Appendix B-4 

2011 Oil and Gas Inventory Enhancement Project for 

CenSARA States 

 
2011 Oil and Gas Emission Inventory 

Enhancement Project for CenSARA States 

Prepared for: 

CENTRAL STATES AIR RESOURCES 

AGENCIES (CenSARA) 

P.O. Box 617 

Oklahoma City, OK 73101 

Prepared by: 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, California, 94945 

www.environcorp.com 

P-415-899-0700 

F-415-899-0707 

Eastern Research Group, Inc. 

1600 Perimeter Park Drive, Suite 200 

Morrisville, NC 27560 

www.erg.com 

P-919 468-7800 

F-919-468-7801 

December 21, 2012 
December 2012 

Disclaimer: The data, type and level of controls, and emission limits in this final report and 

accompanying tool should be considered preliminary and under review by the states. In 

addition, emission and control factors applied in this work may not reflect lower emission limits 

specified in state regulations for ozone non-attainment areas and certain attainment areas 

influencing non-attainment areas. For final 2011 NEI data or for information relating to 

modified emission and control factors, please contact the individual state. 
December 2012 

i 

CONTENTS 

1.0 EXECUTIVE SUMMARY ................................................................................................... 1

2.0 INTRODUCTION ............................................................................................................. 6

2.1 CENRAP Oil and Gas Emission Inventory ......................................................................... 7

2.2 Literature Sources ........................................................................................................... 8

3.0 OBJECTIVES .................................................................................................................. 11

4.0 EMISSIONS INVENTORY DESCRIPTION .......................................................................... 13

4.1 Temporal and Geographic Scope .................................................................................. 13

4.2 Pollutants considered .................................................................................................... 14

4.3 Scope of Emission Sources ............................................................................................ 15

4.4 Oil and Gas Activity Updates for the CenSARA Region ................................................. 17

4.4.1 Obtaining Oil and Gas Activity Data .................................................................... 17

4.4.2 CenSARA Oil and Gas Production Statistics for 2011 ......................................... 22

5.0 INPUT DATA GATHERING ............................................................................................. 29

5.1 Industrial Surveys .......................................................................................................... 29

5.1.1 Geographical Scope ............................................................................................ 29

5.1.2 Survey Description and Development ................................................................ 30

5.1.3 Survey Outreach Process and Results ................................................................. 31

5.2 State Permit Data Review .............................................................................................. 34

5.2.1 Minor Source Permits ......................................................................................... 34

5.2.2 Permit Data Mining Procedure and Examples .................................................... 34

5.3 Literature Sources and Gap-Filling for Non-Surveyed Basins ....................................... 36

5.3.1 Reviewed literature ............................................................................................ 36

5.3.2 Inputs for emissions estimates of non-surveyed basins ..................................... 38

6.0 EMISSIONS CALCULATOR TOOL DEVELOPMENT ............................................................ 41

6.1 Structure of Emissions Tool ........................................................................................... 41

6.2 Summary of methodologies used to estimate emissions for each source 

category ......................................................................................................................... 44

6.2.1 Artificial Lifts ....................................................................................................... 44

6.2.2 Wellhead Compressor Engines ........................................................................... 46

6.2.3 Lateral/Gathering Compressor Engines .............................................................. 48
December 2012 

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6.2.4 Condensate tanks................................................................................................ 50

6.2.5 Dehydrators ........................................................................................................ 53

6.2.6 Drilling Rigs .......................................................................................................... 57

6.2.7 Pneumatic Devices .............................................................................................. 61

6.2.8 Well Completions ................................................................................................ 64

6.2.9 Blowdowns .......................................................................................................... 68

6.2.10 Hydraulic Fracturing Pumps ................................................................................ 71

6.2.11 Fugitive Leaks ...................................................................................................... 72

6.2.12 Heaters ................................................................................................................ 77

6.2.13 Loading Emissions ............................................................................................... 79

6.2.14 Gas-Actuated Pumps ........................................................................................... 81

6.2.15 Mud Degassing .................................................................................................... 85

6.2.16 Crude Oil Tanks ................................................................................................... 88

6.2.17 Produced water tanks ......................................................................................... 91

6.2.18 Casinghead gas venting ....................................................................................... 94

6.3 Output Emissions Summary .......................................................................................... 97

6.4 Formatting tool for NEI submission ............................................................................... 97

7.0 RESULTS....................................................................................................................... 98

7.1 2011 Oil and Gas Area Source Emissions ...................................................................... 98

7.2 Discussion .................................................................................................................... 117

7.2.1 Major oil and gas area sources ......................................................................... 117

7.2.2 Data Gap Findings ............................................................................................. 120

7.2.3 Future work opportunities ................................................................................ 128

8.0 CONCLUSIONS ........................................................................................................... 130

9.0 REFERENCES .............................................................................................................. 131

APPENDICES 

Appendix A: CenSARA States County List

Appendix B: Field Names for Production Data from HPDI

Appendix C: Electronic Appendix: Industry survey forms (Excel Workbooks) 

Appendix D: Electronic Appendix: CenSARA Emissions Calculator Tools (Excel 

Workbooks) 

 
December 2012 

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TABLES 

Table E-1. Key production statistics for basins in the CenSARA domain (HPDI, 

2012). ....................................................................................................................... 2

Table E-2. 2011 Basin-wide Emissions for the CenSARA 2011 Oil and Gas Area 

Source Inventory. .................................................................................................... 4

Table 4-1. Major area sources of NOx, VOCs and HAPs in the upstream oil and gas 

sector. .................................................................................................................... 16

Table 4-2. County-level activity data parameters needed for emissions 

estimation.............................................................................................................. 18

Table 4-3. Production and drilling data sources by state....................................................... 19

Table 4-4. HPDI data coverage by state. ................................................................................ 20

Table 4-5. Basin-wide production statistics for the CenSARA region. ................................... 23

Table 4-6. Summary of production, well counts and spud count by state and 

basin for CenSARA. ................................................................................................ 25

Table 4-7. Summary of drilling activity by basin. ................................................................... 28

Table 5-1. Participating companies in the survey outreach effort. ....................................... 32

Table 5-2. Summary of survey responses and ownership of responses by basin. ................ 32

Table 5-3. Examples of specific data fields gap-filled by state permit data........................... 35

Table 5-4. Specific calculation inputs derived from literature sources. ................................ 37

Table 5-5. Input data assumptions for non-surveyed basins outside of Texas 

(except Marathon Thrust Belt). ............................................................................. 39

Table 5-6. Data sources used for calculation inputs for non-surveyed basins in 

Texas ...................................................................................................................... 40

Table 6-1. Oil and gas emission source categories. ............................................................... 41

Table 6-2. National default emissions factors for mud degassing by mud base. .................. 86

Table 7-1. Basin-wide emissions by area source category for 2011 in the CenSARA 

domain. .................................................................................................................. 99

Table 7-2. Emissions Inventory for 2011 oil and gas sources in CenSARA States. ............... 114

Table 7-3. Quality assessment of input data used to estimate emissions for each 

area source category and basin in CenSARA. ...................................................... 122

FIGURES

Figure E-1. Oil and gas basins in the CenSARA domain. ............................................................ 1

Figure E-2. Active well counts by well type for each basin in CenSARA (HPDI, 

2012). ....................................................................................................................... 3
December 2012 

iv 

Figure 4-1. Oil and gas basins in the CenSARA region. ............................................................ 14

Figure 7-1. NOx emissions by source category (in tons per year). ........................................ 117

Figure 7-2. VOCs emissions by source category (in tons per year). ...................................... 118

Figure 7-3. Methane emissions by source category (in tons per year). ................................ 120
December 2012 

1 

1.0 EXECUTIVE SUMMARY 

The Central States Air Resource Agencies (CenSARA) has identified the need to improve the 

activity data and methodologies used by its member states to develop oil and gas area source 

emissions. CenSARA states, including Texas, Louisiana, Oklahoma, Arkansas, Kansas, Missouri 

and Nebraska need to develop 2011 area source inventories of criteria pollutants (CO, SO2, 

NOx, VOCs, PM), selected hazardous air pollutants (HAPs), hydrogen sulfide and methane to be 

included in their submission to the 2011 National Emissions Inventory (NEI). ENVIRON and the 

Eastern Research Group (ERG) reviewed the available data sources and collected basin-level 

specific emissions information for calendar year 2011 through industry surveys to operators 

within the CenSARA domain. A map of the oil and gas basins within the CenSARA domain is 

shown in Figure E-1. As part of this Project, an Emissions Calculator Tool was developed which 

facilitates calculations of emission estimates for calendar year 2011 and enables each CenSARA 

state to generate oil and gas area source emissions estimates and to format these emissions in 

an EIS-ready format for future NEI submissions. 

Figure E-1. Oil and gas basins in the CenSARA domain. 

The following specific tasks were pursued as part of this goal: 

x Oil and gas production activity levels throughout the CenSARA region including, but not 

limited to, the number of active wells by well type, gas production and oil production, spud 
December 2012 

2 

counts1, feet drilled, and water production were updated for 2011 using the HPDI “DI 

Desktop” database, a commercial database that processes state-level oil and gas 

commission data into a comprehensive database of production statistics. 

x Basin-level data on equipment, activity and emissions factors were developed or collected 

for estimating 2011 emissions from a variety of resources including 1) oil and gas operator 

surveys, 2) state minor source permit applications, and 3) literature review. 

x An Emissions Calculator Tool that estimates 2011 oil and gas area source emissions at the 

basin and county level was developed: estimates are compiled within a worksheet tool, 

documented in this report, which enables CenSARA members to update activity and 

emissions data at the basin and/or county level for future use. The tool is based on the 

existing emissions calculator developed by ERG for Texas (ERG, 2010) but expanded to 

include inventory enhancements performed in the current study. 

x A database program was developed to automatically convert the emissions estimated by 

the Calculator Tool into an EIS-ready format to facilitate NEI submissions. Data stored in the 

EIS staging tables can be converted into valid XML files that are in compliance with the CERS 

using an EPA-supplied XML File Generator tool. This program and the emissions calculator 

provide the necessary set of tools for CenSARA members to both generate the oil and gas 

emissions and format them for NEI submission. 

The CenSARA domain represents a substantial percentage of the onshore oil and gas 

production in the continental United States. In 2010, seven CenSARA oil and gas producing 

states (Texas, Oklahoma, Louisiana, Arkansas, Kansas, Nebraska and Missouri) had a combined 

oil production of approximately 611 million barrels and a combined gas production of 12.8 

trillion cubic feet (EIA, 2012), representing 48 % of total gas production and 31% of total oil 

production in the country. Key production statistics are shown in Table E-1. Production statistics 

obtained from the HPDI database were used as scaling surrogates for estimating oil and gas 

area source emissions at the county level. 

Table E-1. Key production statistics for basins in the CenSARA domain (HPDI, 2012). 

Basin 

2011 Statistics 

Crude Oil 

Production 

(1000 bbl/yr) 

Condensate 

Production 

(1000 bbl/yr) 

Natural Gas 

Production 

(BCF/yr) Spud Count 

Anadarko Basin 38,850 23,404 1,668 1,484 

Arkoma Basin 1,210 106 1,567 952 

Bend Arch-Fort Worth Basin 27,124 3,712 2,088 1,534

Cambridge Arch-Central Kansas 

Uplift 17,441 939 11 843 

Cherokee Platform 9,222 782 104 876 

Denver Basin 393 751 1 6 

East Texas Basin 15,403 6,062 1,839 629 

Forest City Basin 1,329 18 0 773 

Illinois Basin 0 0 3 0 

 

1

 Spud refers to the process of beginning to drill a well. A spud count is the number of wells that commenced 

drilling over a particular period of time. 
December 2012 

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Basin 

2011 Statistics 

Crude Oil 

Production 

(1000 bbl/yr) 

Condensate 

Production 

(1000 bbl/yr) 

Natural Gas 

Production 

(BCF/yr) Spud Count 

Louisiana-Mississippi Salt Basins 14,781 2,151 2,506 707 

Marathon Thrust Belt 4 82 42 8 

Nemaha Uplift 4,620 1,078 23 133 

Ozark Uplift 0 0 0 0 

Palo Duro Basin 3,562 82 19 19 

Permian Basin 299,041 5,683 529 2,201 

Salina Basin 273 8 0 22 

Sedgwick Basin 3,063 1,523 37 257 

Southern Oklahoma 9,377 1,931 78 19 

Western Gulf 144,930 61,147 2,102 1,671 

CenSARA Region Total 590,621 109,459 12,615 12,134

The number of active wells by well type is another key indicator of the oil and gas activity in the 

CenSARA region. Active well counts from the HPDI database for each basin within CenSARA are 

shown in Figure E-2. 

Figure E-2. Active well counts by well type for each basin in CenSARA (HPDI, 2012). 

 -

 20,000

 40,000

 60,000

 80,000

 100,000

 120,000

 140,000

 160,000

 180,000

Oil Well Count Gas Well Count
December 2012 

4 

With the use of the Emissions Calculator Tools developed for this project, 2011 oil and gas area 

source emissions inventories were prepared for each oil and gas producing State within the 

CenSARA region. These inventories are highly detailed in their geographical specificity by 

including emissions at basin, state and county levels, in the array of pollutants included (16 

total), and in the array of source categories analyzed. Source categories included in the 

inventory are: 

x Artificial Lift Engines 

x Wellhead Compressor Engines 

x Lateral Compressor Engines 

x Drilling Rigs 

x Condensate Tanks 

x Hydraulic Fracturing Pumps 

x Well Completion Venting 

x Blowdown Venting 

x Casing Gas Venting 

x Dehydrators 

x Pneumatic Devices 

x Heaters 

x Crude Oil Tanks 

x Produced Water Tanks 

x Gas-Actuated Pneumatic Pumps 

x Fugitive Emissions 

x Mud Degassing 

x Hydrocarbon Liquids Loading 

x Flaring 

Table E-2 shows a summary of resulting basin-wide emissions for 2011 from the oil and gas area 

source inventories developed here. This table only includes emissions for key pollutants of 

relevancy for air quality issues in the CenSARA domain. Emissions by source category are too 

extensive to include here but may be found in other sections of the report. 

Table E-2. 2011 Basin-wide Emissions for the CenSARA 2011 Oil and Gas Area Source 

Inventory. 

Basin NOX (TPY) VOCs (TPY) CH4 (TPY) 

Anadarko Basin 108,952 273,066 708,483 

Arkoma Basin 15,615 16,274 294,226 

Bend Arch-Fort Worth Basin 144,032 147,646 458,542 

Cambridge Arch-Central Kansas Uplift 9,340 39,794 86,424 

Cherokee Platform 36,316 73,951 240,037 

Denver Basin 1,547 7,693 11,984 

East Texas Basin 128,840 100,632 364,708 
December 2012 

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Basin NOX (TPY) VOCs (TPY) CH4 (TPY) 

Forest City Basin 4,345 8,186 19,015 

Illinois Basin 15 16 373 

Louisiana-Mississippi Salt Basins 39,832 40,341 158,601 

Marathon Thrust Belt 3,863 4,525 13,173 

Nemaha Uplift 9,081 22,702 43,783 

Ozark Uplift 0 0 0 

Palo Duro Basin 5,879 6,570 17,978 

Permian Basin 166,429 386,201 626,542 

Salina Basin 82 610 995 

Sedgwick Basin 11,948 25,364 41,127 

Southern Oklahoma 7,491 30,292 56,054 

Western Gulf 142,582 433,119 566,775 

Grand Total CenSARA 836,191 1,616,982 3,708,820 

Review of the oil and gas area source emissions by source category suggests that NOx emissions 

are largely dominated by wellhead compressor emissions, particularly in basins with a large 

number of active gas wells. Other significant sources of NOx include lateral compressors, 

drilling rigs, and well-site heaters. Pneumatic devices are the most significant source of VOC and 

methane emissions in most basins within the CenSARA region. In basins where significant 

production of condensate and crude oil occurs (for example the Permian and Western Gulf 

Basins), VOC emissions are dominated by condensate tank and crude oil tank losses. Other key 

sources of VOC and methane emission include well blowdowns, well-site fugitives and wellhead 

compressor engines. 
December 2012 

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2.0 INTRODUCTION 

The Central States Air Resource Agencies (CenSARA) is a regional organization that supports the 

discussion of air quality issues between its members and other interested parties, and aids in 

identifying options for air pollution control through air quality statutes and regulations. 

CenSARA oil and gas producing states, which include Texas, Oklahoma, Louisiana, Arkansas, 

Kansas, Nebraska and Missouri, have determined that significant area source emissions of 

criteria pollutants (NOx, CO, SO2, VOCs) and greenhouse gases (GHGs) may be associated with 

exploration and production activities in the upstream oil and gas sector. Oil and gas production 

in the remaining two CenSARA states (Iowa and Minnesota) is negligible. Over the last decade, 

oil and gas exploration and production in the United States has grown significantly, primarily in 

the Rocky Mountain states, southern Central states, the Gulf of Mexico, and most recently in 

the Marcellus Shale in the Northeastern U.S. This is partly related to an increased production of 

unconventional oil and gas resources such as shale gas, produced in formations such as the 

Fayetteville Shale in Arkansas, Barnett Shale in Texas and Haynesville Shale in Louisiana. In 

2010, seven CenSARA states (Texas, Oklahoma, Louisiana, Arkansas, Kansas, Nebraska and 

Missouri) had a combined oil production of approximately 611 million barrels and a combined 

gas production of 12.8 trillion cubic feet (EIA, 2012), representing 48 % of total gas production 

and 31% of total oil production in the United States. Sources of emissions in the upstream oil 

and gas sector include equipment and processes used in drilling, completion and production 

activities that are primarily located at or near well sites in active oil and gas fields. These nonpoint emissions sources are generally not monitored under major source permitting programs 

and may or may not be subject to minor source permits, making it difficult for states to identify 

and quantify their emissions and evaluate their collective air quality impacts. Hence, area 

source emissions from the upstream sector remain a source of concern for CenSARA. 

CenSARA sponsored this study to enhance available data and methodologies used by its 

member states to develop oil and gas area source emissions by reviewing and synthesizing 

available data and collecting additional data via oil and gas industry surveys. CenSARA states 

need to develop a 2011 area source inventory for criteria pollutants (CO, SO2, NOx, VOCs, PM), 

selected hazardous air pollutants (HAPs2), hydrogen sulfide and methane to be included with

other emissions inventories submitted to the 2011 National Emissions Inventory (NEI). To 

achieve this, CenSARA contracted ENVIRON and subcontractor Eastern Research Group (ERG) to 

research the available data sources and collect updated and basin-wide specific emissions 

information for upstream oil and gas sources throughout the CenSARA region. In addition, an 

Emissions Calculator Tool was developed as part of this project that facilitates calculation of 

calendar year 2011 emission estimates and will enable each CenSARA state to more easily 

generate emissions estimates for future inventories and NEI submissions. 

 

 

2

 Targeted HAPS include key VOC species – toluene, xylene, formaldehyde, benzene, ethylbenzene, and n-hexane. 
December 2012 

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2.1 CENRAP Oil and Gas Emission Inventory 

This study builds off the work performed by ENVIRON in 2008 for the Central Regional Air 

Planning Association (CENRAP). The CENRAP study was an oil and gas emissions inventory 

enhancement project for the CENRAP region, including Louisiana, Texas, Oklahoma, Arkansas, 

Kansas and Nebraska (Bar-Ilan, et al., 2008). The main objective of the CENRAP study was to 

develop recommendations for input data and detailed methodologies to improve CENRAP’s oil 

and gas area source inventories for the base year 2002 and to develop future year projections 

for calendar year 2018. The study included estimation of nitrogen oxides (NOx), volatile organic 

compounds (VOC), particulate matter (PM10), carbon monoxide (CO), sulfur dioxide (SO2) and 

other pollutants from oil and gas operations. The CENRAP study represented an initial and 

important step towards providing CENRAP states with a means of developing their own 

estimates of oil and gas area source emissions. However, the study had certain limitations such 

as: 

x Limited Survey Participation: a limited survey outreach was performed in the study which 

attempted to gather emissions and activity data for upstream source categories from nine 

(9) major oil and gas producers in the CENRAP region. Even though participating companies 

covered a wide geographic range of activities and ownership of production in the CENRAP 

domain, participation was very limited; only four companies returned surveys with 

sufficient and useful data. 

x Lack of an Emissions Inventory: The CENRAP study was an inventory-enhancement project 

aimed to provide technical guidance and a set of inputs for CENRAP members to 

independently estimate emissions for oil and gas area sources within their jurisdiction. The 

scope of the work did not include development of emission inventories for the base year or 

the future year. 

x Scope of Emissions Sources: some oil and gas source categories, including produced water 

(evaporative ponds, water tanks), drilling mud degassing and hydraulic fracturing engines 

have often not been included in area source inventories, generally due to lack of 

information to characterize their emissions. The current study expands the list of sources 

that were analyzed in CENRAP by now including: hydraulic fracturing pumps, casing gas 

venting, produced water tanks, gas-actuated pneumatic pumps, fugitive emissions from 

compressor seals, mud degassing, and hydrocarbon liquids loading. 

x Use of State-by-State Databases for Production Statistics: the CENRAP study relied on each 

state’s oil and gas conservation commission (OGCC) or equivalent agency’s database to 

obtain drilling and production statistics used to scale emissions on a basin-wide level. This 

required the combination of data from individual states’ OGCC databases which may not all 

have a similar organizational structure. Databases can vary greatly in terms of format, the 

level of detail of the information tracked by each OGCC, and ultimately the availability of 

key statistics such as oil production, gas production, active well counts, spud counts, and 

water production. These inconsistencies impacted the CENRAP study in that it was not 

possible to consistently incorporate low-level statistics such well counts by type, separate 

condensate production and crude oil production estimates, and separate natural gas 

production and casing gas production in all cases. 
December 2012 

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x Use of State Permit Data: Minor source permit applications can be a resource of geographicspecific activity and emissions data for area source emissions inventories. Several states 

have minor source permitting programs that require an air permit for oil and gas production 

facilities (well sites) to operate. These permit applications contain detailed emissions 

calculations that characterize many upstream oil and gas area sources, and they can be a 

useful source of field-type data for regional emissions inventories. The CENRAP study did 

not research minor permit applications to gap-fill data that could not be retrieved by 

industry surveys and literature reviews. The current work takes advantage of this resource. 

2.2 Literature Sources 

Recent studies have become available that contain useful information for estimating emissions 

from oil and gas area sources including information from recent years and/or regions of interest 

to the CenSARA oil and gas emissions inventory. Some of the studies and reports reviewed here 

are: 

Recommendations for Improvements to the CENRAP States’ Oil and Gas Emissions Inventories 

(Bar-Ilan, et al., 2008): As discussed earlier, the CENRAP work included recommendations for 

input data and detailed methodologies to improve oil and gas area source inventories within 

the CENRAP region for year 2002. During the development of emissions inventories in this work 

for selected source categories, the CENRAP study was found to be the most up-to-date and 

regionally-specific source of input data available in the literature for the CenSARA domain. This 

was especially true for some particular categories such as fugitives and heaters that were not 

included in the industry surveys. 

Haynesville Shale 2011 Emissions Inventory Update (ENVIRON, 2012): This study is an update 

for calendar year 2011 of a previous comprehensive inventory of ozone precursor emissions 

(VOC, NOx, and CO) from natural gas exploration and production activities in the Haynesville 

Shale formation, covering its extent in Louisiana and Texas. The updated Haynesville Shale 

inventory is currently in its draft form at the time of the preparation of this report. The original 

study (ENVIRON, 2009) developed emissions for a base year 2009 and future annual projections 

from 2010 to 2020. Source categories included in the inventory range from exploration and 

production phase to downstream sources; emissions sources reviewed included: drill rigs, 

hydraulic fracturing, completion venting, well blowdowns, fugitives, pneumatic devices, 

heaters, dehydrators, flaring, wellhead compressors, compressor stations and gas processing 

plants. In the latest study (ENVIRON, 2012) detailed activity and emissions data on equipment, 

processes, well configuration, emissions factors, and usage were updated with data obtained 

through industry surveys to reflect activity for Haynesville Shale wells in 2011. The current oil 

and gas inventory for CenSARA applies selected preliminary data derived from surveys in the 

Haynesville Shale 2011 draft inventory available as of October 2012 and under the consent of 

the sponsors of that project (NETAC). It must be noted that data from the 2011 Haynesville 

Shale Inventory Update used in this work is in its draft form and may be revised when the 2011 

Haynesville Shale update is finalized. 
December 2012 

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The US EPA 2010 National Greenhouse Gas Inventory (EPA, 2012): This annual inventory is a 

comprehensive analysis of all greenhouse gas emissions sources and sinks in the United States, 

including those in the upstream oil and gas sector. The latest edition available covers years 

1990 to 2010. The study has an independent analysis of emissions from natural gas systems 

that characterizes multiple source categories located at the well-site and in the downstream 

sector. Efforts were made to adjust emissions factors with available data by broad geographic 

producing regions of the United States (Midcontinent, Rocky Mountains, Gulf Coast, etc.) by 

accounting for regional average gas compositions and emissions deductions from state 

regulations or voluntary actions. A separate analysis is available for petroleum systems, which 

analyzes greenhouse gas emissions for the upstream oil sector as well as the transportation and 

refining of crude; these emissions are estimated at a national level, i.e. no regional specificity. 

Since the 2009 edition of the inventory (EPA, 2011), analysis of natural gas systems have 

incorporated adjustments to the inventory to account for hydraulic fracturing in source 

categories like well completions and well workovers. A limitation of this inventory is that it is 

focused on greenhouse gases and thus provides limited information on criteria pollutant 

emissions. However, activity data in these GHG national inventories have proven useful to gapfill missing information for emissions estimates. 

The Climate Registry Oil and Gas Production Protocol (TRC, 2010): This is an annex to The 

Climate Registry’s (TRC) General Reporting Protocol (GRP) that provides guidance on estimating 

and reporting greenhouse gas emissions for members of TRC. The protocol focuses on 

emissions sources in the oil and gas exploration and production sector and provides high-level 

and low-level methodologies to estimate emissions, along with national default emissions 

factors and sample calculations. The protocol is limited to estimating emissions for greenhouse 

gases and thus does not provide emissions factors for criteria pollutants. However, 

methodologies often include a conversion method to extrapolate emissions from one 

hydrocarbon gas to another based on gas analyses, which can then be applied to estimate VOC 

and HAP emissions. 

Texas Statewide Emissions Inventory from Oil and Gas Production (ERG, 2010): This is a 

comprehensive emissions inventory for base year 2008 characterizing area sources from 

upstream onshore oil and gas production sites in Texas. The emissions inventory analyzes 

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

monoxide (CO), particulate matter and hazardous air pollutants (HAPs). Among the sources 

included are dehydrators, oil and condensate tanks, oil and condensate loading, and 

combustion sources such as drilling rigs, artificial lift engines and compressors. The study 

compiled county-level activity data from the Texas Railroad Commission, and specific emissions 

and emission factor data for many source categories from multiple state and regional data 

sources such as vendor data and point source emissions inventory reports. As part of the study, 

an emissions calculator was developed to enable the Texas Commission on Environmental 

Quality to update the emissions inventory for future years by providing updated county-level 

activity data. Inventory development in the current CenSARA work for most Texas basins, 

except Permian, builds off the comprehensive database of activity and emissions factors 

compiled in this study. 
December 2012 

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WRAP Phase III Inventories (WRAP, 2012): These inventories were developed by the Western 

Regional Air Partnership, a regional planning organization for the Rocky Mountain states similar 

to CenSARA in the Central states. The Phase III inventories were the first-ever attempt to 

develop detailed, bottom-up, basin-level criteria pollutant inventories for all oil and gas area 

and point emissions sources. The inventories analyzed a wide range of activities including 

conventional, tight sands and CBM gas production, and oil production. The Phase III inventories 

cover many of the same source categories that are evaluated in the CenSARA inventories. 

Methodologies for estimating area source inventories, and emission factors and input activity 

factors were drawn from the WRAP Phase III inventories as a gap-filling method where other 

information was not available. 
December 2012 

11 

3.0 OBJECTIVES 

States must prepare and submit an inventory of criteria and hazardous air pollutant emissions 

from all emissions sources within their jurisdiction every three years for inclusion in the 

National Emissions Inventory (NEI) compiled by the U.S. Environmental Protection Agency. This 

includes emissions from area sources in oil and gas systems. States’ submissions for the 2011 

NEI are due by the end of 2012. CenSARA is aware that there are data gaps and deficiencies in 

currently available data to characterize oil and gas area sources and has sponsored this study to 

make improvements in the resources available for the preparation of emissions inventories by 

developing reasonable and regionally-representative inputs for emissions calculations and by 

establishing a detailed and reproducible methodology for CenSARA members to apply in future 

NEI submissions. The following tasks were pursued in an effort to achieve this goal: 

x Updated oil and gas production activity throughout the CenSARA region: estimating 

emissions at a basin-wide level requires key production surrogates to be compiled for the 

CenSARA domain on a county-level basis, and for these to be grouped by the geographical 

basin limits to obtain basin-level activity. These key activity factors include (but are not 

limited to) number of active wells by well type, gas production and oil production by well 

type, spud count, feet (depth) drilled by wellbore type, and water production by well type. 

