ATTACHMENT B

CHARACTERIZATION OF OIL AND GAS PRODUCTI ON EQUIPMENT
AND DEVELOP A METHOD OLOGY TO ESTIMATE ST ATEWIDE

EMISSIONSERG 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 D evelop 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, 2010i TABLE OF CONTENTS

Section Page No.

EXECUTIVE SUMMARY ..................................

................................................... ...................iv

1.0 INTRODUCTION ....................................

................................................... ............... 1-1

2.0 AVAILABLE EMISSIONS ESTIMATION METHODOLOGY REVIE W................. 2-1

3.0 IDENTIFICATION OF OIL AND GAS OWNERS/OPERATORS A ND 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 Filesii LIST OF TABLES

Tables Page No.

Table E-1. State-wide Emissions Inventory for 2008 by Source C ategory................................. 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 C ategory................................ 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 Are as................................................. . 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 T exas ........................................... 4-22

Table 4-13. Emission Factors for NO

x and CO Emissions from Dehydrator Regenerator Boilers

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

Table 4-14. Emission Factors for NO

x and CO Emissions from Dehydrator Controls (Flares) 4-26 Table 4-15. Emission Factors for VOC, Benzene, Toluene, Et hylbenzene, and Xylene from Oil Storage Tanks and Condensate Storage Tanks in Texas........ ................................................. 4-29 Table 4-16. Molecular Weight and True Vapor Pressure of Se lected Petroleum Liquids........ 4-32 Table 4-17. Emission Factors for Benzene, Toluene, Ethylbenz ene, and Xylene from Oil and Condensate Loading in Texas...........................

................................................... .................. 4-34 Table 4-18. 2008 CENRAP Data for Volume of Gas Vented per Co mpletion........................ 4-36 Table 4-19. 2008 CENRAP Data for Volume of Gas Vented per Bl owdown 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 H eaters..................................... 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 C ategory................................ 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 Cat egory .................................. 5-14iii 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

NO

x Nitrogen Oxides NSCR Non selective catalytic reduction

NSPS New Source Performance Standard

PM 2.5 particulate matter with an aerodynamic diameter less than or equal to 2.5 microns

PM 10 particulate matter with an aerodynamic diameter less t han or equal to 10 microns RVP Reid Vapor Pressure

SCC Source Classification Code

scf Standard cubic feet SIP State Implementation Plan

SO 2 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 Compoundiv



### EXECUTIVE SUMMARY

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

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

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

to develop a 2008 base year air emissions inventory from the se 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 equipmen t could include storage tanks,

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

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

significant. In particular, due to recent advancements i n 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. Ther efore, 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, emi ssions sensitivity analyses, State

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

The emissions inventory developed under this project address es area source criteria

pollutant emissions of volatile organic compounds (VOC), nitrogen oxides (NO

x ), carbon

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

(PM 10 ), particulate matter with an aerodynamic diameter less than or equal to 2.5 microns

(PM 2.5 ), and sulfur dioxide (SO 2 ); 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 HA Ps from combustion sources.

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

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

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

offshore sources) for oil and gas exploration and produc tion 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). T he third study, which was justv

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

In contrast, this current study addresses onshore area so urces (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 ga s production sites, to develop a

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

oil and gas produced at the county level, to develop survey ma terials 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 emi ssions inventory for future years by

providing updated county-level activity data. Finally, the e missions 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-l evel 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 repor ts submitted to TCEQ (for

dehydrators), vendor data (for compression engines and pumpj ack engines), and published

emission factor and activity data from the Houston Adv anced 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 pol lutant (and total HAP) emissions

by source category, and Table E-2 presents a summary of c riteria 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 si gnificant with over 200,000 tons of NO

x , 1,500,000 tons of VOC, and 30,000 tons of HAPs emitted in 2008. The main source of NO

xvi

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

condensate storage tanks.

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

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

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

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

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

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

typical well pad), and updated equipment characteristics and counts.viiTable E-1. State-wide Emissions Inventory for 2008 by Source CategorySCCSource Category DescriptionCO(tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)TotalHAP(tons/yr)2310000330Artificial Lift 23,169.1446,369.72 154.04 154.04 9.56 440.12140.492310011020Storage Tanks: Crude Oil282,420.055,060.012310011100Heater Treater 9,267.2511,032.44 838.47 838.47 21.32 606.78208.672310011201Tank Truck/Railcar Loading:Crude Oil26,810.72479.912310011450Wellhead116,245.652310011501Fugitives: Connectors2,956.392310011502Fugitives: Flanges135.462310011503Fugitives: Open Ended Lines605.722310011504Fugitives: Pumps4,326.592310011505Fugitives: Valves7,821.142310011506Fugitives: Other12,480.552310020600Compressor Engines 133.77464.56 13.58 13.58 0.21 81.4029.002310021010Storage Tanks: Condensate864,087.9017,281.712310021030Tank Truck/Railcar LoadingCondensate7,235.50144.712310021100Gas Well Heaters 7,564.839,005.75 684.44 684.44 0.04 495.32170.342310021101Natural Gas Fired 2-Cycle LeanBurn Compressor Engines <50 Hp140.52209.25 9.72 9.72 0.16 43.3815.462310021102Natural Gas Fired 2-Cycle LeanBurn Compressor Engines 50 To499 Hp 2,907.9313,776.30 352.37 352.37 5.71 2,012.02716.782310021203Natural Gas Fired 4-Cycle LeanBurn Compressor Engines 500+Hp14,746.4127,288.73 76.95 76.95 15.94 3,817.422,337.582310021301Natural Gas Fired 4-Cycle RichBurn Compressor Engines <50 Hp 93.371,175.69 3.86 3.86 0.25 5.615.50viiiTable E-1. State-wide Emissions Inventory for 2008 by Source Category (Cont.)SCCSource Category DescriptionCO(tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)TotalHAP(tons/yr)2310021302Natural Gas Fired 4-Cycle RichBurn Compressor Engines 50 To499hp 38,988.6986,462.54 226.24 226.24 14.83 1,487.261,451.932310021400Gas Well Dehydrators 904.59293.366,344.855,255.172310021402Natural Gas Fired 4-Cycle RichBurn Compressor Engines 50-499hp W/ Nscr 767.553,321.00 35.02 35.02 2.05 17.7317.462310021403Natural Gas Fired 4-Cycle RichBurn Compressor Engines 500+Hp W/ Nscr 29,646.8047,837.57 175.33 175.33 11.26 794.33775.732310021501Fugitives: Connectors1,161.522310021502Fugitives: Flanges1,199.682310021503Fugitives: Open Ended Lines916.822310021504Fugitives: Pumps476.312310021505Fugitives: Valves7,387.522310021506Fugitives: Other8,732.372310021600Gas Well Venting8,601.782310121700Gas Well Completion: AllProcesses10,139.562310111700Oil Well Completion: AllProcesses19,425.442310121401Gas Well Pneumatic Pumps169,209.86Total:128,330.85247,236.91 2,570.01 2,570.01 81.34 1,568,522.7334,090.45ixTable E-2. State-wide Emissions Inventory for 2008 by CountyCountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Anderson 241.28444.72 5.31 5.31 0.16 2,858.24 52.77Andrews 1,825.993,291.18 49.14 49.14 1.57 31,691.46 444.20Angelina 161.97311.11 2.15 2.15 0.08 629.30 25.94Aransas 165.25317.00 2.28 2.28 0.09 6,574.04 144.42Archer 614.911,088.88 18.74 18.74 0.58 2,719.03 24.45Armstrong 0.000.00 0.00 0.00 0.00 0.00 0.00Atascosa 321.56578.81 8.71 8.71 0.27 2,237.28 31.44Austin 127.18237.83 2.42 2.42 0.07 2,040.58 43.74Bailey 0.000.00 0.00 0.00 0.00 0.00 0.00Bandera 0.210.37 0.01 0.01 0.00 5.14 0.03Bastrop 74.21128.49 2.56 2.56 0.06 1,286.18 16.32Baylor 26.7847.39 0.82 0.82 0.03 189.33 1.96Bee 581.151,101.85 9.42 9.42 0.31 4,717.44 125.89Bell 0.000.00 0.00 0.00 0.00 0.00 0.00Bexar 531.99941.46 16.28 16.28 0.51 2,120.86 7.60Blanco 0.000.00 0.00 0.00 0.00 0.00 0.00Borden 166.31300.48 4.40 4.40 0.14 4,107.39 62.92Bosque 3.456.30 0.08 0.08 0.00 17.43 0.34Bowie 5.139.25 0.14 0.14 0.00 148.70 2.69Brazoria 207.73199.95 6.59 6.59 0.28 14,003.43 292.15Brazos 240.26444.10 5.18 5.18 0.16 3,781.19 74.41Brewster 0.000.00 0.00 0.00 0.00 5.88 0.00Briscoe 0.000.00 0.00 0.00 0.00 12.33 0.01Brooks 690.711,318.85 10.17 10.17 0.35 16,242.00 374.16Brown 204.73339.96 8.55 8.55 0.14 1,626.85 6.71Burleson 366.21669.08 8.80 8.80 0.28 3,881.39 67.20Burnet 0.000.00 0.00 0.00 0.00 0.00 0.00xTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Caldwell 676.241,197.43 20.61 20.61 0.64 3,452.64 22.69Calhoun 189.99360.25 3.07 3.07 0.10 7,473.42 160.35Callahan 182.61321.30 5.76 5.76 0.16 983.48 9.65Cameron 1.683.12 0.03 0.03 0.00 10.26 0.20Camp 30.4155.01 0.79 0.79 0.03 259.21 4.96Carson 569.731,021.51 15.74 15.74 0.41 1,954.76 34.12Cass 54.9598.13 1.55 1.55 0.04 662.46 11.89Castro 0.000.00 0.00 0.00 0.00 0.00 0.00Chambers 84.7694.63 2.75 2.75 0.11 4,424.08 90.13Cherokee 364.58682.18 6.78 6.78 0.18 2,911.32 72.93Childress 1.692.99 0.05 0.05 0.00 57.40 0.71Clay 231.82409.65 7.14 7.14 0.21 1,476.89 16.60Cochran 445.16791.68 13.17 13.17 0.41 6,168.35 67.45Coke 109.55200.99 2.54 2.54 0.08 1,010.20 15.88Coleman 173.73295.58 6.51 6.51 0.13 1,363.81 9.92Collin 0.000.00 0.00 0.00 0.00 0.00 0.00Collingsworth 50.0476.34 2.77 2.77 0.02 742.63 2.58Colorado 319.38601.84 5.54 5.54 0.16 4,980.62 115.78Comal 0.000.00 0.00 0.00 0.00 0.00 0.00Comanche 34.2253.57 1.76 1.76 0.02 438.42 1.97Concho 72.58128.12 2.23 2.23 0.06 821.04 9.65Cooke 495.43884.64 14.25 14.25 0.45 3,467.02 50.26Coryell 0.000.00 0.00 0.00 0.00 3.13 0.00Cottle 95.67180.55 1.63 1.63 0.05 2,376.44 52.30Crane 1,739.983,208.47 38.61 38.61 1.26 17,274.91 291.73Crockett 2,274.884,015.15 68.61 68.61 1.15 28,501.91 414.45Crosby 85.55151.51 2.61 2.61 0.08 1,056.14 9.67xiTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Culberson 72.79137.98 1.20 1.20 0.04 284.44 8.75Dallam 0.000.00 0.00 0.00 0.00 0.00 0.00Dallas 28.0480.04 0.21 0.21 0.02 24.60 4.23Dawson 275.48492.78 7.84 7.84 0.25 5,344.51 72.02Deaf Smith 0.000.00 0.00 0.00 0.00 0.00 0.00Delta 0.000.00 0.00 0.00 0.00 0.00 0.00Denton 1,763.524,690.36 29.51 29.51 1.14 13,254.59 416.58Dewitt 676.491,300.83 9.00 9.00 0.35 11,617.04 287.72Dickens 49.7088.22 1.49 1.49 0.05 1,446.43 20.78Dimmit 197.89353.20 5.65 5.65 0.15 2,515.16 31.86Donley 0.530.77 0.03 0.03 0.00 15.82 0.17Duval 1,111.172,101.02 18.70 18.70 0.63 12,897.27 314.00Eastland 285.26476.94 11.51 11.51 0.18 3,654.84 39.72Ector 1,798.243,277.22 44.40 44.40 1.47 26,211.12 388.97Edwards 270.78492.35 6.60 6.60 0.13 1,377.01 25.49El Paso 0.000.00 0.00 0.00 0.00 0.00 0.00Ellis 51.17144.09 0.47 0.47 0.04 52.43 7.56Erath 161.14295.43 3.68 3.68 0.07 1,556.95 32.84Falls 4.017.09 0.12 0.12 0.00 21.49 0.09Fannin 0.000.00 0.00 0.00 0.00 11.86 0.00Fayette 356.62659.40 7.64 7.64 0.23 5,607.61 115.67Fisher 107.82193.50 2.99 2.99 0.09 1,365.54 16.44Floyd 0.420.75 0.01 0.01 0.00 2.97 0.03Foard 27.9443.90 1.42 1.42 0.01 414.38 2.57Fort Bend 169.68171.80 5.51 5.51 0.22 8,072.59 166.58Franklin 69.40127.99 1.52 1.52 0.05 1,389.52 28.31Freestone 3,821.607,289.51 56.95 56.95 1.93 9,858.72 475.09xiiTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Frio 139.12246.28 4.21 4.21 0.12 1,393.74 14.40Gaines 1,165.522,133.47 27.65 27.65 0.92 27,788.32 460.84Galveston 86.4676.28 2.61 2.61 0.12 17,475.45 358.12Garza 445.72790.41 13.45 13.45 0.42 6,133.80 63.01Gillespie 0.000.00 0.00 0.00 0.00 0.00 0.00Glasscock 416.67761.54 10.00 10.00 0.32 5,431.20 84.49Goliad 731.211,386.08 11.85 11.85 0.37 7,851.72 199.63Gonzales 51.4092.76 1.37 1.37 0.04 578.12 8.62Gray 825.551,440.69 27.11 27.11 0.64 4,163.88 45.84Grayson 201.98365.62 5.22 5.22 0.16 1,707.03 31.65Gregg 1,423.902,592.32 34.92 34.92 1.00 10,980.44 227.68Grimes 334.10638.29 4.87 4.87 0.17 1,264.12 50.60Guadalupe 402.11711.73 12.29 12.29 0.38 2,576.45 22.66Hale 62.99114.67 1.57 1.57 0.05 2,698.37 46.20Hall 0.000.00 0.00 0.00 0.00 0.00 0.00Hamilton 3.125.33 0.11 0.11 0.00 36.47 0.47Hansford 377.68676.20 10.32 10.32 0.17 2,601.06 43.25Hardeman 52.1392.68 1.54 1.54 0.05 1,230.36 19.89Hardin 258.68348.83 7.85 7.85 0.30 22,648.65 447.94Harris 176.00181.67 5.65 5.65 0.23 8,801.29 184.44Harrison 1,879.593,514.48 35.19 35.19 0.93 25,383.90 583.58Hartley 39.0670.27 1.04 1.04 0.02 399.51 6.56Haskell 53.8395.30 1.64 1.64 0.05 443.81 5.44Hays 0.000.00 0.00 0.00 0.00 0.00 0.00Hemphill 2,092.633,936.72 37.08 37.08 1.03 32,774.76 754.74Henderson 453.75854.13 7.99 7.99 0.24 2,535.12 73.92Hidalgo 3,264.696,276.64 43.49 43.49 1.68 56,554.95 1,407.72xiiiTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Hill 308.20597.97 3.53 3.53 0.16 233.61 34.41Hockley 1,004.101,795.93 28.58 28.58 0.91 22,011.88 308.12Hood 926.801,777.59 12.89 12.89 0.47 9,914.41 269.97Hopkins 20.8437.79 0.53 0.53 0.02 298.78 5.06Houston 164.62308.00 3.11 3.11 0.10 1,587.91 35.84Howard 803.871,436.74 23.00 23.00 0.73 9,904.95 107.63Hudspeth 0.120.17 0.01 0.01 0.00 3.29 0.03Hunt 0.000.00 0.00 0.00 0.00 0.00 0.00Hutchinson 903.431,601.32 27.09 27.09 0.72 4,039.66 49.29Irion 531.51961.89 13.77 13.77 0.40 5,877.27 82.51Jack 646.651,121.02 21.80 21.80 0.42 6,701.91 92.20Jackson 303.15569.09 5.55 5.55 0.17 9,879.64 204.59Jasper 205.58394.00 2.87 2.87 0.11 6,405.78 143.58Jeff Davis 0.000.00 0.00 0.00 0.00 1.29 0.03Jefferson 287.19182.64 8.05 8.05 0.46 55,659.21 1,163.27Jim Hogg 266.50500.41 4.83 4.83 0.14 4,021.10 92.33Jim Wells 127.37226.90 3.61 3.61 0.06 1,576.61 26.20Johnson 4,495.4812,647.53 43.01 43.01 3.19 5,209.18 684.81Jones 167.32296.69 5.05 5.05 0.16 1,277.91 14.79Karnes 171.32323.25 2.95 2.95 0.10 3,454.12 76.12Kaufman 4.508.03 0.14 0.14 0.00 62.82 1.05Kendall 0.000.00 0.00 0.00 0.00 0.00 0.00Kenedy 665.441,286.34 8.13 8.13 0.35 4,087.71 143.43Kent 203.51375.70 4.48 4.48 0.16 4,304.19 73.92Kerr 0.000.00 0.00 0.00 0.00 0.00 0.00Kimble 2.944.50 0.16 0.16 0.00 41.29 0.17King 112.59198.82 3.47 3.47 0.10 2,010.47 35.20xivTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Kinney 0.000.00 0.00 0.00 0.00 0.00 0.00Kleberg 494.21948.96 6.71 6.71 0.25 8,845.84 217.77Knox 46.1881.72 1.41 1.41 0.04 354.81 4.00La Salle 259.22470.95 6.38 6.38 0.13 4,078.69 76.37Lamar 0.000.00 0.00 0.00 0.00 0.00 0.00Lamb 15.1027.13 0.42 0.42 0.01 686.85 11.01Lampasas 0.160.20 0.01 0.01 0.00 4.24 0.00Lavaca 924.671,764.89 13.68 13.68 0.47 12,277.67 311.64Lee 307.30564.26 7.08 7.08 0.23 2,650.76 49.84Leon 1,079.722,070.29 15.01 15.01 0.58 5,733.49 197.49Liberty 331.40341.24 9.92 9.92 0.45 27,316.75 570.30Limestone 1,393.872,655.14 21.17 21.17 0.71 4,377.56 180.91Lipscomb 1,125.342,104.13 21.36 21.36 0.58 17,104.94 381.52Live Oak 378.16709.70 6.91 6.91 0.20 6,807.99 149.58Llano 0.000.00 0.00 0.00 0.00 0.00 0.00Loving 1,567.713,023.10 20.15 20.15 0.89 6,348.57 251.69Lubbock 89.19158.04 2.71 2.71 0.08 1,825.32 23.15Lynn 18.5233.00 0.54 0.54 0.02 350.40 4.52Madison 117.26216.26 2.56 2.56 0.07 1,290.52 26.07Marion 96.78174.38 2.56 2.56 0.06 1,407.02 25.69Martin 596.731,088.02 14.69 14.69 0.49 10,928.66 168.72Mason 0.000.00 0.00 0.00 0.00 0.00 0.00Matagorda 609.791,168.96 8.47 8.47 0.32 19,098.24 428.64Maverick 182.47323.89 5.42 5.42 0.15 3,715.58 42.08McCulloch 14.6525.47 0.50 0.50 0.01 109.65 1.15McLennan 8.6515.30 0.26 0.26 0.01 27.43 0.12McMullen 493.90900.42 11.92 11.92 0.29 6,027.42 110.63xvTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Medina 275.72487.25 8.50 8.50 0.26 1,235.77 4.54Menard 27.0047.52 0.85 0.85 0.02 266.84 2.69Midland 1,610.042,951.97 37.75 37.75 1.27 20,938.23 333.93Milam 218.91387.83 6.65 6.65 0.21 1,216.87 9.32Mills 0.360.51 0.02 0.02 0.00 6.38 0.02Mitchell 502.49890.13 15.28 15.28 0.48 6,645.63 65.00Montague 551.48987.06 15.59 15.59 0.49 3,448.92 48.39Montgomery 73.5681.80 2.86 2.86 0.08 2,890.56 54.67Moore 744.021,343.19 19.29 19.29 0.40 3,502.87 63.64Morris 0.210.37 0.01 0.01 0.00 2.01 0.03Motley 3.806.72 0.12 0.12 0.00 52.75 0.49Nacogdoches 1,527.762,897.04 24.29 24.29 0.77 12,723.39 353.60Navarro 170.24301.61 5.16 5.16 0.16 1,444.51 18.73Newton 78.50145.69 1.63 1.63 0.05 1,601.94 31.72Nolan 133.50240.21 3.63 3.63 0.11 1,931.63 25.88Nueces 605.471,127.23 11.99 11.99 0.31 15,740.17 332.51Ochiltree 561.881,020.35 13.94 13.94 0.31 5,760.68 108.67Oldham 5.6810.02 0.17 0.17 0.00 247.24 3.74Orange 67.7971.25 2.06 2.06 0.09 8,467.82 172.90Palo Pinto 455.72785.82 15.70 15.70 0.21 7,033.45 105.26Panola 3,784.217,052.88 73.18 73.18 1.82 50,362.96 1,170.88Parker 1,225.523,294.01 19.49 19.49 0.80 9,840.76 290.06Parmer 0.000.00 0.00 0.00 0.00 0.00 0.00Pecos 4,534.568,670.50 66.30 66.30 2.63 21,760.89 703.44Polk 415.68797.76 5.69 5.69 0.22 29,650.93 625.12Potter 350.79632.33 9.25 9.25 0.21 1,799.21 27.27Presidio 0.000.00 0.00 0.00 0.00 0.00 0.00xviTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Rains 59.61115.43 0.71 0.71 0.03 38.47 6.62Randall 0.000.00 0.00 0.00 0.00 0.00 0.00Reagan 1,209.822,204.56 29.89 29.89 0.99 11,808.61 158.58Real 1.913.34 0.06 0.06 0.00 16.74 0.15Red River 9.5716.96 0.29 0.29 0.01 159.73 2.26Reeves 575.501,077.94 10.88 10.88 0.36 3,146.28 72.34Refugio 652.551,218.19 12.72 12.72 0.40 9,671.07 197.77Roberts 881.181,659.43 15.47 15.47 0.45 15,296.54 346.65Robertson 3,591.036,960.37 41.87 41.87 1.90 4,202.14 427.68Rockwall 0.000.00 0.00 0.00 0.00 0.00 0.00Runnels 145.66262.06 3.96 3.96 0.12 1,177.54 15.82Rusk 2,394.044,447.78 48.27 48.27 1.34 26,428.99 597.16Sabine 2.043.67 0.06 0.06 0.00 19.20 0.14San Augustine 159.66309.99 1.77 1.77 0.09 452.69 23.22San Jacinto 182.43350.28 2.47 2.47 0.09 6,462.64 144.35San Patricio 303.08570.53 5.36 5.36 0.16 12,721.07 267.75San Saba 0.000.00 0.00 0.00 0.00 0.00 0.00Schleicher 297.16521.39 9.30 9.30 0.15 3,975.13 56.43Scurry 920.141,696.28 20.52 20.52 0.72 16,745.60 282.63Shackelford 446.66787.83 13.87 13.87 0.39 2,584.60 27.41Shelby 788.211,506.84 11.24 11.24 0.40 4,681.48 153.59Sherman 382.36689.34 9.93 9.93 0.17 2,226.58 38.78Smith 600.161,117.21 11.83 11.83 0.32 6,759.09 157.15Somervell 69.05132.73 0.93 0.93 0.04 261.32 10.71Starr 1,801.983,435.69 27.08 27.08 0.92 39,905.70 922.75Stephens 548.00962.55 17.22 17.22 0.36 6,028.28 86.04Sterling 507.62898.57 15.24 15.24 0.35 5,045.87 54.84xviiTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Stonewall 125.21222.61 3.72 3.72 0.12 1,647.78 17.01Sutton 1,536.072,640.40 53.45 53.45 0.57 14,703.05 158.36Swisher 0.000.00 0.00 0.00 0.00 0.00 0.00Tarrant 4,070.9111,441.36 39.54 39.54 2.88 4,929.92 620.02Taylor 92.16163.25 2.80 2.80 0.09 693.08 8.42Terrell 890.561,697.22 13.46 13.46 0.45 4,554.08 153.52Terry 217.93388.12 6.39 6.39 0.20 5,118.11 70.81Throckmorton 221.50393.95 6.55 6.55 0.20 1,242.06 15.21Titus 42.1974.68 1.29 1.29 0.04 506.68 8.03Tom Green 170.07304.64 4.76 4.76 0.14 1,945.37 23.40Travis 3.375.97 0.10 0.10 0.00 14.43 0.07Trinity 10.9419.88 0.27 0.27 0.01 193.38 3.42Tyler 463.76896.18 5.69 5.69 0.25 57,953.39 1,201.05Upshur 604.481,126.42 11.73 11.73 0.30 10,582.53 238.20Upton 1,602.982,998.03 30.90 30.90 1.09 32,833.54 647.89Uvalde 0.200.26 0.02 0.02 0.00 4.37 0.01Val Verde 210.53394.38 3.90 3.90 0.10 620.76 21.64Van Zandt 193.81352.82 4.81 4.81 0.15 1,204.59 23.27Victoria 287.47535.68 5.67 5.67 0.16 3,296.01 69.83Walker 13.4924.74 0.31 0.31 0.01 85.26 1.73Waller 88.01106.67 2.83 2.83 0.11 2,859.24 56.46Ward 1,288.642,381.97 28.00 28.00 0.94 9,588.88 230.25Washington 256.76485.36 4.31 4.31 0.14 2,513.65 64.54Webb 3,123.825,806.41 62.66 62.66 1.48 28,275.41 664.71Wharton 692.111,309.84 11.43 11.43 0.37 15,986.48 354.54Wheeler 2,223.924,231.74 34.40 34.40 1.15 40,674.02 955.94Wichita 1,185.962,099.33 36.23 36.23 1.13 5,040.04 46.60xviiiTable E-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Wilbarger 174.53308.95 5.33 5.33 0.17 1,147.90 13.03Willacy 353.53681.05 4.59 4.59 0.19 8,274.58 193.92Williamson 9.0716.05 0.28 0.28 0.01 53.29 0.33Wilson 129.98230.01 3.98 3.98 0.12 757.55 6.10Winkler 917.141,698.44 19.52 19.52 0.63 7,815.47 141.18Wise 2,749.595,099.17 55.75 55.75 1.35 24,225.59 597.53Wood 239.16438.82 5.52 5.52 0.18 4,200.35 82.03Yoakum 1,074.181,960.14 26.21 26.21 0.88 25,649.46 414.59Young 556.32978.60 17.57 17.57 0.50 3,394.26 35.11Zapata 4,438.248,472.07 65.54 65.54 2.24 13,384.86 594.31Zavala 64.75114.70 1.94 1.94 0.05 1,016.76 14.24Total:128,330.85247,236.91 2,570.01 2,570.01 81.34 1,568,522.73 34,090.451-1



### 1.0 INTRODUCTION

This study was implemented for the Texas Commission on Environmental Quality

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

sites that operated in Texas in 2008, and to provide county le vel 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 e stimating emissions from oil and gas production sites and recommendation of a preferred e mission estimation approach for each identified emissions source type;

• Development of survey materials that may be used to ob tain 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 estimat e county-level emissions from each identified source type; and

• Performance of emissions estimation calculations fo r a 2008 base year, including the preparation of emissions inventory calculation spreadshee ts (including activity data and emission factors) and documentation of data, procedures, a nd 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 i nto the Texas Air Emissions Repository (TexAER).

