 

and the number of green completions. Therefore, ERG used default values presented in the 2008 

CENRAP study, which was 0 for both parameters. 

County-level new/recompleted well count, Scounty:

 ERG obtained county-level data for the number of new and recompleted wells from the 

TRC for each county included in this analysis. The TRC data indicated a total of 15,946 

new/recompletions were finished in 2008. Of these, 3,032 were designated as gas wells and 

2,687 were designated as oil wells. The remaining 10,227 wells were classified as O/G (as they 

may end up producing oil, gas or a combination of both). For the purposes of emissions 

calculations, ERG assigned the wells classified as O/G to the oil and gas categories by assuming 

that the percentage of oil and gas well completions in each county was identical to the percentage 

of producing oil and gas wells in each county. For example, if 75% of the producing wells in a 

single county were oil wells, then 75% of the wells classified as O/G were designated as oil 

wells. If there were no producing wells in a county, the completion was assumed to be an oil 

well completion to represent worst-case emissions. As a result of this analysis, there were an 

estimated 8,702 gas well competions and 7,244 oil well completions in 2008. 

Emissions by county Ecompletion,TOTAL:

 Appendix E presents county-level well completion emissions corresponding to the 

number of wells completed in each county, based on the input variables discussed above. 
4-38 

Example Calculation for Well Completions: 

 Using the equations provided above, ERG calculated VOC emissions in Anderson 

County from oil well completions as follows: 

( / ) .0 000035 907200

( )

,

i

gas

vented

completion voc

f

R MW T

P V

E ×

















× ×

×

= 

where: 

Ecompletion,voc = the VOC emissions in Anderson County from a single oil well completion 

event [ton/event] 

P = 1 (atmospheric pressure) [atm] 

Vvented = 2,417 (the volume of vented gas per completion for Anderson County (East 

Texas Basin)) [MCF/event] 

R = 0.082 (the universal gas constant) [L-atm/mol-oK] 

MWgas = 27 (the molecular weight of the gas) [g/mol] 

T = 298 (the atmospheric temperature) [oK] 

0.000035 is the conversion factor from Mscf to liters 

fi = 0.141 (the mass fraction of pollutant i in the vented gas) 

907,200 is the conversion factor from grams to tons of emissions 

Therefore: 

Ecompletion,voc = ((1 atm x 2,417 [MCF/event])/((0.082 [L-atm/mol-oK]/27 [g/mol]) x 298 

[

oK] x 0.000035) x 0.141/907200 

Ecompletion,voc = 11.86 [tons VOC/event] 

 The total emissions from all completions occurring in Anderson County can be evaluated 

following: 

Ecompletion,TOTAL = Ecompletion,voc × Scounty 

where: 

Ecompletion,TOTAL = the total VOC emissions from completions in Anderson County [tons 

VOC/year] 

Ecompletion,voc = 11.86 (completion emissions from a single completion event) [tons 

VOC/event] 

Scounty = 45.94 (the county-wide new well and recompleted well count for Anderson 

County) [oil well completion events/yr] 

Therefore: 

Ecompletion,voc = 11.86 [tons VOC/event] x 50 [oil well completion events/yr] 

Ecompletion,voc = 544.76 [tons VOC/yr] 
4-39 

4.7 Wellhead Blowdowns 

 Wellhead blowdowns refer to the practice of venting gas from wells that have developed 

some kind of cap or obstruction before any additional intervention work can be done on the 

wells. Typically, wellhead blowdowns are conducted on wells that have been shut in for a period 

of time and the operator desires to bring the well back into production. Wellhead blowdowns are 

also sometimes conducted to remove fluid caps that have built up in producing gas wells. 

Because gas is directly vented from the blowdown event, blowdowns can be a source of VOC 

emissions. County-level emissions from this source were estimated for the purpose of this 

inventory. 

 Emissions from wellhead blowdowns were calculated using the methodology from the 

2008 CENRAP study (Bar-Ilan, et al., 2008). Emissions from wellhead blowdowns are 

estimated on the basis of the volume of gas vented during a blowdown, and the average VOC 

content of that gas, obtained from a gas composition analyses. The emissions are also estimated 

based on the frequency of blowdowns. Emissions rates are evaluated at standard temperature 

and pressure (STP). 

 The calculation methodology for blowdown emissions is identical to the method for 

completion emissions, and follows the following equations: 

( / ) .0 000035 907200

( )

,

i

gas

vented

blowdown i

f

R MW T

P V

E ×

















× ×

×

= 

where: 

Ecompletion,i is the emissions of pollutant i from a single blowdown event [ton/event] 

P is atmospheric pressure [1 atm] 

Vvented is the volume of vented gas per blowdown [MCF/event] 

R is the universal gas constant [0.082 L-atm/mol-oK] 

MWgas is the molecular weight of the gas [g/mol] 

T is the atmospheric temperature [298 oK] 

0.000035 is the conversion factor from Mscf to liters 

fi is the mass fraction of pollutant i in the vented gas 

907,200 is the conversion factor from grams to tons of emissions 

 The total emissions from all blowdowns occurring in a county can be evaluated 

following: 
4-40 

Eblowdown,TOTAL = Eblowdown,i × Nblowdown × Nwells 

where: 

Eblowdown,TOTAL are the total emissions county-wide from blowdowns [tons/year] 

Eblowdown,I are the blowdown emissions from a single blowdown event [tons/event] 

Nblowdown is the number of blowdowns per well in the county

Nwells is the total number of active wells in the county 

 No data were available to account for the number of blowdowns using green completion 

or add-on control technologies. While these technologies exist and are used to reduce emissions, 

no data is currently available to estimate the extent at which they are employed in Texas. Also, 

the 2008 CENRAP study did not contain data on green blowdowns or add-on control 

technologies. Therefore, we have assumed 0 for these parameters. 

Volume of vented gas per blowdown, Vvented:

 ERG was unable to obtain estimates for the volume of vented gas per blowdown from the 

TRC. Therefore, ERG used the average volume vented presented in the 2008 CENRAP study. 

This data was presented on a basin-level basis. The data obtained is summarized in Table 4-19 

below. 

Table 4-19. 2008 CENRAP Data for Volume of Gas Vented per 

Blowdown per Wellhead 

Basin 

Volume of Gas Vented 

per Blowdown per 

Wellhead 

(MCF/event/wellhead) 

Anadarko 7.28 

Bend Arch-Fort Worth 38.9 

East Texas 31.67 

Palo Duro a 60.35 

Permian 50 

Perman/Marathon Thrust Belt a 60.35 

Western Gulf 173.9 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins were not included in 

the CENRAP study. These values are an average of the values from the other basins.

 The data were applied to each county in Texas based on the county’s corresponding 

basin. 
4-41 

Mass fraction for a single pollutant, fi:

 ERG used the average basin-level mass fraction for VOCs obtained from the 2008 

CENRAP study (3.6% for gas wells and 14.1% for oil wells). 

County-level number of blowdowns per well, Nblowdown:

 ERG was unable to obtain estimates for the number of blowdowns per well from the 

TRC. Therefore, ERG used the average volume vented presented in the 2008 CENRAP study. 

This data was presented on a basin-level basis. The data obtained is summarized in Table 4-20 

below. 

Table 4-20. 2008 CENRAP Data for Wellhead Blowdown Frequency 

Basin 

Blowdown Frequency 

(events/wellhead/yr) 

Anadarko 3.3 

Bend Arch-Fort Worth 1.54 

East Texas 1.09 

Palo Duro a 5 

Permian 5 

Perman/Marathon Thrust Belt a 5 

Western Gulf 0.71 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins were not included in 

the CENRAP study. These values are an average of the values from the other basins.

 The data were applied to each county in Texas based on the county’s corresponding 

basin. 

County-level well count, Nwells:

 ERG obtained county-level data for the number of wells from the TRC for each county 

included in this analysis. The TRC data (for onshore wells only) indicated a total of 91,732 gas 

wells and 153,831 oil wells for the State of Texas. 
4-42 

Number of blowdowns controlled by flares, cflare and the number of green blowdowns, cgreen:

 ERG was unable to obtain estimates for the number of blowdowns controlled by flares 

and the number of green blowdowns. Therefore, ERG used default values presented in the 2008 

CENRAP study, which was 0 for both parameters. 

Emissions by county Eblowdown,TOTAL:

 Appendix E presents county-level wellhead blowdown emissions corresponding to the 

number of wells in each county, based on the input variables discussed above. 

Example Calculation for Wellhead Blowdowns

 Using the equations provided above, ERG calculated VOC emissions in Anderson 

County from oil wellhead blowdowns as follows: 

( / ) .0 000035 907200

( )

,

i

gas

vented

blowdown voc

f

R MW T

P V

E ×

















× ×

×

= 

where: 

Eblowdown,voc = the VOC emissions in Anderson County from a single oil wellhead 

blowdown event [ton/event] 

P = 1 (atmospheric pressure) [atm] 

Vvented = 31.7 (the volume of vented gas per blowdown for Anderson County (East Texas 

Basin)) [MCF/event] 

R = 0.082 (the universal gas constant) [L-atm/mol-oK] 

MWgas = 27 (the molecular weight of the gas) [g/mol] 

T = 298 (the atmospheric temperature) [oK] 

0.000035 is the conversion factor from Mscf to liters 

fi = 0.141 (the mass fraction of pollutant i in the vented gas) 

907,200 is the conversion factor from grams to tons of emissions 

Therefore: 

Eblowdown,voc = ((1 [atm] x 31.7 [MCF/event])/((0.082 [L-atm/mol-oK]/27 [g/mol]) x 298 

[

oK] x 0.000035) x 0.141/907200 

Eblowdown,voc = 0.1554 [tons/event] 

 The total emissions from all blowdowns occurring in Anderson County can be evaluated 

following: 

Eblowdown,TOTAL = Eblowdown,voc × Nblowdown × Nwells 
4-43 

where: 

Eblowdown,TOTAL = the total VOC emissions county-wide from blowdowns [tons/year] 

Eblowdown,voc =0.1554 (the VOC blowdown emissions from a single blowdown event) 

[tons/event] 

Nblowdown =1.09 (the number of blowdowns per well in Anderson County (East Texas 

Basin)) [events/wellhead/yr]

Nwells = 456 (the total number of active wells in Anderson County) [wells] 

Therefore: 

Eblowdown, TOTAL = 0.1554 [tons VOC/event] x 1.09 [events/wellhead/yr] x 456 [wells] 

Eblowdown, TOTAL = 77.24 [tons VOC/yr] 

4.8 Pneumatic Devices 

 Pneumatic devices are used for a variety of gas well processes and are powered by highpressure produced gas. These devices include transducers, liquid level controllers, pressure 

controllers and positioners. During the normal operation of these devices, they release or bleed 

natural gas to the atmosphere making them a source of VOC emissions. County-level emissions 

from these sources are estimated for the purpose of this inventory. 

 Emissions from pneumatic devices were calculated using the methodology from the 2008 

CENRAP study (Bar-Ilan, et al., 2008). In this emission estimation approach, emissions from 

pneumatic devices at a single well site are calculated using the following equation: 

.0 000035

907200 ,

× ×

















×











= ∑ × ×

T

MW

R

P

V N t

f

E

gas

i

i i annual

j

pneumatic j

 

where: 

Epneumatic,j is the total emissions of pollutant j from all pneumatic devices for a typical well 

[ton/well-year] 

907,200 is the conversion factor from grams to tons of emissions 

fj is the mass fraction of pollutant j in the vented gas 

Vi is the volumetric bleed rate from device i [scf/hr/device] 

Ni is the total number of device i owned by the participating companies 

tannual is the number of hours per year that devices are operating 

P is the atmospheric pressure [1 atm] 

R is the universal gas constant [0.082 L-atm/mol-oK] 

MWgas is the molecular weight of the gas [g/mol] 

T is the atmospheric temperature [298 oK] 

0.000035 is the conversion factor from Mscf to liters 
4-44 

 County-wide emissions are calculated using the following equation: 

Epneumatic,TOTAL = Epneumatic, j × Nwell 

where: 

Epneumatic,TOTAL is the total pneumatic device emissions in the county [ton/yr] 

Epneumatic,j is the pneumatic device emissions for a single well of pollutant j [ton/yr] 

Nwell is the total number of active wells in the county for a given year 

 Emissions rates are evaluated at STP. 

Number of active wells in a given county for 2008, Nwell:

 Total active wells by county for the full 2008 year are not readily available from the TRC 

website. However, well distribution data by county is available from the TRC website on a biannual (February and September) basis and can be found at: 

http://www.rrc.state.tx.us/data/wells/wellcount/index.php. ERG used the September 2008 TRC 

report to get a count of regular producing wells by county. 

Volumetric bleed rate from device i, Vi:

 Bleed rates for various devices are presented in a 2004 EPA Natural Gas Star program 

study. We have used these when calculating emissions from pneumatic devices at gas 

production sites. This data is summarized in Table 4-21. 

Total number of devices, Ni:

 The 2008 CENRAP study obtained basin-level data for the total number of devices per 

well from survey data. The same value for each device type was used for each basin in the 

CENRAP report. ERG used this basin level data as a basis for the number of devices per well. 

This data is summarized in Table 4-21. 

Number of hours per year that devices are operating, tannual:

 ERG has assumed the annual operating hours for these devices is 8,760. 
4-45 

Molecular weight of gas, MWgas:

 The 2008 CENRAP study obtained basin-level data for the gas molecular weight from 

survey data. Where survey data was not available for a specific basin, the average of all 

CENRAP basins was used. ERG used this basin level data as a basis for the gas molecular 

weight. ERG calculated a weighted average based on the total number of wells in each basin. 

This data is summarized in Table 4-21. 

Mass fraction of pollutant j in the vented gas, fj:

 The 2008 CENRAP study obtained basin-level data for the mass fraction of VOC from 

survey data. Where survey data was not available for a specific basin, the average of all 

CENRAP basins was used. ERG used this basin level data as a basis for the VOC mass fraction. 

ERG calculated a weighted average based on the total number of wells in each basin. This data 

is summarized in Table 4-21. 

Table 4-21. CENRAP Basin-Level Data for Pneumatic Devices at Gas Wells 

Number of Devices/Bleed Rate (scf/hr) 

Basin 

Liquid 

Level 

Controller Positioner

Pressure 

Controller Transducer Other

Gas 

Molecular 

Weight 

(g/mol) 

VOC 

Content 

(fraction)

Anadarko 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 21 0.1 

East 

Texas 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 19 0.13 

Fort 

Worth 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 19 0.14 

Permian 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 19 0.14 

Western 

Gulf 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 19 0.02 

Palo 

Duroa 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 20 0.11 

Marathon 

Thrust 

Belta

2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 20 0.11 

Weighted 

Average 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 19.68 0.1054 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins were not included in the CENRAP study. These 

values are an average of the values from the other basins.
4-46 

Emissions by county Epneumatic,TOTAL: 

 Appendix E presents county-level pneumatic device emissions corresponding to the 

number of active oil and gas wells in each county, based on the input variables discussed above. 

Example Calculation for Pneumatic Devices: 

 Using the equations provided above, ERG calculated VOC emissions in Anderson 

County from pneumatic devices as follows: 

For one well: 

.0 000035

907200 ,

× ×

















×











= ∑ × ×

T

MW

R

P

V N t

f

E

gas

i

i i annual

j

pneumatic j

Where: 

Epneumatic,j = VOC emissions from one well in Anderson County [tons/well-year] 

907,200 is the conversion factor from grams to tons of emissions 

fj = 0.1054 (the VOC fraction in the vented gas in Anderson County) 

Vi = 0.031 for liquid level controllers and 0.0168 for pressure controllers (bleed rate for 

devices present in wells in Anderson County) [Mcf/device-hr] 

Ni = 2 for liquid level controllers and 1 for pressure controllers (number of devices 

present in wells in Anderson County) 

tannual = 8,760 (annual operating hours of wells in Anderson County) [hr/yr]

P = 1 (standard pressure) [atm] 

T = 298 (standard temperature) [oK] 

R = 0.082 (universal gas constant) [L-atm/mol-oK] 

MWgas = 19.68 (molecular weight of vented gas at wells in Anderson County) [g/mol] 

0.000035 is the conversion factor from Mscf to liters 

Therefore: 

Epneumatic,j = (0.1504/907,200) x ((0.031 [Mcf/device-hr] * 2 [devices] * 8,760 [hrs]) + 

(0.0168 [MCF/device-hr] * 1 [device] * 8,760 [hrs])) x (1/((0.082 [L-atm/mol-oK] / 19.68 

[g/mol]) * 298 [oK] * 0.000035)) 

Epneumatic,j = 1.845 [tons VOC/well-yr] 

For all wells in Anderson County: 

Epneumatic,TOTAL = Epneumatic, j × Nwell

Where: 

Epneumatic,TOTAL = VOC emissions from all gas wells in Anderson County [tons/yr] 

Epneumatic,j = 1.845 [tons VOC/well-yr] 

Nwell = 133 (number of wells in Anderson County) 
4-47 

Therefore: 

Epneumatic,TOTAL = 1.845 [tons VOC/well-yr] x 133 [wells] 

Epneumatic,TOTAL = 245 [tons VOC/yr] 

4.9 Fugitive Emissions (Equipment Leaks) 

 All oil and gas producing sites have a system of pumps and piping to transport oil and gas 

from the wellhead to the processing area. These pumps and piping networks are constructed 

with many individual components including flanges, valves, seals, and connectors. As a result of 

high operating pressures, varying fitting tightness, and age and condition, each of these 

components has the potential to release fugitive emissions while oil and gas product flows 

through them. County-level emissions from these sources are estimated for the purpose of this 

inventory. 

 Emissions from fugitive components were calculated using the methodology from the 

2008 CENRAP study (Bar-Ilan, et al., 2008). In this methodology, fugitive emissions from a 

single well site may be calculated using the following equation: 

= ∑ × × × ×

i

fugitive j i i annual Yj E EF N t .0 0011 ,

 

where: 

Efugitive,j is the fugitive emissions for a single typical well for pollutant j [ton/yr/well] 

EFi is the emission factor of Total Organic Carbon (TOC) for a single component i

[kg/hr/component] 

Ni is the total number of components of type i

tannual is the annual number of hours the well is in operation [hr/yr] 

Yj is the mass fraction of pollutant j to TOC in the vented gas 

0.0011 is the conversion factor from tons to kilograms 

 County-wide fugitive emissions are calculated using the following equation: 

E fugitive,TOTAL = E fugitive, j × Nwell 

where: 

Efugitive,TOTAL is the total fugitive emission in the county [ton/yr] 

Efugitive,j is the fugitive emissions for a single well of pollutant j [ton/yr] 

Nwell is the total number of active wells in the county for a given year 

 Emissions rates are evaluated at STP. 
4-48 

Number of active wells in a given county for 2008, Nwell:

 Total active wells by county for the full 2008 year are not readily available from the TRC 

website. However, well distribution data by county is available from the TRC website on a biannual (February and September) basis and can be found at: 

http://www.rrc.state.tx.us/data/wells/wellcount/index.php. ERG used the September 2008 TRC 

report to get a count of regular producing wells by county. 

Emission factor of TOC for a single component, EFi:

 AP-42 emissions factors were used to calculate fugitive emissions from equipment leaks 

at oil and gas production sites. Emissions factors are referenced from the AP-42 supporting 

document entitled “Protocol for Equipment Leak Emission Estimations” and summarized in 

Table 4-22 below. 

Table 4-22. AP-42 Emissions Factors for Fugitive Components 

Emissions Factor (kg-TOC/hr) 

Component Type Gas Light Oil 

Valves 0.0045 0.0025 

Pump Seals 0.0024 0.013 

Others 0.0088 0.0075 

Connectors 0.0002 0.00021 

Flanges 0.00039 0.00011 

Open-ended Lines 0.002 0.0014 

Total number of components, Ni:

 The 2008 CENRAP study obtained basin-level data for the total number of components 

per well from survey data. ERG used this basin level data as a basis for the number of 

components per well. ERG calculated a weighted average based on the number of wells at each 

basin. This data is summarized in Table 4-23 for gas wells and Table 4-24 for oil wells. The 

CENRAP data did not contain information on component counts for “Pump Seals”, or “Others” 

(equipment such as dump lever arms, polish rod pumps, or hatches). Therefore, an estimate of 2 

“Pump Seals” and 10 “Others” were used to gapfill the CENRAP data to complete the inventory 

(Maldonado, 2010). 
4-49 

Annual number of hours the well is in operation, tannual:

 ERG used 8,760 hours per year for the hours the well is in operation. 

Mass fraction of pollutant j to TOC in the vented gas, Yj:

 The 2008 CENRAP study obtained basin-level data for the fraction of VOC to TOC in 

the vented gas from survey data. ERG used this basin level data as a basis for the fraction of 

VOC to TOC in the vented gas. ERG calculated a weighted average based on the number of 

wells at each basin. This data is summarized in Table 4-23 for gas wells and Table 4-24 for oil 

wells. 

Table 4-23. CENRAP Basin-Level Data for Fugitives at Gas Wells 

Number of Components Per Typical Well 

Basin Valves 

Pump 

Seals Others Connectors Flanges 

OpenEnded 

Lines 

Fraction 

of VOC 

in TOC 

Anadarko 12 2 10 35 18 6 0.12 

East Texas 12 2 10 35 18 6 0.14 

Fort 

Worth 12 2 10 35 18 6 0.15 

Permian 19 2 10 43 29 3 0.14 

Western 

Gulf 24 2 10 118 59 3 0.02 

Palo Duroa16 2 10 53 28 5 0.11 

Marathon 

Thrust 

Belta

16 2 10 53 28 5 0.11 

Weighted 

Average 16.54 2.00 10.00 58.53 31.00 4.62 0.11226 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins were not included in the CENRAP study. These 

values are an average of the values from the other basins. 

Table 4-24. CENRAP Basin-Level Data for Fugitives at Oil Wells 

Number of Components Per Typical Well 

Basin Valves 

Pump 

Seals Others Connectors Flanges 

OpenEnded 

Lines 

Fraction 

of VOC 

in TOC 

Anadarko 20 2 10 90 0 3 0.12 

East Texas 20 2 10 90 0 3 0.14 

Fort 

Worth 20 2 10 90 0 3 0.15 

Permian 16 2 10 58 12 2 0.14 
4-50 

Table 4-24. CENRAP Basin-Level Data for Fugitives at Oil Wells (Cont.) 

Number of Components Per Typical Well 

Basin Valves 

Pump 

Seals Others Connectors Flanges 

OpenEnded 

Lines 

Fraction 

of VOC 

in TOC 

Western 

Gulf 18 2 10 95 25 2 0.02 

Palo Duroa19 2 10 85 7 3 0.11 

Marathon 

Thrust 

Belta

19 2 10 85 7 3 0.11 

Weighted 

Average 18.80 2.00 10.00 84.60 7.40 2.60 0.11226 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins were not included in the CENRAP study. These 

values are an average of the values from the other basins. 

Emissions by county Efugitive,TOTAL: 

 Appendix E presents county-level fugitive emissions corresponding to the number of 

active oil and gas wells in each county, based on the input variables discussed above. 

Example Calculation for Fugitive Emissions (Equipment Leaks):

 Using the equations provided above, ERG calculated VOC emissions in Anderson 

County from equipment leaks at oil wells as follows: 

For one well: 

= ∑ × × × ×

i

fugitive j i i annual Yj E EF N t .0 0011 ,

Where: 

Efugitive,j = VOC emissions from one oil well in Anderson County [tons/well-year] 

EFi = AP-42 emissions factors 0.0025 for valves, 0.013 for pump seals, 0.0075 for others, 

0.00021 for connectors, 0.00011 for flanges, and 0.0014 for open ended lines [kgTOC/hr] 

Ni = 18.80 for valves, 2.00 for pump seals, 10.00 for others, 84.60 for connectors, 7.40 

for flanges, and 2.60 for open ended lines (number of fugitive areas present in oil wells in 

Anderson County) 

tannual = 8,760 (annual operating hours of oil wells in Anderson County) [hr/yr]

Yj = 0.11226 (mass fraction of VOC in the TOC vented from the fugitive areas) [ton 

VOC/ton TOC] 
4-51 

Therefore: 

Efugitive,j = 8,760 [hr/yr] x 0.11226 [ton VOC/ton TOC] x 0.0011 [tons/kg] x ((0.0025 * 

18.80) + (0.013 * 2.00) + (0.0075 * 10.00) + (0.00021 * 84.60) + (0.00011 * 7.40) + 

(0.0014 * 2.60) [kg-VOC/well-hr])) 

Epneumatic,j = 0.18413 [tons VOC/well-yr] 

For all wells in Anderson County: 

E fugitive,TOTAL = E fugitive, j × Nwell

Where: 

Efugitive,TOTAL = VOC emissions from all oil wells in Anderson County [tons/yr] 

Efugitive,j = 0.18413 [tons VOC/well-yr] 

Nwell = 456 (number of oil wells in Anderson County) 

Therefore: 

Epneumatic,TOTAL = 0.18413 [tons VOC/well-yr] x 456 wells 

Epneumatic,TOTAL = 83.97 [tons VOC/yr] 

4.10 Heaters and Boilers 

 The purpose of heaters and boilers at oil and gas production facilities is to provide 

thermal energy input to certain operations within the production process. They can be used as 

separator heaters (heater treaters) to provide heat input to separation units, as tank heaters to 

maintain storage tank temperatures, or as inline heaters to maintain temperature within pipes and 

connections. Heaters and boilers may also be used in dehydrators; however, these sources are 

covered under the dehydrator source methodology. Heaters and boilers are typically natural gasfired external combustors and are a source of NOx, CO, VOC and PM emissions. SO2 emissions 

may also occur if the gas used to fire the heaters contains Hydrogen Sulfide (H2S) which will be 

subsequently converted to SO2 during combustion. County-level emissions from heater sources 

are estimated for the purpose of this inventory. 

 Emissions from heaters and boilers were calculated using the methodology from the 2008 

CENRAP study (Bar-Ilan, et al., 2008). In this methodology, emissions from a single heater may 

be calculated using the following equation (excluding SO2 emissions): 

( ) × 2000

× × ×

=

local

heater heater annual

heater HV

EF Q t hc

E 
4-52 

where: 

Eheater is the emissions from a given heater [ton/yr] 

EFheater is the emission factor for a heater for a given pollutant [lb/MMscf] 

Qheater is the heater MMBtu/hr rating [MMBturated/hr] 

HVlocal is the local natural gas heating value [MMBtulocal/MMscf] 

tannual is the annual hours of operation [hr/yr] 

hc is the heater cycling fraction to account for the fraction of operating hours that the 

heater is firing. 

2000 is the conversion factor from pounds to tons of emissions 

 SO2 emissions from a single heater may be calculated using the following equation: 

































× ×

















×

× ×

×

×

=

.0 035

907200

78.1

2

2

,

T

MW

R

P

HV

f Q t hc

E

gas

local

H S heater annual

heater SO 

where: 

Eheater,SO2 is the SO2 emissions from a given heater [ton-SO2/yr] 

1.78 is the mass ratio of SO2 to H2S 

fH2S is the mass fraction of H2S in the gas 

907200 is the conversion factor from grams to tons of emissions 

Qheater is the heater MMBtu/hr rating [MMBturated/hr] 

tannual is the annual hours of operation [hr/yr] 

hc is the heater cycling fraction to account for the fraction of operating hours that the 

heater is firing. 