ENVIRON/ERG compiled county-level activity data for calendar year 2011 for oil and gas 

producing CenSARA states; the goal was to use a single, consistent source of production 

statistics instead of collecting data from various state agency datasets which may present 

data in varying formats. 

x Compiled basin-level data on equipment, activity and emissions factors for estimating 

emissions: ENVIRON researched and gathered data from a variety of resources, starting 

with 1) oil and gas operator surveys, 2) state minor source permit applications, and 3) 

literature review, to obtain detailed basin-specific data on operations, equipment and 

processes related to upstream oil and gas area sources. The data collected included 

equipment counts, emissions factors, activity factors for equipment (e.g. annual hours of 

operation, load factors, tier level, etc.), and gas compositions. 

x Developed an Emissions Calculator Tool that estimates 2011 oil and gas area source 

emissions at the basin and county level: 2011 emissions estimates were compiled within a 

fully documented worksheet tool that enables CenSARA members to update activity and 

emissions data at the basin and/or county level for future use. The tool is based on the 

existing emissions calculator developed by ERG for Texas (ERG, 2010) but expanded to 

include inventory enhancements performed in the current study and added components 

that allow the states to update data by including specific control measures and adjusting 

emission factors. A tool for each CenSARA state was developed which includes a summary 

of annual emissions by county, by basin, by pollutant and by source classification codes 

(SCCs). Production statistics at the county and basin level are also summarized within the 

tool. 

x Developed a database program to convert the emissions estimated by the Calculator Tool 

into an EIS-ready format for NEI submissions: A database program was developed to read 

the emissions summary in the Emissions Calculator Tool and convert emissions estimates 
December 2012 

12 

into an EIS-ready format by loading the inventory data into the EPA-supplied Consolidated 

Emissions Reporting Schema (CERS) EIS staging tables. The data stored in the EIS staging 

tables can be converted into valid XML files that are in compliance with the CERS using an 

EPA-supplied XML File Generator tool. This program and the emissions calculator provide 

the necessary set of tools for CenSARA members to both generate the oil and gas emissions 

and format them for NEI submission. 
December 2012 

13 

4.0 EMISSIONS INVENTORY DESCRIPTION 

4.1 Temporal and Geographic Scope 

The current inventory enhancement aims to characterize emissions from oil and gas activities 

for a base year 2011. The base year 2011 in this Project also aligns with the year inventoried in 

the upcoming EPA’s National Emissions Inventory (NEI) for which the CenSARA states must 

submit 2011 emissions data for sources in their jurisdictions by December 31st, 2012. The NEI is 

prepared every three years by the US EPA based primarily upon emission estimates and 

emission model inputs provided by Regional, State, Local and Tribal air agencies. 

Oil and gas facilities’ operational and equipment information were collected through survey 

outreach for companies’ activities in 2011. Drilling and production statistics (well counts, oil and 

gas production, spud count, etc.) for the CenSARA region were compiled for 2011. Final 

emissions were calculated on an annual basis as the majority of the oil and gas sources operate 

throughout the year. Preparation of inventories for future years will be facilitated by the ability 

of CenSARA States to update activity levels and emissions data contained in the 2011 version of 

the Emissions Calculator Tool developed in this Project. 

The geographic scope of this inventory includes all CenSARA member states in which oil and gas 

activities took place during 2011 (Texas, Oklahoma, Louisiana, Arkansas, Kansas, Nebraska and 

Missouri). Oil and gas production in the remaining two CenSARA states (Iowa and Minnesota) is 

negligible. A map of oil and gas basins in the CenSARA region is provided in Figure 4-1. Basin 

geographical boundaries were largely based on USGS definitions but were modified slightly to 

align with county boundaries for ease of reporting county-level emissions in this inventory. 

Thus, counties that are geographically split between multiple basins were assigned to the single 

basin representing the largest geographic portion of the county to avoid the complexity of 

allocating activity factors and emissions at the sub-county level. 
December 2012 

14 

Figure 4-1. Oil and gas basins in the CenSARA region. 

Although activities can vary within a basin (e.g. both oil and gas operations), the geologically 

influenced characteristics of a basin (e.g. depth, pressure, presence of water, oil quality, gas 

composition) directly affect activity parameters that describe oil and gas operations within the 

basin boundaries. A basin therefore represents a sufficiently detailed but tractable geographic 

unit for development of emissions factors and other input data for oil and gas area sources. Oil 

and gas area source emissions were therefore estimated for each basin based on equipment, 

activity and emissions factors compiled for the basin. Emissions were then allocated to each 

county within the basin based on the by-county spatial allocation surrogate (well counts, 

production and drilling) applicable to each source category. Counties falling within each basin 

are listed in Table A-1 of Appendix A. 

4.2 Pollutants considered 

Pollutants included in the oil and gas area source inventory are: 

Criteria pollutants: carbon monoxide (CO), sulfur dioxide (SO2), nitrogen oxides (NOx), volatile 

organic compounds (VOCs), and particulate matter (specifically, PM10 and primary/direct 

PM2.5). 

Greenhouse Gases (GHGs): methane, carbon dioxide and nitrous oxide. 
December 2012 

15 

Hazardous Air Pollutants (HAPs): Calculation of HAPs emissions was limited by the availability of 

emissions factors for indirect sources (such as combustion sources) and the availability of 

detailed gas speciation profiles for direct sources (such as leaking and venting area sources). 

The list of HAPs included in this inventory was based on those pollutants (benzene, 

ethylbenzene, toluene, xylene, formaldehyde and n-hexane) for which emissions data was 

available. It must be noted that gas analyses obtained through company surveys and literature 

data did not consistently include HAP concentrations, and in some cases HAPs speciation 

profiles were not available for a particular basin and/or source category. Thus, in these cases 

certain HAP emissions in a number of basins were not estimated, however the methodology is 

available to estimate these emissions within the calculator tool should speciation data become 

available. 

Insufficient data was found to be available on ammonia (NH3) emissions from all oil and gas 

area sources, thus this pollutant was not estimated within the inventory. 

Hydrogen Sulfide (H2S): Hydrogen sulfide emissions result from direct venting of sour gas. 

Generally, molar concentrations of H2S in the gas are linked to the geographic location (basin) 

where the gas is produced. Data on produced gas H2S content is limited and not all gas analyses 

include H2S. H2S emissions were estimated where data was available. 

4.3 Scope of Emission Sources 

Emissions were estimated for upstream oil and gas sector area sources including those during 

well drilling, completion (including fracing), production and recompletion phases, and 

associated sources located at or in close proximity to the well pad. These numerous small 

sources are generally not tracked as part of major point source permitting programs, and may 

or may not be tracked as part of minor source permitting programs (which vary from state to 

state). Source categories included in the inventory are: 

x Artificial Lift Engines 

x Wellhead Compressor Engines 

x Lateral Compressor Engines 

x Drilling Rigs 

x Condensate Tanks 

x Hydraulic Fracturing Pumps 

x Well Completion Venting 

x Blowdown Venting 

x Casing Gas Venting 

x Dehydrators 

x Pneumatic Devices 

x Heaters 

x Crude Oil Tanks 
December 2012 

16 

x Produced Water Tanks 

x Gas-Actuated Pneumatic Pumps 

x Fugitive Emissions 

x Mud Degassing 

x Hydrocarbon Liquids Loading 

x Flaring 

This 2011 inventory builds off of the previous inventory for the Central states developed for 

CENRAP (Bar-Ilan, et al., 2008), and expands the scope of area source categories to gap-fill 

those emissions that have often not been included in past studies. These include emissions for 

mud degassing, produced water tanks, hydraulic fracturing pumps and casinghead gas venting. 

For source categories included in the original CENRAP study, new data or revisions to 

assumptions were incorporated as appropriate based on new data collected for this study. 

Examples of revisions to the CENRAP methodologies include updating the component list 

assumptions for fugitive emissions to include compressor seal fugitives. The current list of 

sources was cross-referenced with a list of source classification codes (SCCs) to facilitate the 

transfer by states of emissions data from this work to the 2011 NEI. 

Source categories in this inventory were divided in two major groups: “high-tier” sources and 

“low-tier” sources. High-tier sources refer to the most significant area sources of NOx, VOC and 

HAPs based on ENVIRON’s and ERG’s experience from previous oil and gas area source 

inventory development studies and through discussions with CenSARA members. Major sources 

of VOC emissions in oil and gas operations are also significant sources of HAPs. Typically, oil and 

gas area sources are not large contributors to PM emission inventories. Low-tier sources refer 

to other source categories included in the inventory that are not considered high-tier. Table 4-1 

lists the most significant sources of NOx, VOCs and HAPs emissions in the upstream oil and gas 

sector. 

Table 4-1. Major area sources of NOx, VOCs and HAPs in the upstream oil and gas sector. 

Significant emissions source of 

NOx VOCs and HAPs 

Artificial Lift Engines Crude Oil and Condensate Tanks 

Wellhead Compressor Engines Well Completion Venting

Lateral Compressor Engines Blowdown Venting 

Drilling Rigs Casing Gas Venting 

Hydraulic Fracturing Pumps Dehydrators 

Pneumatic Devices 

Pollutant emissions for many source categories will vary according to the type of well (either 

gas or oil) since gas (or associated gas) compositions and process characteristics will differ 

according to the well type. For example, pollutants concentrations in fugitive leaks and any 

other venting emissions will vary between oil wells and gas wells, dehydrator equipment is 

mainly used in gas wells, casing gas venting is only applicable to oil wells, etc. Thus, an 
December 2012 

17 

enhanced methodology has been developed in this work to account for differences in emissions 

between well types by specifying basin-level and well-level calculation inputs, when feasible, 

and by applying more detailed production statistics to scale emissions such as oil versus gas 

well counts, horizontal versus vertical spuds, condensate production versus crude oil 

production, etc. as opposed to using more general surrogates such as active well counts, spud 

counts and oil production. 

While the sources analyzed here may not represent a complete list of all oil and gas area source 

categories, this study includes the most significant area sources that contribute to the vast 

majority of emissions in a basin-level inventory based on the technical team’s experience in 

development of oil and gas inventories. These sources are also the ones with the most 

complete set of input data that can be obtained through literature review and survey efforts, 

thus decreasing the level of uncertainty in the emissions estimates. Sources that could not be 

included due to limited data availability were: salt water injection engines, well pad 

construction equipment, workover equipment and some associated mobile sources. Associated 

on-road mobile sources operating in the well field such as service vehicles used during 

construction, drilling and production phases, are captured under some states’ mobile source 

emissions inventories and are not included in this inventory. 

4.4 Oil and Gas Activity Updates for the CenSARA Region 

4.4.1 Obtaining Oil and Gas Activity Data 

A subtask in this project was to develop 2011 county-level activity data of oil and natural gas 

upstream production and drilling activities for the CenSARA states. Typically, these data are 

available on oil and gas commission websites for each state; however it is typically very 

cumbersome to obtain the data in this way as they are presented in various formats and 

require significant processing to make them useable for inventory development. It is therefore 

advantageous to obtain as much information as possible from a single data source or 

clearinghouse in a standard format. ERG was able to make arrangements to obtain activity data 

for the 2011 base year from DrillingInfo’s HPDI database for production wells (Drillinginfo, Inc. 

2012). These data were supplemented by data obtained from state oil and gas commission 

websites and state-level drilling information from RigData. 

Table 4-2 presents the activity data parameters used to calculate oil and gas emissions. The 

derived level of aggregation is at the county-level. In total, there are 783 counties in the 

CenSARA oil and gas region (which does not include Iowa and Minnesota). 
December 2012 

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Table 4-2. County-level activity data parameters needed for emissions estimation. 

Data Parameter 

Oil Produced (barrels or BBL) 

Natural Gas Produced (thousand standard cubic feet or MCF) 

Condensate Produced (BBL) 

Casinghead Gas Produced (MCF) 

Oil Well Counts 

Natural Gas Well Counts 

Oil Well Completions 

Natural Gas Well Completions 

Produced Water at Oil Wells (BBL) 

Produced Water at Gas Wells (BBL) 

Spud Counts (Vertical, Horizontal, Directional) 

Feet Drilled (Vertical, Horizontal, Directional) 

With the exception of Feet Drilled, all of the above parameters are reported fields in HPDI. 

“Feet Drilled” was estimated by calculating a “feet per drilling day” rate per well, which is 

roughly the well depth divided by the number of days between the Completion Date and the 

Spud Date. This rate was then multiplied by the number of drilling days to obtain the “Feet 

Drilled” value. For wells that were spudded and completed within 2011, the calculation was 

straightforward. For wells that began drilling prior to 2011 and were completed in 2011 or 

began drilling in 2011 and were completed in 2012, only the portion of drilling occurring in 

2011 was considered. 

Table 4-3 presents the activity data sources for each of the activity data parameters identified 

in Table 4-2. 

 
December 2012 

19 

Table 4-3. Production and drilling data sources by state. 

State 

Abbreviation 

Oil/ Casinghead 

Gas Production 

Natural Gas/ 

Condensate 

Production 

Produced 

Water Well Completions 

Spud Counts/ Feet 

Drilled 

AR 2011 HPDI 2011 HPDI 2011 HPDI Oil Gas Commission 

Website 2010 HPDI; RigData 

KS 2011 HPDI 2011 HPDI Not Available 2011 HPDI 

Kansas Corporation 

Commission 

Website 

LA 2011 HPDI 2011 HPDI 2011 HPDI 2011 HPDI 2010 HPDI; RigData 

MO 2011 HPDI 2011 HPDI Not Available 2011 HPDI 2010 HPDI; RigData 

NE 2011 HPDI 2011 HPDI 2011 HPDI 2011 HPDI 2011 HPDI 

OK 2011 HPDI 2011 HPDI Not Available Oil Gas Commission 

Website 2010 HPDI; RigData 

TX 2011 HPDI 2011 HPDI 2011 HPDI 2011 HPDI 2010 HPDI; RigData 

HPDI was the source for all the oil, casinghead gas, natural gas, and condensate data for 2011. 

Additionally: 

x Produced water data were available in HPDI for Arkansas, Louisiana, Nebraska, and Texas. 

Produced water data were not available in HPDI or from the states for Kansas, Missouri and 

Oklahoma. 

x Well completions were available for 2011 in HPDI for Kansas, Louisiana, Missouri, Nebraska, 

and Texas. For Arkansas and Oklahoma, well completion counts were obtained from their 

respective Oil and Gas Commission websites. 

x Spud Counts and Feet Drilled were only available for 2011 in HPDI for Nebraska. For Kansas, 

spud counts and feet drilled were obtained from the Kansas Corporation Commission, Oil 

and Gas Conservation Division website. For Arkansas, Louisiana, Missouri, Oklahoma, and 

Texas, the 2010 feet drilled from HPDI were scaled to 2011 using state-level well starts for 

each state obtained from RigData. 

4.4.1.1 DrillingInfo Database in HPDI 

The first data source for obtaining activity data was information from HPDI’s DrillingInfo. This 

subscription-based information source extracts well-level data from state oil and gas 

commission websites. The data, while publically available, are periodically extracted from each 

commission website, and prepared in a standardized format. As part of EPA’s Enforcement 

Activities, an HPDI annual subscription is purchased allowing data downloads, or “refreshes”, to 

be obtained throughout the year. In accordance with the licensing agreement, well-level data is 

proprietary, but derived products, such as aggregation at the county-level, are acceptable for 

public dissemination. EPA granted authorization of this derived data processing file for 

CenSARA’s use to support this project. For the CenSARA states, there are over 2 million welllevel data records. 
December 2012 

20 

ERG extracted well identification (HPDIHeader), production (HPDIProduction), and test 

(HPDIWellTest) information for onshore wells and leases. Table 4-4 provides details on the 

available data by state, as of the refresh date. Table 4-4 also includes the update frequency of 

the data by state and those states with available test data. 

Table 4-4. HPDI data coverage by state. 

State 

Abbreviation Production Group 

Update 

Frequency Latest Production Data 

Test Data 

Available 

AR Well Monthly 4/1/2012 No 

KS Lease Monthly 3/1/2012 No 

LA Well/Unita Monthly 5/2/2012 Yes 

MO Lease Yearly 1/1/2012 No 

NE Well Monthly 3/1/2012 No 

OK Well Monthly 3/1/2012 No 

TX Oil – Lease; 

Gas – Well 

Twice 

Monthly 5/1/2012 Yes 

a

 Louisiana Department of Natural Resources defines a unit as the “surface area that encompasses part of or the entirety of a 

reservoir.” 

ERG imported all of the data from HPDI into an Oracle database for processing. The Oracle 

database combines and processes all of the download files into one table of all production wells 

for the EPA Enforcement Universe Database. The processing steps are discussed below. 

1) Combine Annual Production and Descriptive Information: For each entity3, ERG 

combined the annual production with the descriptive information (e.g., API 

number, lease name, location, operator, completion date, spud date, latest 

production date) from the HPDIHeader table to create the Wells table for the 

EPA Enforcement Universe Database. Appendix B presents the names and 

descriptions of the fields included in the Wells table. 

2) Remove Duplicate Wells: HPDI includes duplicate information for wells in some 

states because the data are stored by completion zone rather than at the well or 

lease level. Because all of the other descriptive data in HPDI are at the well or 

lease level, ERG combined duplicate API numbers (i.e., well bore identifiers4) into 

a single record to avoid over counting wells. ERG excluded the records with 

missing API numbers (i.e., API_NO is null) from this “remove duplicate well” step. 

This could result in some over counting of wells, but this should be minimal 

 

3

 HPDI assigns a unique number to each property (i.e., lease, well, unit) in the ENTITY_ID field. 

4

 API numbers are up to 14 digits long and are broken into four segments. The first two digits correspond to the 

state; the next three digits correspond to the county in the state. The next five digits are the unique well identifier 

for the county. The next two digits are for the directional side tracks (i.e., horizontal or directional drills that each 

have different bottom hole locations), with 00 representing the original well bore. The last two digits are the event 

sequence code that distinguish between original completion, reentries, recompletion, and hole deepenings. Some 

states do not assign directional side tracks or event sequence codes. 
December 2012 

21 

because a limited number of wells/leases did not have API numbers and there 

were a small percentage of duplicate wells identified. 5

1) Create Updated Active Status Flag (ACTIVE_FLAG): ERG created an updated 

active status flag (ACTIVE_FLAG) using the latest production date 

(LAST_PROD_DATE) after determining that HPDI’s status flag (STATUS) was not 

always accurate as part of the 2011 version of the Universe Database.6

2) Create Production Flags (PROD09_FLAG, PROD10_FLAG, PROD11_FLAG): ERG 

created production flags to identify miscellaneous well types (e.g., injection, 

observation, abandoned, pressure maintenance, N/A) that have oil and gas 

production in 2009 (PROD09_FLAG), 2010 (PROD10_FLAG), and 2011 

(PROD11_FLAG). The production flag is “Yes” if the annual oil or gas production 

is greater than zero. 

3) Assign Each Well as Oil or Gas: Each well was reviewed to determine whether it 

should be labeled as an oil or a gas well. As such, the following hierarchy was 

used:

a. HPDI designations of oil or gas 

b. Wells that had 2011 oil production, but no 2011 natural gas production 

were assigned as “oil” wells;

c. Wells that has 2011 gas production, but no 2011 oil production were 

assigned as “gas” wells; and

d. Wells that had both 2011 oil and gas production were assigned “oil” or 

“gas” based on converting the oil and gas production data into BTU and 

selecting the larger of the two. 

4.4.1.2 State Oil and Gas Commission Websites 

To fill in missing data not available in HPDI, the state oil and gas commission websites were 

searched and the following data were used: 

x 2011 well completions for Arkansas wells were obtained from the Weekly Reports found in 

the Arkansas Oil and Gas Commission website 

(http://www.aogc.state.ar.us/permitreportarch.htm) and were summed to each county 

x 2011 spud counts and feet drilled for Kansas wells were obtained from the Kansas Oil and 

Gas Commission website (http://www.kgs.ku.edu/PRS/Ora_Archive/ks_wells.zip) and 

summed to each county 

x 2011 well completions for Oklahoma counties were obtained from the Oklahoma Oil and 

Gas Commission website (http://www.occeweb.com/og/2011%20Annual%20Report.pdf). 

 

 

5

 Duplicate wells in states with missing API numbers could be identified using the permit number, which should be 

unique for each well. 

6

 ERG found some wells with an “Active” STATUS had not produced in a number of years, while some wells with an 

“Inactive” STATUS had production data for 2010. 
December 2012 

22 

4.4.1.3 RigData 

Drilling data in HPDI for 2011 was sparse, with only 2011 information from Nebraska available. 

As such, 2011 estimates needed to be generated for the remaining states. We used RigData 

(http://www.rigdata.com) as a source of Well Starts by year. The 2010 spud counts and feet 

drilled in HPDI for Arkansas, Kansas, Louisiana, Missouri, Oklahoma, and Texas were adjusted by 

the ratio of wells starts from 2010 to 2011 for each of these states. 

4.4.2 CenSARA Oil and Gas Production Statistics for 2011 

A summary of the resulting oil and gas production statistics by basin obtained through the HPDI 

database is presented in Table 4-5. This includes some key activity indicators such as natural gas 

production, casing head gas production, crude oil production, condensate production, gas well 

and oil well counts, and water production. Statistics at the county-level and by well type for 

each surrogate are included in the Emissions Calculator Tool developed in this work. Production 

statistics were used as scaling surrogates for estimating emissions at a county level. Surrogate 

values extracted from HPDI have detail at the well-level; for example, the classification of well 

counts, water production, spud count, well completions and production is separated by well 

type (gas or oil). This allows regional scaling of emissions for a particular source category by 

capturing the difference in speciation of emissions which is affected by pollutant 

concentrations in the gas and by operational parameters characteristic of each well type. It is 

important to note that produced water information in the HPDI database were available only 

for four of the seven oil and gas producing states in CenSARA (Nebraska, Arkansas, Texas and 

Louisiana). Therefore, basin-wide water production numbers are not always representative of 

the basin total as several basins are located in more than one state, including those for which 

water production was not available. 
December 2012 

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Table 4-5. Basin-wide production statistics for the CenSARA region. 

Basin 

Crude Oil 

Production 

(bbl/yr) 

Condensate 

Production 

(bbl/yr) 

Casinghead Gas 

Production 

(MCF/yr) 

Natural Gas 

Production 

(MCF/yr) Oil Well Count Gas Well Count 

Produced water 

(bbl/yr)* 

Anadarko Basin 38,849,509 23,404,233 128,500,510 1,667,680,731 27,048 67,323 63,229,429 Arkoma Basin 1,209,675 105,776 1,192,053 1,566,638,491 1,871 18,341 - Bend Arch-Fort Worth Basin 27,124,167 3,711,767 90,863,234 2,087,999,221 53,312 25,082 756,141,538 Cambridge ArchCentral Kansas Uplift 17,441,133 938,882 - 10,535,459 26,195 2,601 35,704,420 Cherokee Platform 9,221,921 782,270 10,409,412 103,922,916 28,782 15,622 - Denver Basin 393,004 751,191 35,498 1,165,036 106 775 12,254,436 East Texas Basin 15,402,824 6,062,203 18,305,801 1,839,495,352 21,342 23,326 398,204,370 Forest City Basin 1,328,525 17,874 - 277,443 7,644 288 3,726,059 Illinois Basin - - - 2,573,300 - 24 - LouisianaMississippi Salt Basins 14,780,502 2,150,516 16,345,448 2,505,781,194 18,101 17,316 522,274,052 Marathon Thrust Belt 4,064 82,300 161,216 41,565,726 13 675 577,272 Nemaha Uplift 4,619,574 1,077,952 10,359,925 23,190,001 9,916 2,192 - Ozark Uplift - - - - - - - Palo Duro Basin 3,561,696 81,566 2,693,538 18,964,419 1,818 1,082 32,039,947 Permian Basin 299,041,345 5,683,488 669,798,454 529,029,342 145,544 20,295 3,226,217,276 
December 2012 

24 

Basin 

Crude Oil 

Production 

(bbl/yr) 

Condensate 

Production 

(bbl/yr) 

Casinghead Gas 

Production 

(MCF/yr) 

Natural Gas 

Production 

(MCF/yr) Oil Well Count Gas Well Count 

Produced water 

(bbl/yr)* 

Salina Basin 272,924 8,187 - 691 493 1 181,834 Sedgwick Basin 3,063,174 1,523,188 - 36,776,210 5,417 3,401 - Southern Oklahoma 9,376,880 1,930,874 20,170,919 77,555,318 9,256 3,037 - Western Gulf 144,929,906 61,146,973 311,480,930 2,101,896,695 45,439 25,923 1,489,520,630 CenSARA Region Total 590,620,823 109,459,240 1,280,316,938 12,615,047,545 402,297 227,304 6,540,071,263  *Produced water is not representative of each basin's total since water production statistics were not available for every state. Water production was available for AR, LA, NE and TX only. 
December 2012 

25 

Table 4-6 shows the distribution of the production levels by state and within the basin portion 

of each state. 

Table 4-6. Summary of production, well counts and spud count by state and basin for 

CenSARA. 

State Basin 

Crude Oil 

Production 

(bbl/yr) 

Natural Gas 

Production 

(MCF/yr) 

Active Well 

Counts 

Total 

Spuds 

Arkansas 

Arkoma Basin 

 

- 

 

1,070,434,560 

 

7,976 

 

859 

Illinois Basin 

 

- 

 

2,573,300 

 

24 

 

- 

Louisiana-Mississippi Salt 

Basins 

 

5,154,192 

 

4,577,320 

 

2,485 

 

187 

Ozark Uplift 

 

- 

 

- 

 

- 

 

- 

State Total 

 

5,154,192 

 

1,077,585,180 

 

10,485 

 

1,046 

Kansas 

Anadarko Basin 

 

11,917,770 

 

223,851,902 

 

33,672 

 

676 

Cambridge Arch-Central 

Kansas Uplift 

 

16,996,535 

 

9,756,144 

 

28,375 

 

808 

Cherokee Platform 

 

1,885,177 

 

40,742,354 

 

22,524 

 

780 

Forest City Basin 

 

1,199,139 

 

277,443 

 

7,873 

 

761 

Nemaha Uplift 

 

1,758,271 

 

250,264 

 

6,890 

 

102 

Salina Basin 

 

272,924 

 

691 

 

494 

 

22 

Sedgwick Basin 

 

3,063,174 

 

36,776,210 

 

8,818 

 

257 

State Total 

 

37,092,990 

 

311,655,008 

 

108,646 

 

3,406 

Louisiana 

Louisiana-Mississippi Salt 

Basins 

 

9,626,310 

 

2,501,203,874 

 

32,932 

 

520 

Western Gulf 

 

49,454,095 

 

351,991,634 

 

5,510 

 

101 

State Total 

 

59,080,405 

 

2,853,195,508 

 

38,442 

 

621 

Missouri Cherokee Platform 

 

27,401 

 

- 

 

5 

 

- 

Forest City Basin 

 

85,409 

 

- 

 

29 

 

- 
December 2012 

26 

State Basin 

Crude Oil 

Production 

(bbl/yr) 

Natural Gas 

Production 

(MCF/yr) 

Active Well 

Counts 

Total 

Spuds 

Illinois Basin 

 

- 

 

- 

 

- 

 

- 

Ozark Uplift 

 

- 

 

- 

 

- 

 

- 

State Total 

 

112,810 

 

- 

 

34 

 

- 

Nebraska 

Cambridge Arch-Central 

Kansas Uplift 

 

444,598 

 

779,315 

 

421 

 

35 

Denver Basin 

 

393,004 

 

1,165,036 

 

881 

 

6 

Forest City Basin 

 

43,977 

 

- 

 

30 

 

12 

Nemaha Uplift 

 

- 

 

- 

 

- 

 

- 

Salina Basin 

 

- 

 

- 

 

- 

 

- 

State Total 

 

881,579 

 

1,944,351 

 

1,332 

 

53 

Oklahoma 

Anadarko Basin 

 

12,337,317 

 

816,787,833 

 

32,765 

 

243 

Arkoma Basin 

 

1,209,675 

 

496,203,931 

 

12,236 

 

93 

Bend Arch-Fort Worth 

Basin 

 

151,100 

 

- 

 

143 

 

4 

Cherokee Platform 

 

7,309,343 

 

63,180,562 

 

21,875 

 

96 

Nemaha Uplift 

 

2,861,303 

 

22,939,737 

 

5,218 

 

31 

Palo Duro Basin 

 

58,349 

 

782,668 

 

141 

 

- 

Southern Oklahoma 

 

9,376,880 

 

77,555,318 

 

12,293 

 

19 

State Total 

 

33,303,967 

 

1,477,450,049 

 

84,671 

 

486 

Texas 

Anadarko Basin 

 

14,594,422 

 

627,040,996 

 

27,934 

 

565 

Bend Arch-Fort Worth 

Basin 

 

26,973,067 

 

2,087,999,221 

 

78,251 

 

1,530 

East Texas Basin 

 

15,402,824 

 

1,839,495,352 

 

44,668 

 

629 
December 2012 

27 

State Basin 

Crude Oil 

Production 

(bbl/yr) 

Natural Gas 

Production 

(MCF/yr) 

Active Well 

Counts 

Total 

Spuds 

Marathon Thrust Belt 

 

4,064 

 

41,565,726 

 

688 

 

8 

Palo Duro Basin 

 

3,503,347 

 

18,181,751 

 

2,759 

 

19 

Permian Basin 

 

299,041,345 

 

529,029,342 

 

165,839 

 

2,201 

Western Gulf 

 

95,475,811 

 

1,749,905,061 

 

65,852 

 

1,570 

State Total 

 

454,994,880 

 

6,893,217,449 

 

385,991 

 

6,522 

CenSARA Region Total 

 

590,620,823 

 

12,615,047,545 

 

402,297 

 

227,304 

A significant amount of upstream oil and gas emissions occur during drilling; these emissions 

will be affected by the operational characteristics of the type of well drilled. The HPDI database 

provides a highly detailed breakdown of the drilling activity, which separates the main activity 

drivers (spud count and feet drilled) by well type (gas or oil) and by wellbore type (horizontal or 

vertical wells). This allows for application of different emissions rates depending on the type of 

well and wellbore and it also enables a better allocation of the drilling activity that likely 

involves hydraulic fracturing techniques. 
December 2012 

28 

Table 4-7. Summary of drilling activity by basin. 

Basin Spud Count Total Vertical Feet Drilled Total Horizontal Feet Drilled Well Completions 

Anadarko Basin 1,484 5,350,439 6,014,414 1,544 Arkoma Basin 952 99,081 4,311,829 1,327 Bend Arch-Fort Worth Basin 1,534 1,129,252 9,850,854 1,802 Cambridge Arch-Central Kansas Uplift 843 3,086,133 - 232 Cherokee Platform 876 1,004,617 60,137 438 Denver Basin 6 43,645 - 7 East Texas Basin 629 2,696,345 4,731,632 530 Forest City Basin 773 598,428 - 43 Illinois Basin - - - - Louisiana-Mississippi Salt Basins 707 1,340,228 4,675,104 1,477 Marathon Thrust Belt 8 89,113 - - Nemaha Uplift 133 490,563 54,484 192 Ozark Uplift - - - - Palo Duro Basin 19 78,880 11,034 13 Permian Basin 2,201 18,911,110 2,184,534 1,706 Salina Basin 22 72,212 - 5 Sedgwick Basin 257 1,209,269 - 44 Southern Oklahoma 19 63,827 118,125 350 Western Gulf 1,671 4,845,453 11,352,479 2,006 CenSARA Region Total 12,134 41,108,593 43,364,626 11,716 
December 2012 

29 

5.0 INPUT DATA GATHERING 

This section describes the different sources of information used to gather activity inputs used to 

estimate oil and gas area source emissions. Input data include the fractional usage of 

equipment at well-sites, properties of the equipment such as size, annual usage hours, 

emissions controls and emissions factors, process characteristics such as venting rates and well 

component counts, and chemical composition analyses used to determine pollutant emission 

rates. An attempt was made to obtain basin-specific input data applicable to each source 

category listed in Section 4.3. Where basin-specific data were unavailable, national averages or 

other available regional data were used, particularly for estimating emissions from lower-tier 

source categories. CenSARA member states will be able to update this information in future 

inventories using the emissions calculator tool developed in this study if more detailed data is 

available in the future. 