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

upstream oil and gas production sites. Table 1-1 presents a l ist 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 T O 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 T O 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 Tanks1-2 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 lite rature 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 detail ed information on the emissions

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

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

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

provided in Section 6, conclusions and recommendations ba sed 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 poll utant (and total HAP) emissions

by source category, and Table 1-3 presents a summary of cr iteria 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 NO

x , 1,500,000

tons of VOC, and 30,000 tons of HAP. The main source of N O

x emissions are compressor

engines, while the main source of VOC and HAP emissions are oil and condensate storage tanks.1-4Table 1-2. State-wide Emissions Inventory for 2008 by Source CategorySCCSource Category DescriptionCO(tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)TotalHAP(tons/yr)2310000330 Artificial Lift 23,169.14 46,369.72 154.04154.049.56440.12140.492310011020 Storage Tanks: Crude Oil282,420.055,060.012310011100 Heater Treater 9,267.25 11,032.44 838.47838.4721.32606.78208.672310011201Tank Truck/Railcar Loading:Crude Oil26,810.72479.912310011450 Wellhead116,245.652310011501 Fugitives: Connectors2,956.392310011502 Fugitives: Flanges135.462310011503 Fugitives: Open Ended Lines605.722310011504 Fugitives: Pumps4,326.592310011505 Fugitives: Valves7,821.142310011506 Fugitives: Other12,480.552310020600 Compressor Engines 133.77 464.56 13.5813.580.2181.4029.002310021010 Storage Tanks: Condensate864,087.9017,281.712310021030Tank Truck/Railcar LoadingCondensate7,235.50144.712310021100 Gas Well Heaters 7,564.83 9,005.75 684.44684.440.04495.32170.342310021101Natural Gas Fired 2-Cycle LeanBurn Compressor Engines <50 Hp 140.52 209.25 9.729.720.1643.3815.462310021102Natural Gas Fired 2-Cycle LeanBurn Compressor Engines 50 To499 Hp2,907.93 13,776.30 352.37352.375.712,012.02716.782310021203Natural Gas Fired 4-Cycle LeanBurn Compressor Engines 500+Hp 14,746.41 27,288.73 76.9576.9515.943,817.422,337.582310021301Natural Gas Fired 4-Cycle RichBurn Compressor Engines <50 Hp 93.37 1,175.69 3.863.860.255.615.501-5Table 1-2. State-wide Emissions Inventory for 2008 by Source Category (Cont.)SCCSource Category DescriptionCO(tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)TotalHAP(tons/yr)2310021302Natural Gas Fired 4-Cycle RichBurn Compressor Engines 50 To499hp38,988.69 86,462.54 226.24226.2414.831,487.261,451.932310021400 Gas Well Dehydrators 904.59 293.366,344.855,255.172310021402Natural Gas Fired 4-Cycle RichBurn Compressor Engines 50-499hp W/ Nscr767.55 3,321.00 35.0235.022.0517.7317.462310021403Natural Gas Fired 4-Cycle RichBurn Compressor Engines 500+Hp W/ Nscr29,646.80 47,837.57 175.33175.3311.26794.33775.732310021501 Fugitives: Connectors1,161.522310021502 Fugitives: Flanges1,199.682310021503 Fugitives: Open Ended Lines916.822310021504 Fugitives: Pumps476.312310021505 Fugitives: Valves7,387.522310021506 Fugitives: Other8,732.372310021600 Gas Well Venting8,601.782310121700Gas Well Completion: AllProcesses10,139.562310111700Oil Well Completion: AllProcesses19,425.442310121401 Gas Well Pneumatic Pumps169,209.86Total:128,330.85 247,236.91 2,570.012,570.0181.341,568,522.7334,090.451-6Table 1-3. State-wide Emissions Inventory for 2008 by CountyCountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Anderson 241.28444.72 5.31 5.31 0.16 2,858.24 52.77Andrews 1,825.993,291.18 49.14 49.14 1.57 31,691.46 444.20Angelina 161.97311.11 2.15 2.15 0.08 629.30 25.94Aransas 165.25317.00 2.28 2.28 0.09 6,574.04 144.42Archer 614.911,088.88 18.74 18.74 0.58 2,719.03 24.45Armstrong 0.000.00 0.00 0.00 0.00 0.00 0.00Atascosa 321.56578.81 8.71 8.71 0.27 2,237.28 31.44Austin 127.18237.83 2.42 2.42 0.07 2,040.58 43.74Bailey 0.000.00 0.00 0.00 0.00 0.00 0.00Bandera 0.210.37 0.01 0.01 0.00 5.14 0.03Bastrop 74.21128.49 2.56 2.56 0.06 1,286.18 16.32Baylor 26.7847.39 0.82 0.82 0.03 189.33 1.96Bee 581.151,101.85 9.42 9.42 0.31 4,717.44 125.89Bell 0.000.00 0.00 0.00 0.00 0.00 0.00Bexar 531.99941.46 16.28 16.28 0.51 2,120.86 7.60Blanco 0.000.00 0.00 0.00 0.00 0.00 0.00Borden 166.31300.48 4.40 4.40 0.14 4,107.39 62.92Bosque 3.456.30 0.08 0.08 0.00 17.43 0.34Bowie 5.139.25 0.14 0.14 0.00 148.70 2.69Brazoria 207.73199.95 6.59 6.59 0.28 14,003.43 292.15Brazos 240.26444.10 5.18 5.18 0.16 3,781.19 74.41Brewster 0.000.00 0.00 0.00 0.00 5.88 0.00Briscoe 0.000.00 0.00 0.00 0.00 12.33 0.01Brooks 690.711,318.85 10.17 10.17 0.35 16,242.00 374.16Brown 204.73339.96 8.55 8.55 0.14 1,626.85 6.71Burleson 366.21669.08 8.80 8.80 0.28 3,881.39 67.201-7Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Burnet 0.000.00 0.00 0.00 0.00 0.00 0.00Caldwell 676.241,197.43 20.61 20.61 0.64 3,452.64 22.69Calhoun 189.99360.25 3.07 3.07 0.10 7,473.42 160.35Callahan 182.61321.30 5.76 5.76 0.16 983.48 9.65Cameron 1.683.12 0.03 0.03 0.00 10.26 0.20Camp 30.4155.01 0.79 0.79 0.03 259.21 4.96Carson 569.731,021.51 15.74 15.74 0.41 1,954.76 34.12Cass 54.9598.13 1.55 1.55 0.04 662.46 11.89Castro 0.000.00 0.00 0.00 0.00 0.00 0.00Chambers 84.7694.63 2.75 2.75 0.11 4,424.08 90.13Cherokee 364.58682.18 6.78 6.78 0.18 2,911.32 72.93Childress 1.692.99 0.05 0.05 0.00 57.40 0.71Clay 231.82409.65 7.14 7.14 0.21 1,476.89 16.60Cochran 445.16791.68 13.17 13.17 0.41 6,168.35 67.45Coke 109.55200.99 2.54 2.54 0.08 1,010.20 15.88Coleman 173.73295.58 6.51 6.51 0.13 1,363.81 9.92Collin 0.000.00 0.00 0.00 0.00 0.00 0.00Collingsworth 50.0476.34 2.77 2.77 0.02 742.63 2.58Colorado 319.38601.84 5.54 5.54 0.16 4,980.62 115.78Comal 0.000.00 0.00 0.00 0.00 0.00 0.00Comanche 34.2253.57 1.76 1.76 0.02 438.42 1.97Concho 72.58128.12 2.23 2.23 0.06 821.04 9.65Cooke 495.43884.64 14.25 14.25 0.45 3,467.02 50.26Coryell 0.000.00 0.00 0.00 0.00 3.13 0.00Cottle 95.67180.55 1.63 1.63 0.05 2,376.44 52.30Crane 1,739.983,208.47 38.61 38.61 1.26 17,274.91 291.731-8Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Crockett 2,274.884,015.15 68.61 68.61 1.15 28,501.91 414.45Crosby 85.55151.51 2.61 2.61 0.08 1,056.14 9.67Culberson 72.79137.98 1.20 1.20 0.04 284.44 8.75Dallam 0.000.00 0.00 0.00 0.00 0.00 0.00Dallas 28.0480.04 0.21 0.21 0.02 24.60 4.23Dawson 275.48492.78 7.84 7.84 0.25 5,344.51 72.02Deaf Smith 0.000.00 0.00 0.00 0.00 0.00 0.00Delta 0.000.00 0.00 0.00 0.00 0.00 0.00Denton 1,763.524,690.36 29.51 29.51 1.14 13,254.59 416.58Dewitt 676.491,300.83 9.00 9.00 0.35 11,617.04 287.72Dickens 49.7088.22 1.49 1.49 0.05 1,446.43 20.78Dimmit 197.89353.20 5.65 5.65 0.15 2,515.16 31.86Donley 0.530.77 0.03 0.03 0.00 15.82 0.17Duval 1,111.172,101.02 18.70 18.70 0.63 12,897.27 314.00Eastland 285.26476.94 11.51 11.51 0.18 3,654.84 39.72Ector 1,798.243,277.22 44.40 44.40 1.47 26,211.12 388.97Edwards 270.78492.35 6.60 6.60 0.13 1,377.01 25.49El Paso 0.000.00 0.00 0.00 0.00 0.00 0.00Ellis 51.17144.09 0.47 0.47 0.04 52.43 7.56Erath 161.14295.43 3.68 3.68 0.07 1,556.95 32.84Falls 4.017.09 0.12 0.12 0.00 21.49 0.09Fannin 0.000.00 0.00 0.00 0.00 11.86 0.00Fayette 356.62659.40 7.64 7.64 0.23 5,607.61 115.67Fisher 107.82193.50 2.99 2.99 0.09 1,365.54 16.44Floyd 0.420.75 0.01 0.01 0.00 2.97 0.03Foard 27.9443.90 1.42 1.42 0.01 414.38 2.571-9Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Fort Bend 169.68171.80 5.51 5.51 0.22 8,072.59 166.58Franklin 69.40127.99 1.52 1.52 0.05 1,389.52 28.31Freestone 3,821.607,289.51 56.95 56.95 1.93 9,858.72 475.09Frio 139.12246.28 4.21 4.21 0.12 1,393.74 14.40Gaines 1,165.522,133.47 27.65 27.65 0.92 27,788.32 460.84Galveston 86.4676.28 2.61 2.61 0.12 17,475.45 358.12Garza 445.72790.41 13.45 13.45 0.42 6,133.80 63.01Gillespie 0.000.00 0.00 0.00 0.00 0.00 0.00Glasscock 416.67761.54 10.00 10.00 0.32 5,431.20 84.49Goliad 731.211,386.08 11.85 11.85 0.37 7,851.72 199.63Gonzales 51.4092.76 1.37 1.37 0.04 578.12 8.62Gray 825.551,440.69 27.11 27.11 0.64 4,163.88 45.84Grayson 201.98365.62 5.22 5.22 0.16 1,707.03 31.65Gregg 1,423.902,592.32 34.92 34.92 1.00 10,980.44 227.68Grimes 334.10638.29 4.87 4.87 0.17 1,264.12 50.60Guadalupe 402.11711.73 12.29 12.29 0.38 2,576.45 22.66Hale 62.99114.67 1.57 1.57 0.05 2,698.37 46.20Hall 0.000.00 0.00 0.00 0.00 0.00 0.00Hamilton 3.125.33 0.11 0.11 0.00 36.47 0.47Hansford 377.68676.20 10.32 10.32 0.17 2,601.06 43.25Hardeman 52.1392.68 1.54 1.54 0.05 1,230.36 19.89Hardin 258.68348.83 7.85 7.85 0.30 22,648.65 447.94Harris 176.00181.67 5.65 5.65 0.23 8,801.29 184.44Harrison 1,879.593,514.48 35.19 35.19 0.93 25,383.90 583.58Hartley 39.0670.27 1.04 1.04 0.02 399.51 6.56Haskell 53.8395.30 1.64 1.64 0.05 443.81 5.441-10Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Hays 0.000.00 0.00 0.00 0.00 0.00 0.00Hemphill 2,092.633,936.72 37.08 37.08 1.03 32,774.76 754.74Henderson 453.75854.13 7.99 7.99 0.24 2,535.12 73.92Hidalgo 3,264.696,276.64 43.49 43.49 1.68 56,554.95 1,407.72Hill 308.20597.97 3.53 3.53 0.16 233.61 34.41Hockley 1,004.101,795.93 28.58 28.58 0.91 22,011.88 308.12Hood 926.801,777.59 12.89 12.89 0.47 9,914.41 269.97Hopkins 20.8437.79 0.53 0.53 0.02 298.78 5.06Houston 164.62308.00 3.11 3.11 0.10 1,587.91 35.84Howard 803.871,436.74 23.00 23.00 0.73 9,904.95 107.63Hudspeth 0.120.17 0.01 0.01 0.00 3.29 0.03Hunt 0.000.00 0.00 0.00 0.00 0.00 0.00Hutchinson 903.431,601.32 27.09 27.09 0.72 4,039.66 49.29Irion 531.51961.89 13.77 13.77 0.40 5,877.27 82.51Jack 646.651,121.02 21.80 21.80 0.42 6,701.91 92.20Jackson 303.15569.09 5.55 5.55 0.17 9,879.64 204.59Jasper 205.58394.00 2.87 2.87 0.11 6,405.78 143.58Jeff Davis 0.000.00 0.00 0.00 0.00 1.29 0.03Jefferson 287.19182.64 8.05 8.05 0.46 55,659.21 1,163.27Jim Hogg 266.50500.41 4.83 4.83 0.14 4,021.10 92.33Jim Wells 127.37226.90 3.61 3.61 0.06 1,576.61 26.20Johnson 4,495.4812,647.53 43.01 43.01 3.19 5,209.18 684.81Jones 167.32296.69 5.05 5.05 0.16 1,277.91 14.79Karnes 171.32323.25 2.95 2.95 0.10 3,454.12 76.12Kaufman 4.508.03 0.14 0.14 0.00 62.82 1.05Kendall 0.000.00 0.00 0.00 0.00 0.00 0.001-11Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Kenedy 665.441,286.34 8.13 8.13 0.35 4,087.71 143.43Kent 203.51375.70 4.48 4.48 0.16 4,304.19 73.92Kerr 0.000.00 0.00 0.00 0.00 0.00 0.00Kimble 2.944.50 0.16 0.16 0.00 41.29 0.17King 112.59198.82 3.47 3.47 0.10 2,010.47 35.20Kinney 0.000.00 0.00 0.00 0.00 0.00 0.00Kleberg 494.21948.96 6.71 6.71 0.25 8,845.84 217.77Knox 46.1881.72 1.41 1.41 0.04 354.81 4.00La Salle 259.22470.95 6.38 6.38 0.13 4,078.69 76.37Lamar 0.000.00 0.00 0.00 0.00 0.00 0.00Lamb 15.1027.13 0.42 0.42 0.01 686.85 11.01Lampasas 0.160.20 0.01 0.01 0.00 4.24 0.00Lavaca 924.671,764.89 13.68 13.68 0.47 12,277.67 311.64Lee 307.30564.26 7.08 7.08 0.23 2,650.76 49.84Leon 1,079.722,070.29 15.01 15.01 0.58 5,733.49 197.49Liberty 331.40341.24 9.92 9.92 0.45 27,316.75 570.30Limestone 1,393.872,655.14 21.17 21.17 0.71 4,377.56 180.91Lipscomb 1,125.342,104.13 21.36 21.36 0.58 17,104.94 381.52Live Oak 378.16709.70 6.91 6.91 0.20 6,807.99 149.58Llano 0.000.00 0.00 0.00 0.00 0.00 0.00Loving 1,567.713,023.10 20.15 20.15 0.89 6,348.57 251.69Lubbock 89.19158.04 2.71 2.71 0.08 1,825.32 23.15Lynn 18.5233.00 0.54 0.54 0.02 350.40 4.52Madison 117.26216.26 2.56 2.56 0.07 1,290.52 26.07Marion 96.78174.38 2.56 2.56 0.06 1,407.02 25.69Martin 596.731,088.02 14.69 14.69 0.49 10,928.66 168.721-12Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Mason 0.000.00 0.00 0.00 0.00 0.00 0.00Matagorda 609.791,168.96 8.47 8.47 0.32 19,098.24 428.64Maverick 182.47323.89 5.42 5.42 0.15 3,715.58 42.08McCulloch 14.6525.47 0.50 0.50 0.01 109.65 1.15McLennan 8.6515.30 0.26 0.26 0.01 27.43 0.12McMullen 493.90900.42 11.92 11.92 0.29 6,027.42 110.63Medina 275.72487.25 8.50 8.50 0.26 1,235.77 4.54Menard 27.0047.52 0.85 0.85 0.02 266.84 2.69Midland 1,610.042,951.97 37.75 37.75 1.27 20,938.23 333.93Milam 218.91387.83 6.65 6.65 0.21 1,216.87 9.32Mills 0.360.51 0.02 0.02 0.00 6.38 0.02Mitchell 502.49890.13 15.28 15.28 0.48 6,645.63 65.00Montague 551.48987.06 15.59 15.59 0.49 3,448.92 48.39Montgomery 73.5681.80 2.86 2.86 0.08 2,890.56 54.67Moore 744.021,343.19 19.29 19.29 0.40 3,502.87 63.64Morris 0.210.37 0.01 0.01 0.00 2.01 0.03Motley 3.806.72 0.12 0.12 0.00 52.75 0.49Nacogdoches 1,527.762,897.04 24.29 24.29 0.77 12,723.39 353.60Navarro 170.24301.61 5.16 5.16 0.16 1,444.51 18.73Newton 78.50145.69 1.63 1.63 0.05 1,601.94 31.72Nolan 133.50240.21 3.63 3.63 0.11 1,931.63 25.88Nueces 605.471,127.23 11.99 11.99 0.31 15,740.17 332.51Ochiltree 561.881,020.35 13.94 13.94 0.31 5,760.68 108.67Oldham 5.6810.02 0.17 0.17 0.00 247.24 3.74Orange 67.7971.25 2.06 2.06 0.09 8,467.82 172.90Palo Pinto 455.72785.82 15.70 15.70 0.21 7,033.45 105.261-13Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Panola 3,784.217,052.88 73.18 73.18 1.82 50,362.96 1,170.88Parker 1,225.523,294.01 19.49 19.49 0.80 9,840.76 290.06Parmer 0.000.00 0.00 0.00 0.00 0.00 0.00Pecos 4,534.568,670.50 66.30 66.30 2.63 21,760.89 703.44Polk 415.68797.76 5.69 5.69 0.22 29,650.93 625.12Potter 350.79632.33 9.25 9.25 0.21 1,799.21 27.27Presidio 0.000.00 0.00 0.00 0.00 0.00 0.00Rains 59.61115.43 0.71 0.71 0.03 38.47 6.62Randall 0.000.00 0.00 0.00 0.00 0.00 0.00Reagan 1,209.822,204.56 29.89 29.89 0.99 11,808.61 158.58Real 1.913.34 0.06 0.06 0.00 16.74 0.15Red River 9.5716.96 0.29 0.29 0.01 159.73 2.26Reeves 575.501,077.94 10.88 10.88 0.36 3,146.28 72.34Refugio 652.551,218.19 12.72 12.72 0.40 9,671.07 197.77Roberts 881.181,659.43 15.47 15.47 0.45 15,296.54 346.65Robertson 3,591.036,960.37 41.87 41.87 1.90 4,202.14 427.68Rockwall 0.000.00 0.00 0.00 0.00 0.00 0.00Runnels 145.66262.06 3.96 3.96 0.12 1,177.54 15.82Rusk 2,394.044,447.78 48.27 48.27 1.34 26,428.99 597.16Sabine 2.043.67 0.06 0.06 0.00 19.20 0.14San Augustine 159.66309.99 1.77 1.77 0.09 452.69 23.22San Jacinto 182.43350.28 2.47 2.47 0.09 6,462.64 144.35San Patricio 303.08570.53 5.36 5.36 0.16 12,721.07 267.75San Saba 0.000.00 0.00 0.00 0.00 0.00 0.00Schleicher 297.16521.39 9.30 9.30 0.15 3,975.13 56.43Scurry 920.141,696.28 20.52 20.52 0.72 16,745.60 282.631-14Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Shackelford 446.66787.83 13.87 13.87 0.39 2,584.60 27.41Shelby 788.211,506.84 11.24 11.24 0.40 4,681.48 153.59Sherman 382.36689.34 9.93 9.93 0.17 2,226.58 38.78Smith 600.161,117.21 11.83 11.83 0.32 6,759.09 157.15Somervell 69.05132.73 0.93 0.93 0.04 261.32 10.71Starr 1,801.983,435.69 27.08 27.08 0.92 39,905.70 922.75Stephens 548.00962.55 17.22 17.22 0.36 6,028.28 86.04Sterling 507.62898.57 15.24 15.24 0.35 5,045.87 54.84Stonewall 125.21222.61 3.72 3.72 0.12 1,647.78 17.01Sutton 1,536.072,640.40 53.45 53.45 0.57 14,703.05 158.36Swisher 0.000.00 0.00 0.00 0.00 0.00 0.00Tarrant 4,070.9111,441.36 39.54 39.54 2.88 4,929.92 620.02Taylor 92.16163.25 2.80 2.80 0.09 693.08 8.42Terrell 890.561,697.22 13.46 13.46 0.45 4,554.08 153.52Terry 217.93388.12 6.39 6.39 0.20 5,118.11 70.81Throckmorton 221.50393.95 6.55 6.55 0.20 1,242.06 15.21Titus 42.1974.68 1.29 1.29 0.04 506.68 8.03Tom Green 170.07304.64 4.76 4.76 0.14 1,945.37 23.40Travis 3.375.97 0.10 0.10 0.00 14.43 0.07Trinity 10.9419.88 0.27 0.27 0.01 193.38 3.42Tyler 463.76896.18 5.69 5.69 0.25 57,953.39 1,201.05Upshur 604.481,126.42 11.73 11.73 0.30 10,582.53 238.20Upton 1,602.982,998.03 30.90 30.90 1.09 32,833.54 647.89Uvalde 0.200.26 0.02 0.02 0.00 4.37 0.01Val Verde 210.53394.38 3.90 3.90 0.10 620.76 21.64Van Zandt 193.81352.82 4.81 4.81 0.15 1,204.59 23.271-15Table 1-3. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Victoria 287.47535.68 5.67 5.67 0.16 3,296.01 69.83Walker 13.4924.74 0.31 0.31 0.01 85.26 1.73Waller 88.01106.67 2.83 2.83 0.11 2,859.24 56.46Ward 1,288.642,381.97 28.00 28.00 0.94 9,588.88 230.25Washington 256.76485.36 4.31 4.31 0.14 2,513.65 64.54Webb 3,123.825,806.41 62.66 62.66 1.48 28,275.41 664.71Wharton 692.111,309.84 11.43 11.43 0.37 15,986.48 354.54Wheeler 2,223.924,231.74 34.40 34.40 1.15 40,674.02 955.94Wichita 1,185.962,099.33 36.23 36.23 1.13 5,040.04 46.60Wilbarger 174.53308.95 5.33 5.33 0.17 1,147.90 13.03Willacy 353.53681.05 4.59 4.59 0.19 8,274.58 193.92Williamson 9.0716.05 0.28 0.28 0.01 53.29 0.33Wilson 129.98230.01 3.98 3.98 0.12 757.55 6.10Winkler 917.141,698.44 19.52 19.52 0.63 7,815.47 141.18Wise 2,749.595,099.17 55.75 55.75 1.35 24,225.59 597.53Wood 239.16438.82 5.52 5.52 0.18 4,200.35 82.03Yoakum 1,074.181,960.14 26.21 26.21 0.88 25,649.46 414.59Young 556.32978.60 17.57 17.57 0.50 3,394.26 35.11Zapata 4,438.248,472.07 65.54 65.54 2.24 13,384.86 594.31Zavala 64.75114.70 1.94 1.94 0.05 1,016.76 14.24Total:128,330.85247,236.91 2,570.01 2,570.01 81.34 1,568,522.73 34,090.452-1



### 2.0 AVAILABLE EMISSIONS ESTIMATION METHODOLOGY

REVIEW

One of the objectives of this project was to conduct a l iterature 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 categor y was selected. In the project Work

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

summary of the available and recommended emission estima tion 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 ac tivities 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 proje ct was the development of survey

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

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

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

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

2010.

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

this part of the project.4-1



### 4.0 EMISSIONS CALCULATION METHODOLOGY

This section presents a discussion of each source type i ncluded 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 descr iption 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 engi nes are normally used to drive

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

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

well-head natural gas and can represent a significant NO

x area emissions source category as they

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

Emissions from compressor engines were calculated usin g a methodology similar to that

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

Compressor Engine Survey and Engine NO

x Emissions at Gas Production Facilities” (HARC,

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

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

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

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

Forth Worth (DFW) metropolitan area and Southeast Te xas. 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 th ese data, ERG calculated countylevel emissions from compressor engines with the foll owing equation:

1 The HARC 2005 report was updated in 2006 to include more engin e size categories and to add the year 2000 to the previous inventory; however, these updates did not change t he calculation methodology used in the original 2005

report.4-2

where:

E ik

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

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

F 1 i is the fraction of wells requiring compression in county i

F 2 j is the fraction of compression load represented by engi nes of type j

EF jk is the emission factor for engine type j, and pollutan t k [g/ Hp -hr]

C i is the compression requirements for county i [ Hp -hr/Mscf] 907,180 is the conversion factor from grams to tons of emiss ions

Total gas production in county i, TGP i :

Natural gas production data by county ( TGP i ) 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, Randa ll, San Saba, and Swisher counties had

no gas or oil production in 2008.

Fraction of wells requiring compression in county i, F 1 i :

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

of wells requiring compression (F 1 i ) was estimated in the HARC study as the fraction of active

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

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

following equation:

       

− = > 2008) 5, February on Wells Active (Total 2007)

in Completed (Wells 1 Old Year 1 Wells of Fraction

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/in dex.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 distributi on 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:         ∗

∗ ∗

× = 180

, 907 2 1 i

jk j i

i ik C

EF F F TGP E4-3

http://www.rrc.state.tx.us/data/wells/wellcount/ind ex.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 ar e 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 explai ned above, ERG has assumed that all wells

completed in 2007 were completed on February 5, 200 7. ERG applied the fractions shown in the

Table 4-1 to the counties in each respective distri ct.

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 (F 1i )
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, F 2 j :

Fraction of compression load by engine type (F 2 j ) 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 t he Texas attainment areas, the Houston

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

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

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

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

population) for each of the three categories used i n 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 su rveys. These engines were removed

because they were located in thirteen counties (Aus tin, 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 popu lation (335) of engines for these counties

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

engine survey data sets:

• Fifty-five engines from the DFW survey and two engi nes from the Southeast survey that lacked engine characteristic data;

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

• Three engines from the HARC study that were identif ied as not being located at a gas well; and

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

After combining the data sets (and removing certai n 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 appropriat ely, ERG performed extensive internet

research as well as phone interviews with engine ma nufactures to standardize engine make and

model naming conventions. Additionally, some assum ptions 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 m odel number which defines the engine as a

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

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

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

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

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

specific engine model and then calculated the fract ion of compression load by engine type (F 2j )4-5

for three categories (Texas attainment areas, the D allas 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 countie s, these counties were combined into the

Houston nonattainment area.

Emission factor for engine type j, and pollutant k, EF jk :

Emission factors for each unique engine make and m odel (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 NO

x , CO, and VOC emission factors for the engines loca ted in

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

as phone interviews with specific engine manufactur es. Manufacture emissions data was

averaged across all performance data given for a sp ecific engine.

NO

x emission factors for the engines located in nonatt ainment counties (Table 4-5) are

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

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

sources of NO

x , including some stationary, gas-fired reciprocatin g internal combustion engines.

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

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

Dallas-Fort Worth rule, rich burn engines greater t han 50 horsepower are restricted to 0.5 g/ Hp

hr, lean burn engines installed or moved before Jun e 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. The refore, an adjusted NO

x emission factor of 0.67

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

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

the attainment area NO

x emission factor in Table 4-3 was used for these co unties for this 2008

base year inventory.