HVlocal is the local natural gas heating value [MMBtulocal/MMscf] 

P is atmospheric pressure [1 atm] 

R is the universal gas constant [0.082 L-atm/mol-oK] 

MWgas is the molecular weight of the gas [g/mol] 

T = 298 (standard temperature) [oK] 

0.035 is the conversion factor from cubic feet to liters 

 The total emissions generated by heaters and boilers from specific county are calculated 

using the following equation: 

2000

,

, ,

TOTAL j

heater TOTAL heater i heater

W

E = E × N × 

where: 

Eheater,TOTAL is the total heater emissions of pollutant i in county j [ton/yr] 

Eheater,i is the total emissions of pollutant i from a single heater [ton/yr] 

WTOTAL,j is the total number of wells in county j 

Nheater is the typical number of heaters per well in the county 

2000 is the conversion factor from pounds to tons of emissions 
4-53 

Total number of wells in a given county for 2008, WTOTAL,j:

 Total active wells by county for the full 2008 year are not readily available from the TRC 

website. However, well distribution data by county is available from the TRC website on a biannual (February and September) basis and can be found at: 

http://www.rrc.state.tx.us/data/wells/wellcount/index.php. ERG used the September 2008 TRC 

report to get a count of regular producing wells by county. 

Emission factor for a heater for a given pollutant, EFheater:

 ERG used EPA’s AP-42 emissions factors when calculating emissions from heaters and 

boilers at oil and gas production sites. Emissions factors are referenced from Tables 1.4-1 and 

1.4-2 of AP 42, Fifth Edition, Volume I, Chapter 1: External Combustion Sources and 

summarized in Table 4-25 below. 

Table 4-25. AP-42 Emissions Factors for Natural Gas Fired Heaters 

Pollutant Emissions Factor 

(lb/MMscf) 

NOx 100 

CO 84 

PM10 7.6a

VOC 5.5 

a

 PM10 assumed to be equal to PM2.5. 

Heater MMBTU/hr rating, Qheater:

 The 2008 CENRAP study obtained basin-level data for the heater rating from survey 

data. ERG used this basin level data as a basis for the heater rating. ERG calculated a weighted 

average based on the number of wells at each basin. This data is summarized in Table 4-26 for 

gas wells and Table 4-27 for oil wells. 

Local natural gas heating value, HVlocal:

 The 2008 CENRAP study obtained basin-level data for the local heating value from 

survey data. The same value was used for the gas well heating value and oil well heating value 

for each basin in the CENRAP report. The gas well value was 1,209 MMBtu/MMscf, and the oil 
4-54 

well value was 1,655 MMBtu/MMscf. ERG used this basin level data as a basis for the local 

heating values. 

Annual hours of operation, tannual:

 The 2008 CENRAP study obtained basin-level data for the annual heater operating hours 

from survey data. ERG used this basin level data as a basis for the annual operating hours. ERG 

calculated a weighted average based on the number of wells at each basin. This data is 

summarized in Table 4-26 for gas wells and Table 4-27 for oil wells. 

Heater cycling fraction, hc:

 The 2008 CENRAP study used a default value of 1 for heater cycling fraction. ERG also 

used this as a basis for the heater cycling fraction. 

Mass fraction of H2S, fH2S:

 The 2008 CENRAP study obtained basin-level data for the mass fraction of H2S from 

survey data. ERG used this basin level data as a basis for the mass fraction of H2S. ERG 

calculated a weighted average based on the number of wells at each basin. This data is 

summarized in Table 4-26 for gas wells and Table 4-27 for oil wells. 

Molecular weight of gas, MWgas:

 The 2008 CENRAP study obtained basin-level data for the gas molecular weight from 

survey data. ERG used this basin level data as a basis for the gas molecular weight. ERG 

calculated a weighted average based on the number of wells at each basin. This data is 

summarized in Table 4-26 for gas wells and Table 4-27 for oil wells. 

Typical number of heater per well, Nheater:

 The 2008 CENRAP study obtained basin-level data for the average number of heaters per 

well from survey data. ERG used this basin level data as a basis for the average number of 

heaters per well. ERG calculated a weighted average based on the number of wells at each 

basin. This data is summarized in Table 4-26 for gas wells and Table 4-27 for oil wells. 
4-55 

Table 4-26. CENRAP Basin-Level Data for Heaters at Gas Wells 

Heater Operating Parameters 

Natural Gas Fuel 

Parameters 

Basin 

Number of 

heaters in 

a typical 

well setup 

Heater 

Firing Rate 

[MMBtu/hr]

Annual 

Activity 

[hr] 

Local Heating 

Value 

[MMBtu/MMscf]

Heater 

Cycling

MWgas

[g/mol] 

H2S Mass 

Fraction 

Anadarko 0.94 0.92 4,601 1,209 1 21 - 

East 

Texas 0.95 0.64 2,982 1,209 1 19 0.02 

Fort 

Worth 1 0.50 4,380 1,209 1 20 - 

Permian 0.54 0.69 4,121 1,209 1 19 0.0001 

Western 

Gulf 1.1 0.46 4,297 1,209 1 19 - 

Palo 

Duroa 0.91 0.64 4,076 1,209 1 20 0.005 

Marathon 

Thrust 

Belta

0.91 0.64 4,076 1,209 1 20 0.005 

Weighted 

Average 0.91 0.64 4,076 1,209 1 20 0.005 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins were not included in the CENRAP study. These values 

are an average of the values from the other basins. 

Table 4-27. CENRAP Basin-Level Data for Heaters at Oil Wells 

Heater Operating Parameters 

Natural Gas Fuel 

Parameters 

Basin 

Number of 

heaters in 

a typical 

well setup 

Heater 

Firing Rate 

[MMBtu/hr]

Annual 

Activity 

[hr] 

Local Heating 

Value 

[MMBtu/MMscf]

Heater 

Cycling

MWgas

[g/mol] 

H2S Mass 

Fraction 

Anadarko 0.94 0.92 4,601 1,655 1 23 - 

East 

Texas 0.95 0.64 2,982 1,655 1 27 1.30 

Fort 

Worth 1 0.50 4,380 1,655 1 25 - 

Permian 0.54 0.69 4,121 1,655 1 34 6.50 

Western 

Gulf 1.1 0.46 4,297 1,655 1 25 - 

Palo 

Duroa 0.91 0.64 4,076 1,655 1 27 1.56 
4-56 

Table 4-27. CENRAP Basin-Level Data for Heaters at Oil Wells (Cont.) 

Heater Operating Parameters 

Natural Gas Fuel 

Parameters 

Basin 

Number of 

heaters in 

a typical 

well setup 

Heater 

Firing Rate 

[MMBtu/hr]

Annual 

Activity 

[hr] 

Local Heating 

Value 

[MMBtu/MMscf]

Heater 

Cycling

MWgas

[g/mol] 

H2S Mass 

Fraction 

Marathon 

Thrust 

Belta

0.91 0.64 4,076 1,655 1 27 1.56 

Weighted 

Average 0.91 0.64 4,076 1,655 1 27 1.56 

a

Data for the Palo Duro and Permian/Marathon Thrust Belt Basins were not included in the CENRAP study. These values 

are an average of the values from the other basins. 

HAP Emissions for Heaters and Boilers: 

 HAP emissions from heaters and boilers were calculated using VOC and PM speciation 

data as follows: 

EVOC-HAP = EVOC x (E%VOC-HAP /100) 

where: 

EVOC-HAP = Speciated VOC-HAP emissions [tons/yr] 

EVOC = VOC emissions [tons/yr] 

E%VOC-HAP = % HAP composition of VOC emissions 

and 

EPM-HAP = EPM x (E%PM-HAP /100) 

where: 

EPM-HAP = Speciated PM-HAP emissions [tons/yr] 

EPM = PM emissions [tons/yr] 

E%PM-HAP = % HAP composition of PM emissions 

 Appendix C contains the VOC and PM HAP speciation data. 

Emissions by county Eheater,TOTAL: 

 Appendix E presents county-level heater emissions corresponding to the number of active 

oil and gas wells in each county, based on the input variables discussed above. 
4-57 

Example Calculation for Heaters and Boilers:

 Using the equations provided above, ERG calculated NOx and SO2 emissions in 

Anderson County from heaters and boilers at oil wells as follows: 

For NOx emissions from one heater: 

( ) × 2000

× × ×

=

local

heater heater annual

heater HV

EF Q t hc

E

Where: 

Eheater = NOx emissions from one heater in Anderson County [tons/year] 

EFheater = 100 (AP-42 emissions factor for NOx) [lb/MMscf] 

Qheater = 0.64 (heater firing rate) [MMBtu/hr] 

HVlocal = 1,655 (local natural gas heating value) [MMBTUlocal/MMscf]) 

tannual = 4,076 (annual hours of heater operation) [hr/yr]

hc = 1 (heater cycling fraction to account for the fraction of operating hours that the 

heater is firing) 

2000 is the conversion factor from pounds to tons of emissions 

Therefore: 

Eheater = (100 [lb/MMscf] * 0.64 [MMBtu/hr] * 4,076 [hr/yr] * 1)/(1,655 

[MMBtu/MMscf] * 2000 [lb/ton]) 

Eheater = 0.07881 [tons NOx /heater-yr] 

For all wells in Anderson County: 

Eheater,TOTAL = Eheater,i × Nheater ×WTOTAL, j

Where: 

Eheater,TOTAL = NOx emissions from all oil wells in Anderson County [tons/yr] 

Eheater,j = 0.07881 [tons NOx /heater-yr] 

Nheater = 0.91 (average number of heaters per well) 

WTOTAL,j = 456 (number of wells in Anderson County) 

Therefore: 

 Eheater,TOTAL = 0.07881 [tons NOx /heater-yr] x 0.91 [heaters/well] x 456 [wells] 

Eheater,TOTAL = 32.70 [tons NOx /yr] 
4-58 

For SO2 emissions from one heater: 

































× ×

















×

× ×

×

×

=

.0 035

907200

78.1

2

2

,

T

MW

R

P

HV

f Q t hc

E

gas

local

H S heater annual

heater SO

Where: 

Eheater,SO2 = SO2 emissions from one heater [ton-SO2/yr] 

fH2S = 1.56 (mass fraction of H2S in the gas) 

Qheater = 0.64 (heater firing rate) [MMBtu/hr] 

HVlocal = 1,655 (local natural gas heating value) [MMBtulocal/MMscf]) 

tannual = 4,076 (annual hours of heater operation) [hr/yr]

hc = 1 (heater cycling fraction to account for the fraction of operating hours that the 

heater is firing) 

P = 1 (standard pressure) [atm] 

R = 0.082 (universal gas constant) [L-atm/mol-oK] 

T = 298 (standard temperature) [oK] 

MWgas = 27 (molecular weight of the gas) [g/mol] 

Therefore: 

Eheater,SO2 = ((1.78 * 1.56)/907,200) x (((0.64 [MMbtu/hr] * 4,076 [hr/yr] * 1)/1,655 

[MMBtu/MMscf]) x (1/((0.082 [L-atm/mol-oK] /27 [g/mol]) * 298 [oK] * 0.035)) 

Eheater,SO2 = 1.5231 x 10-4 [tons SO2/heater-yr] 

For all wells in Anderson County: 

Eheater,TOTAL = Eheater,i × Nheater ×WTOTAL, j

Where: 

Eheater,TOTAL = SO2 emissions from all oil wells in Anderson County [tons/yr] 

Eheater,j = 1.5231 x 10-4 [tons SO2/heater-yr] 

Nheater = 0.91 (average number of heaters per well) 

WTOTAL,j = 456 (number of wells in Anderson County) 

Therefore: 

Eheater,TOTAL = 1.5231 x 10-4 [tons SO2/heater-yr] x 0.91 [heaters/well] x 456 wells 

Eheater,TOTAL = 0.0632 [tons SO2/yr] 
5-1 

5.0 RESULTS 

 Detailed emission estimates developed for this project are found in Appendix D for 

compressor engines, and in Appendix E for the remainder of the source types. These Appendices 

contain county-level emissions for source category on an individual pollutant basis. Table 5-1 

presents a state-wide summary of criteria pollutant (and total HAP) emissions by source category, 

Table 5-2 presents a summary of criteria pollutant (and total HAP) emissions for each county, and 

Table 5-3 presents a summary of state-wide speciated HAP emissions by source type. 

 As Table 5-1 indicates, natural gas compressor engines account for nearly 70 percent of 

state-wide NOx emissions with pumpjack engines accounting for another 20 percent of total NOx

emissions. Oil and gas well heaters account for the remaining 10 percent, with a small contribution 

from glycol dehydrator boilers. The relative contribution of these sources to state-wide CO 

emissions are similar, with oil and gas well heaters comprising a slightly higher percentage of 

emissions at approximately 13 percent. 

 The majority of PM10 and PM2.5 emissions are also from combustion sources, but the oil 

and gas well heaters are the primary source type, contributing nearly 60 percent to state-wide 

totals. The remainder of PM10 and PM2.5 emissions come from compressor engines and pumpjack 

engines, with a small contribution from glycol dehydrator boilers. 

 The profile is quite different for VOC, where over 70 percent of emissions originate from 

oil and condensate storage tanks. Condensate tanks in particular comprise over 50 percent of statewide VOC emissions from oil and gas area sources. The remainder of VOC is emitted from the 

combustion sources mentioned above, and other minor source types such as well completions and 

blowdowns, pneumatic devices (which contribute over 10% of the total VOC emissions), and 

equipment leak fugitives. 

 The relative profile of the contribution of each source type to state-wide HAP emissions is 

similar to that of VOC emissions. Oil and condensate storage tanks contribute over 65 percent of 

the state-wide total HAP emissions, with dehydrators contributing over 15 percent of the statewide total HAP emissions. The remainder of HAP emissions come from combustion sources and 

oil and condensate loading racks.
5-2 

Table 5-1. State-wide Emissions Inventory for 2008 by Source Category 

SCC Source Category Description 

CO 

(tons/yr) 

NOx

(tons/yr) 

PM10

(tons/yr)

PM2.5

(tons/yr) 

SO2

(tons/yr)

V

(to

2310000330 Artificial Lift 23,169.14 46,369.72 154.04 154.04 9.56 2310011020 Storage Tanks: Crude Oil 282310011100 Heater Treater 9,267.25 11,032.44 838.47 838.47 21.32 2310011201 

Tank Truck/Railcar Loading: Crude Oil 2

2310011450 Wellhead 112310011501 Fugitives: Connectors 2310011502 Fugitives: Flanges 2310011503 Fugitives: Open Ended Lines 2310011504 Fugitives: Pumps 2310011505 Fugitives: Valves 2310011506 Fugitives: Other 12310020600 Compressor Engines 133.77 464.56 13.58 13.58 0.21 2310021010 Storage Tanks: Condensate 862310021030 

Tank Truck/Railcar Loading Condensate 

2310021100 Gas Well Heaters 7,564.83 9,005.75 684.44 684.44 0.04 2310021101 

Natural Gas Fired 2-Cycle Lean Burn Compressor Engines <50 Hp 140.52 209.25 9.72 9.72 0.16 

2310021102 

Natural Gas Fired 2-Cycle Lean Burn Compressor Engines 50 To 499 Hp 2,907.93 13,776.30 352.37 352.37 5.71 

2310021203 

Natural Gas Fired 4-Cycle Lean Burn Compressor Engines 500+ Hp 14,746.41 27,288.73 76.95 76.95 15.94 

2310021301 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines <50 Hp 93.37 1,175.69 3.86 3.86 0.25 
5-3 

Table 5-1. State-wide Emissions Inventory for 2008 by Source Category (Cont.) 

SCC Source Category Description 

CO 

(tons/yr) 

NOx

(tons/yr) 

PM10

(tons/yr)

PM2.5

(tons/yr) 

SO2

(tons/yr)

V

(to

2310021302 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50 To 499hp 38,988.69 86,462.54 226.24 226.24 14.83 

2310021400 Gas Well Dehydrators 904.59 293.36 2310021402 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 50-499hp W/ Nscr 767.55 3,321.00 35.02 35.02 2.05 

2310021403 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines 500+ Hp W/ Nscr 29,646.80 47,837.57 175.33 175.33 11.26 

2310021501 Fugitives: Connectors 2310021502 Fugitives: Flanges 2310021503 Fugitives: Open Ended Lines 2310021504 Fugitives: Pumps 2310021505 Fugitives: Valves 2310021506 Fugitives: Other 2310021600 Gas Well Venting 2310121700 

Gas Well Completion: All Processes 1

2310111700 

Oil Well Completion: All Processes 1

2310121401 Gas Well Pneumatic Pumps 16

Total: 128,330.85 247,236.91 2,570.01 2,570.01 81.34 1,56
5-4 

Table 5-2. State-wide Emissions Inventory for 2008 by County 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Anderson 241.28 444.72 5.31 5.31 0.16 2,858.2Andrews 1,825.99 3,291.18 49.14 49.14 1.57 31,691.4Angelina 161.97 311.11 2.15 2.15 0.08 629.3Aransas 165.25 317.00 2.28 2.28 0.09 6,574.0Archer 614.91 1,088.88 18.74 18.74 0.58 2,719.0Armstrong 0.00 0.00 0.00 0.00 0.00 0.0Atascosa 321.56 578.81 8.71 8.71 0.27 2,237.2Austin 127.18 237.83 2.42 2.42 0.07 2,040.5Bailey 0.00 0.00 0.00 0.00 0.00 0.0Bandera 0.21 0.37 0.01 0.01 0.00 5.1Bastrop 74.21 128.49 2.56 2.56 0.06 1,286.1Baylor 26.78 47.39 0.82 0.82 0.03 189.3Bee 581.15 1,101.85 9.42 9.42 0.31 4,717.4Bell 0.00 0.00 0.00 0.00 0.00 0.0Bexar 531.99 941.46 16.28 16.28 0.51 2,120.8Blanco 0.00 0.00 0.00 0.00 0.00 0.0Borden 166.31 300.48 4.40 4.40 0.14 4,107.3Bosque 3.45 6.30 0.08 0.08 0.00 17.4Bowie 5.13 9.25 0.14 0.14 0.00 148.7Brazoria 207.73 199.95 6.59 6.59 0.28 14,003.4Brazos 240.26 444.10 5.18 5.18 0.16 3,781.1Brewster 0.00 0.00 0.00 0.00 0.00 5.8Briscoe 0.00 0.00 0.00 0.00 0.00 12.3Brooks 690.71 1,318.85 10.17 10.17 0.35 16,242.0Brown 204.73 339.96 8.55 8.55 0.14 1,626.8Burleson 366.21 669.08 8.80 8.80 0.28 3,881.3Burnet 0.00 0.00 0.00 0.00 0.00 0.0
5-5 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Caldwell 676.24 1,197.43 20.61 20.61 0.64 3,452.6Calhoun 189.99 360.25 3.07 3.07 0.10 7,473.4Callahan 182.61 321.30 5.76 5.76 0.16 983.4Cameron 1.68 3.12 0.03 0.03 0.00 10.2Camp 30.41 55.01 0.79 0.79 0.03 259.2Carson 569.73 1,021.51 15.74 15.74 0.41 1,954.7Cass 54.95 98.13 1.55 1.55 0.04 662.4Castro 0.00 0.00 0.00 0.00 0.00 0.0Chambers 84.76 94.63 2.75 2.75 0.11 4,424.0Cherokee 364.58 682.18 6.78 6.78 0.18 2,911.3Childress 1.69 2.99 0.05 0.05 0.00 57.4Clay 231.82 409.65 7.14 7.14 0.21 1,476.8Cochran 445.16 791.68 13.17 13.17 0.41 6,168.3Coke 109.55 200.99 2.54 2.54 0.08 1,010.2Coleman 173.73 295.58 6.51 6.51 0.13 1,363.8Collin 0.00 0.00 0.00 0.00 0.00 0.0Collingsworth 50.04 76.34 2.77 2.77 0.02 742.6Colorado 319.38 601.84 5.54 5.54 0.16 4,980.6Comal 0.00 0.00 0.00 0.00 0.00 0.0Comanche 34.22 53.57 1.76 1.76 0.02 438.4Concho 72.58 128.12 2.23 2.23 0.06 821.0Cooke 495.43 884.64 14.25 14.25 0.45 3,467.0Coryell 0.00 0.00 0.00 0.00 0.00 3.1Cottle 95.67 180.55 1.63 1.63 0.05 2,376.4Crane 1,739.98 3,208.47 38.61 38.61 1.26 17,274.9Crockett 2,274.88 4,015.15 68.61 68.61 1.15 28,501.9Crosby 85.55 151.51 2.61 2.61 0.08 1,056.1
5-6 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Culberson 72.79 137.98 1.20 1.20 0.04 284.4Dallam 0.00 0.00 0.00 0.00 0.00 0.0Dallas 28.04 80.04 0.21 0.21 0.02 24.6Dawson 275.48 492.78 7.84 7.84 0.25 5,344.5Deaf Smith 0.00 0.00 0.00 0.00 0.00 0.0Delta 0.00 0.00 0.00 0.00 0.00 0.0Denton 1,763.52 4,690.36 29.51 29.51 1.14 13,254.5Dewitt 676.49 1,300.83 9.00 9.00 0.35 11,617.0Dickens 49.70 88.22 1.49 1.49 0.05 1,446.4Dimmit 197.89 353.20 5.65 5.65 0.15 2,515.1Donley 0.53 0.77 0.03 0.03 0.00 15.8Duval 1,111.17 2,101.02 18.70 18.70 0.63 12,897.2Eastland 285.26 476.94 11.51 11.51 0.18 3,654.8Ector 1,798.24 3,277.22 44.40 44.40 1.47 26,211.1Edwards 270.78 492.35 6.60 6.60 0.13 1,377.0El Paso 0.00 0.00 0.00 0.00 0.00 0.0Ellis 51.17 144.09 0.47 0.47 0.04 52.4Erath 161.14 295.43 3.68 3.68 0.07 1,556.9Falls 4.01 7.09 0.12 0.12 0.00 21.4Fannin 0.00 0.00 0.00 0.00 0.00 11.8Fayette 356.62 659.40 7.64 7.64 0.23 5,607.6Fisher 107.82 193.50 2.99 2.99 0.09 1,365.5Floyd 0.42 0.75 0.01 0.01 0.00 2.9Foard 27.94 43.90 1.42 1.42 0.01 414.3Fort Bend 169.68 171.80 5.51 5.51 0.22 8,072.5Franklin 69.40 127.99 1.52 1.52 0.05 1,389.5Freestone 3,821.60 7,289.51 56.95 56.95 1.93 9,858.7
5-7 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Frio 139.12 246.28 4.21 4.21 0.12 1,393.7Gaines 1,165.52 2,133.47 27.65 27.65 0.92 27,788.3Galveston 86.46 76.28 2.61 2.61 0.12 17,475.4Garza 445.72 790.41 13.45 13.45 0.42 6,133.8Gillespie 0.00 0.00 0.00 0.00 0.00 0.0Glasscock 416.67 761.54 10.00 10.00 0.32 5,431.2Goliad 731.21 1,386.08 11.85 11.85 0.37 7,851.7Gonzales 51.40 92.76 1.37 1.37 0.04 578.1Gray 825.55 1,440.69 27.11 27.11 0.64 4,163.8Grayson 201.98 365.62 5.22 5.22 0.16 1,707.0Gregg 1,423.90 2,592.32 34.92 34.92 1.00 10,980.4Grimes 334.10 638.29 4.87 4.87 0.17 1,264.1Guadalupe 402.11 711.73 12.29 12.29 0.38 2,576.4Hale 62.99 114.67 1.57 1.57 0.05 2,698.3Hall 0.00 0.00 0.00 0.00 0.00 0.0Hamilton 3.12 5.33 0.11 0.11 0.00 36.4Hansford 377.68 676.20 10.32 10.32 0.17 2,601.0Hardeman 52.13 92.68 1.54 1.54 0.05 1,230.3Hardin 258.68 348.83 7.85 7.85 0.30 22,648.6Harris 176.00 181.67 5.65 5.65 0.23 8,801.2Harrison 1,879.59 3,514.48 35.19 35.19 0.93 25,383.9Hartley 39.06 70.27 1.04 1.04 0.02 399.5Haskell 53.83 95.30 1.64 1.64 0.05 443.8Hays 0.00 0.00 0.00 0.00 0.00 0.0Hemphill 2,092.63 3,936.72 37.08 37.08 1.03 32,774.7Henderson 453.75 854.13 7.99 7.99 0.24 2,535.1Hidalgo 3,264.69 6,276.64 43.49 43.49 1.68 56,554.9
5-8 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Hill 308.20 597.97 3.53 3.53 0.16 233.6Hockley 1,004.10 1,795.93 28.58 28.58 0.91 22,011.8Hood 926.80 1,777.59 12.89 12.89 0.47 9,914.4Hopkins 20.84 37.79 0.53 0.53 0.02 298.7Houston 164.62 308.00 3.11 3.11 0.10 1,587.9Howard 803.87 1,436.74 23.00 23.00 0.73 9,904.9Hudspeth 0.12 0.17 0.01 0.01 0.00 3.2Hunt 0.00 0.00 0.00 0.00 0.00 0.0Hutchinson 903.43 1,601.32 27.09 27.09 0.72 4,039.6Irion 531.51 961.89 13.77 13.77 0.40 5,877.2Jack 646.65 1,121.02 21.80 21.80 0.42 6,701.9Jackson 303.15 569.09 5.55 5.55 0.17 9,879.6Jasper 205.58 394.00 2.87 2.87 0.11 6,405.7Jeff Davis 0.00 0.00 0.00 0.00 0.00 1.2Jefferson 287.19 182.64 8.05 8.05 0.46 55,659.2Jim Hogg 266.50 500.41 4.83 4.83 0.14 4,021.1Jim Wells 127.37 226.90 3.61 3.61 0.06 1,576.6Johnson 4,495.48 12,647.53 43.01 43.01 3.19 5,209.1Jones 167.32 296.69 5.05 5.05 0.16 1,277.9Karnes 171.32 323.25 2.95 2.95 0.10 3,454.1Kaufman 4.50 8.03 0.14 0.14 0.00 62.8Kendall 0.00 0.00 0.00 0.00 0.00 0.0Kenedy 665.44 1,286.34 8.13 8.13 0.35 4,087.7Kent 203.51 375.70 4.48 4.48 0.16 4,304.1Kerr 0.00 0.00 0.00 0.00 0.00 0.0Kimble 2.94 4.50 0.16 0.16 0.00 41.2King 112.59 198.82 3.47 3.47 0.10 2,010.4
5-9 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Kinney 0.00 0.00 0.00 0.00 0.00 0.0Kleberg 494.21 948.96 6.71 6.71 0.25 8,845.8Knox 46.18 81.72 1.41 1.41 0.04 354.8La Salle 259.22 470.95 6.38 6.38 0.13 4,078.6Lamar 0.00 0.00 0.00 0.00 0.00 0.0Lamb 15.10 27.13 0.42 0.42 0.01 686.8Lampasas 0.16 0.20 0.01 0.01 0.00 4.2Lavaca 924.67 1,764.89 13.68 13.68 0.47 12,277.6Lee 307.30 564.26 7.08 7.08 0.23 2,650.7Leon 1,079.72 2,070.29 15.01 15.01 0.58 5,733.4Liberty 331.40 341.24 9.92 9.92 0.45 27,316.7Limestone 1,393.87 2,655.14 21.17 21.17 0.71 4,377.5Lipscomb 1,125.34 2,104.13 21.36 21.36 0.58 17,104.9Live Oak 378.16 709.70 6.91 6.91 0.20 6,807.9Llano 0.00 0.00 0.00 0.00 0.00 0.0Loving 1,567.71 3,023.10 20.15 20.15 0.89 6,348.5Lubbock 89.19 158.04 2.71 2.71 0.08 1,825.3Lynn 18.52 33.00 0.54 0.54 0.02 350.4Madison 117.26 216.26 2.56 2.56 0.07 1,290.5Marion 96.78 174.38 2.56 2.56 0.06 1,407.0Martin 596.73 1,088.02 14.69 14.69 0.49 10,928.6Mason 0.00 0.00 0.00 0.00 0.00 0.0Matagorda 609.79 1,168.96 8.47 8.47 0.32 19,098.2Maverick 182.47 323.89 5.42 5.42 0.15 3,715.5McCulloch 14.65 25.47 0.50 0.50 0.01 109.6McLennan 8.65 15.30 0.26 0.26 0.01 27.4McMullen 493.90 900.42 11.92 11.92 0.29 6,027.4
5-10 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Medina 275.72 487.25 8.50 8.50 0.26 1,235.7Menard 27.00 47.52 0.85 0.85 0.02 266.8Midland 1,610.04 2,951.97 37.75 37.75 1.27 20,938.2Milam 218.91 387.83 6.65 6.65 0.21 1,216.8Mills 0.36 0.51 0.02 0.02 0.00 6.3Mitchell 502.49 890.13 15.28 15.28 0.48 6,645.6Montague 551.48 987.06 15.59 15.59 0.49 3,448.9Montgomery 73.56 81.80 2.86 2.86 0.08 2,890.5Moore 744.02 1,343.19 19.29 19.29 0.40 3,502.8Morris 0.21 0.37 0.01 0.01 0.00 2.0Motley 3.80 6.72 0.12 0.12 0.00 52.7Nacogdoches 1,527.76 2,897.04 24.29 24.29 0.77 12,723.3Navarro 170.24 301.61 5.16 5.16 0.16 1,444.5Newton 78.50 145.69 1.63 1.63 0.05 1,601.9Nolan 133.50 240.21 3.63 3.63 0.11 1,931.6Nueces 605.47 1,127.23 11.99 11.99 0.31 15,740.1Ochiltree 561.88 1,020.35 13.94 13.94 0.31 5,760.6Oldham 5.68 10.02 0.17 0.17 0.00 247.2Orange 67.79 71.25 2.06 2.06 0.09 8,467.8Palo Pinto 455.72 785.82 15.70 15.70 0.21 7,033.4Panola 3,784.21 7,052.88 73.18 73.18 1.82 50,362.9Parker 1,225.52 3,294.01 19.49 19.49 0.80 9,840.7Parmer 0.00 0.00 0.00 0.00 0.00 0.0Pecos 4,534.56 8,670.50 66.30 66.30 2.63 21,760.8Polk 415.68 797.76 5.69 5.69 0.22 29,650.9Potter 350.79 632.33 9.25 9.25 0.21 1,799.2Presidio 0.00 0.00 0.00 0.00 0.00 0.0
5-11 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Rains 59.61 115.43 0.71 0.71 0.03 38.4Randall 0.00 0.00 0.00 0.00 0.00 0.0Reagan 1,209.82 2,204.56 29.89 29.89 0.99 11,808.6Real 1.91 3.34 0.06 0.06 0.00 16.7Red River 9.57 16.96 0.29 0.29 0.01 159.7Reeves 575.50 1,077.94 10.88 10.88 0.36 3,146.2Refugio 652.55 1,218.19 12.72 12.72 0.40 9,671.0Roberts 881.18 1,659.43 15.47 15.47 0.45 15,296.5Robertson 3,591.03 6,960.37 41.87 41.87 1.90 4,202.1Rockwall 0.00 0.00 0.00 0.00 0.00 0.0Runnels 145.66 262.06 3.96 3.96 0.12 1,177.5Rusk 2,394.04 4,447.78 48.27 48.27 1.34 26,428.9Sabine 2.04 3.67 0.06 0.06 0.00 19.2San Augustine 159.66 309.99 1.77 1.77 0.09 452.6San Jacinto 182.43 350.28 2.47 2.47 0.09 6,462.6San Patricio 303.08 570.53 5.36 5.36 0.16 12,721.0San Saba 0.00 0.00 0.00 0.00 0.00 0.0Schleicher 297.16 521.39 9.30 9.30 0.15 3,975.1Scurry 920.14 1,696.28 20.52 20.52 0.72 16,745.6Shackelford 446.66 787.83 13.87 13.87 0.39 2,584.6Shelby 788.21 1,506.84 11.24 11.24 0.40 4,681.4Sherman 382.36 689.34 9.93 9.93 0.17 2,226.5Smith 600.16 1,117.21 11.83 11.83 0.32 6,759.0Somervell 69.05 132.73 0.93 0.93 0.04 261.3Starr 1,801.98 3,435.69 27.08 27.08 0.92 39,905.7Stephens 548.00 962.55 17.22 17.22 0.36 6,028.2Sterling 507.62 898.57 15.24 15.24 0.35 5,045.8
5-12 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Stonewall 125.21 222.61 3.72 3.72 0.12 1,647.7Sutton 1,536.07 2,640.40 53.45 53.45 0.57 14,703.0Swisher 0.00 0.00 0.00 0.00 0.00 0.0Tarrant 4,070.91 11,441.36 39.54 39.54 2.88 4,929.9Taylor 92.16 163.25 2.80 2.80 0.09 693.0Terrell 890.56 1,697.22 13.46 13.46 0.45 4,554.0Terry 217.93 388.12 6.39 6.39 0.20 5,118.1Throckmorton 221.50 393.95 6.55 6.55 0.20 1,242.0Titus 42.19 74.68 1.29 1.29 0.04 506.6Tom Green 170.07 304.64 4.76 4.76 0.14 1,945.3Travis 3.37 5.97 0.10 0.10 0.00 14.4Trinity 10.94 19.88 0.27 0.27 0.01 193.3Tyler 463.76 896.18 5.69 5.69 0.25 57,953.3Upshur 604.48 1,126.42 11.73 11.73 0.30 10,582.5Upton 1,602.98 2,998.03 30.90 30.90 1.09 32,833.5Uvalde 0.20 0.26 0.02 0.02 0.00 4.3Val Verde 210.53 394.38 3.90 3.90 0.10 620.7Van Zandt 193.81 352.82 4.81 4.81 0.15 1,204.5Victoria 287.47 535.68 5.67 5.67 0.16 3,296.0Walker 13.49 24.74 0.31 0.31 0.01 85.2Waller 88.01 106.67 2.83 2.83 0.11 2,859.2Ward 1,288.64 2,381.97 28.00 28.00 0.94 9,588.8Washington 256.76 485.36 4.31 4.31 0.14 2,513.6Webb 3,123.82 5,806.41 62.66 62.66 1.48 28,275.4Wharton 692.11 1,309.84 11.43 11.43 0.37 15,986.4Wheeler 2,223.92 4,231.74 34.40 34.40 1.15 40,674.0Wichita 1,185.96 2,099.33 36.23 36.23 1.13 5,040.0
5-13 

Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.) 

County CO (tons/yr) NOx (tons/yr) PM10 (tons/yr) 

PM2.5

(tons/yr) SO2 (tons/yr) 

VOC 

(tons/yr) 

Wilbarger 174.53 308.95 5.33 5.33 0.17 1,147.9Willacy 353.53 681.05 4.59 4.59 0.19 8,274.5Williamson 9.07 16.05 0.28 0.28 0.01 53.2Wilson 129.98 230.01 3.98 3.98 0.12 757.5Winkler 917.14 1,698.44 19.52 19.52 0.63 7,815.4Wise 2,749.59 5,099.17 55.75 55.75 1.35 24,225.5Wood 239.16 438.82 5.52 5.52 0.18 4,200.3Yoakum 1,074.18 1,960.14 26.21 26.21 0.88 25,649.4Young 556.32 978.60 17.57 17.57 0.50 3,394.2Zapata 4,438.24 8,472.07 65.54 65.54 2.24 13,384.8Zavala 64.75 114.70 1.94 1.94 0.05 1,016.7

Total: 128,330.85 247,236.91 2,570.01 2,570.01 81.34 1,568,522.7
5-14 

Table 5-3. State-wide Speciated HAP Emissions by Source Category 

Source Category 

Hazardous Air Pollutant

Dehydrators Pump Jacks Oil and Gas Heaters Tank Truck/Railcar Loading Natural Gas Compressor Engines 

1,1,2,2-Tetrachloroethane 0.10 3.23 1,1,2-Trichloroethane 0.06 2.19 1,3-Butadiene 2.59 59.71 1,3-Dichloropropene 0.05 1.82 1,4-Dichlorobenzene 4.69 0.24 38.67 2,2,4-Trimethylpentane 7.95 2-Methylnaphthalene 0.09 0.005 2.91 3-Methylcholanthrene 0.01 0.0004 0.20 7,12-Dimethylbenz[a]Anthracene 0.06 0.003 1.74 Acenaphthene 0.36 0.001 0.23 Acenaphthylene 0.36 0.001 0.65 Acetaldehyde 10.91 1.78 481.46 Acrolein 10.28 366.67 Anthracene 0.48 0.00 0.37 Benz[a]Anthracene 0.36 0.00 0.28 Benzene 1,477.65 6.18 0.42 129.92 136.05 Benzo(g,h,i)Fluoranthene 0.24 0.00 Benzo[a]Pyrene 0.24 0.001 0.07 Benzo[b]Fluoranthene 0.36 0.001 0.12 Benzo[e]Pyrene 0.04 Benzo[g,h,i,]Perylene 0.001 0.11 Benzo[k]Fluoranthene 0.36 0.001 0.28 Biphenyl 6.74 Carbon Tetrachloride 0.07 2.53 Chlorobenzene 0.05 1.96 Chloroform 0.05 1.96 Chrysene 0.36 0.001 0.17 Dibenzo[a,h]Anthracene 0.24 0.001 0.19 Ethyl Benzene 88.89 0.10 54.19 3.18 
5-15 

Table 5-3. State-wide Speciated HAP Emissions by Source Category (Cont.) 

Source Category 

Hazardous Air Pollutant

Dehydrators Pump Jacks Oil and Gas Heaters Tank Truck/Railcar Loading Natural Gas Compressor Engines 

Ethylene Dibromide 0.08 3.05 Fluoranthene 0.60 0.002 0.28 Fluorene 0.56 0.002 0.72 Formaldehyde 80.13 15.03 3,263.20 Hexane 360.69 781.76 Indeno[1,2,3-c,d]Pyrene 0.36 0.001 0.28 Methanol 11.96 80.80 Methylene Chloride 0.16 3.82 m-Xylene 0.04 0.44 Naphthalene 0.38 0.12 9.87 o-Xylene 0.04 0.83 Phenanthrene 3.50 0.01 2.02 Phenol 0.76 Pyrene 1.00 0.004 0.42 Styrene 0.05 1.67 Toluene 786.98 2.18 0.68 208.89 56.08 Vinyl Chloride 0.03 1.03 Xylenes (Mixture of o, m, and p Isomers) 2,901.66 0.76 231.62 20.92 Statewide Total 5,255.17 140.49 379.00 624.62 5,349.44 
6-1 

6.0 FORMATTED TexAER FILES 

Once the emissions inventory was completed, the data was prepared for electronic 

submittal to the Texas Air Emissions Repository (TexAER) using the National Emissions 

Inventory (NEI) Input Format (NIF) 3.0. Area source text-formatted input files were prepared 

for all onshore oil and gas area source categories for a 2008 base year. The NIF 3.0 files were 

created using information provided by TCEQ regarding the correct format and valid code listings 

for submittal to TexAER. Prior to submittal to TCEQ, the NIF 3.0 files were pre-processed 

using EPA’s NIF Basic Format and Content Checker to check for errors and inconsistencies. 

Additionally, ERG performed a test upload to TexAER to ensure the files were complete and 

accurate and in a format consistent with the TexAER area source file data requirements. The 

formatted TexAER files are included as Appendix F. 
7-1 

7.0 CONCLUSIONS AND RECOMMENDATIONS 

 This study presents a comprehensive, statewide 2008 emissions inventory for Texas for 

onshore, upstream oil and gas production area sources. Data used to prepare the emissions 

inventory were obtained from a variety of sources, including existing databases (such as the 

Texas Railroad Commission (TRC) oil and gas production data), point source emissions 

inventory reports submitted to TCEQ (for dehydrators), vendor data (for compression engines 

and pumpjack engines), and published emission factor and activity data from the Houston 

Advanced Research Center (HARC), the Central Regional Air Planning Association (CENRAP), 

and the U.S. Environmental Protection Agency (EPA).

 Further improvements to this inventory could be made through collection of County-level 

activity data through use of the survey instrument developed as described in Section 3.0. Such a 

survey will help quantify the specific number, size, type, and location of the various equipment 

types used at upstream oil and gas production sites in Texas. 

 While characterization of emissions from all of the source types would benefit from 

detailed survey data, there are a few categories where minimal Texas-specific data was available. 

Specifically, this inventory was based on default profiles for several source categories that could 

be improved through implementation of the survey as follows: 

• Well Completions and Well Blowdowns - survey data is needed to determine the 

volumes of gas released during these operations, the composition of the gas released, and 

the extent that these operations are controlled; 

• Pneumatic Devices - survey data is needed to determine the number of devices used at 

each upstream oil and gas production site, the bleed rates for each equipment type, and 

the composition of the natural gas released from these sources; 

• Fugitive Emissions (Equipment Leaks) - this could be a significant source category and 

there is some uncertainty as to the current estimate of the number and types of fugitive 

emission soruces (valves, flanges, etc.). As with well completions and well blowdowns, 

gas composition data is needed to be able to speciate the emissions from this source 

category; and 

• Heaters and Boilers - survey data is needed to quantify the number and size of these small 

combustion units located at upstream oil and gas production sites. 

Also, HAP emissions could be estimated for several source categories not currently 

included in the HAP inventory if HAP speciation data could be obtained for the chemical 

composition of the natural gas emitted during various processes. In particular, this data would be 
7-2 

used to estimate HAP emissions from well completions, well blowdowns, pneumatic devices, 

and equipment leaks. 

It is likely the current inventory may be overestimating emissions to some degree from 

some sources due to the lack of information on control device use. In particular, this data would 

be useful for well completions (flaring and “green completion” techniques), oil and condensate 

storage tanks and loading racks (vapor recovery units and flares), and engines (SCR and NSCR). 

Again, information submitted by the operators would help account for emission control measures 

providing more accurate emission estimates. 
8-1 

8.0 REFERENCES 

Bar-Ilan, Amnon; Parikh, Rajashi; Grant, John; Shah, Tejas; and Pollack, Alison, 2008. 

Recommendations for Improvements to the CENRAP States’ Oil and Gas Emissions Inventories. 

Prepared for Central States Regional Air Partnership. November, 2008 

US EPA, 1991. “AP 42, Fifth Edition, Volume I, Chapter 13: Industrial Flares.” EPA’s 

Compilation of Air Pollutant Emission Factors, AP-42 Section 13.5, September, 1991. 

US EPA, 1995. “Protocol for Equipment Leak Emission Estimates,” U.S. Environmental 

Protection Agency, Research Triangle Park, NC, 1995. 

US EPA, 1998. “AP 42, Fifth Edition, Volume I, Chapter 1: External Combustion Sources,” 

EPA’s Compilation of Air Pollutant Emission Factors, AP-42 Section 1, September, 1998. 

US EPA, 2000. “AP 42, Fifth Edition, Volume I, Chapter 3: Internal Combustion Sources,” 

EPA’s Compilation of Air Pollutant Emission Factors, AP-42 Section 3.2, August, 2000. 

US EPA, 2005. US Environmental Protection Agency, 2005. WebFIRE Emission Factors. 

Accessed July 2, 2010. Internet address: 

http://cfpub.epa.gov/oarweb/download/WebFIREFactors.csv

US EPA, 2006. “AP 42, Fifth Edition, Volume I, Chapter 7: Liquid Storage Tanks,” EPA’s 

Compilation of Air Pollutant Emission Factors, AP-42 Section 7.1, November, 2006. 

US EPA, 2008. “AP 42, Fifth Edition, Volume I, Chapter 5: Petroleum Industry,” EPA’s 

Compilation of Air Pollutant Emission Factors, AP-42 Section 5.2, June, 2008. 

The Electric Power Research Institute (EPRI), 2005. Assessment of Emerging Low-Emission 

Technologies for Combustion-Based Distributed Resource Generators. Prepared by Energy and 

Environmental Analysis, Inc. March, 2005. 

Houston Advanced Research Center (HARC), 2005. Natural Gas Compressor Engine Survey 

and Engine NOx Emissions at Gas Production Facilities. Prepared by Eastern Research Group, 

Inc. August 31, 2005. 

Houston Advanced Research Center (HARC), 2006. Natural Gas Compressor Engine Survey for 

Gas Production and Processing Facilities. Prepared by Eastern Research Group, Inc. October 5, 

2006. 

Maldonado, Martha, 2010. Fugitive component equipment counts for Pump Seals and Others in 

Texas. Personal Communication with Mr. Mike Pring, Eastern Research Group, Inc. August 18, 

2010. 
8-2 

Pollack, Alison; Russell, James; Grant, John; Friesen, Ron; Fields, Paula; and Wolf, Marty, 

2006. Ozone Precursors Emission Inventory for San Juan and Rio Arriba Counties, New Mexico. 

Prepared for New Mexico Environment Department. August, 2006. 

Pollution Solutions, 2005. “Tyler/Longview/Marshall Flexible Attainment Region Emission 

Inventory of Ozone Precursors VOC, NOx and CO,” Prepared for Northeast Texas Air Care. 

February, 2005. 

Pollution Solutions, 2007. “Special Study Relating to Oil and Gas Production: 2005 and 2007 

Emissions from Compressor Engines with Consideration for Load Factor” Final report prepared 

for the East Texas Council of Governments, Kilgore, TX. 

Texas Environmental Research Consortium (TERC), October 2006, revised April 2009. VOC 

Emissions from Oil and Condensate Storage Tanks. 

Texas Commission on Environmental Quality (TCEQ), 2007. Emissions from Oil and Gas 

Production Facilities, 2007. Prepared by Eastern Research Group, Inc. August 31, 2007. 

Texas Commission on Environmental Quality (TCEQ), 2009. Drilling Rig Emission Inventory 

for the State of Texas, 2009. Prepared by Eastern Research Group, Inc. July 15, 2009. 

Texas Commission on Environmental Quality (TCEQ), 2010. Offshore Oil and Gas Platform 

Report. Prepared by Eastern Research Group, Inc. August 16, 2010. 
Appendix A – Task 2 Memorandum
A-1 

TECHNICAL MEMORANDUM

Date: April 26, 2010 

To: Martha Maldonado 

 Project Representative 

 Texas Commission on Environmental Quality (TCEQ) 

From: Richard Billings, Eastern Research Group (ERG) 

Daryl Hudson (ERG) 

Mike Pring (ERG) 

Jason Renzaglia (ERG) 

Brandon Smith (ERG) 

Stephen Treimel (ERG) 

 

Re: Oil and Gas Sources Inventory - Final Technical Memorandum for Task 2 

 TCEQ Contract No. 582-7-84003, Work Order No. 582-7-84003-FY10-26 

1.0 Introduction

The purpose of this Work Order is to develop a 2008 base year air emissions inventory from 

upstream onshore oil and gas production sites for select counties in Texas. The inventory will 

address area source criteria pollutant emissions of volatile organic compounds (VOC), nitrogen 

oxides (NOX), carbon monoxide (CO), particulate matter with an aerodynamic diameter less than 

or equal to 10 microns (PM10), particulate matter with an aerodynamic diameter less than or equal 

to 2.5 microns (PM2.5), and sulfur dioxide (SO2); and certain toxic pollutant emissions such as 

formaldehyde, benzene, toluene, ethylbenzene, and xylene. In addition to compiling the 

emissions inventory, other goals of this Work Order are to identify the emission source types 

operating at oil and gas production sites, identify the best emissions determination methodology 

for each emission source type, and develop a methodology for estimating emissions from oil and 

gas production sites based on the oil and gas produced at the county level. 

This Work Order builds on two previous studies ERG conducted for TCEQ to estimate emissions 

from oil and gas exploration and production activities. The first, implemented in 2007, 

focused on compiling a state-wide emissions inventory (including both onshore and offshore 

sources) for oil and gas exploration and production for a 2005 base year (ERG, 2007). The 

second study, conducted in 2009 for a 2008 base year, focused only on emissions from onshore 

oil and gas well drilling rig engines (ERG, 2009). Both of these studies included emission 

estimates for every county in Texas. In contrast, this current study will only address onshore 

area sources (those not included in the Texas point source inventory), and excludes the 23 

counties in the Barnett Shale area (Archer, Bosque, Clay, Comanche, Cooke, Coryell, Dallas, 

Denton, Eastland, Ellis, Erath, Hill, Hood, Jack, Johnson, Montague, Palo Pinto, Parker, 

Shackelford, Somervell, Stephens, Tarrant, and Wise). TCEQ is currently developing an 
A-2 

emissions inventory for oil and gas sources in the Barnett Shale, and offshore oil and gas 

platforms are currently under evaluation as part of TCEQ Work Order No. 582-07-84003-FY10-

25. 

 

The project is divided into four primary technical work tasks: 

• Identification and review of existing studies pertaining to estimating emissions from oil 

and gas production sites and recommendation of an emission estimation approach for 

each identified source type; 

• Collection of activity and emissions data through an industry survey and, as available, 

obtain data from existing studies and databases; 

• Development of a methodology to estimate county-level emissions from each identified 

source type; and 

• Performance of emissions estimation calculations, including documentation of data, 

procedures, and results in a final project report. The final emissions inventory will be 

compiled into National Emissions Inventory Input Format (NIF) 3.0 text files for import 

into Texas Air Emissions Repository (TexAER). 

The purpose of this memo is to identify and summarize emission estimation methodologies 

available for oil and gas production sites as determined through a technical review and 

evaluation of recent studies of emission sources at oil and gas production sites. In the project 

Work Plan, this work is referred to as Task 2. The existing studies reviewed and a summary of 

the available and recommended emission estimation approaches for each source type are 

presented in this memo, including summaries of the data required to implement the preferred 

approach and ERG’s recommendations how best to obtain the needed data. In addition, any data 

gaps identified that impact the ability to develop a 2008 inventory estimate for a category are 

described and possible methods for addressing the data gaps (through the use of existing or 

default data) are presented. 

This discussion begins by presenting the list of oil and gas source types that are the focus of this 

project in Section 2.0, Identification of Source Categories. A specific list of source types was 

contained in the Work Order and these source types were the focus of the Task 2 analysis, 

although this analysis was not limited to only those source types. As other additional source 

types were identified in the course of reviewing the existing studies, they are also included in this 

analysis. In Section 3.0, the specific oil and gas emission source types addressed in the project 

are presented, along with a review of any relevant existing studies, and a recommended emission 

estimation approach. Section 4.0 includes the references used in preparation of this 

memorandum. Appendix A contains a list of acronyms and abbreviations used in the text of this 

document. Terms are also defined in the text the first time they are used. 

2.0 Identification of Source Categories

The majority of the oil and gas production source categories analyzed in this project were also 

included in the previous TCEQ Oil and Gas study (ERG, 2007). Other oil and gas emissions 

sources were specified by TCEQ in the work order. 
A-3 

For the purposes of this project and this memorandum, the following oil and gas source types 

have been addressed: 

• Well Completions 

• Well Blowdowns 

• Wellheads 

• Pneumatic Devices 

• Fugitive Emissions (Equipment Leaks) 

• Artificial Lift (Pumpjack) Engines 

• Heaters and Boilers 

• Dehydrators 

• Storage Tanks 

• Oil and Condensate Loading Racks 

• Compressor Engines 

• Turbines 

These types of sources are considered "upstream" sources, which include activities associated 

with searching for potential oil and gas fields, drilling of exploratory wells, and subsequently 

development and operating the wells that recover and bring the natural gas and/or oil to the 

surface. The majority of upstream sources are area sources and are not currently accounted for 

in the point sources inventory. 

"Midstream" and "downstream" sources are associated with those operations that subsequently 

store, process, refine, market, and transport oil and gas products such as crude oil, natural gas, 

gasoline, and natural gas liquids. These types of sources are typically included in the point 

source emissions inventory, and consist of gas processing plants, pipeline compressor stations, 

and oil refineries. Point sources are not included in this inventory effort. 

Table 1 provides a summary of the general source category types listed above, the specific 

operations or processes that generate air emissions, and identification of the pollutants associated 

with each source. Table 2 identifies the specific emission processes, and the list of available 

Source Classification Codes (SCCs) for association with each source type. The SCC list is based 

on a list of available SCC’s for oil and gas sources as provided to ERG by TCEQ. 