Three different approaches were used to obtain data on equipment and process activities: 

1) Conduct new industry surveys of oil and gas operators within the CenSARA region, 

2) Review oil and gas equipment and activity datasets developed by state agencies and 

state facility permits and 

3) Obtain information from existing studies or use averages from survey data from various 

basins in CenSARA. 

These three approaches are described in more detail below. 

5.1 Industrial Surveys 

In the anticipation that not all information necessary to estimate 2011 emissions for the 

selected area source categories would be available through state agency datasets and existing 

literature, a limited industrial survey was conducted to gather representative data at the basin 

level on field equipment and operations for the higher tier oil and gas source categories. The 

survey effort was targeted at the major oil and gas producers operating in each basin within the 

CenSARA region. It has been ENVIRON’s experience with previous regional emissions 

inventories, such as the Rocky Mountain States oil and gas inventories prepared for the 

Western Regional Air Partnership (Bar-Ilan et al., 2008), that direct surveys of oil and gas 

operators are needed to properly characterize equipment, well configuration, usage, processes, 

and emissions factors. 

5.1.1 Geographical Scope 

ENVIRON narrowed the geographical scope of the survey outreach to the major oil and gas 

producing basins of particular interest to CenSARA states. For example, the Texas Commission 

on Environmental Quality (TCEQ) indicated that they were mainly interested in developing new 

data for the Permian Basin as they already have an established methodology and inputs for 

estimating oil and gas emissions in other basins within the State. Louisiana Department of 

Environmental Quality (LADEQ) requested that the survey focus on activities in the northern 

portion of the state where potential air quality issues in the area of Baton-Rouge could be 
December 2012 

30 

focused on, thus the Louisiana-Mississippi Salts Flats basin was of particular interest to them. 

Discussions with Oklahoma, Arkansas and Kansas determined that survey efforts would focus 

on areas where the bulk of the production occurs within each of these states, including the 

Anadarko, Arkoma and Cambridge Arch-Central Kansas Uplift basins. Cambridge Arch is also a 

major oil and gas producing region in Nebraska. Thus, surveys were developed to gather data 

for the following basins: 

x Anadarko Basin 

x Arkoma Basin 

x Louisiana-Mississippi Salt Basins 

x Cambridge Arch-Central Kansas Uplift 

x Sedgwick Basin 

x Permian Basin 

Information in the survey was specifically requested at the basin level and for calendar year 

2011. As part of the survey, operators were asked to list the counties within each basin where 

they have operations in order to verify the proper region to apply the data being collected. 

5.1.2 Survey Description and Development 

The survey effort was focused on collecting field data on the most significant area sources of 

NOx, VOC and HAPs referred to here as “high-tier” source categories and listed in Table 4-1. 

These sources can have a high variability in emissions and operation parameters across 

different basins, hence estimates for these sources benefit from industry data at the basin 

level. A worksheet format survey form was prepared for each targeted operating company to 

fill out and return in electronic format. The survey design was based on previous oil and gas 

inventory surveys used in the IPAMS/WRAP Phase III oil and gas emission inventory 

development project (Bar-Ilan et al., 2008). The survey consisted of various tabs requesting 

information for each of the high-tier source categories, as well as an introductory tab describing 

the purpose of the survey, the regional scope, and instructions for filling in the requested 

information. Another tab gathered/confirmed contact information of the surveyed company 

and allowed them to enter the counties of operation and any notes or comments on the data 

provided. The set of survey forms used in this study are included as electronic Appendix D. 

Each source category tab requested basic information needed to determine input values for 

basin-level emissions calculations. Among the data fields included were equipment counts, 

hours of operation, horsepower, load factors, firing rates, emissions factors, engines 

configuration for drilling rigs, venting rates and event counts for venting categories, well 

configuration for pneumatics and fugitives, and information on emissions controls such as 

control method, fraction controlled and control efficiency. Where appropriate, data was 

requested by well type to account for differences between oil and gas wells in equipment 

configurations, venting rates and emissions factors. Each survey also requested information on 

gas composition analyses of produced gas by well type (gas or oil), necessary to estimate VOC, 

HAPs, methane (CH4), and hydrogen sulfide (H2S) emissions for venting/leaking source 
December 2012 

31 

categories based on the pollutants concentrations in the gas. Operators were asked to provide 

any supplemental documents to aid in emissions calculations including: input and output files 

from emissions models such as EPA TANKS, E&P Tank and GRI-GlyCalc; equipment inventories 

for compressor engines, drill rigs, and artificial lifts; and copies of produced gas composition 

analyses. 

5.1.3 Survey Outreach Process and Results 

ENVIRON analyzed oil and gas production by operator for 2011 from the HPDI database and 

state oil and gas commission records and developed a list of the top oil producing and top gas 

producing companies in each basin. Production ownership varied considerably by basin for oil 

and gas, thus a recommended list of selected companies for the survey outreach was 

developed based on the representation of at least 50% ownership of production (both oil & 

gas) within each basin or the selection of the top 10 companies (in the case they had at least 

50% ownership). This resulted in a comprehensive list of 127 oil and gas companies 

recommended for survey. ENVIRON has developed working relationships with many major oil 

and gas companies, particularly through ongoing oil and gas emissions projects such as the 

IPAMS/WRAP Phase III (Bar-Ilan et al., 2008). ENVIRON and CenSARA state agencies worked 

together to establish contacts at selected companies for which ENVIRON did not already have a 

suitable contact. Between the collaboration of ENVIRON and CenSARA members, a list of 

contacts for 82 companies was compiled; individual (non-generic) contacts for 45 operators out 

of the 127 selected could not be identified during the survey outreach effort. Subsequently, 

CenSARA or state agencies sent each company contact within their jurisdiction an introductory 

letter explaining the purpose of the survey, its importance to the operator and to the state 

agencies, and requesting their cooperation in responding to the survey request in a timely 

manner. 

ENVIRON sent electronic surveys to each of the 82 companies for which an electronic contact 

was available. The email communication included a survey form for each of the basins in which 

the company was a significant oil and gas operator. Thus, several companies such as 

Chesapeake Operating, Inc. and XTO Energy, Inc. received requests to fill two to three surveys, 

one for each basin where they have operations, yielding a total of 99 surveys that were sent out 

among the top oil and top gas producing companies of the CenSARA region. A window of 30 

calendar days was given to the companies to fill-in the surveys, with a subsequent extension of 

1-2 weeks for some companies that requested it. Eleven (11) companies sent responses stating 

that they declined to participate; the most frequent explanation for declining was lack of 

resources to fill-in the survey at the time of request due to concurrent requirements to 

complete national Subpart W GHG inventory reporting to the EPA. Twenty-one (21) companies 

agreed to participate, resulting in 29 surveys (out of 99) filled by operators/contractors and 

returned to ENVIRON; these are shown in Table 5-1. The remaining 50 companies contacted did 

not respond to any communications. Survey response rates by basin are summarized in Tables 

5-2. 
December 2012 

32 

Table 5-1. Participating companies in the survey outreach effort. 

Company Name Basin of Major Operation 

Baird Oil Company LLC Cambridge Arch-Central Kansas Uplift 

BHP Billiton Arkoma 

Bonanza Creek Louisiana-Mississippi Salt Flats 

Chaparral Energy Anadarko 

Chesapeake Energy Anadarko, Arkoma 

ConocoPhillips Anadarko 

Edmiston Oil Company, Inc Sedgwick, Cambridge Arch-Central Kansas Uplift 

John O. Farmer Inc Cambridge Arch-Central Kansas Uplift 

Merit Energy Anadarko 

Murfin Drilling Company Inc Cambridge Arch-Central Kansas Uplift 

Noble Energy, Inc Cambridge Arch-Central Kansas Uplift 

Priority Oil and Gas, LLC Cambridge Arch-Central Kansas Uplift 

Ritchie Exploration Cambridge Arch-Central Kansas Uplift, Anadarko 

Sheridan Production Company Arkoma 

Southwestern Energy Company Arkoma 

Stephens Production Company Arkoma 

Trans Pacific Oil Anadarko, Cambridge Arch-Central Kansas Uplift, Sedgwick 

Vess Oil Corporation Cambridge Arch-Central Kansas Uplift 

Whiting Oil and Gas Corporation Anadarko, Louisiana-Mississippi Salt Flats 

Woolsey Operating Co, LLC Sedgwick 

XTO Energy Anadarko, Louisiana-Mississippi Salt Flats, Permian 

Table 5-2. Summary of survey responses and ownership of responses by basin. 

Basin 

Surveys 

Sent 

Surveys 

Returned 

Percent 

Response 

Basin-wide Gas 

Production 

Ownership of 

Respondents (%) 

Basin-wide Oil 

Production 

Ownership of 

Respondents (%) 

Anadarko Basin 26 7 26.9% 21.1% 18.4% 

Arkoma Basin 17 6 35.3% 68.5% 32.5% 

Louisiana-Mississippi 

Salt Basins 13 3 23.1% 2.4% 15.7% 

Cambridge Arch-Central 

Kansas Uplift 18 9 50.0% 38.0% 16.7% 

Sedgwick Basin 15 3 20.0% 13.1% 11.8% 

Permian Basin 10 1 10.0% 4.1% 2.6% 

Total 99 29 29.3% 

Table 5-2 shows the production ownership of the survey respondents in each basin. This 

percent ownership provides a qualitative assessment of the level of basin-wide representation 

that was achieved from the survey effort. Ideally, if most surveyed companies had participated, 

50-90 percent of basin production would have been reflected in the returned surveys. The 
December 2012 

33 

largest number of responses was obtained from small-to-large operators in the Cambridge Arch 

Basin, and two major gas producers (Priority and Noble Energy) responded to the survey, 

representing 38% of basin-wide gas production in the Cambridge Arch. Although responses 

were limited, the Arkoma basin was well represented for gas production and to a lesser extent 

for oil production as a result of the participation of key players such as Sheridan and 

Southwestern Energy. Although several responses for the Louisiana-Mississippi Salt Basins were 

received for oil producers, it should be noted that the surveys were intentionally not sent to the 

major gas producers in the basin as they were part of the recent Haynesville Shale emissions 

study described below in the literature review. Overall, the percent response from operators 

within all the basins was lower than desired, particularly for oil companies in the Permian Basin, 

the largest oil producing region in Texas, for which only one response was returned. 

Survey data from responding companies were evaluated for quality, applicability and 

usefulness. Returned surveys were not consistently filled for all source categories. For some 

basins, sufficient and useful data was collected from survey responses for many of the source 

categories, and for other basins/source combinations, very little useful data was provided in the 

surveys. Criteria for evaluating surveys were: 

x Quality of data: survey responses were assessed for quality to determine if specific data 

were beyond the typical range of values for a parameter based on ENVIRON’s experience 

from previous oil and gas survey efforts or in comparison to other data sources. In cases of 

specific responses of questionable quality, ENVIRON made efforts to further examine the 

data by contacting the surveyed company and asking for further clarification on the data 

provided. ENVIRON also examined the company’s levels of operation to evaluate if it would 

warrant any unusually high or low level of activity for particular data fields. Data that were 

determined to lie well outside a typical range without a reasonable explanation were 

rejected from inclusion in the final compilation. Incidences of this were isolated to a few 

responders. 

x Applicability and usefulness: This relates to data that were provided in a different format or 

were simply incomplete and could not easily be converted or assigned to representative 

equipment and process input data required by the methodology. For example, for a 

particular basin there was a single response for lateral compressor engines which applied to 

an electric compressor from one small operator. This data could not be assumed to be 

representative of the entire basin’s usage of lateral compressors and thus was not used. On 

occasion, useful and representative data were provided in different formats that allowed 

the estimations of emissions for a particular source by converting the data to the desired 

format or making changes to the methodology. 

Each data field gathered from survey responses was averaged primarily by basin, by well type 

when applicable, and by any other breakdown relevant to the source category; for example 

drilling rig data were averaged by horizontal and vertical configurations of drill rigs. When 

applicable and when sufficient data were available, the weighted average of some data fields 

was estimated using operator-production surrogates (gas production, oil production, well 

counts) that were available from the HPDI data. For example, the data field “fraction of wells 
December 2012 

34 

with wellhead compressors” was provided by groups of companies within a few basins, and the 

final input was derived from the weighted average based on operator well counts to arrive at a 

more representative value for the basin. 

5.2 State Permit Data Review 

5.2.1 Minor Source Permits 

Each state’s Air Quality Division (or equivalent agency) has a set of air permitting programs that 

may or may not cover a number of oil and gas area sources. Minor source permits are typically 

a sub-classification of construction or operating permits required for new and modified minor 

sources. A minor source is any source that emits less than a major source threshold. Some 

states have a broad scope of sources and/or facilities that are subject to this type of permit, 

covering facilities such as oil and gas well-sites (often termed production facilities), where many 

of the oil and gas area sources are located. Other states’ permitting programs focus on major 

sources and only cover minor sources located at oil and gas downstream facilities (e.g. gas 

plants, compressors on transmission lines) that would generally not qualify as an area source 

category. 

Some data fields that could not be collected through survey responses were derived from 

permit applications from states’ minor (or synthetic minor) source permitting programs such as 

those of Oklahoma, Kansas and Louisiana. In these states, oil and gas facilities, including new 

and modified well sites, require a construction and/or operating permit application that 

includes the calculation of emissions from minor sources at the facility; these may include: well 

heaters, condensate/crude oil tanks, wellhead compressor engines, artificial lift engines, 

dehydrator units, fugitives, flaring, liquids loading, and other engines located on site. Many of 

these “minor” sources are typically classified as an oil and gas area source category. Thus, data 

from minor source permits can be useful for the estimation of area source emissions. A caveat 

in utilizing permit data is that emissions estimates for permit applications are often based on 

conservative assumptions to reflect the highest level of emissions achievable by a facility or the 

potential to emit (PTE). It should also be noted that minor sources located further downstream 

in the oil and gas process than a well site (such as a tank battery or compressor station) may 

not represent activity at the well site. Nevertheless, minor source permit data were useful for 

gap-filling many data fields for source category/basin combinations with regionally-specific 

information that was not otherwise available from the survey responses or other data sources. 

Permit applications for ‘production facilities’ (well sites) denote the county where the facility is 

located, thus providing a way for allocating the activity data to the basins of interest, i.e., 

Louisiana Mississippi Salt Flats, Anadarko and Arkoma, Cambridge and Sedgwick. 

5.2.2 Permit Data Mining Procedure and Examples 

CenSARA member states worked with ENVIRON to provide access to hard copies of minor 

source permit applications for production facilities that required a 2011 permit. Oklahoma 

members provided access to a library of CY2011 synthetic minor source permit applications for 

production facilities at Anadarko and Arkoma. Data was pulled from 25 permits for source 
December 2012 

35 

categories of interest including compressor engines, artificial lift engines, condensate tanks and 

heaters. 

Louisiana provided a comprehensive list of oil and gas related Agency Interest (AI) numbers, an 

identification number assigned to every facility regulated by the Louisiana Department of 

Environmental (LADEQ,) and categorized under a source industrial classification (SIC) code. 

Production facilities were filtered from the AI database based on the SIC codes for well sites, 

and sample applications were queried in LADEQ’s Electronic Document Management System 

(EDMS) by the AI numbers. A bank of 30 permit applications were reviewed to extract 

emissions data for compressor engines, artificial lift engines, condensate/oil tanks, and 

dehydrators in production facilities located in the Louisiana Mississippi Salt Flats basin. 

Examples of specific data fields that were extracted from air permits and used as calculation 

inputs for source categories’ emissions are shown in Table 5-3. 

Table 5-3. Examples of specific data fields gap-filled by state permit data. 

Source Category Data field(s) Comments on derivation of data 

Condensate/oil tanks Heating value of flash gas; tank 

losses per unit throughput (lbsVOC/bbl) 

Tanks losses per unit throughput values were derived 

by dividing annual uncontrolled tank emissions 

(flashing +w/b) by the liquid throughput of the tank in 

barrels, and taking a throughput-based weighted 

average from all permits. 

Controls: fraction of tank throughput 

flared 

Dehydrators Still vent VOC emissions per unit of 

gas throughput (lbs-VOC/MMSCF); 

dehydrator reboiler BTU rating 

Still vent VOC emissions per unit throughput values

were derived by dividing annual uncontrolled 

dehydrator emissions by the annual gas throughput in 

MMSCF/yr. A throughput-based weighted average 

from all permits was used. 

Heaters Heater rating (MMBTU/hr) A weighted average from various permits was used. 

Compressors 

(wellhead and lateral) 

Fraction of lean burn versus rich 

burn 

OKDEQ provided an equipment inventory on 

compressor engines (minor sources) by basin; this 

inventory included equipment counts, engines 

characteristics such as size, rich vs. lean burn and data 

on controls. Fractions were estimated based on 

equipment counts and the categorization of interest. 

Controls: fraction of rich burn 

engines controlled by non-selective 

catalytic reduction; fraction of lean 

burn engines controlled by catalytic 

oxidizers 

In addition, Kansas and Oklahoma provided specific minor source permit data from their 

records to help gap-fill data fields for particular source categories. For example, condensate 

tanks and crude oil tanks emissions data (and emissions model runs if available) from permits 

were obtained to estimate an average VOC emissions factor for tank losses. E&P TANK model 

runs include the speciation of flash and post-flash gas streams that enabled estimation of HAPs 

emissions from tanks. Oklahoma also provided crucial data on minor source compressor 

engines that allowed for the derivation of data fields such as percent of compressors 

controlled, and fraction of lean burn versus rich burn. 
December 2012 

36 

Gas composition analyses for different gas venting/leaking points at well sites, such as 

produced gas, flash gas, and post-flash gas, were also extracted from permit applications, or 

provided directly by state agencies (Kansas) for specific basins. These were used to gap-fill any 

average gas compositions needed to estimate VOC and HAPs emissions from condensate/oil 

tanks flashing losses, tank unloading emissions, and other venting sources. 

5.3 Literature Sources and Gap-Filling for Non-Surveyed Basins 

Regionally-specific inputs that could not be derived from surveys or state minor source air 

permits were gap-filled with data from previous oil and gas emissions studies or, when 

considered necessary, using regional average values from survey data collected for other basins 

within CenSARA. This approach was used primarily but not exclusively for the low-tier source 

categories and for those basins that were not part of the survey outreach. ENVIRON and ERG 

reviewed existing sources of data in the literature on oil and gas activities and emission factors 

to fill in remaining data gaps in the inventory calculation inputs. 

5.3.1 Reviewed literature 

Literature was reviewed for information applicable to oil and gas activities in the CenSARA 

domain. Data sources were evaluated to determine which data were most suitable for filling 

data gaps either for selected source category/basin combinations or, in some cases, for all 

basins for a low-tier source category. Criteria used to determine the applicability of the 

literature data for the CenSARA oil and gas emissions inventory was based on: (1) the 

geographic scope of the study (2) temporal representativeness of the study and (3) 

quality/consistency of data as compared against other literature sources. The geographic scope 

was the most critical criteria for selection of the data as equipment/process characteristics, 

emissions rates, and gas compositions vary by region. For example, preliminary data from the 

Haynesville Shale 2011 Emissions Inventory Update (ENVIRON, 2012) was found to be the most 

relevant for certain source category estimates for the Louisiana-Mississippi Salt Flats Basin; the 

Haynesville Shale formation is located within the Salt Flats Basin and is where most of the 

basin-wide gas production is generated. Specific calculation inputs derived from the Haynesville 

Shale 2011 Emissions (Draft) Inventory are shown in Table 5-4, along with the other data 

resources that were reviewed and from which data inputs were derived in this study. When 

warranted, the temporal characteristic of the data source was considered as a selection criteria 

to insure that the most up-to-date data were applied in the calculations. Finally, data were 

evaluated for usefulness and consistency with similar oil and gas emissions inventory inputs and 

individual data points were either rejected or used based on ENVIRON’s experience with 

previous oil and gas inventory development projects. 
December 2012 

37 

Table 5-4. Specific calculation inputs derived from literature sources. 

Literature Source 

Geographic Domain of 

Source 

Source Category/Basin 

data was applied for Data Field(s) 

2011 Update of the 

Haynesville Shale 

Emissions Inventory 

(ENVIRON, 2012). 

Draft Inventory as of 

October 2012

Haynesville Shale 

formation within the 

Louisiana Mississippi Salt 

Flats basin 

Wellhead Compressors/Salt 

Flats 

Fraction of lean burn vs. rich burn; 

rated horsepower for lean burn 

engines; load factors 

Controls: % of rich burn engines 

controlled by non-selective 

catalytic reduction 

Drill Rigs (Horizontal)/Salt 

Flats 

Total horsepower and hours of 

operation from a diesel-powered 

drill rig (includes all equipment in 

rig) 

Fracturing Pumps/Salt Flats Engine horsepower and load 

factors 

Recommendations 

for Improvements to 

the CENRAP States’ 

Oil and Gas 

Emissions 

Inventories (BarIlan, et al., 2008) 

Central Region States Drill Rigs/Permian Vertical and horizontal drill rig 

configurations (total HP, load 

factors) 

Completion Well 

Venting/Permian 

Venting rate (MCF/event) 

Heaters/OK, LA, TX basins Numbers of heaters per well; 

heater BTU rating 

Fugitives/all basins Number of devices per typical 

well 

Condensate Tanks/Permian Controls: Fraction of tank 

throughput flared 

EPA 2010 National 

Greenhouse Gas 

Inventory 

(EPA, 2012) 

National average Completion Well 

Venting/Sedgwick 

Venting rate volume (MCF/event) 

National average Heaters/Kansas basins Numbers of heaters per well 

Midcontinent Region Gas-actuated pneumatic 

Pumps/all basins 

Methane venting rate per unit gas 

throughput, Methane venting rate 

per kimray pump, average no. 

pumps per well 

Midcontinent Region Compressor seal 

fugitives/all basins 

Methane leaking rate from 

compressor seals (SCF 

methane/hr/compressor) 

National average Crude oil loading/all basins Fraction of crude oil production 

delivered to refinery by truck 

EPA Natural Gas Star 

Workshop on 

Plunger Lifts 

(EPA, 2006a) 

National average Blowdowns/AnadarkoArkoma Controls: Plunger lift control 

efficiency for liquids unloading 

The Climate Registry 

Oil and Gas 

Production Annex II 

to the General 

Reporting Protocol 

(TRC, 2010) 

National average Water tanks/Permian and 

Salt Flats 

Methane emissions factor for 

water tank losses at gas wells; 

methane emissions factors for 

water tanks at oil wells 

Mud degassing/all basins Methane emissions factors for 

mud degassing; methodology 
December 2012 

38 

Literature Source 

Geographic Domain of 

Source 

Source Category/Basin 

data was applied for Data Field(s) 

EPA AP 42, 

Compilation of Air 

Pollutant Emission 

Factors, Fifth Edition 

(EPA, 1991; EPA, 

1995; EPA, 1998; 

EPA, 2000; EPA, 

2008) 

National average Compressor engines 

(wellhead and lateral)/all 

basins 

Natural gas fired reciprocating 

engines emissions factors for rich 

burn and lean burn engines 

Artificial Lifts/all basins Natural gas fired reciprocating 

engines emissions factors for rich 

burn engines for all pollutants of 

interest 

Flaring (all venting source 

categories)/all basins 

Flaring emissions factors for all 

criteria pollutants, greenhouse 

gases and formaldehyde 

Heaters/all basins External combustion natural gasfired engines emissions factors 

Fugitives/all basins TOC emissions factors for each

equipment type by service 

type(kg/hr/component) 

Loading/all basins Saturation factors and 

methodology for liquid loading 

emissions 

NONROAD2008a 

emissions model 

(EPA, 2005) 

CenSARA states average Drill Rigs/all basins CenSARA regional average 

emissions factors for 2011 for oil 

field equipment derived from EPA 

NONROAD2008 model 

SPECIATE 4.0 (EPA, 

2006b) 

National average Drill Rigs, Fracing Pumps, 

Flaring, Heaters/all basins 

Speciation profiles for HAPs in 

combustion emissions from 

selected source categories 

WRAP Phase III 

(WRAP, 2012) 

Rocky Mountain Region Drilling Rigs/Permian Engine time of operation 

Crude Oil Tanks/Permian VOC emissions factor (lbsVOC/bbl) 

Controls: fraction of tank 

throughput flared 

Dehydrator/Permian VOC emissions factor (lbsVOC/MMSCF) 

5.3.2 Inputs for emissions estimates of non-surveyed basins 

Inventory development in this study was focused on characterizing to the best extent possible 

emissions and activity in the major oil and gas producing basins (based on 2011 production 

statistics) and on basins identified by CenSARA as being of special interest. Basin-specific data 

were collected via industry surveys and via review of minor source air permits as explained in 

previous sections. Part of the oil and gas activity data for most basins in Texas other than the 

Permian and the Marathon Thrust Belt were obtained from the Texas statewide oil and gas 

inventory and its associated emissions calculator tool previously developed by ERG (ERG, 2010). 

Data inputs for the following basins that were not included in the surveys were developed on a 

case by case basis: 

x Bend Arch-Fort Worth Basin (TX, OK) 
December 2012 

39 

x Cherokee Platform (KS, OK) 

x Denver Basin (NE) 

x East Texas Basin (TX) 

x Forest City Basin (MO, KS) 

x Illinois Basin (MO, AR) 

x Marathon Thrust Belt (TX) 

x Nemaha Uplift (NE, KS, OK) 

x Ozark Uplift (MO, AR) 

x Palo Duro Basin (TX) 

x Salina Basin (KS, NE) 

x Southern Oklahoma (OK) 

x Western Gulf (TX, LA) 

For basins outside of Texas, such as Cherokee, Nemaha Uplift, Ozark Uplift, Salina, Southern 

Oklahoma, Denver, Forest City and Illinois, inputs for each emissions calculation field were 

developed based on regionally-specific averages (or equivalencies) of data used in other 

surveyed-basins’ calculations. Averages were compiled differently for each non-surveyed basin 

based on what ENVIRON considered the most equivalent region (or mix of regions) to represent 

activity in the non-surveyed basin. For example, data fields for Denver basin were assumed to 

be similar to those of the Cambridge Arch. The averaging rules were applied consistently in 

each data field throughout all source categories in the inventory. Table 5-5 summarizes the 

averaging rules for input data for non-surveyed basins outside of Texas. 

Table 5-5. Input data assumptions for non-surveyed basins outside of Texas (except 

Marathon Thrust Belt). 

Non-surveyed basin Inputs were developed as 

Cherokee Platform Activity data is the average of activity from surveyed basins (Anadarko, Cambridge, 

Arkoma, Permian and Louisiana Salt Flats) 

Denver Basin Activity data assumed similar to that of Cambridge Arch Basin 

Forest City Basin Activity data is the average of Cambridge and Sedgwick Basins’ activity 

Illinois Basin Activity data assumed similar to that of Arkoma Basin 

Marathon Thrust Belt Activity data assumed similar to that of Permian Basin 

Nemaha Uplift Activity data is the average of Cambridge and Sedgwick Basins’ activity 

Ozark Uplift Activity data is the average of activity from surveyed basins (Anadarko, Cambridge, 

Arkoma, Permian and Louisiana Salt Flats) 

Salina Basin Activity data assumed similar to that of Cambridge Arch Basin 

Southern Oklahoma Activity data is the average of Arkoma and Anadarko Basins’ activity 

Activity inputs in the Marathon Thrust Belt were assumed to be equivalent to those in the 

Permian Basin. For non-surveyed basins in Texas other than the Marathon Thrust Belt, input 

data for certain source categories were derived from previous oil and gas inventories prepared 

for or by the Texas Commission on Environmental Quality (TCEQ) as shown in Table 5-6 
December 2012 

40 

including the Texas Statewide Oil and Gas Inventory (ERG, 2010) which estimated 2008 countylevel emissions for area sources in the upstream sector (on-shore). ERG collected county-level 

activity data, and specific emissions and emission factors data for each source category 

included in that inventory based on a variety of data sources, including existing databases (such 

as the Texas Railroad Commission (TRC) oil and gas production data), point source emissions 

inventory reports submitted to TCEQ (used for dehydrators), vendor data (used for 

compression engines and artificial lift engines), and published emission factor and activity data 

from the Houston Advanced Research Center (HARC), the Central Regional Air Planning 

Association (CENRAP), and the U.S. Environmental Protection Agency (EPA). 

Table 5-6. Data sources used for calculation inputs for non-surveyed basins in Texas 

Study and General Description Author, Year Notes 

TCEQ’s Characterization of Oil and Gas 

Production Equipment and Develop a 

Methodology to Estimate Statewide 

Emissions 

ERG, 2010 Base year 2008 emissions inventory at the

county-level for multiple oil and gas source 

categories. Includes emissions calculator 

tool for Texas basins. 

TCEQ’s Condensate Tank Oil and Gas 

Activities Study 

ERG, 2012 Developed emissions factors and control 

factors for condensate storage tanks. Data 

is meant to be used for area source 

inventory development at the county-level 

for eight geographic regions in the TX. 

Data from these studies were applied to Texas’ basins using the methodologies developed for 

CenSARA to the extent possible. For those source categories that were not covered in previous 

Texas studies, calculation inputs were based on a regional average using data from surveyedbasins. State agencies may choose to gather the necessary data to update and provide more 

regionally specific inputs in the future. 

 
December 2012 

41 

6.0 EMISSIONS CALCULATOR TOOL DEVELOPMENT 

6.1 Structure of Emissions Tool 

The CenSARA Oil and Gas Emissions Calculations Tool is housed in a Microsoft Excel workbook. 