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

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

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

greater than 50 Hp and located in a nonattainment a rea, would have non-selective catalytic4-6Table 4-3. Emission Factor Data for Texas Attainment AreasEmission Factor (EFjk) (g/Hp-hr)Engine Make & ModelSCCNumber ofEngines[Lean / Rich]EngineHorsepower(Hp)CompressionLoad by EngineType (F2j)Fuel Consumption(MMBtu/Hp-hr)PMNOxCOVOCSO2CAT G3306 NA 2310021302 0 / 165 145 8.98% 0.007775 3.35E-02 13.48 13.46 0.22 2.07E-03CAT G3304 NA 2310021302 0 / 130 95 4.64% 0.007567 3.26E-02 21.08 1.6 0.24 2.02E-03Wauk VRG330 2310021302 0 / 107 68 2.73% 0.008038 3.46E-02 12.951 1.104 0.05(1)2.14E-03CAT G3306 TA 2310021302 0 / 67 203 5.11% 0.008098 3.49E-02 16.57 16.57 0.12 2.16E-03Wauk F817 G 2310021302 0 / 42 87 1.37% 0.007253 3.13E-02 16.0 1.0 1.7(2)1.93E-03AJAX DPC-60 2310021102 39 / 0 58 0.85% 0.009000 1.57E-01 4.4 1.7 0.8 2.40E-03AJAX DPC-1152310021102/231002060031 / 2 110 1.36% 0.009000 1.57E-01 4.4 2.4 0.9 2.40E-03Wauk F1197 G 2310021302 0 / 32 183 2.20% 0.007253 3.13E-02 20.0 1.0 0.20(1)1.93E-03CAT G3406 NA(3)2310021302 0 / 31 290 3.37% 0.007407 3.19E-02 23.2267 6.14 0.17 1.98E-03CAT G3516 TALE 2310021203 30 / 0 1245 14.02% 0.007365 2.58E-04 2.0 1.805 0.28 1.96E-03CAT G3306 NA HCR(4)2310021302 0 / 29 145 1.58% 0.007775 3.35E-02 13.48 13.46 0.22 2.07E-03AJAX DPC-3602310021102/231002060027 / 1 346 3.64% 0.008400 1.46E-01 6.3 1.4 1.0 2.24E-03AJAX DPC-180 2310021102 28 / 0 173 1.82% 0.008400 1.46E-01 6.3 1.4 1.0 2.24E-03AJAX DPC-140 2310021102 26 / 0 134 1.31% 0.008200 1.43E-01 10.5 1.3 0.7 2.19E-03AJAX DPC-280 2310021102 25 / 0 269 2.52% 0.008200 1.43E-01 11.4 1.3 0.7 2.19E-03Wauk VRG220(5)2310021301 0 / 24 45 0.41% 0.008038 3.46E-02 12.951 1.104 0.05(1)2.14E-03AJAX DPC-80 2310021102 22 / 0 77 0.64% 0.008900 1.55E-01 4.4 2.8 0.9 2.37E-03CAT G342 NA(6)2310021302 0 / 21 225 1.77% 0.008588 3.70E-02 0.101 0.317 0.086(1)2.29E-03AJAX C-422310021101/231002060019 / 1 40 0.30% 0.009900 1.72E-01 4.4 3.3 0.8 2.64E-03GEMINI G26 2310021301 0 / 19 26 0.19% 0.008038 3.46E-02 12.951 1.104 0.05(1)2.14E-03Wauk L7042 GL(7)2310021203 19 / 0 1357 9.68% 0.007238 2.53E-02 1.0 2.85 0.95(1)1.93E-03CAT G342 TA(6)2310021302 0 / 16 225 1.35% 0.008588 3.70E-02 0.101 0.317 0.086(1)2.29E-03Wauk VRG310(5)2310021302 0 / 16 68 0.41% 0.008038 3.46E-02 12.951 1.104 0.05(1)2.14E-03CAT G399 TA(10)2310021403 0 / 16 802 4.82% 0.008710 3.75E-02 0.7756 0.1592 0.0086(8)2.32E-03Wauk L7042 GSI(10)2310021403 0 / 15 1357 7.64% 0.007558 3.26E-02 1.6 1.3 0.025(1)2.02E-03CAT G398 TA(9, 10)2310021403 0 / 15 605 3.41% 0.008710 3.75E-02 0.7756 0.1592 0.0086(8)2.32E-03CAT G3406 TA 2310021302 0 / 14 290 1.52% 0.007407 3.19E-02 23.2267 6.14 0.17 1.98E-03CAT G3512 TALE 2310021203 14 / 0 932 4.90% 0.007385 2.58E-04 2.0 2.04 0.295 1.97E-03CAT G3406(11)2310021302 0 / 14 290 1.52% 0.007407 3.19E-02 23.2267 6.14 0.17 1.98E-03Wauk L7042 G(10)2310021403 0 / 14 961 5.05% 0.007180 3.09E-02 1.6 1.3 0.025(1)1.91E-034-7Table 4-3. Emission Factor Data for Texas Attainment Areas (Cont.)Emission Factor (EFjk) (g/Hp-hr)Engine Make & ModelSCCNumber ofEngines[Lean / Rich]EngineHorsepower(Hp)CompressionLoad by EngineType (F2j)Fuel Consumption(MMBtu/Hp-hr)PMNOxCOVOCSO2AJAX DPC-2302310021102/231002060010 / 1 221 0.91% 0.008700 1.52E-01 4.4 2.4 0.90 2.32E-03TOTAL -- 1082 -- 100%Weighted AverageEFs0.04 7.57 3.85 0.35 2.07E-031. 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 bothmodels.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 forboth models.5. Based on discussions with Waukesha, the VRG220 and VRG310 models have the same emission factors asthe VRG330.6. Emissions data based on AP-42 background document with no HAP control. Emission factor data did notdifferentiate between a G342 TA or NA engine, thussame emission factors were assumed for both models.7. No emission factor data could be found for thisengine. Because it is a 4-stroke and has similar horsepower to the Wauk VRG220, it was assumed that emission factors were the same for both models.8. Assumed to be equal to CAT G342 NA.9. No emission factor data could be found for thisengine. Since it is a similar model manufactured in the same time period, it was assumed that emission factors were the same as CAT G399 TA.10. Engines are documented as having non-selectivecatalytic reduction (NSCR) control technology. ERG has applied a 90% reduction to the emission factors for CO and VOC for these engines11. 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.4-8Table 4-4. Emission Factor Data for Dallas Nonattainment AreasEmission Factor (EFjk) (g/Hp-hr)Engine Make & ModelSCCNumber ofEngines[Lean / Rich]EngineHorsepower(Hp)Fraction ofCompressionLoad byEngine Type(F2j)FuelConsumption(MMBtu/Hp-hr)PMNOx(1)CO(1)VOC(1)SO2CAT G3306 NA 2310021402 0 / 281 145 6.10% 0.007775 3.35E-02 0.50 1.346 0.022 2.07E-03CAT G3304 NA HCR(2)2310021402 0 / 72 95 1.02% 0.007567 3.26E-02 0.50 0.16 0.024 2.02E-03Cummins G8.3 2310021402 0 / 64 112 1.07% 0.008228 3.55E-02 0.50 0.946 0.001(3)2.19E-03CAT G3516 TALE 2310021203 60 / 0 1245 11.18% 0.007364 2.58E-04 0.67 1.805 0.28 1.96E-03CAT G3606 TALE LCR(4)2310021203 59 / 0 1835 16.21% 0.006612 2.31E-04 0.67 2.5625 0.605 1.76E-03CAT G3306 NA HCR(5)2310021402 0 / 58 145 1.26% 0.007775 3.35E-02 0.50 1.346 0.022 2.07E-03Wauk L7044 GSI 2310021403 0 / 50 1540 11.53% 0.007665 3.30E-02 0.50 1.03 0.02(6)2.04E-03Wauk L5794 GSI 2310021403 0 / 49 1265 9.28% 0.007430 3.20E-02 0.50 0.88 0.03(3)1.98E-03CAT G3304 NA 2310021402 0 / 46 95 0.65% 0.007567 3.26E-02 0.50 0.16 0.024 2.02E-03Wauk L7042 GSI 2310021403 37 / 0 1357 7.52% 0.007557 2.64E-04 0.67 13.0 0.25(3)2.02E-03CAT G3516 2310021203 0 / 29 1050 4.56% 0.007700 3.32E-02 0.50 1.31 0.029(3)2.05E-03CAT G3516 TALE AFRC(7)2310021203 29 / 0 1245 5.41% 0.007364 2.58E-04 0.67 1.805 0.28 1.96E-03Cummins 8.3 GTA 2310021402 0 / 28 183 0.77% 0.007380 3.18E-02 0.50 0.205 0.007(3)1.97E-03CAT G3608 TALE 2310021203 28 / 0 2408 10.09% 0.006592 2.31E-04 0.67 2.56 0.5975 1.76E-03CAT G3606 TALE 2310021203 26 / 0 1835 7.14% 0.006612 2.31E-04 0.67 2.56 0.605 1.76E-03Cummins G5.9 2310021402 0 / 25 84 0.31% 0.007914 3.41E-02 0.50 1.451 0.022(3)2.11E-03AJAX DPC-1802310021102/23100206007 / 17 173 0.62% 0.008400 1.46E-01 0.55 1.4 1.0 2.24E-03CAT G3306 TA 2310021402 0 / 19 203 0.58% 0.008098 3.49E-02 0.50 1.657 0.012 2.16E-03CAT G3508 TALE 2310021203 17 / 0 670 1.71% 0.007510 2.63E-04 0.67 1.84 0.3 2.00E-03CAT G3512 TALE 2310021203 17 / 0 932 2.37% 0.007385 2.58E-04 0.67 2.04 0.295 1.97E-03AJAX DPC-1402310021102/23100206003 / 11 134 0.28% 0.008200 1.43E-01 0.54 1.3 0.7 2.19E-03AJAX DPC-1152310021102/23100206005 / 8 110 0.21% 0.009000 1.57E-01 0.57 2.4 0.9 2.40E-03Wauk VRG330 2310021402 0 / 12 68 0.12% 0.008038 3.46E-02 0.50 0.110 0.005(3)2.14E-03TOTAL -- 1048 -- 100%WeightedAverage EFs0.02 7.57 2.62 0.30 1.93E-031. 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 technology. ERG has applied a 90% reductionto the emission factors for CO and VOC for these engines. As the compliance date for 30 TAC, Chapter117, Subchapter D Division 2 is not until after 2008, the attainment area NOx emission factor is used.2. 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 forboth models.3. Non-Methane Hydrocarbon.4. There is no emission factor data available distinguishing CAT G3606 TALE LCR from G3606 TALE, thusit was assumed that emission factors were the samefor both models. Furthermore, although datareceived from the 2007 DFW survey reported the CATG3606 TALE LCR model has a rich burn engine; basedon further research, ERG determined that this engine is a lean burn engine.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 forboth 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 asthe CAT G3516 TALE. Furthermore, several of theseengines were reported as rich burn in the data received from the 2007 DFW survey; however, based on further research, ERG determined that this engine canonly be a lean burn engine.4-9Table 4-5. Emission Factor Data for Houston Nonattainment AreasEmission Factor (EFjk) (g/Hp-hr)Engine Make & ModelSCCNumber ofEngines[Lean / Rich]EngineHorsepower(Hp)Fraction ofCompressionLoad byEngine Type(F2j)FuelConsumption(MMBtu/Hp-hr)PMNOx(1)CO(1)VOC(1)SO2CAT G3304 NA 2310021402 0 / 26 95 5.49% 0.007567 3.26E-02 0.50 0.16 0.024 2.02E-03CAT G3306 NA 2310021402 0 / 24 145 7.73% 0.007775 3.35E-02 0.50 1.346 0.022 2.07E-03Wauk VRG330 2310021402 0 / 23 68 3.47% 0.008038 3.46E-02 0.50 0.1104 0.005(2)2.14E-03CAT G379 NA(3)2310021402 0 / 14 327 10.17% 0.008710 3.75E-02 0.50 0.1592 0.009(4)2.32E-03Wauk F1197 G 2310021402 0 / 13 183 5.28% 0.007253 3.13E-02 0.50 0.1 0.020(2)1.93E-03CAT G3306 TA 2310021402 0 / 13 203 5.86% 0.008098 3.49E-02 0.50 1.657 0.012 2.16E-03CAT G342 NA(5)2310021402 0 / 10 225 5.00% 0.008588 3.70E-02 0.101 0.0317 0.009(2)2.29E-03CAT G3406 TA 2310021402 0 / 9 290 5.80% 0.007407 3.19E-02 0.50 0.614 0.017 1.98E-03Wauk F817 G 2310021402 0 / 7 87 1.35% 0.007253 3.13E-02 0.50 0.1 0.17(6)1.93E-03AJAX C-42 2310021101 5 / 0 40 0.44% 0.009900 1.72E-01 4.4(8)3.3 0.8 2.64E-03CAT G398 TA(3)2310021403 0 / 5 605 6.72% 0.008710 3.75E-02 0.50 0.1592 0.009(4)2.32E-03AJAX DPC-140 2310021102 5 / 0 134 1.49% 0.008200 1.43E-01 0.50 1.3 0.7 2.19E-03SUPERIOR 8GTLB 2310021203 4 / 0 1100 9.77% 0.008788 3.07E-04 0.50 3.6 0.4 2.34E-03CAT G379 TA(3)2310021402 0 / 4 417 3.70% 0.008710 3.75E-02 0.50 0.1592 0.009(4)2.32E-03CAT G3516 TALE 2310021203 3 / 0 1245 8.30% 0.007364 2.58E-04 0.50 1.805 0.28 1.96E-03Wauk F11 G 2310021402 0 / 3 119 0.79% 0.007600 3.27E-02 0.50 0.079 0.027(2)2.03E-03CAT G3306 2310021402 0 / 3 183 1.22% 0.007579 3.27E-02 0.50 0.146 0.012 2.02E-03Wauk VRG220(7)2310021301 0 / 3 45 0.30% 0.008038 3.46E-02 12.951(8)1.104 0.05(2)2.14E-03Wauk VRG330 TA 2310021402 0 / 3 100 0.67% 0.007307 3.15E-02 0.50 0.1587 0.002(2)1.95E-03Wauk L7042 GL 2310021203 3 / 0 1357 9.04% 0.007237 2.53E-04 0.50 2.85 0.95(2)1.93E-03Wauk L7042 G 2310021403 0 / 3 961 6.40% 0.007180 3.09E-02 0.50 1.3 0.025(2)1.91E-03CAT G342 TA(5)2310021402 0 / 2 225 1.00% 0.008588 3.70E-02 0.101 0.0317 0.009(2)2.29E-03TOTAL 199 100%WeightedAverage EFs0.03 0.53 1.17 0.17 2.12E-031. NOx emission factors were adjusted for 30 TAC, Chapter 117, Subchapter D, Division 2 nonattainmentrule. Also, ERG assumed any four stroke rich burnengine, greater than 50 Hp and located in anonattainment area, would have non-selective catalytic reduction (NSCR) control technology. ERG has applied a 90% reduction to the emission factors forCO and VOC for these engines.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 same as CAT G399 TA.4. 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, so it was assumed that they havethe same emission factors.No control device is needed since NOx emissions arebelow Texas mandated emission standards.6. Total Hydrocarbon.7. Based on discussions with Waukesha, the VRG220 and VRG310 models have the same emission factors asthe 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 e missions of CO for engines equipped with

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

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

90% control efficiency adjustment.

All PM and SO 2 emission factors were obtained from AP-42 Section 3.2 (US EPA,

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

or a 4 stroke rich-burn engine. The PM emission fa ctor represents both PM 10 and PM 2.5 . The

SO 2 emission factor assumes the sulfur content in natu ral gas is 0.002 grams per standard cubic

foot.

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

compression load by engine type (F 2 j ), a single set of weighted emission factors was ca lculated

for each pollutant in each attainment status catego ry.

Compression requirements for county i, C i :

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

pressure ratio and volume or mass flow rate. In pa rticular, 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 t he 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 me chanical work that is required to compress

the natural gas produced by the well. This mechani cal 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 rel ationship 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 dir ect relationship of mechanical work to

volume of fuel burned, one would expect a 100 Hp en gine 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 co mpressors at the county level.4-11

The 2005 HARC report developed compression require ments ranging between 3.1 and

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

two nonattainment areas (Houston and Dallas) by obt aining 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, a nd 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

adjusted 2 for the findings in a 2008 Pollution Solutions stu dy, yields a compression requirement

of 2.97 (Hp-hr/Mscf).

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

Those compression requirements were applied to coun ties 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) ent itled “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 t hat was consumed by the compressor engines and consequently overestimated the amount of emissions fro m these engines. A more recent study by Pollution Solutions (2008) entitled “2005 and 2007 Compressor Engine Emiss ions and Load Factors Report” determined average load factors for three engine categories, all o f which were less than 100%. For engines less than 240 Hp, the load factor was 70%. For engines between 240-500 Hp, the loa d factor was 69%. For engines greater than 500 Hp, the load factor was 58%. Applying the load factors reduce d the estimated 2005 emissions of NO

x by 34% and

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

HAP Emissions for Compressor Engines

HAP emissions from compressor engines were calcula ted using VOC and PM speciation

data as follows:

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

where:

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

E VOC = VOC emissions [tons/yr]

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

and

E

PM-HAP = E

PM x ( E %PM-HAP

/100)

where:

E

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

E PM = 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, EF ik :

Appendix D presents county-level emissions for com pressor engines corresponding to

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

through 4-9 depict the distribution of emissions fo r 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 distr ibutions 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 SC C for Texas Attainment

Counties

SCC PM NO

x CO VOC SO 2 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 SC C for Dallas Nonattainment

Counties

SCC PM NO

x CO VOC SO 2 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 SC C for Houston

Nonattainment Counties

SCC PM NO

x CO VOC SO 2 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 Engine s <50 Hp 2310021102 Natural Gas Fired 2-Cycle Lean Burn Compressor Engine s 50 To 499 Hp 2310021103 Natural Gas Fired 2-Cycle Lean Burn Compressor Engine s 500+ Hp 2310021201 Natural Gas Fired 4-Cycle Lean Burn Compressor Engine s <50 Hp 2310021202 Natural Gas Fired 4-Cycle Lean Burn Compressor Engine s 50-499 Hp 2310021203 Natural Gas Fired 4-Cycle Lean Burn Compressor Engine s 500+ Hp 2310021301 Natural Gas Fired 4-Cycle Rich Burn Compressor Engine s <50 Hp 2310021302 Natural Gas Fired 4-Cycle Rich Burn Compressor Engine s 50 To 499 Hp 2310021303 Natural Gas Fired 4-Cycle Rich Burn Compressor Engine s 500+ Hp 2310021401 Natural Gas Fired 4-Cycle Rich Burn Compressor Engine s <50 Hp W/ Nscr 2310021402 Natural Gas Fired 4-Cycle Rich Burn Compressor Engine s 50-499 Hp W/ Nscr 2310021403 Natural Gas Fired 4-Cycle Rich Burn Compressor Engine s 500+ Hp W/ Nscr

Example Calculation for Compressor Engines

Using the equation provided above, ERG calculated NO

x emissions in Anderson County

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

where:

E ik = NO

x emissions in Anderson County [tons/year]

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

F 1 i = 0.8572 (the fraction of wells requiring compressi on in Anderson County)

F 2 j = 0.0013 (the fraction of compression load represe nted by natural gas fired 2-cycle lean burn compressor engines)         ∗

∗ ∗

× = 180

, 907 2 1 i

jk j i

i ik C

EF F F TGP E4-15

EF jk = 7.57 (the NO

x emission factor for natural gas fired 2-cycle lean burn compressor engines) [g/Hp-hr]

C i = 3.03 (the compression requirements for Anderson County) [Hp-hr/Mscf] 907,180 is the conversion factor from grams to tons of emissions

Therefore:

E ik = 12,044,998 [Mscf] x ((0.8572 * 0.0013 * 7.57 [g N O

x/Hp-hr] * 3.03 [Hphr/Mscf])/907,180)

E ik = 0.339373 [tons NO

x /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 l ocations 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 smalle r engines than wellhead compressor

engines.

Emissions from pumpjack engines were calculated us ing a methodology similar to that

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

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

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

equation:

where:

E ik

is the emissions for county i, and pollutant k [to ns/yr]

W i is the total number of active oil wells in county i [wells] f pumpjack is the fraction of oil wells with artificial lift e ngines

e pumpjack is the fraction of artificial lift engines that ar e electrically operated

EF k 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

t annual is the annual number of hours the engine is used [ hr/yr] 907,180 is the conversion factor from grams to tons of emissions



# ( )       ∗

∗ ∗ ×

− × × = 180

, 907 1 annual k pumpjack pumpjack i ik t LF HP EF

e f W E4-16

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

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

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

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

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

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

Fraction of oil wells with artificial lift engines, f pumpjack :

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

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

an artificial lift engine because the wells have en ough 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, ins talls, and repairs pumpjacks and pumpjack

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

located in Texas are older than one year and thus w ould 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:

       

− = > 2008) 5, February on Wells Oil Active (Total 2007) in Completed Wells (Oil 1 Old Year 1 Wells Oil of Fraction

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

completion, and plugging summaries which are availa ble at:

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

distribution data showing the number of regular pro ducing 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.rr c.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 ol d was determined to be 0.967 (1 – (5,084

/ 153,831) = 0.967). The actual fraction may be sl ightly 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 a ll wells completed in 2007 were

completed on February 5, 2007.

Fraction of artificial lift engines that are electr ically operated, e pumpjack :

ERG assumed that 70% of the artificial lift system s 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 arti ficial lift engines, three of which were

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

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

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

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

the artificial lift engine. Fractions of artificia l lift engines that are electrically operated range d

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

70%.

Emission factor for pollutant k, EF k :

Through various phone interviews, ERG determined t hat the most popular pumpjack

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

range from about 5 to 32 horsepower (depending on t he 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 emis sion factors was calculated for each pollutant

assuming equal fuel usage by each engine size for a ll pollutants.

The New Source Performance Standard (NSPS), Subpar t JJJJ limits emissions of NO

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

horsepower that were manufactured after July 1, 200 8. 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 man ufactured prior to July 1, 2008 and/or4-18

were not modified or reconstructed after June 12, 2 006. Therefore, no pumpjack engines in this

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

All PM and SO 2 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 PM 10 and PM 2.5 . The SO 2 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) (EF

jk ) Arrow

C Series

Model Horsepower

(Hp) Fuel

Consumption (MMBtu/Hp-hr) PM NO

x CO VOC SO 2 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 acros s 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 en gine power and the minimum power to be a

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

power curve, the report estimated an average loadin g 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, t annual :

The 2006 New Mexico study assumed that pumpjack en gines operate nearly without

interruption year-round (8,760 hours per year). Ho wever, 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 h ours. ERG also verified this assumption

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

ERG recommends surveying operators to verify this a ssumption. 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 calculate d using VOC and PM speciation

data as follows:

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

where:

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

E VOC = VOC emissions [tons/yr]

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

and

E

PM-HAP = E

PM x ( E %PM-HAP

/100)

where:

E

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

E PM = 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, E ik :

Appendix E presents county-level pumpjack engine e missions 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 NO

x emissions in Anderson County

from pumpjack engines as follows:

where:

E ik

= NO

x emissions in Anderson County [tons/yr]

W i = 456 (the total number of active oil wells in And erson County) [wells] f pumpjack = 1 (the fraction of oil wells in Anderson County w ith artificial lift engines)

e pumpjack = 0.70 (the fraction of artificial lift engines in Anderson County that are electrically operated)

EF k = 14.75 (the emission factor for NO

x ) [g/Hp-hr]

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

LF = 0.71 (the load factor of the engine while operat ing)

t annual = 4,380 (is the annual number of hours the engine is used) [hr/yr] 907,180 is the conversion factor from grams to ton s of emissions

Therefore:

E ik

= 456 x 1 x (1 - 0.70) x ((14.75 [g NO

x /Hp-hr] x 20.55 [Hp] x 0.71 x 4,380 [hr/yr])/907,180))

E ik

= 142.14 [tons NO

x

/yr]

4.3 Dehydrators

A dehydrator is used to remove moisture from produ ced 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 glyco l. The water vapor in the gas stream becomes

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

absorption process, the glycol also absorbs some me thane 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 flas h vessel. In those dehydrators,

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

dehydrator during both of these steps.

Depending upon the dehydrator equipment, these emi ssions may be recaptured and

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

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



# ( )       ∗

∗ ∗ ×

− × × = 180

, 907 1 annual k pumpjack pumpjack i ik t LF HP EF

e f W E4-21

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

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

emissions of CO and NO

x .

4.3.1 Dehydrator Flash Vessels and Regenerator Vents

Emissions from dehydrator flash vessels and regene rator vents were calculated using a

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

place of the CENRAP emission factors, ERG derived e stimates 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 f lash vessel and glycol regenerator vent

emissions with the following equation:

where:

E ik

is the emissions for county i, and pollutant k [to ns/yr]

TGP i is the total production of natural gas from gas we lls in county i [MMscf/yr]

EF k 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 c ounty i, TGP i :

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

counties had no gas production in 2008.

Emission factor for pollutant k, EF k :

In place of the CENRAP emission factors, ERG deriv ed estimates of dehydrator emission

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

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

were prepared by the operators using Gly-Calc softw are. 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 configu rations, as well as control technologies, are in

use for natural gas production in Texas. There wer e 82 complete samples in the dataset,      

× × = 000

,2 1

k i ik EF TGP E4-22

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

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

These emission factors may produce emissions estim ates that are lower than actual

emissions at the area-source dehydrators in the sta te. 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 small er area sources. Control requirements are

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

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

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

Texas and is a good composite representation of sta tewide 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, E ik :

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

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

variables discussed above.

Example Calculation for Dehydrator Flash Vessels an d Regeneration Vents

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

County from dehydrator flash vessels and regenerati on vents as follows:

where:

E ik

= (the Benzene emissions for Anderson County) [ton s/yr]

TGP i = 12,045 (the total production of natural gas from gas wells in Anderson County) [MMCF/yr]

EF k = 0.38 (the emission factor for Benzene) [lb/MMscf ]      

× × = 000

,2 1

k i ik EF TGP E4-23

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

Therefore:

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

E ik = 2.29 [tons/yr]

4.3.2 Glyol Regenerator Boilers

Emissions from glycol regenerator boilers were cal culated 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 fr om dehydrator regenerator boilers with the

following equation:

where:

E ik

is the emissions for county i, and pollutant k [to ns/yr]

TGP i is the total production of natural gas from gas we lls in county i [MMscf/yr]

EF k 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 c ounty i, TGP i :

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

counties had no gas production in 2008.

Emission factor for pollutant k, EF k :

ERG used the CENRAP emission factors for regenerat or boiler emissions. The

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

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

Table 4-13. Emission Factors for NO

x and CO Emissions from Dehydrator Regenerator Boilers

Pollutant Emission Factor (lb/MMscf)

NO

x 0.052

CO 0.105      

× × = 000

,2 1

k i ik EF TGP E4-24

Emissions for county i, and pollutant k, E ik :

Appendix E presents county-level dehydrator regene rator boiler emissions corresponding

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

discussed above.

Example Calculation for Glycol Regenerator Boilers:

Using the equation provided above, ERG calculated NO

x emissions in Anderson County

from glycol regenerator boilers as follows:

where:

E ik

= NO

x emissions in Anderson County [tons/yr]

TGP i = 12,045 (the total production of natural gas from gas wells in Anderson County) [MMscf/yr]

EF k = 0.052 (the emission factor for NO

x ) [lb/MMscf] 2,000 is the conversion factor from pounds to tons of emissions

Therefore:

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

E ik

= 0.31 [tons NO

x

/yr]

4.3.3 Dehydrator Emission Control Device

Emissions from dehydrator control devices were cal culated 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 1 3.5 for NO

x 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 e missions data submitted to TCEQ by operators

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

where:

E ik

is the emissions for county i, and pollutant k [to ns/yr]

TGP i is the total production of natural gas from gas we lls in county i [MMscf/yr]

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

D is the density of the gas flared [lbs/MMscf]      

× × = 000

,2 1

k i ik EF TGP E



### 000 ,2 1 1
× × × × × = k

flared i ik 

### EF

HV D f TGP E

### 4-25

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

EF k 

### 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 c ounty i, TGP i 

### :

Natural gas production data by county ( TGP i 

### ) was provided for 2008 by the TRC. 57

counties had no gas production in 2008.

Fraction of produced gas that is flared, F flared 

### :

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 de hydrators in use at point sources in Texas.

The sum of the reported emissions from flash vessel s 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 r eported in those 82 samples, producing a

weighted average. Because emissions are reported i n 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 fl ared/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 fl ared by assuming it was equivalent to

the density of the dry gas produced by the dehydrat or. 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 s um 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 10 6 

### standard cubic feet per MMscf, to yield a factor w ith units of pounds

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

density of the gas produced is 0.047 pounds per sta ndard 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, EF k 

### :

ERG used the CENRAP emission factors for dehydrato r control emissions. Although the

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

and regenerator vent emissions are controlled by in cinerators, 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 mi llion Btu (lbs/MMBtu) of gas flared. These

emission factors are shown in Table 4-14 below.

Table 4-14. Emission Factors for NO

x and CO Emissions

from Dehydrator Controls (Flares)

Pollutant Emission Factor (lb/MMBtu)



### NO

x 

### 0.068

CO 0.37

Emissions for county i, and pollutant k, E ik 

### :

Appendix E presents county-level dehydrator contro l 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 NO

x 

### emissions in Anderson County

from dehydrator controls as follows:

000 ,2 1 1
× × × × × = k

flared i ik 

### EF

HV D f TGP E

### 4-27

where:

E ik



### = NO

x 

### emissions for Anderson County [tons/yr]

TGP i 

### = 12,045 (the total production of natural gas from gas wells in Anderson County) [MMscf/yr]

F flared 

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

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

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

EF k 

### = 0.068 (the NO

x 

### emission factor) [lbs/MMBtu] 2,000 is the conversion factor from pounds to tons of emissions

Therefore:

E ik 

### = 12,045 [MMscf/yr] x 13.41 [lbs flared/MMscf prod uced] x (1/46,952 [lbs/MMscf]) x 1,209 [MMBtu/MMscf] x 0.068 [lbs/MM Btu] x (1/2,000)

E ik



### = 0.14 [tons NO

x



### /yr]

4.4 Oil and Condensate Storage Tanks



### Storage tanks are used in a variety of application s 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 mix ture of liquid and gaseous organic

compounds, nitrogen, carbon dioxide, water, sand, a nd other impurities. The mixture is typically

passed through a three-phase separator, which allow s the water, oil and gas to separate. The

liquid oil and water components are then piped to s torage tanks. If the well produces gas, it is

possible that liquids may condense out of the gas a s 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 wellh ead and gathering sites are composed

of flashing losses, working losses, and breathing l osses. Flashing losses occur when a produced

liquid (crude oil or condensate) with entrained gas es 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 filli ng of the tank. Breathing losses (also called

standing losses) occur due to the normal evaporatio n of liquid in a tank. Breathing losses are

vapors that are produced in response to the daily t emperature change.

### 4-28

Emissions from oil and condensate storage tanks we re 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 emis sion 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 vap or recovery units. For this 2008 inventory,

ERG calculated county-level emissions from oil stor age tank and condensate storage tank vent

emissions with the following equations:

and

where:

E ik



### is the emissions for county i, and pollutant k [to ns/yr]

TOP i 

### is the total production of oil from oil wells in c ounty i [BBL/yr]

TCP i 

### is the total production of condensate from gas wel ls in county i [BBL/yr]

EF ik 

### 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, TOP i 

### :

Oil production data by county ( TOP i 

### ) was provided for 2008 by the TRC. 42 counties

had no oil production in 2008.

Total production of condensate from gas wells in co unty i, TCP i 

### :

Condensate production data by county ( TOP i 

### ) was provided for 2008 by the TRC. 80

counties had no condensate production in 2008.

Emission factor for county i, and pollutant k, EF ik 

### :

VOC Emission Factors : The VOC emission factors for oil storage tank bat teries and

condensate storage tank batteries are taken from th e 2009 TERC study and are in units of pounds

per barrel of oil/condensate produced and are shown in Table 4-15 below.      



### × × = 000

,2 1

ik i ik 

### EF TOP E

     



### × × = 000

,2 1

ik i ik 

### EF TCP E

### 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 da ta published in the 2009 TERC study. Tables

3-4 and 3-5 in the TERC study showed the measured v ent 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, et hylbenzene, 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, E ik 

### :

Appendix E present county-level oil storage tank a nd condensate storage tank vent

emissions corresponding to the production of oil an d condensate at oil wells and natural gas

wells located in each county, based on the input va riables 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:

E ik



### = VOC emissions for Anderson County [tons/yr]

TOP i 

### = 678,901 (the total production of oil from oil we lls in Anderson County) [BBL/yr]

EF ik 

### = 1.60 (the VOC emission factor for Anderson Count y) [lb/BBL]

     



### × × = 000

,2 1

ik i ik 

### EF TOP E

### 4-30

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

Therefore:

E ik 

### = 678,901 [BBL/yr] x 1.6 [lb/BBL] x (1/2,000)

E ik 

### = 543 [tons/yr]

4.5 Oil and Condensate Loading



### Oil and condensate stored in field storage tanks i s transferred to trucks and railcars and

shipped to refineries for further processing. Fugi tive VOC emissions are released from these

loading processes as the vapors in the receiving ve ssel are displaced by the liquids from the

storage tanks. These vapors are normally vented to the atmosphere.

Emissions from oil and condensate loading were cal culated using the emission estimation

methodology in the 2009 TCEQ study. This methodolo gy 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 fac tors were multiplied by county-specific 2008

oil and condensate production data obtained from th e TRC to derive county-specific emission

estimates. ERG obtained monthly temperature data f or 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 mole cular 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 multip lying the emission factor by county-level oil

and condensate production data. The calculations a ssume that venting emissions are

uncontrolled by flares or vapor recovery units. Th e AP-42 equation to calculate loading

emission factors is shown in the following equation

.