The final list of SCC's used to compile the emissions inventory into the NIF 3.0 text files will be 

provided in the emissions inventory report. The structure of the SCC scheme for many of the 

source types included in this study allows for aggregation of emissions under one SCC, or the 

use of multiple SCC's if sufficient detailed data is obtained to disaggregate emissions into 

smaller sub-categories. For example, SCC 2310011500 may be used for "FUGITIVES: ALL 

PROCESSES" from oil production, or there are 6 separate SCC's that may be used to 

disaggregate fugitive emissions into sub-categories of "connectors", "flanges", "valves", "open 

ended lines", "pumps", and "other". 
 A-4 

Table 1. Identification of Source Categories Addressed in the Texas Oil and Gas Emission In

Oil & Gas Source Type Specific Emission Sources P

Well Completions Emissions from venting/flaring from the well completion phase Well Blowdowns Emissions from venting/flaring from well blowdowns Wellheads Emissions from wellhead assemblies and rod pumps Pneumatic Devices Fugitive emissions from pneumatic devices used during well exploration and production Fugitive Emissions (Equipment Leaks) Fugitive emissions from pumps and piping components Artificial Lift Engines (Pumpjack Engines) 

Combustion emissions from artificial lift engines associated with oil 

production SO2

Heaters and Boilers Emissions from natural gas-fired heaters and boilers SO2Dehydrators Emissions from glycol dehydrator still vents and reboilers VO

Et

Storage Tanks Working, breathing, and flashing losses from oil and condensate storage tanks Oil and Condensate Loading Racks Fugitive emissions from truck and/or railcar loading Compressor Engines Combustion emissions from compressor engines associated with oil and gas production SO2Turbines Combustion emissions from turbines associated with oil and gas production SO2
 A-5 

Table 2. Assignment of SCCs to Texas Oil and Gas Sourcesa

SCC Tier Description Short Descriptio

2270010010 OTHER OIL FIELD EQUIPMENT DIESEL: INDUSTRIAL EQUIPMENT: OTHE

(DRILLING RIGS) 

2310000000 TOTAL: ALL PROCESSES OIL & GAS EXPLORATION AND PRODUCT2310000330 ARTIFICIAL LIFT OIL AND GAS EXPLORATION AND PRODU2310001000 TOTAL: ALL PROCESSES ON SHORE OIL & GAS EXPLORATION & P

PROCESSES 

2310010000 TOTAL: ALL PROCESSES CRUDE OIL PRODUCTION ALL PROCESSE2310010100 OIL WELL HEATERS OIL PRODUCTION WELL HEATERS 2310010200 TANKS - FLASHING & STANDING/ WORKING/ 

BREATHING 

OIL PRODUCTION TANKS INCLUDING FL

2310010300 PNEUMATIC DEVICES OIL PRODUCTION PNEUMATIC DEVICES2310010700 OIL WELL FUGITIVES OIL AND GAS EXPLORATION AND PRODU

FUGITIVES 

2310010800 OIL WELL TRUCK LOADING OIL AND GAS EXPLORATION AND PRODU

LOADING 

2310011000 TOTAL: ALL PROCESSES ON SHORE CRUDE OIL PRODUCTION ALL 2310011020 STORAGE TANKS: CRUDE OIL ON SHORE OIL PRODUCTION CRUDE TAN2310011100 HEATER TREATER ON SHORE OIL PRODUCTION HEATER TR2310011201 TANK TRUCK/RAILCAR LOADING: CRUDE OIL ON SHORE OIL PRODUCTION TRUCK/RAI2310011450 WELLHEAD ON SHORE OIL PRODUCTION WELLHEAD 2310011500 FUGITIVES: ALL PROCESSES ON SHORE OIL PRODUCTION FUGITIVES 2310011501 FUGITIVES: CONNECTORS ON SHORE OIL PRODUCTION FUGITIVES 2310011502 FUGITIVES: FLANGES ON SHORE OIL PRODUCTION FUGITIVES 2310011503 FUGITIVES: OPEN ENDED LINES ON SHORE OIL PRODUCTION FUGITIVES 2310011504 FUGITIVES: PUMPS ON SHORE OIL PRODUCTION FUGITIVES 2310011505 FUGITIVES: VALVES ON SHORE OIL PRODUCTION FUGITIVES 2310011506 FUGITIVES: OTHER ON SHORE OIL PRODUCTION FUGITIVES 2310020000 TOTAL: ALL PROCESSES NATURAL GAS EXPLORATION AND PROD2310020309 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES: ALL 

ON-SHORE GAS PRODUCTION 4CYCLE RI

2310020600 COMPRESSOR ENGINES GAS PRODUCTION COMPRESSOR ENGINE2310020700 GAS WELL FUGITIVES NATURAL GAS PRODUCTION GAS WELL 2310020800 GAS WELL TRUCK LOADING NATURAL GAS PRODUCTION GAS WELL 
 A-6 

SCC Tier Description Short Descriptio

2310021000 TOTAL: ALL PROCESSES ON SHORE GAS PRODUCTION: ALL PROC2310021010 STORAGE TANKS: CONDENSATE ON-SHORE GAS PRODUCTION: STORAGE 2310021030 TANK TRUCK/RAILCAR LOADING 

CONDENSATE 

ON SHORE GAS PRODUCTION TRUCK ANCONDENSATE 

2310021100 GAS WELL HEATERS ON-SHORE GAS PRODUCTION HEATERS 2310021101 NATURAL GAS FIRED 2-CYCLE LEAN BURN 

COMPRESSOR ENGINES <50 HP 

ON-SHORE GAS PRODUCTION: NATURAL BURN COMPRESSOR ENGINES <50 HP 

2310021102 NATURAL GAS FIRED 2-CYCLE LEAN BURN 

COMPRESSOR ENGINES 50 TO 499 HP 

ON-SHORE GAS PRODUCTION: NATURAL BURN COMPRESSOR ENGINES 50 TO 499 H

2310021103 NATURAL GAS FIRED 2-CYCLE LEAN BURN 

COMPRESSOR ENGINES 500+ HP 

ON-SHORE GAS PRODUCTION NATURAL BURN COMPRESSOR ENGINES 500+ HP 

2310021109 NATURAL GAS FIRED 2-CYCLE LEAN BURN 

COMPRESSOR ENGINES: ALL 

ON-SHORE GAS PRODUCTION: NATURAL BURN COMPRESSOR ENGINES: ALL 

2310021201 NATURAL GAS FIRED 4-CYCLE LEAN BURN 

COMPRESSOR ENGINES <50 HP 

ON-SHORE GAS PRODUCTION NATURAL BURN COMPRESSOR ENGINES <50 HP 

2310021202 NATURAL GAS FIRED 4-CYCLE LEAN BURN 

COMPRESSOR ENGINES 50-499HP 

ON-SHORE GAS PRODUCTION NATURAL BURN COMPRESSOR ENGINES 50 HP - 499 

2310021203 NATURAL GAS FIRED 4-CYCLE LEAN BURN 

COMPRESSOR ENGINES 500+ HP 

ON-SHORE GAS PRODUCTION NATURAL BURN COMPRESSOR ENGINES 500+ HP 

2310021209 NATURAL GAS FIRED 4-CYCLE LEAN BURN 

COMPRESSOR ENGINES 

ON-SHORE GAS PRODUCTION NATURAL BURN COMPRESSOR ENGINES 

2310021300 GAS WELL PNEUMATIC DEVICES ON-SHORE GAS PRODUCTION PNEUMATI2310021301 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES <50 HP 

ON-SHORE GAS PRODUCTION NATURAL 

BURN COMPRESSOR ENGINES <50 HP 

2310021302 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES 50 TO 499HP 

ON-SHORE GAS PRODUCTION NATURAL 

BURN COMPRESSOR ENGINES 50 TO 499 H

2310021303 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES 500+ HP 

ON-SHORE GAS PRODUCTION NATURAL 

BURN COMPRESSOR ENGINES 500+ HP 

2310021400 GAS WELL DEHYDRATORS ON-SHORE GAS PRODUCTION DEHYDRAT2310021401 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES <50 HP W/ NSCR 

ON-SHORE GAS PRODUCTION NATURAL 

BURN COMPRESSOR ENG. <50HP W/ NON REDUCTION 

2310021402 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES 50-499HP W/ NSCR 

ON-SHORE GAS PRODUCTION NATURAL 

BURN COMPRESSOR ENG. 50-499HP W/ NOREDUCTION 
 A-7 

SCC Tier Description Short Descriptio

2310021403 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES 500+ HP W/ NSCR 

ON-SHORE GAS PRODUCTION NATURAL 

BURN COMPRESSOR ENG. 500+ HP W/ NO

REDUCTION 

2310021409 NATURAL GAS FIRED 4-CYCLE RICH BURN 

COMPRESSOR ENGINES W/NSCR: ALL 

ON-SHORE GAS PRODUCTION NATURAL 

BURN COMPRESSOR ENGINES WITH NONREDUCTION: ALL 

2310021450 WELLHEAD ON-SHORE GAS PRODUCTION: WELLHEA2310021500 GAS WELL COMPLETION - FLARING & 

VENTING 

ON SHORE GAS PRODUCTION WELL COM

VENTING 

2310021501 FUGITIVES: CONNECTORS ON-SHORE GAS PRODUCTION: FUGITIVE2310021502 FUGITIVES: FLANGES ON-SHORE GAS PRODUCTION: FUGITIVE2310021503 FUGITIVES: OPEN ENDED LINES ON-SHORE GAS PRODUCTION: FUGITIVE2310021504 FUGITIVES: PUMPS ON-SHORE GAS PRODUCTION: FUGITIVE2310021505 FUGITIVES: VALVES ON-SHORE GAS PRODUCTION: FUGITIVE2310021506 FUGITIVES: OTHER ON-SHORE GAS PRODUCTION: FUGITIVE2310021509 FUGITIVES: ALL PROCESSES ON-SHORE GAS PRODUCTION: FUGITIVE2310021600 GAS WELL VENTING ON-SHORE GAS PRODUCTION GAS WELL 2310030000 TOTAL: ALL PROCESSES OIL AND GAS EXPLORATION AND PRODU

LIQUIDS 

2310030210 TANKS - FLASHING & STANDING/ WORKING/ 

BREATHING, UNCONTROLLED 

OIL AND GAS PRODUCTION NATURAL GAINCLUDING FLASH UNCONTROLLED 

2310030220 TANKS - FLASHING & STANDING/ WORKING/ 

BREATHING, CONTROLLED 

OIL & GAS PRODUCTION NATURAL GAS 

FLASH CONTROLLED 

2310031000 TOTAL: ALL PROCESSES ON-SHORE OIL AND GAS EXPLORATION 

NATURAL GAS LIQUIDS 

2310111000 ALL PROCESSES ON-SHORE OIL EXPLORATION: ALL PROC2310111401 OIL WELL PNEUMATIC PUMPS ON-SHORE OIL EXPLORATION: OIL WELL 2310111700 OIL WELL COMPLETION: ALL PROCESSES ON-SHORE OIL EXPLORATION: OIL WELL 

PROCESSES 

2310111701 OIL WELL COMPLETION: FLARING ON-SHORE OIL EXPLORATION: OIL WELL 2310111702 OIL WELL COMPLETION: VENTING ON-SHORE OIL EXPLORATION: OIL WELL 2310121000 ALL PROCESSES ON-SHORE GAS EXPLORATION: ALL PRO2310121401 GAS WELL PNEUMATIC PUMPS ON-SHORE GAS EXPLORATION: GAS WEL2310121700 GAS WELL COMPLETION: ALL PROCESSES ON-SHORE GAS EXPLORATION: GAS WEL

PROCESSES 

2310121701 GAS WELL COMPLETION: FLARING ON-SHORE GAS EXPLORATION: GAS WEL
 A-8 

SCC Tier Description Short Descriptio

2310121702 GAS WELL COMPLETION: VENTING ON-SHORE GAS EXPLORATION: GAS WEL a SCCs were obtained from TCEQ.
A-9 

3.0 Source Types

3.1 Well Completions 

Following drilling and casing, a well must be “completed.” Completion is the process which 

enables the well to produce oil or gas. To complete the production well, casing is installed and 

cemented and the drilling rig is removed from the site. As the well is completed, an initial 

mixture of gas, hydrocarbon liquids, water, sand, and other materials comes to the surface. 

Standard practice during the completion process has been to vent or flare the natural gas 

released, some of which is VOC. This category addresses VOC emissions associated with the 

completion process at oil and gas wells. County-level emissions from this source will be 

estimated for the purpose of this inventory. 

3.1.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from well completions. The relevant sources 

reviewed are listed in Table 3.1. 

Table 3.1 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Well Completion Emissions Estimates 

Report Title Geographic 

Coverage Publication Date 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 

Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

CENRAP 

States November, 2008 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Piceance Basin (BarIlan, et al., 2009a) 

Piceance 

Basin, 

Colorado 

January, 2009 

Development of Emissions Inventories for 

Natural Gas Exploration and Product Activities in 

the Haynesville Shale (Grant, et al., 2009) 

Haynesville 

Shale, Texas August, 2009 

3.1.2 Emission estimation approaches 

The reviewed literature provided component-based approaches for estimating releases from well 

completions/recompletions. One component-based method is utilized in several studies 

including the 2008 CENRAP study “Recommendations for Improvements to the CENRAP 

States’ Oil and Gas Emissions Inventories” (Bar-Ilan, et al. 2008), “Development of Emissions 

Inventories for Natural Gas Exploration and Product Activities in the Haynesville Shale” (Grant, 

et al., 2009) and the “Development of Baseline 2006 Emissions from Oil and Gas Activity in the 

Piceance Basin” (Bar-Ilan, et al., 2009a). These studies estimate the emissions per completion 
A-10 

event based on the volume of vented gas per completion and the mass fraction of the given 

pollutant in the venting gas. This value is multiplied by the number completion events and takes 

into account destruction of a portion of the pollutant based on flaring or other “green” 

completion methods (methods by which emissions are minimized during well completion 

through capture and/or destruction of the vented gases). The “Emissions from Oil and Gas 

Production Facilities” (TCEQ, 2007) study uses U.S. Environmental Protection Agency’s 

(EPA’s) AP-42 emissions factors for CO and NOx emissions and uses a displacement equation 

(mass balance approach) to estimate SO2 and VOC emissions. Emissions are then calculated by 

multiplying this emissions factor by the number of completions, and the mass fraction of the 

given pollutant in the vented gas. The latter data may be collected via industry surveys. 

3.1.3 Preferred emission estimation approach 

As a preferred method to estimate emissions from well completions, ERG will use the 

methodology from the Central Regional Air Planning Association (CENRAP) study. 

Emissions from well completions will be estimated on the basis of the volume of gas vented 

during completion and the average VOC content of that gas, obtained from a gas composition 

analyses. Emissions rates are evaluated at standard temperature and pressure (STP) in the 

CENRAP study. Data on the operating temperature and pressure will be collected via survey and 

emissions will be adjusted for the appropriate operating parameters. 

The calculation methodology for completion emissions follows Equations 1 and 2: 

( / ) 5.3 10 5 907200

( )

,

i

gas

vented

completion i

f

R MW T

P V

E ×

















× × × −

×

= Equation (1)

where: 

Ecompletion,i is the emissions of pollutant i from a single completion event [ton/event] 

P is atmospheric pressure [1 atm] 

Vvented is the volume of vented gas per completion [MCF/event] 

R is the universal gas constant [0.082 L-atm/mol-K] 

MWgas is the molecular weight of the gas [g/mol] 

T is the atmospheric temperature [298 K] 

fi is the mass fraction of pollutant i in the vented gas 

The total emissions from all completions occurring in a county can be evaluated following 

Equation 2: 

( ) completion TOTAL completion i county flare green E = E × S × 1− 98.0 c − c , ,

 Equation (2) 

where: 

Ecompletion,TOTAL are the total emissions county-wide from completions [tons/year] 

Ecompletion,i are the completion emissions from a single completion event [tons/event] 

cflare is the fraction of completions in the basin controlled by flares 
A-11 

cgreen is the fraction of completions in the basin controlled by green completion 

techniques 

Scounty is the county-wide new well and recompleted well count 

Volume of vented gas per completion, Vvented:

The 2008 CENRAP study obtained basin-level vented gas volumes from survey data. ERG will 

attempt to obtain estimates for the volume of vented gas per completion by conducting a survey 

of oil and gas producers. Depending on the amount of data collected, averages may be 

determined at the county level, the Texas Railroad Commission (TRC) District level, the basin 

level, or state-wide. If insufficient data is collected on all counties, ERG may default to the 

average volume vented presented in the 2008 CENRAP study. The CENRAP data can also be 

used as a QA check to ensure that results from the survey are reasonable. 

Mass fraction for a single pollutant, fi:

The 2008 CENRAP study obtained basin-level mass fractions for various pollutants from survey 

data. Where survey data were not available for a specific basin, the average of all CENRAP 

basins was used. ERG will attempt to obtain estimates for the mass fraction of pollutants by 

conducting a survey of oil and gas. Depending on the amount of data collected, averages may be 

determined at the county level, the TRC District level, the basin level, or state-wide. If 

insufficient data is collected on all counties, ERG may default to the average mass fractions of 

pollutants presented in the 2008 CENRAP study. The CENRAP data can also be used as a QA 

check to ensure that results from the survey are reasonable. 

Number of completions controlled by flares, cflare and the number of green completions, cgreen:

The 2008 CENRAP study obtained basin-level estimates for the number of completions 

controlled by flares and the number of completions controlled by green completion techniques 

from survey data. ERG will attempt to obtain estimates for the number of completions 

controlled by flares or green completions either by conducting a survey of oil and gas producers, 

or from existing data from the TRC. Depending on the amount of data collected, averages may 

be determined at the county level, the TRC District level, the basin level, or state-wide. 

County-level new/recompleted well count, Scounty:

ERG will obtain county-level data for the number of new and recompleted wells from the TRC 

for each county included in this analysis. 

3.1.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level data on the 

number of well completions, volume of vented gas per completion, oil and gas product 

composition, and number of completions controlled by flares or controlled by green completion 

techniques, and the number of active oil and gas wells are required. ERG will collect data on the 

number of oil and gas well completions per county using the most recently available database 

from the TRC. ERG will attempt to collect all other data items by conducting a survey of oil and 

gas producers owning active wells in the Texas counties covered in this emissions inventory 

development effort. 
A-12 

3.2 Well Blowdowns 

Well blowdowns refer to the practice of venting gas from wells that have developed some kind 

of cap or obstruction before any additional intervention work can be done on the wells. 

Typically, well blowdowns are conducted on wells that have been shut in for a period of time 

and the operator desires to bring the well back into production. Well blowdowns are also 

sometimes conducted to remove fluid caps that have built up in producing gas wells. Because gas 

is directly vented from the blowdown event, blowdowns can be a source of VOC emissions. 

County-level emissions from this source will be estimated for the purpose of this inventory. 

3.2.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from well blowdowns. The relevant sources 

reviewed are listed in Table 3.2. 

Table 3.2 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Well Blowdown Emissions Estimates 

Report Title Geographic 

Coverage Publication Date 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 

 Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

 CENRAP 

States November, 2008 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Piceance Basin (BarIlan, et al., 2009a) 

 Piceance 

Basin, 

Colorado 

January, 2009 

Development of Emissions Inventories for 

Natural Gas Exploration and Product Activities in 

the Haynesville Shale (Grant, et al., 2009) 

Haynesville 

Shale, Texas August, 2009 

3.2.2 Emission estimation approaches 

The reviewed literature provided component-based approaches for estimating releases from well 

blowdowns. One component-based method is utilized in several studies including the 2008 

CENRAP study “Recommendations for Improvements to the CENRAP States’ Oil and Gas 

Emissions Inventories” (Bar-Ilan, et al. 2008), “Development of Emissions Inventories for 

Natural Gas Exploration and Product Activities in the Haynesville Shale” (Grant, et al., 2009) 

and the “Development of Baseline 2006 Emissions from Oil and Gas Activity in the Piceance 

Basin” (Bar-Ilan, et al., 2009a). Emissions from blowdowns are estimated on the basis of the 

volume of gas vented during a blowdown and the average pollutant content of that gas, obtained 

from gas composition analyses. This methodology is very similar to that of completion venting. 

Flaring and/or green practices may be used to control emissions from the blowdown process. 
A-13 

The previous ERG study, “Emissions from Oil and Gas Production Facilities” (TCEQ, 2007), did 

not estimate emissions from well blowdowns. 

3.2.3 Preferred emission estimation approach 

As a preferred method, ERG will use the methodology from the CENRAP study to generate 

estimated emissions from well blowdowns. 

Emissions from well blowdowns will be estimated on the basis of the volume of gas vented 

during blowdown and the average VOC content of that gas, obtained from a gas composition 

analyses. Emissions rates are evaluated at STP in the CENRAP study. Data on the operating 

temperature and pressure will be collected via survey and emissions will be adjusted for the 

appropriate operating parameters. 

The calculation methodology for blowdown emissions is identical to the method for completion 

emissions, and follows Equations 3 and 4: 

( / ) 5.3 10 5 907200

( )

,

i

gas

vented

blowdown i

f

R MW T

P V

E ×

















× × × −

×

= Equation (3)

where: 

Ecompletion,i is the emissions of pollutant i from a single blowdown event [ton/event] 

P is atmospheric pressure [1 atm] 

Vvented is the volume of vented gas per blowdown [MCF/event] 

R is the universal gas constant [0.082 L-atm/mol-K] 

MWgas is the molecular weight of the gas [g/mol] 

T is the atmospheric temperature [298 K] 

fi is the mass fraction of pollutant i in the vented gas 

The total emissions from all blowdowns occurring in a county can be evaluated following 

Equation 4: 

( ) blowdown TOTAL blowdown i blowdown wells flare green E = E × N × N × 1− 98.0 c − c , ,

 Equation (4) 

where: 

Eblowdown,TOTAL are the total emissions county-wide from blowdowns [tons/year] 

Eblowdown,i are the blowdown emissions from a single blowdown event [tons/event] 

Nblowdown is the number of blowdowns per well in the county

Nwells is the total number of active wells in the county 

cflare is the fraction of blowdowns in the basin controlled by flares 

cgreen is the fraction of blowdowns in the basin controlled by green completion techniques 
A-14 

Volume of vented gas per blowdown, Vvented:

The 2008 CENRAP study obtained basin-level vented gas volumes from survey data. ERG will 

attempt to obtain estimates for the volume of vented gas per blowdown by conducting a survey 

of oil and gas producers. In the event that insufficient data is collected on a particular county, 

ERG will use the average of all other counties. If insufficient data is collected on all counties, 

ERG may default to the average volume vented presented in the 2008 CENRAP study. The 

CENRAP data can also be used as a Quality Assurance (QA) check to ensure that results from 

the survey are reasonable. 

Mass fraction for a single pollutant, fi:

The 2008 CENRAP study obtained basin-level mass fractions for various pollutants from survey 

data. Where survey data was not available for a specific basin, the average of all CENRAP 

basins was used. ERG will attempt to obtain estimates for the mass fraction of pollutants by 

conducting a survey of oil and gas producers. Depending on the amount of data collected, 

averages may be determined at the county level, the TRC District level, the basin level, or statewide. If insufficient data is collected on all counties, ERG may default to the average mass 

fractions of pollutants presented in the 2008 CENRAP study. The CENRAP data can also be 

used as a QA check to ensure that results from the survey are reasonable. 

County-level number of blowdowns per well, Nblowdown:

The 2008 CENRAP study obtained basin-level number of blowdowns from survey data. ERG 

will attempt to obtain estimates for the number of blowdowns per county by conducting a survey 

of oil and gas producers. In the event that insufficient data is collected on a particular county, 

ERG will use the average of all other counties. Depending on the amount of data collected, 

averages may be determined at the county level, the TRC District level, the basin level, or statewide. If insufficient data is collected on all counties, ERG may default to the average mass 

fractions of pollutants presented in the 2008 CENRAP study. The CENRAP data can also be 

used as a QA check to ensure that results from the survey are reasonable. 

County-level well count, Nwells:

The 2008 CENRAP study obtained basin-level number of wells from survey data. ERG will 

attempt to obtain estimates for the number of wells per county by conducting a survey of oil and 

gas producers. In the event that insufficient data is collected on a particular county, ERG will 

use the average of all other counties. Depending on the amount of data collected, averages may 

be determined at the county level, the TRC District level, the basin level, or state-wide. If 

insufficient data is collected on all counties, ERG may default to the average mass fractions of 

pollutants presented in the 2008 CENRAP study. The CENRAP data can also be used as a QA 

check to ensure that results from the survey are reasonable. 

Number of blowdowns controlled by flares, cflare and the number of green blowdowns, cgreen:

The 2008 CENRAP study obtained basin-level estimates for the number of blowdowns 

controlled by flares and the number of blowdowns controlled by green techniques from survey 

data. ERG will attempt to obtain county-level estimates for the number of blowdowns controlled 

by flares or green blowdown methods either by conducting a survey of oil and gas producers, or 
A-15 

from existing data from the TRC. Depending on the amount of data collected, averages may be 

determined at the county level, the TRC District level, the basin level, or state-wide. 

3.2.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level data on the 

number of well blowdowns, volume of vented gas per blowdown, oil and gas product 

composition, and number of blowdowns controlled by flares or controlled by green techniques, 

and the number of active oil and gas wells are required. ERG will collect data on the number of 

oil and gas wells per county using the most recently available database from the TRC. ERG will 

attempt to collect all other data items by conducting a survey of oil and gas producers owning 

active wells in the Texas counties covered in this emissions inventory development effort. 

3.3 Wellheads 

The wellhead is the part of an oil or gas well that terminates at the surface and is the location

where oil or gas products can be withdrawn. The primary function of the wellhead is to hold the 

casings and the production tubing of the well. On top of the wellhead sits the tubing hanger, 

from which the production tubing is run. The well christmas tree rests on top of the tubing 

hanger, as well as surface flow-control facilities used in the production phase of the well. The 

wellhead is a source of VOC emissions from various fugitive outlets including seals and joints. 

County-level emissions from this source will be estimated for the purpose of this inventory. 

3.3.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from emissions generated at oil and gas wellheads. 

The relevant sources reviewed are listed in Table 3.3. 

Table 3.3 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Wellhead Emissions Estimates 

Report Title Geographic 

Coverage Publication Date 

Oil and Gas Emission Inventories for the Western 

States (Russell, et al., 2005) WRAP States December, 2005 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 

3.3.2 Emission estimation approaches 

The reviewed literature provided two similar approaches to estimate emissions from wellheads at 

oil and gas sites. The first of these approaches is presented in the study: “Oil and Gas Emission 

Inventories for the Western States” (Russell, et al., 2005), which uses oil and gas production data 

along with emission factors for various wellhead sources to determine wellhead emissions. 

These sources include: tanks, dehydrators, heaters, completions, and pneumatic devices. 
A-16 

Emissions from all of these sources are discussed elsewhere in this report. The “Emissions from 

Oil and Gas Production Facilities” (TCEQ, 2007) study uses AP-42 emission factors for oil and 

gas facilities to determine wellhead emissions from wellhead assemblies and rod pumps. Other 

reviewed sources did not provide wellhead emissions calculation methodologies. 

3.3.3 Preferred emission estimation approach 

As a preferred method to estimate emissions from wellheads, ERG will use the AP-42 emission 

factor to calculate emissions from oil and gas wellheads, based on the number of oil and gas 

wellheads in place. The AP-42 emission factor for VOC emissions from gas wellheads is based 

on gas production. Gas production data by county in Texas is also available from the TRC. 

However, additional emission methodologies may be developed if additional sources are located. 

3.3.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level data on the 

number of oil wellheads and gas production are required. ERG will collect data on the number 

of oil wellheads and gas production wellhead sites per county using the most recently available 

database from the TRC. 

3.4 Pneumatic Devices 

Pneumatic devices are used for a variety of gas and oil well processes and are powered by highpressure produced gas. These devices include transducers, liquid level controllers, pressure 

controllers and positioners. During the normal operation of these devices, they release or bleed 

natural gas to the atmosphere making them a source of VOC emissions. County-level emissions 

from these sources will be estimated for the purpose of this inventory. 

3.4.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from emissions generated by pneumatic devices 

typically utilized at oil and natural gas production wells. The relevant sources reviewed are 

listed in Table 3.4. 

Table 3.4 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Pneumatic Device Emissions Estimates 

Report Title Geographic 

Coverage Publication Date 

Oil and Gas Emission Inventories for the Western 

States (Russell, et al., 2005) WRAP States December, 2005 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 
A-17 

Table 3.4 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Pneumatic Device Emissions Estimates (Cont.) 

Report Title Geographic 

Coverage Publication Date 

WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation 

Phase II (Bar-Ilan, et al., 2007) 

WRAP States September, 2007 

Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

CENRAP 

States November, 2008 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Piceance Basin (BarIlan, et al., 2009a) 

Piceance 

Basin, 

Colorado 

January, 2009 

3.4.2 Emission estimation approaches 

The reviewed literature provided two similar approaches with different bases to estimate 

emissions from pneumatic devices at oil and gas sites. The first of these approaches is presented 

in the Western Regional Air Partnership (WRAP) Phase I (Russell, et al., 2005) and WRAP 

Phase II (Bar-Ilan, et al., 2007) reports which utilize separate emissions factors for oil wells and 

gas wells provided by the Wyoming Department of Environmental Quality (WYDEQ). The 

emissions factors for VOC and Hazardous Air Pollutants (HAPs) from pumps are given on a per 

well basis (tons/yr/well) and are calculated based on an average usage/bleed rate of 5 scf/hr, 

statewide average weighted gas compositions, continuous operation, and an assumption of two 

pumps per gas well and one pump per oil well. Area-wide emissions are then calculated based 

on the number of gas wells and oil wells currently active in a specific area. This approach was 

also adopted in the 2007 TCEQ report on emissions from oil and gas production facilities. 

However, the emissions factors were recalculated using weight percents provided in a 2004 

report from the Gas Processors Association (GPA). 

An alternative approach is presented in both the 2008 CENRAP study “Recommendations for 

Improvements to the CENRAP States’ Oil and Gas Emissions Inventories” (Bar-Ilan, et al. 2008) 

and “Development of Baseline 2006 Emissions from Oil and Gas Activity in the Piceance Basin” 

(Bar-Ilan, et al., 2009a). The same calculation approach is used in this method; however, this 

method uses bleed rates obtained from the results of an extensive study performed by EPA as 

part of the Natural Gas Star program in 2004. This study provides bleed rate estimates for 

several different device types – liquid level controllers, positioners, pressure controllers, and 

transducers. This approach also conducted a survey to estimate the number of each device type 

present at typical gas and oil well sites. Given the additional level of detail presented with this 

approach, it will be the preferred approach for estimating emissions from pneumatic devices. 
A-18 

3.4.3 Preferred emission estimation approach 

As a preferred method to estimate emissions from pneumatic devices, ERG will use the 

CENRAP methodology. 