A separate workbook was developed for each state and is used to compile emissions for only 

that state. These are included in Electronic Appendix C. The Calculator Tool design is similar to 

the emissions calculator tool previously developed by ERG for the TCEQ but is more robust and 

flexible to accommodate the large amount of data developed in this study and the needs of 

each individual state. The Tool is structured to allow users to enter either county- or basinspecific information and review the calculated emissions. The “backbone” of the Tool consists 

of three main data sheets: 

x Inputs_Activity: county-level production and drilling information. There are 783 counties 

within the CenSARA oil and gas region; 

x Basin_Factors: basin-level factors that apply to variations in oil and natural gas activities 

across each basin. There are 19 basins within the CenSARA oil and gas region. 

Approximately 400 data parameters describe each basin and source category; 

x Emission_Factors: applied to selected source categories, regardless of geographic level. 

The information in the three main data sheets are actively linked to the SCC-specific emission 

calculation worksheets. In total, there are 34 worksheets representing 18 source categories. 

Table 6-1 presents the Source Categories and the applicable SCCs. 

Table 6-1. Oil and gas emission source categories.

Source Category SCC SCC Shortened Description 

ARTIFICIAL LIFT ENGINES 2310000330 Oil & Gas Expl & Prod /All Processes /Artificial Lift 

BLOWDOWNS 2310021603 On-Shore Gas Production / Gas Well Venting - 

Blowdowns 

CASINGHEAD GAS VENTING 2310011000 On Shore Crude Oil Production All Processes 

CONDENSATE TANKS 2310021010 On-Shore Gas Production /Storage Tanks: 

Condensate 

CRUDE OIL TANKS 2310010200 Oil & Gas Expl & Prod /Crude Petroleum /Oil Well 

Tanks - Flashing & Standing/Working/Breathing 

DEHYDRATORS 2310021400 On-Shore Gas Production Dehydrators 

DRILL RIGS 2310000220 Oil And Gas Exploration Drill Rigs 

FUGITIVES 2310011501 On-Shore Oil Production /Fugitives: Connectors 

FUGITIVES 2310011502 On-Shore Oil Production /Fugitives: Flanges 

FUGITIVES 2310011503 On-Shore Oil Production /Fugitives: Open Ended 

Lines 

FUGITIVES 2310011505 On-Shore Oil Production /Fugitives: Valves 

FUGITIVES 2310021501 On-Shore Gas Production /Fugitives: Connectors 

FUGITIVES 2310021502 On-Shore Gas Production /Fugitives: Flanges 

FUGITIVES 2310021503 On-Shore Gas Production /Fugitives: Open Ended 

Lines 

FUGITIVES 2310021505 On-Shore Gas Production /Fugitives: Valves 

FUGITIVES 2310021506 On-Shore Gas Production /Fugitives: Other 

GAS-ACTUATED PUMPS 2310111401 On-Shore Oil Exploration /Oil Well Pneumatic Pumps 
December 2012 

42 

Source Category SCC SCC Shortened Description 

GAS-ACTUATED PUMPS 2310121401 On-Shore Gas Exploration: Gas Well Pneumatic 

Pumps 

HEATERS 2310010100 On-Shore Oil Production /Heater Treater 

HEATERS 2310021100 On-Shore Gas Production /Gas Well Heaters 

HYDRAULIC FRACTURING 2310000660 Oil & Gas Expl & Prod /All Processes /Hydraulic 

Fracturing Engines 

LATERAL/GATHERING LINE 

COMPRESSORS 

2310021351 On-Shore Gas Production/Lateral Compressors 4 

Cycle Rich Burn 

LATERAL/GATHERING LINE 

COMPRESSORS 

2310021251 On-Shore Gas Production/Lateral Compressors 4 

Cycle Lean Burn 

LOADING EMISSIONS 2310011201 On-Shore Oil Production /Tank Truck/Railcar 

Loading: Crude Oil 

LOADING EMISSIONS 2310021030 On-Shore Gas Production /Tank Truck/Railcar 

Loading: Condensate 

MUD DEGASSING 2310111100 On-Shore Oil Exploration /Mud Degassing 

MUD DEGASSING 2310121100 On-Shore Gas Exploration /Mud Degassing 

PNEUMATIC DEVICES 2310010300 Oil Production Pneumatic Devices 

PNEUMATIC DEVICES 2310021300 On-Shore Gas Production Pneumatic Devices 

PRODUCED WATER 2310000550 PRODUCED WATER 

WELL COMPLETIONS 2310111700 On-Shore Oil Exploration: Oil Well Completion: All 

Processes 

WELL COMPLETIONS 2310121700 On-Shore Gas Exploration: Gas Well Completion: All 

Processes 

WELLHEAD COMPRESSOR 

ENGINES 2310021202 On-Shore Gas Production /Natural Gas Fired 4Cycle Lean Burn Compressor Engines 50 To 499 HP 

WELLHEAD COMPRESSOR 

ENGINES 2310021302 On-Shore Gas Production /Natural Gas Fired 4Cycle 

Rich Burn Compressor Engines 50 To 499 HP 

At the request of the technical team, three new SCCs were generated by EPA relating to specific 

source categories. They include: 

x Tool Source Category: Hydraulic Fracturing 

o New SCC: 2310000660 

o SCC Shortened Description: Oil & Gas Expl & Prod /All Processes /Hydraulic Fracturing 

Engines 

o Comment: This SCC replaces 2270010010; while this is a valid SCC description (Diesel: 

Industrial Equipment: Other Oil Field Equipment (Drilling Rigs)), the SCC is under the 

NONROAD Sector, and would need to be submitted separately from the other Nonpoint 

source oil and natural gas source categories. To avoid generating two separate EIS 

submittal files, EPA created a new nonpoint SCC code to describe this emission source. 

x Tool Source Category: Lateral/Gathering Compressors – 4-Cycle, Lean Burn 

o New SCC: 2310021251 

o SCC Shortened Description: On-Shore Gas Production/Lateral Compressors 4-Cycle Lean 

Burn 
December 2012 

43 

o Comment: This SCC replaces 2310021209, which is “On-Shore Gas Production/ Total: All 

Natural Gas Fired 4-Cycle Lean Burn Compressor Engines”. This description is too 

general and not specific enough for this source category. 

x Tool Source Category: Lateral/Gathering Compressors – 4-Cycle, Rich Burn 

o New SCC: 2310021351 

o SCC Shortened Description: On-Shore Gas Production/Lateral Compressors 4-Cycle Rich 

Burn 

o Comment: This SCC replaces 2310021309, which is “On-Shore Gas Production/ Total: All 

Natural Gas Fired 4-Cycle Rich Burn Compressor Engines”. This description is too general 

and not specific enough for this source category. 

Each SCC worksheet follows the same general structure. The first nine columns contain 

descriptive information related to the emissions estimate, and are: FIPS, State abbreviation, 

County Name, Attainment status, Basin Name, SCC, SCC Shortened description, Source 

Category name, pollutant code. The next sets of fields are information extracted from the 

“Inputs_Activity” tab, such as: oil counts; gas completions; and horizontal drilling depth. The 

last grouping of information is for data fields extracted from the “Basin_Factors” tab, such as: 

hours of operation, molecular weight of the gas; and fraction of benzene in the VOC emissions. 

The traditional nonpoint sources inventory contains activity data, emission factor, control 

information, and then emissions. Thus, after the last grouping of extracted information: 1) the 

activity data are populated or calculated; 3) the emission factor data are populated or 

calculated; and 3) the emissions are calculated. In each of the worksheets, the User has the 

ability to adjust emissions to avoid including point source emissions in the area source 

emissions total, and then a final nonpoint emission estimate is generated. Each workbook has a 

crosswalk of point sources to nonpoint sources SCCs which may be useful in entering the point 

source emissions adjustment. 

There is also enhanced flexibility in adjusting inputs at the county- or basin-level, as well as 

color shading to assist the user with interpretation of data. The color shadings are as follows: 

x Yellow: the user can overwrite the data in these cells; 

x Red: point source activity adjustments can be made by the user. This is not recommended 

unless the adjustments cover all upstream oil and gas emissions that are currently included 

in the state’s point sources emissions inventory; and 

x Orange: point source emission adjustments can be made by the User in each SCC 

worksheet. 
December 2012 

44 

6.2 Summary of methodologies used to estimate emissions for each source 

category 

Emissions for individual oil and gas area source categories are developed following a bottom-up 

approach that begins with developing mass emission rates for each pollutant based on an 

activity surrogate (e.g. tons per well, tons per barrel of oil, tons per feet drilled). These bysurrogate emission rates are then scaled to county-level emissions by multiplying the emission 

rates by the scaling surrogate or activity from a particular county (e.g. gas well counts, 

horizontal feet drilled, crude oil production, etc.). Basin-level emissions are calculated as the 

sum of emissions from each county within the basin geographical limits. 

Emissions calculations are performed within the Emissions Calculator Tool; data field names for 

calculation inputs are shown in a table at the end of each source category section in the same 

format and nomenclature as they would appear in the tool. Basin-specific input data for each 

source category calculation are located in the ‘BASIN_FACTORS’ and ‘INPUTS_ACTIVITY’ tabs of 

the tool which include emissions factors and equipment/activity factors for the various source 

categories. County-level production statistics, also referred to here as scaling surrogates (e.g. 

well counts, gas production, oil production, etc.), and other activity factors such as the fraction 

of gas wells with wellhead compressors are also located in the ‘INPUTS_ACTIVITY’ tab. Other 

input data referenced here may also be found in the ‘EMISSION_FACTORS’ tab, which contains 

average emission rates that were derived from the literature and are U.S. national default 

values (not regionally specific). Values in this tab are standard emissions rates generally defined 

by equipment properties or process characteristics, such as those for engine emissions, flaring 

emissions and by-component fugitives that do not typically vary by region . Therefore, venting 

emission rates, which are highly dependent on regional gas compositions, are not included in 

this tab but are instead included in the ‘BASIN_FACTORS’ tab. 

The following sections describe emissions calculations for each source category; it is noted that 

some of these methodologies may apply to multiple SCCs and thus, are calculated separately in 

the individual sheets per SCC within the tool. The corresponding tab (calculation sheet) where 

each methodology is applied is included for reference. 

6.2.1 Artificial Lifts 

Calculation sheet: ARTIFICIAL_LIFTS_2310000330 

Artificial lifts in this analysis refer specifically to engines located at oil wells that provide lift to 

the liquids in a well up to the wellhead. Generally, artificial lift engines such as pump jacks are 

small natural-gas fired engines similar to wellhead compressors. In the past decade there has 

been an increased use of electrified artificial lift engines powered by the grid; for this kind, 

emissions are assumed to be zero. The basic methodology for estimating emissions from a 

single non-electrified artificial lift engine is shown below: 

 
December 2012 

45 

Equation 1) 

907,185

i annual

engine

EF HP LF t

E

u u u

 

where: 

Eengine are emissions from an artificial lift engine [ton/year/engine] 

EFi is the emissions factor of pollutant i [g/hp-hr] 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

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

907,185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

It is recommended that artificial lift engine emissions be scaled up to the county level on the 

basis of oil well counts. The methodology for scaling up artificial lift engine emissions is shown 

below: 

Equation 2) engine TOTAL engine pumpjack CF WTOTAL E , n u E u f u 1(  ) u

where: 

Eengine,TOTAL is the total emissions from artificial lift engines in a county [ton/yr] 

Eengine is the total emissions from an artificial lift engine (as shown in Equation 1) 

[ton/yr/engine] 

n is the total number of artificial lift engines per well, generally equal to 1 (n=1) 

[engine/well] 

WTOTAL is the total number of oil wells in a county [wells] 

fpumpjack is the fraction of oil wells with artificial lift engines 

CF is the fraction of artificial lift engines that are electrified 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

FRACTION_ARTIFICIAL_ELECTRIC Fraction of artificial lift engines that 

are electric 

Unitless BASIN_FACTORS 

ARTIFICIAL_ENGINE_HP Typical horsepower (HP) of an 

artificial lift engine 

HP BASIN_FACTORS 

ARTIFICIAL_LOAD_FACTOR_LIFT_ENGINES Typical load factor of an artificial lift 

engine 

Unitless BASIN_FACTORS 

ARTIFICIAL_ANNUAL_ACTIVITY_HOURS Typical number of hours operated 

for artificial lift engines 

Hours 

per year 

BASIN_FACTORS 

EMISSION_FACTOR_NUMERATOR Engine emissions factor for

pollutant i 

g/hp-hr EMISSION_FACTORS 

FRACT_OILWELLS_NEED_COMPRESSION Fraction of oil wells with artificial 

lift engines 

Unitless INPUTS_ACTIVITY 

 
December 2012 

46 

6.2.2 Wellhead Compressor Engines 

Calculation sheet(s): WELLHEAD_COMPRESSORS_2310021202; 

WELLHEAD_COMPRESSORS_2310021302 

Wellhead compressor engines are generally small natural-gas fired engines located at the well 

site and used to boost produced gas pressure from downhole pressure to the required pressure 

for delivery to a transmissions pipeline. The fractional usage of these engines will depend on 

the basin characteristics; hence for those basins that largely require wellhead compression, this 

may be a significant area source of NOx emissions. Compressor engines found at a wellhead 

were categorized into two main categories in this analysis and thus emissions are estimated for 

each type of engine and consequently extrapolated to county-wide emissions. These categories 

of compressors are: 

x Rich burn compressors 

x Lean burn compressors 

The basic methodology for estimating emissions from wellhead compressor engines is shown in 

Equation 3: 

Equation 3) 1( )

907,185 , controlled i

i annual

engine type F CF EF HP LF t

E u  u

u u u

 

where: 

Eengine are emissions from a particular type (rich vs. lean) of compressor engine 

[ton/year/engine] 

EFi is the emissions factor of pollutant i [g/hp-hr] (note that this may be different for NOx

emissions from rich-burn vs. lean-burn engines) 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

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

Fcontrolled is the fraction of compressors of a particular type (rich vs. lean) that are controlled 

CFi is the control factor for controlled engines for pollutant i 

907,185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

County-level emissions are made up of the combination of emissions from each type of 

wellhead compressor, rich burn and lean burn. Emissions are scaled to county level using the 

usage fraction (C) of each engine type against all other compressor engines, the fraction of 

wells with wellhead compressor engines, and the total gas well count in a county, according to 

equation below: 

 
December 2012 

47 

Equation 4)   engine TOTAL rich engine rich lean engine lean TOTAL wellhead E C E  C E uW u f

, , ,

where: 

Eengine,TOTAL is the total emissions from compressor engines in a county [ton/yr] 

Eengine,lean is the total emissions from a single lean burn compressor engine per Equation (3) 

[ton/yr] 

Eengine,rich is the total emissions from a single rich burn compressor engine per Equation (3) 

[ton/yr] 

Clean is the fraction of lean-burn wellhead compressors in the basin amongst all wellhead 

compressors 

Crich is the fraction of rich-burn wellhead compressors in the basin amongst all wellhead 

compressors 

WTOTAL is the total gas well count in a county 

fwellhead is the fraction of all gas wells in the basin with wellhead compressor engines

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

EMISSION_FACTOR_NUMERATOR Engine emissions factor for 

pollutant i 

g/hp-hr EMISSION_FACTORS 

FRACTION_RICH_BURN Fraction of wellhead compressor 

engines that are rich-burn 

Unitless BASIN_FACTORS 

FRACTION_LEAN_BURN Fraction of wellhead compressor 

engines that are lean-burn 

Unitless BASIN_FACTORS 

LEAN_BURN_LOAD_FACTOR Typical load factor of a lean-burn 

wellhead compressor engine 

Unitless BASIN_FACTORS 

RICH_BURN_LOAD_FACTOR Typical load factor of a rich-burn 

wellhead compressor engine 

Unitless BASIN_FACTORS 

LEAN_BURN_CONTROLLED Fraction of wellhead lean-burn

compressor engines that are 

controlled 

Unitless BASIN_FACTORS 

RICH_BURN_CONTROLLED Fraction of wellhead rich-burn 

compressor engines that are 

controlled 

Unitless BASIN_FACTORS 

LEAN_BURN_HP Typical horsepower (HP) of a leanburn wellhead compressor engine HP BASIN_FACTORS 

RICH_BURN_HP Typical horsepower (HP) of a richburn wellhead compressor engine HP BASIN_FACTORS 

ANNUAL_ACTIVITY_HR Typical number of hours operated

for wellhead compressor engines 

Hours per 

year 

BASIN_FACTORS 

FRACT_GASWELLS_NEED_COMPRESSION Fraction of gas wells needing 

wellhead compression, HPDI 

Database or Survey Data 

Unitless INPUTS_ACTIVITY 

 
December 2012 

48 

6.2.3 Lateral/Gathering Compressor Engines 

Calculation sheet(s): LATERAL_COMPRESSORS_2310021351; 

LATERAL_COMPRESSORS_2310021251 

Lateral compressor engines are used to gather gas from multiple individual wells, generally 

serving groups of approximately 10 to 100 wells. These engines are generally medium size and 

larger than wellhead compressor engines, but often not large enough to trigger Title V or other 

major source permitting requirements. Lateral compressor engines were categorized into two 

main categories and thus emissions are estimated for each type of engine and consequently 

extrapolated to county-wide emissions. These categories of compressors are: 

x Rich burn compressors 

x Lean burn compressors 

The basic methodology for estimating emissions from lateral compressor engines is shown in 

Equation 5: 

Equation 5) 1( )

907,185 , controlled i

i annual

engine type F CF EF HP LF t

E u  u

u u u

 

where: 

Eengine,type are emissions from a particular type (rich vs. lean) of compressor engine 

[ton/year/engine] 

EFi is the emissions factor of pollutant i [g/hp-hr] (note that this value may be differ 

between rich-burn vs. lean-burn engines) 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

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

Fcontrolled is the fraction of lateral compressors of a particular type that are controlled 

CFi is the control factor for controlled engines for pollutant i 

907,185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

County-level emissions are represented by a mix of the two types of lateral compressors. Single 

engine emissions are scaled to county level using the fraction (C) of these engine types to total 

engines, the fraction of wells served by lateral compressor engines, and the total gas well count 

in a county, according to equation below: 

Equation 6)  

lateral

engine TOTAL rich engine rich lean engine lean TOTAL N

E C E C E W

1

, ,  , u u

 
December 2012 

49 

where: 

Eengine,TOTAL is the total emissions from compressor engines in a county [ton/yr] 

Eengine,lean is the total emissions from a single lean burn compressor engine per Equation (5) 

[ton/yr] 

Eengine,rich is the total emissions from a single rich burn compressor engine per Equation (5) 

[ton/yr] 

Clean is the fraction of lean-burn lateral compressors in the basin amongst all lateral 

compressors 

Crich is the fraction of rich-burn lateral compressors in the basin amongst all lateral 

compressors 

WTOTAL is the total gas well count in a county 

Nlateral is the number of gas wells served by a lateral compressor engine 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

EMISSION_FACTOR_NUMERATOR Engine emissions factor for pollutant i g/hp-hr EMISSION_FACTORS 

LATERAL_HRS_OPERATION Typical number of hours operated for 

lateral/gathering compressor engines 

Hours per year BASIN_FACTORS 

LATERAL_NUM_WELLS_PER_LINE No. wells served by single lateral 

compressor 

Wells per 

compressor 

BASIN_FACTORS 

LATERAL_FRACT_RICH Fraction of lateral compressors that 

are rich-burn 

Unitless BASIN_FACTORS 

LATERAL_FRACT_LEAN Fraction of lateral compressors that 

are lean-burn 

Unitless BASIN_FACTORS 

LATERAL_LEAN_HP Typical horsepower (HP) of a leanburn lateral compressor engine HP BASIN_FACTORS 

LATERAL_RICH_HP Typical horsepower (HP) of a richburn lateral compressor engine HP BASIN_FACTORS 

LATERAL_LEAN_LOAD_FACT Typical load factor of a lean-burn 

lateral compressor engine 

Unitless BASIN_FACTORS 

LATERAL_RICH_LOAD_FACT Typical load factor of a rich-burn 

lateral compressor engine 

Unitless BASIN_FACTORS 

LATERAL_LEAN_ENGINE_CONT_FRAC Fraction of lean-burn lateral 

compressor engines that are 

controlled 

Unitless BASIN_FACTORS 

LATERAL_RICH_ENGINE_CONT_FRAC Fraction of rich-burn lateral 

compressor engines that are 

controlled 

Unitless BASIN_FACTORS 
December 2012 

50 

6.2.4 Condensate tanks 

Calculation sheet: CONDENSATE_TANKS_2310021010 

Condensate storage tanks are considered a significant source of VOC emissions. Tank losses are 

generated by flashing and by working and breathing processes, although generally the 

emissions are dominated by flashing losses. This analysis uses a combined-losses emissions 

factor and assumes that the gas compositions from both processes are identical. The 

methodology for estimating condensate tank combined losses is shown below: 

Equation 7) > @ captured efficiency

condensate tanks VOC

condensate ks VOC F C C

EF

E u 1 u u

2000

, ,

,tan ,

where: 

Econdensate,tanks,VOC is the VOC emissions per liquid unit throughput from condensate tanks 

[tons/bbl] 

EFcondensate,tanks,VOC is the VOC emissions factor for combined losses from condensate tanks 

[lb-VOC/bbl] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of condensate tanks with flares 

2000 is the unit conversion factor lb/ton 

The methodology for estimating condensate tank combined losses from other pollutants i in the 

flashing gas is shown below: 

Equation 8) ܧ௡௢௖ௗ௘௡௦௔௧௘,௧௔௡௞௦,௜ = ܧ௡௢௖ௗ௘௡௦௔௧௘,௧௔௡௞௦,௏ை஼ ×

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡೔

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡ೇೀ಴

where: 

Econdensate,tanks,i is the emissions of pollutant i per liquid unit throughput from condensate 

tanks [tons/bbl] 

Econdensate,tanks,VOC is the VOC emissions per liquid unit throughput from condensate tanks 

[tons-VOC/bbl] 

weight fraction is the mass-based concentration of pollutant i and VOC in the flashing gas 

Flaring emissions from condensate tank controls 

This source category includes any flaring emissions associated with controls applied to 

condensate tanks. The methodology for estimating emissions from flaring of condensate tank 

flash gas is described below: 
December 2012 

51 

Equation 9)

    2000

1000 , , ,

 ̧

1

·

 ̈

©

§ u

 u u u u u

EF HV

E P Q F C C

i

flare tank i county condensate tanks captured efficiency

where: 

Eflare,tank,i is the county-wide flaring emissions of pollutant i from condensate tank controls 

[ton/yr] 

Qcondensate,tank is the uncontrolled volume of tank losses vented per unit of condensate 

throughput [MCF/bbl] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of condensate tanks with flares 

EFi is the flaring emissions factor for pollutant i [lb/MMBtu] 

HV is the local heating value of the gas [BTU/SCF] 

Pcounty is the annual throughput of condensate production in the county [bbl/yr] 

2000 is the unit conversion factor lb/ton 

1000 is the unit conversion factor MCF/MMCF 

The methodology for estimating SO2 emissions from flaring of oil and condensate flash gas is 

shown below: 

Equation 10) 

     

907185

2

5.3 10

2 2

5

,

, , u u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧ u u u

1

·

 ̈

©

§

u u u u u

 



H S

gas

condensate tank captured efficiency county

flare tank SO f

T MW

R

P Q F C C P

E

where: 

2

Eflare,tank ,SO is the county-wide SO2 flaring emissions from condensate tanks controls 

[ton/yr] 

P is atmospheric pressure [1 atm] 

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

MWgas is the molecular weight of the flash gas [g/mol] 

T is the atmospheric temperature [298 K] 

H S

f

2

 is the mass fraction of H2S in the flash gas 

Qcondensate,tank, is the uncontrolled volume of tank losses vented per unit of condensate 

throughput [MCF/bbl] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of condensate tanks with flares 
December 2012 

52 

Pcounty is the annual throughput of condensate production county-wide [bbl/yr] 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

To estimate county-wide total condensate tank emissions, which includes venting and flaring, 

for each pollutant i, Equation 11 below is used: 

Equation 11) Econd.tan ks,TOTAL Econdensate,tan ks,i u P  Eflare,tan k ,i

where 

Econd.tanks,TOTAL is the county-wide total emissions for pollutant i from condensate tanks 

[tons/yr] 

Econdensate,tanks,i is the combined losses of pollutant i per liquid unit throughput from 

condensate tanks [tons/bbl] 

P is the annual production of condensate county-wide [bbl/yr] 

Eflare,tank,i is the county-wide flaring emissions of pollutant i from condensate tank controls 

[ton/yr] 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

COND_TANK_FRAC_TO_TANKS Fraction of condensate directed to 

tanks 

Unitless BASIN_FACTORS 

COND_TANK_FLARE_FRAC Fraction of condensate tanks with 

a flare 

Unitless BASIN_FACTORS 

COND_TANK_FLASH_GAS_VOC_FRAC VOC fraction of the flash gas Unitless BASIN_FACTORS 

COND_TANK_FLARE_CAPT_EFF Capture Efficiency of the flare Unitless BASIN_FACTORS 

COND_TANK_FLARE_CONT_EFF Control Efficiency of the flare Unitless BASIN_FACTORS 

COND_TANK_AVG_FLASH_LOSSES Flashing emission factor VOC lost 

per barrel (BBL) of condensate 

throughput 

LB VOCS/BBL BASIN_FACTORS 

COND_TANK_AVG_WORK_BREATH_LOSS Working/Breathing emission 

factor VOC lost per barrel (BBL) of 

condensate throughput 

LB VOCS/BBL BASIN_FACTORS 

COND_TANKS_NUM_PER_WELL Number of condensate tanks per 

well 

COUNT BASIN_FACTORS 

COND_TANK_VOC_LOSS_THROUGHPUT Emission factor of VOC per barrel 

(BBL) of condensate throughput 

LB VOC/BBL BASIN_FACTORS 

COND_TANK_FLASH_GAS_VENTING_RAT

E 

Volume of flash gas vented per 

BBL of condensate throughput 

MCF/BBL BASIN_FACTORS 

COND_TANK_LOCAL_HV Heating value of the flared gas at 

the condensate tank 

BTU/SCF BASIN_FACTORS 
December 2012 

53 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

COND_TANK_FRACT_H2S Fraction of hydrogen sulfide in the 

flared gas at the condensate tank 

Unitless BASIN_FACTORS 

COND_TANK_MW_GAS Molecular weight of the flash gas 

being flared at the condensate 

tank 

G/MOL BASIN_FACTORS 

COND_TANK_FACTOR_CH4_VOC Methane ratio to VOC being 

emitted from condensate storage 

tanks 

Unitless BASIN_FACTORS 

COND_TANK_FACTOR_BENZ_VOC Benzene fraction of VOC being 

emitted from condensate storage 

tanks 

Unitless BASIN_FACTORS 

COND_TANK_FACTOR_ETHYLBENZ_VOC Ethylbenzene fraction of VOC 

being emitted from condensate 

storage tanks 

Unitless BASIN_FACTORS 

COND_TANK_FACTOR_TOLUENE_VOC Toluene fraction of VOC being 

emitted from condensate storage 

tanks 

Unitless BASIN_FACTORS 

COND_TANK_FACTOR_XYLENE_VOC Xylene fraction of VOC being 

emitted from condensate storage 

tanks 

Unitless BASIN_FACTORS 

6.2.5 Dehydrators 

Calculation sheet: DEHYDRATORS_2310021400 

In the current analysis, this source category refers to wellhead dehydrator units. Dehydrator 

units are used to remove excess water from produced natural gas prior to delivery to the 

pipeline or to a gas processing plant. Two main sources of emissions are found in a dehydrator 

device: hydrocarbon emissions (including VOC, HAPs, CH4) are generated in the dehydrator still 

vent, and combustion emissions are generated in the dehydrator reboiler. In addition, if 

dehydrator still vents are controlled by flare, combustion emissions from flaring controls 

contribute to the total dehydrator emissions. The basic methodology for estimating countywide emissions from dehydrator still vents is shown in Equation 12: 

Equation 12) > @ captured efficiency

stillvent

stillvent VOC F C C

EF E P u  u u

u

 u 1

1000 2000 ,

where: 

Estillvent,VOC is the county-wide VOC emissions from dehydrator still vents [ton/yr] 

EFstillvent is the VOC emission factor for dehydrator still vent per unit of gas throughput [lbVOC/MMSCF] 

P is the annual county-wide throughput of gas (gas production) [MCF/yr] 

F is the fraction of dehydrator vents with flares 
December 2012 

54 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

2000 is the unit conversion factor lb/ton 

1000 is the unit conversion factor MCF/MMCF 

The methodology for estimating dehydrator still vent emissions from other pollutants i is shown 

below 

Equation 13) ܧ௦௧௜௟௟௩௘௡௧,௜ = ܧ௦௧௜௟௟௩௘௡௧,௏ை஼ ×

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡೔

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡ೇೀ಴

where: 

Estillvent,i is the county-wide emissions of pollutant i from dehydrator still vents [ton/yr] 

Estillvent,VOC is the county-wide VOC emissions from dehydrator still vents [ton/yr] 

weight fraction is the mass-based concentration of pollutant i or VOC in the vented gas 

The basic methodology for estimating emissions for the dehydrator reboiler is equivalent to 

that of a standard field heater: 

× ܰ = ௜ ,௥௘௟௜௢௕௘௥ܧ (14 Equation

ாி೔ × ொೝ೐್೚೔೗೐ೝ× ௧ೌ೙೙ೠೌ೗ × ௛௖

ு௏೗೚೎ೌ೗ × ଵ.ଵ଴ల ×ଶ଴଴଴

× ܹ

where: 

Ereboiler,i is the county-wide emissions from pollutant i from dehydrator reboilers [ton/yr] 

EFiis the emission factor for pollutant i for natural gas-fired small boilers [lb/MMSCF] 

Qreboiler is the heater size [Btu/hr] 

HVlocal is the local natural gas heating value [Btulocal/SCF] 

tannual is the annual hours of operation [hr] 

hc is a heater cycling fraction of operating hours that the heater is firing

N is the number of dehydrators per well [1/well] 

W is the county-wide number of active gas wells in a particular year [well/yr] 

2000 is the unit conversion factor lb/ton 

1.106 is the unit conversion factor SCF/MMSCF 

Flaring emissions from dehydrator venting controls 

The methodology for estimating county-wide emissions from flaring of dehydrator still vent gas 

is described below 

Equation 15) 

    2000

10 , , , 6

 ̧

1

·

 ̈

©

§ u

 u u u u u

EF HV

E G Q F C C

i

flare dehy i dehydrator vent captured efficiency
December 2012 

55 

where: 