### 4-31

where:

LL ik 

### 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)

P i 

### is the true vapor pressure of liquid loaded [psia] for county i

M is the molecular weight of tank vapors [lb/lb-mole ]

T i 

### is the temperature of bulk liquid loaded [ o 

### R] 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 dedicate d 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, P i 

### :

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 conde nsate 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 tr ue vapor pressure for the county-specific

average temperature is calculated for oil loading w ith the equation.

where:

P i 

### is the true vapor pressure of liquid loaded [psia] for county i

T i 

### is the temperature of bulk liquid loaded [ o 

### F] for county i

The true vapor pressure for the county-specific av erage temperature is calculated for

condensate loading with the equation.

where:

P i 

### is the true vapor pressure of liquid loaded [psia] for county i

T i 

### is the temperature of bulk liquid loaded [ o 

### F] for county i

These formulas are derived from linear interpolati on of the slope and intercept of the line

formed between the values for the true vapor pressu re of crude oil RVP 5 (representing oil) and

gasoline RVP 7 (representing condensate) at 55 degr ees Fahrenheit and 75 degrees Fahrenheit.         

### ∗ ∗ × =

i i

ik 

### T M

P S LL 46. 12



## ( ) 58.0 057 .0

− × = i i 

### T P



## ( ) 03.1 077 .0

− × = i i 

### T P

### 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 Select ed 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, T i 

### :

The average 2008 temperature data, degrees Fahrenh eit, 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 t he average ambient air temperature.

Loading loss for county i, and pollutant k, LL ik 

### :

The loading loss is the county-specific emission f actor 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-lev el emissions from oil loading

emissions and condensate loading emissions with the following equations:

and      



### × × × = 000

,2 1 42 k i ik 

### LL TOP E

     



### × × × = 000

,2 1 42 ik i ik 

### LL TCP E

### 4-33

where:

E ik



### is the loading emissions for county i, and polluta nt k [tons/yr]

TOP i 

### is the total production of oil from oil wells in c ounty i [BBL/yr]

TCP i 

### is the total production of condensate from gas wel ls in county i [BBL/yr]

LL ik 

### is the loading loss (emission factor) for pollutan t 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, TOP i 

### :

Oil production data by county ( TOP i 

### ) was provided for 2008 by the TRC. 42 counties

had no oil production in 2008.

Total production of condensate from gas wells in co unty i, TCP i 

### :

Condensate production data by county ( TOP i 

### ) was provided for 2008 by the TRC. 80

counties had no condensate production in 2008.

Loading loss, LL ik 

### :

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 c onstituent of

the vapors emitted during oil and condensate loadin g. The benzene, toluene, ethylbenzene, and

xylene emission factors for oil loading and condens ate 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 combina tion with the measured weight percent VOC

data from those same tables and the VOC emission fa ctors 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 un its 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, Ethylben zene, 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, E ik 

### :

Emissions for oil and condensate loading racks for each county are calculated by

multiplying a county-specific loading loss factor b y the county-specific oil and condensate

production. Appendix E present county-level oil co ndensate loading rack emissions

corresponding to the production of oil and condensa te at oil wells and natural gas wells located

in each county, based on the input variables discus sed 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:

LL ik 

### = (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 lo ading operation))

P i 

### = 3.1 (the true vapor pressure of liquid loaded fo r Anderson County) [psia]

M = 50 (the molecular weight of tank vapors) [lb/lb- mole]

T i 

### = 524.27 (the temperature of bulk liquid loaded fo r Anderson County) [ o 

### R]

where:

E ik 

### = loading VOC emissions for county i, and pollutan t k [tons/yr]

TOP i 

### = 678,901 (the total production of oil from oil we lls in Anderson County) [BBL/yr]

LL ik 

### = 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 M

P S LL 46. 12



    



### × × × = 000

,2 1 42 k i ik 

### LL TOP E

### 4-35

Therefore:

LL ik 

### = 12.46 x ((1.00 x 3.1 [psia] x 50 [lb/lb-mole])/52 4.27 [ o 

### R])

LL ik 

### = 3.684 [lb/1,000 gal of liquid loaded]

E ik 

### = 678,901 [BBL/yr] x 3.684 [lb/1,000 gal of liquid loaded] x 42 x (1/2,000)

E ik



### = 52.52 [tons VOC/yr]

4.6 Well Completions



### Following drilling and casing, a well must be “com pleted.” Completion is the process

which enables the well to produce oil or gas. To c omplete the production well, casing is

installed and cemented and the drilling rig is remo ved 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 addr esses VOC emissions associated with the

completion process at oil and gas wells. County-le vel emissions from this source were estimated

for the purpose of this inventory.

Emissions from well completions were calculated us ing the methodology from the 2008

CENRAP study (Bar-Ilan, et al., 2008). Emissions f rom 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. Emission s rates are evaluated at standard temperature

and pressure (STP).

The calculation methodology for completion emission s follows the following equations:

907200 000035 .0 ) / ( )

(

, i

gas vented

i completion f

T MW R V P E ×        

×

× ×

=

where:

E completion,i is the emissions of pollutant i from a single completion event [ton/event]

P is atmospheric pressure [1 atm]

V vented is the volume of vented gas per completion [MCF/eve nt]

R is the universal gas constant [0.082 L-atm/mol- o K]

MW gas is the molecular weight of the gas [g/mol]

T is the atmospheric temperature [298 o K]

0.000035 is the conversion factor from Mscf to lite rs f i is the mass fraction of pollutant i in the vented gas 907,200 is the conversion factor from grams to tons of emissions4-36

The total emissions from all completions occurring in a county can be evaluated

following:

county i completion TOTAL completion S

E E ×

=

, ,

where:

E completion,TOTAL are the total emissions county-wide from completion s [tons/year]

E completion,i are the completion emissions from a single completi on event [tons/event]

S county is the county-wide new well and recompleted well co unt

No data were available to account for the number o f completions that were completed

using green completion or add-on control technologi es. While these technologies exist and are

used to reduce emissions, no data is currently avai lable 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, V vented :

ERG was unable to obtain estimates for the volume of vented gas per completion from

the TRC. Therefore, ERG used the average volume ve nted presented in the 2008 CENRAP

study. This data was presented on a basin-level ba sis. The data obtained is summarized in

Table 4-18 below.

Table 4-18. 2008 CENRAP Data for Volume of Gas Vented per Completi on

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 base d on the county’s corresponding

basin.

Mass fraction for a single pollutant, f i :

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, c flare and the number of green completions, c green :

ERG was unable to obtain estimates for the number of completions controlled by flares

and the number of green completions. Therefore, ER G used default values presented in the 2008

CENRAP study, which was 0 for both parameters.

County-level new/recompleted well count, S county :

ERG obtained county-level data for the number of n ew 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 b oth). 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 count y, 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 w ell completions in 2008.

Emissions by county E completion,TOTAL :

Appendix E presents county-level well completion e missions 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:

907200 000035 .0 ) / ( )

(

, i

gas vented

voc completion f

T MW R V P E ×        

×

× ×

=

where:

E completion,voc = the VOC emissions in Anderson County from a single oil well completion event [ton/event]

P = 1 (atmospheric pressure) [atm]

V vented = 2,417 (the volume of vented gas per completion f or Anderson County (East Texas Basin)) [MCF/event]

R = 0.082 (the universal gas constant) [L-atm/mol- o K]

MW gas = 27 (the molecular weight of the gas) [g/mol]

T = 298 (the atmospheric temperature) [ o K]

0.000035 is the conversion factor from Mscf to lite rs f i = 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:

E completion,voc = ((1 atm x 2,417 [MCF/event])/((0.082 [L-atm/mol- o K]/27 [g/mol]) x 298
[ o K] x 0.000035) x 0.141/907200

E completion,voc = 11.86 [tons VOC/event]

The total emissions from all completions occurring in Anderson County can be evaluated

following:

county voc completion TOTAL completion S

E E ×

=

, ,

where:

E completion,TOTAL = the total VOC emissions from completions in Ande rson County [tons VOC/year]

E completion,voc = 11.86 (completion emissions from a single comple tion event) [tons VOC/event]

S county = 45.94 (the county-wide new well and recompleted w ell count for Anderson County) [oil well completion events/yr]

Therefore:

E completion,voc = 11.86 [tons VOC/event] x 50 [oil well completion events/yr]

E completion,voc = 544.76 [tons VOC/yr]4-39

4.7 Wellhead Blowdowns

Wellhead blowdowns refer to the practice of ventin g gas from wells that have developed

some kind of cap or obstruction before any addition al 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 ev ent, 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). Emissi ons 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 compositio n analyses. The emissions are also estimated

based on the frequency of blowdowns. Emissions rat es 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 equ ations:

907200 000035 .0 ) / ( )

(

, i

gas vented

i blowdown f

T MW R V P E ×        

×

× ×

=

where:

E completion,i is the emissions of pollutant i from a single blowdown event [ton/event]

P is atmospheric pressure [1 atm]

V vented is the volume of vented gas per blowdown [MCF/event ]

R is the universal gas constant [0.082 L-atm/mol- o K]

MW gas is the molecular weight of the gas [g/mol]

T is the atmospheric temperature [298 o K]

0.000035 is the conversion factor from Mscf to lite rs f i 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 i n a county can be evaluated

following:4-40 wells blowdown i blowdown TOTAL blowdown N N E E ×

× =

, ,

where:

E

blowdown,TOTAL are the total emissions county-wide from blowdowns [tons/year]

E blowdown,I are the blowdown emissions from a single blowdown e vent [tons/event]

N blowdown is the number of blowdowns per well in the county

N wells is the total number of active wells in the county

No data were available to account for the number o f blowdowns using green completion

or add-on control technologies. While these techno logies exist and are used to reduce emissions,

no data is currently available to estimate the exte nt 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 the se parameters.

Volume of vented gas per blowdown, V vented :

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. Th e 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 va lues from the other basins.

The data were applied to each county in Texas base d on the county’s corresponding

basin.4-41

Mass fraction for a single pollutant, f i :

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, N blowdown :

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. Th e 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 va lues from the other basins.

The data were applied to each county in Texas base d on the county’s corresponding

basin.

County-level well count, N wells :

ERG obtained county-level data for the number of w ells from the TRC for each county

included in this analysis. The TRC data (for onsho re 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, c flare and the number of green blowdowns, c green :

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 E blowdown,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:

907200 000035 .0 ) / ( )

(

, i

gas vented

voc blowdown f

T MW R V P E ×        

×

× ×

=

where:

E

blowdown,voc = the VOC emissions in Anderson County from a single oil wellhead blowdown event [ton/event]

P = 1 (atmospheric pressure) [atm]

V vented = 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- o K]

MW gas = 27 (the molecular weight of the gas) [g/mol]

T = 298 (the atmospheric temperature) [ o K]

0.000035 is the conversion factor from Mscf to lite rs f i = 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:

E blowdown,voc = ((1 [atm] x 31.7 [MCF/event])/((0.082 [L-atm/mol- o K]/27 [g/mol]) x 298
[ o K] x 0.000035) x 0.141/907200

E blowdown,voc = 0.1554 [tons/event]

The total emissions from all blowdowns occurring i n Anderson County can be evaluated

following:

wells blowdown voc blowdown TOTAL blowdown N N E E × × =

, ,4-43

where:

E

blowdown,TOTAL = the total VOC emissions county-wide from blowdown s [tons/year]

E blowdown,voc =0.1554 (the VOC blowdown emissions from a single b lowdown event) [tons/event]

N blowdown =1.09 (the number of blowdowns per well in Anderson County (East Texas Basin)) [events/wellhead/yr]

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

Therefore:

E blowdown, TOTAL

= 0.1554 [tons VOC/event] x 1.09 [events/wellhead/ yr] x 456 [wells]

E blowdown, TOTAL

= 77.24 [tons VOC/yr]

4.8 Pneumatic Devices

Pneumatic devices are used for a variety of gas we ll processes and are powered by highpressure produced gas. These devices include trans ducers, liquid level controllers, pressure

controllers and positioners. During the normal ope ration 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 u sing the methodology from the 2008

CENRAP study (Bar-Ilan, et al., 2008). In this emi ssion estimation approach, emissions from

pneumatic devices at a single well site are calcula ted using the following equation:

000035 .0 907200 ,

× ×         ×      

× × = 

## ∑

T MW R P t N V f E

gas i annual

i i j

j pneumatic

where:

E

pneumatic,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 f j is the mass fraction of pollutant j in the vented gas

V i is the volumetric bleed rate from device i [scf/hr/device]

N i is the total number of device i owned by the participating companies

t annual is the number of hours per year that devices are o perating

P is the atmospheric pressure [1 atm]

R is the universal gas constant [0.082 L-atm/mol- o K]

MW gas is the molecular weight of the gas [g/mol]

T is the atmospheric temperature [298 o K]

0.000035 is the conversion factor from Mscf to lite rs4-44

County-wide emissions are calculated using the fol lowing equation:

well j pneumatic TOTAL pneumatic N

E E ×

=

, ,

where:

E

pneumatic,TOTAL is the total pneumatic device emissions in the coun ty [ton/yr]

E pneumatic,j is the pneumatic device emissions for a single well of pollutant j [ton/yr]

N well 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, N well :

Total active wells by county for the full 2008 yea r are not readily available from the TRC

website. However, well distribution data by countyis available from the TRC website on a biannual (February and September) basis and can be fo und at:

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

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

Volumetric bleed rate from device i, V i :

Bleed rates for various devices are presented in a 2004 EPA Natural Gas Star program

study. We have used these when calculating emissio ns from pneumatic devices at gas

production sites. This data is summarized in Table 4-21.

Total number of devices, N i :

The 2008 CENRAP study obtained basin-level data fo r the total number of devices per

well from survey data. The same value for each dev ice 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

, t annual :

ERG has assumed the annual operating hours for the se devices is 8,760.4-45

Molecular weight of gas, MW gas :

The 2008 CENRAP study obtained basin-level data fo r the gas molecular weight from

survey data. Where survey data was not available f or 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, f j :

The 2008 CENRAP study obtained basin-level data fo r the mass fraction of VOC from

survey data. Where survey data was not available f or 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 tota l 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

Duro a 2 / 31 0 / 15.2 1 / 16.8 0 / 13.6 0 / 0 20 0.11

Marathon

Thrust

Belt a 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 0.105 4

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 basi ns.4-46

Emissions by county E pneumatic,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:

000035 .0 907200 ,

× ×         ×      

× × = 

## ∑

T MW R P t N V f E

gas i annual

i i j

j pneumatic

Where:

E

pneumatic,j = VOC emissions from one well in Anderson County [ tons/well-year] 907,200 is the conversion factor from grams to tons of emissions f j = 0.1054 (the VOC fraction in the vented gas in An derson County)

V i = 0.031 for liquid level controllers and 0.0168 for pressure controllers (bleed rate for devices present in wells in Anderson County) [Mcf/d evice-hr]

N i = 2 for liquid level controllers and 1 for pressur e controllers (number of devices present in wells in Anderson County)

t annual = 8,760 (annual operating hours of wells in Ander son County) [hr/yr]

P = 1 (standard pressure) [atm]

T = 298 (standard temperature) [ o K]

R = 0.082 (universal gas constant) [L-atm/mol- o K]

MW gas = 19.68 (molecular weight of vented gas at wells i n Anderson County) [g/mol]

0.000035 is the conversion factor from Mscf to lite rs

Therefore:

E pneumatic,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- o K] / 19.68 [g/mol]) * 298 [ o K] * 0.000035))

E pneumatic,j = 1.845 [tons VOC/well-yr]

For all wells in Anderson County:

well j pneumatic TOTAL pneumatic N

E E ×

=

, ,

Where:

E

pneumatic,TOTAL = VOC emissions from all gas wells in Anderson Coun ty [tons/yr]

E pneumatic,j = 1.845 [tons VOC/well-yr]

N well = 133 (number of wells in Anderson County)4-47

Therefore:

E pneumatic,TOTAL = 1.845 [tons VOC/well-yr] x 133 [wells]

E pneumatic,TOTAL = 245 [tons VOC/yr]

4.9 Fugitive Emissions (Equipment Leaks)

All oil and gas producing sites have a system of p umps and piping to transport oil and gas

from the wellhead to the processing area. These pu mps 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 em issions while oil and gas product flows

through them. County-level emissions from these so urces 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 thi s methodology, fugitive emissions from a

single well site may be calculated using the follow ing equation:



# ∑ ×

× × × =

i j annual i i j fugitive Y

t N EF E 0011 .0

,

where:

E

fugitive,j is the fugitive emissions for a single typical wel l for pollutant j [ton/yr/well]

EF i is the emission factor of Total Organic Carbon (TO C) for a single component i [kg/hr/component]

N i is the total number of components of type i

t annual is the annual number of hours the well is in opera tion [hr/yr]

Y j is the mass fraction of pollutant j to TOC in the vented gas 0.0011 is the conversion factor from tons to kilogr ams

County-wide fugitive emissions are calculated usin g the following equation:

well j fugitive TOTAL fugitive N

E E ×

=

, ,

where:

E

fugitive,TOTAL is the total fugitive emission in the county [ton/y r]

E fugitive,j is the fugitive emissions for a single well of poll utant j [ton/yr]

N well 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, N well :

Total active wells by county for the full 2008 yea r are not readily available from the TRC

website. However, well distribution data by countyis available from the TRC website on a biannual (February and September) basis and can be fo und at:

http://www.rrc.state.tx.us/data/wells/wellcount/ind ex.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, EF i :

AP-42 emissions factors were used to calculate fug itive 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 Emis sion 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, N i :

The 2008 CENRAP study obtained basin-level data fo r the total number of components

per well from survey data. ERG used this basin lev el data as a basis for the number of

components per well. ERG calculated a weighted ave rage based on the number of wells at each

basin. This data is summarized in Table 4-23 for g as wells and Table 4-24 for oil wells. The

CENRAP data did not contain information on componen t counts for “Pump Seals”, or “Others”

(equipment such as dump lever arms, polish rod pump s, or hatches). Therefore, an estimate of 2

“Pump Seals” and 10 “Others” were used to gapfill t he CENRAP data to complete the inventory

(Maldonado, 2010).4-49

Annual number of hours the well is in operation, t annual :

ERG used 8,760 hours per year for the hours the we ll is in operation.

Mass fraction of pollutant j to TOC in the vented gas, Y j :

The 2008 CENRAP study obtained basin-level data fo r the fraction of VOC to TOC in

the vented gas from survey data. ERG used this bas in level data as a basis for the fraction of

VOC to TOC in the vented gas. ERG calculated a wei ghted average based on the number of

wells at each basin. This data is summarized in Ta ble 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 Duro a 16 2 10 53 28 5 0.11

Marathon

Thrust

Belt a 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 basi ns.

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 0.144-50

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 Duro a 19 2 10 85 7 3 0.11

Marathon

Thrust

Belt a 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 basi ns.

Emissions by county E fugitive,TOTAL :

Appendix E presents county-level fugitive emission s corresponding to the number of

active oil and gas wells in each county, based on t he input variables discussed above.

Example Calculation for Fugitive Emissions (Equipme nt 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 j annual i i j fugitive Y

t N EF E 0011 .0

,

Where:

E

fugitive,j = VOC emissions from one oil well in Anderson Coun ty [tons/well-year]

EF i = 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]

N i = 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)

t annual = 8,760 (annual operating hours of oil wells in A nderson County) [hr/yr]

Y j = 0.11226 (mass fraction of VOC in the TOC vented from the fugitive areas) [ton
VOC/ton TOC]4-51

Therefore:

E fugitive,j = 8,760 [hr/yr] x 0.11226 [ton VOC/ton TOC] x 0.00 11 [tons/kg] x ((0.0025 * 18.80) + (0.013 * 2.00) + (0.0075 * 10.00) + (0.000 21 * 84.60) + (0.00011 * 7.40) + (0.0014 * 2.60) [kg-VOC/well-hr]))

E pneumatic,j = 0.18413 [tons VOC/well-yr]

For all wells in Anderson County:

well j fugitive TOTAL fugitive N

E E ×

=

, ,

Where:

E

fugitive,TOTAL = VOC emissions from all oil wells in Anderson Coun ty [tons/yr]

E fugitive,j = 0.18413 [tons VOC/well-yr]

N well = 456 (number of oil wells in Anderson County)

Therefore:

E pneumatic,TOTAL = 0.18413 [tons VOC/well-yr] x 456 wells

E pneumatic,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 t he 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 he aters 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. H eaters and boilers are typically natural gasfired external combustors and are a source of NO

x , CO, VOC and PM emissions. SO 2 emissions

may also occur if the gas used to fire the heaters contains Hydrogen Sulfide (H 2 S) which will be

subsequently converted to SO 2 during combustion. County-level emissions from he ater 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 met hodology, emissions from a single heater may

be calculated using the following equation (excludi ng SO 2 emissions):



## ( ) 2000 × × × ×

=

local annual

heater heater

heater HV hc

t Q EF E4-52

where:

E

heater is the emissions from a given heater [ton/yr]

EF heater is the emission factor for a heater for a given po llutant [lb/MMscf] Q heater is the heater MMBtu/hr rating [MMBtu rated /hr]

HV local is the local natural gas heating value [MMBtu local /MMscf]

t annual 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 o f emissions

SO 2 emissions from a single heater may be calculated u sing the following equation:

     

 

     

 

× ×         × × × × ×

=

035 .0 907200 78.1

2

2 , T MW R P

HV hc t Q f E

gas local annual heater S H

SO heater

where:

E

heater,SO2 is the SO 2 emissions from a given heater [ton-SO 2 /yr]

1.78 is the mass ratio of SO 2 to H 2 S f H2S is the mass fraction of H 2 S in the gas 907200 is the conversion factor from grams to tons of emissions Q heater is the heater MMBtu/hr rating [MMBtu rated /hr]

t annual 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.

HV local is the local natural gas heating value [MMBtu local /MMscf]

P is atmospheric pressure [1 atm]

R is the universal gas constant [0.082 L-atm/mol- o K]

MW gas is the molecular weight of the gas [g/mol]

T = 298 (standard temperature) [ o K]

0.035 is the conversion factor from cubic feet to l iters

The total emissions generated by heaters and boile rs from specific county are calculated

using the following equation:

2000 ,

, , j TOTAL

heater i heater TOTAL heater W

N E E ×

× =

where:

E

heater,TOTAL is the total heater emissions of pollutant i in cou nty j [ton/yr]

E heater,i is the total emissions of pollutant i from a singl e heater [ton/yr]

W TOTAL,j is the total number of wells in county j

N heater is the typical number of heaters per well in the c ounty 2000 is the conversion factor from pounds to tons o f emissions4-53

Total number of wells in a given county for 2008, W TOTAL,j :

Total active wells by county for the full 2008 yea r are not readily available from the TRC

website. However, well distribution data by countyis available from the TRC website on a biannual (February and September) basis and can be fo und at:

http://www.rrc.state.tx.us/data/wells/wellcount/ind ex.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, EF heater :

ERG used EPA’s AP-42 emissions factors when calcul ating 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 Heate rs

Pollutant Emissions Factor (lb/MMscf)

NO

x 100

CO 84

PM 10 7.6 a

VOC 5.5

a PM 10 assumed to be equal to PM 2.5

.

Heater MMBTU/hr rating, Q heater :

The 2008 CENRAP study obtained basin-level data fo r the heater rating from survey

data. ERG used this basin level data as a basis fo r 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, HV local :

The 2008 CENRAP study obtained basin-level data fo r the local heating value from

survey data. The same value was used for the gas w ell 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 oil4-54

well value was 1,655 MMBtu/MMscf. ERG used this ba sin level data as a basis for the local

heating values.

Annual hours of operation, t annual :

The 2008 CENRAP study obtained basin-level data fo r the annual heater operating hours

from survey data. ERG used this basin level data a s a basis for the annual operating hours. ERG

calculated a weighted average based on the number o f 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 fo r heater cycling fraction. ERG also

used this as a basis for the heater cycling fractio n.

Mass fraction of H 2 S, f H2S :

The 2008 CENRAP study obtained basin-level data fo r the mass fraction of H 2 S from

survey data. ERG used this basin level data as a b asis for the mass fraction of H 2 S. ERG

calculated a weighted average based on the number o f 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, MW gas :

The 2008 CENRAP study obtained basin-level data fo r the gas molecular weight from

survey data. ERG used this basin level data as a b asis for the gas molecular weight. ERG

calculated a weighted average based on the number o f 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, N heater :

The 2008 CENRAP study obtained basin-level data fo r the average number of heaters per

well from survey data. ERG used this basin level d ata as a basis for the average number of

heaters per well. ERG calculated a weighted averag e based on the number of wells at each

basin. This data is summarized in Table 4-26 for g as 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 MW gas

[g/mol] H 2 S 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

Duro a 0.91 0.64 4,076 1,209 1 20 0.005

Marathon

Thrust

Belt a 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 val ues 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 MW gas

[g/mol] H 2 S 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

Duro a 0.91 0.64 4,076 1,655 1 27 1.564-56 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 MW gas

[g/mol] H 2 S Mass

Fraction

Marathon

Thrust

Belt a 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 val ues are an average of the values from the other basins.

HAP Emissions for Heaters and Boilers :

HAP emissions from heaters and boilers were calcul ated using VOC and PM speciation

data as follows:

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

where:

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

E VOC = VOC emissions [tons/yr]

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

and

E

PM-HAP = E

PM x ( E %PM-HAP

/100)

where:

E

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

E PM = 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 E heater,TOTAL :

Appendix E presents county-level heater emissions corresponding to the number of active

oil and gas wells in each county, based on the inpu t variables discussed above.4-57

Example Calculation for Heaters and Boilers:

Using the equations provided above, ERG calculated NO

x and SO 2 emissions in

Anderson County from heaters and boilers at oil wel ls as follows:

For NO

x emissions from one heater:



## ( ) 2000 × × × ×

=

local annual

heater heater

heater HV hc

t Q EF E

Where:

E

heater = NO

x emissions from one heater in Anderson County [tons /year]

EF heater = 100 (AP-42 emissions factor for NO

x ) [lb/MMscf] Q heater = 0.64 (heater firing rate) [MMBtu/hr]

HV local = 1,655 (local natural gas heating value) [MMBTU local /MMscf])

t annual = 4,076 (annual hours of heater operation) [hr/yr]

hc = 1 (heater cycling fraction to account for the fr action of operating hours that the heater is firing) 2000 is the conversion factor from pounds to tons o f emissions

Therefore:

E heater = (100 [lb/MMscf] * 0.64 [MMBtu/hr] * 4,076 [hr/yr ] * 1)/(1,655 [MMBtu/MMscf] * 2000 [lb/ton])

E heater = 0.07881 [tons NO

x /heater-yr]

For all wells in Anderson County:

j TOTAL heater i heater TOTAL heater 

### W

N E E

, , , 

### ×

× =

Where:



### E

heater,TOTAL = NO

x emissions from all oil wells in Anderson County [t ons/yr]



### E heater,j = 0.07881 [tons NO

x /heater-yr]



### N heater = 0.91 (average number of heaters per well)



### W TOTAL,j = 456 (number of wells in Anderson County)

Therefore:



### E heater,TOTAL = 0.07881 [tons NO

x /heater-yr] x 0.91 [heaters/well] x 456 [wells]



### E heater,TOTAL = 32.70 [tons NO

x /yr]4-58

For SO 2 emissions from one heater:

     

 

     

 

× ×         × × × × ×

=

035 .0 907200 78.1

2

2 , T MW R P

HV hc t Q f E

gas local annual heater S H

SO heater

Where:



### E

heater,SO2 = SO 2 emissions from one heater [ton-SO 2 /yr] 

### f H2S = 1.56 (mass fraction of H 2 S in the gas) 

### Q heater = 0.64 (heater firing rate) [MMBtu/hr]



### HV local = 1,655 (local natural gas heating value) [MMBtu local /MMscf])



### t annual = 4,076 (annual hours of heater operation) [hr/yr]



### hc = 1 (heater cycling fraction to account for the fr action of operating hours that the heater is firing)



### P = 1 (standard pressure) [atm]



### R = 0.082 (universal gas constant) [L-atm/mol- o K]



### T = 298 (standard temperature) [ o K]



### MW gas = 27 (molecular weight of the gas) [g/mol]

Therefore:



### E heater,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- o K] /27 [g/mol]) * 298 [ o K] * 0.035))



### E heater,SO2 = 1.5231 x 10 -4 [tons SO 2 /heater-yr]

For all wells in Anderson County:

j TOTAL heater i heater TOTAL heater 

### W

N E E

, , , 

### ×

× =

Where:



### E

heater,TOTAL = SO 2 emissions from all oil wells in Anderson County [t ons/yr]



### E heater,j = 1.5231 x 10 -4 [tons SO 2 /heater-yr]



### N heater = 0.91 (average number of heaters per well)



### W TOTAL,j = 456 (number of wells in Anderson County)

Therefore:



### E heater,TOTAL = 1.5231 x 10 -4 [tons SO 2 /heater-yr] x 0.91 [heaters/well] x 456 wells



### E heater,TOTAL = 0.0632 [tons SO 2 /yr]5-1



### 5.0 RESULTS

Detailed emission estimates developed for this pro ject are found in Appendix D for

compressor engines, and in Appendix E for the remai nder 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 speciate d HAP emissions by source type.

As Table 5-1 indicates, natural gas compressor eng ines account for nearly 70 percent of

state-wide NO

x emissions with pumpjack engines accounting for ano ther 20 percent of total NO

x emissions. Oil and gas well heaters account for the remaining 10 percent, with a small contribution

from glycol dehydrator boilers. The relative contr ibution of these sources to state-wide CO

emissions are similar, with oil and gas well heater s comprising a slightly higher percentage of

emissions at approximately 13 percent.