Emissions from a single well site are calculated using Equation 5: 

5

,

5.3 10

907200

−

× × ×

















×











= ∑ × ×

T

MW

R

P

V N t

f

E

gas

i

i i annual

j

pneumatic j

 Equation (5) 

where: 

Epneumatic,j is the total emissions of pollutant j from all pneumatic devices for a typical well 

[ton/year/well] 

Vi is the volumetric bleed rate from device i [scf/hr/device] 

Ni is the total number of device i owned by the participating companies 

tannual is the number of hours per year that devices are operating 

P is the atmospheric pressure [1 atm] 

R is the universal gas constant [0.082 L-atm/mol-K] 

MWgas is the molecular weight of the gas [g/mol] 

T is the atmospheric temperature [298 K] 

fj is the mass fraction of pollutant j in the vented gas 

County-wide emissions are calculated using Equation 6: 

Epneumatic,TOTAL = Epneumatic, j × Nwell Equation (6) 

where: 

Epneumatic,TOTAL is the total pneumatic device emissions in the county [ton/yr] 

Epneumatic,j is the pneumatic device emissions for a single well of pollutant j [ton/yr] 

Nwell is the total number of active wells in the county for a given year 

Emissions rates are evaluated at STP in the CENRAP study. Data on the operating temperature 

and pressure will be collected via survey and emissions will be adjusted for the appropriate 

operating parameters. 

Volumetric bleed rate from device i, Vi:

The 2008 CENRAP study uses bleed rates for various devices presented in a 2004 EPA Natural 

Gas Star program study. ERG will also use the bleed rates from the EPA Natural Gas Star 

program study when calculating emissions from pneumatic devices at oil and gas production 

sites. 

Total number of devices, Ni:

The 2008 CENRAP study obtained basin-level total number of devices per well from survey 

data. Where survey data was not available for a specific basin, the average of all CENRAP 
A-19 

basins was used. ERG will attempt to obtain estimates for the number of devices per well by 

conducting a survey of oil and gas producers. Depending on the amount of data collected, 

averages may be determined at the county level, the TRC District level, the basin level, or statewide. If insufficient data is collected on all counties, ERG may default to the average of number 

of devices for each type presented in the 2008 CENRAP study. The CENRAP data can also be 

used as a quality assurance check to ensure that results from the survey are reasonable. 

Number of hours per year that devices are operating, tannual:

The 2008 CENRAP study assumed basin-level annual hours of device operation to be 8760 hr/yr 

(non-stop operation). ERG will attempt to obtain estimates for the annual hours of device 

operation by conducting a survey of oil and gas producers. Depending on the amount of data 

collected, averages may be determined at the county level, the TRC District level, the basin 

level, or state-wide. If insufficient data is collected on all counties, ERG may default to a value 

of 8760 hr/yr assumed in the 2008 CENRAP study. The CENRAP data can also be used as a 

quality assurance check to ensure that results from the survey are reasonable. 

Molecular weight of gas, MWgas:

The 2008 CENRAP study obtained basin-level molecular weights of gas bleeding from survey 

data. ERG will attempt to obtain data on the molecular weights by conducting a survey of oil 

and gas producers. Depending on the amount of data collected, averages may be determined at 

the county level, the TRC District level, the basin level, or state-wide. If insufficient data is 

collected on all counties, ERG may default to the average of the molecular weights in the 2008 

CENRAP study. The CENRAP data can also be used as a quality assurance check to ensure that 

results from the survey are reasonable. 

Mass fraction of pollutant j in the vented gas, fj:

The 2008 CENRAP study obtained basin-level mass fractions from survey data. ERG will 

attempt to obtain estimates for the mass fractions of pollutants by conducting a survey of oil and 

gas producers. Depending on the amount of data collected, averages may be determined at the 

county level, the TRC District level, the basin level, or state-wide. If insufficient data is 

collected on all counties, ERG may default to the compositions presented in the 2008 CENRAP 

study. The CENRAP data can also be used as a quality assurance check to ensure that results 

from the survey are reasonable. 

3.4.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level data on the 

number of devices per well, annual hours of device operation, oil and gas product composition 

and molecular weight, and number of active oil and gas wells are required. ERG will collect 

data on the number of oil and gas wells per county using the most recently available database 

from the TRC. ERG will attempt to collect all other data items by conducting a survey of oil and 

gas producers owning active wells in the Texas counties covered in this emissions inventory 

development effort. 
A-20 

3.5 Fugitive Emissions (Equipment Leaks) 

All oil and gas producing sites have a system of pumps and piping to transport oil and gas from 

the wellhead to the processing area. These pumps and piping networks are constructed with 

many individual components including flanges, valves, seals, and connectors. As a result of high 

operating pressures, varying fitting tightness, and age and condition, each of these components 

has the potential to release fugitive emissions while oil and gas product flows through them. 

County-level emissions from these sources will be estimated for the purpose of this inventory. 

3.5.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from fugitive emissions generated by non-point 

source equipment and components typically utilized at oil and natural gas production wells. The 

relevant sources reviewed are listed in Table 3.5. 

Table 3.5 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Fugitive Emissions Estimates 

Report Title Geographic 

Coverage Publication Date 

Ozone Precursors Emissions Inventory for San 

Juan and Rio Arriba Counties, New Mexico 

(Pollack, et al., 2006) 

San Juan and 

Rio Arriba 

Counties, 

New Mexico 

August, 2006 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 

Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

CENRAP 

States November, 2008 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Piceance Basin (BarIlan, et al., 2009a) 

Piceance 

Basin, 

Colorado 

January, 2009 

3.5.2 Emission estimation approaches 

The reviewed literature sources all provided a similar approach for estimating fugitive emissions 

from equipment leaks. This method estimates emissions using component-based emissions 

factors. The component-based method uses EPA’s AP-42 emissions factors for each component 

type based on the type of service to which the equipment applies – gas, light liquid, heavy liquid, 

or water. Emissions are then calculated by multiplying this emissions factor by the number of 

components per well, the annual number of hours the well is in operation, and the mass fraction 

of the given pollutant in the vented gas. The latter data were collected via industry surveys. 

These well-based emissions are then multiplied by the number of wells for a given area. The 

2007 TCEQ study uses emissions factors developed by the American Petroleum Institute (API), 
A-21 

and the number of components per well was obtained from a study conducted by the Canadian 

Association of Petroleum Producers (CAPP). 

The component-based method applies to both oil and gas producing wells. If sufficient data on 

the number of components at each well site can be obtained, performing a component-based 

analysis will allow for the most comprehensive estimates for fugitive releases. 

3.5.3 Preferred emission estimation approach 

As a preferred method to estimate fugitive emissions from equipment leaks, ERG will use the 

CENRAP methodology. 

Fugitive emissions from a single well site may be calculated using Equation 7: 

= ∑ × × × ×

i

fugitive j i i annual Yj E EF N t .0 0011 ,

 Equation (7) 

where: 

Efugitive,j is the fugitive emissions for a single typical well for pollutant j [ton/yr/well] 

EFi is the emission factor of TOC for a single component i [kg/hr/component] 

Ni is the total number of components of type i

tannual is the annual number of hours the well is in operation [hr/yr] 

Yj is the mass fraction of pollutant j to TOC in the vented gas 

County-wide fugitive emissions are calculated using Equation 8: 

Efugitive,TOTAL = Efugitive, j × Nwell Equation (8) 

where: 

Efugitive,TOTAL is the total fugitive emission in the county [ton/yr] 

Efugitive,j is the fugitive emissions for a single well of pollutant j [ton/yr] 

Nwell is the total number of active wells in the county for a given year 

Emissions rates are evaluated at STP in the CENRAP study. Data on the operating temperature 

and pressure will be collected via survey and emissions will be adjusted for the appropriate 

operating parameters. 

Emission factor of TOC for a single component, EFi:

ERG will use EPA’s AP-42 emissions factors when calculating fugitive emissions from 

equipment leaks at oil and gas production sites. 

Total number of components, Ni:

The 2008 CENRAP study obtained basin-level total number of components per well from survey 

data. Where survey data was not available for a specific basin, the average of all CENRAP 

basins was used. ERG will attempt to obtain estimates for the number of components per well by 

conducting a survey of oil and gas producers. Depending on the amount of data collected, 

averages may be determined at the county level, the TRC District level, the basin level, or state-
A-22 

wide. If insufficient data is collected on all counties, ERG may default to the average number of 

components for each service type presented in the 2008 CENRAP study. The CENRAP data can 

also be used as a quality assurance check to ensure that results from the survey are reasonable. 

Annual number of hours the well is in operation, tannual:

The 2008 CENRAP study assumed basin-level annual hours of well operation to be 8760 hr/yr 

(non-stop operation). ERG will attempt to obtain estimates for the annual hours of well 

operation by conducting a survey of oil and gas producers. Depending on the amount of data 

collected, averages may be determined at the county level, the TRC District level, the basin 

level, or state-wide. If insufficient data is collected on all counties, ERG may default to a value 

of 8760 hr/yr assumed in the 2008 CENRAP study. The CENRAP data can also be used as a 

quality assurance check to ensure that results from the survey are reasonable. 

Mass fraction of pollutant j to TOC in the vented gas, Yj:

The 2008 CENRAP study obtained basin-level mass fractions from survey data. ERG will 

attempt to obtain estimates for the mass fractions of pollutants by conducting a survey of oil and 

gas producers. Depending on the amount of data collected, averages may be determined at the 

county level, the TRC District level, the basin level, or state-wide. If insufficient data is 

collected on all counties, ERG may default to the compositions presented in the 2008 CENRAP 

study. The CENRAP data can also be used as a quality assurance check to ensure that results 

from the survey are reasonable. 

3.5.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level data on the 

number of components per well, annual hours of well operation, oil and gas product 

composition, and number of active oil and gas wells are required. ERG will collect data on the 

number of oil and gas wells per county using the most recently available database from the TRC. 

ERG will attempt to collect all other data items by conducting a survey of oil and gas producers 

owning active wells in the Texas counties covered in this emissions inventory development 

effort. 

3.6 Artificial Lift (Pumpjack) Engines 

A pumpjack is used to mechanically lift liquid out of the well if there is not enough bottom hole 

pressure for the liquid to flow all the way to the surface. The pumpjack can be driven by an 

electric motor; however, in isolated locations without access to electricity, combustion engines 

are used. The most common "off-grid" pumpjack engines run on casing gas produced from the 

well, but pumpjacks have been run on many types of fuel, such as propane (LPG) and diesel. 

Generally, pumpjacks have smaller engines than wellhead compressor engines, but they operate 

continuously (8760 hours per year) with minimum down-time. For this project, criteria pollutant 

emissions from pumpjack engines will be estimated. 
A-23 

3.6.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from artificial lift pumpjack engines. The relevant 

sources reviewed are listed in Table 3.6. 

Table 3.6 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Artificial Lift (Pumpjack) Engines 

Report Title Geographic 

Coverage Publication Date 

Natural Gas Compressor Engine Survey and 

Engine NOx Emissions at Gas Production 

Facilities (HARC, 2005) 

Eastern 

Portion of 

Texas 

August, 2005 

Ozone Precursors Emission Inventory for San 

Juan and Rio Arriba Counties, New Mexico 

(Pollack, et al., 2006) 

San Juan and 

Rio Arriba 

Counties, 

New Mexico 

August, 2006 

Natural Gas Compressor Engine Survey 

for Gas Production and Processing 

Facilities (HARC, 2006) 

Eastern 

Portion of 

Texas 

October, 2006 

Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

CENRAP 

States November, 2008 

3.6.2 Emission estimation approaches 

Of the studies reviewed, there was basically only one methodology used in determining 

emissions from pumpjack engines. The 2008 study conducted by ENIRON entitled: 

"Recommendations for Improvements to the CENRAP States' Oil and Gas Emission Inventories" 

(Bar-Ilan, et al., 2008), applies pollutant specific emission factors (g/hp-hr) to various data 

gathered from an inventory of artificial lift engines (based off of surveyed companies). The data 

consisted of engine specific information including horsepower, load factors, and actual hours 

operated. The emissions were scaled up to the basin level on the basis of well counts and then 

scaled to county-level using the fraction of total oil production from oil wells located in each 

county. All engine emissions factors (except those for SO2) were obtained from the EPA’s 

NONROAD model (EPA, 2005), which contains default emissions factors for an artificial lift 

natural gas fired engine. A similar methodology was used to calculate emissions from artificial 

pumpjack engines in the 2006 study entitled: "Ozone Precursors Emission Inventory for San 

Juan and Rio Arriba Counties, New Mexico" (Pollack, et al., 2006). However, the emission 

factors used in the 2006 New Mexico study were based on survey data of specific engine 

types/categories and their manufacturers' emission rates instead of the EPA’s NONROAD 

model. The specific methodology from these two studies is discussed in Section 3.6.3. 
A-24 

As an alternative to the methodology used in the CENRAP 2008 and the 2006 New Mexico 

studies, ERG explored the idea of applying the methodology we have proposed for estimating 

emissions from compressor engines (see Section 3.11) to determine emissions from pumpjack 

engines. We believe this approach would be optimal when calculating pumpjack emissions at 

the county level because it would not require knowing the specific count of pumpjack engines, 

nor their individual sizes. However, the approach would require ERG to develop power-to-pump 

requirements (Hp-hr/bbl) which are certain to vary with the depth of the oil in each well and may 

also depend on other factors such as plunger/equipment variations. ERG will attempt to obtain 

the required data to implement this methodology (pumpjack engine size, hours of operation, 

engine loads, well depth, and production data for each well) through the industry survey. 

Depending upon the response rate to the survey, ERG may be able to proceed with this approach 

and develop power-to-pump requirements in terms of Hp-hr/bbl based on engine size, hours of 

operation, and oil production data. At this point, we consider this to be an alternative approach. 

3.6.3 Preferred emission estimation approach 

ERG will use the methodology from the 2008 CENRAP study to generate estimated emissions 

from pumpjack engines. The calculation methodology for this particular approach is shown in 

Equations 9 and 10: 

907,185

i annual

engine

EF HP LF t

E

× × ×

= Equation (9)

where: 

Eengine are emissions from a pumpjack engine [ton/year/engine] 

EFi is the emissions factor of pollutant i [g/hp-hr] 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

tannual is the annual number of hours the engine is used [hr/yr] 

County-wide pumpjack engine emissions would then be calculated using Equation (10): 

1( ) engine,TOTAL engine TOTAL pumpjack pumpjack E = E ×W × f × − e Equation (10) 

where: 

Eengine,TOTAL is the total emissions from pumpjack engines in the county [ton/yr] 

Eengine is the total emissions from a pumpjack engine [ton/yr] 

WTOTAL is the total number of wells in the county 

fpumpjack is the fraction of oil wells with pumpjack engines

 epumpjack is the fraction of pumpjack engines that are electrified 

3.6.4 Data Needs 

ERG will implement the approach used in the 2008 CENRAP study and 2006 New Mexico study 

to estimate emissions from pumpjack engines. In order to perform the emission calculations, 
A-25 

information on engine ratings, load factors, annual hours of engine operation and county-level 

data of the number of oil wells with and without pumpjack engines is required. ERG will collect 

data on the number of oil wells per county using the most recently available database from the 

TRC. ERG will attempt to collect all other data items by conducting a survey of oil and gas 

producers owning active oil wells in the Texas counties covered in this emissions inventory 

development effort. 

If the industry response is sufficient, ERG may attempt to develop power-to-pump requirements 

(Hp-hr/bbl) for pumpjack engines to implement the alternative approach. 

3.7 Heaters and Boilers 

The purpose of heaters and boilers at oil and gas production facilities is to provide thermal 

energy input to certain operations within the production process. They can be used as separator 

heaters (heater treaters) to provide heat input to separation units, as tank heaters to maintain 

storage tank temperatures, or as inline heaters to maintain temperature within pipes and 

connections. Heaters and boilers may also be used in dehydrators; however, these sources will 

be covered under the dehydrator source methodology of this report. Heaters and boilers are 

typically natural gas-fired external combustors. They are primarily considered a source of NOx, 

as well as a minor source of CO, VOC and PM emissions. SO2 emissions may also occur if the 

gas used to fire the heaters contains Hydrogen Sulfide (H2S) which will be subsequently 

converted to SO2 during combustion. County-level emissions from heater sources will be 

estimated for the purpose of this inventory. 

3.7.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from emissions generated by heaters and boilers 

typically utilized at oil and natural gas production wells. The relevant sources reviewed are 

listed in Table 3.7. 

Table 3.7 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Heater and Boiler Emissions Estimates 

Report Title Geographic 

Coverage Publication Date 

Oil and Gas Emission Inventories for the Western 

States (Russell, et al., 2005) WRAP States December, 2005 

Ozone Precursors Emission Inventory for San 

Juan and Rio Arriba Counties, New Mexico 

(Pollack, et al., 2006) 

San Juan and 

Rio Arriba 

Counties, 

New Mexico 

August, 2006 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 
A-26 

Table 3.7 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Heater and Boiler Emissions Estimates (Cont.) 

Report Title Geographic 

Coverage Publication Date 

WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation 

Phase II (Bar-Ilan, et al., 2007) 

WRAP States September, 2007 

Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

CENRAP 

States November, 2008 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Piceance Basin (BarIlan, et al., 2009a) 

Piceance 

Basin, 

Colorado 

January, 2009 

3.7.2 Emission estimation approaches 

The reviewed literature provided two different approaches to estimating emissions from heaters 

and boilers at oil and gas sites. The first of these approaches is presented in the WRAP Phase I 

report “Oil and Gas Emission Inventories for the Western States” (Russell, et al., 2005) and 

WRAP Phase II report “WRAP Area Source Emissions Inventory Projections and Control 

Strategy Evaluation Phase II” (Bar-Ilan, et al., 2007). This approach will subsequently be 

referred to as Method 1. Method 1 utilizes separate emissions factors for oil wells and gas wells 

provided by the WYDEQ. The emissions factors for gas wells are given on a per well basis 

(lbs/yr per well) and oil well emissions factors are given on a per barrel produced basis 

(lbs/barrel). Area-wide emissions are then calculated based on the number of gas wells and 

barrels of oil produced in a specific area. Method 1 was also adopted in the 2007 TCEQ report 

on emissions from oil and gas production facilities. 

An alternative approach to estimate emissions from heaters and boilers was presented in the 2008 

CENRAP report “Recommendations for Improvements to the CENRAP States’ Oil and Gas 

Emissions Inventories” (Bar-Ilan, et al. 2008) and the Piceance Basin study “Development of 

Baseline 2006 Emissions from Oil and Gas Activity in the Piceance Basin” (Bar-Ilan, et al., 

2009a) from the Independent Petroleum Association of Mountain States (IPMAS)/WRAP Phase 

III reports. This approach will subsequently be referred to as Method 2. For Method 2, 

emissions of a particular pollutant from a single heater are based on the emissions factor of the 

heater, the annual flow rate of gas and the annual operating time of the heater. The gas flow is 

derived from the rating of the heater and the local natural gas heating value. All emissions 

factors used were based on EPA’s AP-42 emissions factors for natural gas-fired heaters provided 

under the external combustion sources category. An additional heater cycling fraction factor was 

also incorporated which takes into account the fraction of operating hours that the heater is 

actually firing. The 2008 CENRAP report also provides a separate methodology for estimating 

SO2 emissions by estimating the mass of gas combusted in the heater using the ideal gas law and 

then utilizing the mass fraction of H2S in the gas assuming 100 percent conversion to SO2. 

Basin-wide emissions were then estimated by determining the typical number of heaters per well 

and scaling up by well count. These estimates were then expanded to the county-level by 
A-27 

allocating the total basin-wide heater emissions into each county according to the fraction of 

basin total wells that are located in each county. 

Between the two methodologies, Method 2 provides a fundamental, bottom-up approach which 

allows for emissions to be estimated based on site-specific parameters and results in a more 

accurate and dynamic emissions inventory for heaters and boilers. Method 1 uses emissions 

factors which are previously calculated based on industry-wide averages for heater ratings and 

gas heating values specific to Wyoming, resulting in a lack of flexibility and detail as compared 

to Method 2. Additionally, Method 2 incorporates a scaling factor based on the number of 

heaters per well to supplement the scaling factor for the total number of wells. This level of 

detail is advantageous and allows for an additional layer of data collection when calculating 

emissions on the county-level. This is not captured in Method 1 which only accounts for the 

total number of wells. 

There are some short-comings with Method 2 that will need to be addressed in the development 

of this current emissions inventory. Due to lack of detail in the utilized databases, a breakdown 

of emissions by well type (i.e. oil or gas) was not available. Additionally, county-level 

emissions were derived from the allocation of basin-wide emissions based on the fraction of 

wells located in each county. The development of the updated TCEQ emissions inventory will 

attempt to obtain county-level data by well type in all aspects of the analysis to obtain a more 

accurate model of emissions from county to county. 

3.7.3 Preferred emission estimation approach 

As a preferred method to estimate emissions from heaters and boilers, ERG will use the 

CENRAP methodology. 

Emissions from a single heater may be calculated using Equation 11 (excluding SO2 emissions): 

( ) 10 2000 6× ×

× × ×

=

local

heater heater annual

heater HV

EF Q t hc

E Equation (11) 

where: 

Eheater is the emissions from a given heater [ton/yr] 

EFheater is the emission factor for a heater for a given pollutant [lb/MMSCF] 

Qheater is the heater MMBTU/hr rating [MMBTUrated/hr] 

HVlocal is the local natural gas heating value [MMBTUlocal/scf] 

tannual is the annual hours of operation [hr/yr] 

hc is the heater cycling fraction to account for the fraction of operating hours that the 

heater is firing. 

SO2 emissions from a single heater may be calculated using Equation 12: 
A-28 

































× ×

















×

× ×

×

×

=

.0 035

907200

2

2

2

,

T

MW

R

P

HV

f Q t hc

E

gas

local

H S heater annual

heater SO Equation (12) 

where: 

Eheater,SO2 is the SO2 emissions from a given heater [ton-SO2/yr] 

fH2S is the mass fraction of H2S in the gas 

Qheater is the heater MMBTU/hr rating [MMBTUrated/hr] 

tannual is the annual hours of operation [hr/yr] 

hc is the heater cycling fraction to account for the fraction of operating hours that the 

heater is firing. 

HVlocal is the local natural gas heating value [MMBTUlocal/scf] 

P is atmospheric pressure [1 atm] 

R is the universal gas constant [0.082 L-atm/mol-K] 

MWgas is the molecular weight of the gas [g/mol] 

The total emissions generated by heaters and boilers from specific county are calculated using 

Equation 13: 

( )

2000 2

, ,

TOTAL

heater TOTAL heater heater SO heater

W

E = E + E × N × Equation (13) 

where: 

Eheater,TOTAL is the total heater emissions in the county [ton/yr] 

Eheater is the total emissions from a single heater [ton/yr] 

Eheater,SO2 is the total SO2 emissions from a single heater [ton-SO2/yr] 

WTOTAL is the total number of wells in the county 

Nheater is the typical number of heaters per well in the county 

Emission factor for a heater for a given pollutant, Eheater:

ERG will use EPA’s AP-42 emissions factors when calculating emissions from heaters and 

boilers at oil and gas production sites. 

Heater MMBTU/hr rating, Qheater:

The 2008 CENRAP study obtained basin-level heater firing rates from survey data. Where 

survey data was not available for a specific basin, the average of all CENRAP basins was used. 

ERG will attempt to obtain heater firing rates by conducting a survey of oil and gas producers. 

Depending on the amount of data collected, averages may be determined at the county level, the 

TRC District level, the basin level, or state-wide. If insufficient data is collected on all counties, 

ERG may default to the average of the heater firing rate values presented in the 2008 CENRAP 

study. The CENRAP data can also be used as a quality assurance check to ensure that results 

from the survey are reasonable. 
A-29 

Local natural gas heating value, HVlocal:

The 2008 CENRAP study attempted to collect basin-level local heating values from survey data. 

However, the responses for the request of the value were insufficient; therefore, the average 

natural gas heating value from the IPAMS/WRAP Phase III analysis was used. ERG will 

attempt to obtain local heating values by conducting a survey of oil and gas producers. 

Depending on the amount of data collected, averages may be determined at the county level, the 

TRC District level, the basin level, or state-wide. If insufficient data is collected on all counties, 

ERG may default to the local natural gas heating value presented in the 2008 CENRAP study 

originally taken from the IPAMS/WRAP Phase III study. The CENRAP data can also be used as 

a quality assurance check to ensure that results from the survey are reasonable.

Annual hours of operation, tannual:

The 2008 CENRAP study obtained basin-level annual hours of operation for heaters from survey 

data. ERG will attempt to obtain data on the annual hours of operation for heaters and boilers by 

conducting a survey of oil and gas producers. Depending on the amount of data collected, 

averages may be determined at the county level, the TRC District level, the basin level, or statewide. If insufficient data is collected on all counties, ERG may default to the average of the 

annual operation hours presented in the 2008 CENRAP study. The CENRAP data can also be 

used as a quality assurance check to ensure that results from the survey are reasonable. 

Heater cycling fraction, hc:

The 2008 CENRAP study obtained basin-level heater cycling fractions from survey data. A 

heater cycling fraction of 1 was obtained for all responding basins. ERG will attempt to obtain 

data on the heater cycling fraction by conducting a survey of oil and gas producers. Depending 

on the amount of data collected, averages may be determined at the county level, the TRC 

District level, the basin level, or state-wide. If insufficient data is collected on all counties, ERG 

may default to a value of 1 as used in the 2008 CENRAP study. The CENRAP data can also be 

used as a quality assurance check to ensure that results from the survey are reasonable. 

Mass fraction of H2S, fH2S:

The 2008 CENRAP study obtained basin-level mass fractions of H2S in the gas used to fire the 

heaters and boilers from survey data. ERG will attempt to obtain data on the mass fraction of 

H2S by conducting a survey of oil and gas producers, or from the TRC. Depending on the 

amount of data collected, averages may be determined at the county level, the TRC District level, 

the basin level, or state-wide. If insufficient data is collected on all counties, ERG may default to

the average of the H2S mass fractions in the 2008 CENRAP study. The CENRAP data can also 

be used as a quality assurance check to ensure that results from the survey are reasonable. 

Molecular weight of gas, MWgas:

The 2008 CENRAP study obtained basin-level molecular weights of gas used to fire the heaters 

and boilers from survey data. ERG will attempt to obtain data on the molecular weights by 

conducting a survey of oil and gas producers. Depending on the amount of data collected, 

averages may be determined at the county level, the TRC District level, the basin level, or statewide. If insufficient data is collected on all counties, ERG may default to the average of the 

molecular weights in the 2008 CENRAP study. The CENRAP data can also be used as a quality 

assurance check to ensure that results from the survey are reasonable. 
A-30 

Typical number of heater per well, Nheater:

The 2008 CENRAP study obtained basin-level typical number of heaters per well from survey 

data. ERG will attempt to obtain data on the number of heaters per well by conducting a survey 

of oil and gas producers. Depending on the amount of data collected, averages may be 

determined at the county level, the TRC District level, the basin level, or state-wide. If 

insufficient data is collected on all counties, ERG may default to the average of the number of 

heaters per well in the 2008 CENRAP study. The CENRAP data can also be used as a quality 

assurance check to ensure that results from the survey are reasonable. 

3.7.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level data on the 

number of heaters and boilers per well, annual hours of heater operation, heater ratings, local 

natural gas heating values, heater cycling fractions, gas molecular weight and H2S content, and 

number of active oil and gas wells are required. ERG will collect data on the number of oil and 

gas wells per county using the most recently available database from the TRC. ERG will attempt 

to collect all other data items by conducting a survey of oil and gas producers owning active 

wells in the Texas counties covered in this emissions inventory development effort. 