Eflare,dehy is the county-wide emissions of pollutant i from dehydrator vent gas flaring [ton/yr] 

Qdehydrator,vent is the volume of gas flared per unit of gas throughput in dehydrator [MCF 

vented/MMSCF natural gas] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of dehydrators with flares 

EFi is the flaring emissions factor for pollutant i [lb/MMBtu] 

HV is the local heating value of the gas [BTU/SCF] 

G is the county-wide gas production [MMSCF/yr] 

2000 is the unit conversion factor lb/ton 

1.106 is the unit conversion factor SCF/MMSCF 

The methodology for estimating SO2 emissions from flaring of dehydrator vent gas is shown 

below 

Equation 16) 

   

907185

2

5.3 10

2 2

5

,

, , u u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧ u u u

1

·

 ̈

©

§

u u u u

 u



H S

gas

dehydrator vent captured efficiency

flare dehydrator SO f

T MW

R

G Q F C C

E P

where: 

2

Eflare,dehydrator,SO is the county-wide SO2 flaring emissions from flaring of dehydrator vent gas 

[ton/yr] 

P is atmospheric pressure [1 atm] 

Qdehydrator,vent is the volume of gas flared per unit of gas throughput [MCF vented/MMSCF 

natural gas] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of dehydrators with flares 

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

MWgas is the molecular weight of the dehydrator venting gas [g/mol] 

T is the atmospheric temperature [298 K] 

H S

f

2

 is the mass fraction of H2S in the dehydrator venting gas 

G is the county-wide gas production [MMSCF/yr] 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

 
December 2012 

56 

Extrapolation to county-level emissions 

Equations 12-16 provide direct county-level estimates of pollutant emissions from dehydrator 

still vents, reboilers, and flaring controls. Emissions of the same pollutant each of these three 

sub-categories should be added together to arrive at total county-level dehydrator emissions 

(still vent + reboiler + flaring). 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

DEHYD_FRACT_FLARES Fraction of dehydrators with flares Unitless BASIN_FACTORS 

DEHYD_STILL_VENT_VOC_EF VOC Stillvent emission factor LB 

VOC/MMSCF 

BASIN_FACTORS 

DEHYD_REBOILER_RATING Heater size rating BTU/HR BASIN_FACTORS 

DEHYD_LHV Heating value of the natural gas 

used for fuel 

BTU/SCF BASIN_FACTORS 

DEHYD_OP_HRS Typical number of hours operated 

for the reboiler 

Hours per year BASIN_FACTORS 

DEHYD_HEATING_CYCLE Fraction to account for the 

fraction of operating hours that 

the heater is firing 

Unitless BASIN_FACTORS 

DEHYD_NUM_PER_WELL Number of dehydrators per well COUNT/WELL BASIN_FACTORS 

DEHYD_VOL_GAS_FLARED_THROUGHPUT Volume of gas flared per unit of 

natural gas throughput 

MCF/MMSCF BASIN_FACTORS 

DEHYD_VOC_FRACT_FLARE_GAS VOC fraction in the Flared Gas Unitless BASIN_FACTORS 

DEHYD_H2S_FRACT_FLARE_GAS Hydrogen sulfide fraction in the 

Flared Gas 

Unitless BASIN_FACTORS 

DEHYD_MW Molecular weight of the flared gas G/MOL BASIN_FACTORS 

DEHYD_FLARING_CAPTURE_EFF Capture Efficiency of the flare Unitless BASIN_FACTORS 

DEHYD_FLARING_CONTROL_EFF Control Efficiency of the flare Unitless BASIN_FACTORS 

DEHYD_STILL_VENT_CH4_VOC Methane ratio to VOC being 

emitted from dehydrator still vent 

Unitless BASIN_FACTORS 

DEHYD_STILL_VENT_BENZ_VOC Benzene ratio to VOC being 

emitted from dehydrator still vent 

Unitless BASIN_FACTORS 

DEHYD_STILL_VENT_ETHYLBENZ_VOC Ethylbenzene ratio to VOC being 

emitted from dehydrator still vent 

Unitless BASIN_FACTORS 

DEHYD_STILL_VENT_TOLEUNE_VOC Toluene ratio to VOC being 

emitted from dehydrator still vent 

Unitless BASIN_FACTORS 

DEHYD_STILL_VENT_XYLENE_VOC Xylene ratio to VOC being emitted 

from dehydrator still vent 

Unitless BASIN_FACTORS 
December 2012 

57 

6.2.6 Drilling Rigs 

Calculation sheet: DRILL_RIGS_2310000220 

Drilling rig emissions considered three primary engines: Draw works, Mud pumps and 

Generators. Each of these three engine types is used for differing periods of time throughout 

the drilling process and are likely to have different load factor and sizes. Each of the three 

engines is also likely to be of differing model years and hence Tier levels. Some drilling rigs 

operate with a set of large generator engines which provides electric power to the other prime 

movers of the rig – draw works and mud pumps; these type of rigs are referred to here as 

diesel-electric rigs. In order to account for variations in engine characteristics and their effect in 

final emissions, average emissions for each type of engine k (k=drawworks, mum pumps or 

generators) is estimated separately. In addition, operation parameters such as time and load 

factor vary for vertical wellbores and horizontal wellbores; hence emissions were estimated 

separately for both drilling methods using equation 17 and 18. 

Emissions for a single engine of type k are estimated according to Equation 17: 

= ௜,௞ ௘௡௜௚௡௘ܧ (17 Equation

ாி೔×ு௉ೖ×௅ிೖ×௧೐ೡ೐೙೟×௡

ଽ଴଻,ଵ଼ହ

where: 

Eengine k,i are emissions of pollutant i from an engine type k [ton/spud] 

EFi is the average emissions factor of pollutant i [g/hp-hr] 

HPk is the average horsepower for an engine k in the basin [hp] 

LFk is the average load factor of the engine k 

tevent is the number of hours engine k is used [hr/spud] 

907,185 is the mass unit conversion [g/ton] 

n is the number of type-k engines in the typical drill rig 

The emission factor for pollutant i, EFi, is an average emissions factor derived from EPA’s

NONROAD2008 model and based on the representative population of drilling engine of various 

tier levels in NONROAD. The emissions factor for drill-rig equipment varies by horsepower 

range, and there are three possible horsepower bins applicable to the typical range of 

equipment sizes for drill rig engines. Hence, three sets of possible engine emissions factors (by 

HP) are used. 

Emissions from a single drill rig ൫ܧௗ௥௜௟௟௥௜௚்ை்஺௅,௜൯ are estimated in Equation 18 as the sum of 

individual emissions from each drill rig engine as calculated with Equation 17 in [tons/spud]: 

Equation 18) ܧௗ௥௜௟௟௥௜௚்ை்஺௅,௜ = σ ܧ௞ ௘௡௜௚௡௘,௜ 

Two distinct drill-rigs configurations may be found in various basins: 

x Diesel-mechanical (D) drill rigs: in which all k engines are diesel-fueled 
December 2012 

58 

x Diesel-electric (DE) powered drill rigs: in which only the generator is powered by diesel and 

the draw works and mud pumps are electric (and thus do not have direct emissions 

associated with them) 

Thus equations 17 and 18 will vary by these two configurations, and a set of input values for 

each the four combinations of vertical/horizontal wellbores and diesel/diesel-electric rigs must 

be applied. 

Emissions from drill rigs correlate to the depth of the wellbore, which will vary between 

horizontal and vertical wellbores; thus emissions can be estimated on a “per foot drilled’ basis 

using the equation below 

Equation 19) 

௜,௚௡௜௟௟௜௥ௗܧൣ

൧

௩௘௥௧௜௖௔௟/௛௢௥௜௭௢௡௧௔௟

= ൤

ா೏ೝ೔೗೗ೝ೔೒೅ೀ೅ಲಽ,೔ವ×(ଵିிವಶ)ାா೏ೝ೔೗೗ೝ೔೒೅ೀ೅ಲಽ,೔ವಶ×ிವಶ

஽ೞ೛ೠ೏ ൨

ೡ೐ೝ೟೔೎ೌ೗

೓೚ೝ೔೥೚೙೟ೌ೗

where 

௜,௚௡௜௟௟௜௥ௗܧ

 is the total emissions for a horizontal or vertical spud per unit of feet drilled 

[tons/ft] 

ܧௗ௥௜௟௟௥௜௚்ை்஺௅,௜஽ is the emissions from a single diesel-powered drill rig (from Equation 18) 

for a vertical or a horizontal spud [tons/spud] 

ܧௗ௥௜௟௟௥௜௚்ை்஺௅,௜஽ா is the emissions from a single diesel-electric drill rig (from Equation 18) 

for a vertical or a horizontal spud [tons/spud] 

FDE is the fraction of drill rigs that are diesel-electric 

Dspud is the average depth of a vertical or horizontal spud [ft/spud] 

Extrapolation to county-level emissions 

Emissions per feet drilled are scaled to county-level drilling emissions according to Equation 20 

Equation 20) 

ܧௗ௥௜௟௟,௖௢௨௡௧௬ି௪௜ௗ௘,௜ = ൣܧௗ௥௜௟௟௜௡௚,௜൧

௩௘௥௧௜௖௔௟

× ܦ௩௘௥௧௜௖௔௟ + ൣܧௗ௥௜௟௟௜௡௚,௜൧

௛௢௥௜௭௢௡௧௔௟

× ܦ௜௥௢௛௭௢௡௧௔௟

where: 

Edrill ,county-wide,i is the total emissions of pollutant i from county-wide drilling activity [tons/yr] 

Edrilling,i is the total emissions from drilling a single well [tons/ft] 

Dvertical is the total depth drilled in the county for vertical wells in a particular year [ft/r] 

Dhorizontal is the total depth drilled in the county for horizontal wells in a particular year [ft/yr] 

 
December 2012 

59 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

DRILL_FRACT_DIESEL_ELECTRIC Fraction of drill-rigs that are 

diesel-electric 

Unitless BASIN_FACTORS 

DRILL_HORIZ_DEPTH_SPUD Average depth per spud, 

horizontal drilling 

FT/SPUD BASIN_FACTORS 

DRILL_HORIZ_SPUD_DURATION Average duration per spud, 

horizontal drilling 

HR BASIN_FACTORS 

DRILL_HORIZ_FUEL_CONSUMED Average fuel consumed, 

horizontal drilling 

GALLONS BASIN_FACTORS 

DRILL_HORIZ_DRAW_HP Average horsepower for 

draworks, horizontal drilling 

HP BASIN_FACTORS 

DRILL_HORIZ_DRAW_LOAD_FACTOR Average load factor for draworks, 

horizontal drilling 

Unitless BASIN_FACTORS 

DRILL_HORIZ_DRAW_NUM_ENGINES_RIG Average number of engines per 

rig for draworks, horizontal 

drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_HORIZ_DRAW_HRS_SPUD Average number of engines hours 

per spud for draworks, horizontal 

drilling 

HR/SPUD BASIN_FACTORS 

DRILL_HORIZ_MUD_PUMPS_HP Average horsepower for mud 

pumps, horizontal drilling 

HP BASIN_FACTORS 

DRILL_HORIZ_MUD_PUMPS_LOAD_FACTOR Average load factor for mud 

pumps, horizontal drilling 

Unitless BASIN_FACTORS 

DRILL_HORIZ_MUD_PUMPS_NUM_ENGINES_RIG Average number of engines per 

rig for mud pumps, horizontal 

drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_HORIZ_MUD_PUMPS_HRS_SPUD Average number of engines hours 

per spud for mud pumps, 

horizontal drilling 

HR/SPUD BASIN_FACTORS 

DRILL_HORIZ_GEN_DIESEL_HP Average horsepower for diesel 

rigs, horizontal drilling 

HP BASIN_FACTORS 

DRILL_HORIZ_GEN_DIESEL_LOAD_FACTOR Average load factor for diesel 

rigs, horizontal drilling 

Unitless BASIN_FACTORS 

DRILL_HORIZ_GEN_DIESEL_NUM_ENGINES_RIG Average number of engines per 

rig for diesel rigs, horizontal 

drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_HORIZ_GEN_DIESEL_HRS_SPUD Average number of engines hours 

per spud for diesel rigs, 

horizontal drilling 

HR/SPUD BASIN_FACTORS 

DRILL_HORIZ_GEN_DIESEL_ELEC_HP Average horsepower for dieselelectric rigs, horizontal drilling HP BASIN_FACTORS 

DRILL_HORIZ_GEN_DIESEL_ELEC_LOAD_FACTOR Average load factor for dieselelectric rigs, horizontal drilling Unitless BASIN_FACTORS 
December 2012 

60 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

DRILL_HORIZ_GEN_DIESEL_ELEC_NUM_ENGINES_RIG Average number of engines per 

rig for diesel-electric rigs, 

horizontal drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_HORIZ_GEN_DIESEL_ELEC_HRS_SPUD Average number of engines hours 

per spud for diesel-electric rigs, 

horizontal drilling 

HR/SPUD BASIN_FACTORS 

DRILL_VERT_DEPTH_SPUD Average depth per spud, vertical 

drilling 

FT/SPUD BASIN_FACTORS 

DRILL_VERT_SPUD_DURATION Average duration per spud,

vertical drilling 

HR BASIN_FACTORS 

DRILL_VERT_FUEL_CONSUMED Average fuel consumed, vertical 

drilling 

GALLONS BASIN_FACTORS 

DRILL_VERT_DRAW_HP Average horsepower for 

draworks, vertical drilling 

HP BASIN_FACTORS 

DRILL_VERT_DRAW_LOAD_FACTOR Average load factor for draworks, 

vertical drilling 

Unitless BASIN_FACTORS 

DRILL_VERT_DRAW_NUM_ENGINES_RIG Average number of engines per 

rig for draworks, vertical drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_VERT_DRAW_HRS_SPUD Average number of engines hours 

per spud for draworks, vertical 

drilling 

HR/SPUD BASIN_FACTORS 

DRILL_VERT_MUD_PUMPS_HP Average horsepower for mud 

pumps, vertical drilling 

HP BASIN_FACTORS 

DRILL_VERT_MUD_PUMPS_LOAD_FACTOR Average load factor for mud 

pumps, vertical drilling 

Unitless BASIN_FACTORS 

DRILL_VERT_MUD_PUMPS_NUM_ENGINES_RIG Average number of engines per 

rig for mud pumps, vertical 

drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_VERT_MUD_PUMPS_HRS_SPUD Average number of engines hours 

per spud for mud pumps, vertical 

drilling 

HR/SPUD BASIN_FACTORS 

DRILL_VERT_GEN_DIESEL_HP Average horsepower for diesel 

rigs, vertical drilling 

HP BASIN_FACTORS 

DRILL_VERT_GEN_DIESEL_LOAD_FACTOR Average load factor for diesel 

rigs, vertical drilling 

Unitless BASIN_FACTORS 

DRILL_VERT_GEN_DIESEL_NUM_ENGINES_RIG Average number of engines per 

rig for diesel rigs, vertical drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_VERT_GEN_DIESEL_HRS_SPUD Average number of engines hours 

per spud for diesel rigs, vertical 

drilling 

HR/SPUD BASIN_FACTORS 

DRILL_VERT_GEN_DIESEL_ELEC_HP Average horsepower for dieselelectric rigs, vertical drilling HP BASIN_FACTORS 

DRILL_VERT_GEN_DIESEL_ELEC_LOAD_FACTOR Average load factor for dieselelectric rigs, vertical drilling Unitless BASIN_FACTORS 
December 2012 

61 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

DRILL_VERT_GEN_DIESEL_ELEC_NUM_ENGINES_RIG Average number of engines per 

rig for diesel-electric rigs, vertical 

drilling 

COUNT/RIG BASIN_FACTORS 

DRILL_VERT_GEN_DIESEL_ELEC_HRS_SPUD Average number of engines hours 

per spud for diesel-electric rigs, 

vertical drilling 

HR/SPUD BASIN_FACTORS 

6.2.7 Pneumatic Devices 

Calculation Sheet: PNEUMATIC_GASWELL_2310021300; PNEUMATIC_OILWELL_2310010300 

Pneumatic devices are control devices located at the well site that are powered pneumatically 

by high-pressure produced gas. These devices are typically under operation throughout the 

year and they may or may not vent the working fluid during operation, making them a 

potentially significant source of VOC emissions. The counts of pneumatic devices vary between 

oil and gas wells, thus emissions were estimated separately for both well types. Emissions from 

pneumatic devices vary by the bleed rate of the device. Here it is assumed that four 

configurations can be found in a typical well: high bleed, low bleed, intermittent and no bleed. 

Emissions for the first three types of device i must be determined. The methodology for 

estimating the emissions from pneumatic devices for a particular type of well are shown in 

Equation 21: 

Equation 21) 

 ̧

 ̧

1

·

 ̈

 ̈

©

§

 ̧ u u u

1

·

 ̈

©

§

u

 ̧ u

1

·

 ̈

©

§

 u u



¦

5

,

1000 5.3 10

907185

T MW

R

P

V N t

f

E

gas

i

i i annual

j

pneumatic j



where: 

Epneumatic,j is the total emissions of pollutant j from all pneumatic devices for a particular type 

of well (oil vs. gas) [ton/year/well] 

Vi

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

Ni is the average number of devices i found in a type of well (oil vs. gas) [devices/well] 

tannual is the number of hours per year that devices were operating [8760 hr/yr] 

P is the atmospheric pressure [1 atm] 

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

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

T is the atmospheric temperature [298 K] 

fjis the mass fraction of pollutant j in the vented gas (produced gas) 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

1000 is the unit conversion factor SCF/MCF 

 
December 2012 

62 

Extrapolation to county-level emissions 

County-wide pneumatic device emissions for each well type were estimated according to 

Equation 22: 

Equation 22) Epneumatic,TOTAL, j Epneumatic, j u Nwell

where: 

Epneumatic,TOTAL,j is the total pneumatic device emissions of pollutant j in the county [ton/yr] 

Epneumatic,j is the pneumatic device emissions of pollutant j for a type of well (gas vs. oil) 

[ton/yr/well] 

Nwell is the total number of active gas (or oil) wells in the county [wells] 

Total emissions from pneumatic devices will be the combination of basin-wide emissions from 

each well type: 

Equation 23) > @ > @

oilwells pneumatic TOTAL j gaswells

Eallpneumatics, j Epneumatic,TOTAL, j  E , ,

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

PNEUMATIC_GAS_WELL_NO_BLEED_NUM_DEV Count of "No Bleed" pneumatic 

devices at gas wells 

COUNT BASIN_FACTORS 

PNEUMATIC_GAS_WELL_NO_BLEED_BLEED_RATE Bleed rate of "No Bleed" 

pneumatic devices at gas wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_GAS_WELL_LOW_BLEED_NUM_DEV Count of "Low Bleed" pneumatic 

devices at gas wells 

COUNT BASIN_FACTORS 

PNEUMATIC_GAS_WELL_LOW_BLEED_BLEED_RATE Bleed rate of "Low Bleed" 

pneumatic devices at gas wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_GAS_WELL_HIGH_BLEED_NUM_DEV Count of "High Bleed" 

pneumatic devices at gas wells 

COUNT BASIN_FACTORS 

PNEUMATIC_GAS_WELL_HIGH_BLEED_BLEED_RATE Bleed rate of "High Bleed" 

pneumatic devices at gas wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_GAS_WELL_INTERM_BLEED_NUM_DEV Count of "Intermittent" 

pneumatic devices at gas wells 

COUNT BASIN_FACTORS 

PNEUMATIC_GAS_WELL_INTERM_BLEED_BLEED_RATE Bleed rate of "Intermittent" 

pneumatic devices at gas wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_OIL_WELL_NO_BLEED_NUM_DEV Count of "No Bleed" pneumatic 

devices at oil wells 

COUNT BASIN_FACTORS 

PNEUMATIC_OIL_WELL_NO_BLEED_BLEED_RATE Bleed rate of "No Bleed" 

pneumatic devices at oil wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_OIL_WELL_LOW_BLEED_NUM_DEV Count of "Low Bleed" pneumatic 

devices at oil wells 

COUNT BASIN_FACTORS 
December 2012 

63 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

PNEUMATIC_OIL_WELL_LOW_BLEED_BLEED_RATE Bleed rate of "Low Bleed" 

pneumatic devices at oil wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_OIL_WELL_HIGH_BLEED_NUM_DEV Count of "High Bleed" 

pneumatic devices at oil wells 

COUNT BASIN_FACTORS 

PNEUMATIC_OIL_WELL_HIGH_BLEED_BLEED_RATE Bleed rate of "High Bleed" 

pneumatic devices at oil wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_GAS_WELL_INTERM_BLEED_NUM_DEV Count of "Intermittent" 

pneumatic devices at oil wells 

COUNT BASIN_FACTORS 

PNEUMATIC_OIL_WELL_INTERM_BLEED_BLEED_RATE Bleed rate of "intermittent" 

pneumatic devices at oil wells 

SCF/HR/ 

DEVICE 

BASIN_FACTORS 

PNEUMATIC_GASWELL_MW Molecular weight of the vented 

gas emitted from pneumatic 

devices at gas wells 

G/MOL BASIN_FACTORS 

PNEUMATIC_OILWELL_MW Molecular weight of the vented 

gas emitted from pneumatic 

devices at oil wells 

G/MOL BASIN_FACTORS 

PNEUMATIC_GASWELL_VOC VOC Fraction of vented gas 

being emitted from pneumatic 

devices at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GASWELL_H2S H2S Fraction of vented gas being 

emitted from pneumatic devices 

at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GASWELL_CO2 CO2 Fraction of vented gas 

being emitted from pneumatic 

devices at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GASWELL_CH4 CH4 Fraction of vented gas being 

emitted from pneumatic devices 

at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OILWELL_VOC VOC Fraction of vented gas 

being emitted from pneumatic 

devices at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OILWELL_H2S H2S Fraction of vented gas being 

emitted from pneumatic devices 

at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OILWELL_CO2 CO2 Fraction of vented gas 

being emitted from pneumatic 

devices at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OILWELL_CH4 CH4 Fraction of vented gas being 

emitted from pneumatic devices 

at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_ANNUAL_OP_HR Typical number of hours 

operated for pneumatic devices 

Hours per year BASIN_FACTORS 
December 2012 

64 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

PNEUMATIC_OIL_BENZ_VOC Benzene fraction of VOC being

emitted from pneumatic devices 

at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OIL_ETHYLBENZ_VOC Ethylbenzene fraction of VOC 

being emitted from pneumatic 

devices at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OIL_TOLUENE_VOC Toluene fraction of VOC being 

emitted from pneumatic devices 

at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OIL_XYLENE_VOC Xylene fraction of VOC being 

emitted from pneumatic devices 

at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OIL_METHANE_VOC Methane fraction of VOC being 

emitted from pneumatic devices 

at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_OIL_H2S Hydrogen sulfide fraction of VOC 

being emitted from pneumatic 

devices at oil wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GAS_BENZ_VOC Benzene fraction of VOC being

emitted from pneumatic devices 

at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GAS_ETHYLBENZ_VOC Ethylbenzene fraction of VOC 

being emitted from pneumatic 

devices at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GAS_TOLUENE_VOC Toluene fraction of VOC being 

emitted from pneumatic devices 

at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GAS_XYLENE_VOC Xylene fraction of VOC being 

emitted from pneumatic devices 

at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GAS_METHANE_VOC Methane fraction of VOC being 

emitted from pneumatic devices 

at gas wells 

Unitless BASIN_FACTORS 

PNEUMATIC_GAS_H2S Hydrogen sulfide fraction of VOC 

being emitted from pneumatic 

devices at gas wells 

Unitless BASIN_FACTORS 

6.2.8 Well Completions 

Calculation sheet: WELL_COMPLETIONS_GAS_2310121700;

WELL_COMPLETIONS_OIL_2310111700 

This category refers to emissions from well completions events, which includes initial 

completions and recompletions. Data provided in the HPDI database includes a count of annual 
December 2012 

65 

well completions (combines initial and recompletions), thus county-wide emissions will be a 

combination of the two. However, well completions characteristics will vary by well type; hence 

emissions were estimated separately for gas well completions and oil well completions. The 

calculation methodology for estimating emissions from a single completion event is shown 

below in Equation 24: 

Equation 24) 

 

907185 5.3 10 5

,

i

gas

completion

completion i

f

T MW

R

P Q

E u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧u u u

1

·

 ̈

©

§

u

 



where: 

Ecompletion,i is the uncontrolled emissions of pollutant i from a single completion event 

[ton/event] 

P is atmospheric pressure [1 atm] 

Qcompletion is the uncontrolled volume of gas generated per completion [MCF/event] 

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

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

T is the atmospheric temperature [298 K] 

fiis the mass fraction of pollutant i in the completion venting gas 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

Flaring emissions from well completion controls 

The methodology for estimating flaring emissions from completion venting processes is 

described below 

Equation 25) 

   

2000

1000 ,  ̧

 ̧

1

·

 ̈

 ̈

©

§

u

u u u u u

 county

i completion captured efficiency

flare completion S

EF Q F C C HV

E

where: 

Eflare,completion is the county-wide flaring emissions of pollutant i for well completions [ton/yr] 

EFi is the flaring emissions factor for pollutant i [lb/MMBtu] 

Qcompletion is the uncontrolled volume of gas generated per completion [MCF/event] 

HV is the local heating value of the gas [BTU/SCF] 

Scounty is the county-wide number of well completion events for a particular year [events/yr] 

F is the fraction of well completions with flares 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

2000 is the unit conversion factor lbs/ton 

1000 is the unit conversion factor MCF/MMCF 
December 2012 

66 

The methodology for estimating SO2 emissions from flaring of completion vent gas is shown 

below: 

Equation 26) 

     

907185

2

5.3 10

2 2

5

, , u u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧ u u u

1

·

 ̈

©

§

u u u u u

 



H S

gas

completion county captured efficiency

flare completion SO f

T MW

R

P Q S F C C

E

where: 

2

Eflare,completion,SO is the county-wide SO2 flaring emissions from flaring of completion vent gas 

[ton/yr] 

P is atmospheric pressure [1 atm] 

Qcompletion is the uncontrolled volume of gas generated per completion [MCF/event] 

Scounty is the county-wide number of well completion events for a particular year [events/yr] 

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

MWgas is the molecular weight of the completion venting gas [g/mol] 

T is the atmospheric temperature [298 K] 

H S

f

2

is the mass fraction of H2S in the completion venting gas 

F is the fraction of well completions with flares 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

County-wide emissions are obtained by scaling-up well completions by well type with the 

number of completions events (also by well type) for a particular year. This can be done 

applying Equation 27: 

Equation 27)

      Ecompletion,TOTAL Ecompletion,i u Scounty 1 Fflare u Ccaptured u Cefficiency  Fgreen  Eflare,completion,i

where: 

Ecompletion,TOTAL are the total emissions county-wide of pollutant i from well completions 

[tons/year] 

Ecompletion,i are the completion emissions from a single completion event [tons/event] 

Fgreen is the fraction of completions in the basin that were controlled by green completion 

techniques 

Fflare is the fraction of completions in the basin controlled by flare 
December 2012 

67 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

Scounty is the county-wide total completions events in a particular year [events/year] 

Eflare,completion,i is the county-wide flaring emissions from flaring of completion vent gas 

[ton/yr] 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units 

WORKSHEET 

TAB 

WELL_COMP_VOL_GAS_VENTED Volume of gas generated per completion MCF/EVENT BASIN_FACTORS 

WELL_COMP_FRACT_WITH_FLARING Fraction of well completions with flares Unitless BASIN_FACTORS 

WELL_COMP_FLARING_CONT_EFF Control Efficiency of the flare Unitless BASIN_FACTORS 

WELL_COMP_FLARING_CAPTURE_EFF Capture Efficiency of the flare Unitless BASIN_FACTORS 

WELL_COMP_CONT_GREEN Fraction of well completions controlled by 

green completion techniques 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_VOC_WT_PCT Fraction of VOC in the vented gas during 

completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_H2S_WT_PCT Fraction of Hydrogen sulfide in the vented 

gas during completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_CO2_WT_PCT Fraction of Carbon dioxide in the vented 

gas during completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_CH4_WT_PCT Fraction of Methane in the vented gas 

during completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_BENZ_WT_PCT Fraction of Benzene in the vented gas 

during completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_ETHYLBENZ_WT_PCT Fraction of Ethylbenzene in the vented gas 

during completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_TOLUENE_WT_PCT Fraction of Toluene in the vented gas 

during completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_XYLENE_WT_PCT Fraction of Xylene in the vented gas during 

completion at oil wells 

Unitless BASIN_FACTORS 

WELL_COMP_OIL_LHV Heating value of the vented gas during 

completion at oil wells 

BTU/SCF BASIN_FACTORS 

WELL_COMP_OIL_MW Molecular weight of the vented gas during 

completion at oil wells 

G/MOL BASIN_FACTORS 

WELL_COMP_GAS_VOC_WT_PCT Fraction of VOC in the vented gas during 

completion at gas wells 

Unitless BASIN_FACTORS 

WELL_COMP_GAS_H2S_WT_PCT Fraction of Hydrogen sulfide in the vented 

gas during completion at gas wells 

Unitless BASIN_FACTORS 

WELL_COMP_GAS_CO2_WT_PCT Fraction of Carbon dioxide in the vented 

gas during completion at gas wells 

Unitless BASIN_FACTORS 

WELL_COMP_GAS_CH4_WT_PCT Fraction of Methane in the vented gas 

during completion at gas wells 

Unitless BASIN_FACTORS 
December 2012 

68 

FIELD FIELD DESCRIPTION Units 

WORKSHEET 

TAB 

WELL_COMP_GAS_BENZ_WT_PCT Fraction of Benzene in the vented gas 

during completion at gas wells 

Unitless BASIN_FACTORS 

WELL_COMP_GAS_ETHYLBENZ_WT_PCT Fraction of Ethylbenzene in the vented gas 

during completion at gas wells 

Unitless BASIN_FACTORS 

WELL_COMP_GAS_TOLUENE_WT_PCT Fraction of Toluene in the vented gas 

during completion at gas wells 

Unitless BASIN_FACTORS 

WELL_COMP_GAS_XYLENE_WT_PCT Fraction of Xylene in the vented gas during 

completion at gas wells 

Unitless BASIN_FACTORS 

WELL_COMP_GAS_LHV Heating value of the vented gas during 

completion at gas wells 

BTU/SCF BASIN_FACTORS 

WELL_COMP_GAS_MW Molecular weight of the vented gas during 

completion at gas wells 

G/MOL BASIN_FACTORS 

6.2.9 Blowdowns 

Calculation sheet: BLOWDOWNS_2310021603 

This source category refers to the practice of venting gas from gas wells to prevent liquid buildup in the well that could limit production. This practice is also commonly referred as “liquids 

unloading”. Vented gas from blowdowns is a VOC emissions source. Emissions from 

blowdowns are based on the average venting volume per blowdown and the gas composition 

of the vented gas. Blowdown emissions may be controlled by a combustion device such as a 

flare, or may also be controlled by “smart” plunger lift devices, which decrease liquids build-up 

and thus reduce the amount of venting volume from the blowdowns. The calculation 

methodology for estimating emissions from a single blowdown event is shown below in 