The majority of PM 10 and PM 2.5 emissions are also from combustion sources, but th e oil

and gas well heaters are the primary source type, c ontributing nearly 60 percent to state-wide

totals. The remainder of PM 10 and PM 2.5 emissions come from compressor engines and pumpjac k

engines, with a small contribution from glycol dehy drator 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 s ource type to state-wide HAP emissions is

similar to that of VOC emissions. Oil and condensa te storage tanks contribute over 65 percent of

the state-wide total HAP emissions, with dehydrator s contributing over 15 percent of the statewide total HAP emissions. The remainder of HAP emi ssions come from combustion sources and

oil and condensate loading racks.5-2Table 5-1. State-wide Emissions Inventory for 2008 by Source CategorySCCSource Category DescriptionCO(tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)TotalHAP(tons/yr)2310000330 Artificial Lift 23,169.14 46,369.72 154.04154.049.56440.12140.492310011020 Storage Tanks: Crude Oil282,420.055,060.012310011100 Heater Treater 9,267.25 11,032.44 838.47838.4721.32606.78208.672310011201Tank Truck/Railcar Loading:Crude Oil26,810.72479.912310011450 Wellhead116,245.652310011501 Fugitives: Connectors2,956.392310011502 Fugitives: Flanges135.462310011503 Fugitives: Open Ended Lines605.722310011504 Fugitives: Pumps4,326.592310011505 Fugitives: Valves7,821.142310011506 Fugitives: Other12,480.552310020600 Compressor Engines 133.77 464.56 13.5813.580.2181.4029.002310021010 Storage Tanks: Condensate864,087.9017,281.712310021030Tank Truck/Railcar LoadingCondensate7,235.50144.712310021100 Gas Well Heaters 7,564.83 9,005.75 684.44684.440.04495.32170.342310021101Natural Gas Fired 2-Cycle LeanBurn Compressor Engines <50 Hp 140.52 209.25 9.729.720.1643.3815.462310021102Natural Gas Fired 2-Cycle LeanBurn Compressor Engines 50 To499 Hp2,907.93 13,776.30 352.37352.375.712,012.02716.782310021203Natural Gas Fired 4-Cycle LeanBurn Compressor Engines 500+Hp 14,746.41 27,288.73 76.9576.9515.943,817.422,337.582310021301Natural Gas Fired 4-Cycle RichBurn Compressor Engines <50 Hp 93.37 1,175.69 3.863.860.255.615.505-3Table 5-1. State-wide Emissions Inventory for 2008 by Source Category (Cont.)SCCSource Category DescriptionCO(tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)TotalHAP(tons/yr)2310021302Natural Gas Fired 4-Cycle RichBurn Compressor Engines 50 To499hp38,988.69 86,462.54 226.24226.2414.831,487.261,451.932310021400 Gas Well Dehydrators 904.59 293.366,344.855,255.172310021402Natural Gas Fired 4-Cycle RichBurn Compressor Engines 50-499hp W/ Nscr767.55 3,321.00 35.0235.022.0517.7317.462310021403Natural Gas Fired 4-Cycle RichBurn Compressor Engines 500+Hp W/ Nscr29,646.80 47,837.57 175.33175.3311.26794.33775.732310021501 Fugitives: Connectors1,161.522310021502 Fugitives: Flanges1,199.682310021503 Fugitives: Open Ended Lines916.822310021504 Fugitives: Pumps476.312310021505 Fugitives: Valves7,387.522310021506 Fugitives: Other8,732.372310021600 Gas Well Venting8,601.782310121700Gas Well Completion: AllProcesses10,139.562310111700Oil Well Completion: AllProcesses19,425.442310121401 Gas Well Pneumatic Pumps169,209.86Total:128,330.85 247,236.91 2,570.012,570.0181.341,568,522.7334,090.455-4Table 5-2. State-wide Emissions Inventory for 2008 by CountyCountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Anderson 241.28444.72 5.31 5.31 0.16 2,858.24 52.77Andrews 1,825.993,291.18 49.14 49.14 1.57 31,691.46 444.20Angelina 161.97311.11 2.15 2.15 0.08 629.30 25.94Aransas 165.25317.00 2.28 2.28 0.09 6,574.04 144.42Archer 614.911,088.88 18.74 18.74 0.58 2,719.03 24.45Armstrong 0.000.00 0.00 0.00 0.00 0.00 0.00Atascosa 321.56578.81 8.71 8.71 0.27 2,237.28 31.44Austin 127.18237.83 2.42 2.42 0.07 2,040.58 43.74Bailey 0.000.00 0.00 0.00 0.00 0.00 0.00Bandera 0.210.37 0.01 0.01 0.00 5.14 0.03Bastrop 74.21128.49 2.56 2.56 0.06 1,286.18 16.32Baylor 26.7847.39 0.82 0.82 0.03 189.33 1.96Bee 581.151,101.85 9.42 9.42 0.31 4,717.44 125.89Bell 0.000.00 0.00 0.00 0.00 0.00 0.00Bexar 531.99941.46 16.28 16.28 0.51 2,120.86 7.60Blanco 0.000.00 0.00 0.00 0.00 0.00 0.00Borden 166.31300.48 4.40 4.40 0.14 4,107.39 62.92Bosque 3.456.30 0.08 0.08 0.00 17.43 0.34Bowie 5.139.25 0.14 0.14 0.00 148.70 2.69Brazoria 207.73199.95 6.59 6.59 0.28 14,003.43 292.15Brazos 240.26444.10 5.18 5.18 0.16 3,781.19 74.41Brewster 0.000.00 0.00 0.00 0.00 5.88 0.00Briscoe 0.000.00 0.00 0.00 0.00 12.33 0.01Brooks 690.711,318.85 10.17 10.17 0.35 16,242.00 374.16Brown 204.73339.96 8.55 8.55 0.14 1,626.85 6.71Burleson 366.21669.08 8.80 8.80 0.28 3,881.39 67.20Burnet 0.000.00 0.00 0.00 0.00 0.00 0.005-5Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Caldwell 676.241,197.43 20.61 20.61 0.64 3,452.64 22.69Calhoun 189.99360.25 3.07 3.07 0.10 7,473.42 160.35Callahan 182.61321.30 5.76 5.76 0.16 983.48 9.65Cameron 1.683.12 0.03 0.03 0.00 10.26 0.20Camp 30.4155.01 0.79 0.79 0.03 259.21 4.96Carson 569.731,021.51 15.74 15.74 0.41 1,954.76 34.12Cass 54.9598.13 1.55 1.55 0.04 662.46 11.89Castro 0.000.00 0.00 0.00 0.00 0.00 0.00Chambers 84.7694.63 2.75 2.75 0.11 4,424.08 90.13Cherokee 364.58682.18 6.78 6.78 0.18 2,911.32 72.93Childress 1.692.99 0.05 0.05 0.00 57.40 0.71Clay 231.82409.65 7.14 7.14 0.21 1,476.89 16.60Cochran 445.16791.68 13.17 13.17 0.41 6,168.35 67.45Coke 109.55200.99 2.54 2.54 0.08 1,010.20 15.88Coleman 173.73295.58 6.51 6.51 0.13 1,363.81 9.92Collin 0.000.00 0.00 0.00 0.00 0.00 0.00Collingsworth 50.0476.34 2.77 2.77 0.02 742.63 2.58Colorado 319.38601.84 5.54 5.54 0.16 4,980.62 115.78Comal 0.000.00 0.00 0.00 0.00 0.00 0.00Comanche 34.2253.57 1.76 1.76 0.02 438.42 1.97Concho 72.58128.12 2.23 2.23 0.06 821.04 9.65Cooke 495.43884.64 14.25 14.25 0.45 3,467.02 50.26Coryell 0.000.00 0.00 0.00 0.00 3.13 0.00Cottle 95.67180.55 1.63 1.63 0.05 2,376.44 52.30Crane 1,739.983,208.47 38.61 38.61 1.26 17,274.91 291.73Crockett 2,274.884,015.15 68.61 68.61 1.15 28,501.91 414.45Crosby 85.55151.51 2.61 2.61 0.08 1,056.14 9.675-6Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Culberson 72.79137.98 1.20 1.20 0.04 284.44 8.75Dallam 0.000.00 0.00 0.00 0.00 0.00 0.00Dallas 28.0480.04 0.21 0.21 0.02 24.60 4.23Dawson 275.48492.78 7.84 7.84 0.25 5,344.51 72.02Deaf Smith 0.000.00 0.00 0.00 0.00 0.00 0.00Delta 0.000.00 0.00 0.00 0.00 0.00 0.00Denton 1,763.524,690.36 29.51 29.51 1.14 13,254.59 416.58Dewitt 676.491,300.83 9.00 9.00 0.35 11,617.04 287.72Dickens 49.7088.22 1.49 1.49 0.05 1,446.43 20.78Dimmit 197.89353.20 5.65 5.65 0.15 2,515.16 31.86Donley 0.530.77 0.03 0.03 0.00 15.82 0.17Duval 1,111.172,101.02 18.70 18.70 0.63 12,897.27 314.00Eastland 285.26476.94 11.51 11.51 0.18 3,654.84 39.72Ector 1,798.243,277.22 44.40 44.40 1.47 26,211.12 388.97Edwards 270.78492.35 6.60 6.60 0.13 1,377.01 25.49El Paso 0.000.00 0.00 0.00 0.00 0.00 0.00Ellis 51.17144.09 0.47 0.47 0.04 52.43 7.56Erath 161.14295.43 3.68 3.68 0.07 1,556.95 32.84Falls 4.017.09 0.12 0.12 0.00 21.49 0.09Fannin 0.000.00 0.00 0.00 0.00 11.86 0.00Fayette 356.62659.40 7.64 7.64 0.23 5,607.61 115.67Fisher 107.82193.50 2.99 2.99 0.09 1,365.54 16.44Floyd 0.420.75 0.01 0.01 0.00 2.97 0.03Foard 27.9443.90 1.42 1.42 0.01 414.38 2.57Fort Bend 169.68171.80 5.51 5.51 0.22 8,072.59 166.58Franklin 69.40127.99 1.52 1.52 0.05 1,389.52 28.31Freestone 3,821.607,289.51 56.95 56.95 1.93 9,858.72 475.095-7Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Frio 139.12246.28 4.21 4.21 0.12 1,393.74 14.40Gaines 1,165.522,133.47 27.65 27.65 0.92 27,788.32 460.84Galveston 86.4676.28 2.61 2.61 0.12 17,475.45 358.12Garza 445.72790.41 13.45 13.45 0.42 6,133.80 63.01Gillespie 0.000.00 0.00 0.00 0.00 0.00 0.00Glasscock 416.67761.54 10.00 10.00 0.32 5,431.20 84.49Goliad 731.211,386.08 11.85 11.85 0.37 7,851.72 199.63Gonzales 51.4092.76 1.37 1.37 0.04 578.12 8.62Gray 825.551,440.69 27.11 27.11 0.64 4,163.88 45.84Grayson 201.98365.62 5.22 5.22 0.16 1,707.03 31.65Gregg 1,423.902,592.32 34.92 34.92 1.00 10,980.44 227.68Grimes 334.10638.29 4.87 4.87 0.17 1,264.12 50.60Guadalupe 402.11711.73 12.29 12.29 0.38 2,576.45 22.66Hale 62.99114.67 1.57 1.57 0.05 2,698.37 46.20Hall 0.000.00 0.00 0.00 0.00 0.00 0.00Hamilton 3.125.33 0.11 0.11 0.00 36.47 0.47Hansford 377.68676.20 10.32 10.32 0.17 2,601.06 43.25Hardeman 52.1392.68 1.54 1.54 0.05 1,230.36 19.89Hardin 258.68348.83 7.85 7.85 0.30 22,648.65 447.94Harris 176.00181.67 5.65 5.65 0.23 8,801.29 184.44Harrison 1,879.593,514.48 35.19 35.19 0.93 25,383.90 583.58Hartley 39.0670.27 1.04 1.04 0.02 399.51 6.56Haskell 53.8395.30 1.64 1.64 0.05 443.81 5.44Hays 0.000.00 0.00 0.00 0.00 0.00 0.00Hemphill 2,092.633,936.72 37.08 37.08 1.03 32,774.76 754.74Henderson 453.75854.13 7.99 7.99 0.24 2,535.12 73.92Hidalgo 3,264.696,276.64 43.49 43.49 1.68 56,554.95 1,407.725-8Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Hill 308.20597.97 3.53 3.53 0.16 233.61 34.41Hockley 1,004.101,795.93 28.58 28.58 0.91 22,011.88 308.12Hood 926.801,777.59 12.89 12.89 0.47 9,914.41 269.97Hopkins 20.8437.79 0.53 0.53 0.02 298.78 5.06Houston 164.62308.00 3.11 3.11 0.10 1,587.91 35.84Howard 803.871,436.74 23.00 23.00 0.73 9,904.95 107.63Hudspeth 0.120.17 0.01 0.01 0.00 3.29 0.03Hunt 0.000.00 0.00 0.00 0.00 0.00 0.00Hutchinson 903.431,601.32 27.09 27.09 0.72 4,039.66 49.29Irion 531.51961.89 13.77 13.77 0.40 5,877.27 82.51Jack 646.651,121.02 21.80 21.80 0.42 6,701.91 92.20Jackson 303.15569.09 5.55 5.55 0.17 9,879.64 204.59Jasper 205.58394.00 2.87 2.87 0.11 6,405.78 143.58Jeff Davis 0.000.00 0.00 0.00 0.00 1.29 0.03Jefferson 287.19182.64 8.05 8.05 0.46 55,659.21 1,163.27Jim Hogg 266.50500.41 4.83 4.83 0.14 4,021.10 92.33Jim Wells 127.37226.90 3.61 3.61 0.06 1,576.61 26.20Johnson 4,495.4812,647.53 43.01 43.01 3.19 5,209.18 684.81Jones 167.32296.69 5.05 5.05 0.16 1,277.91 14.79Karnes 171.32323.25 2.95 2.95 0.10 3,454.12 76.12Kaufman 4.508.03 0.14 0.14 0.00 62.82 1.05Kendall 0.000.00 0.00 0.00 0.00 0.00 0.00Kenedy 665.441,286.34 8.13 8.13 0.35 4,087.71 143.43Kent 203.51375.70 4.48 4.48 0.16 4,304.19 73.92Kerr 0.000.00 0.00 0.00 0.00 0.00 0.00Kimble 2.944.50 0.16 0.16 0.00 41.29 0.17King 112.59198.82 3.47 3.47 0.10 2,010.47 35.205-9Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Kinney 0.000.00 0.00 0.00 0.00 0.00 0.00Kleberg 494.21948.96 6.71 6.71 0.25 8,845.84 217.77Knox 46.1881.72 1.41 1.41 0.04 354.81 4.00La Salle 259.22470.95 6.38 6.38 0.13 4,078.69 76.37Lamar 0.000.00 0.00 0.00 0.00 0.00 0.00Lamb 15.1027.13 0.42 0.42 0.01 686.85 11.01Lampasas 0.160.20 0.01 0.01 0.00 4.24 0.00Lavaca 924.671,764.89 13.68 13.68 0.47 12,277.67 311.64Lee 307.30564.26 7.08 7.08 0.23 2,650.76 49.84Leon 1,079.722,070.29 15.01 15.01 0.58 5,733.49 197.49Liberty 331.40341.24 9.92 9.92 0.45 27,316.75 570.30Limestone 1,393.872,655.14 21.17 21.17 0.71 4,377.56 180.91Lipscomb 1,125.342,104.13 21.36 21.36 0.58 17,104.94 381.52Live Oak 378.16709.70 6.91 6.91 0.20 6,807.99 149.58Llano 0.000.00 0.00 0.00 0.00 0.00 0.00Loving 1,567.713,023.10 20.15 20.15 0.89 6,348.57 251.69Lubbock 89.19158.04 2.71 2.71 0.08 1,825.32 23.15Lynn 18.5233.00 0.54 0.54 0.02 350.40 4.52Madison 117.26216.26 2.56 2.56 0.07 1,290.52 26.07Marion 96.78174.38 2.56 2.56 0.06 1,407.02 25.69Martin 596.731,088.02 14.69 14.69 0.49 10,928.66 168.72Mason 0.000.00 0.00 0.00 0.00 0.00 0.00Matagorda 609.791,168.96 8.47 8.47 0.32 19,098.24 428.64Maverick 182.47323.89 5.42 5.42 0.15 3,715.58 42.08McCulloch 14.6525.47 0.50 0.50 0.01 109.65 1.15McLennan 8.6515.30 0.26 0.26 0.01 27.43 0.12McMullen 493.90900.42 11.92 11.92 0.29 6,027.42 110.635-10Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Medina 275.72487.25 8.50 8.50 0.26 1,235.77 4.54Menard 27.0047.52 0.85 0.85 0.02 266.84 2.69Midland 1,610.042,951.97 37.75 37.75 1.27 20,938.23 333.93Milam 218.91387.83 6.65 6.65 0.21 1,216.87 9.32Mills 0.360.51 0.02 0.02 0.00 6.38 0.02Mitchell 502.49890.13 15.28 15.28 0.48 6,645.63 65.00Montague 551.48987.06 15.59 15.59 0.49 3,448.92 48.39Montgomery 73.5681.80 2.86 2.86 0.08 2,890.56 54.67Moore 744.021,343.19 19.29 19.29 0.40 3,502.87 63.64Morris 0.210.37 0.01 0.01 0.00 2.01 0.03Motley 3.806.72 0.12 0.12 0.00 52.75 0.49Nacogdoches 1,527.762,897.04 24.29 24.29 0.77 12,723.39 353.60Navarro 170.24301.61 5.16 5.16 0.16 1,444.51 18.73Newton 78.50145.69 1.63 1.63 0.05 1,601.94 31.72Nolan 133.50240.21 3.63 3.63 0.11 1,931.63 25.88Nueces 605.471,127.23 11.99 11.99 0.31 15,740.17 332.51Ochiltree 561.881,020.35 13.94 13.94 0.31 5,760.68 108.67Oldham 5.6810.02 0.17 0.17 0.00 247.24 3.74Orange 67.7971.25 2.06 2.06 0.09 8,467.82 172.90Palo Pinto 455.72785.82 15.70 15.70 0.21 7,033.45 105.26Panola 3,784.217,052.88 73.18 73.18 1.82 50,362.96 1,170.88Parker 1,225.523,294.01 19.49 19.49 0.80 9,840.76 290.06Parmer 0.000.00 0.00 0.00 0.00 0.00 0.00Pecos 4,534.568,670.50 66.30 66.30 2.63 21,760.89 703.44Polk 415.68797.76 5.69 5.69 0.22 29,650.93 625.12Potter 350.79632.33 9.25 9.25 0.21 1,799.21 27.27Presidio 0.000.00 0.00 0.00 0.00 0.00 0.005-11Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Rains 59.61115.43 0.71 0.71 0.03 38.47 6.62Randall 0.000.00 0.00 0.00 0.00 0.00 0.00Reagan 1,209.822,204.56 29.89 29.89 0.99 11,808.61 158.58Real 1.913.34 0.06 0.06 0.00 16.74 0.15Red River 9.5716.96 0.29 0.29 0.01 159.73 2.26Reeves 575.501,077.94 10.88 10.88 0.36 3,146.28 72.34Refugio 652.551,218.19 12.72 12.72 0.40 9,671.07 197.77Roberts 881.181,659.43 15.47 15.47 0.45 15,296.54 346.65Robertson 3,591.036,960.37 41.87 41.87 1.90 4,202.14 427.68Rockwall 0.000.00 0.00 0.00 0.00 0.00 0.00Runnels 145.66262.06 3.96 3.96 0.12 1,177.54 15.82Rusk 2,394.044,447.78 48.27 48.27 1.34 26,428.99 597.16Sabine 2.043.67 0.06 0.06 0.00 19.20 0.14San Augustine 159.66309.99 1.77 1.77 0.09 452.69 23.22San Jacinto 182.43350.28 2.47 2.47 0.09 6,462.64 144.35San Patricio 303.08570.53 5.36 5.36 0.16 12,721.07 267.75San Saba 0.000.00 0.00 0.00 0.00 0.00 0.00Schleicher 297.16521.39 9.30 9.30 0.15 3,975.13 56.43Scurry 920.141,696.28 20.52 20.52 0.72 16,745.60 282.63Shackelford 446.66787.83 13.87 13.87 0.39 2,584.60 27.41Shelby 788.211,506.84 11.24 11.24 0.40 4,681.48 153.59Sherman 382.36689.34 9.93 9.93 0.17 2,226.58 38.78Smith 600.161,117.21 11.83 11.83 0.32 6,759.09 157.15Somervell 69.05132.73 0.93 0.93 0.04 261.32 10.71Starr 1,801.983,435.69 27.08 27.08 0.92 39,905.70 922.75Stephens 548.00962.55 17.22 17.22 0.36 6,028.28 86.04Sterling 507.62898.57 15.24 15.24 0.35 5,045.87 54.845-12Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Stonewall 125.21222.61 3.72 3.72 0.12 1,647.78 17.01Sutton 1,536.072,640.40 53.45 53.45 0.57 14,703.05 158.36Swisher 0.000.00 0.00 0.00 0.00 0.00 0.00Tarrant 4,070.9111,441.36 39.54 39.54 2.88 4,929.92 620.02Taylor 92.16163.25 2.80 2.80 0.09 693.08 8.42Terrell 890.561,697.22 13.46 13.46 0.45 4,554.08 153.52Terry 217.93388.12 6.39 6.39 0.20 5,118.11 70.81Throckmorton 221.50393.95 6.55 6.55 0.20 1,242.06 15.21Titus 42.1974.68 1.29 1.29 0.04 506.68 8.03Tom Green 170.07304.64 4.76 4.76 0.14 1,945.37 23.40Travis 3.375.97 0.10 0.10 0.00 14.43 0.07Trinity 10.9419.88 0.27 0.27 0.01 193.38 3.42Tyler 463.76896.18 5.69 5.69 0.25 57,953.39 1,201.05Upshur 604.481,126.42 11.73 11.73 0.30 10,582.53 238.20Upton 1,602.982,998.03 30.90 30.90 1.09 32,833.54 647.89Uvalde 0.200.26 0.02 0.02 0.00 4.37 0.01Val Verde 210.53394.38 3.90 3.90 0.10 620.76 21.64Van Zandt 193.81352.82 4.81 4.81 0.15 1,204.59 23.27Victoria 287.47535.68 5.67 5.67 0.16 3,296.01 69.83Walker 13.4924.74 0.31 0.31 0.01 85.26 1.73Waller 88.01106.67 2.83 2.83 0.11 2,859.24 56.46Ward 1,288.642,381.97 28.00 28.00 0.94 9,588.88 230.25Washington 256.76485.36 4.31 4.31 0.14 2,513.65 64.54Webb 3,123.825,806.41 62.66 62.66 1.48 28,275.41 664.71Wharton 692.111,309.84 11.43 11.43 0.37 15,986.48 354.54Wheeler 2,223.924,231.74 34.40 34.40 1.15 40,674.02 955.94Wichita 1,185.962,099.33 36.23 36.23 1.13 5,040.04 46.605-13Table 5-2. State-wide Emissions Inventory for 2008 by County (Cont.)CountyCO (tons/yr)NOx(tons/yr)PM10(tons/yr)PM2.5(tons/yr)SO2(tons/yr)VOC(tons/yr)Total HAP(tons/yr)Wilbarger 174.53308.95 5.33 5.33 0.17 1,147.90 13.03Willacy 353.53681.05 4.59 4.59 0.19 8,274.58 193.92Williamson 9.0716.05 0.28 0.28 0.01 53.29 0.33Wilson 129.98230.01 3.98 3.98 0.12 757.55 6.10Winkler 917.141,698.44 19.52 19.52 0.63 7,815.47 141.18Wise 2,749.595,099.17 55.75 55.75 1.35 24,225.59 597.53Wood 239.16438.82 5.52 5.52 0.18 4,200.35 82.03Yoakum 1,074.181,960.14 26.21 26.21 0.88 25,649.46 414.59Young 556.32978.60 17.57 17.57 0.50 3,394.26 35.11Zapata 4,438.248,472.07 65.54 65.54 2.24 13,384.86 594.31Zavala 64.75114.70 1.94 1.94 0.05 1,016.76 14.24Total:128,330.85247,236.91 2,570.01 2,570.01 81.34 1,568,522.73 34,090.455-14Table 5-3. State-wide Speciated HAP Emissions by Source CategorySource CategoryHazardous Air PollutantDehydratorsPump JacksOil and GasHeatersTankTruck/RailcarLoadingNatural GasCompressorEnginesStorageTanksStatewideTotal1,1,2,2-Tetrachloroethane 0.10 3.233.331,1,2-Trichloroethane 0.06 2.192.251,3-Butadiene 2.59 59.7162.301,3-Dichloropropene 0.05 1.821.871,4-Dichlorobenzene 4.69 0.24 38.6743.602,2,4-Trimethylpentane 7.957.952-Methylnaphthalene 0.09 0.005 2.913.013-Methylcholanthrene 0.01 0.0004 0.200.207,12-Dimethylbenz[a]Anthracene 0.06 0.003 1.741.81Acenaphthene 0.36 0.001 0.230.59Acenaphthylene 0.36 0.001 0.651.01Acetaldehyde 10.91 1.78 481.46494.14Acrolein 10.28 366.67376.95Anthracene 0.48 0.00 0.370.86Benz[a]Anthracene 0.36 0.00 0.280.64Benzene 1,477.65 6.18 0.42 129.92136.055,794.48 7,544.70Benzo(g,h,i)Fluoranthene 0.24 0.000.24Benzo[a]Pyrene 0.24 0.001 0.070.31Benzo[b]Fluoranthene 0.36 0.001 0.120.48Benzo[e]Pyrene 0.040.04Benzo[g,h,i,]Perylene 0.001 0.110.11Benzo[k]Fluoranthene 0.36 0.001 0.280.64Biphenyl 6.746.74Carbon Tetrachloride 0.07 2.532.60Chlorobenzene 0.05 1.962.01Chloroform 0.05 1.962.02Chrysene 0.36 0.001 0.170.53Dibenzo[a,h]Anthracene 0.24 0.001 0.190.43Ethyl Benzene 88.89 0.10 54.193.181,003.02 1,149.375-15Table 5-3. State-wide Speciated HAP Emissions by Source Category (Cont.)Source CategoryHazardous Air PollutantDehydratorsPump JacksOil and GasHeatersTankTruck/RailcarLoadingNatural GasCompressorEnginesStorageTanksStatewideTotalEthylene Dibromide 0.08 3.053.14Fluoranthene 0.60 0.002 0.280.88Fluorene 0.56 0.002 0.721.29Formaldehyde 80.13 15.03 3,263.203,358.36Hexane 360.69 781.761,142.45Indeno[1,2,3-c,d]Pyrene 0.36 0.001 0.280.64Methanol 11.96 80.8092.76Methylene Chloride 0.16 3.823.98m-Xylene 0.04 0.440.49Naphthalene 0.38 0.12 9.8710.37o-Xylene 0.04 0.830.87Phenanthrene 3.50 0.01 2.025.54Phenol 0.760.76Pyrene 1.00 0.004 0.421.42Styrene 0.05 1.671.72Toluene 786.98 2.18 0.68 208.8956.089,756.68 10,811.49Vinyl Chloride 0.03 1.031.06Xylenes (Mixture of o, m, and pIsomers) 2,901.66 0.76 231.6220.925,787.54 8,942.50Statewide Total 5,255.17 140.49 379.00 624.625,349.4422,341.72 34,090.456-1



### 6.0 FORMATTED TexAER FILES

Once the emissions inventory was completed, the dat a was prepared for electronic

submittal to the Texas Air Emissions Repository (Te xAER) using the National Emissions

Inventory (NEI) Input Format (NIF) 3.0. Area sourc e 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 regardin g the correct format and valid code listings

for submittal to TexAER. Prior to submittal to TCE Q, 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 200 8 emissions inventory for Texas for

onshore, upstream oil and gas production area sourc es. 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 product ion data), point source emissions

inventory reports submitted to TCEQ (for dehydrator s), vendor data (for compression engines

and pumpjack engines), and published emission facto r and activity data from the Houston

Advanced Research Center (HARC), the Central Region al Air Planning Association (CENRAP),

and the U.S. Environmental Protection Agency (EPA).

Further improvements to this inventory could be ma de 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 th e source types would benefit from

detailed survey data, there are a few categories wh ere minimal Texas-specific data was available.

Specifically, this inventory was based on default p rofiles for several source categories that could

be improved through implementation of the survey as follows:



### • Well Completions and Well Blowdowns - survey data i s needed to determine the volumes of gas released during these operations, th e composition of the gas released, and the extent that these operations are controlled;



### • Pneumatic Devices - survey data is needed to determ ine the number of devices used at each upstream oil and gas production site, the blee d rates for each equipment type, and the composition of the natural gas released from th ese sources;



### • Fugitive Emissions (Equipment Leaks) - this could b e a significant source category and there is some uncertainty as to the current estimat e 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 specia te the emissions from this source category; and



### • Heaters and Boilers - survey data is needed to quan tify the number and size of these small combustion units located at upstream oil and gas pr oduction sites.

Also, HAP emissions could be estimated for several source categories not currently

included in the HAP inventory if HAP speciation dat a could be obtained for the chemical

composition of the natural gas emitted during vario us processes. In particular, this data would be7-2

used to estimate HAP emissions from well completion s, well blowdowns, pneumatic devices,

and equipment leaks.

It is likely the current inventory may be overestim ating emissions to some degree from

some sources due to the lack of information on cont rol 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 uni ts 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 Stat es’ Oil and Gas Emissions Inventories. Prepared for Central States Regional Air Partnershi p. November, 2008

US EPA, 1991. “AP 42, Fifth Edition, Volume I, Chap ter 13: Industrial Flares.” EPA’s Compilation of Air Pollutant Emission Factors, AP-4 2 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, Chap ter 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, Chap ter 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 E mission Factors. Accessed July 2, 2010. Internet address: http://cfpub.epa.gov/oarweb/download/WebFIREFactors .csv

US EPA, 2006. “AP 42, Fifth Edition, Volume I, Chap ter 7: Liquid Storage Tanks,” EPA’s Compilation of Air Pollutant Emission Factors, AP-4 2 Section 7.1, November, 2006.

US EPA, 2008. “AP 42, Fifth Edition, Volume I, Chap ter 5: Petroleum Industry,” EPA’s Compilation of Air Pollutant Emission Factors, AP-4 2 Section 5.2, June, 2008.

The Electric Power Research Institute (EPRI), 2005. Assessment of Emerging Low-Emission Technologies for Combustion-Based Distributed Resou rce Generators. Prepared by Energy and Environmental Analysis, Inc. March, 2005.

Houston Advanced Research Center (HARC), 2005. Nat ural Gas Compressor Engine Survey and Engine NO

x Emissions at Gas Production Facilities. Prepared b y Eastern Research Group, Inc. August 31, 2005.