3.8 Dehydrators 

Oil and natural gas, when first pumped from the ground, may contain a mixture of liquid and 

gaseous organic compounds, nitrogen, carbon dioxide, water, sand, and other impurities. The 

extracted product is passed through a three-phase separator. The separator allows the water, oil 

and gas to separate. The gaseous component is then piped to a dehydrator to remove any 

remaining moisture, improving its quality for sale, and to help prevent corrosion in downstream 

pipelines. 

The most common and economical process for dehydrating natural gas is to contact the gas with 

a hygroscopic liquid such as one of the glycols. Glycol dehydration is an absorption process, 

where the water vapor in the gas stream becomes dissolved in a relatively pure stream of glycol 

liquid solvent, removing the water from the natural gas. This process is completed in an 

absorption column. After the water is removed from the gas stream, the gas is pumped to a gas 

transmission pipeline. During the absorption process, the glycol also absorbs some methane and 

VOC. 

After leaving the absorber, the water-rich glycol is de-pressurized. This step is necessary as the 

absorber is typically operated at high pressure. The pressure must be reduced before the 

regeneration step. This step may occur in a flash vessel, if the dehydration system is equipped 

with one, or it may occur in the glycol regenerator vessel. If the water-rich glycol is first fed to a 

flash vessel, the hydrocarbon vapors are vented and any liquid hydrocarbons are skimmed from 

the glycol. The de-pressurization step is the primary source of VOC emissions from dehydrator 

systems. 

The glycol is regenerated by boiling the water out of the glycol. The water-rich glycol is 

pumped into a vented boiler vessel called a glycol regenerator boiler. Heat is added until the 
A-31 

temperature of the mixture is greater than 212 degrees (the boiling point of water), but less than 

400 degrees (the boiling point of glycol). The regeneration step allows the glycol to be purified 

and recovered for reuse with minimal loss of glycol. Any VOCs remaining in the glycol are 

volatized and vented to the atmosphere. The glycol regeneration step involves burning a fuel in a 

boiler to heat the glycol-water mixture. The combustion results in emissions of NOX and CO, 

and small amounts of PM10, SO2, VOC, and HAPs. 

In summary, the two discreet units in a dehydrator system that generate pollutant emissions are 

the flash vessel (if present) and the glycol regenerator boiler. The flash vessel and glycol 

regenerator normally vent methane, VOC, and HAP during normal, uncontrolled operation, 

while the glycol regenerator boiler also has combustion emissions. 

3.8.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from dehydrators. The relevant sources reviewed 

are listed in Table 3.8. 

Table 3.8 Existing Oil and Gas Exploration Emissions Studies

Report Title Geographic 

Coverage 

Publication 

Date 

Oil and Gas Emission Inventories for the Western States 

(Russell, et al., 2005) 

WRAP 

States December 2005 

Emissions from Oil and Gas Production Facilities (TCEQ, 

2007) Texas August, 2007 

WRAP Area Source Emissions Inventory Projections and 

Control Strategy Evaluation Phase II (Bar-Ilan, et al., 2007) 

WRAP 

States September, 2007

Development of Baseline 2006 Emissions from Oil and Gas 

Activity in the South San Juan Basin (Bar-Ilan, et al., 

2009b) 

New Mexico November, 2009

Recommendations for Improvements to the CENRAP 

States’ Oil and Gas Emissions Inventories (Bar-Ilan, et al., 

2008) 

CENRAP 

States November, 2008

Development of Emissions Inventories for Natural Gas 

Exploration and Production Activity in the Haynesville 

Shale (Grant, et al., 2009) 

Haynesville 

Shale, Texas 

& Louisiana 

August 2009 

3.8.2 Emission Estimation Approaches 

The reviewed literature provided both component-based and production-based approaches for 

estimating emissions from dehydrator flash vessels, glycol regenerator vents, and glycol 

regenerator boilers. 
A-32 

The 2005 WRAP Phase I study “Oil and Gas Emission Inventories for the Western States” 

(Russell, et al., 2005), the 2007 WRAP Phase II study “WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation Phase II” (Bar-Ilan, et al., 2007), and the 2007 

TCEQ study “Emissions from Oil and Gas Production Facilities” estimated uncontrolled VOC 

emissions from dehydrator flash vessels and glycol regenerator vents using a gas productionbased emission factor provided by the WYDEQ. The emission factor was multiplied by wellspecific gas production figures obtained from the State oil and gas commissions. The Wyoming 

emission factor was derived by calculating a production-weighted average composition of wet 

gas for each formation across the state. The weighted average was then used with GlyCalc 

modeling software to calculate emission factors based on one million standard cubic foot of gas 

per day (MSCFD). This methodology is not preferred for the 2008 inventory as the emission 

factor is based on gas composition data from Wyoming. 

The 2009 WRAP Phase III study “Development of Baseline 2006 Emissions from Oil and Gas 

Activity in the South San Juan Basin” (Bar-Ilan, et al., 2009b) utilized a similar approach to 

estimating emissions from dehydrator flash vessels and glycol regenerator vents as was done in 

the WRAP Phase I study. Emissions from glycol regenerator boilers were calculated using AP42 emission factors and the limited data available for field dehydrators to produce an emission 

factor on a per-unit-of-gas-throughput basis. This emission factor was applied to basin-wide gas 

production rates to determine basin-wide emissions from the regenerator boilers. 

The 2008 CENRAP study “Recommendations for Improvements to the CENRAP States’ Oil and 

Gas Emissions Inventories” (Bar-Ilan, et al., 2008) utilized the same approach to estimating 

emissions as was done in the WRAP Phase III study, except for the Texas basins. For Texas 

basins, the VOC emissions from dehydrator flash vessels were estimated with GlyCalc software 

using data on the composition of wellhead gas for each of the basins. This gas composition data 

were obtained from Northeast Texas Air Care (NETAC) and TCEQ and was based on sampling. 

This emission factor was applied to all gas production in each basin to derive basin-wide 

emissions estimates for dehydrator flash vessels and glycol regenerator vents. Emissions from 

glycol regenerator boilers were calculated using AP-42 emission factors to produce an emission 

factor on a per-unit of gas throughput basis. This emission factor was applied to all gas 

production in each basin to derive basin-wide emissions estimates for glycol regenerator boilers. 

This methodology was also used in the 2009 study “Development of Emissions Inventories for 

Natural Gas Exploration and Production Activity in the Haynesville Shale” (Grant, et al., 2009) 

for the East Texas Basin. 

The reviewed literature also addressed the effect of dehydrator system control technologies on 

emissions. The 2007 WRAP Phase II study “WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation Phase II” (Bar-Ilan, et al. 2007) evaluated three 

strategies or technologies for controlling VOC and HAP emissions from dehydrator systems. 

These are: optimize glycol circulation rate, install electric pumps, and install flash tank 

separators. 

• Optimizing Glycol Recirculation Rate: The study determined that VOC emissions 

could be reduced by 33 to 67 percent by optimizing the glycol circulation rate. Glycol 
A-33 

recirculation rate is set for the optimal rate based on the initial rate of gas production at a 

well. However, the rate is typically not adjusted as the gas production rate declines. As 

production rates decrease over time, glycol units designed for the original production 

rates tend to over circulate causing emission increases without significant reduction in 

gas moisture content. 

• Using Electric Pumps: The study determined that VOC emissions could be reduced by 

67 percent by using electric pumps to move the glycol fluids. Typically, fluids are 

moved through the glycol dehydration and regeneration system by using the pressurized 

gas produced at the wellhead. VOC emissions occur when the gas is vented during the 

regenerator step. 

• Installing a Flash Vessel Separator: The study determined that VOC emissions could 

be reduced by 10-40 percent by installing a flash vessel separator on dehydrator systems 

that do not already incorporate one. 

The 2007 WRAP Phase II study “WRAP Area Source Emissions Inventory Projections and 

Control Strategy Evaluation Phase II” (Bar-Ilan, et al. 2007) estimated that VOC and HAP 

emissions could be reduced by 98% through the use of VRUs. The US EPA, in AP-42, Chapter 

13.5 (Industrial Flares), estimates that control of waste VOC via flaring would control VOC by a 

minimum of 98%. These technologies are also applicable for vents in dehydrator systems. 

VRUs also ‘increase’ oil and gas production by recovering hydrocarbons that would be lost and 

redirecting them for pipeline sale or onsite fuel supply. 

3.8.3 Preferred Emission Estimation Approach 

Dehydrator System Flash Vessels and Glycol Regenerator Vents: As a preferred method, 

ERG will use the basic methodology from the CENRAP study to generate estimated emissions 

from dehydrators. The calculation of emission factors will be based on gas composition and 

production data obtained from the survey or other available data, and the annual natural gas 

production by county will be obtained for the year 2008 from the TRC. Survey data will be used 

to estimate the percentage of dehydration systems using four control technologies (optimize flow 

rate, flash tanks, VRUs, and flares). GlyCalc will be used to develop emission factors for VOC, 

benzene, toluene, ethylbenzene, and xylene (BTEX). Depending on the amount of data 

collected, averages may be determined at the county level, the TRC District level, the basin 

level, or state-wide. 

Glycol Regenerator Boilers: Emission factors for glycol regenerator boilers will be based on 

survey data for the amount of fuel needed to regenerate the glycol given the glycol flow rates and 

average moisture content of the gas produced. Depending on the amount of data collected, 

averages may be determined at the county level, the TRC District level, the basin level, or statewide. 

The equations and methodology for estimating dehydrator-related emissions are discussed 

below. These equations assume that all gas requires dehydration, either in the field or at a 

central processing facility, that all dehydrators circulate glycol at the optimum rate, and that the 

standard dehydrator system does not incorporate a flash vessel. 
A-34 

The calculation methodology for dehydrator flash vessel and glycol regenerator vent emissions at 

the county level follows Equation 14: 

Edehydrator, i, county j = EFdehydrator, i, county j x Pgas, county j x (1 + 0.5 Cflowrate – 0.25 Cflashvessel – 0.98 Cvru

– 0.98 Cflare) 

Equation (14)

where: 

Edehydrator, i, county j is the emissions of pollutant i from dehydrators in county j [tons/year] 

EFdehydrator, i, county j is the emission factor for pollutant i from dehydrators in county j 

[tons/MSCF] 

Pgas, county j is the production of gas in county j [MSCF/year] 

Cflowrate is the fraction of gas production in county j without optimized dehydrator flow 

rate 

Cflashvessel is the fraction of gas production in county j with dehydrators equipped with 

flash tanks 

Cvru is the fraction of gas production in county j controlled by VRUs 

Cflare is the fraction of gas production in county j controlled by flares 

A glycol regenerator boiler is essentially a heater and has similar emissions characteristics to 

typical combustion units. On-site gas is typically used as the fuel. Glycol regenerator boiler 

emission factors are developed using the process simulation software GlyCalc and AP-42 

emission factors for heaters. The emission factor is developed in terms of the amount of heat 

needed to process one MSCF of produced gas, and is adjusted for the heat content of the on-site 

gas, as needed. The calculation methodology for glycol regenerator boilers at the county level 

follows Equation 15: 

Eregenerator boiler, i, county j = EFregenerator boiler, i x Pgas, county j Equation (15)

where: 

Eregenerator boiler, i, county j is the emissions of pollutant i from glycol regenerator boilers in 

county j [tons/year] 

EFregenerator boiler, i is the emission factor for pollutant i from a glycol regenerator boiler per 

unit production [tons/MSCF] 

Pgas, county j is the gas production [MSCF/year] 

3.8.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level data on gas 

composition (VOC content and HAP speciation), typical configurations of dehydration system 

equipment (including glycol flow rates per MSCF of gas produced), and the GlyCalc software 

are required. ERG will collect data on the natural gas production per county using the most 

recently available database from the TRC, and will purchase the GlyCalc software directly from 

the vendor. ERG will attempt to collect all other data items by conducting a survey of oil and 

gas producers owning active wells in the Texas counties covered in this emissions inventory 

development effort. 
A-35 

3.9 Storage Tanks 

Storage tanks are used in a variety of applications in the oil and gas industry. An oil and gas 

well may produce oil, natural gas, or a mixture of the two. When oil and gas are brought to the 

surface, the liquids produced may contain a mixture of liquid and gaseous organic compounds, 

nitrogen, carbon dioxide, water, sand, and other impurities. The mixture is typically passed 

through a three-phase separator, which allows the water, oil and gas to separate. The liquid oil 

and water components are then piped to storage tanks. If the well produces gas, it is possible that 

liquids may condense out of the gas as the pressure is decreased. The hydrocarbon liquid 

produced at gas wells is known as condensate. Oil and condensate are piped to storage tanks 

until they can be transported offsite. Tanks are typically vented to the atmosphere. 

Oil and condensate storage tank emissions at wellhead and gathering sites are composed of 

flashing losses, working losses, and breathing losses. Flashing losses occur when a produced 

liquid (crude oil or condensate) with entrained gases experiences a pressure drop, as during the 

transfer of liquid hydrocarbons from a wellhead or separator to a storage tank. As the pressure 

on the liquid drops, some of the lighter compounds dissolved in the liquid are released or 

“flashed”. Some compounds that are liquids at the initial pressure and temperature, change 

phase from a liquid to a gas and are also released or “flashed” from the liquid in the storage tank. 

Working losses occur when vapors are displaced from a tank during the filling and unloading 

cycles, and when the fluid is agitated during filling of the tank. Breathing losses (also called 

standing losses) occur due to the normal evaporation of liquid in a tank. Breathing losses are 

vapors that are produced in response to the daily temperature change. 

3.9.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from oil and condensate storage tanks. The 

relevant sources reviewed are listed in Table 3.9. 

Table 3.9 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Storage Tanks 

Report Title Geographic 

Coverage Publication Date 

Calculation of Flashing Losses/VOC Emissions 

from Hydrocarbon Storage Tanks (ODEQ, 2004) All Regions July, 2004 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 

WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation 

Phase II (Bar-Ilan, et al., 2007) 

WRAP States September, 2007 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Uinta Basin (Friesen, 

et al., 2009) 

Uinta Basin, 

Utah March , 2009 
A-36 

Table 3.9 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Storage Tanks (Cont.) 

Report Title Geographic 

Coverage Publication Date 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Piceance Basin (BarIlan, et al., 2009a) 

Piceance 

Basin, 

Colorado 

January, 2009 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the South San Juan Basin 

(Bar-Ilan, et al., 2009b) 

San Juan 

Basin, New 

Mexico 

November, 2009 

Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

CENRAP 

States November, 2008 

Technical Supplement 6: Above Ground Liquid 

Storage Tanks (TCEQ, 2009a) Texas January 2009 

Upstream Oil and Gas Storage Tank Project Flash 

Emissions Models Evaluation (TCEQ, 2009b) Texas July, 2009 

Flash Emissions Model Evaluation Quantifying 

Volatile Organic Compound Emissions from 

Upstream Oil and Gas Storage Tanks (TCEQ, 

2009d) 

Texas October 2009 

VOC Emissions From Oil And Condensate 

Storage Tanks (TERC, 2009) East Texas April, 2009 

Calculating Volatile Organic Compounds (VOC) 

Flash Emissions from Crude Oil and Condensate 

Tanks at Oil and Gas Production Sites (APDG 

5942) (TCEQ, 2009c) 

Texas September, 2009 

3.9.2 Emission Estimation Approaches 

The reviewed literature provided both component-based and production-based approaches for 

estimating emissions from oil and condensate storage tanks. The three 2009 WRAP Phase III 

studies “Development of Baseline 2006 Emissions from Oil and Gas Activity in the San Juan 

Basin” (Bar-Ilan, et al., 2009b), “Development of Baseline 2006 Emissions from Oil and Gas 

Activity in the Piceance Basin” (Bar Ilan, et al., 2009a), and “Development of Baseline 2006 

Emissions from Oil and Gas Activity in the Uinta Basin” (Friesen, et al., 2009) either used 

storage tank emission factors supplied by producers or calculated emission factors for storage 

tanks based on data provided by the producers. These emission factors were then used to 

directly calculate emissions based on production at each well site (Piceance Basin), or to derive 

weighted average emission factors for the basin that were then multiplied by basin-wide 

production to derive emission estimates (San Juan Basin, Uinta Basin). 
A-37 

The 2009 TERC study “VOC Emissions From Oil And Condensate Storage Tanks” (TERC, 

2009) used data from the measured emissions from oil and condensate tank batteries to develop 

emission factors for the other oil and condensate storage tanks in the East Texas region. 

The 2009 TCEQ study “Upstream Oil and Gas Storage Tank Project Flash Emissions Models 

Evaluation” (TCEQ, 2009b) compared data from directly measured emissions from 36 oil and 

condensate storage tank batteries to the emissions estimates generated using the HYSYS process 

simulator, the E&P Tank model, the Gas-to-Oil Ratio (GOR), the Vasquez-Beggs correlation, the 

GRI-HAPCalc program, the Valko-McCain correlation, the EC/R equation, and TANKS 4.09d. 

The 2008 CENRAP study “Recommendations for Improvements to the CENRAP States’ Oil and 

Gas Emissions Inventories” (Bar-Ilan, et al., 2008) estimated emission factors for oil and 

condensate storage tanks using GRI-GLYCalc or HYSYS software, and these emission factors 

were multiplied by production figures for oil and condensate to develop emissions estimates. 

The 2009 TCEQ study “Upstream Oil and Gas Storage Tank Project Flash Emissions Models 

Evaluation” (TCEQ, 2009b), the 2009 TCEQ guidance “Technical Supplement 6: Above Ground 

Liquid Storage Tanks” (TCEQ, 2009a), and the 2009 TCEQ guide “Calculating Volatile Organic 

Compounds (VOC) Flash Emissions from Crude Oil and Condensate Tanks at Oil and Gas 

Production Sites (APDG 5942)” (TCEQ, 2009c) recommend calculating working and breathing 

losses with EPA TANKS and calculating flashing losses from black oil systems and gas 

condensate systems using, in order of preference, direct measurement, process simulator models 

(HYSIM, HYSIS, WINSIM, or PROSIM), the E&P TANK program, GRI-HAPCalc, or the GOR 

method. 

The 2007 TCEQ study used an emission factor developed for gas production in Wyoming, which 

was applied to oil and condensate production data for Texas. 

The reviewed literature also addressed the effect of storage tank control technologies on 

emissions. The 2007 WRAP Phase II study “WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation Phase II” (Bar-Ilan, et al. 2007) estimated that VOC 

and HAP emissions could be reduced by 98% through the use of VRUs. VRUs also ‘increase’ 

oil and gas production by recovering hydrocarbons that would be lost and redirecting them for 

pipeline sale or onsite fuel supply. The US EPA, in AP-42, Chapter 13.5 (Industrial Flares), 

estimates that control of waste VOC via flaring would control VOC by a minimum of 98%. 

3.9.3 Preferred Emission Estimation Approach 

ERG proposes a two tiered approach to developing regional emission estimates. ERG will use 

the methodology and emission factor data developed in the 2009 TERC to develop emission 

estimates for oil and condensate storage tanks in the East Texas Shale region. ERG will use this 

same methodology in other regions of Texas for which adequate existing direct measurement 

data are available. For other regions of Texas, ERG will use the methodology recommended in 

the 2009 TCEQ study, the 2009 TCEQ guidance, and the 2009 TCEQ APDG 5942. Specifically, 

we anticipate that working and breathing losses will be calculated with EPA TANKS, and 

flashing losses will be calculated using process simulator models, the E&P TANK program, 
A-38 

GRI-HAPCalc, or the GOR method, using the average VOC content of wellhead gas, obtained 

from a gas composition analyses, the API gravity of oil, and the gas-oil ratio, as data is available. 

Emission factors developed using these approaches will be assigned to the counties within their 

respective regions and will be multiplied by county-specific production data obtained from the 

TRC to derive county-specific emission estimates. Data on operating temperature and pressure 

will be collected via survey and emissions will be adjusted for the appropriate operating 

parameters. 

The calculation methodology for oil storage tank emissions at the county level follows Equation 

16: 

Eoil tank, i, county j = EFoil, i, county j x Poil, county j x (1 – 0.98 Cvru – 0.95 Cflare) Equation (16) 

where: 

Eoil tank, i, county j is the emissions of pollutant i from oil storage tanks in county j [tons/year] 

EFoil, i, county j is the emission factor for pollutant i from oil storage tanks in county j 

[tons/MSCF] 

Poil, county j is the production of oil in county j [MSCF/year] 

Cvru is the fraction of oil production in county j controlled by VRUs 

Cflare is the fraction of oil production in county j controlled by flares 

The calculation methodology for condensate storage tank emissions at the county level follows 

Equation 17: 

Econdensate tank, i, county j = EFcondensate, i, county j x Pcondensate, county j x (1 – 0.98 Cvru – 0.95 Cflare) 

Equation (17) 

where: 

Econdensate tank, i, county j is the emissions of pollutant i from oil storage tanks in county j 

[tons/year] 

EFcondensate, i, county j is the emission factor for pollutant i from oil storage tanks in county j 

[tons/MSCF] 

Pcondensate, county j is the production of oil in county j [MSCF/year] 

Cvru is the fraction of condensate production in county j controlled by VRUs 

Cflare is the fraction of condensate production in county j controlled by flares 

Emission factors, EFoil, i, county j, EFcondensate, i, county j:

The 2009 TERC study developed emission factors for oil and condensate storage tanks in the 

East Texas region. ERG will use these emission factors in developing emissions estimates for 

the counties covered by these studies. For the remainder of Texas, ERG will attempt to obtain 

county-level data on the properties of oil and condensate produced to develop emission factors 

for oil and condensate storage tanks using process simulation models or other emissions 

estimation models as outlined above. Depending on the amount of data collected, averages may 

be determined at the county level, the TRC District level, the basin level, or state-wide. 
A-39 

Production of oil and condensate Poil, county j, Pcondensate, county j

ERG will obtain county level data on the production of oil and condensate from the TRC. 

Fraction of storage tanks controlled by flares, Cflare and the fraction of storage tanks controlled 

by VRUs, Cvru:

ERG will attempt to obtain estimates for the number of storage tanks controlled by flares or 

VRUs either by conducting a survey of oil and gas producers, or from existing data from the 

TRC. Depending on the amount of data collected, averages may be determined at the county 

level, the TRC District level, the basin level, or state-wide. 

3.9.4 Data Needs 

In order to implement the preferred emission estimation approach, county-level data on monthly 

oil and condensate production data, monthly average temperature data, the frequency of oil and 

condensate tank unloading operations, and oil and gas composition/speciation profiles are 

needed. ERG will collect survey data on the number, size, configuration and usage of tanks at 

oil wells and gas wells, along with production data matched to those sites, so that averages for 

tank volume relative to production rate can be determined. ERG will collect data on oil and 

condensate production data using the most recently available database from the TRC. ERG will 

attempt to collect all other data items by conducting a survey of oil and gas producers owning 

active wells in the Texas counties covered in this emissions inventory development effort. 

3.10 Oil and Condensate Loading Racks 

Oil and condensate stored in field storage tanks is transferred to trucks and railcars and shipped 

to refineries for further processing. Fugitive VOC emissions are released from these loading 

processes as the vapors in the receiving vessel are displaced by the liquids from the storage 

tanks. These vapors are normally vented to the atmosphere. 

3.10.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from oil and condensate loading racks. The 

relevant sources reviewed are listed in Table 3.10.

Table 3.10 Oil and Gas Exploration Emissions Studies 

Report Title Geographic 

Coverage 

Publication 

Date 

Emissions from Oil and Gas Production Facilities (TCEQ, 2007) Texas August, 

2007 

WRAP Area Source Emissions Inventory Projections and Control 

Strategy Evaluation Phase II (Bar-Ilan, et al. 2007) Western States September, 2007 

Development of Baseline 2006 Emissions from Oil and Gas 

Activity in the South San Juan Basin (Bar-Ilan, et al., 2009b) New Mexico November, 2009 
A-40 

3.10.2 Emission Estimation Approaches 

The August 2007 TCEQ report “Emissions from Oil and Gas Production Facilities” (TCEQ, 

2007) and the November 2009 report “Development of Baseline 2006 Emissions from Oil and 

Gas Activity in the South San Juan Basin” (Bar-Ilan, et al., 2009b) included a production-based 

emissions methodology for oil and condensate loading. Both of these studies estimated 

uncontrolled VOC emissions from oil and condensate loading using the AP-42 loading equation. 

In the 2007 TCEQ study, the true vapor pressure of oil and condensate was determined by using 

average temperature data for each county in Texas and temperature-dependent vapor pressures of 

crude oil from AP-42. Temperature data from 87 weather stations throughout Texas were 

obtained and isotherms were developed to estimate average annual temperatures for each county 

in Texas. These temperatures determined both the true vapor pressure using AP-42 data and the 

average temperature of the bulk liquid (T). The molecular weight of tank vapors was assumed 

constant and equal to AP-42 data for crude oil (50 lb/lb-mole) and gasoline (RVP 7) (68 lb/lbmole) at 60 degrees F for oil and condensate, respectively. The gasoline value was used for 

condensate since no specific number for condensate was available. The type of loading 

operation was assumed to be submerged loading with a dedicated vapor balance. 

The AP-42 equation to calculate temperature-dependent emission factors for loadout losses 

generates an emission factor based on the amount of liquid loaded. The calculated emission 

factors were applied to the amount of oil and condensate produced in each county, which was 

obtained from data provided by the TRC. 

The reviewed literature also addressed the effect of storage tank control technologies on 

emissions. These technologies could be adapted to control emissions from storage tank 

unloading. The 2007 WRAP Phase II study “WRAP Area Source Emissions Inventory 

Projections and Control Strategy Evaluation Phase II” (Bar-Ilan, et al. 2007) estimated that VOC 

and HAP emissions could be reduced by 98% through the use of VRUs. The US EPA, in AP-42, 

Chapter 13.5 (Industrial Flares), estimates that control of waste VOC via flaring would control 

VOC by a minimum of 98%. 

3.10.3 Preferred Emission Estimation Approach 

ERG will use the methodology in the 2007 TCEQ study and the 2009 WRAP Phase III study. 

AP-42 emission factors for loading losses will be calculated at the county level. These emission 

factors will be multiplied by county-specific production data obtained from the TRC to derive 

county-specific emission estimates. This methodology requires oil and condensate production 

data, data on the composition and RVP of the oil and condensate produced, and monthly 

temperature data for the counties in which the oil and condensate are produced. Survey data will 

be gathered on the number of sites in the county that use VRUs or flares to control loading 

emissions. These data will be used to account for emissions controlled by VRUs or flares. 

The AP-42 equation to calculate loading emission factors is shown in Equation 18: 

LLoil, condensate, county j = 12.46 x S x P x M / Tcounty j Equation (18) 
A-41 

Where: 

LLoil, condensate, county j is the loading loss [lb/1,000 gal of liquid loaded] for county j 

S is Saturation factor (based on type of loading operation) 

P is True vapor pressure of liquid loaded [psia] 

M is Molecular weight of tank vapors [lb/lb-mole] 

Tcounty j is Temperature of bulk liquid loaded [oR] for county j 

The AP-42 equation to calculate temperature-dependent emission factors for loadout losses 

generates an emission factor based on the amount of liquid loaded. Truck or railcar loading 

emissions will then be calculated by multiplying the emission factor by county-level production 

figures for oil and condensate production, as shown in Equation 19: 

Eloading, county j = LLoil, condensate, county j x Poil, condensate, county j x 42 gal/bbl x 1 ton/2,000 lbs x

(1 – 0.98 Cvru – 0.98 Cflare) 

 Equation (19)

Where: 

Eloading, county j is the emissions from oil or condensate truck loading for county j [ton/year]

LLoil, condensate, county j is the emission factor for oil or condensate loading loss for county j 

[lb/1,000gal]

Poil, condensate, county j is oil or condensate production for county j [bbl/year] 

Cvru is the fraction of loading in county j controlled by VRUs 

Cflare is the fraction of loading in county j controlled by flares 

3.10.4 Data Needs 

In order to implement the preferred emissions estimation approach, county-level oil and 

condensate production data on a monthly basis, loading type, vapor pressure data for oil and 

condensate, molecular weight of tank vapors, and monthly average temperature data for each 

county is needed. ERG will collect county-level oil and condensate production data using the 

most recently available database from the TRC. ERG will attempt to obtain the other data 

needed to apply this methodology through the survey. If survey data is unavailable, default data 

may be used as described above for the 2007 TCEQ study. The 2007 TCEQ data can also be 

used as a QA check on the reasonableness of the survey results. 