Equation 28: 

Equation 28) 

 

907185 5.3 10 5

,

i

gas

vented

blowdown i

f

T MW

R

P V

E u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧u u u

1

·

 ̈

©

§

u

 



where: 

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

P is atmospheric pressure [1 atm] 

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

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

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

T is the atmospheric temperature [298 K] 

fiis the mass fraction of pollutant i in the vented gas 

3.5x10-5 is the unit conversion factor MCF/L 
December 2012 

69 

907185 is the unit conversion factor g/ton 

Emissions from flare controls for blowdown vents 

In case a region applies flaring controls to blowdown vents, the methodology for estimating 

flaring emissions is described below: 

Equation 29)

   

2000

1000 ,  ̧

 ̧

1

·

 ̈

 ̈

©

§

u u

u u u u u

 county blowdown

i vented captured efficiency

flare blowdown S N

EF V F C C HV

E

where: 

Eflare,blowdown is the county-wide flaring emissions of pollutant i for blowdowns [ton/yr] 

EFi is the flaring emissions factor for pollutant i [lb/MMBtu] 

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

HV is the local heating value of the gas [BTU/SCF] 

Scounty is the county-wide number of active gas wells for a particular year [wells] 

Nblowdown the average number of annual blowdowns per well in the basin [event/yr-well] 

F is the fraction of well blowdowns that are flared 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

1000 is the unit conversion factor MCF/MMCF 

2000 is the unit conversion factor lb/ton 

The methodology for estimating SO2 emissions from flaring of blowdown gas is shown below 

Equation 30)

     

907185

2

5.3 10

2 2

5

, , u u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧ u u u

1

·

 ̈

©

§

u u u u u u

 



H S

gas

vented county blowdown captured efficiency

flare blowdown SO f

T MW

R

P V S N F C C

E

where: 

2

Eflare,blowdown,SO is the county-wide SO2 flaring emissions from flaring of blowdown vent gas 

[ton/yr] 

P is atmospheric pressure [1 atm] 

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

Scounty is the county-wide number of gas wells [wells] 

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

MWgas is the molecular weight of the blowdown gas [g/mol] 

T is the atmospheric temperature [298 K] 

H S

f

2

is the mass fraction of H2S in the blowdown venting gas 
December 2012 

70 

F is the fraction of blowdowns with flares 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

Nblowdown the average number of annual blowdowns per well in the basin [event/yr-well] 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

The total county-level emissions from all blowdowns are evaluated following Equation 31: 

Equation 31)   Eblowdown,TOTAL Eblowdown,i u Nblowdown u Nwells u 1 Fcontrol,device uCefficiency

where: 

Eblowdown,TOTAL are the total county-wide emissions of pollutant i from blowdowns [tons/yr] 

Eblowdown,i are the blowdown emissions from a single blowdown event [tons/event] 

Fcontrol,device is the fraction of blowdowns in the basin that were controlled 

Cefficiency is the control efficiency of the control technology used (plunger lifts for example) 

Nblowdown is the average number of annual blowdowns per well in the basin [event/yr-well] 

Nwells is the total number of active gas wells in the county for a particular year [well] 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

BLOWDOWN_AVG_FREQ Average number of annual 

blowdowns per well 

EVENT/YEAR BASIN_FACTORS 

BLOWDOWN_VOL_GAS_VENTED Volume of gas generated per 

blowdown 

MCF/EVENT BASIN_FACTORS 

BLOWDOWN_FREQ_CONT_METHOD Control Technology frequently used Type BASIN_FACTORS 

BLOWDOWN_FRACT_CONTROLLED Fraction of blowdowns with control 

method 

Unitless BASIN_FACTORS 

BLOWDOWN_CONTROL_METHD_EFF Control Efficiency of the method Unitless BASIN_FACTORS 

BLOWDOWN_VOC_WT_PCT Fraction of VOC in the vented gas 

during blowdowns 

Unitless BASIN_FACTORS 

BLOWDOWN_H2S_WT_PCT Fraction of Hydrogen sulfide in the 

vented gas during blowdowns 

Unitless BASIN_FACTORS 

BLOWDOWN_CO2_WT_PCT Fraction of Carbon dioxide in the 

vented gas during blowdowns 

Unitless BASIN_FACTORS 

BLOWDOWN_CH4_WT_PCT Fraction of Methane in the vented gas 

during blowdowns 

Unitless BASIN_FACTORS 

BLOWDOWN_BENZ_WT_PCT Fraction of Benzene in the vented gas 

during blowdowns 

Unitless BASIN_FACTORS 

BLOWDOWN_ETHYLBENZ_WT_PCT Fraction of Ethylbenzene in the 

vented gas during blowdowns 

Unitless BASIN_FACTORS 

BLOWDOWN_TOLUENE_WT_PCT Fraction of Toluene in the vented gas Unitless BASIN_FACTORS 
December 2012 

71 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

during blowdowns 

BLOWDOWN_XYLENE_WT_PCT Fraction of Xylene in the vented gas 

during blowdowns 

Unitless BASIN_FACTORS 

BLOWDOWN_VENT_MW Molecular weight of the vented gas 

during blowdowns 

G/MOL BASIN_FACTORS 

6.2.10 Hydraulic Fracturing Pumps 

Calculation Sheet: HYDRAULIC_FRACTURING_2310000660 

This category refers to equipment used in hydraulic fracturing practices during well completions 

and recompletions, generally related to unconventional oil and gas production such as shale gas 

and tight sands oil/gas. Engines used during hydraulic fracturing are generally large dieselfueled pumps that can be a significant NOx emissions source. Average emissions factors for 

hydraulic fracturing engines were derived from EPA’s NONROAD2008 model based on the oil 

equipment source category bin in NONROAD. The basic methodology for estimating exhaust 

emissions from engines used at a hydraulic fracturing event is shown below 

Equation 32) 

907,185 , ,

i stages stage

fracing event i

EF HP LF N t

E n

u u u u

 u

where: 

Efracing,event is the exhaust emissions for pollutant i from a single fracing event [ton/event] 

EFi is the emissions factor of pollutant i [g/hp-hr] 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

Nstages is the number of stages per fracing event [stage/event] 

tannual is the duration of the fracturing stage [hr/stage]

n is the number of engines used per fracing event 

907185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

Frac pump emissions can be scaled up to the county level on the basis of horizontal spuds. It is 

assumed that hydraulic fracturing is performed in all horizontal spuds and thus the 

methodology for scaling up fracturing pump engine emissions is based on this surrogate as 

shown below: 

Equation 33) Efrac, pumps,TOTAL,i Nevent u Efracing ,event,i

where: 
December 2012 

72 

Efrac,pump,TOTAL is the total emissions from frac pump engines in the county [ton/yr] 

Efracing,event is the total exhaust emissions from engines in a single fracing event [ton/event] 

Nevents is the number of horizontal wells drilled in a particular year [spuds/yr] 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

HYDRAULIC_FRACTURE_HP Typical horsepower (HP) of a hydraulic 

fracture engine 

HP BASIN_FACTORS 

HYDRAULIC_FRACTURE_LOAD_FACTOR Typical load factor of a hydraulic 

fracture engine 

Unitless BASIN_FACTORS 

HYDRAULIC_FRACTURE_STAGES_WELL Number of stages per fracturing event COUNT BASIN_FACTORS 

HYDRAULIC_FRACTURE_HR_STAGE Typical duration of the fracturing 

stage 

Hours per 

stage 

BASIN_FACTORS 

HYDRAULIC_FRACTURE_TOTAL_DURATIO

N 

Total number of hours for fracturing Hours per 

year 

BASIN_FACTORS 

HYDRAULIC_FRACTURE_ENGINES_EVENT Number of fracturing engines used 

per fracturing event 

COUNT BASIN_FACTORS 

HYDRAULIC_FRACTURE_HP-HR_WELL Total horsepower-hour from hydraulic 

fracturing per well 

HPHR/WELL BASIN_FACTORS 

HYDRAULIC_FRACTURE_ALT_EF Alternative value, if available, for 

hydraulic fracturing 

G/HP-HR BASIN_FACTORS 

6.2.11 Fugitive Leaks 

Calculation Sheets: FUGITIVE_GAS_CON_2310021501; FUGITIVE_GAS_FLANGES_2310021502; 

FUGITIVE_GAS_OEL_2310021503; FUGITIVE_GAS_VALVES_2310021505; 

FUGITIVE_GAS_COMSEAL_2310021506; FUGITIVE_OIL_CON_2310021501; 

FUGITIVE_OIL_FLANGES_2310021502; FUGITIVE_OIL_OEL_2310021503; 

FUGITIVE_OIL_VALVES_2310021505; 

This source category refers to leaking emissions of produced gas that escape through well site 

and pipeline components such as connectors, flanges, open-ended lines and valves. As a 

revision to the CENRAP study (Bar-Ilan, et al., 2008), compressor wet seals fugitive emissions 

have been added to this inventory. It must be noted that this source category refers only to 

fugitive emissions components located at the wellhead and that large transmission pipeline 

fugitives and other midstream fugitives sources are not part of this analysis. 

Fugitive emissions for an individual typical well are estimated according to Equation 34: 

Equation 34) ¦ u u u

i

fugitive j i i annual Yj E EF N t

,

where: 

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

EFi is the emission factor of TOC for a single component i [kg/hr/component] 
December 2012 

73 

Ni is the total number of components of type i

tannual is the annual number of hours the well is in operation [8760 hr/yr] 

Yj is the mass ratio of pollutant j to TOC in the vented gas 

In addition, fugitive leaks from wellhead compressor seals can be estimated from the following 

equation 

Equation 35) 

   

gas

wellhead lateral

gas

vented

compressor fug CH W

f N

T MW

R

P V t

E u



u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧ u u u u

1

·

 ̈

©

§

u u

 

 907185 *1000

/1

5.3 10 24 5

, , 4

where: 

Ecompressor,fug,CH4 is the county-wide methane fugitive emissions from compressor seals 

[ton/yr] 

P is atmospheric pressure [1 atm] 

Vvented is the volume of leaked gas per compressor [SCF/compressor/day] 

t is the annual hours of operation for wellhead compressors [hrs/yr] 

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

MWgas is the molecular weight of the pollutant [g/mol] 

T is the atmospheric temperature [298 K] 

fwellhead is the fraction of wells with wellhead compressors 

Nlateral is the number of gas wells served by a lateral compressor engine 

Wgas is the county-wide number of gas wells 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

1000 is the unit conversion factor SCF/MCF 

24 is the unit conversion factor hr/day 

To estimate emissions from other pollutants (VOC, CO2, H2S) the following equation may be 

used: 

Equation 36) 

4 4

, , , 4

CH

i

CH

i

compressor fug i compressorfug M

M

MW

MW E E CH

 u u

where: 

E compressor,fug,i is the county-wide compressor fugitive emissions for pollutant i [ton/yr] 

EF compressor,fug,CH4 is the compressor fugitive emissions for methane [ton CH4/yr] 

MWi is the molecular weight of pollutant i [lb/lb-mol]

MWCH4 is the molecular weight of methane [lb/lb-mol] 

MCH4 is the mole percent of methane in the local gas [%] 

Mi is the mole percent of pollutant in the local gas [%] 
December 2012 

74 

Extrapolation to county-level emissions 

County-wide fugitive emissions from well-site piping components are estimated according to 

Equation 37 

Equation 37) Efugitive,TOTAL Efugitive, j u Nwell

where: 

Efugitive,TOTAL is the total fugitive emissions from well-site piping components in the county 

[ton/yr] 

Efugitive,j is the fugitive emissions for a single well of pollutant j [ton/yr/well] (from Equation 

35) 

Nwell is the total number of active wells in the county [wells] 

Total county-wide fugitive emissions are the sum of compressor seals emissions and bycomponent fugitive emissions. 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

FUG_VALVES_GAS Count of valves per gas service COUNT BASIN_FACTORS 

FUG_VALVES_HO Count of valves per heavy oil service COUNT BASIN_FACTORS 

FUG_VALVES_LO Count of valves per light oil service COUNT BASIN_FACTORS 

FUG_VALVES_WO Count of valves per water/oil service COUNT BASIN_FACTORS 

FUG_PUMP_SEALS_GAS Count of pump seals per gas service COUNT BASIN_FACTORS 

FUG_PUMP_SEALS_HO Count of pump seals per heavy oil 

service 

COUNT BASIN_FACTORS 

FUG_PUMP_SEALS_LO Count of pump seals per light oil 

service 

COUNT BASIN_FACTORS 

FUG_PUMP_SEALS_WO Count of pump seals per water/oil 

service 

COUNT BASIN_FACTORS 

FUG_OTHERS_GAS Count of compressor seals per gas 

service 

COUNT BASIN_FACTORS 

FUG_OTHERS_HO Count of compressor seals per heavy 

oil service 

COUNT BASIN_FACTORS 

FUG_OTHERS_LO Count of compressor seals per light oil 

service 

COUNT BASIN_FACTORS 

FUG_OTHERS_WO Count of compressor seals per 

water/oil service 

COUNT BASIN_FACTORS 

FUG_CONN_GAS Count of connectors per gas service COUNT BASIN_FACTORS 

FUG_CONN_HO Count of connectors per heavy oil 

service 

COUNT BASIN_FACTORS 

FUG_CONN_LO Count of connectors per light oil 

service 

COUNT BASIN_FACTORS 
December 2012 

75 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

FUG_CONN_WO Count of connectors per water/oil 

service 

COUNT BASIN_FACTORS 

FUG_FLANGES_GAS Count of flanges per gas service COUNT BASIN_FACTORS 

FUG_FLANGES_HO Count of flanges per heavy oil service COUNT BASIN_FACTORS 

FUG_FLANGES_LO Count of flanges per light oil service COUNT BASIN_FACTORS 

FUG_FLANGES_WO Count of flanges per water/oil service COUNT BASIN_FACTORS 

FUG_OEL_GAS Count of open-ended lines per gas 

service 

COUNT BASIN_FACTORS 

FUG_OEL_HO Count of open-ended lines per heavy 

oil service 

COUNT BASIN_FACTORS 

FUG_OEL_LO Count of open-ended lines per light oil 

service 

COUNT BASIN_FACTORS 

FUG_OEL_WO Count of open-ended lines per 

water/oil service 

COUNT BASIN_FACTORS 

FUG_ANNUAL_HRS Annual operating hours for fugitive 

components 

Hours per year BASIN_FACTORS 

FUG_GW_VOC_TOC Fraction of VOC in Total organic 

compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_GW_H2S_TOC Fraction of Hydrogen sulfide in Total 

organic compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_GW_CO2_TOC Fraction of Carbon dioxide in Total 

organic compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_GW_CH4_TOC Fraction of Methane dioxide in Total 

organic compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_GW_BENZ_TOC Fraction of Benzene dioxide in Total 

organic compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_GW_ETHYLBENZ_TOC Fraction of Ethylbenzene dioxide in 

Total organic compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_GW_TOLUENE_TOC Fraction of Toluene dioxide in Total 

organic compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_GW_XYLENE_TOC Fraction of Xylene dioxide in Total 

organic compounds at gas wells 

Unitless BASIN_FACTORS 

FUG_OW_VOC_TOC Fraction of VOC in Total organic 

compounds at oil wells 

Unitless BASIN_FACTORS 

FUG_OW_H2S_TOC Fraction of Hydrogen sulfide in Total 

organic compounds at oil wells 

Unitless BASIN_FACTORS 

FUG_OW_CO2_TOC Fraction of Carbon dioxide in Total 

organic compounds at oil wells 

Unitless BASIN_FACTORS 

FUG_OW_CH4_TOC Fraction of Methane in Total organic 

compounds at oil wells 

Unitless BASIN_FACTORS 

FUG_OW_BENZ_TOC Fraction of Benzene in Total organic 

compounds at oil wells 

Unitless BASIN_FACTORS 
December 2012 

76 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

FUG_OW_ETHYLBENZ_TOC Fraction of Ethylbenzene in Total 

organic compounds at oil wells 

Unitless BASIN_FACTORS 

FUG_OW_TOLUENE_TOC Fraction of Toluene in Total organic 

compounds at oil wells 

Unitless BASIN_FACTORS 

FUG_OW_XYLENE_TOC Fraction of Xylene in Total organic 

compounds at oil wells 

Unitless BASIN_FACTORS 

FUG_COMP_SEAL_CH4_LEAKING Methane leaking rate per compressor 

daily 

SCF/HR/ 

COMPRESSOR 

BASIN_FACTORS 

FRACT_WELL_COMPRESS Fraction of wells serviced by wellhead 

compressors 

Unitless BASIN_FACTORS 

NUM_WELL_COMPRESS Number of wells serviced by a single 

lateral compressor 

COUNT BASIN_FACTORS 

FUG_COMP_SEAL_HOURS_OP Annual operating hours for 

compressors 

Hours per year BASIN_FACTORS 

FUG_GAS_LHV Heating value of the leaked gas at 

compressor seals 

BTU/SCF BASIN_FACTORS 

FUG_GAS_MW Molecular weight of the leaked gas at 

compressor seals 

G/MOL BASIN_FACTORS 

FUG_GAS_VOC_WT_FRACT VOC fraction in leaked gas at 

compressor seals 

Unitless BASIN_FACTORS 

FUG_GAS_H2S_WT_FRACT Hydrogen sulfide fraction in leaked gas 

at compressor seals 

Unitless BASIN_FACTORS 

FUG_GAS_CO2_WT_FRACT Carbon dioxide fraction in leaked gas at 

compressor seals 

Unitless BASIN_FACTORS 

FUG_GAS_CH4_WT_FRACT Methane fraction in leaked gas at 

compressor seals 

Unitless BASIN_FACTORS 

FUG_GAS_BENZ_WT_FRACT Benzene fraction in leaked gas at 

compressor seals 

Unitless BASIN_FACTORS 

FUG_GAS_ETHYLBENZ_WT_FRACT Ethylbenzene fraction in leaked gas at 

compressor seals 

Unitless BASIN_FACTORS 

FUG_GAS_TOLUENE_WT_FRACT Toluene fraction in leaked gas at 

compressor seals 

Unitless BASIN_FACTORS 

FUG_GAS_XYLENE_WT_FRACT Xylene fraction in leaked gas at 

compressor seals 

Unitless BASIN_FACTORS 

VOC_MOL_PCT VOC molar PCT Value Unitless BASIN_FACTORS 

CO2_MOL_PCT Carbon dioxide molar PCT Value Unitless BASIN_FACTORS 

CH4_MOL_PCT Methane molar PCT Value Unitless BASIN_FACTORS 

H2S_MOL_PCT Hydrogen sulfide molar PCT Value Unitless BASIN_FACTORS 

VOC_MOL_WT Molecular weight of VOC G/MOL BASIN_FACTORS
December 2012 

77 

6.2.12 Heaters 

Calculation sheets: HEATERS_OIL_2310010100; HEATERS_GAS_2310021100 

This category refers to natural gas-fired external combustors used in oil and gas production 

facilities to provide heat input to separator (separator heaters) or to provide heat to tanks (tank 

heaters). It must be noted that this category does not refer to reboilers used in dehydrators as 

those emissions are captured in the dehydrator source category. The basic methodology for 

estimating emissions for all pollutants except SO2 for a single heater is shown in Equation 38. 

Local fuel gas properties will vary between gas wells and oil wells; hence emissions were 

estimated separately for this category. Due to limited field data for this category, all other 

parameters unrelated to local gas composition were assumed to be the same for gas and oil 

wells. 

Equation 38)   u 2000

u u u

 

local

heater heater annual

heater HV

EF Q t hc

E

where: 

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

EFheater is the emission factor for a heater for a given pollutant [lb/million SCF] 

Qheater is the heater MMBTU/hr rating [MMBTUrated/hr] 

HVlocal is the local natural gas heating value [BTUlocal/SCF] 

tannual is the annual hours of operation [hr/yr] 

hc is a heater cycling fraction to account for the fraction of operating hours that the heater 

is firing (if not available, hc=1) 

2000 is the unit conversion factor lb/ton 

The methodology for estimating SO2 emissions from heaters requires first estimating the mass 

of gas combusted in the heater, and then uses the mass fraction of H2S in the gas and the 

assumption that all H2S is converted to SO2. This methodology is described in Equation 39 

Equation 39)  

 ̧

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

 ̈

©

§

 ̧

 ̧

1

·

 ̈

 ̈

©

§

 ̧u u

1

·

 ̈

©

§

u

u u

u

u

 

.0 035

907185

2

2

2

,

T MW

R

P

HV

f Q t hc

E

gas

local

H S heater annual

heater SO

where: 

2

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

2 SO f is the mass fraction of H2S in the gas 

Qheater is the heater MMBTU/hr rating [MMBTUrated/hr] 

HVlocal is the local natural gas heating value [MMBTUlocal/scf] 

tannual is the annual hours of operation [hr/yr] 
December 2012 

78 

hc is a heater cycling fraction to account for the fraction of operating hours that the heater 

is firing 

P is atmospheric pressure [1 atm] 

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

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

3.5x10-3 is the unit conversion factor SCF/L 

907185 is the unit conversion factor g/ton 

1000 is the unit conversion factor SCF/MCF 

Extrapolation to county-level emissions 

County-wide heater emissions are estimated by determining the typical number of heaters per 

well and scaling up by well count. This is shown in Equation 40: 

Equation 40) Eheater,TOTAL Eheater u Nheater uWTOTAL

where: 

Eheater,TOTAL is the total heater emissions in a county for a specific pollutant [ton/yr] 

Eheater is the total emissions from a single heater for a specific pollutant [ton/yr] 

WTOTAL is the total number of wells in the county 

Nheater is the typical number of heaters per well throughout in the basin 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

NUM_HEATERS_TYPICAL Typical number of heaters at a well COUNT BASIN_FACTORS 

HEATER_RATING Heater rating MMBTU/HR BASIN_FACTORS 

HEATER_ANNUAL_OP_HOURS Typical number of hours operated for 

heaters 

Hours per year BASIN_FACTORS 

HEATER_CYCLING Fraction to account for the fraction of 

operating hours that the heater is firing 

Unitless BASIN_FACTORS 

HEATER_GASWELL_H2S_FRAC Fraction of hydrogen sulfide in the 

natural gas 

Unitless BASIN_FACTORS 

HEATER_GASWELL_LOCAL_HV Heating value of the natural gas used for 

fuel 

BTU/SCF BASIN_FACTORS 

HEATER_GASWELL_MW Molecular weight of the gas emitted

from the gas well heater 

G/MOL BASIN_FACTORS 

HEATER_OILWELL_H2S_FRAC Fraction of hydrogen sulfide in the oil Unitless BASIN_FACTORS 

HEATER_OILWELL_LOCAL_HV Heating value of the oil used for fuel BTU/SCF BASIN_FACTORS 

HEATER_OILWELL_MW Molecular weight of the gas emitted

from the oil well heater 

G/MOL BASIN_FACTORS 

 
December 2012 

79 

6.2.13 Loading Emissions 

Calculation Sheets: LOADING_COND_2310021030; LOADING_CRUDE_2310011201 

This category refers to loading losses that occur when transferring hydrocarbon liquids, crude 

oil or condensate, from storage tanks to cargo trucks. The emissions will vary by the gas 

speciation of the working losses; hence emissions were calculated separately for each 

hydrocarbon liquid. Equations 41-44 may be used for both categories (SCCs). The loading loss 

rate is estimated following Equation 41: 

Equation 41)  ̧

1

·

 ̈

©

§

u

u u

 u

1000

12 46.

T

S V M

L

where: 

L is the loading loss rate [lb/1000gal] 

S is the saturation factor taken from AP-42 default values based on operating mode (here 

assumed as submerged loading: dedicated normal service) 

V is the true vapor pressure of the liquid loaded [psia] 

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

T is the temperature of the bulk liquid [oR] 

VOC truck loading emissions are then estimated by Equation 42 which is dependent on the VOC 

fraction in the gas. When available, basin-specific working/breathing gas compositions from 

condensate/crude oil storage tanks were used in Equations 42-44; however when basin-level 

data was limited or unavailable, produced gas analyses were used to speciate emissions from 

each pollutant. 

Equation 42) ܧ௔௢௟ௗ௜௡௚, ௏ை஼ =

௅

ଵ଴଴଴

 × ܻ௩௢௖ ×

ସଶ

ଶ଴଴଴

where: 

Eloading are the VOC tank loading emissions [ton-VOC/bbl] 

L is the loading loss rate [lb/1000gal] 

YVOC is the weight fraction of VOC in the vapor in the liquid loaded 

42 is a unit conversion [gal/bbl] 

2000 is a unit conversion [lbs/ton] 

CO2 and CH4 emissions are calculated based on Equations 43-44:

Equation 43) ܧ௔௢௟ௗ௜௡௚,஼ுସ = ܧ௔௢௟ௗ௜௡௚,௏ை஼ ×

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡಴ಹర

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡ೇೀ಴

Equation 44) ܧ௔௢௟ௗ௜௡௚,஼ைଶ = ܧ௔௢௟ௗ௜௡௚,௏ை஼ ×

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡಴ೀమ

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡ೇೀ಴

where: 

Eloading,CO2 is the total loading CO2 emissions per barrel of liquid [ton/bbl] 
December 2012 

80 

E loadingCH4 is the total loading CH4 emissions per barrel of liquid [ton/bbl] 

Weight fractions of each pollutant in the vapor losses from the liquid loaded 

Extrapolation to county-level emissions 

Annual emissions per pollutant i from condensate loading were scaled to county-level by annual 

condensate production per Equation 45: 

Equation 45) ܧ௧௔௡௞ ௟௢௔ௗ௢௨௧, ௜ = ܧ௔௢௟ௗ௜௡௚, ௜ × ܵ௕௕௟ ௖௢௡ௗ௘௡௦௔௧௘ × ܨ௧௥௨௖௞௘ௗ

where: 

Etank loadout, i is the annual county-level emissions for pollutant i from condensate tank loadout [ton/yr] 

Eloading, i is the emissions for pollutant i from loading per barrel [ton/bbl] 

Sbbl condensate is the total annual of barrels condensate produced county-wide [bbl/yr] 

Fpipeline is the fraction of condensate production that is delivered by truck 

Annual emissions per pollutant i from oil loading were scaled to county-level by annual oil 

production per Equation 46: 

Equation 46) ܧ௧௔௡௞ ௟௢௔ௗ௢௨௧,௢௜௟, ௜ = ܧ௔௢௟ௗ௜௡௚, ௜ × ܵ௕௕௟ ௢௜௟ × ܨ௧௥௨௖௞௘ௗ

where: 

Etank loadout, i is the annual county-level emissions for pollutant i from crude oil tank load-out 

[ton/yr] 

Eloading, i is the emissions for pollutant i from loading per barrel [ton/bbl] 

Sbbl oil is the total annual oil produced county-wide [bbl/yr] 

Fpipeline is the fraction of oil production that is delivered by truck 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

LOADING_OP_MODE Typical operating mode for liquids loading TYPE BASIN_FACTORS 

LOADING_SAT_FAC Saturation factor based on operating 

mode 

Unitless BASIN_FACTORS 

LOADING_FRAC_COND_TRUCK Fraction of condensate loading to trucks Unitless BASIN_FACTORS 

LOADING_FRAC_CRUDE_TRUCK Fraction of crude oil loading to trucks Unitless BASIN_FACTORS 

LOADING_COND_BULK_LIQ_T Temperature of the bulk condensate R BASIN_FACTORS 

LOADING_COND_VOC_WT_PCT Fraction of VOC in the vapor of loaded 

condensate 

Unitless BASIN_FACTORS 

LOADING_COND_CO2_WT_PCT Fraction of Carbon dioxide in the vapor of 

loaded condensate 

Unitless BASIN_FACTORS 

LOADING_COND_CH4_WT_PCT Fraction of Methane in the vapor of 

loaded condensate 

Unitless BASIN_FACTORS 

LOADING_COND_MW_VAPOR Molecular weight of condensate vapor G/MOL BASIN_FACTORS 
December 2012 

81 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

LOADING_COND_PRESS_VAPOR True vapor pressure of the condensate PSIA BASIN_FACTORS 

LOADING_OIL_BULK_LIQ_T Temperature of the bulk crude oil R BASIN_FACTORS 

LOADING_OIL_VOC_WT_PCT Fraction of VOC in the vapor of loaded 

crude oil 

Unitless BASIN_FACTORS 

LOADING_OIL_CO2_WT_PCT Fraction of Carbon dioxide in the vapor of 

loaded crude oil 

Unitless BASIN_FACTORS 

LOADING_OIL_CH4_WT_PCT Fraction of Methane in the vapor of 

loaded crude oil 

Unitless BASIN_FACTORS 

LOADING_OIL_MW_VAPOR Molecular weight of crude oil vapor G/MOL BASIN_FACTORS 

LOADING_OIL_PRESS_VAPOR True vapor pressure of the crude oil PSIA BASIN_FACTORS 

LOADING_COND_BENZ_VOC Benzene ratio to VOC being emitted 

during condensate loading 

Unitless BASIN_FACTORS 

LOADING_COND_ETHYLBENZ_VOC Ethylbenzene ratio to VOC being emitted 

during condensate loading 

Unitless BASIN_FACTORS 

LOADING_COND_TOLUENE_VOC Toluene ratio to VOC being emitted during 

condensate loading 

Unitless BASIN_FACTORS 

LOADING_COND_XYLENE_VOC Xylene ratio to VOC being emitted during 

condensate loading 

Unitless BASIN_FACTORS 

LOADING_COND_METHANE_VOC Methane ratio to VOC being emitted 

during condensate loading 

Unitless BASIN_FACTORS 

LOADING_COND_H2S_VOC Hydrogen sulfide ratio to VOC being 

emitted during condensate loading 

Unitless BASIN_FACTORS 

LOADING_CRUDE_BENZ_VOC Benzene ratio to VOC being emitted 

during crude oil loading 

Unitless BASIN_FACTORS 

LOADING_CRUDE_ETHYLBENZ_VOC Ethylbenzene ratio to VOC being emitted 

during crude oil loading 

Unitless BASIN_FACTORS 

LOADING_CRUDE_TOLUENE_VOC Toluene ratio to VOC being emitted during 

crude oil loading 

Unitless BASIN_FACTORS 

LOADING_CRUDE_XYLENE_VOC Xylene ratio to VOC being emitted during 

crude oil loading 

Unitless BASIN_FACTORS 

LOADING_CRUDE_METHANE_VOC Methane ratio to VOC being emitted 

during crude oil loading 

Unitless BASIN_FACTORS 

LOADING_CRUDE_H2S_VOC Hydrogen sulfide ratio to VOC being 

emitted during crude oil loading 

Unitless BASIN_FACTORS 

6.2.14 Gas-Actuated Pumps 

Calculation sheets: GAS_ACT_GAS_2310121401; GAS_ACT_OIL_2310111401. 