Houston Advanced Research Center (HARC), 2006. Nat ural Gas Compressor Engine Survey for Gas Production and Processing Facilities. Prepared by Eastern Research Group, Inc. October 5,

2006.

Maldonado, Martha, 2010. Fugitive component equipme nt 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; Fries en, Ron; Fields, Paula; and Wolf, Marty, 2006. Ozone Precursors Emission Inventory for San J uan and Rio Arriba Counties, New Mexico. Prepared for New Mexico Environment Department. Aug ust, 2006.

Pollution Solutions, 2005. “Tyler/Longview/Marshall Flexible Attainment Region Emission Inventory of Ozone Precursors VOC, NO

x 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 Consideratio n for Load Factor” Final report prepared for the East Texas Council of Governments, Kilgore, TX.

Texas Environmental Research Consortium (TERC), Oct ober 2006, revised April 2009. VOC Emissions from Oil and Condensate Storage Tanks.

Texas Commission on Environmental Quality (TCEQ), 2 007. Emissions from Oil and Gas Production Facilities, 2007. Prepared by Eastern Re search Group, Inc. August 31, 2007.

Texas Commission on Environmental Quality (TCEQ), 2 009. Drilling Rig Emission Inventory for the State of Texas, 2009. Prepared by Eastern R esearch Group, Inc. July 15, 2009.

Texas Commission on Environmental Quality (TCEQ), 2 010. Offshore Oil and Gas Platform Report. Prepared by Eastern Research Group, Inc. Au gust 16, 2010.Appendix A – Task 2 MemorandumA-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 s elect counties in Texas. The inventory will address area source criteria pollutant emissions of volatile organic compounds (VOC), nitrogen oxides (NO X ), carbon monoxide (CO), particulate matter with an aerodynamic diameter less than or equal to 10 microns (PM 10 ), particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (PM 2.5 ), and sulfur dioxide (SO 2 ); and certain toxic pollutant emissions such as formaldehyde, benzene, toluene, ethylbenzene, and x ylene. 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 method ology for estimating emissions from oil and gas production sites based on the oil and gas produ ced 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 activit ies. The first, implemented in 2007, focused on compiling a state-wide emissions invento ry (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 yea r, 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, J ohnson, 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 perta ining to estimating emissions from oil and gas production sites and recommendation of an e mission estimation approach for each identified source type;

• 

### Collection of activity and emissions data through a n industry survey and, as available, obtain data from existing studies and databases;

• 

### Development of a methodology to estimate county-lev el emissions from each identified source type; and

• 

### Performance of emissions estimation calculations, i ncluding documentation of data, procedures, and results in a final project report. The final emissions inventory will be compiled into National Emissions Inventory Input Fo rmat (NIF) 3.0 text files for import into Texas Air Emissions Repository (TexAER).

The purpose of this memo is to identify and summari ze emission estimation methodologies available for oil and gas production sites as deter mined 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 a pproaches 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 obta in 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 d ata gaps (through the use of existing or default data) are presented.

This discussion begins by presenting the list of oi l and gas source types that are the focus of this project in Section 2.0, Identification of Source Ca tegories. 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 thos e source types. As other additional source types were identified in the course of reviewing th e 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 refe rences 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 f irst time they are used.

2.0 Identification of Source Categories



### The majority of the oil and gas production source c ategories analyzed in this project were also included in the previous TCEQ Oil and Gas study (ER G, 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 memorandu m, 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" so urces, which include activities associated with searching for potential oil and gas fields, dr illing of exploratory wells, and subsequently development and operating the wells that recover an d 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 a nd 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 proc essing 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 ca tegory 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 source s as provided to ERG by TCEQ.

The final list of SCC's used to compile the emissio ns inventory into the NIF 3.0 text files will be provided in the emissions inventory report. The st ructure of the SCC scheme for many of the source types included in this study allows for aggr egation of emissions under one SCC, or the use of multiple SCC's if sufficient detailed data i s obtained to disaggregate emissions into smaller sub-categories. For example, SCC 231001150 0 may be used for "FUGITIVES: ALL PROCESSES" from oil production, or there are 6 sepa rate SCC's that may be used to disaggregate fugitive emissions into sub-categories of "connectors", "flanges", "valves", "open ended lines", "pumps", and "other".A-4Table 1. Identification of Source Categories Addressed in the Texas Oil and Gas Emission InventoryOil & Gas Source TypeSpecific Emission SourcesPotential PollutantsWell Completions Emissions from venting/flaring from the wellcompletion phase CO, NOX, VOCWell Blowdowns Emissions from venting/flaring from well blowdowns CO, NOX, VOCWellheads Emissions from wellhead assemblies and rod pumpsVOCPneumatic DevicesFugitive emissions from pneumatic devices used during well explorationand productionVOCFugitive Emissions (EquipmentLeaks)Fugitive emissions from pumps and piping components VOCArtificial Lift Engines (PumpjackEngines)Combustion emissions from artificial lift engines associated with oilproductionSO2, NOx, VOC, PM, COHeaters and Boilers Emissions from natural gas-fired heaters and boilers SO2, NOx, VOC, PM, CODehydrators Emissions from glycol dehydrator still vents andreboilersVOC, Benzene, Toluene,Ethylbenzene, XyleneStorage TanksWorking, breathing, and flashing losses from oil and condensatestoragetanksVOCOil and Condensate Loading Racks Fugitive emissions from truck and/or railcar loading VOCCompressor EnginesCombustion emissions from compressor engines associated withoil andgas productionSO2, NOx, VOC, PM, CO,FormaldehydeTurbinesCombustion emissions from turbines associated with oil and gasproductionSO2, NOx, VOC, PM, COA-5Table 2. Assignment of SCCs to Texas Oil and Gas SourcesaSCCTier DescriptionShort Description2270010010 OTHER OIL FIELD EQUIPMENT DIESEL: INDUSTRIAL EQUIPMENT: OTHER OIL FIELD EQUIPMENT(DRILLING RIGS)2310000000 TOTAL: ALL PROCESSES OIL & GAS EXPLORATION AND PRODUCTION ALL PROCESSES2310000330 ARTIFICIAL LIFT OIL AND GAS EXPLORATION AND PRODUCTION ARTIFICIAL LIFT2310001000 TOTAL: ALL PROCESSES ON SHORE OIL & GAS EXPLORATION & PRODUCTION ALLPROCESSES2310010000 TOTAL: ALL PROCESSES CRUDE OIL PRODUCTION ALL PROCESSES2310010100 OIL WELL HEATERS OIL PRODUCTION WELL HEATERS2310010200 TANKS - FLASHING & STANDING/ WORKING/BREATHINGOIL PRODUCTION TANKS INCLUDING FLASHING2310010300 PNEUMATIC DEVICES OIL PRODUCTION PNEUMATIC DEVICES2310010700 OIL WELL FUGITIVES OIL AND GAS EXPLORATION AND PRODUCTION OIL WELLFUGITIVES2310010800 OIL WELL TRUCK LOADING OIL AND GAS EXPLORATION ANDPRODUCTION OIL WELL TRUCKLOADING2310011000 TOTAL: ALL PROCESSES ON SHORE CRUDE OIL PRODUCTIONALL PROCESSES2310011020 STORAGE TANKS: CRUDE OIL ON SHORE OIL PRODUCTION CRUDE TANKS2310011100 HEATER TREATER ON SHORE OIL PRODUCTION HEATER TREATER2310011201 TANK TRUCK/RAILCAR LOADING: CRUDE OIL ON SHORE OILPRODUCTION TRUCK/RAIL LOADING OF CRUDE2310011450 WELLHEADON SHORE OIL PRODUCTION WELLHEAD2310011500 FUGITIVES: ALL PROCESSES ON SHORE OIL PRODUCTION FUGITIVES ALL PROCESSES2310011501 FUGITIVES: CONNECTORS ON SHORE OIL PRODUCTION FUGITIVES CONNECTORS2310011502 FUGITIVES: FLANGES ON SHORE OIL PRODUCTION FUGITIVES FLANGES2310011503 FUGITIVES: OPEN ENDED LINES ON SHORE OIL PRODUCTION FUGITIVES OPEN ENDED LINES2310011504 FUGITIVES: PUMPS ON SHORE OIL PRODUCTION FUGITIVESPUMPS2310011505 FUGITIVES: VALVES ON SHORE OIL PRODUCTION FUGITIVES VALVES2310011506 FUGITIVES: OTHER ON SHORE OIL PRODUCTION FUGITIVESOTHER2310020000 TOTAL: ALL PROCESSES NATURAL GAS EXPLORATION AND PRODUCTION: ALL PROCESSES2310020309 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES: ALLON-SHORE GAS PRODUCTION 4CYCLE RICH BURN COMPRESSORS2310020600 COMPRESSOR ENGINES GAS PRODUCTION COMPRESSOR ENGINES (FOR WRAP USE)2310020700 GAS WELL FUGITIVES NATURAL GAS PRODUCTION GAS WELLFUGITIVES2310020800 GAS WELL TRUCK LOADING NATURAL GAS PRODUCTION GASWELL TRUCK LOADINGA-6SCC Tier DescriptionShort Description2310021000 TOTAL: ALL PROCESSES ON SHORE GAS PRODUCTION: ALLPROCESSES2310021010 STORAGE TANKS: CONDENSATE ON-SHORE GAS PRODUCTION:STORAGE TANKS: CONDENSATE2310021030 TANK TRUCK/RAILCAR LOADINGCONDENSATEON SHORE GAS PRODUCTION TRUCK AND RAIL LOADING OFCONDENSATE2310021100 GAS WELL HEATERS ON-SHORE GAS PRODUCTION HEATERS2310021101 NATURAL GAS FIRED 2-CYCLE LEAN BURNCOMPRESSOR ENGINES <50 HPON-SHORE GAS PRODUCTION: NATURAL GAS FIRED 2-CYCLE LEANBURN COMPRESSOR ENGINES <50 HP2310021102 NATURAL GAS FIRED 2-CYCLE LEAN BURNCOMPRESSOR ENGINES 50 TO 499 HPON-SHORE GAS PRODUCTION: NATURAL GAS FIRED 2-CYCLE LEANBURN COMPRESSOR ENGINES 50 TO 499 HP2310021103 NATURAL GAS FIRED 2-CYCLE LEAN BURNCOMPRESSOR ENGINES 500+ HPON-SHORE GAS PRODUCTION NATURAL GAS FIRED 2-CYCLE LEANBURN COMPRESSOR ENGINES 500+ HP2310021109 NATURAL GAS FIRED 2-CYCLE LEAN BURNCOMPRESSOR ENGINES: ALLON-SHORE GAS PRODUCTION: NATURAL GAS FIRED 2-CYCLE LEANBURN COMPRESSOR ENGINES: ALL2310021201 NATURAL GAS FIRED 4-CYCLE LEAN BURNCOMPRESSOR ENGINES <50 HPON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE LEANBURN COMPRESSOR ENGINES <50 HP2310021202 NATURAL GAS FIRED 4-CYCLE LEAN BURNCOMPRESSOR ENGINES 50-499HPON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE LEANBURN COMPRESSOR ENGINES 50 HP - 499 HP2310021203 NATURAL GAS FIRED 4-CYCLE LEAN BURNCOMPRESSOR ENGINES 500+ HPON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE LEANBURN COMPRESSOR ENGINES 500+ HP2310021209 NATURAL GAS FIRED 4-CYCLE LEAN BURNCOMPRESSOR ENGINESON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE LEANBURN COMPRESSOR ENGINES2310021300 GAS WELL PNEUMATIC DEVICES ON-SHORE GAS PRODUCTIONPNEUMATIC DEVICES2310021301 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES <50 HPON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE RICHBURN COMPRESSOR ENGINES <50 HP2310021302 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES 50 TO 499HPON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE RICHBURN COMPRESSOR ENGINES 50 TO 499 HP2310021303 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES 500+ HPON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE RICHBURN COMPRESSOR ENGINES 500+ HP2310021400 GAS WELL DEHYDRATORS ON-SHORE GAS PRODUCTION DEHYDRATORS2310021401 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES <50 HP W/ NSCRON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE RICHBURN COMPRESSOR ENG. <50HP W/ NON SPECIFIC CATALYTICREDUCTION2310021402 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES 50-499HP W/ NSCRON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE RICHBURN COMPRESSOR ENG. 50-499HP W/ NON SPECIFIC CATALYTICREDUCTIONA-7SCC Tier DescriptionShort Description2310021403 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES 500+ HP W/ NSCRON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE RICHBURN COMPRESSOR ENG. 500+ HP W/ NON SPECIFIC CATALYTICREDUCTION2310021409 NATURAL GAS FIRED 4-CYCLE RICH BURNCOMPRESSOR ENGINES W/NSCR: ALLON-SHORE GAS PRODUCTION NATURAL GAS FIRED 4-CYCLE RICHBURN COMPRESSOR ENGINES WITH NON-SPECIFIC CATALYTICREDUCTION: ALL2310021450 WELLHEADON-SHORE GAS PRODUCTION: WELLHEAD2310021500 GAS WELL COMPLETION - FLARING &VENTINGON SHORE GAS PRODUCTION WELL COMPLETION - FLARING ANDVENTING2310021501 FUGITIVES: CONNECTORS ON-SHORE GAS PRODUCTION: FUGITIVES: CONNECTORS2310021502 FUGITIVES: FLANGES ON-SHORE GAS PRODUCTION: FUGITIVES: FLANGES2310021503 FUGITIVES: OPEN ENDED LINES ON-SHORE GAS PRODUCTION: FUGITIVES: OPEN ENDED LINES2310021504 FUGITIVES: PUMPS ON-SHORE GAS PRODUCTION: FUGITIVES: PUMPS2310021505 FUGITIVES: VALVES ON-SHORE GAS PRODUCTION: FUGITIVES: VALVES2310021506 FUGITIVES: OTHER ON-SHORE GAS PRODUCTION: FUGITIVES: OTHER2310021509 FUGITIVES: ALL PROCESSES ON-SHORE GAS PRODUCTION:FUGITIVES: ALL PROCESSES2310021600 GAS WELL VENTING ON-SHORE GAS PRODUCTION GAS WELLVENTING2310030000 TOTAL: ALL PROCESSES OIL AND GAS EXPLORATION AND PRODUCTION: NATURAL GASLIQUIDS2310030210 TANKS - FLASHING & STANDING/ WORKING/BREATHING, UNCONTROLLEDOIL AND GAS PRODUCTION NATURAL GAS LIQUIDS TANKSINCLUDING FLASH UNCONTROLLED2310030220 TANKS - FLASHING & STANDING/ WORKING/BREATHING, CONTROLLEDOIL & GAS PRODUCTION NATURAL GAS LIQUIDS TANKS INCLUDINGFLASH CONTROLLED2310031000 TOTAL: ALL PROCESSES ON-SHORE OIL AND GAS EXPLORATION AND PRODUCTION:NATURAL GAS LIQUIDS2310111000 ALL PROCESSES ON-SHORE OIL EXPLORATION: ALL PROCESSES2310111401 OIL WELL PNEUMATIC PUMPS ON-SHORE OIL EXPLORATION:OIL WELL PNEUMATIC PUMPS2310111700 OIL WELL COMPLETION: ALL PROCESSES ON-SHORE OIL EXPLORATION: OIL WELL COMPLETION: ALLPROCESSES2310111701 OIL WELL COMPLETION: FLARING ON-SHORE OIL EXPLORATION: OIL WELL COMPLETION: FLARING2310111702 OIL WELL COMPLETION: VENTING ON-SHORE OIL EXPLORATION: OIL WELL COMPLETION: VENTING2310121000 ALL PROCESSES ON-SHORE GAS EXPLORATION: ALL PROCESSES2310121401 GAS WELL PNEUMATIC PUMPS ON-SHORE GAS EXPLORATION:GAS WELL PNEUMATIC PUMPS2310121700 GAS WELL COMPLETION: ALL PROCESSES ON-SHORE GAS EXPLORATION: GAS WELL COMPLETION: ALLPROCESSES2310121701 GAS WELL COMPLETION: FLARING ON-SHORE GAS EXPLORATION: GAS WELL COMPLETION: FLARINGA-8SCC Tier DescriptionShort Description2310121702 GAS WELL COMPLETION: VENTING ON-SHORE GAS EXPLORATION: GAS WELL COMPLETION: VENTINGaSCCs were obtained from TCEQ.

### A-9

3.0 Source Types

3.1 Well Completions



### Following drilling and casing, a well must be “comp leted.” Completion is the process which enables the well to produce oil or gas . To complete the production well, casing is insta lled and cemented and the drilling rig is removed from the s ite. As the well is completed, an initial mixture of gas, hydrocarbon liquids, water, sand, a nd 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 addr esses VOC emissions associated with the completion process at oil and gas wells. County-le vel 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 informa tion 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 fromOil 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 ap proaches for estimating releases from well completions/recompletions. One component-based met hod is utilized in several studies including the 2008 CENRAP study “Recommendations fo r Improvements to the CENRAP States’ Oil and Gas Emissions Inventories” (Bar-Ila n, 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 st udies estimate the emissions per completion

### A-10

event based on the volume of vented gas per complet ion and the mass fraction of the given pollutant in the venting gas. This value is multip lied by the number completion events and takes into account destruction of a portion of the pollut ant 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 ga ses). 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 NO

x 

### emissions and uses a displacement equation (mass balance approach) to estimate SO 2 

### and VOC emissions. Emissions are then calculated b y 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 we ll completions, ERG will use the methodology from the Central Regional Air Planning Association (CENRAP) study.

Emissions from well completions will be estimated o n the basis of the volume of gas vented during completion and the average VOC content of th at gas, obtained from a gas composition analyses. Emissions rates are evaluated at standar d temperature and pressure (STP) in the CENRAP study. Data on the operating temperature an d pressure will be collected via survey and emissions will be adjusted for the appropriate oper ating parameters.

The calculation methodology for completion emission s follows Equations 1 and 2:

907200 5 10 5.3 ) / ( )

(

, i

gas vented

i completion 

### f

T MW R V P E ×        



### −

× × × ×

= 

### Equation (1)

where:

E

completion,i 

### is the emissions of pollutant i 

### from a single completion event [ton/event]

P 

### is atmospheric pressure [1 atm]

V vented 

### is the volume of vented gas per completion [MCF/eve nt]

R 

### is the universal gas constant [0.082 L-atm/mol-K]

MW gas 

### is the molecular weight of the gas [g/mol]

T 

### is the atmospheric temperature [298 K] f i 

### 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:


# ( )

green flare county i completion TOTAL completion c c S E E

− − × × = 98.0

1

, , 

### Equation (2)

where:

E

completion,TOTAL 

### are the total emissions county-wide from completion s [tons/year]

E completion,i 

### are the completion emissions from a single completi on event [tons/event]

c flare 

### is the fraction of completions in the basin control led by flares

### A-11

c green 

### is the fraction of completions in the basin control led by green completion techniques

S county 

### is the county-wide new well and recompleted well co unt

Volume of vented gas per completion, V vented 

### : The 2008 CENRAP study obtained basin-level vented g as volumes from survey data. ERG will attempt to obtain estimates for the volume of vente d 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 coll ected 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, f i 

### : The 2008 CENRAP study obtained basin-level mass fra ctions for various pollutants from survey data. Where survey data were not available for a s pecific basin, the average of all CENRAP basins was used. ERG will attempt to obtain estimat es for the mass fraction of pollutants by conducting a survey of oil and gas. Depending on t he amount of data collected, averages may be determined at the county level, the TRC District le vel, 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 re asonable.

Number of completions controlled by flares, c flare 

### and the number of green completions, c green 

### : The 2008 CENRAP study obtained basin-level estimate s 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 estim ates 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 t he 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, S county 

### : 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 estim ation approach, county-level data on the number of well completions, volume of vented gas pe r completion, oil and gas product composition, and number of completions controlled b y flares or controlled by green completion techniques, and the number of active oil and gas we lls are required. ERG will collect data on the number of oil and gas well completions per county u sing the most recently available database from the TRC. ERG will attempt to collect all othe r data items by conducting a survey of oil and gas producers owning active wells in the Texas coun ties 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 interve ntion work can be done on the wells. Typically, well blowdowns are conducted on wells th at have been shut in for a period of time and the operator desires to bring the well back int o 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, blowdow ns can be a source of VOC emissions. County-level emissions from this source will be est imated for the purpose of this inventory.

3.2.1 Literature Review



### ERG conducted a literature review to obtain informa tion 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 fromOil 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 ap proaches for estimating releases from well blowdowns. One component-based method is utilized i n several studies including the 2008 CENRAP study “Recommendations for Improvements to t he CENRAP States’ Oil and Gas Emissions Inventories” (Bar-Ilan, et al. 2008), “De velopment of Emissions Inventories for Natural Gas Exploration and Product Activities in t he Haynesville Shale” (Grant, et al., 2009) and the “Development of Baseline 2006 Emissions fro m Oil and Gas Activity in the Piceance Basin” (Bar-Ilan, et al., 2009a). Emissions from b lowdowns are estimated on the basis of the volume of gas vented during a blowdown and the aver age 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 contr ol 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 surv ey 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:

907200 5 10 5.3 ) / ( )

(

, i

gas vented

i blowdown 

### f

T MW R V P E ×        



### −

× × × ×

= 

### Equation (3)

where:

E

completion,i 

### is the emissions of pollutant i 

### from a single blowdown event [ton/event]

P 

### is atmospheric pressure [1 atm]

V vented 

### is the volume of vented gas per blowdown [MCF/event ]

R 

### is the universal gas constant [0.082 L-atm/mol-K]

MW gas 

### is the molecular weight of the gas [g/mol]

T 

### is the atmospheric temperature [298 K] f i 

### 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:


# ( )

green flare wells blowdown i blowdown TOTAL blowdown c c N N E E

− − × × × = 98.0 1

, , 

### Equation (4)

where:

E

blowdown,TOTAL 

### are the total emissions county-wide from blowdowns [tons/year]

E blowdown,i 

### are the blowdown emissions from a single blowdown e vent [tons/event]

N blowdown 

### is the number of blowdowns per well in the county

N wells 

### is the total number of active wells in the county

c flare 

### is the fraction of blowdowns in the basin controlle d by flares

c green 

### is the fraction of blowdowns in the basin controll ed by green completion techniques

### A-14

Volume of vented gas per blowdown, V vented 

### : The 2008 CENRAP study obtained basin-level vented g as volumes from survey data. ERG will attempt to obtain estimates for the volume of vente d gas per blowdown by conducting a survey of oil and gas producers. In the event that insuff icient 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 presen ted 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, f i 

### : The 2008 CENRAP study obtained basin-level mass fra ctions for various pollutants from survey data. Where survey data was not available for a sp ecific basin, the average of all CENRAP basins was used. ERG will attempt to obtain estimat es for the mass fraction of pollutants by conducting a survey of oil and gas producers. Depe nding 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 cou nties, ERG may default to the average mass fractions of pollutants presented in the 2008 CENRA P 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, N blowdown 

### : The 2008 CENRAP study obtained basin-level number o f 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 insuff icient data is collected on a particular county, ERG will use the average of all other counties. De pending 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 cou nties, ERG may default to the average mass fractions of pollutants presented in the 2008 CENRA P 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, N wells 

### : The 2008 CENRAP study obtained basin-level number o f 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 o n 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 re asonable.

Number of blowdowns controlled by flares, c flare 

### and the number of green blowdowns, c green 

### : The 2008 CENRAP study obtained basin-level estimate s for the number of blowdowns controlled by flares and the number of blowdowns co ntrolled by green techniques from survey data. ERG will attempt to obtain county-level esti mates for the number of blowdowns controlled by flares or green blowdown methods either by condu cting 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 le vel, the basin level, or state-wide.

3.2.4 Data Needs



### In order to implement the preferred emissions estim ation 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 requ ired. ERG will collect data on the number of oil and gas wells per county using the most recentl y available database from the TRC. ERG will attempt to collect all other data items by conducti ng 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 o f the wellhead is to hold the casings and the production tubing of the well. On top of the wellhead sits the tubi ng hanger, from which the production tubing is run. The well christmas tree rests on top of t he 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 est imated for the purpose of this inventory.

3.3.1 Literature Review



### ERG conducted a literature review to obtain informa tion 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 approa ches to estimate emissions from wellheads at oil and gas sites. The first of these approaches i s 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 so urces to determine wellhead emissions. These sources include: tanks, dehydrators, heaters, completions, and pneumatic devices.

### A-16

Emissions from all of these sources are discussed e lsewhere in this report. The “Emissions from Oil and Gas Production Facilities” (TCEQ, 2007) stu dy 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 we llheads, ERG will use the AP-42 emission factor to calculate emissions from oil and gas well heads, 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 i n Texas is also available from the TRC. However, additional emission methodologies may be d eveloped if additional sources are located.

3.3.4 Data Needs



### In order to implement the preferred emissions estim ation approach, county-level data on the number of oil wellheads and gas production are requ ired. 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 trans ducers, liquid level controllers, pressure controllers and positioners. During the normal ope ration 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 purpos e of this inventory.

3.4.1 Literature Review



### ERG conducted a literature review to obtain informa tion on established methodologies to estimate the atmospheric release of pollutants from emissions generated by pneumatic devices typically utilized at oil and natural gas productio n 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 fromOil 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 approa ches with different bases to estimate emissions from pneumatic devices at oil and gas sit es. The first of these approaches is presented in the Western Regional Air Partnership (WRAP) Phas e I (Russell, et al., 2005) and WRAP Phase II (Bar-Ilan, et al., 2007) reports which uti lize separate emissions factors for oil wells and gas wells provided by the Wyoming Department of Env ironmental Quality (WYDEQ). The

emissions factors for VOC and Hazardous Air Polluta nts (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, contin uous 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 f rom oil and gas production facilities. However, the emissions factors were recalculated us ing weight percents provided in a 2004 report from the Gas Processors Association (GPA).

An alternative approach is presented in both the 20 08 CENRAP study “Recommendations for Improvements to the CENRAP States’ Oil and Gas Emis sions Inventories” (Bar-Ilan, et al. 2008) and “Development of Baseline 2006 Emissions from Oi l and Gas Activity in the Piceance Basin” (Bar-Ilan, et al., 2009a). The same calculation ap proach is used in this method; however, this

method uses bleed rates obtained from the results o f 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 contr ollers, 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 t he additional level of detail presented with this approach, it will be the preferred approach for est imating emissions from pneumatic devices.

### A-18

3.4.3 Preferred emission estimation approach



### As a preferred method to estimate emissions from pn eumatic devices, ERG will use the CENRAP methodology.

Emissions from a single well site are calculated us ing Equation 5:

5

, 10 5.3 907200

− × × ×         ×      

× × = 

# ∑

T MW R P t N V f E

gas i annual

i i j

j pneumatic Equation (5)

where:

E

pneumatic,j is the total emissions of pollutant j from all pneumatic devices for a typical well [ton/year/well]

V i is the volumetric bleed rate from device i [scf/hr/device]

N i is the total number of device i owned by the participating companies

t annual is the number of hours per year that devices are o perating

P is the atmospheric pressure [1 atm]

R is the universal gas constant [0.082 L-atm/mol-K]

MW gas is the molecular weight of the gas [g/mol]

T is the atmospheric temperature [298 K] f j is the mass fraction of pollutant j in the vented gas

County-wide emissions are calculated using Equation 6:

well j pneumatic TOTAL pneumatic N

E E ×

=

, , Equation (6)

where:

E

pneumatic,TOTAL is the total pneumatic device emissions in the coun ty [ton/yr]

E pneumatic,j is the pneumatic device emissions for a single well of pollutant j [ton/yr]

N well 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 emiss ions will be adjusted for the appropriate operating parameters.

Volumetric bleed rate from device i, V i : 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 blee d rates from the EPA Natural Gas Star program study when calculating emissions from pneum atic devices at oil and gas production

sites.

Total number of devices, N i : The 2008 CENRAP study obtained basin-level total nu mber of devices per well from survey data. Where survey data was not available for a sp ecific basin, the average of all CENRAPA-19

basins was used. ERG will attempt to obtain estima tes for the number of devices per well by conducting a survey of oil and gas producers. Depe nding 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 cou nties, ERG may default to the average of number of devices for each type presented in the 2008 CENR AP study. The CENRAP data can also be used as a quality assurance check to ensure that re sults from the survey are reasonable.

Number of hours per year that devices are operating

, t annual : The 2008 CENRAP study assumed basin-level annual ho urs of device operation to be 8760 hr/yr (non-stop operation). ERG will attempt to obtain e stimates for the annual hours of device operation by conducting a survey of oil and gas pro ducers. 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 coll ected on all counties, ERG may default to a value of 8760 hr/yr assumed in the 2008 CENRAP study. Th e CENRAP data can also be used as a quality assurance check to ensure that results from the survey are reasonable.

Molecular weight of gas, MW gas : The 2008 CENRAP study obtained basin-level molecula r weights of gas bleeding from survey data. ERG will attempt to obtain data on the molec ular 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 a verage 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, f j : The 2008 CENRAP study obtained basin-level mass fra ctions 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 col lected, averages may be determined at the county level, the TRC District level, the basin lev el, or state-wide. If insufficient data is collected on all counties, ERG may default to the c ompositions presented in the 2008 CENRAP study. The CENRAP data can also be used as a quali ty assurance check to ensure that results from the survey are reasonable.

3.4.4 Data Needs

In order to implement the preferred emissions estim ation 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 othe r data items by conducting a survey of oil and gas producers owning active wells in the Texas coun ties 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 pu mps and piping to transport oil and gas from the wellhead to the processing area. These pumps a nd piping networks are constructed with many individual components including flanges, valve s, 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 whi le oil and gas product flows through them. County-level emissions from these sources will be e stimated for the purpose of this inventory.

3.5.1 Literature Review

ERG conducted a literature review to obtain informa tion 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 fromOil 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 simi lar approach for estimating fugitive emissions from equipment leaks. This method estimates emissi ons 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 equi pment applies – gas, light liquid, heavy liquid, or water. Emissions are then calculated by multipl ying 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 latt er data were collected via industry surveys. These well-based emissions are then multiplied by t he 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 o btained, performing a component-based analysis will allow for the most comprehensive esti mates for fugitive releases.