3.11 Compressor Engines 

Spark-ignited internal combustion engines are normally used to drive gas field compressors. The 

compressors are used to boost the pressure of well-head natural gas so that it can be injected into 

higher pressure gathering lines. These compressor engines burn well-head natural gas and can 

represent a significant NOx area emissions source category as they generally operate 8,760 hours 

per year with minimum down-time. For this project, in addition to criteria pollutant emissions, 

formaldehyde emissions from compressor engines will be estimated. Formaldehyde is formed as 

a by-product of the combustion process. 
A-42 

3.11.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from compressor engines. The relevant sources 

reviewed are listed in Table 3.11. 

Table 3.11 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Compressor Engines 

Report Title Geographic 

Coverage Publication Date 

Tyler/Longview/Marshall Flexible Attainment 

Region Emission Inventory of Ozone Precursors 

VOC, NOx and CO (Pollution Solutions, 2005) 

Tyler, 

Longview, 

Marshall 

area, Texas 

February, 2005 

Natural Gas Compressor Engine Survey and 

Engine NOx Emissions at Gas Production 

Facilities (HARC, 2005) 

Eastern 

Portion of 

Texas 

August, 2005 

Ozone Precursors Emission Inventory for San 

Juan and Rio Arriba Counties, New Mexico 

(Pollack, et al., 2006) 

San Juan and 

Rio Arriba 

Counties, 

New Mexico 

August, 2006 

Natural Gas Compressor Engine Survey 

for Gas Production and Processing 

Facilities (Burklin and Heaney, 2006) 

Eastern 

Portion of 

Texas 

October, 2006 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 

Special Study Relating to Oil and Gas 

Production: 2005 and 2007 Emissions from 

Compressor Engines with Consideration for Load 

Factor (Pollution Solutions, 2008) 

Tyler, 

Longview, 

Marshall 

area, Texas 

August, 2008 

Recommendations for Improvements to the 

CENRAP States’ Oil and Gas Emissions 

Inventories (Bar-Ilan, et al., 2008) 

CENRAP 

States November, 2008 

2008 Southeast Texas Compressor Engines and 

Dehydrators Survey (TCEQ, 2009e) 

Southeast 

Texas 

Presentation 

May, 2009 

Development of Emissions Inventories for 

Natural Gas Exploration and Production Activity 

in the Haynesville Shale (Grant, et al., 2009) 

Northeast 

Texas and 

Northwest 

Louisiana 

August, 2009 
A-43 

3.11.2 Emission estimation approaches 

Of the studies reviewed, the majority take a similar approach in determining emissions from 

compressor engines at oil and gas production facilities. These studies typically apply a county 

specific emission factor (developed through various survey data) to natural gas production by 

county. The specific methodology is discussed in Section 3.11.3. 

It should be noted that the CENRAP 2008 report varies from this approach in that it recommends 

using well count as a surrogate for scaling wellhead compressor emissions to the basin level. 

The report states that gas production estimates may underestimate the number of wellhead 

compressors in use. County-level emissions estimates were then derived by allocating basin total 

wellhead compressor engine emissions to the county level by the fraction of total basin wells in 

each county. 

3.11.3 Preferred emission estimation approach 

As a preferred method to estimate emissions from natural gas compressor engines, ERG will use 

annual natural gas production by county along with survey-generated county-level emission 

factors to determine emissions from compressor engines at oil and gas production facilities. The 

annual natural gas production by county will be obtained for the year 2008 from the TRC. 

County-level emission factors will be calculated using the methodology from the study “Natural 

Gas Compressor Engine Survey and Engine NOX Emissions at Gas Production Facilities” 

conducted by ERG for the Houston Advanced Research Council (HARC) to generate emission 

factors from compressor engines at oil and gas production facilities (HARC, 2005). The HARC 

2005 report was updated in 2006 to include more engine size categories and to add the year 2000 

to the previous inventory; however, these updates did not change the calculation methodology 

used in the original 2005 report. 

County-level emission factors will be calculated Equation (19) as provided in the HARC study 

reports: 

EFijk = F1i x F2j x Ci x Hj x EFjk x 1/2000 Equation (19) 

Where: 

EFijk is the emission factor for county i, for engine type j, and pollutant k [tons/MSCF] 

F1i is the fraction of wells requiring compression in county i 

F2j is the fraction of compression load represented by engines of type j 

Ci is the compression requirements for county i [hp-hr/MSCF] 

Hj is the brake specific fuel consumption for engine type j [MMBtu/hp-hr] 

EFjk is the emission factor for engine type j, and pollutant k [lb/MMBtu] 

The data needed to implement this approach is discussed below. 
A-44 

Fraction of wells requiring compression in county i, F1i:

The HARC studies (HARC, 2005 and 2006) assumed the fraction of wells requiring compression 

is equal to the fraction of wells greater than one year old. As 2008 is the base year for this study 

and was an unusually active year in Texas for well drilling, ERG will attempt to verify this 

assumption by contacting experts in the field by phone as well as through a survey questionnaire. 

Although the fraction of wells greater than one year old was relatively constant in the three 

districts examined by the HARC studies, ERG will re-calculate an average fraction across the 

entire state using data from all twelve TRC districts for 2008. The number of wells completed 

each year and the total number of operating wells by district are available from the TRC. 

Fraction of compression load represented by engines of type j, F2j:

While the initial report (HARC, 2005) focused on engines less than 500 horsepower (hp), the 

follow-up report (HARC, 2006) included engines greater than 500 hp and also provided a more 

detailed breakdown of engines less than 500 hp. ERG will attempt to update the distribution of 

engine types through a new survey questionnaire. In addition, ERG will combine engine data 

from the two 2007 TCEQ engine surveys conducted on the counties located in the Dallas -Forth 

Worth (D-FW) metropolitan area and Southeast Texas. These TCEQ surveys were completed as 

efforts to amend the state clean air plan for ozone. Engine operators reported engine counts, 

engine sizes, NOX emissions, and other data to TCEQ. If insufficient data are available through 

the D-FW and Southeast Texas surveys, ERG may default to the distribution of engine types 

presented in the follow-up HARC report and TCEQ surveys to estimate the fractions of various 

engine types in attainment and nonattainment areas of Texas. 

Compression Requirements for county i, Ci: 

A compressor's operating behavior is generally dependent on the relationship between pressure 

ratio and volume or mass flow rate. In particular, the operating behavior for a compressor engine 

located at an oil and gas well is based on the compressor suction and discharge pressures 

required to convey the natural gas from the well head to the gathering lines. These pressures, or 

the compression ratio, along with the natural gas flow-rate through the compressor, define the 

engine load in terms of the amount of mechanical work that is required to compress the natural 

gas produced by the well. This mechanical work (hp-hr) is directly proportional to the volume of 

fuel (MSCF) that must be burned by the compressor engine and the relationship is termed a 

compression requirement (hp-hr/MSCF). Special compressor calculators can be used to convert 

inlet and outlet pressures into compression requirements which can then be used to determine 

emissions created by compressor engines. Because of this direct relationship of mechanical 

work to volume of fuel burned, one would expect a 100 Hp engine to burn almost an equal 

amount of fuel as two (2) 50 Hp engines when compressing the same volume of natural gas 

produced by the same well. Therefore, it is not necessary to know the specific numbers of 

engines, or their individual sizes when calculating emissions from compressors at the county 

level. 

In spite of this observable fact, all natural gas compressors have a maximum rating and most of 

them deliver less natural gas than their maximum rating. In a 2002 emissions inventory 

(Pollution Solutions, 2005) entitled "Tyler/Longview/Marshall Flexible Attainment Region 

Emission Inventory", the author developed a compression requirement (hp-day/MSCF) through 

survey data assuming the compressor engines were operating under full load or maximum 
A-45 

installed horsepower. This assumption caused an overestimation of the amount of fuel that was 

consumed by the compressor engines and consequently overestimated the amount of emissions 

from these engines. A more recent study by Pollution Solutions (2008) entitled "2005 and 2007 

Compressor Engine Emissions and Load Factors Report" determined average load factors for 

three engine categories, all of which were less than 100%. For engines less than 240 hp, the load 

factor was 70%. For engines between 240-500 hp, the load factor was 69%. For engines greater 

than 500 hp, the load factor was 58%. These engine load factors were applied to the previous 

study (Pollution Solutions, 2005) in order to determine more accurate emissions estimates for 

compressor engines located in Panola County as well as the five NETAC counties. 

The 2005 HARC report developed compression requirements ranging between 3.1 and 3.5 Hphr/MSCF for three distinct districts in eastern Texas, including one attainment area and two 

nonattainment areas (Houston and Dallas) by obtaining typical well pressures and gathering line 

pressures through a field study. The engines in this particular field survey were operated at loads 

ranging from about 10% to 70% of full load, and averaged 40% load. Additionally, compression 

requirements that can be deduced from the 2008 Pollution Solutions study are relatively in-line 

with the compression requirements used in the 2005 HARC report. More specifically, the 191 

Hp-day/MSCF compression requirement used in the 2005 Pollutions Solutions study, when 

adjusted for the load factors from the 2008 Pollutions Solutions study, yield compression 

requirements between 4.5 to 5.5 Hp-hr/MSCF. Additionally, TCEQ determined through a 2007 

TCEQ engine survey (conducted on the counties located in the D-FW metropolitan area) a 

compression requirement of 226 Hp-day/MMcf for area source compressor engines outside the 

D-FW metropolitan area. This value equates to approximately 5.4 Hp-hr/MSCF which is also in 

agreement with previous studies mentioned. 

ERG will attempt to develop 2008 compression requirements through a new survey 

questionnaire that would aim to collect typical well pressures and gathering line pressures, as 

well as engine load factors. As mentioned previously, the compression requirements developed 

for the 2005 HARC study, the 2008 Pollution Solutions study, and the 2007 TCEQ engine D-FW 

metropolitan survey were all relatively consistent. ERG may default to and apply an average of 

these factors to the entire state in both attainment and nonattainment areas if insufficient data is 

obtained through the survey effort. 

Brake specific fuel consumption for engine type j, Hj:

The HARC studies (HARC, 2005 and 2006) determined brake specific fuel consumption for the 

most common engine model of each engine category using engine model distributions provided 

by engine leasing companies. ERG will develop updated representative engine models using data 

gathered through a survey questionnaire. In addition, ERG will use the engine data from the two 

2007 TCEQ engine surveys conducted on the counties located in the D-FW metropolitan area 

and Southeast Texas, and may use the 2005 and 2006 HARC data as well. 

Emission factor for engine type j, and pollutant k, EFjk:

As noted in the 2008 CENRAP study, there are two distinct types of compressor engines used to 

boost the pressure of well-head natural gas: “rich-burn” engines that are characterized by NOx

emissions factors in the range of approximately 10 – 20 g/bhp-hr; and “lean-burn” engines that 

are characterized by NOx emissions factors in the range of approximately 1.0 – 5.0 g/bhp-hr. The 
A-46 

exact NOx emissions factors depend on the horsepower, make and model, and model year of the 

engine, and whether the engine has been converted from a rich-burn to a lean-burn engine. 

Many of the compressor engine emission factors used in the 2008 CENRAP study came from a 

2006 study entitled: "Ozone Precursors Emission Inventory for San Juan and Rio Arriba 

Counties, New Mexico" (Pollack, et al., 2006). This particular study contained an extensive 

database of emissions factors for a range of well-head compressor engine makes and models. 

From this database, average rich-burn and lean-burn engine emissions factors for NOx, VOC, 

CO, and SO2 were derived. PM10, CO2, and CH4 emission factors were obtained from AP-42. It 

should be noted that all pollutant and engine-specific emission factors used in the 2005/2006 

HARC studies were taken from AP-42. 

For this study, ERG will attempt to develop improved emission factors (especially for NOx and 

formaldehyde emissions) using data gathered through a survey questionnaire in order to estimate 

pollutant emissions from each engine type based on the county-by-county breakdown of engine 

use described above. In addition to new survey data, ERG will use the engine data from the two 

2007 TCEQ engine surveys conducted on the counties located in the D-FW metropolitan area 

and Southeast Texas; as well as the data from the 2006 New Mexico study. If insufficient data 

is collected through the survey effort, ERG may default to and apply the average rich-burn and 

lean-burn engine emissions factors used in the 2006 New Mexico study, or AP-42 emission 

factors. 

ERG has not found any studies using a different formaldehyde emission factor than provided in 

EPA's AP-42 document (July 2000) entitled "Natural Gas-fired Reciprocating Engines". AP-42 

presents Formaldehyde emission factors for 2-stroke lean burn engines, 4-stroke lean burn 

engines, and 4-stroke rich burn engines. All the AP-42 formaldehyde emission factors have an 

"A" rating. 

3.11.4 Data Needs 

In order to implement the preferred emission estimation approach, the gas production in each 

county is needed. ERG will collect data on throughput per county using the most recently 

available database from the TRC. This activity data when applied to the different factors 

mentioned in Section 3.11.3 above, will allow ERG to estimate county-level emissions from 

compressor engines. 

3.12 Turbines 

Turbines are used in the oil and gas industry to compress gas or to generate electricity. In the gas 

industry they tend to be used in processing and transmission rather than gathering applications 

(CAPP, 2004). Compressors driven by turbines may be found at midstream oil and gas facilities 

such as large pipeline compressor stations, gas storage facilities, or gas processing plants. 

Turbines may also be utilized in some smaller upstream applications to assist in the transfer of 

gas produced in the field from multiple or individual well sites or gas gathering plants to 

midstream facilities. However, some of these applications (at the well or gas gathering plant 

level) are usually handled by reciprocating internal combustion engines, which are covered in 
A-47 

Section 3.11 of this memo. Most midstream facilities utilizing natural gas-fired turbines are 

assumed to be permitted and included in the inventory as major point sources. Turbines used in 

the oil and gas industry burn natural gas and can represent a significant source of NOx emissions, 

in addition to other combustion-related pollutants.

In remote locations such as offshore platforms or oil and gas fields where electricity off the grid 

is not readily available, gas turbines may be used in a combined heat and power (CHP) 

application to drive generators for electricity and to provide heat in buildings and crew quarters. 

3.12.1 Literature Review 

ERG conducted a literature review to obtain information on established methodologies to 

estimate the atmospheric release of pollutants from turbines. The relevant sources reviewed are 

listed in Table 3.12. 

Table 3.12 Existing Oil and Gas Exploration Emissions Studies Containing Methodologies 

for Turbines 

Report Title Geographic 

Coverage Publication Date 

Emissions from Oil and Gas Production Facilities 

(TCEQ, 2007) Texas August, 2007 

Development of Baseline 2006 Emissions from 

Oil and Gas Activity in the Uinta Basin (Friesen, 

et al., 2009) 

Uinta Basin, 

Utah March , 2009 

3.12.2 Emission estimation approaches 

The reviewed literature did not provide any sources that explicitly included gas-fired turbines as 

an area source emissions source. 

The study “Development of baseline 2006 Emissions From Oil and Gas Activity in the Unita 

Basin” (Friesen, et al., 2009) included one compressor station that was defined as a turbine as 

part of the point source inventory. The data for this point source was provided directly by the 

State of Utah. 

The study “Emissions from Oil and Gas Production Facilities” (TCEQ, 2007) included emission 

from turbines located at offshore platforms as obtained from the Minerals Management Service 

(MMS). The study did not estimate emissions from onshore turbines. 

3.12.3 Preferred emission estimation approach 

At this point, it is unknown whether turbines will be found at locations other than point sources 

already included in the State of Texas Air Reporting System (STARS) emissions inventory. 

There are no existing studies that present approaches for estimating area sources emissions from 

turbines used in oil and gas upstream production sources, but there are AP-42 emission factors 
A-48 

that could be used if it is discovered that there are turbines not counted in the point source 

inventory. 

3.12.4 Data Needs 

As part of the survey efforts, ERG will include questions pertaining to turbine usage in gas field 

applications at the well level and at gas gathering and processing stations. As any smaller 

turbines (those not already included in the point source inventory) would be used for the same 

purposes as compressor engines, the target recipients of the survey would be identical. Based on 

the findings of the HARC “Natural Gas Compressor Engine Survey for Gas Production and 

Processing Facilities” study (HARC, 2006), there are very few engines used in gas field 

compressor applications approaching the size of the smallest turbines (approximately 1,500 hp). 

ERG will coordinate inclusion of turbines in this area source inventory with TCEQ if it is 

determined that there are turbines unaccounted for in the point source inventory. 

4.0 References

Bar-Ilan, Amnon; Grant, John; Parikh, Rajashi; Pollack, Alison; Henderer, Doug; Pring, Daniel; 

and Sgamma, Kathleen, 2009a. Development of Baseline 2006 Emissions from Oil and Gas 

Activity in the Piceance Basin. Prepared for the Western Governor’s Association and the 

Independent Petroleum Association of Mountain States. January, 2009. 

Bar-Ilan, Amnon; Grant, John; Parikh, Rajashi; Pollack, Alison; Henderer, Doug; Pring, Daniel; 

and Sgamma, Kathleen, 2009b. Development of Baseline 2006 Emissions from Oil and Gas 

Activity in the South San Juan Basin. Prepared for the Western Regional Air Partnership and the 

Independent Petroleum Association of Mountain States. November, 2009. 

Bar-Ilan, Amnon; Parikh, Rajashi; Grant, John; Shah, Tejas; and Pollack, Alison, 2008. 

Recommendations for Improvements to the CENRAP States’ Oil and Gas Emissions Inventories. 

Prepared for Central States Regional Air Partnership. November, 2008 

Bar-Ilan, Amnon; Friesen, Ron; Pollack, Alison; and Hoats, Abigail, 2007. WRAP Area Source 

Emissions Inventory Projections and Control Strategy Evaluation Phase II. Prepared for the 

Western Governor’s Association. September, 2007. 

Canadian Association of Petroleum Producers (CAPP), September 2004. A National Inventory 

of Greenhouse Gas (GHG), Criteria Air Contaminant (CAC) and Hydrogen Sulfide (H2S) 

Emissions by the Upstream Oil and Gas Industry, Volume 3, Methodology for Greenhouse 

Gases. 

EPA, 2005. “User’s Guide for the Final NONROAD2005 Model,” U.S. Environmental 

Protection Agency, Research Triangle Park, NC, 2005. EPA420-R-05-013. 

Friesen, John; Parikh, Rajashi; Grant, John; Bar-Ilan, Amnon; Pollack, Alison; Henderer, Doug; 

Pring, Daniel; Sgamma, Kathleen; and Schlagel, Phil, 2009. Development of Baseline 2006 
A-49 

Emissions from Oil and Gas Activity in the Uinta Basin. Prepared for the Western Governor’s 

Association and the Independent Petroleum Association of Mountain States. March, 2009. 

Grant, John; Parker, Lynsey; Bar-Ilan, Amnon; Kemball-Cook, Sue; Yarwood, Greg. 

Development of Emissions Inventories for Natural Gas Exploration and Production Activities in 

the Haynesville Shale. Prepared for The East Texas Council of Governments. August 2009. 

Houston Advanced Research Center (HARC), 2005. Natural Gas Compressor Engine Survey and 

Engine NOX Emissions at Gas Production Facilities. Prepared by Eastern Research Group, Inc. 

August 31, 2005. 

Houston Advanced Research Center (HARC), 2006. Natural Gas Compressor Engine Survey for 

Gas Production and Processing Facilities. Prepared by Eastern Research Group, Inc. October 5, 

2006. 

Oklahoma Department of Environmental Quality (ODEQ), July 2004. Calculation of Flashing 

Losses/VOC Emissions from Hydrocarbon Storage Tanks. Internet Address: 

http://www.deq.state.ok.us/factsheets/air/CalculationLosses.pdf 

Pollack, Alison; Russell, James; Grant, John; Friesen, Ron; Fields, Paula; and Wolf, Marty, 

2006. Ozone Precursors Emission Inventory for San Juan and Rio Arriba Counties, New Mexico. 

Prepared for New Mexico Environment Department. August, 2006. 

Pollution Solutions, 2005. “Tyler/Longview/Marshall Flexible Attainment Region Emission 

Inventory of Ozone Precursors VOC, NOx and CO,” Prepared for Northeast Texas Air Care. 

February, 2005. 

Pollution Solutions, 2007. “Special Study Relating to Oil and Gas Production: 2005 and 2007 

Emissions from Compressor Engines with Consideration for Load Factor" Final report prepared 

for the East Texas Council of Governments, Kilgore, TX. 

Russell, James and Pollack, Alison, 2005. Oil and Gas Emissions Inventories for the Western 

States. Prepared for Western Governor’s Association. December, 2005. 

Texas Commission on Environmental Quality (TCEQ), 2007. Emissions from Oil and Gas 

Production Facilities, 2007. Prepared by Eastern Research Group, Inc. August 31, 2007. 

Texas Commission on Environmental Quality (TCEQ), 2009a. 2009 Emissions Inventory 

Guidelines: Appendix A: Technical Supplement 6: Above Ground Liquid Storage Tanks. Texas 

Commission on Environmental Quality, TCEQ Publication RG-360A/09. January 2009. 

Texas Commission on Environmental Quality (TCEQ), 2009b. Upstream Oil and Gas Storage 

Tank Project Flash Emissions Models Evaluation. July, 2009. 
A-50 

Texas Commission on Environmental Quality (TCEQ), 2009c. Calculating Volatile Organic 

Compounds (VOC) Flash Emissions from Crude Oil and Condensate Tanks at Oil and Gas 

Production Sites (APDG 5942), 2009. September, 2009. 

Texas Commission on Environmental Quality (TCEQ), 2009d. Flash Emissions Model 

Evaluation Quantifying Volatile Organic Compound Emissions from Upstream Oil and Gas 

Storage Tanks, 2009. Slide Presentation by Danielle Nesvacil, John Jolly, and Russ Nettles 

(TCEQ) and Butch Gidney and Stephen Pena (Hy-Bon Engineering). October 2009. 

Texas Environmental Research Consortium (TERC), October 2006, revised April 2009. VOC 

Emissions from Oil and Condensate Storage Tanks.
A-51 

APPENDIX A 

LIST OF ACRONYMS/ABBREVIATIONS 

API American Petroleum Institute 

BTEX Benzene, Toluene, Ethylbenzene, and Xylene 

CAPP Canadian Association of Petroleum Producers 

CenRAP Central States Regional Air Partnership 

CO Carbon Monoxide 

DOE U.S. Department of Energy 

ERG Eastern Research Group, Inc. 

GOR Gas-to-Oil Ratio 

GPA Gas Processors Association 

GRI Gas Research Institute 

HAP Hazardous Air Pollutant 

HARC Houston Advanced Research Center 

hp Horsepower 

H2S Hydrogen Sulfide 

IPMAS Independent Petroleum Association of Mountain States 

LPG Liquefied Petroleum Gas 

MMS Minerals Management Service 

MMSCF Million Standard Cubic Feet 

MMSCFD Million Standard Cubic Feet Per Day 

MSCF Thousand Standard Cubic Feet 

MW Molecular Weight 

NETAC Northeast Texas Air Care 

NIF National Emissions Inventory Input Format 

NOx Nitrogen Oxides 

PM10 Particulate Matter that has particle diameter less than 10 micrometers 

PM2.5 Particulate Matter that has particle diameter less than 2.5 micrometers 

QA Quality Assurance 

SCC Source Classification Code 

SCF Standard Cubic Feet 

SO2 Sulfur Dioxide 

STARS State of Texas Air Reporting System 

STP Standard Temperature and Pressure 

TCEQ Texas Commission on Environmental Quality 

TexAER Texas Air Emissions Repository 

TRC Texas Railroad Commission 

US EPA United States Environmental Protection Agency 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

WRAP Western Regional Air Partnership 

WYDEQ Wyoming Department of Environmental Quality 
Appendix B – Task 3 Memorandum 
B-1 

TECHNICAL MEMORANDUM

Date: July 9, 2010 

To: Martha Maldonado 

 Project Representative 

 Texas Commission on Environmental Quality (TCEQ) 

From: Mike Pring, Eastern Research Group, Inc. (ERG) 

Daryl Hudson (ERG) 

Jason Renzaglia (ERG) 

Brandon Smith (ERG) 

Stephen Treimel (ERG) 

 

Re: Oil and Gas Sources Inventory – Final Technical Memorandum for Task 3 

 TCEQ Contract No. 582-7-84003, Work Order No. 582-7-84003-FY10-26 

1.0 Introduction

The purpose of this Work Order is to develop a 2008 base year air emissions inventory from 

upstream onshore oil and gas production sites for select counties in Texas. The inventory will 

address area source criteria pollutant emissions of volatile organic compounds (VOC), nitrogen 

oxides (NOX), carbon monoxide (CO), particulate matter with an aerodynamic diameter less than 

or equal to 10 microns (PM10), particulate matter with an aerodynamic diameter less than or equal 

to 2.5 microns (PM2.5), and sulfur dioxide (SO2); and certain toxic pollutant emissions such as 

formaldehyde from compressor engines, and benzene, toluene, ethylbenzene, and xylene from 

dehydrators. In addition to compiling the emissions inventory, other goals of this Work Order 

are to identify the emission source types operating at oil and gas production sites, identify the 

best emissions determination methodology for each emission source type, develop a 

methodology for estimating emissions from oil and gas production sites based on the oil and gas 

produced at the county level, and identify the producers of oil and gas for each county. 

This Work Order builds on two previous studies ERG conducted for TCEQ to estimate emissions 

from oil and gas exploration and production activities. The first, implemented in 2007, 

focused on compiling a state-wide emissions inventory (including both onshore and offshore 

sources) for oil and gas exploration and production for a 2005 base year (ERG, 2007). The 

second study, conducted in 2009 for a 2008 base year, focused only on emissions from onshore 

oil and gas well drilling rig engines (ERG, 2009). Both of these studies included emission 

estimates for every county in Texas. In contrast, this current study will only address onshore 

area sources (those not included in the Texas point source inventory), and does not address 

drilling rig engines. TCEQ is also currently developing an emissions inventory for offshore oil 

and gas platforms under TCEQ Work Order No. 582-07-84003-FY10-25. 

 
B-2 

The onshore area source project is divided into four primary technical work tasks: 

• Identification and review of existing studies pertaining to estimating emissions from oil 

and gas production sites and recommendation of an emission estimation approach for 

each identified source type; 

• Identification of oil and gas well operators and preparation of draft survey materials, 

including obtaining data from existing studies and databases; 

• Development of a methodology to estimate county-level emissions from each identified 

source type; and 

• Development of a 2008 base year emissions inventory, including collection of activity 

and emissions data (as available), the preparation of emissions inventory calculation 

spreadsheets (including activity data and emission factors) and documentation of data, 

procedures, and results in a final project report. The final emissions inventory will be 

compiled into National Emissions Inventory Input Format (NIF) 3.0 text files for import 

into Texas Air Emissions Repository (TexAER). 

The purpose of this memo is to document the methodology ERG will use to identify the owners 

and/or operators of oil and gas production sites, and to provide TCEQ with draft survey 

materials. Additionally, the methodology used to develop the draft survey materials are 

provided. In the project Work Plan, this work is referred to as Task 3. 