Gas-actuated pumps refer to small gas-driven plunger pumps used at oil and gas production 

sites, to provide a constant supply of chemicals or lubricants to specific flow lines or equipment. 

These are regularly used in sites where electric power is unavailable. As part of their operation, 

gas-driven pumps vent part of the driving gas to the atmosphere, making them a VOC and 
December 2012 

82 

methane emissions source. Two types of gas-actuated pumps were considered: Kimray pumps 

and chemical injection pumps (CIP). For oil wells only CIPs are assumed to be used. Annual 

vented gas rates per well from Kimray pumps are estimated following Equation 47: 

Equation 47) 

 ̧

 ̧

1

·

 ̈

 ̈

©

§

 ̧u u u

1

·

 ̈

©

§

u

 u u

5

4

, 4

1000 5.3 10

907185

T MW

R

P

Q

EF

E

gas

kimray

CH

kimray CH

where: 

Ekimray,CH4 is the per-well methane emissions from Kimray pumps at gas wells [tons-CH4/wellyr] 

EFCH4 is the methane emissions factor for a Kimray pump per unit throughput [SCFCH4/MMSCF] 

Qkimray is the average gas pumped per well annually with Kimray pumps [MMSCF/well-yr] 

P is the atmospheric pressure [1 atm] 

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

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

T is the atmospheric temperature [298 K] 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

1000 is the unit conversion factor SCF/MCF 

Emissions from CIPs are estimated based on equation 48: 

Equation 48) 

 ̧

1

·

 ̈

©

§

 ̧ u u u

1

·

 ̈

©

§

u

 u u u

5

4

, 4

1000 5.3 10 907185 24 T MW

R

t P

N

EF

E

methane

CIP

CIP

CH

CIP CH

where: 

ECIP,CH4 is the per-well methane emissions from CIP pumps at gas wells [tons-CH4/well-yr] 

EFCH4 is the methane emissions factor for a CIP pump [SCF-CH4/pump/day] 

NCIP is the average number of CIPs per well [pump/well] 

tCIP is the regular operation time for chemical injection pumps [hrs/yr] 

P is the atmospheric pressure [1 atm] 

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

MWmethane is the molecular weight of methane [g/mol] 

T is the atmospheric temperature [298 K] 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

1000 is the unit conversion factor SCF/MCF 
December 2012 

83 

To estimate emissions from other pollutants (VOC, CO2, H2S, HAPs) from Kimray and CIP 

pumps, the following equation may be used: 

Equation 49) 

4 4

, 4

CH

i

CH

i

pump i pump M

M

MW

MW E E CH

 u u

where: 

E pump,i is the emissions for pollutant i per well from CIPs or Kimray Pumps [ton/well-yr] 

EFpump,CH4 is the methane emissions from CIPs or Kimray Pumps [ton CH4/well-yr] (from 

equations 47 or 48) 

MWi is the molecular weight of pollutant i [lb/lb-mol]

MWCH4 is the molecular weight of methane [lb/lb-mol] 

MCH4 is the mole percent of methane in the local gas vented from the pump [%] 

Mi is the mole percent of pollutant in the local gas vented from the pump [%] 

Extrapolation to county-level emissions 

To estimate county-wide annual emissions from gas-actuated pumps for each pollutant, the 

scaling surrogate used is well counts, according to equation 50: 

Equation 50) 

ܧீ௉஺, = ௜ ൣ)ܧ஼ூ௉, ௜ + ܧ௔௥௠௜௞௬,௜) × ܵ௪௘௟௟ ௖௢௨௡௧൧

௚௔௦ ௪௘௟௟௦

௜ ,௉ூ஼ܧൣ +

 × ܵ௪௘௟௟ ௖௢௨௡௧൧

௢௜௟ ௪௘௟௟௦ 

where: 

EGAP, i is the annual county-wide emissions for pollutant i from gas-actuated pumps [ton/yr] 

Ekimray, i is the emissions from kimray pumps per well type (gas or oil) [ton/yr-well] 

ECIP, i is the emissions from chemical injection pumps per well type (gas or oil) [ton/yr-well] 

Swell count is the number of active wells (gas or oil) in a particular county [wells] 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units 

WORKSHEET 

TAB 

ACT_GAS_KIM_CH4_VENT_RATE Methane vent rate for gas wells 

using Kimray pumps 

SCF/MMSCF BASIN_FACTORS 

ACT_GAS_KIM_AVG_GAS_PUMPED_WELL_YR Average gas pumped per well 

annually with Kimray pumps per 

unit throughput 

MMSCF/WELL/YR BASIN_FACTORS 

ACT_GAS_CIP_CH4_VENT_RATE Methane vent rate for gas wells 

using CIP pumps 

SCF/MMSCF BASIN_FACTORS 

ACT_GAS_CIP_HRS_OP Average gas pumped per gas well 

annually with CIP pumps per unit 

throughput 

MMSCF/WELL/YR BASIN_FACTORS 
December 2012 

84 

FIELD FIELD DESCRIPTION Units 

WORKSHEET 

TAB 

ACT_GAS_CIP_AVG_NUM_PUMP_WELL Average number of CIP pumps per 

gas well 

COUNT/WELL BASIN_FACTORS 

ACT_OIL_CIP_CH4_VENT_RATE Methane vent rate for oil wells 

using CIP pumps 

SCF/MMSCF BASIN_FACTORS 

ACT_OIL_CIP_HRS_OP Average gas pumped per oil well 

annually with CIP pumps per unit 

throughput 

MMSCF/WELL/YR BASIN_FACTORS 

ACT_OIL_CIP_AVG_NUM_PUMP_WELL Average number of CIP pumps per 

oil well 

COUNT/WELL BASIN_FACTORS 

ACT_GAS_MW_GAS Molecular weight of the gas emitted 

by gas-actuated pumps at gas wells 

G/MOL BASIN_FACTORS 

ACT_GAS_MOL_PCT_VOC VOC fraction of gas emitted by gasactuated pumps at gas wells Unitless BASIN_FACTORS 

ACT_GAS_MOL_PCT_H2S Hydrogen sulfide fraction of gas

emitted by gas-actuated pumps at 

gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_MOL_PCT_CO2 Carbon dioxide fraction of gas 

emitted by gas-actuated pumps at 

gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_MOL_PCT_CH4 Methane fraction of gas emitted by 

gas-actuated pumps at gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_VOC_MW Molecular weight of the VOC 

emitted by gas-actuated pumps at 

gas wells 

G/MOL BASIN_FACTORS 

ACT_OIL_MW_GAS Molecular weight of the gas emitted 

by gas-actuated pumps at gas wells 

G/MOL BASIN_FACTORS 

ACT_OIL_MOL_PCT_VOC VOC fraction of gas emitted by gasactuated pumps at oil wells Unitless BASIN_FACTORS 

ACT_OIL_MOL_PCT_H2S Hydrogen sulfide fraction of gas

emitted by gas-actuated pumps at 

oil wells 

Unitless BASIN_FACTORS 

ACT_OIL_MOL_PCT_CO2 Carbon dioxide fraction of gas 

emitted by gas-actuated pumps at 

oil wells 

Unitless BASIN_FACTORS 

ACT_OIL_MOL_PCT_CH4 Methane fraction of gas emitted by 

gas-actuated pumps at oil wells 

Unitless BASIN_FACTORS 

ACT_OIL_VOC_MW Molecular weight of the VOC 

emitted by gas-actuated pumps at 

oil wells 

G/MOL BASIN_FACTORS 

ACT_OIL_BENZ_VOC Benzene ratio to VOC being emitted

by gas-actuated pumps at oil wells 

Unitless BASIN_FACTORS 
December 2012 

85 

FIELD FIELD DESCRIPTION Units 

WORKSHEET 

TAB 

ACT_OIL_ETHYLBENZ_VOC Ethylbenzene ratio to VOC being 

emitted by gas-actuated pumps at 

oil wells 

Unitless BASIN_FACTORS 

ACT_OIL_TOLUENE_VOC Toluene ratio to VOC being emitted 

by gas-actuated pumps at oil wells 

Unitless BASIN_FACTORS 

ACT_OIL_XYLENE_VOC Xylene ratio to VOC being emitted 

by gas-actuated pumps at oil wells 

Unitless BASIN_FACTORS 

ACT_OIL_METHANE_VOC Methane ratio to VOC being 

emitted by gas-actuated pumps at 

oil wells 

Unitless BASIN_FACTORS 

ACT_OIL_H2S Hydrogen sulfide ratio to VOC being 

emitted by gas-actuated pumps at 

oil wells 

Unitless BASIN_FACTORS 

ACT_GAS_BENZ_VOC Benzene ratio to VOC being emitted

by gas-actuated pumps at gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_ETHYLBENZ_VOC Ethylbenzene ratio to VOC being 

emitted by gas-actuated pumps at 

gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_TOLUENE_VOC Toluene ratio to VOC being emitted 

by gas-actuated pumps at gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_XYLENE_VOC Xylene ratio to VOC being emitted 

by gas-actuated pumps at gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_METHANE_VOC Methane ratio to VOC being 

emitted by gas-actuated pumps at 

gas wells 

Unitless BASIN_FACTORS 

ACT_GAS_H2S Hydrogen sulfide ratio to VOC being 

emitted by gas-actuated pumps at 

gas wells 

Unitless BASIN_FACTORS 

6.2.15 Mud Degassing 

Calculation Sheets: MUD_DEG_GAS_2310121100; MUD_DEG_OIL_2310111100 

Drilling mud degassing refers to the practice of extracting the entrained gas from the drilling 

mud once it is outside of the wellbore. During this process VOCs and methane (and other 

pollutants in the gas) are vented to the atmosphere. National default emissions factors for mud 

degassing are available from The Climate Registry Reporting Protocol: 
December 2012 

86 

Table 6-2. National default emissions factors for mud degassing by mud base. 

Emission Source Emission Factor Units7 Emission Factor Units8 

Mud degassing – water-based 

mud 

881.84 lbs THC / drilling day 0.2605 tonnes CH4/ drilling day 

Mud degassing – oil-based mud 198.41 lbs THC / drilling day 0.0586 tonnes CH4/ drilling day 

Mud degassing – synthetic mud 198.41 lbs THC / drilling day 0.0586 tonnes CH4/ drilling day 

Water-based mud emissions factors were assumed as a default conservative value, but this 

parameter may be updated in the tool by the User with other factors in Table 6-2 or any basinspecific factor that may be available. This can be done in the EMISSIONS_FACTOR tab of the 

tool. To account for the use of different mud bases within a region, the methane emissions 

factor may be estimated as a weighted average based on a usage fraction of each mud type 

within a basin. 

Applying the local-gas methane mass fraction to the mud degassing emission factors provides 

the site-representative emissions as shown in equation 51. Because the mud entrained gas is 

the gas coming out directly from the wellbore during drilling, produced gas compositions by 

well type are used to characterize these emissions. Equations 51-52 are applicable to both oil 

and gas wells mud degassing emissions, however gas compositions and surrogate values 

(spuds) will vary for each well type. 

Equation 51) 83 85.

.1 102 4

, , 4 , 4

CH

mud vent CH drill mud CH

M

E N u EF u u

where: 

E mud,vent,CH4 is the mud degassing emissions for methane per spud [ton/spud] 

EFmud,CH4 is the emissions factor for methane [ton CH4/drilling days] 

Ndrill is the number of drilling days per spud [drilling days/spud] 

83.85 is the mole percent of methane from the vented gas used to derive the emissions 

factor (EF) 

MCH4 is the mole percent of methane in the local gas vented during mud degassing [%] (if 

basin-specific methane emissions factor is used, M=83.85) 

1.102 is the conversion of tonnes to short tons 

To estimate emissions from other pollutants in the vented gas Equation 52 may be used: 

 

7

 Wilson, Darcy, Richard Billings, Regi Oommen, and Roger Chang, Eastern Research Group, Inc. Year 2005 Gulfwide 

Emission Inventory Study, U.S. Department of the Interior, Minerals Management Services, Gulf of Mexico OCS 

Region, New Orleans, December 2007, Section 5.2.10.

8

 Based on gas content of 65.13 weight percent CH4, derived from sample data provided in the original source of 

the emission factors. Original sample data is as follows, in terms of mole%: 83.85% CH4, 5.41% C2H6, 6.12% C3H8, 

3.21% C4H10, and 1.40% C5H12 (Wilson et al., 2007) 
December 2012 

87 

Equation 52) 

4 4

, , , 4

CH

i

CH

i

mud vent i mud vent M

M

MW

MW E E CH

 u u

where: 

E mud,vent,i is the mud degassing emissions for pollutant i per spud [ton/spud] 

EFmud,ven6,CH4 is the vented emissions for methane [ton CH4/spud] 

MWi is the molecular weight of pollutant i [lb/lb-mol]

MWCH4 is the molecular weight of methane [lb/lb-mol] 

MCH4 is the mole percent of methane in the local gas vented during mud degassing [%] 

Mi is the mole percent of pollutant in the local gas vented during mud degassing [%] 

Extrapolation to county-level emissions 

To estimate county-wide annual emissions, mud degassing emissions by spud are scaled with 

the county-wide count of drilling events (spuds), according to Equation 53: 

Equation 53) ܧ௠௨ௗ,௩௘௡௧,்ை்஺௅ ௜ = ܧ௠௨ௗ,௩௘௡௧, ௜ × ܵ௦௣௨ௗ௦

where: 

Emud,vent,TOTAL,i is the annual county-wide emissions for pollutant i from mud degassing 

[ton/yr] 

Emud,vent, i is the emissions from mud degassing from a drilling event [ton/spud] 

Sspuds is the number of wells drilled in a county for a particular year [spud/yr] 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

MUD_AVG_DRILL_DAYS_SPUD Average number of drilling days per 

spud 

DAYS/SPUD BASIN_FACTORS 

MUD_BASED_USED Mud type TYPE BASIN_FACTORS 

MUD_GAS_VOC_MOLAR VOC molar PCT Value of degassed mud

at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_CO2_MOLAR Carbon dioxide molar PCT Value of 

degassed mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_CH4_MOLAR Methane molar PCT Value of degassed

mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_H2S_MOLAR Hydrogen sulfide molar PCT Value of 

degassed mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_VOC_MW Molecular weight of VOC in the 

degassed mud at gas wells 

G/MOL BASIN_FACTORS 

MUD_OIL_VOC_MOLAR VOC molar PCT Value of degassed mud

at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_CO2_MOLAR Carbon dioxide molar PCT Value of 

degassed mud at oil wells 

Unitless BASIN_FACTORS 
December 2012 

88 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

MUD_OIL_CH4_MOLAR Methane molar PCT Value of degassed 

mud at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_H2S_MOLAR Hydrogen sulfide molar PCT Value of 

degassed mud at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_VOC_MW Molecular weight of VOC in the 

degassed mud at oil wells 

G/MOL BASIN_FACTORS 

MUD_OIL_MOL_PCT_BENZ Benzene molar PCT Value of degassed 

mud at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_MOL_PCT_ETHYLBENZ Ethylbenzene molar PCT Value of 

degassed mud at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_MOL_PCT_TOLUENE Toluene molar PCT Value of degassed 

mud at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_MOL_PCT_XYLENE Xylene molar PCT Value of degassed 

mud at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_MOL_PCT_METHANE Methane molar PCT Value of degassed 

mud at oil wells 

Unitless BASIN_FACTORS 

MUD_OIL_MOL_PCT_VOC VOC molar PCT Value of degassed mud 

at oil wells 

Unitless BASIN_FACTORS 

MUD_GAS_MOL_PCT_BENZ Benzene molar PCT Value of degassed 

mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_MOL_PCT_ETHYLBENZ Ethylbenzene molar PCT Value of 

degassed mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_MOL_PCT_TOLUENE Toluene molar PCT Value of degassed 

mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_MOL_PCT_XYLENE Xylene molar PCT Value of degassed 

mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_MOL_PCT_METHANE Methane molar PCT Value of degassed 

mud at gas wells 

Unitless BASIN_FACTORS 

MUD_GAS_MOL_PCT_VOC VOC molar PCT Value of degassed mud 

at gas wells 

Unitless BASIN_FACTORS 

6.2.16 Crude Oil Tanks 

Calculation Sheet: CRUDE_OIL_TANKS_2310010200 

Crude oil tank emissions are generated by working and breathing processes. The methodology 

for estimating oil tank venting emissions is shown in Equations 54-55. This methodology is 

based on a combined working and breathing losses VOC emissions factor on a per unit 

throughput basis (mass emissions per barrel of oil). 

 
December 2012 

89 

Equation 54) > @ captured efficiency

oil tanks VOC

oilt ks VOC oil F C C

EF

E P u u 1 u u

2000

, ,

,tan ,

where: 

Eoil,tanks,VOC is the county-wide annual VOC venting losses from oil tanks [tons-VOC/yr] 

EFoil,tank,VOC is the VOC emissions factor for total losses from oil tanks [lb-VOC/bbl] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of oil tanks with flares 

Poil is the county-wide oil production [bbl/yr] 

2000 is the unit conversion factor lb/ton 

The methodology for estimating crude oil tank losses from other pollutants i in the 

working/breathing gas is shown below 

Equation 55) ܧ௟௜௢,௧௔௡௞௦,௜ = ܧ௟௜௢,௧௔௡௞௦,௏ை஼ ×

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡೔

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡ೇೀ಴

where: 

Eoil,tanks,i is the county-wide annual venting losses of pollutant i from oil tanks [tons/yr] 

Eoil,tanks,VOC is the county-wide annual VOC venting losses from oil tanks [tons-VOC/yr] 

weight fraction is the mass-based concentration of pollutant i and VOC in the 

working/breathing gas 

The methodology for estimating condensate tank combined losses from other pollutants i in the 

flashing gas is shown below 

Equation 56) ܧ௡௢௖ௗ௘௡௦௔௧௘,௧௔௡௞௦,௜ = ܧ௡௢௖ௗ௘௡௦௔௧௘,௧௔௡௞௦,௏ை஼ ×

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡೔

௪௘௜௚௛௧ ௙௥௔௖௧௜௢௡ೇೀ಴

where: 

Econdensate,tanks,i is the emissions of pollutant i per liquid unit throughput from condensate 

tanks [tons/bbl] 

Econdensate,tanks,VOC is the VOC emissions per liquid unit throughput from condensate tanks 

[tons/bbl] 

weight fraction is the mass-based concentration of pollutant i and VOC in the flashing gas 

Flaring emissions from oil tank controls 

This source category includes any flaring emissions associated with controls applied to crude oil 

tanks. The methodology for estimating emissions from flaring of oil tank gas losses is described 

below: 
December 2012 

90 

Equation 57) 

    2000

1000 , , , ,

 ̧

1

·

 ̈

©

§ u

 u u u u u

EF HV

E P Q F C C

i

flare tank i countywide oil tanks flash captured efficiency

where: 

Eflare,tank is the county-wide emissions from crude oil tank flaring [ton/yr] 

Qoil,tank,flash is the volume of gas flared per unit of oil throughput [MCF/bbl] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of oil tanks with flares 

EFi is the flaring emissions factor for pollutant i [lb/MMBtu] 

HV is the local heating value of the gas [BTU/SCF] 

Pcountywide is the annual production of oil for a particular county [bbl/yr] 

1000 is the unit conversion factor MCF/MMCF 

2000 is the unit conversion factor lb/ton 

The methodology for estimating SO2 emissions from flaring of oil tank losses is shown below: 

Equation 58) 

     

907185

2

5.3 10

2 2

5

, ,

, , u u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧ u u u

1

·

 ̈

©

§

u u u u u

 



H S

gas

oil tanks flash captured efficiency countywide

flare tank SO f

T MW

R

P Q F C C P

E

where: 

2

Eflare,tank ,SO is the county-wide SO2 emissions from flaring controls in oil tanks [ton/yr] 

P is atmospheric pressure [1 atm] 

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

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

T is the atmospheric temperature [298 K] 

H S

f

2

 is the mass fraction of H2S in the gas 

Qoil,tank,flash is the volume of gas vented per unit of oil throughput [MCF/bbl] 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

F is the fraction of crude oil tanks with flares 

Pcountywide is the annual throughput of oil production for a particular county [bbl/yr] 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

 
December 2012 

91 

Extrapolation to county-level emissions 

Equations 54-58 provide county-wide estimates directly using by-county oil production as a 

surrogate. The total county-wide emissions from crude oil tanks are the sum of flaring and 

crude tank working and breathing emissions (by-pollutant). 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

OIL_TANK_FRAC_TO_TANKS Fraction of oil directed to tanks Unitless BASIN_FACTORS 

OIL_TANK_FLARE_FRAC Fraction of oil tanks with a flare Unitless BASIN_FACTORS 

OIL_TANK_AVG_FLASH_LOSSES Flashing emission factor VOC lost per 

barrel (BBL) of crude oil throughput 

LB VOCS/BBL BASIN_FACTORS 

OIL_TANK_FLARE_CAPT_EFF Capture Efficiency of the flare Unitless BASIN_FACTORS 

OIL_TANK_FLARE_CONT_EFF Control Efficiency of the flare Unitless BASIN_FACTORS 

OIL_TANK_GAS_VENTING_RATE Volume of flash gas vented per BBL of 

crude oil throughput 

MCF/BBL BASIN_FACTORS 

OIL_TANK_LOCAL_HV Heating value of the flared gas at the 

crude oil tank 

BTU/SCF BASIN_FACTORS 

OIL_TANK_FRACT_H2S Fraction of hydrogen sulfide in the flared 

gas at the crude oil tank 

Unitless BASIN_FACTORS 

OIL_TANK_FRACT_VOC Fraction of VOC in the flared gas at the 

crude oil tank 

Unitless BASIN_FACTORS 

OIL_TANK_MW_GAS Molecular weight of the flash gas being 

flared at the crude oil storage tank 

G/MOL BASIN_FACTORS 

OIL_TANK_BENZ_VOC Benzene fraction of VOC being emitted 

from crude oil storage tanks 

Unitless BASIN_FACTORS 

OIL_TANK_ETHYLBENZ_VOC Ethylbenzene fraction of VOC being 

emitted from crude oil storage tanks 

Unitless BASIN_FACTORS 

OIL_TANK_TOLUENE_VOC Toluene fraction of VOC being emitted 

from crude oil storage tanks 

Unitless BASIN_FACTORS 

OIL_TANK_XYLENE_VOC Xylene fraction of VOC being emitted 

from crude oil storage tanks 

Unitless BASIN_FACTORS 

OIL_TANK_CH4_VOC Methane ratio to VOC being emitted 

from crude oil storage tanks 

Unitless BASIN_FACTORS 

OIL_TANK_H2S_VOC Hydrogen sulfide ratio to VOC being 

emitted from crude oil storage tanks 

Unitless BASIN_FACTORS 

6.2.17 Produced water tanks 

Calculation Sheets: PROD_WATER_2310000550 

Water tank emissions are generated by working and breathing processes. Because information 

on oil and gas field handling of produced water is limited, emissions from this source were 

assumed uncontrolled. The methodology for estimating water tank emissions is shown below 
December 2012 

92 

separately for gas wells and oil wells as water production and gas compositions for each welltype will differ: 

Gas well water tanks: 

Equation 59) water gas

water tanks i

water gaswells i S

EF

E ,

, ,

, ,

2000

 u

where: 

Ewater,tanks, i is the county-wide annual emissions from water tanks located at gas wells 

[tons/yr] 

EFwater,gas wells,i is the emissions factor for pollutant i from working/breathing losses from 

water tanks in gas well sites [lb/bbl] 

Swater,gas is the county-wide annual production of water [bbl/yr] from gas wells 

2000 is the unit conversion factor lbs/ton 

Oil well water tanks: 

Equation 60) 

 

water oil

water LPwells i water RPwells i

water oilwells i S

EF F EF F

E ,

, , , ,

, ,

2000

1( )

u

u  u 

 

where: 

Ewater,oil wells,i is the county-wide annual emissions from water tanks located at oil wells 

[tons/yr] 

EFwater,LP,i is the emissions factor for pollutant i from working/breathing losses from water 

tanks at low pressure oil wells (i.e. wells with artificial lifts) [lb/bbl] 

EFwater,LP,i is the emissions factor for pollutant i from working/breathing losses from water 

tanks at regular pressure oil well sites [lb/bbl] 

F is the fraction of water production from oil wells with artificial lifts 

Swater,oil is the county-wide annual production of water [bbl/yr] from oil wells

2000 is the unit conversion factor lbs/ton 

To estimate emissions from other pollutants in the losses from water tanks, the following 

equation may be used: 

Equation 61) 

4 4

, , , 4

CH

i

CH

i

water wells i water wells M

M

MW

MW E E CH

 u u

where: 

E water,wells,i is the water tank county-wide venting losses of pollutant i from water tanks at 

particular well type (oil or gas) [ton/yr] 

EFwater,wells,CH4 is the water tank emissions for methane for a particular well type [ton CH4/yr] 

MWi is the molecular weight of pollutant i [lb/lb-mol]
December 2012 

93 

MWCH4 is the molecular weight of methane [lb/lb-mol] 

MCH4 is the mole percent of methane in the water tanks gas (local produced gas) [%] 

Mi is the mole percent of pollutant in the water tanks gas (local produced gas) [%] 

Extrapolation to county-level emissions 

County-wide emissions from produced water tanks are estimated directly from equations 59 

through 61. The sum of oil wells and gas wells water tank emissions yield total county-wide 

emissions from water tanks. 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

PROD_WATER_FRACT_TANK Fraction of produced water sent to 

tanks 

Unitless BASIN_FACTORS 

PROD_WATER_AVG_LOSS_GAS WELLS Average Methane losses from gas 

wells 

LB/BBL BASIN_FACTORS 

PROD_WATER_WELLS_ART_LIFT_OIL WELLS Fraction of low pressure oil wells, 

i.e. fraction of wells with artificial 

lifts 

Unitless BASIN_FACTORS 

PROD_WATER_AVG_LOSS_LP_OIL WELLS Average Methane losses from Low 

Pressure oil wells 

LB/BBL BASIN_FACTORS 

PROD_WATER_AVG_LOSS_REG_OIL WELLS Average Methane losses from 

Regular Pressure oil wells 

LB/BBL BASIN_FACTORS 

PROD_WATER_GASWELL_VOC_MOLAR VOC molar PCT Value of produced 

water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GASWELL_CO2_MOLAR Carbon dioxide molar PCT Value of 

produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GASWELL_CH4_MOLAR Methane molar PCT Value of 

produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GASWELL_H2S_MOLAR Hydrogen sulfide molar PCT Value 

of produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GASWELL_VOC_MW Molecular weight of VOC in the 

produced water at gas wells 

G/MOL BASIN_FACTORS 

PROD_WATER_OILWELL_VOC_MOLAR VOC molar PCT Value of produced 

water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OILWELL_CO2_MOLAR Carbon dioxide molar PCT Value of 

produced water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OILWELL_CH4_MOLAR Methane molar PCT Value of 

produced water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OILWELL_H2S_MOLAR Hydrogen sulfide molar PCT Value 

of produced water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OILWELL_VOC_MW Molecular weight of VOC in the 

produced water at oil wells 

G/MOL BASIN_FACTORS 

PROD_WATER_OIL_MOL_PCT_BENZ Benzene molar PCT Value of 

produced water at oil wells 

Unitless BASIN_FACTORS 
December 2012 

94 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

PROD_WATER_OIL_MOL_PCT_ETHYLBENZ Ethylbenzene molar PCT Value of 

produced water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OIL_MOL_PCT_TOLUENE Toluene molar PCT Value of 

produced water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OIL_MOL_PCT_XYLENE Xylene molar PCT Value of 

produced water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OIL_MOL_PCT_METHANE Methane molar PCT Value of 

produced water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_OIL_MOL_PCT_VOC VOC molar PCT Value of produced 

water at oil wells 

Unitless BASIN_FACTORS 

PROD_WATER_GAS_MOL_PCT_BENZ Benzene molar PCT Value of 

produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GAS_MOL_PCT_ETHYLBENZ Ethylbenzene molar PCT Value of 

produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GAS_MOL_PCT_TOLUENE Toluene molar PCT Value of 

produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GAS_MOL_PCT_XYLENE Xylene molar PCT Value of 

produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GAS_MOL_PCT_METHANE Methane molar PCT Value of 

produced water at gas wells 

Unitless BASIN_FACTORS 

PROD_WATER_GAS_MOL_PCT_VOC VOC molar PCT Value of produced 

water at gas wells 

Unitless BASIN_FACTORS 

6.2.18 Casinghead gas venting 

Calculation sheets: CASING_HEAD_GAS_2310011000 

This section refers to the practice of venting associated gas from oil wells which sometimes 

takes place when the well is not connected to a gas sales pipeline or when amount of gas 

produced by the well is so limited that is not profitable for capture. The calculation 

methodology for estimating basin-wide emissions from casing gas vented is shown below in 

Equation 62: 

Equation 62)

    flare captured efficiency

i

gas

ca g gas oil

ca g gas i F C C

f

T MW

R

P Q S

E u u  u u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧u u u

1

·

 ̈

©

§

u u

 



1

907185 5.3 10 5

sin ,

sin , ,

where: 

Ecasing,gas,i is the county-wide emissions of pollutant i from casing gas venting [ton/bbl] 

P is atmospheric pressure [1 atm] 

Qcasing,gas,i is the venting rate of casing gas per unit of oil production [MCF/bbl] 
December 2012 

95 

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

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

T is the atmospheric temperature [298 K] 

fiis the mass fraction of pollutant i in the casing gas 

Soil is the annual county-wide production of oil [bbl/yr] 

Fflare is the fraction of casing gas vent controlled with flares 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

Flaring emissions from casing gas controls 

Emissions from flaring controls applied to casing head gas are included in this source category. 