3.5.3 Preferred emission estimation approach

As a preferred method to estimate fugitive emission s from equipment leaks, ERG will use the CENRAP methodology.

Fugitive emissions from a single well site may be c alculated using Equation 7:



# ∑ ×

× × × =

i j annual i i j fugitive Y

t N EF E 0011 .0

, Equation (7)

where:

E

fugitive,j is the fugitive emissions for a single typical wel l for pollutant j [ton/yr/well]

EF i is the emission factor of TOC for a single compone nt i [kg/hr/component]

N i is the total number of components of type i

t annual is the annual number of hours the well is in opera tion [hr/yr]

Y j is the mass fraction of pollutant j to TOC in the vented gas

County-wide fugitive emissions are calculated using Equation 8:

well j fugitive TOTAL fugitive N

E E ×

=

, , Equation (8)

where:

E

fugitive,TOTAL is the total fugitive emission in the county [ton/y r]

E fugitive,j is the fugitive emissions for a single well of poll utant j [ton/yr]

N well 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 emiss ions will be adjusted for the appropriate operating parameters.

Emission factor of TOC for a single component, EF i : ERG will use EPA’s AP-42 emissions factors when cal culating fugitive emissions from equipment leaks at oil and gas production sites.

Total number of components, N i : The 2008 CENRAP study obtained basin-level total nu mber of components per well from survey data. Where survey data was not available for a sp ecific basin, the average of all CENRAP basins was used. ERG will attempt to obtain estimat es for the number of components per well by conducting a survey of oil and gas producers. Depe nding 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 cou nties, ERG may default to the average number of components for each service type presented in the 2 008 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, t annual : The 2008 CENRAP study assumed basin-level annual ho urs of well operation to be 8760 hr/yr (non-stop operation). ERG will attempt to obtain e stimates for the annual hours of well operation by conducting a survey of oil and gas pro ducers. 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 coll ected on all counties, ERG may default to a value of 8760 hr/yr assumed in the 2008 CENRAP study. Th e 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, Y j : The 2008 CENRAP study obtained basin-level mass fra ctions 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 col lected, averages may be determined at the county level, the TRC District level, the basin lev el, or state-wide. If insufficient data is collected on all counties, ERG may default to the c ompositions presented in the 2008 CENRAP study. The CENRAP data can also be used as a quali ty assurance check to ensure that results from the survey are reasonable.

3.5.4 Data Needs

In order to implement the preferred emissions estim ation 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 mo st 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 i n 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 with out access to electricity, combustion engines are used. The most common "off-grid" pumpjack engi nes 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 well head compressor engines, but they operate continuously (8760 hours per year) with minimum dow n-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 informa tion 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 o ne methodology used in determining emissions from pumpjack engines. The 2008 study co nducted by ENIRON entitled: "Recommendations for Improvements to the CENRAP Sta tes' Oil and Gas Emission Inventories" (Bar-Ilan, et al., 2008), applies pollutant specifi c emission factors (g/hp-hr) to various data gathered from an inventory of artificial lift engin es (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 basi n 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 SO 2 ) were obtained from the EPA’s NONROAD model (EPA, 2005), which contains default e missions factors for an artificial lift natural gas fired engine. A similar methodology wa s 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 base d 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 stu dies is discussed in Section 3.6.3.A-24

As an alternative to the methodology used in the CE NRAP 2008 and the 2006 New Mexico studies, ERG explored the idea of applying the meth odology 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 knowi ng 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/equipm ent variations. ERG will attempt to obtain the required data to implement this methodology (pu mpjack engine size, hours of operation, engine loads, well depth, and production data for e ach 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 s tudy to generate estimated emissions from pumpjack engines. The calculation methodology for this particular approach is shown in Equations 9 and 10:

185

, 907 annual i engine t

LF HP EF E ×

× ×

= Equation (9)

where:

E engine are emissions from a pumpjack engine [ton/year/eng ine]

EF i 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

t annual 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(

, pumpjack pumpjack TOTAL engine TOTAL engine e f W E E

− × × × = Equation (10)

where:

E engine,TOTAL is the total emissions from pumpjack engines in the county [ton/yr]

E engine is the total emissions from a pumpjack engine [ton/ yr]

W TOTAL is the total number of wells in the county f pumpjack is the fraction of oil wells with pumpjack engines

e

pumpjack is the fraction of pumpjack engines that are elect rified

3.6.4 Data Needs

ERG will implement the approach used in the 2008 CE NRAP study and 2006 New Mexico study to estimate emissions from pumpjack engines. In or der 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 pu mpjack engines is required. ERG will collect data on the number of oil wells per county using th e most recently available database from the TRC. ERG will attempt to collect all other data it ems by conducting a survey of oil and gas producers owning active oil wells in the Texas coun ties covered in this emissions inventory development effort.

If the industry response is sufficient, ERG may att empt to develop power-to-pump requirements (Hp-hr/bbl) for pumpjack engines to implement the a lternative approach.

3.7 Heaters and Boilers

The purpose of heaters and boilers at oil and gas p roduction facilities is to provide thermal energy input to certain operations within the produ ction 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. T hey are primarily considered a source of NO

x , as well as a minor source of CO, VOC and PM emissio ns. SO 2 emissions may also occur if the gas used to fire the heaters contains Hydrogen Sulf ide (H 2 S) which will be subsequently

converted to SO 2 during combustion. County-level emissions from he ater sources will be estimated for the purpose of this inventory.

3.7.1 Literature Review

ERG conducted a literature review to obtain informa tion on established methodologies to estimate the atmospheric release of pollutants from emissions generated by heaters and boilers typically utilized at oil and natural gas productio n 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, 2007A-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 fromOil 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 appr oaches to estimating emissions from heaters and boilers at oil and gas sites. The first of the se approaches is presented in the WRAP Phase I report “Oil and Gas Emission Inventories for the We stern States” (Russell, et al., 2005) and WRAP Phase II report “WRAP Area Source Emissions In ventory Projections and Control Strategy Evaluation Phase II” (Bar-Ilan, et al., 20 07). This approach will subsequently be referred to as Method 1. Method 1 utilizes separat e emissions factors for oil wells and gas wells provided by the WYDEQ. The emissions factors for g as wells are given on a per well basis (lbs/yr per well) and oil well emissions factors ar e given on a per barrel produced basis (lbs/barrel). Area-wide emissions are then calcula ted 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 i n the Piceance Basin” (Bar-Ilan, et al.,

2009a ) from the Independent Petroleum Association of Moun tain States (IPMAS)/WRAP Phase III reports. This approach will subsequently be re ferred to as Method 2. For Method 2, emissions of a particular pollutant from a single h eater 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 fa ctors 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 frac tion of operating hours that the heater is actually firing. The 2008 CENRAP report also provi des a separate methodology for estimating

SO 2 emissions by estimating the mass of gas combusted in the heater using the ideal gas law and then utilizing the mass fraction of H 2 S in the gas assuming 100 percent conversion to SO 2

. Basin-wide emissions were then estimated by determi ning the typical number of heaters per well and scaling up by well count. These estimates were then expanded to the county-level byA-27

allocating the total basin-wide heater emissions in to 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 heater s and boilers. Method 1 uses emissions factors which are previously calculated based on in dustry-wide averages for heater ratings and gas heating values specific to Wyoming, resulting i n 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 f or 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 capture d in Method 1 which only accounts for the

total number of wells.

There are some short-comings with Method 2 that wil l need to be addressed in the development of this current emissions inventory. Due to lack o f 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 t he 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 he aters and boilers, ERG will use the CENRAP methodology.

Emissions from a single heater may be calculated us ing Equation 11 (excluding SO 2 emissions):



# ( )

2000 10 6 × × × × ×

=

local annual

heater heater

heater HV hc

t Q EF E Equation (11)

where:

E

heater is the emissions from a given heater [ton/yr]

EF heater is the emission factor for a heater for a given po llutant [lb/MMSCF] Q heater is the heater MMBTU/hr rating [MMBTU rated /hr]

HV local is the local natural gas heating value [MMBTU local /scf]

t annual 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.

SO 2 emissions from a single heater may be calculated u sing Equation 12:A-28      

 

     

 

× ×         × × × × ×

=

035 .0 907200 2

2

2 , T MW R P

HV hc t Q f E

gas local annual heater S H

SO heater Equation (12)

where:

E

heater,SO2 is the SO 2 emissions from a given heater [ton-SO 2 /yr] f H2S is the mass fraction of H 2 S in the gas Q heater is the heater MMBTU/hr rating [MMBTU rated /hr]

t annual 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.

HV local is the local natural gas heating value [MMBTU local /scf]

P is atmospheric pressure [1 atm]

R is the universal gas constant [0.082 L-atm/mol-K]

MW gas is the molecular weight of the gas [g/mol]

The total emissions generated by heaters and boiler s from specific county are calculated using Equation 13:



# ( )

2000 2 , , TOTAL

heater SO heater heater TOTAL heater W N E E E × × + = Equation (13)

where:

E

heater,TOTAL is the total heater emissions in the county [ton/yr ]

E heater is the total emissions from a single heater [ton/y r]

E heater,SO2 is the total SO 2 emissions from a single heater [ton-SO 2 /yr]

W TOTAL is the total number of wells in the county

N heater is the typical number of heaters per well in the c ounty

Emission factor for a heater for a given pollutant, E heater : ERG will use EPA’s AP-42 emissions factors when cal culating emissions from heaters and boilers at oil and gas production sites.

Heater MMBTU/hr rating, Q heater : The 2008 CENRAP study obtained basin-level heater f iring 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 c onducting 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 quali ty assurance check to ensure that results from the survey are reasonable.A-29

Local natural gas heating value, HV local : The 2008 CENRAP study attempted to collect basin-le vel 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 conductin g 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 va lue presented in the 2008 CENRAP study originally taken from the IPAMS/WRAP Phase III stud y. The CENRAP data can also be used as a quality assurance check to ensure that results fr om the survey are reasonable.

Annual hours of operation, t annual : The 2008 CENRAP study obtained basin-level annual h ours of operation for heaters from survey data. ERG will attempt to obtain data on the annua l hours of operation for heaters and boilers by conducting a survey of oil and gas producers. Depe nding 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 cou nties, 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 re sults from the survey are reasonable.

Heater cycling fraction, hc : The 2008 CENRAP study obtained basin-level heater c ycling fractions from survey data. A heater cycling fraction of 1 was obtained for all r esponding 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 de termined at the county level, the TRC District level, the basin level, or state-wide. If insufficient data is collected on all counties, ER G may default to a value of 1 as used in the 2008 CEN RAP study. The CENRAP data can also be used as a quality assurance check to ensure that re sults from the survey are reasonable.

Mass fraction of H 2 S, f H2S : The 2008 CENRAP study obtained basin-level mass fra ctions of H 2 S in the gas used to fire the heaters and boilers from survey data. ERG will att empt to obtain data on the mass fraction of

H 2 S by conducting a survey of oil and gas producers, or from the TRC. Depending on the amount of data collected, averages may be determine d at the county level, the TRC District level,
the basin level, or state-wide. If insufficient da ta is collected on all counties, ERG may default to the average of the H 2 S mass fractions in the 2008 CENRAP study. The CEN RAP data can also be used as a quality assurance check to ensure that results from the survey are reasonable.

Molecular weight of gas, MW gas : The 2008 CENRAP study obtained basin-level molecula r 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. Depe nding 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 cou nties, ERG may default to the average of the molecular weights in the 2008 CENRAP study. The CE NRAP data can also be used as a quality

assurance check to ensure that results from the sur vey are reasonable.A-30

Typical number of heater per well, N heater : The 2008 CENRAP study obtained basin-level typical number of heaters per well from survey data. ERG will attempt to obtain data on the numbe r 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 le vel, 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 CEN RAP data can also be used as a quality

assurance check to ensure that results from the sur vey are reasonable.

3.7.4 Data Needs

In order to implement the preferred emissions estim ation approach, county-level data on the number of heaters and boilers per well, annual hour s of heater operation, heater ratings, local natural gas heating values, heater cycling fraction s, gas molecular weight and H 2 S content, and number of active oil and gas wells are required. E RG will collect data on the number of oil and gas wells per county using the most recently availa ble database from the TRC. ERG will attempt to collect all other data items by conducting a sur vey of oil and gas producers owning active

wells in the Texas counties covered in this emissio ns inventory development effort.

3.8 Dehydrators

Oil and natural gas, when first pumped from the gro und, 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 s eparator. 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 dehydrat ing natural gas is to contact the gas with a hygroscopic liquid such as one of the glycols. G lycol dehydration is an absorption process, where the water vapor in the gas stream becomes dis solved 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 proce ss, the glycol also absorbs some methane and

VOC.

After leaving the absorber, the water-rich glycol i s de-pressurized. This step is necessary as the absorber is typically operated at high pressure. T he 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 prima ry 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 theA-31

temperature of the mixture is greater than 212 degr ees (the boiling point of water), but less than 400 degrees (the boiling point of glycol). The reg eneration 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 combu stion results in emissions of NO X and CO,

and small amounts of PM 10 , SO 2 , 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 regene rator boiler. The flash vessel and glycol regenerator normally vent methane, VOC, and HAP dur ing normal, uncontrolled operation, while the glycol regenerator boiler also has combus tion emissions.

3.8.1 Literature Review

ERG conducted a literature review to obtain informa tion 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 St ates (Russell, et al., 2005) WRAP

States December 2005

Emissions from Oil and Gas Production Facilities (T CEQ, 2007) Texas August, 2007

WRAP Area Source Emissions Inventory Projections an d 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 Ga s Exploration and Production Activity in the Haynesvi lle Shale (Grant, et al., 2009) Haynesville
Shale, Texas

& Louisiana August 2009

3.8.2 Emission Estimation Approaches

The reviewed literature provided both component-bas ed 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 I nventories for the Western States” (Russell, et al., 2005), the 2007 WRAP Phase II stu dy “WRAP Area Source Emissions Inventory Projections and Control Strategy Evaluation Phase I I” (Bar-Ilan, et al., 2007), and the 2007 TCEQ study “Emissions from Oil and Gas Production F acilities” estimated uncontrolled VOC emissions from dehydrator flash vessels and glycol regenerator vents using a gas productionbased emission factor provided by the WYDEQ. The e mission factor was multiplied by wellspecific gas production figures obtained from the S tate oil and gas commissions. The Wyoming emission factor was derived by calculating a produc tion-weighted average composition of wet gas for each formation across the state. The weigh ted average was then used with GlyCalc modeling software to calculate emission factors bas ed 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 Wyomin g.

The 2009 WRAP Phase III study “Development of Basel ine 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 rege nerator 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 Improvem ents 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 ves sels were estimated with GlyCalc software using data on the composition of wellhead gas for e ach 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 product ion in each basin to derive basin-wide emissions estimates for dehydrator flash vessels an d 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 emiss ions estimates for glycol regenerator boilers. This methodology was also used in the 2009 study “D evelopment 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 o f dehydrator system control technologies on emissions. The 2007 WRAP Phase II study “WRAP Area Source Emissions Inventory Projections and Control Strategy Evaluation Phase I I” (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, instal l 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. GlycolA-33

recirculation rate is set for the optimal rate base d 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 d esigned for the original production rates tend to over circulate causing emission incre ases 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 glyc ol fluids. Typically, fluids are moved through the glycol dehydration and regenerati on 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 v essel separator on dehydrator systems that do not already incorporate one.

The 2007 WRAP Phase II study “WRAP Area Source Emis sions 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 o f 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 applic able for vents in dehydrator systems. VRUs also ‘increase’ oil and gas production by reco vering hydrocarbons that would be lost and redirecting them for pipeline sale or onsite fuel s upply.

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 fact ors will be based on gas composition and production data obtained from the survey or other a vailable 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 u sing 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 wi ll be based on survey data for the amount of fuel needed to regene rate the glycol given the glycol flow rates and average moisture content of the gas produced. Depe nding 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 dehydr ator-related emissions are discussed below. These equations assume that all gas require s dehydration, either in the field or at a central processing facility, that all dehydrators c irculate glycol at the optimum rate, and that the standard dehydrator system does not incorporate a f lash vessel.A-34

The calculation methodology for dehydrator flash ve ssel and glycol regenerator vent emissions at the county level follows Equation 14:

E dehydrator , i, county j = EF dehydrator, i, county j x P gas, county j x (1 + 0.5 C

flowrate – 0.25 C

flashvessel – 0.98 C

vru – 0.98 C

flare ) Equation (14)

where:

E

dehydrator, i, county j is the emissions of pollutant i from dehydrators in county j [tons/year]

EF dehydrator, i, county j is the emission factor for pollutant i from dehydra tors in county j
[tons/MSCF]

P gas, county j is the production of gas in county j [MSCF/year]

C flowrate is the fraction of gas production in county j witho ut optimized dehydrator flow

rate

C flashvessel is the fraction of gas production in county j with dehydrators equipped with

flash tanks

C

vru is the fraction of gas production in county j contr olled by VRUs

C flare is the fraction of gas production in county j cont rolled 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 si mulation 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 gl ycol regenerator boilers at the county level follows Equation 15:

E regenerator boiler, i, county j

= EF regenerator boiler, i x P gas, county j Equation (15)

where:

E regenerator boiler, i, county j is the emissions of pollutant i from glycol regene rator boilers in county j [tons/year]

EF regenerator boiler, i is the emission factor for pollutant i from a glyc ol regenerator boiler per unit production [tons/MSCF]

P gas, county j is the gas production [MSCF/year]

3.8.4 Data Needs

In order to implement the preferred emissions estim ation approach, county-level data on gas composition (VOC content and HAP speciation), typic al 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 coun ties 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 im purities. The mixture is typically passed through a three-phase separator, which allows the w ater, oil and gas to separate. The liquid oil and water components are then piped to storage tank s. 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 t ypically vented to the atmosphere.

Oil and condensate storage tank emissions at wellhe ad and gathering sites are composed of flashing losses, working losses, and breathing loss es. Flashing losses occur when a produced liquid (crude oil or condensate) with entrained gas es 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 filli ng of the tank. Breathing losses (also called standing losses) occur due to the normal evaporatio n of liquid in a tank. Breathing losses are vapors that are produced in response to the daily t emperature change.

3.9.1 Literature Review

ERG conducted a literature review to obtain informa tion 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 , 2009A-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 fromOil 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-bas ed and production-based approaches for estimating emissions from oil and condensate storag e tanks. The three 2009 WRAP Phase III studies “Development of Baseline 2006 Emissions fro m Oil and Gas Activity in the San Juan Basin” (Bar-Ilan, et al., 2009b), “Development of B aseline 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 Ba sin” (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. The se 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 tha t were then multiplied by basin-wide production to derive emission estimates (San Juan B asin, Uinta Basin).A-37

The 2009 TERC study “VOC Emissions From Oil And Con densate Storage Tanks” (TERC, 2009) used data from the measured emissions from oi l and condensate tank batteries to develop

emission factors for the other oil and condensate s torage tanks in the East Texas region.

The 2009 TCEQ study “Upstream Oil and Gas Storage T ank Project Flash Emissions Models Evaluation” (TCEQ, 2009b) compared data from direct ly 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 Improvem ents 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 c ondensate to develop emissions estimates. The 2009 TCEQ study “Upstream Oil and Gas Storage T ank Project Flash Emissions Models Evaluation” (TCEQ, 2009b), the 2009 TCEQ guidance “ Technical Supplement 6: Above Ground Liquid Storage Tanks” (TCEQ, 2009a), and the 2009 T CEQ guide “Calculating Volatile Organic Compounds (VOC) Flash Emissions from Crude Oil and Condensate Tanks at Oil and Gas Production Sites (APDG 5942)” (TCEQ, 2009c) recomme nd calculating working and breathing losses with EPA TANKS and calculating flashing loss es from black oil systems and gas condensate systems using, in order of preference, d irect measurement, process simulator models (HYSIM, HYSIS, WINSIM, or PROSIM), the E&P TANK pro gram, GRI-HAPCalc, or the GOR

method.

The 2007 TCEQ study used an emission factor develop ed for gas production in Wyoming, which was applied to oil and condensate production data f or Texas.

The reviewed literature also addressed the effect o f storage tank control technologies on emissions. The 2007 WRAP Phase II study “WRAP Area Source Emissions Inventory Projections and Control Strategy Evaluation Phase I I” (Bar-Ilan, et al. 2007) estimated that VOC and HAP emissions could be reduced by 98% through t he use of VRUs. VRUs also ‘increase’ oil and gas production by recovering hydrocarbons t hat would be lost and redirecting them for pipeline sale or onsite fuel supply. The US EPA, i n AP-42, Chapter 13.5 (Industrial Flares), estimates that control of waste VOC via flaring wou ld control VOC by a minimum of 98%.

3.9.3 Preferred Emission Estimation Approach

ERG proposes a two tiered approach to developing re gional 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 t he East Texas Shale region. ERG will use this same methodology in other regions of Texas for whic h adequate existing direct measurement data are available. For other regions of Texas, ER G will use the methodology recommended in the 2009 TCEQ study, the 2009 TCEQ guidance, and th e 2009 TCEQ APDG 5942. Specifically, we anticipate that working and breathing losses wil l be calculated with EPA TANKS, and flashing losses will be calculated using process si mulator models, the E&P TANK program,A-38

GRI-HAPCalc, or the GOR method, using the average V OC 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 w ill 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 em issions at the county level follows Equation

16:

E oil tank, i, county j

= EF oil, i, county j x P oil, county j x (1 – 0.98 C

vru – 0.95 C

flare ) Equation (16)

where:

E oil tank, i, county j is the emissions of pollutant i from oil storage ta nks in county j [tons/year]

EF oil, i, county j is the emission factor for pollutant i from oil sto rage tanks in county j
[tons/MSCF]

P oil, county j is the production of oil in county j [MSCF/year]

C

vru is the fraction of oil production in county j contr olled by VRUs

C flare is the fraction of oil production in county j contr olled by flares

The calculation methodology for condensate storage tank emissions at the county level follows Equation 17:

E condensate tank, i, county j

= EF condensate, i, county j x P condensate, county j x (1 – 0.98 C

vru – 0.95 C

flare ) Equation (17)

where:

E condensate tank, i, county j is the emissions of pollutant i from oil storage ta nks in county j [tons/year]

EF condensate, i, county j is the emission factor for pollutant i from oil sto rage tanks in county j [tons/MSCF]

P condensate, county j is the production of oil in county j [MSCF/year]

C

vru is the fraction of condensate production in county j controlled by VRUs

C flare is the fraction of condensate production in county j controlled by flares

Emission factors, EF oil, i, county j , EF condensate, 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 fac tors in developing emissions estimates for the counties covered by these studies. For the rem ainder of Texas, ERG will attempt to obtain county-level data on the properties of oil and cond ensate 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 P oil, county j , P condensate, 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, C flare and the fraction of storage tanks controlled by VRUs, C

vru : 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 p roducers, or from existing data from the TRC. Depending on the amount of data collected, av erages 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 estima tion 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 g as 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 dete rmined. 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 conducti ng 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 atm osphere.

3.10.1 Literature Review

ERG conducted a literature review to obtain informa tion 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 (T CEQ, 2007) Texas August,

2007

WRAP Area Source Emissions Inventory Projections an d 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,

2009A-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 loadin g. 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 a nd temperature-dependent vapor pressures of crude oil from AP-42. Temperature data from 87 wea ther stations throughout Texas were obtained and isotherms were developed to estimate a verage annual temperatures for each county in Texas. These temperatures determined both the t rue vapor pressure using AP-42 data and the average temperature of the bulk liquid (T). The mo lecular 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, respe ctively. 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-depende nt 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 conde nsate produced in each county, which was obtained from data provided by the TRC.

The reviewed literature also addressed the effect o f 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 I I” (Bar-Ilan, et al. 2007) estimated that VOC and HAP emissions could be reduced by 98% through t he use of VRUs. The US EPA, in AP-42, Chapter 13.5 (Industrial Flares), estimates that co ntrol 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 c alculated at the county level. These emission factors will be multiplied by county-specific produ ction data obtained from the TRC to derive county-specific emission estimates. This methodolo gy requires oil and condensate production data, data on the composition and RVP of the oil an d 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 th at 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 fa ctors is shown in Equation 18:

LL oil, condensate, county j

= 12.46 x S x P x M / T county j Equation (18)A-41

Where:

LL oil, 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 ope ration)

P is True vapor pressure of liquid loaded [psia]

M is Molecular weight of tank vapors [lb/lb-mole]

T county j is Temperature of bulk liquid loaded [ o R] for county j

The AP-42 equation to calculate temperature-depende nt 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 th e emission factor by county-level production figures for oil and condensate production, as shown in Equation 19:

E loading, county j

= LL oil, condensate, county j x P oil, condensate, county j x 42 gal/bbl x 1 ton/2,000 lbs x ( 1 – 0.98 C

vru – 0.98 C

flare ) Equation (19)

Where:

E loading, county j is the emissions from oil or condensate truck loadi ng for county j [ton/year]

LL oil, condensate, county j is the emission factor for oil or condensate loadin g loss for county j [lb/1,000gal]

P oil, condensate, county j is oil or condensate production for county j [bbl/y ear]

C

vru is the fraction of loading in county j controlled b y VRUs

C flare is the fraction of loading in county j controlled by flares

3.10.4 Data Needs

In order to implement the preferred emissions estim ation approach, county-level oil and condensate production data on a monthly basis, load ing type, vapor pressure data for oil and condensate, molecular weight of tank vapors, and mo nthly average temperature data for each county is needed. ERG will collect county-level oi l 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 st udy. The 2007 TCEQ data can also be used as a QA check on the reasonableness of the sur vey results.

3.11 Compressor Engines

Spark-ignited internal combustion engines are norma lly 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 NO

x area emissions source category as they generally o perate 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 informa tion 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, 2009A-43

3.11.2 Emission estimation approaches

Of the studies reviewed, the majority take a simila r approach in determining emissions from compressor engines at oil and gas production facili ties. 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 S ection 3.11.3.

It should be noted that the CENRAP 2008 report vari es from this approach in that it recommends using well count as a surrogate for scaling wellhea d 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 estimate s 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 na tural 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 engi nes at oil and gas production facilities. The annual natural gas production by county will be obt ained for the year 2008 from the TRC.

County-level emission factors will be calculated us ing the methodology from the study “Natural Gas Compressor Engine Survey and Engine NO X 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 prod uction facilities (HARC, 2005). The HARC 2005 report was updated in 2006 to include more eng ine size categories and to add the year 2000 to the previous inventory; however, these updates d id not change the calculation methodology used in the original 2005 report.

County-level emission factors will be calculated Eq uation (19) as provided in the HARC study

reports:

EF ijk = F 1i x F 2j x C i x H

j x EF j k x 1/2000 Equation (19)

Where:

EF

ijk is the emission factor for county i, for engine ty pe j, and pollutant k [tons/MSCF]

F 1i is the fraction of wells requiring compression in county i

F 2j is the fraction of compression load represented by engines of type j

C i is the compression requirements for county i [hp-h r/MSCF]

H j is the brake specific fuel consumption for engine t ype j [MMBtu/hp-hr]

EF jk is the emission factor for engine type j, and poll utant k [lb/MMBtu]

The data needed to implement this approach is discu ssed below.A-44

Fraction of wells requiring compression in county i

, F 1i : 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 ph one as well as through a survey questionnaire. Although the fraction of wells greater than one yea r 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 distric ts for 2008. The number of wells completed each year and the total number of operating wells b y district are available from the TRC.

Fraction of compression load represented by engines of type j, F 2j : While the initial report (HARC, 2005) focused on en gines less than 500 horsepower (hp), the follow-up report (HARC, 2006) included engines grea ter 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. I n 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, NO X

emissions, and other data to TCEQ. If insufficien t data are available through the D-FW and Southeast Texas surveys, ERG may defau lt to the distribution of engine types presented in the follow-up HARC report and TCEQ sur veys to estimate the fractions of various engine types in attainment and nonattainment areas of Texas.

Compression Requirements for county i, C i : A compressor's operating behavior is generally depe ndent 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 comp ressor suction and discharge pressures required to convey the natural gas from the well he ad to the gathering lines. These pressures, or the compression ratio, along with the natural gas f low-rate through the compressor, define the engine load in terms of the amount of mechanical wo rk 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 e ngine 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 o f this direct relationship of mechanical work to volume of fuel burned, one would expect a 1 00 Hp engine to burn almost an equal amount of fuel as two (2) 50 Hp engines when compre ssing the same volume of natural gas produced by the same well. Therefore, it is not ne cessary 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 c ompressors have a maximum rating and most of them deliver less natural gas than their maximum ra ting. In a 2002 emissions inventory (Pollution Solutions, 2005) entitled "Tyler/Longvie w/Marshall Flexible Attainment Region Emission Inventory", the author developed a compression requirement (hp-day/MSCF) through survey data assuming the compressor engines were op erating under full load or maximumA-45

installed horsepower. This assumption caused an ov erestimation 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 Pollut ion 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 tha n 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 deter mine more accurate emissions estimates for compressor engines located in Panola County as well as the five NETAC counties.

The 2005 HARC report developed compression requirem ents ranging between 3.1 and 3.5 Hphr/MSCF for three distinct districts in eastern Tex as, including one attainment area and two nonattainment areas (Houston and Dallas) by obtaini ng typical well pressures and gathering line pressures through a field study. The engines in thi s particular field survey were operated at loads ranging from about 10% to 70% of full load, and ave raged 40% load. Additionally, compression requirements that can be deduced from the 2008 Poll ution 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 200 5 Pollutions Solutions study, when adjusted for the load factors from the 2008 Polluti ons 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 locat ed in the D-FW metropolitan area) a compression requirement of 226 Hp-day/MMcf for area source compressor engi nes outside the D-FW metropolitan area. This value equates to appr oximately 5.4 Hp-hr/MSCF which is also in agreement with previous studies mentioned.

ERG will attempt to develop 2008 compression requir ements through a new survey questionnaire that would aim to collect typical wel l pressures and gathering line pressures, as well as engine load factors. As mentioned previous ly, the compression requirements developed for the 2005 HARC study, the 2008 Pollution Solutio ns 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 attainmen t and nonattainment areas if insufficient data is obtained through the survey effort.