This discussion begins by presenting the references and datasets that were used to identify oil 

and gas production sites owners and operators in Section 2.0. Section 3.0 presents example draft 

survey forms, the process used to develop these, with the forms and instructions for each source 

type provided in Attachment B. 

County-level, area source emission estimates will be developed based on county-level oil and gas 

production data (total oil and gas produced in each county in 2008). 

2.0 Identification of Oil and Gas Owners and Operators

This task targets identification of Oil and Gas Area Source operators who were active in Texas in 

2008. A list of candidate owners and operators were obtained from multiple sources as follows: 

• Texas Railroad Commission (RRC) and RigData® - ERG obtained data from the RRC for 

all oil and gas wells drilled in Texas in 2008. This database contains over 18,500 records 

for wells where drilling occurred in 2008. In addition, ERG obtained the RigData®

database (a commercial database) in 2009 as part of the “Drilling Rig Emission Inventory 

for the State of Texas” project conducted for TCEQ. In addition to drilling contractor 

data, this database also contains owner and operator contact information (Company 

Name, Company Contact Name, and Company Contact Mailing Address) for over 24,000 

wells. The combined data for these 2 datasets is included in Attachment A as “Drilling 

Data 2008 Contact Directory.xls”. 

• TCEQ Permit Data – TCEQ provided contact information for approximately 9,000 

regulated entities registered with TCEQ pursuant to Standard Permit pursuant to 116.620 

(Installation and/or Modification of Oil and Gas Facilities). This database contains 
B-3 

owner and operator contact information (Company Name, Company Contact Name, 

Company Contact Mailing Address, Company Contact Title, and Company Contact Email address for some sources). It is assumed that many of these sources are not 

currently required to report their air emissions to TCEQ under TAC 101.10(a)(1-3). This 

data is included in Attachment A as “Standard Permit 116.620 Contact Directory.xls”. 

• Texas Railroad Commission (RRC) Oil & Gas Directory - Operator Contact Information 

– This data was obtained directly from the RRC and includes a listing of entities 

registered with the Commission's Oil and Gas Division by name, including address and 

telephone number. The listing includes all operators with Active status on Commission 

organization records, as well as those with "Delinquent" status (indicating that they still 

have activity, but have not updated their organizational registration). The listing does not 

include those with "Inactive" status (indicating no activity and no current registration). 

This data was obtained from 

(http://www.rrc.state.tx.us/data/operators/ogdirectory/index.php) on April 28, 2010 and is 

included in Attachment A as “TRC Oil and Gas Contact Directory.xls”. 

These databases were imported into MS Access for easy querying for duplicates and to QA 

addresses and contact information. The final datasets of contact information are included in 

Attachment A. 

3.0 Survey Forms

As TCEQ may wish to conduct a state-wide survey of oil and gas owners and operators in the 

future in order to refine the emissions inventory, survey forms were prepared for Artificial Lift 

Engines, Compressor Engines, Dehydrators, Equipment Leaks, Heaters, Loading Racks, 

Pneumatic Devices, Storage Tanks, Well Blowdowns, and Well Completions. These forms were 

structured such that the information needed to develop more highly-refined emissions estimates 

for each source category (at a county-level, using area source approaches) would be obtained. 

While obtaining the needed data, other goals in the development of these forms was to make 

them as straightforward as possible, to make them universally accessible (through the use of 

widely used software found in MS-Office), and to make them consistent with the format and 

nomenclature used in TCEQ’s current Barnett Shale study. TCEQ comments on the draft survey 

materials have been incorporated into the final survey materials provided herein. 

Attachment B presents final survey forms for Artificial Lift Engines, Compressor Engines, 

Dehydrators, Equipment Leaks, Heaters, Loading Racks, Pneumatic Devices, Storage Tanks, 

Well Blowdowns, and Well Completions. 
B-4 

ATTACHMENT A 

(See files “Standard Permit 116.620 Contact Directory.xls”, “TRC Oil and Gas Contact 

Directory.xls”, and “Drilling Data 2008 Contact Directory.xls”) 
B-5 

ATTACHMENT B 

Draft Survey Packages 

(See files “Artificial Lift Engine Survey.xls”, “Compressor Engine Survey.xls”, “Dehydrator 

Survey.xls”, “Equipment Leaks Survey.xls”, “Heater Survey.xls”, “Loading Rack Survey.xls”, 

“Pneumatic Device Survey.xls”, “Storage Tank Survey.xls”, “Well Blowdown Survey.xls”, and 

“Well Completion Survey.xls”) 
Appendix C - VOC and PM HAP Speciation Data 
C-1 

Appendix C. HAP Factors 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Pump Jack Natural Gas VOC 0.11259434 lb/MMBtu Pump Jack Natural Gas Acetaldehyde 2.79E-03 lb/MMBtu 2.48E+00 APump Jack Natural Gas Acrolein 2.63E-03 lb/MMBtu 2.34E+00 APump Jack Natural Gas Benzene 1.58E-03 lb/MMBtu 1.40E+00 APump Jack Natural Gas 1,3-Butadiene 6.63E-04 lb/MMBtu 5.89E-01 APump Jack Natural Gas Carbon Tetrachloride* 1.77E-05 lb/MMBtu 1.57E-02 APump Jack Natural Gas Chlorobenzene* 1.29E-05 lb/MMBtu 1.15E-02 APump Jack Natural Gas Chloroform* 1.37E-05 lb/MMBtu 1.22E-02 APump Jack Natural Gas Dichlorobenzene 1.20E-03 lb/MMBtu 1.07E+00 

AN

Pump Jack Natural Gas 1,3-Dichloropropene* 1.27E-05 lb/MMBtu 1.13E-02 APump Jack Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMBtu 1.42E-02 

AN

Pump Jack Natural Gas Ethylbenzene* 2.48E-05 lb/MMBtu 2.20E-02 APump Jack Natural Gas Ethylene Dibromide* 2.13E-05 lb/MMBtu 1.89E-02 APump Jack Natural Gas Formaldehyde 2.05E-02 lb/MMBtu 1.82E+01 APump Jack Natural Gas Methanol 3.06E-03 lb/MMBtu 2.72E+00 APump Jack Natural Gas Methylene Chloride 4.12E-05 lb/MMBtu 3.66E-02 APump Jack Natural Gas 2-Methylnaphthalene 2.40E-05 lb/MMBtu 2.13E-02 

AN

Pump Jack Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMBtu 1.60E-03 

AN

Pump Jack Natural Gas Naphthalene* 9.71E-05 lb/MMBtu 8.62E-02 APump Jack Natural Gas Propylene 0.016842105 lb/MMBtu 1.50E+01 

AEhf_

Pump Jack Natural Gas Styrene* 1.19E-05 lb/MMBtu 1.06E-02 APump Jack Natural Gas 1,1,2,2-Tetrachloroethane 2.53E-05 lb/MMBtu 2.25E-02 APump Jack Natural Gas Toluene 5.58E-04 lb/MMBtu 4.96E-01 APump Jack Natural Gas 1,1,2-Trichloroethane* 1.53E-05 lb/MMBtu 1.36E-02 APump Jack Natural Gas Vinyl Chloride* 7.18E-06 lb/MMBtu 6.38E-03 APump Jack Natural Gas Xylenes (isomers and mixture) 1.95E-04 lb/MMBtu 1.73E-01 APump Jack Natural Gas o-Xylenes 0.01 EPump Jack Natural Gas m-Xylenes 0.01 E
C-2 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Pump Jack Natural Gas PM 7.70E-04 lb/MMBtu Pump Jack Natural Gas Acenaphthene* 1.80E-06 lb/MMBtu 2.34E-01 

AN

Pump Jack Natural Gas Acenaphthylene* 1.80E-06 lb/MMBtu 2.34E-01 

AN

Pump Jack Natural Gas Anthracene* 2.40E-06 lb/MMBtu 3.12E-01 

AN

Pump Jack Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMBtu 2.34E-01

AN

Pump Jack Natural Gas Benzo(a)pyrene* 1.20E-06 lb/MMBtu 1.56E-01 

AN

Pump Jack Natural Gas Benzo(b)fluoranthene* 1.80E-06 lb/MMBtu 2.34E-01 

AN

Pump Jack Natural Gas Benzo(g,h,i)perylene* 1.20E-06 lb/MMBtu 1.56E-01 

AN

Pump Jack Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMBtu 2.34E-01 

AN

Pump Jack Natural Gas Chrysene* 1.80E-06 lb/MMBtu 2.34E-01 

AN

Pump Jack Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMBtu 1.56E-01 

AN

Pump Jack Natural Gas Fluoranthene 3.00E-06 lb/MMBtu 3.90E-01 

AN

Pump Jack Natural Gas Fluorene 2.80E-06 lb/MMBtu 3.64E-01 

AN

Pump Jack Natural Gas Indeno(1,2,3-cd_pyrene* 1.80E-06 lb/MMBtu 2.34E-01 

AN

Pump Jack Natural Gas Phenanathrene 1.75E-05 lb/MMBtu 2.27E+00 

AN

Pump Jack Natural Gas Pyrene 5.00E-06 lb/MMBtu 6.49E-01 

AN
C-3 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Total VOC 5.5 

lb/MMscf burned A

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Acetaldehyde 0.0089 

lb/MMscf burned 1.6127E-01 

AEhf_

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Benzene 0.0021 

lb/MMscf burned 3.8182E-02 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Dichlorobenzene 1.2000E-03 

lb/MMscf burned 2.1818E-02 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.6000E-05 

lb/MMscf burned 2.9091E-04 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Formaldehyde 0.0750 

lb/MMscf burned 1.3636E+00 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Hexane 1.8000E+00 

lb/MMscf burned 3.2727E+01 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas 2-Methylnaphthalene 2.4000E-05 

lb/MMscf burned 4.3636E-04 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas 3-Methylchloranthrene* 1.8000E-06 

lb/MMscf burned 3.2727E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Naphthalene 6.1000E-04 

lb/MMscf burned 1.1091E-02 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Toluene 3.4000E-03 

lb/MMscf burned 6.1818E-02 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Total PM 1.9 

lb/MMscf burned A

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Acenaphthene* 1.8000E-06 

lb/MMscf burned 9.4737E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Acenaphthylene* 1.8000E-06 

lb/MMscf burned 9.4737E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Anthracene* 2.4000E-06 

lb/MMscf burned 1.2632E-04 

AN
C-4 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Benz(a)anthracene* 1.8000E-06 

lb/MMscf burned 9.4737E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Benzo(a)pyrene* 1.2000E-06 

lb/MMscf burned 6.3158E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Benzo(b)fluoranthene* 1.8000E-06 

lb/MMscf burned 9.4737E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Benzo(g,h,i)perylene* 1.2000E-06 

lb/MMscf burned 6.3158E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Benzo(k)fluoranthene* 1.8000E-06 

lb/MMscf burned 9.4737E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Chrysene* 1.8000E-06 

lb/MMscf burned 9.4737E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Dibenzo(a,h)anthracene* 1.2000E-06 

lb/MMscf burned 6.3158E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Fluoranthene 3.0000E-06 

lb/MMscf burned 1.5789E-04 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Fluorene 2.8000E-06 

lb/MMscf burned 1.4737E-04 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Indeno(1,2,3-cd)pyrene* 1.8000E-06 

lb/MMscf burned 9.4737E-05 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Phenanathrene 1.7000E-05 

lb/MMscf burned 8.9474E-04 

AN

Boiler-Max MMBTU/hr<10-natural gas Natural Gas Pyrene 5.0000E-06 

lb/MMscf burned 2.6316E-04 

AN
C-5 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Natural Gas Engines 2 cycle rich Natural Gas VOC 5.152709841 lb/MMscf ANatural Gas Engines 2 cycle rich Natural Gas Acetaldehyde 2.79E-03 lb/MMscf 5.41E-02 ANatural Gas Engines 2 cycle rich Natural Gas Acrolein 2.63E-03 lb/MMscf 5.10E-02 ANatural Gas Engines 2 cycle rich Natural Gas Benzene 1.58E-03 lb/MMscf 3.07E-02 ANatural Gas Engines 2 cycle rich Natural Gas 1,3-Butadiene 6.63E-04 lb/MMBtu 1.29E-02 ANatural Gas Engines 2 cycle rich Natural Gas Carbon Tetrachloride* 1.77E-05 lb/MMBtu 3.44E-04 ANatural Gas Engines 2 cycle rich Natural Gas Chlorobenzene* 1.29E-05 lb/MMBtu 2.50E-04 ANatural Gas Engines 2 cycle rich Natural Gas Chloroform* 1.37E-05 lb/MMBtu 2.66E-04 ANatural Gas Engines 2 cycle rich Natural Gas Dichlorobenzene 1.20E-03 lb/MMscf 2.33E-02 

AN

Natural Gas Engines 2 cycle rich Natural Gas 1,3-Dichloropropene* 1.27E-05 lb/MMBtu 2.46E-04 ANatural Gas Engines 2 cycle rich Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMscf 3.11E-04 

AN

Natural Gas Engines 2 cycle rich Natural Gas Ethylbenzene* 2.48E-05 lb/MMscf 4.81E-04 ANatural Gas Engines 2 cycle rich Natural Gas Ethylene Dibromide* 2.13E-05 lb/MMscf 4.13E-04 ANatural Gas Engines 2 cycle rich Natural Gas Formaldehyde 2.05E-02 lb/MMscf 3.98E-01 ANatural Gas Engines 2 cycle rich Natural Gas Hexane 1.80E+00 lb/MMscf 3.49E+01 

AN

Natural Gas Engines 2 cycle rich Natural Gas Methanol 3.06E-03 lb/MMscf 5.94E-02 ANatural Gas Engines 2 cycle rich Natural Gas Methylene Chloride 4.12E-05 lb/MMscf 8.00E-04 ANatural Gas Engines 2 cycle rich Natural Gas 2-Methylnaphthalene 2.40E-05 lb/MMscf 4.66E-04 

AN

Natural Gas Engines 2 cycle rich Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMscf 3.49E-05 

AN

Natural Gas Engines 2 cycle rich Natural Gas Naphthalene* 9.71E-05 lb/MMBtu 1.88E-03 ANatural Gas Engines 2 cycle rich Natural Gas Propylene 0.016842105 lb/MMBtu 3.27E-01 

AEhf_

Natural Gas Engines 2 cycle rich Natural Gas Styrene* 1.19E-05 lb/MMBtu 2.31E-04 ANatural Gas Engines 2 cycle rich Natural Gas 1,1,2,2-Tetrachloroethane 2.53E-05 lb/MMBtu 4.91E-04 ANatural Gas Engines 2 cycle rich Natural Gas Toluene 5.58E-04 lb/MMBtu 1.08E-02 ANatural Gas Engines 2 cycle rich Natural Gas 1,1,2-Trichloroethane* 1.53E-05 lb/MMBtu 2.97E-04 ANatural Gas Engines 2 cycle rich Natural Gas Vinyl Chloride* 7.18E-06 lb/MMBtu 1.39E-04 ANatural Gas Engines 2 cycle rich Natural Gas Xylenes (isomers and mixture) 1.95E-04 lb/MMBtu 3.78E-03 A
C-6 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Natural Gas Engines 2 cycle rich Natural Gas o-Xylenes 0.01 ENatural Gas Engines 2 cycle rich Natural Gas m-Xylenes 0.01 ENatural Gas Engines 2 cycle rich Natural Gas PM 3.84E-02 lb/MMscf ANatural Gas Engines 2 cycle rich Natural Gas Acenaphthene* 1.80E-06 lb/MMscf 4.69E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Acenaphthylene* 1.80E-06 lb/MMscf 4.69E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Anthracene* 2.40E-06 lb/MMscf 6.25E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMscf 4.69E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Benzo(a)pyrene* 1.20E-06 lb/MMscf 3.13E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Benzo(b)fluoranthene* 1.80E-06 lb/MMscf 4.69E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Benzo(g,h,i)perylene* 1.20E-06 lb/MMscf 3.13E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMscf 4.69E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Chrysene* 1.80E-06 lb/MMscf 4.69E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMscf 3.13E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Fluoranthene 3.00E-06 lb/MMscf 7.81E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Fluorene 2.80E-06 lb/MMscf 7.29E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Indeno(1,2,3-cd_pyrene* 1.80E-06 lb/MMscf 4.69E-03 

AN

Natural Gas Engines 2 cycle rich Natural Gas Phenanathrene 1.75E-05 lb/MMscf 4.56E-02 

AN

Natural Gas Engines 2 cycle rich Natural Gas Pyrene 5.00E-06 lb/MMscf 1.30E-02 

AN
C-7 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Natural Gas Engine 4 cycle lean Natural Gas VOC 0.12 lb/MMBtu ANatural Gas Engine 4 cycle lean Natural Gas Acetaldehyde 8.36E-03 lb/MMBtu 6.97E+00 ANatural Gas Engine 4 cycle lean Natural Gas Acrolein 5.14E-03 lb/MMBtu 4.28E+00 ANatural Gas Engine 4 cycle lean Natural Gas Benzene 4.40E-04 lb/MMBtu 3.67E-01 ANatural Gas Engine 4 cycle lean Natural Gas Biphenyl 2.12E-04 lb/MMBtu 1.77E-01 ANatural Gas Engine 4 cycle lean Natural Gas 1,3-Butadiene 2.67E-04 lb/MMBtu 2.23E-01 ANatural Gas Engine 4 cycle lean Natural Gas Carbon Tetrachloride* 3.67E-05 lb/MMBtu 3.06E-02 ANatural Gas Engine 4 cycle lean Natural Gas Chlorobenzene* 3.04E-05 lb/MMBtu 2.53E-02 ANatural Gas Engine 4 cycle lean Natural Gas Chloroform* 2.85E-05 lb/MMBtu 2.38E-02 ANatural Gas Engine 4 cycle lean Natural Gas Dichlorobenzene 1.20E-03 lb/MMBtu 1.00E+00 

AN

Natural Gas Engine 4 cycle lean Natural Gas 1,3-Dichloropropene* 2.64E-05 lb/MMBtu 2.20E-02 ANatural Gas Engine 4 cycle lean Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMBtu 1.33E-02 

AN

Natural Gas Engine 4 cycle lean Natural Gas Ethylbenzene 3.97E-05 lb/MMBtu 3.31E-02 ANatural Gas Engine 4 cycle lean Natural Gas Ethylene Dibromide* 4.43E-05 lb/MMBtu 3.69E-02 ANatural Gas Engine 4 cycle lean Natural Gas Formaldehyde 5.28E-02 lb/MMBtu 4.40E+01 ANatural Gas Engine 4 cycle lean Natural Gas Methanol 2.50E-03 lb/MMBtu 2.08E+00 ANatural Gas Engine 4 cycle lean Natural Gas 2-Methylnaphthalene 3.32E-05 lb/MMBtu 2.77E-02 ANatural Gas Engine 4 cycle lean Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMBtu 1.50E-03 

AN

Natural Gas Engine 4 cycle lean Natural Gas Methylene Chloride 2.00E-05 lb/MMBtu 1.67E-02 ANatural Gas Engine 4 cycle lean Natural Gas n-Hexane 1.11E-03 lb/MMBtu 9.25E-01 ANatural Gas Engine 4 cycle lean Natural Gas Naphthalene 7.44E-05 lb/MMBtu 6.20E-02 ANatural Gas Engine 4 cycle lean Natural Gas Phenol 2.40E-05 lb/MMBtu 2.00E-02 ANatural Gas Engine 4 cycle lean Natural Gas Propylene 0.012673684 lb/MMBtu 1.06E+01 

AEhf_

Natural Gas Engine 4 cycle lean Natural Gas Styrene* 2.36E-05 lb/MMBtu 1.97E-02 ANatural Gas Engine 4 cycle lean Natural Gas Tetrachloroethane 2.48E-06 lb/MMBtu 2.07E-03 ANatural Gas Engine 4 cycle lean Natural Gas 1,1,2,2-Tetrachloroethane* 4.00E-05 lb/MMBtu 3.33E-02 ANatural Gas Engine 4 cycle lean Natural Gas Toluene 4.08E-04 lb/MMBtu 3.40E-01 ANatural Gas Engine 4 cycle lean Natural Gas 1,1,2-Trichloroethane* 3.18E-05 lb/MMBtu 2.65E-02 A
C-8 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Natural Gas Engine 4 cycle lean Natural Gas 2,2,4-Trimethylpentane 2.50E-04 lb/MMBtu 2.08E-01 ANatural Gas Engine 4 cycle lean Natural Gas Vinyl Chloride 1.49E-05 lb/MMBtu 1.24E-02 ANatural Gas Engine 4 cycle lean Natural Gas Xylene 1.84E-04 lb/MMBtu 1.53E-01 ANatural Gas Engine 4 cycle lean Natural Gas o-Xylenes 0.01 ENatural Gas Engine 4 cycle lean Natural Gas m,p-Xylenes 0.01 ENatural Gas Engine 4 cycle lean Natural Gas PM 7.71E-04 lb/MMBtu ANatural Gas Engine 4 cycle lean Natural Gas Acenaphthene 1.25E-06 lb/MMBtu 1.62E-01 ANatural Gas Engine 4 cycle lean Natural Gas Acenaphthylene 5.53E-06 lb/MMBtu 7.17E-01 ANatural Gas Engine 4 cycle lean Natural Gas Anthracene* 2.40E-06 lb/MMBtu 3.11E-01 

AN

Natural Gas Engine 4 cycle lean Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMBtu 2.33E-01 

AN

Natural Gas Engine 4 cycle lean Natural Gas Benzo(b)fluoranthene 1.66E-07 lb/MMBtu 2.15E-02 ANatural Gas Engine 4 cycle lean Natural Gas Benzo(e)pyrene 4.15E-07 lb/MMBtu 5.38E-02 ANatural Gas Engine 4 cycle lean Natural Gas Benzo(g,h,i)perylene 4.14E-07 lb/MMBtu 5.37E-02 ANatural Gas Engine 4 cycle lean Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMBtu 2.33E-01 

AN

Natural Gas Engine 4 cycle lean Natural Gas Chrysene 6.93E-07 lb/MMBtu 8.99E-02 ANatural Gas Engine 4 cycle lean Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMBtu 1.56E-01 

AN

Natural Gas Engine 4 cycle lean Natural Gas Fluoranthene 1.11E-06 lb/MMBtu 1.44E-01 ANatural Gas Engine 4 cycle lean Natural Gas Fluorene 5.67E-06 lb/MMBtu 7.35E-01 ANatural Gas Engine 4 cycle lean Natural Gas Indeno(1,2,3-cd)pyrene* 1.80E-06 lb/MMBtu 2.33E-01 

AN

Natural Gas Engine 4 cycle lean Natural Gas Phenanthrene 1.04E-05 lb/MMBtu 1.35E+00 ANatural Gas Engine 4 cycle lean Natural Gas Pyrene 1.36E-06 lb/MMBtu 1.76E-01 ANatural Gas Engines 4 cycle rich Natural Gas VOC 0.03 lb/MMBtu Natural Gas Engines 4 cycle rich Natural Gas Acetaldehyde 2.79E-03 lb/MMBtu 9.30E+00 ANatural Gas Engines 4 cycle rich Natural Gas Acrolein 2.63E-03 lb/MMBtu 8.77E+00 ANatural Gas Engines 4 cycle rich Natural Gas Benzene 1.58E-03 lb/MMBtu 5.27E+00 ANatural Gas Engines 4 cycle rich Natural Gas 1,3-Butadiene 6.63E-04 lb/MMBtu 2.21E+00 ANatural Gas Engines 4 cycle rich Natural Gas Carbon Tetrachloride* 1.77E-05 lb/MMBtu 5.90E-02 A
C-9 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Natural Gas Engines 4 cycle rich Natural Gas Chlorobenzene* 1.29E-05 lb/MMBtu 4.30E-02 ANatural Gas Engines 4 cycle rich Natural Gas Chloroform* 1.37E-05 lb/MMBtu 4.57E-02 ANatural Gas Engines 4 cycle rich Natural Gas 1,3-Dichloropropene* 1.27E-05 lb/MMBtu 4.23E-02 ANatural Gas Engines 4 cycle rich Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMBtu 5.33E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Ethylbenzene* 2.48E-05 lb/MMBtu 8.27E-02 ANatural Gas Engines 4 cycle rich Natural Gas Ethylene Dibromide* 2.13E-05 lb/MMBtu 7.10E-02 ANatural Gas Engines 4 cycle rich Natural Gas Formaldehyde 2.05E-02 lb/MMBtu 6.83E+01 ANatural Gas Engines 4 cycle rich Natural Gas Methylene Chloride 4.12E-05 lb/MMBtu 1.37E-01 ANatural Gas Engines 4 cycle rich Natural Gas 2-Methylnaphthalene 2.40E-05 lb/MMBtu 8.00E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMBtu 6.00E-03 

AN

Natural Gas Engines 4 cycle rich Natural Gas Naphthalene* 9.71E-05 lb/MMBtu 3.24E-01 ANatural Gas Engines 4 cycle rich Natural Gas Styrene* 1.19E-05 lb/MMBtu 3.97E-02 ANatural Gas Engines 4 cycle rich Natural Gas 1,1,2,2-Tetrachloroethane 2.53E-05 lb/MMBtu 8.43E-02 ANatural Gas Engines 4 cycle rich Natural Gas Toluene 5.58E-04 lb/MMBtu 1.86E+00 ANatural Gas Engines 4 cycle rich Natural Gas 1,1,2-Trichloroethane* 1.53E-05 lb/MMBtu 5.10E-02 ANatural Gas Engines 4 cycle rich Natural Gas Vinyl Chloride* 7.18E-06 lb/MMBtu 2.39E-02 ANatural Gas Engines 4 cycle rich Natural Gas Xylenes (isomers and mixture) 1.95E-04 lb/MMBtu 6.50E-01 ANatural Gas Engines 4 cycle rich Natural Gas o-Xylenes 0.01 ENatural Gas Engines 4 cycle rich Natural Gas m-Xylenes 0.01 ENatural Gas Engines 4 cycle rich Natural Gas PM 9.50E-03 lb/MMBtu Natural Gas Engines 4 cycle rich Natural Gas Acenaphthene* 1.80E-06 lb/MMBtu 1.89E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Acenaphthylene* 1.80E-06 lb/MMBtu 1.89E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Anthracene* 2.40E-06 lb/MMBtu 2.53E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMBtu 1.89E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Benzo(a)pyrene* 1.20E-06 lb/MMBtu 1.26E-02 

AN
C-10 

Appendix C. HAP Factors (Cont.) 

Source Category Fuel Type Pollutant Emission Factors 

Emission 

Factor Unit % HAP 

Natural Gas Engines 4 cycle rich Natural Gas Benzo(b)fluoranthene* 1.80E-06 lb/MMBtu 1.89E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Benzo(g,h,i)perylene* 1.20E-06 lb/MMBtu 1.26E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMBtu 1.89E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Chrysene* 1.80E-06 lb/MMBtu 1.89E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMBtu 1.26E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Fluoranthene 3.00E-06 lb/MMBtu 3.16E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Fluorene 2.80E-06 lb/MMBtu 2.95E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Indeno(1,2,3-cd_pyrene* 1.80E-06 lb/MMBtu 1.89E-02 

AN

Natural Gas Engines 4 cycle rich Natural Gas Phenanathrene 1.75E-05 lb/MMBtu 1.84E-01 

AN

Natural Gas Engines 4 cycle rich Natural Gas Pyrene 5.00E-06 lb/MMBtu 5.26E-02 

AN
Appendix D – Compressor Engine Workbook 
Appendix E – Texas Oil and Gas Emissions Inventory 
Appendix F – Formatted TexAer Files