Brake specific fuel consumption for engine type j, H j : The HARC studies (HARC, 2005 and 2006) determined b rake specific fuel consumption for the most common engine model of each engine category us ing engine model distributions provided by engine leasing companies. ERG will develop updat ed representative engine models using data gathered through a survey questionnaire. In additi on, 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, EF jk : As noted in the 2008 CENRAP study, there are two di stinct types of compressor engines used to boost the pressure of well-head natural gas: “rich- burn” engines that are characterized by NO

x emissions factors in the range of approximately 10 – 20 g/bhp-hr; and “lean-burn” engines that are characterized by NO

x emissions factors in the range of approximately 1. 0 – 5.0 g/bhp-hr. TheA-46

exact NO

x emissions factors depend on the horsepower, make a nd model, and model year of the engine, and whether the engine has been converted f rom 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 Inv entory 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-h ead compressor engine makes and models. From this database, average rich-burn and lean-burn engine emissions factors for NO

x , VOC,
CO, and SO 2 were derived. PM 10 , CO 2 , and CH 4 emission factors were obtained from AP-42. It should be noted that all pollutant and engine-speci fic emission factors used in the 2005/2006

HARC studies were taken from AP-42.

For this study, ERG will attempt to develop improve d emission factors (especially for NO

x 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 dat a, 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 2 006 New Mexico study. If insufficient data is collected through the survey effort, ERG may def ault 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 for maldehyde 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 A P-42 formaldehyde emission factors have an "A" rating.

3.11.4 Data Needs

In order to implement the preferred emission estima tion approach, the gas production in each county is needed. ERG will collect data on throughp ut per county using the most recently available database from the TRC. This activity dat a when applied to the different factors mentioned in Section 3.11.3 above, will allow ERG t o estimate county-level emissions from compressor engines.

3.12 Turbines

Turbines are used in the oil and gas industry to co mpress gas or to generate electricity. In the gas industry they tend to be used in processing and tra nsmission rather than gathering applications (CAPP, 2004). Compressors driven by turbines may b e found at midstream oil and gas facilities such as large pipeline compressor stations, gas sto rage facilities, or gas processing plants. Turbines may also be utilized in some smaller upstr eam applications to assist in the transfer of gas produced in the field from multiple or individu al well sites or gas gathering plants to midstream facilities. However, some of these appli cations (at the well or gas gathering plant level) are usually handled by reciprocating interna l combustion engines, which are covered inA-47

Section 3.11 of this memo. Most midstream faciliti es utilizing natural gas-fired turbines are assumed to be permitted and included in the invento ry as major point sources. Turbines used in the oil and gas industry burn natural gas and can r epresent a significant source of NO

x emissions, in addition to other combustion-related pollutants.

In remote locations such as offshore platforms or o il 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 informa tion 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 F rom Oil and Gas Activity in the Unita Basin” (Friesen, et al., 2009) included one compres sor station that was defined as a turbine as part of the point source inventory. The data for t his point source was provided directly by the

State of Utah.

The study “Emissions from Oil and Gas Production Fa cilities” (TCEQ, 2007) included emission from turbines located at offshore platforms as obta ined from the Minerals Management Service (MMS). The study did not estimate emissions from o nshore 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 Reportin g System (STARS) emissions inventory. There are no existing studies that present approach es for estimating area sources emissions from turbines used in oil and gas upstream production so urces, but there are AP-42 emission factorsA-48

that could be used if it is discovered that there a re turbines not counted in the point source inventory.

3.12.4 Data Needs

As part of the survey efforts, ERG will include que stions 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 s ource inventory) would be used for the same purposes as compressor engines, the target recipien ts of the survey would be identical. Based on the findings of the HARC “Natural Gas Compressor En gine Survey for Gas Production and Processing Facilities” study (HARC, 2006), there ar e 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 a rea 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; Poll ack, Alison; Henderer, Doug; Pring, Daniel; and Sgamma, Kathleen, 2009a. Development of Baselin e 2006 Emissions from Oil and Gas Activity in the Piceance Basin. Prepared for the We stern Governor’s Association and the Independent Petroleum Association of Mountain State s. January, 2009.

Bar-Ilan, Amnon; Grant, John; Parikh, Rajashi; Poll ack, Alison; Henderer, Doug; Pring, Daniel; and Sgamma, Kathleen, 2009b. Development of Baselin e 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 State s. November, 2009.

Bar-Ilan, Amnon; Parikh, Rajashi; Grant, John; Shah , Tejas; and Pollack, Alison, 2008. Recommendations for Improvements to the CENRAP Stat es’ Oil and Gas Emissions Inventories. Prepared for Central States Regional Air Partnershi p. November, 2008

Bar-Ilan, Amnon; Friesen, Ron; Pollack, Alison; and Hoats, Abigail, 2007. WRAP Area Source Emissions Inventory Projections and Control Strateg y 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, Vol ume 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-Il an, Amnon; Pollack, Alison; Henderer, Doug; Pring, Daniel; Sgamma, Kathleen; and Schlagel, Phil , 2009. Development of Baseline 2006A-49

Emissions from Oil and Gas Activity in the Uinta Ba sin. Prepared for the Western Governor’s Association and the Independent Petroleum Associati on of Mountain States. March, 2009.

Grant, John; Parker, Lynsey; Bar-Ilan, Amnon; Kemba ll-Cook, Sue; Yarwood, Greg. Development of Emissions Inventories for Natural Ga s Exploration and Production Activities in the Haynesville Shale. Prepared for The East Texas Council of Governments. August 2009.

Houston Advanced Research Center (HARC), 2005. Natu ral Gas Compressor Engine Survey and Engine NO X Emissions at Gas Production Facilities. Prepared b y Eastern Research Group, Inc. August 31, 2005.

Houston Advanced Research Center (HARC), 2006. Natu ral 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/Calculati onLosses.pdf

Pollack, Alison; Russell, James; Grant, John; Fries en, Ron; Fields, Paula; and Wolf, Marty, 2006. Ozone Precursors Emission Inventory for San J uan and Rio Arriba Counties, New Mexico. Prepared for New Mexico Environment Department. Aug ust, 2006.

Pollution Solutions, 2005. “Tyler/Longview/Marshall Flexible Attainment Region Emission Inventory of Ozone Precursors VOC, NOx and CO,” Pre pared 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 Consideratio n for Load Factor" Final report prepared for the East Texas Council of Governments, Kilgore, TX.

Russell, James and Pollack, Alison, 2005. Oil and G as Emissions Inventories for the Western States. Prepared for Western Governor’s Association . December, 2005.

Texas Commission on Environmental Quality (TCEQ), 2 007. Emissions from Oil and Gas Production Facilities, 2007. Prepared by Eastern Re search Group, Inc. August 31, 2007.

Texas Commission on Environmental Quality (TCEQ), 2 009a. 2009 Emissions Inventory Guidelines: Appendix A: Technical Supplement 6: Abo ve Ground Liquid Storage Tanks. Texas Commission on Environmental Quality, TCEQ Publicati on RG-360A/09. January 2009.

Texas Commission on Environmental Quality (TCEQ), 2 009b. Upstream Oil and Gas Storage Tank Project Flash Emissions Models Evaluation. Jul y, 2009.A-50

Texas Commission on Environmental Quality (TCEQ), 2 009c. Calculating Volatile Organic Compounds (VOC) Flash Emissions from Crude Oil and Condensate Tanks at Oil and Gas Production Sites (APDG 5942), 2009. September, 200 9.

Texas Commission on Environmental Quality (TCEQ), 2 009d. Flash Emissions Model Evaluation Quantifying Volatile Organic Compound Em issions 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 En gineering). October 2009.

Texas Environmental Research Consortium (TERC), Oct ober 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

H 2 S Hydrogen Sulfide IPMAS Independent Petroleum Association of Mountai n 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

PM 10 Particulate Matter that has particle diameter les s than 10 micrometers

PM 2.5 Particulate Matter that has particle diameter les s than 2.5 micrometers QA Quality Assurance

SCC Source Classification Code

SCF Standard Cubic Feet

SO 2 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 Agenc y VOC Volatile Organic Compounds VRU Vapor Recovery Unit WRAP Western Regional Air Partnership WYDEQ Wyoming Department of Environmental QualityAppendix B – Task 3 MemorandumB-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 s elect counties in Texas. The inventory will address area source criteria pollutant emissions of volatile organic compounds (VOC), nitrogen oxides (NO X ), carbon monoxide (CO), particulate matter with an aerodynamic diameter less than or equal to 10 microns (PM 10 ), particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (PM 2.5 ), and sulfur dioxide (SO 2 ); and certain toxic pollutant emissions such as formaldehyde from compressor engines, and benzene, toluene, ethylbenzene, and xylene from dehydrators. In addition to compiling the emission s 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 e mission source type, develop a methodology for estimating emissions from oil and g as production sites based on the oil and gas produced at the county level, and identify the prod ucers 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 activit ies. The first, implemented in 2007, focused on compiling a state-wide emissions invento ry (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 yea r, 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 devel oping 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 fou r primary technical work tasks:

• Identification and review of existing studies perta ining to estimating emissions from oil and gas production sites and recommendation of an e mission estimation approach for each identified source type;

• Identification of oil and gas well operators and pr eparation of draft survey materials, including obtaining data from existing studies and databases;

• Development of a methodology to estimate county-lev el 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 Fo rmat (NIF) 3.0 text files for import into Texas Air Emissions Repository (TexAER).

The purpose of this memo is to document the methodo logy ERG will use to identify the owners and/or operators of oil and gas production sites, a nd to provide TCEQ with draft survey materials. Additionally, the methodology used to d evelop the draft survey materials are provided. In the project Work Plan, this work is r eferred 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 Se ction 2.0. Section 3.0 presents example draft survey forms, the process used to develop these, wi th the forms and instructions for each source type provided in Attachment B.

County-level, area source emission estimates will b e 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 Are a Source operators who were active in Texas in 2008. A list of candidate owners and operators wer e 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. Th is database contains over 18,500 records for wells where drilling occurred in 2008. In addi tion, 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 operato r contact information (Company Name, Company Contact Name, and Company Contact Mai ling Address) for over 24,000

wells. The combined data for these 2 datasets is i ncluded in Attachment A as “Drilling Data 2008 Contact Directory.xls”.

• TCEQ Permit Data – TCEQ provided contact informatio n 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 Fa cilities). This database containsB-3

owner and operator contact information (Company Nam e, 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 Permi t 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 Divisi on by name, including address and telephone number. The listing includes all operator s with Active status on Commission organization records, as well as those with "Delinq uent" status (indicating that they still have activity, but have not updated their organizat ional 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/ogdirect ory/index.php) on April 28, 2010 and is

included in Attachment A as “TRC Oil and Gas Contac t Directory.xls”.

These databases were imported into MS Access for ea sy querying for duplicates and to QA

addresses and contact information. The final datase ts 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, a nd Well Completions. These forms were

structured such that the information needed to deve lop 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 u niversally accessible (through the use of widely used software found in MS-Office), and to ma ke them consistent with the format and nomenclature used in TCEQ’s current Barnett Shale s tudy. TCEQ comments on the draft survey materials have been incorporated into the final sur vey materials provided herein.

Attachment B presents final survey forms for Artifi cial Lift Engines, Compressor Engines, Dehydrators, Equipment Leaks, Heaters, Loading Rack s, Pneumatic Devices, Storage Tanks, Well Blowdowns, and Well Completions.B-4 ATTACHMENT A

(See files “Standard Permit 116.620 Contact Directo ry.xls”, “TRC Oil and Gas Contact

Directory.xls”, and “Drilling Data 2008 Contact Dir ectory.xls”)B-5 ATTACHMENT B

Draft Survey Packages

(See files “Artificial Lift Engine Survey.xls”, “Co mpressor 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 DataC-1Appendix C. HAP FactorsSource CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourcePump Jack Natural Gas VOC0.11259434 lb/MMBtuPump Jack Natural Gas Acetaldehyde 2.79E-03 lb/MMBtu 2.48E+00 AP-42,Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Acrolein2.63E-03 lb/MMBtu 2.34E+00 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Benzene1.58E-03 lb/MMBtu 1.40E+00 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas 1,3-Butadiene 6.63E-04 lb/MMBtu 5.89E-01 AP-42,Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Carbon Tetrachloride* 1.77E-05 lb/MMBtu 1.57E-02 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Chlorobenzene* 1.29E-05 lb/MMBtu 1.15E-02 AP-42,Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Chloroform* 1.37E-05 lb/MMBtu 1.22E-02 AP-42,Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Dichlorobenzene 1.20E-03 lb/MMBtu 1.07E+00AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas 1,3-Dichloropropene* 1.27E-05 lb/MMBtu 1.13E-02AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMBtu 1.42E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Ethylbenzene* 2.48E-05 lb/MMBtu 2.20E-02 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Ethylene Dibromide* 2.13E-05 lb/MMBtu 1.89E-02 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Formaldehyde 2.05E-02 lb/MMBtu 1.82E+01 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Methanol 3.06E-03 lb/MMBtu 2.72E+00 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Methylene Chloride 4.12E-05 lb/MMBtu 3.66E-02AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas 2-Methylnaphthalene 2.40E-05 lb/MMBtu 2.13E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMBtu 1.60E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Naphthalene* 9.71E-05 lb/MMBtu 8.62E-02 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Propylene 0.016842105 lb/MMBtu 1.50E+01Air Resources Board. CaliforniaEnvironmental Protection Agency.http://www.arb.ca.gov/app/emsinv/catef_form.htmlPump Jack Natural Gas Styrene*1.19E-05 lb/MMBtu 1.06E-02 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas 1,1,2,2-Tetrachloroethane 2.53E-05 lb/MMBtu 2.25E-02 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Toluene5.58E-04 lb/MMBtu 4.96E-01 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas 1,1,2-Trichloroethane* 1.53E-05 lb/MMBtu 1.36E-02 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Vinyl Chloride* 7.18E-06 lb/MMBtu 6.38E-03 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas Xylenes (isomers and mixture) 1.95E-04 lb/MMBtu 1.73E-01 AP-42, Section 3.2 (U.S. EPA 2002)Pump Jack Natural Gas o-Xylenes 0.01 EPA Speciate 4.2 DatabasePump Jack Natural Gas m-Xylenes 0.01 EPA Speciate 4.2 DatabaseC-2Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourcePump Jack Natural Gas PM7.70E-04 lb/MMBtuPump Jack Natural Gas Acenaphthene* 1.80E-06 lb/MMBtu 2.34E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Acenaphthylene* 1.80E-06 lb/MMBtu 2.34E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Anthracene* 2.40E-06 lb/MMBtu 3.12E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMBtu 2.34E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Benzo(a)pyrene* 1.20E-06 lb/MMBtu 1.56E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Benzo(b)fluoranthene* 1.80E-06 lb/MMBtu 2.34E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Benzo(g,h,i)perylene* 1.20E-06 lb/MMBtu 1.56E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMBtu 2.34E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Chrysene* 1.80E-06 lb/MMBtu 2.34E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMBtu 1.56E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Fluoranthene 3.00E-06 lb/MMBtu 3.90E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Fluorene2.80E-06 lb/MMBtu 3.64E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Indeno(1,2,3-cd_pyrene* 1.80E-06 lb/MMBtu 2.34E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Phenanathrene 1.75E-05 lb/MMBtu 2.27E+00AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionPump Jack Natural Gas Pyrene5.00E-06 lb/MMBtu 6.49E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionC-3Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceBoiler-Max MMBTU/hr<10-natural gas Natural Gas Total VOC5.5lb/MMscfburned AP-42, Sections 1.4 (U.S. EPA 2002)Boiler-Max MMBTU/hr<10-natural gas Natural Gas Acetaldehyde 0.0089lb/MMscfburned 1.6127E-01Air Resources Board. CaliforniaEnvironmental Protection Agency.http://www.arb.ca.gov/app/emsinv/catef_form.htmlBoiler-Max MMBTU/hr<10-natural gas Natural Gas Benzene0.0021lb/MMscfburned 3.8182E-02AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Dichlorobenzene 1.2000E-03lb/MMscfburned 2.1818E-02AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.6000E-05lb/MMscfburned 2.9091E-04AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Formaldehyde 0.0750lb/MMscfburned 1.3636E+00AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Hexane 1.8000E+00lb/MMscfburned 3.2727E+01AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas 2-Methylnaphthalene 2.4000E-05lb/MMscfburned 4.3636E-04AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gasNatural Gas 3-Methylchloranthrene* 1.8000E-06lb/MMscfburned3.2727E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gasNatural Gas Naphthalene 6.1000E-04lb/MMscfburned1.1091E-02AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Toluene 3.4000E-03lb/MMscfburned 6.1818E-02AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Total PM1.9lb/MMscfburned AP-42, Sections 1.4 (U.S. EPA 2002)Boiler-Max MMBTU/hr<10-natural gas Natural Gas Acenaphthene* 1.8000E-06lb/MMscfburned 9.4737E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Acenaphthylene* 1.8000E-06lb/MMscfburned 9.4737E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Anthracene* 2.4000E-06lb/MMscfburned 1.2632E-04AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionC-4Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceBoiler-Max MMBTU/hr<10-natural gas Natural Gas Benz(a)anthracene* 1.8000E-06lb/MMscfburned 9.4737E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Benzo(a)pyrene* 1.2000E-06lb/MMscfburned 6.3158E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gasNatural Gas Benzo(b)fluoranthene* 1.8000E-06lb/MMscfburned9.4737E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gasNatural Gas Benzo(g,h,i)perylene* 1.2000E-06lb/MMscfburned6.3158E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Benzo(k)fluoranthene* 1.8000E-06lb/MMscfburned 9.4737E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Chrysene* 1.8000E-06lb/MMscfburned 9.4737E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Dibenzo(a,h)anthracene* 1.2000E-06lb/MMscfburned 6.3158E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Fluoranthene 3.0000E-06lb/MMscfburned 1.5789E-04AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Fluorene 2.8000E-06lb/MMscfburned 1.4737E-04AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Indeno(1,2,3-cd)pyrene* 1.8000E-06lb/MMscfburned 9.4737E-05AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Phenanathrene 1.7000E-05lb/MMscfburned 8.9474E-04AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionBoiler-Max MMBTU/hr<10-natural gas Natural Gas Pyrene 5.0000E-06lb/MMscfburned 2.6316E-04AP-42, Sections 1.4 (U.S. EPA 2002)Natural Gas CombustionC-5Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceNatural Gas Engines 2 cycle rich Natural Gas VOC 5.152709841 lb/MMscf AP-42, Section 5.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Acetaldehyde2.79E-03 lb/MMscf 5.41E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Acrolein2.63E-03 lb/MMscf 5.10E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Benzene1.58E-03 lb/MMscf 3.07E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas 1,3-Butadiene6.63E-04 lb/MMBtu 1.29E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Carbon Tetrachloride* 1.77E-05 lb/MMBtu 3.44E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Chlorobenzene*1.29E-05 lb/MMBtu 2.50E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Chloroform*1.37E-05 lb/MMBtu 2.66E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Dichlorobenzene 1.20E-03 lb/MMscf 2.33E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas 1,3-Dichloropropene* 1.27E-05 lb/MMBtu 2.46E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMscf 3.11E-04AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Ethylbenzene* 2.48E-05 lb/MMscf 4.81E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Ethylene Dibromide* 2.13E-05 lb/MMscf 4.13E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Formaldehyde2.05E-02 lb/MMscf 3.98E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Hexane1.80E+00 lb/MMscf 3.49E+01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Methanol 3.06E-03 lb/MMscf 5.94E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Methylene Chloride 4.12E-05 lb/MMscf 8.00E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas 2-Methylnaphthalene 2.40E-05 lb/MMscf 4.66E-04AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMscf 3.49E-05AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Naphthalene* 9.71E-05 lb/MMBtu 1.88E-03 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Propylene 0.016842105 lb/MMBtu 3.27E-01Air Resources Board. CaliforniaEnvironmental Protection Agency.http://www.arb.ca.gov/app/emsinv/catef_form.htmlNatural Gas Engines 2 cycle rich Natural Gas Styrene*1.19E-05 lb/MMBtu 2.31E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas 1,1,2,2-Tetrachloroethane 2.53E-05 lb/MMBtu 4.91E-04 AP-42, Section 3.2 (U.S.EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Toluene5.58E-04 lb/MMBtu 1.08E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas 1,1,2-Trichloroethane* 1.53E-05 lb/MMBtu 2.97E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Vinyl Chloride* 7.18E-06 lb/MMBtu 1.39E-04 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Xylenes (isomers and mixture) 1.95E-04 lb/MMBtu 3.78E-03 AP-42, Section 3.2 (U.S. EPA 2002)C-6Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceNatural Gas Engines 2 cycle rich Natural Gas o-Xylenes0.01 EPA Speciate 4.2 DatabaseNatural Gas Engines 2 cycle rich Natural Gas m-Xylenes0.01 EPA Speciate 4.2 DatabaseNatural Gas Engines 2 cycle rich Natural Gas PM3.84E-02 lb/MMscf AP-42, Section 5.2 (U.S. EPA 2002)Natural Gas Engines 2 cycle rich Natural Gas Acenaphthene* 1.80E-06 lb/MMscf 4.69E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Acenaphthylene*1.80E-06 lb/MMscf 4.69E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Anthracene* 2.40E-06 lb/MMscf 6.25E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMscf 4.69E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Benzo(a)pyrene* 1.20E-06 lb/MMscf 3.13E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Benzo(b)fluoranthene* 1.80E-06 lb/MMscf 4.69E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Benzo(g,h,i)perylene* 1.20E-06 lb/MMscf 3.13E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMscf 4.69E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Chrysene* 1.80E-06 lb/MMscf 4.69E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMscf 3.13E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Fluoranthene3.00E-06 lb/MMscf 7.81E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Fluorene2.80E-06 lb/MMscf 7.29E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Indeno(1,2,3-cd_pyrene* 1.80E-06 lb/MMscf 4.69E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Phenanathrene 1.75E-05 lb/MMscf 4.56E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 2 cycle rich Natural Gas Pyrene5.00E-06 lb/MMscf 1.30E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionC-7Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceNatural Gas Engine 4 cycle lean Natural Gas VOC0.12 lb/MMBtu AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Acetaldehyde8.36E-03 lb/MMBtu 6.97E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Acrolein5.14E-03 lb/MMBtu 4.28E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Benzene4.40E-04 lb/MMBtu 3.67E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Biphenyl 2.12E-04 lb/MMBtu 1.77E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas 1,3-Butadiene2.67E-04 lb/MMBtu 2.23E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Carbon Tetrachloride* 3.67E-05 lb/MMBtu 3.06E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Chlorobenzene*3.04E-05 lb/MMBtu 2.53E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Chloroform*2.85E-05 lb/MMBtu 2.38E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Dichlorobenzene 1.20E-03 lb/MMBtu 1.00E+00AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas 1,3-Dichloropropene* 2.64E-05 lb/MMBtu 2.20E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMBtu 1.33E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas Ethylbenzene 3.97E-05 lb/MMBtu 3.31E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Ethylene Dibromide* 4.43E-05 lb/MMBtu 3.69E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Formaldehyde5.28E-02 lb/MMBtu 4.40E+01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Methanol 2.50E-03 lb/MMBtu 2.08E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas 2-Methylnaphthalene 3.32E-05 lb/MMBtu 2.77E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMBtu 1.50E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas Methylene Chloride 2.00E-05 lb/MMBtu 1.67E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas n-Hexane 1.11E-03 lb/MMBtu 9.25E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Naphthalene 7.44E-05 lb/MMBtu 6.20E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Phenol2.40E-05 lb/MMBtu 2.00E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Propylene 0.012673684 lb/MMBtu 1.06E+01Air Resources Board. CaliforniaEnvironmental Protection Agency.http://www.arb.ca.gov/app/emsinv/catef_form.htmlNatural Gas Engine 4 cycle lean Natural Gas Styrene*2.36E-05 lb/MMBtu 1.97E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Tetrachloroethane 2.48E-06 lb/MMBtu 2.07E-03 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas 1,1,2,2-Tetrachloroethane* 4.00E-05 lb/MMBtu 3.33E-02 AP-42, Section 3.2 (U.S.EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Toluene4.08E-04 lb/MMBtu 3.40E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas 1,1,2-Trichloroethane* 3.18E-05 lb/MMBtu 2.65E-02 AP-42, Section 3.2 (U.S. EPA 2002)C-8Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceNatural Gas Engine 4 cycle lean Natural Gas 2,2,4-Trimethylpentane 2.50E-04 lb/MMBtu 2.08E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Vinyl Chloride 1.49E-05 lb/MMBtu 1.24E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Xylene1.84E-04 lb/MMBtu 1.53E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas o-Xylenes0.01 EPA Speciate 4.2 DatabaseNatural Gas Engine 4 cycle lean Natural Gas m,p-Xylenes0.01 EPA Speciate 4.2 DatabaseNatural Gas Engine 4 cycle lean Natural Gas PM7.71E-04 lb/MMBtu AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Acenaphthene 1.25E-06 lb/MMBtu 1.62E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Acenaphthylene5.53E-06 lb/MMBtu 7.17E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Anthracene* 2.40E-06 lb/MMBtu 3.11E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMBtu 2.33E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas Benzo(b)fluoranthene 1.66E-07 lb/MMBtu 2.15E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Benzo(e)pyrene 4.15E-07 lb/MMBtu 5.38E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Benzo(g,h,i)perylene 4.14E-07 lb/MMBtu 5.37E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMBtu 2.33E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas Chrysene 6.93E-07 lb/MMBtu 8.99E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMBtu 1.56E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas Fluoranthene1.11E-06 lb/MMBtu 1.44E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Fluorene5.67E-06 lb/MMBtu 7.35E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Indeno(1,2,3-cd)pyrene* 1.80E-06 lb/MMBtu 2.33E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engine 4 cycle lean Natural Gas Phenanthrene 1.04E-05 lb/MMBtu 1.35E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engine 4 cycle lean Natural Gas Pyrene1.36E-06 lb/MMBtu 1.76E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas VOC0.03 lb/MMBtuNatural Gas Engines 4 cycle rich Natural Gas Acetaldehyde2.79E-03 lb/MMBtu 9.30E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Acrolein2.63E-03 lb/MMBtu 8.77E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Benzene1.58E-03 lb/MMBtu 5.27E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas 1,3-Butadiene6.63E-04 lb/MMBtu 2.21E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Carbon Tetrachloride* 1.77E-05 lb/MMBtu 5.90E-02 AP-42, Section 3.2 (U.S. EPA 2002)C-9Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceNatural Gas Engines 4 cycle rich Natural Gas Chlorobenzene*1.29E-05 lb/MMBtu 4.30E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Chloroform*1.37E-05 lb/MMBtu 4.57E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas 1,3-Dichloropropene* 1.27E-05 lb/MMBtu 4.23E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas 7,12-Dimethylbenz(a)anthracene* 1.60E-05 lb/MMBtu 5.33E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Ethylbenzene* 2.48E-05 lb/MMBtu 8.27E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Ethylene Dibromide* 2.13E-05 lb/MMBtu 7.10E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Formaldehyde2.05E-02 lb/MMBtu 6.83E+01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Methylene Chloride 4.12E-05 lb/MMBtu 1.37E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas 2-Methylnaphthalene 2.40E-05 lb/MMBtu 8.00E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas 3-Methylchloranthrene* 1.80E-06 lb/MMBtu 6.00E-03AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Naphthalene* 9.71E-05 lb/MMBtu 3.24E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Styrene*1.19E-05 lb/MMBtu 3.97E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas 1,1,2,2-Tetrachloroethane 2.53E-05 lb/MMBtu 8.43E-02 AP-42, Section 3.2 (U.S.EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Toluene5.58E-04 lb/MMBtu 1.86E+00 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas 1,1,2-Trichloroethane* 1.53E-05 lb/MMBtu 5.10E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Vinyl Chloride* 7.18E-06 lb/MMBtu 2.39E-02 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas Xylenes (isomers and mixture) 1.95E-04 lb/MMBtu 6.50E-01 AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas Engines 4 cycle rich Natural Gas o-Xylenes0.01 EPA Speciate 4.2 DatabaseNatural Gas Engines 4 cycle rich Natural Gas m-Xylenes0.01 EPA Speciate 4.2 DatabaseNatural Gas Engines 4 cycle rich Natural Gas PM9.50E-03 lb/MMBtuNatural Gas Engines 4 cycle rich Natural Gas Acenaphthene* 1.80E-06 lb/MMBtu 1.89E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Acenaphthylene*1.80E-06 lb/MMBtu 1.89E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Anthracene* 2.40E-06 lb/MMBtu 2.53E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Benz(a)anthracene* 1.80E-06 lb/MMBtu 1.89E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Benzo(a)pyrene* 1.20E-06 lb/MMBtu 1.26E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionC-10Appendix C. HAP Factors (Cont.)Source CategoryFuel TypePollutantEmission FactorsEmissionFactor Unit% HAPEmission Factor SourceNatural Gas Engines 4 cycle rich Natural Gas Benzo(b)fluoranthene* 1.80E-06 lb/MMBtu 1.89E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Benzo(g,h,i)perylene* 1.20E-06 lb/MMBtu 1.26E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Benzo(k)fluoranthene* 1.80E-06 lb/MMBtu 1.89E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Chrysene* 1.80E-06 lb/MMBtu 1.89E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Dibenzo(a,h)anthracene* 1.20E-06 lb/MMBtu 1.26E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Fluoranthene3.00E-06 lb/MMBtu 3.16E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Fluorene2.80E-06 lb/MMBtu 2.95E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Indeno(1,2,3-cd_pyrene* 1.80E-06 lb/MMBtu 1.89E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Phenanathrene 1.75E-05 lb/MMBtu 1.84E-01AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionNatural Gas Engines 4 cycle rich Natural Gas Pyrene5.00E-06 lb/MMBtu 5.26E-02AP-42, Section 3.2 (U.S. EPA 2002)Natural Gas CombustionAppendix D – Compressor Engine WorkbookAppendix E – Texas Oil and Gas Emissions InventoryAppendix F – Formatted TexAer Files