The methodology for estimating emissions from flaring of casing gas is described below: 

Equation 63) 

   

2000

1000

sin ,

sin , ,  ̧

 ̧

1

·

 ̈

 ̈

©

§

u

u u u u u

 oil

i ca g gas captured efficiency

ca g gas i

S

EF Q F C C HV

E

where: 

Eflare,casing,gas is the county-wide flaring emissions of pollutant i from vented casing gas 

[ton/yr] 

EFi is the flaring emissions factor for pollutant i [lb/MMBtu] 

Qcasing,gas is the volume of casing gas vented per barrel of oil produced [MCF/bbl] 

HV is the local heating value of the gas [BTU/SCF] 

Soil is the annual county-wide production of oil [bbl/yr] 

F is the fraction of casing gas vent controlled with flares 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

2000 is the unit conversion factor lbs/ton 

The methodology for estimating SO2 emissions from flaring of casing head gas is shown below: 

Equation 64) 

      flare captured efficiency

SO

gas

ca g gas oil

ca g flare SO F C C

f

T MW

R

P Q S

E u u u u u

 ̧

 ̧

 ̧

 ̧

1

·

 ̈

 ̈

 ̈

 ̈

©

§

 ̧u u u

1

·

 ̈

©

§

u u

 

 907185

2

5.3 10

2

2

5

sin ,

sin , ,

where: 

2

Eca sin g, flare,SO is the county-wide SO2 emissions from flaring of casing gas [ton/yr] 

P is atmospheric pressure [1 atm] 
December 2012 

96 

Qcasing,gas is vented volume of casing gas per barrel of oil [MCF/bbl] 

Soil is the annual county-wide production of oil [bbl/yr] 

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

MWgas is the molecular weight of the casing gas [g/mol] 

T is the atmospheric temperature [298 K] 

H S

f

2

is the mass fraction of H2S in the casing gas 

F is the fraction of casing gas vents controlled by flare 

Ccapture is the capture efficiency of the flare 

Cefficiency is the control efficiency of the flare 

3.5x10-5 is the unit conversion factor MCF/L 

907185 is the unit conversion factor g/ton 

Extrapolation to county-level emissions 

County-wide emissions from casing gas venting and casing gas flaring are estimated directly 

from Equations 62-64. The sum of venting and flaring emissions by pollutant yield the total 

county-wide emissions from casing head gas that is not captured for sale. 

Source category data fields within the tool 

FIELD FIELD DESCRIPTION Units WORKSHEET TAB 

CASING_GAS_VENTING_RATE Venting rate of casing gas per unit of oil 

production throughput 

MCF/BBL BASIN_FACTORS 

CASING_GAS_FRACT_VENTS_CONT Fraction of casing gas vent controlled 

with flares 

Unitless BASIN_FACTORS 

CASING_GAS_FLARING_CONT_EFF Control Efficiency of the flare Unitless BASIN_FACTORS 

CASING_GAS_FLARING_CAPTURE_EFF Capture Efficiency of the flare Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_VOC Fraction of VOC in the vented casing gas Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_H2S Fraction of Hydrogen sulfide in the 

vented casing gas 

Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_CO Fraction of CO in the vented casing gas Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_CH4 Fraction of Methane in the vented 

casing gas 

Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_BENZ Fraction of Benzene in the vented casing 

gas 

Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_ETHYLBENZ Fraction of Ethylbenzene in the vented 

casing gas 

Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_TOLUENE Fraction of Toluene in the vented casing 

gas 

Unitless BASIN_FACTORS 

CASING_GAS_WT_FRACT_XYLENE Fraction of Xylene in the vented casing 

gas 

Unitless BASIN_FACTORS 

CASING_GAS_LHV Heating value of the vented casing gas BTU/SCF BASIN_FACTORS 

CASING_GAS_MW Molecular weight of the vented casing 

gas 

G/MOL BASIN_FACTORS 

 
December 2012 

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6.3 Output Emissions Summary 

The nonpoint emission estimates from each worksheet is linked to a “compiled_emissions” 

worksheet, which contains the entire emissions inventory for the state. At this point, the user 

can simply upload this tab into a database program for further data analysis. The information in 

the “compiled_emissions” worksheet is then fed to summary Pivot tables, which provides easyto-use summaries of source category emissions, geographic emissions, and activity data. These 

worksheet tabs are: 

x EMISSIONS_SUMMARY_GEOGRAPHIC 

x EMISSIONS_SUMMARY_SOURCE 

x ACTIVITY_SUMMARY_GEOGRAPHIC 

The information in the “compiled_emissions” worksheet are also fed into four worksheet tabs 

relating to the EPA’s Emission Inventory System (EIS) data submittal for nonpoint sources. The 

EIS staging tables for nonpoint sources can be found in “Nonpoint Inventory – April 2012” at 

http://www.epa.gov/ttn/chief/eidocs/training.html#eis. 

6.4 Formatting tool for NEI submission 

Within each workbook, selected information in the “compiled_emissions” worksheet are also 

fed into four worksheet tabs relating to the EPA’s Emission Inventory System (EIS) data 

submittal for nonpoint sources. The EIS staging tables for nonpoint sources can be found in 

“Nonpoint Inventory – April 2012” at http://www.epa.gov/ttn/chief/eidocs/training.html#eis. 

Although there are 13 tables relating to the nonpoint staging tables, EPA requires that the 

following four data tables need to be submitted: 

x Emissions 

x EmissionProcess 

x ReportingPeriod 

x Location 

The User can simply import the information from these four tabs into their emission inventory 

database program to generate the XML files needed for submittal. As a way to check the format 

of these EIS tables, a sample output XML file from one of the states’ tools was submitted to the 

EIS QA environment, and passed through the system checks without any issues. 

 
December 2012 

98 

7.0 RESULTS 

7.1 2011 Oil and Gas Area Source Emissions 

Emissions estimates were compiled from each State’s tool to arrive at the basin-wide 

inventories for the oil and gas regions within the CenSARA domain. Emissions were collected 

from the ‘compiled_emissions’ tab in each of the tools and combined in a Microsoft Access 

database to aggregate emissions from each State and allocate them in equivalent basin and 

source category bins. Emissions inventories developed in this work are highly detailed in their 

geographical specificity (detail by basin, state and county), in the array of pollutants included 

(16 total) and the number of source categories analyzed (18 area sources, 34 SCCs). Hence, for 

the purpose of summarizing results in this report, only key pollutants relevant to air quality 

issues of interest to CenSARA will be highlighted. For more detailed emissions, the User can 

manipulate the pivot table summaries within each tool to display emissions in the desired 

groupings. 

Basin-wide emissions by source are shown in Table 7-1 for selected pollutants including the 

major criteria pollutants (NOx, VOC, CO, PM10, PM2.5, SO2), hydrogen sulfide (H2S), total HAPs (a 

combination of benzene, ethylbenzene, toluene, xylene, formaldehyde and n-hexane) and 

methane (CH4). 

Following Table 7-1, the distribution of total CenSARA domain emissions allocated by State, and 

by each basin within a CenSARA state is shown in Table 7-2. 

As stated earlier in this report, the following data should be considered preliminary. As the 

states complete their QA/QC and take into consideration additional information (ex: applicable 

control measures), there will likely be changes. Each state should be contacted regarding what 

it has been ultimately reported to the NEI.
December 2012 

99 

Table 7-1. Basin-wide emissions by area source category for 2011 in the CenSARA domain. 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Anadarko Basin 108,951.8 133,644.6 273,065.5 89.1 3,767.9 3,761.5 48.9 4,087.6 708,482.8  Artificial Lift Engines 9,028.4 13,960.2 117.7 2.3 77.2 77.2 - 90.9 914.8  Blowdowns - - 38,738.4 10.7 - - - 77.0 99,343.0  Casinghead Gas Venting - - 738.8 0.0 - - - - 2,964.2  Condensate Tanks 196.8 1,040.5 10,201.2 - - - - 306.3 6,664.9  Crude Oil Tanks 0.0 0.2 13,377.2 - - - - 25.9 79.4  Dehydrators 0.0 0.0 1,545.3 - 0.0 0.0 - 587.2 2,024.3  Drill Rigs 4,899.3 1,116.7 308.2 8.5 191.1 186.1 - 38.4 5.0  Fugitives - - 17,828.3 - - - 4.0 26.3 50,765.0  Gas-Actuated Pumps - - 8,735.9 - - - 2.2 16.0 23,384.4  Heaters 20,686.5 17,376.6 1,137.8 0.0 1,572.2 1,572.2 - 159.3 475.8  Hydraulic Fracturing 1,126.1 254.5 71.1 1.9 43.8 42.5 - 8.9 1.2  Lateral/Gathering Line Compressors 

 22,250.0 31,625.1 876.4 18.8 592.5 592.5 - 730.9 10,400.2 

 Loading Emissions - - 1,063.0 - - - 0.0 14.0 149.4  Mud Degassing - - 8,419.7 - - - 1.3 8.8 27,383.9  Pneumatic Devices - - 166,568.8 - - - 41.2 294.8 453,681.8  Produced Water - - 772.3 - - - 0.2 1.5 2,006.1  Well Completions 96.1 507.8 128.8 4.5 - - - 54.9 71.5  Wellhead Compressor Engines 50,668.6 67,763.0 2,436.7 42.4 1,291.0 1,291.0 - 1,646.6 28,168.1  Arkoma Basin 15,615.5 12,461.8 16,273.7 17.2 428.6 425.3 3.5 340.8 294,226.3  Artificial Lift Engines 866.4 1,339.7 11.3 0.2 7.4 7.4 - 8.7 87.8  Blowdowns - - 3,911.6 0.3 - - - - 99,372.0 
December 2012 

100 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Casinghead Gas Venting - - - - - - - - -  Condensate Tanks 1.0 5.2 38.2 - - - - 0.6 56.3  Crude Oil Tanks - - 1,357.6 5.6 - - - 63.9 180.6  Dehydrators 0.0 0.0 14.2 - 0.0 0.0 - 11.6 14.6  Drill Rigs 1,221.0 286.7 74.9 2.3 48.1 46.8 - 9.3 1.2  Fugitives - - 1,368.4 - - - 1.1 - 13,460.9  Gas-Actuated Pumps - - 707.7 - - - 0.6 - 5,724.0  Heaters 2,473.3 2,077.6 136.0 0.0 188.0 188.0 - 19.0 56.9  Hydraulic Fracturing 1,688.9 381.7 106.6 2.9 65.7 63.7 - 13.3 1.7  Lateral/Gathering Line Compressors 

 3,003.5 2,403.9 300.3 1.8 37.7 37.7 - 71.1 3,172.0 

 Loading Emissions - - 7.5 - - - 0.0 0.0 0.1  Mud Degassing - - 341.4 - - - 0.1 - 6,162.2  Pneumatic Devices - - 7,043.5 - - - 1.6 - 158,096.8  Produced Water - - - - - - - - - Well Completions 1.2 6.4 315.7 0.5 - - - 0.7 2,158.5  Wellhead Compressor Engines 6,360.2 5,960.7 538.9 3.7 81.7 81.7 - 142.4 5,680.7  Bend Arch-Fort Worth Basin 144,032.1 189,210.9 147,646.4 1,667.3 2,468.9 2,464.8 1,106 3,099.4 458,542.4  Artificial Lift Engines 8,596.6 13,292.6 112.1 2.2 73.5 73.5 - 86.6 871.0  Blowdowns - - 12,307.2 1.0 - - - 32.5 60,509.5  Casinghead Gas Venting 0.1 0.4 1,042.2 1,062.0 - - - 5.0 1,457.1  Condensate Tanks 19.1 101.1 12,544.2 - - - - 135.0 5,045.4  Crude Oil Tanks 1.2 6.6 13,093.3 487.4 - - - 317.1 1,832.8  Dehydrators 0.0 0.0 81.6 - 0.0 0.0 - 26.9 427.6  Drill Rigs 3,539.4 859.3 213.3 6.8 140.9 137.0 - 26.5 3.5 
December 2012 

101 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Fugitives - - 14,693.9 - - - 268.1 76.8 37,108.9  Gas-Actuated Pumps - - 5,114.4 - - - 68.8 23.0 12,994.7  Heaters 10,873.8 9,134.0 598.1 0.1 826.4 826.4 - 83.7 250.1  Hydraulic Fracturing 199.2 45.0 12.6 0.3 7.8 7.5 - 1.6 0.2  Lateral/Gathering Line Compressors 

 8,631.4 12,391.0 246.4 3.1 91.6 91.6 - 120.7 2,397.8 

 Loading Emissions - - 255.7 - - - 0.0 3.1 7.4  Mud Degassing - - 2,735.0 - - - 23.9 10.0 8,791.6  Pneumatic Devices - - 74,054.9 - - - 729.2 286.8 259,451.4  Produced Water - - 4,407.0 - - - 16.0 13.2 17,832.4  Well Completions 13.9 73.3 1,853.6 57.3 - - - 14.9 6,151.0  Wellhead Compressor Engines 112,157.3 153,307.6 4,281.0 47.2 1,328.7 1,328.7 - 1,836.0 43,410.0  Cambridge Arch-Central Kansas Uplift 

 9,339.9 11,728.8 39,793.7 2.4 282.8 282.5 0.0 209.7 86,424.4 

 Artificial Lift Engines 1,413.7 2,186.0 18.4 0.4 12.1 12.1 - 14.2 143.2  Blowdowns - - 542.9 - - - - 0.2 9,202.2  Casinghead Gas Venting 0.1 0.7 713.2 - - - - 0.1 1,364.3  Condensate Tanks - - 8,418.8 - - - - 40.5 1,929.2  Crude Oil Tanks - - 3,039.6 - - - - 73.4 425.4  Dehydrators 0.0 0.0 0.8 - 0.0 0.0 - 0.7 0.9  Drill Rigs 246.6 66.3 13.4 0.6 10.2 9.9 - 1.7 0.2  Fugitives - - 5,612.6 - - - - 0.0 12,739.3  Gas-Actuated Pumps - - 1,418.7 - - - - 0.0 3,412.7  Heaters 2,868.6 2,409.6 157.8 - 218.0 218.0 - 22.1 66.0  Hydraulic Fracturing - - - - - - - - -
December 2012 

102 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Lateral/Gathering Line Compressors 

 917.6 1,272.4 32.8 0.3 8.4 8.4 - 12.0 319.5 

 Loading Emissions - - 69.6 - - - 0.0 0.9 0.5  Mud Degassing - - 547.1 - - - - 0.0 1,141.8  Pneumatic Devices - - 18,732.4 - - - - 0.3 52,516.8  Produced Water - - 112.8 - - - - 0.0 1,799.0  Well Completions - - 279.8 - - - - 0.0 619.1  Wellhead Compressor Engines 3,893.3 5,793.8 82.9 1.1 34.1 34.1 - 43.5 744.3  Cherokee Platform 36,316.4 48,490.0 73,950.7 567.4 791.4 791.1 620.1 901.9 240,037.0  Artificial Lift Engines 10,550.7 16,314.0 137.6 2.7 90.2 90.2 - 106.2 1,069.0  Blowdowns - - 7,665.4 0.6 - - - 20.2 37,687.6  Casinghead Gas Venting 0.0 0.1 354.3 361.1 - - - 1.7 495.4  Condensate Tanks 3.9 20.4 2,528.4 - - - - 27.2 1,016.9  Crude Oil Tanks 0.4 2.2 4,451.6 165.7 - - - 107.8 623.1  Dehydrators 0.0 0.0 59.2 - 0.0 0.0 - 48.5 60.9  Drill Rigs 171.5 53.9 9.5 0.4 7.3 7.1 - 1.1 0.1  Fugitives - - 8,216.3 - - - 144.8 42.2 21,427.0  Gas-Actuated Pumps - - 2,898.4 - - - 37.1 12.8 7,650.2  Heaters 6,193.6 5,202.6 340.6 0.0 470.7 470.7 - 47.7 142.5  Hydraulic Fracturing 1.1 0.2 0.1 0.0 0.0 0.0 - 0.0 0.0  Lateral/Gathering Line Compressors 

 5,375.9 7,717.6 153.5 1.9 57.1 57.1 - 75.2 1,493.5 

 Loading Emissions - - 55.4 - - - 0.0 0.7 1.6  Mud Degassing - - 2,538.3 - - - 44.3 12.1 4,564.3  Pneumatic Devices - - 43,364.8 - - - 393.9 163.8 156,710.8 
December 2012 

103 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Produced Water - - - - - - - - -  Well Completions 4.0 21.3 642.5 29.1 - - - 5.3 1,669.6  Wellhead Compressor Engines 14,015.3 19,157.5 535.0 5.9 166.0 166.0 - 229.4 5,424.6  Denver Basin 1,547.2 2,203.1 7,693.4 0.4 20.8 20.8 0.2 52.4 11,984.2  Artificial Lift Engines 5.7 8.8 0.1 0.0 0.0 0.0 - 0.1 0.6  Blowdowns - - 161.8 - - - - 0.0 2,741.9  Casinghead Gas Venting 0.0 0.0 16.1 - - - - 0.0 30.7  Condensate Tanks - - 6,735.8 - - - - 32.4 1,543.6  Crude Oil Tanks - - 68.5 - - - - 1.7 9.6  Dehydrators 0.0 0.0 0.1 - 0.0 0.0 - 0.1 0.1  Drill Rigs 3.5 0.9 0.2 0.0 0.1 0.1 - 0.0 0.0  Fugitives - - 61.8 - - - - 0.0 714.7  Gas-Actuated Pumps - - 93.4 - - - 0.2 0.0 245.1  Heaters 104.5 87.8 5.7 0.0 7.9 7.9 - 0.8 2.4  Hydraulic Fracturing - - - - - - - - - Lateral/Gathering Line Compressors 

 273.4 379.1 9.8 0.1 2.5 2.5 - 3.6 95.2 

 Loading Emissions - - 54.3 - - - 0.0 0.7 0.4  Mud Degassing - - 4.2 - - - - - 8.0  Pneumatic Devices - - 401.8 - - - - 0.1 5,737.6  Produced Water - - 45.8 - - - - - 614.4  Well Completions - - 9.5 - - - - - 18.1  Wellhead Compressor Engines 1,160.1 1,726.3 24.7 0.3 10.2 10.2 - 13.0 221.8  East Texas Basin 128,840.1 171,678.3 100,631.5 944.4 1,975.3 1,972.9 439.8 3,417.4 364,708.0  Artificial Lift Engines 3,576.3 5,529.9 46.6 0.9 30.6 30.6 - 36.0 362.4 
December 2012 

104 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Blowdowns - - 11,445.5 0.9 - - - 30.2 56,273.2  Casinghead Gas Venting 0.0 0.2 591.8 603.0 - - - 2.8 827.5  Condensate Tanks 13.5 71.4 8,858.4 - - - - 95.3 3,562.9  Crude Oil Tanks 0.7 3.7 7,435.2 276.8 - - - 180.0 1,040.8  Dehydrators 0.0 0.0 1,491.3 - 0.0 0.0 - 879.9 417.6  Drill Rigs 2,023.6 517.8 120.1 4.0 81.6 79.3 - 14.8 1.9  Fugitives - - 7,691.6 - - - 107.5 35.3 23,747.5  Gas-Actuated Pumps - - 2,923.5 - - - 27.6 11.5 9,254.1  Heaters 6,415.7 5,389.2 352.9 0.0 487.6 487.6 - 49.4 147.6  Hydraulic Fracturing 60.1 13.6 3.8 0.1 2.3 2.3 - 0.5 0.1  Lateral/Gathering Line Compressors 

 8,027.1 11,523.5 229.2 2.9 85.2 85.2 - 112.3 2,230.0 

 Loading Emissions - - 405.4 - - - 0.0 4.6 12.1  Mud Degassing - - 916.9 - - - 3.4 2.8 3,700.4  Pneumatic Devices - - 51,252.8 - - - 293.6 171.8 210,096.9  Produced Water - - 2,237.4 - - - 7.7 6.7 9,119.9  Well Completions 4.0 21.1 479.4 10.0 - - - 3.8 1,834.0  Wellhead Compressor Engines 108,719.1 148,607.9 4,149.7 45.8 1,288.0 1,288.0 - 1,779.7 42,079.2  Forest City Basin 4,344.9 6,090.1 8,186.2 1.1 89.2 89.1 11.5 58.7 19,014.8  Artificial Lift Engines 3,032.0 4,688.3 39.5 0.8 25.9 25.9 - 30.5 307.2  Blowdowns - - 58.2 - - - - 0.1 298.0  Casinghead Gas Venting 0.0 0.0 29.9 - - - - 0.0 66.5  Condensate Tanks - - 142.2 - - - - 0.7 32.6  Crude Oil Tanks - - 180.2 - - - - 4.4 25.2  Dehydrators 0.0 0.0 0.3 - 0.0 0.0 - 0.3 0.3 
December 2012 

105 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Drill Rigs 47.8 12.8 2.6 0.1 2.0 1.9 - 0.3 0.0  Fugitives - - 1,493.1 - - - - 1.7 3,413.5  Gas-Actuated Pumps - - 395.6 - - - 11.5 0.5 854.2  Heaters 745.8 626.5 41.0 0.0 56.7 56.7 - 5.7 17.2  Hydraulic Fracturing - - - - - - - - - Lateral/Gathering Line Compressors 

 101.6 140.9 3.6 0.0 0.9 0.9 - 1.3 35.4 

 Loading Emissions - - 1.4 - - - 0.0 0.0 0.0  Mud Degassing - - 534.8 - - - - 1.7 1,028.1  Pneumatic Devices - - 5,093.1 - - - - 6.5 12,458.4  Produced Water - - 24.1 - - - - 0.0 92.5  Well Completions - - 137.5 - - - - 0.2 305.9  Wellhead Compressor Engines 417.7 621.5 8.9 0.1 3.7 3.7 - 4.7 79.8  Illinois Basin 15.3 13.5 15.6 0.0 0.4 0.4 0.0 0.3 372.7  Artificial Lift Engines - - - - - - - - - Blowdowns - - 5.1 0.0 - - - - 130.0  Casinghead Gas Venting - - - - - - - - - Condensate Tanks - - - - - - - - - Crude Oil Tanks - - - - - - - - - Dehydrators 0.0 0.0 0.0 - 0.0 0.0 - 0.0 0.0  Drill Rigs - - - - - - - - - Fugitives - - 0.7 - - - 0.0 - 17.2  Gas-Actuated Pumps - - 0.4 - - - - - 7.3  Heaters 3.1 2.6 0.2 0.0 0.2 0.2 - 0.0 0.1  Hydraulic Fracturing - - - - - - - - - 
December 2012 

106 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Lateral/Gathering Line Compressors 

 3.9 3.1 0.4 0.0 0.0 0.0 - 0.1 4.2 

 Loading Emissions - - - - - - - - - Mud Degassing - - - - - - - - - Pneumatic Devices - - 8.1 - - - 0.0 - 206.5  Produced Water - - - - - - - - - Well Completions - - - - - - - - - Wellhead Compressor Engines 8.3 7.8 0.7 0.0 0.1 0.1 - 0.2 7.4  Louisiana-Mississippi Salt Basins 39,831.9 49,055.7 40,340.8 458.7 1,053.9 1,050.6 1,404 1,726.2 158,600.9  Artificial Lift Engines 2,880.0 4,453.3 37.6 0.7 24.6 24.6 - 29.0 291.8  Blowdowns - - 825.9 - - - - 8.9 5,353.5  Casinghead Gas Venting - - - - - - - - - Condensate Tanks 2.2 11.8 2,679.1 - - - - 40.3 209.8  Crude Oil Tanks - - 2,118.9 308.8 - - - 25.4 513.0  Dehydrators 0.0 0.0 613.7 - 0.0 0.0 - 503.3 632.2  Drill Rigs 3,061.7 704.9 192.1 5.3 119.7 116.5 - 23.9 3.1  Fugitives - - 5,838.1 - - - 421.9 156.8 17,901.9  Gas-Actuated Pumps - - 1,886.1 - - - 108.9 44.6 7,080.8  Heaters 8,349.7 7,013.8 459.2 0.1 634.6 634.6 - 64.3 192.0  Hydraulic Fracturing 70.1 15.8 4.4 0.1 2.7 2.6 - 0.6 0.1  Lateral/Gathering Line Compressors 

 10,066.5 15,565.4 131.3 2.6 86.1 86.1 - 101.4 1,020.0 

 Loading Emissions - - 164.6 - - - 0.0 2.2 1.2  Mud Degassing - - 360.5 - - - 23.6 9.3 1,223.1  Pneumatic Devices - - 22,961.1 - - - 790.2 423.9 111,484.9 
December 2012 

107 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Produced Water - - 1,453.1 - - - 59.6 29.4 6,605.2  Well Completions 10.1 53.6 19.9 134.3 - - - 6.0 30.8  Wellhead Compressor Engines 15,391.5 21,237.2 595.2 6.6 186.1 186.1 - 257.0 6,057.7  Marathon Thrust Belt 3,863.2 5,585.2 4,525.2 1.6 51.9 51.9 0.5 64.8 13,172.8  Artificial Lift Engines 2.3 3.5 0.0 0.0 0.0 0.0 - 0.0 0.2  Blowdowns - - 906.4 - - - - - 2,607.9  Casinghead Gas Venting - - - - - - - - -  Condensate Tanks 0.3 1.4 236.8 - - - - 2.5 95.2  Crude Oil Tanks 0.0 0.0 2.5 0.1 - - - 0.1 0.3  Dehydrators 0.0 0.0 10.5 - 0.0 0.0 - 5.1 11.8  Drill Rigs 21.9 5.0 1.4 0.0 0.9 0.8 - 0.2 0.0  Fugitives - - 152.8 - - - 0.1 - 440.5  Gas-Actuated Pumps - - 28.0 - - - 0.1 - 208.9  Heaters 90.9 76.4 5.0 0.0 6.9 6.9 - 0.7 2.1  Hydraulic Fracturing - - - - - - - - - Lateral/Gathering Line Compressors 

 232.3 333.5 6.6 0.1 2.5 2.5 - 3.2 64.5 

 Loading Emissions - - 5.4 - - - 0.0 0.1 0.2  Mud Degassing - - 13.9 - - - 0.2 0.2 41.8  Pneumatic Devices - - 3,058.3 - - - 0.2 - 8,801.3  Produced Water - - 9.4 - - - 0.0 0.1 32.2  Well Completions - - - - - - - - - Wellhead Compressor Engines 3,515.6 5,165.6 88.2 1.4 41.7 41.7 - 52.7 865.8  Nemaha Uplift 9,081.4 12,867.0 22,701.9 2.3 158.1 158.0 14.9 192.3 43,783.4  Artificial Lift Engines 3,933.2 6,081.8 51.3 1.0 33.6 33.6 - 39.6 398.5 
December 2012 

108 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Blowdowns - - 443.3 - - - - 0.9 2,268.4  Casinghead Gas Venting 0.0 0.1 103.9 - - - - 0.1 231.1  Condensate Tanks - - 8,578.0 - - - - 41.3 1,965.7  Crude Oil Tanks - - 626.7 - - - - 15.1 87.7  Dehydrators 0.0 0.0 26.3 - 0.0 0.0 - 21.5 27.1  Drill Rigs 39.2 10.5 2.1 0.1 1.6 1.6 - 0.3 0.0  Fugitives - - 2,187.0 - - - - 2.7 5,735.0  Gas-Actuated Pumps - - 679.2 - - - 14.9 1.0 1,662.1  Heaters 1,156.9 971.8 63.6 0.0 87.9 87.9 - 8.9 26.6  Hydraulic Fracturing - - - - - - - - -  Lateral/Gathering Line Compressors 

 773.3 1,072.3 27.6 0.3 7.1 7.1 - 10.1 269.2 

 Loading Emissions - - 78.3 - - - 0.0 1.0 0.6  Mud Degassing - - 88.3 - - - - 0.3 179.5  Pneumatic Devices - - 9,067.3 - - - - 13.2 28,750.1  Produced Water - - - - - - - - - Well Completions - - 611.2 - - - - 0.8 1,574.0  Wellhead Compressor Engines 3,178.8 4,730.6 67.7 0.9 27.9 27.9 - 35.5 607.7  Ozark Uplift - - - - - - - - - Artificial Lift Engines - - - - - - - - - Blowdowns - - - - - - - - - Casinghead Gas Venting - - - - - - - - - Condensate Tanks - - - - - - - - - Crude Oil Tanks - - - - - - - - - Dehydrators - - - - - - - - - 
December 2012 

109 

Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

 Drill Rigs - - - - - - - - -  Fugitives - - - - - - - - - Gas-Actuated Pumps - - - - - - - - - Heaters - - - - - - - - -  Hydraulic Fracturing - - - - - - - - - Lateral/Gathering Line Compressors 

 - - - - - - - - -

Loading Emissions - - - - - - - - - Mud Degassing - - - - - - - - -Pneumatic Devices - - - - - - - - -Produced Water - - - - - - - - - Well Completions - - - - - - - - -Wellhead Compressor Engines - - - - - - - - -Palo Duro Basin 5,879.2 7,884.9 6,570.0 206.9 94.8 94.7 37.8 159.7 17,978.0 Artificial Lift Engines 289.2 447.2 3.8 0.1 2.5 2.5 - 2.9 29.3 Blowdowns - - 530.9 0.0 - - - 1.4 2,610.3 Casinghead Gas Venting 0.0 0.1 136.8 139.4 - - - 0.7 191.3 Condensate Tanks 0.3 1.7 216.3 - - - - 2.3 87.0 Crude Oil Tanks 0.2 0.9 1,719.3 64.0 - - - 41.6 240.7 Dehydrators 0.0 0.0 10.8 - 0.0 0.0 - 8.9 11.1 Drill Rigs 15.6 4.7 0.9 0.0 0.7 0.6 - 0.1 0.0 Fugitives - - 532.0 - - - 9.1 2.7 1,417.2 Gas-Actuated Pumps - - 189.4 - - - 2.3 0.8 512.3 Heaters 406.0 341.0 22.3 0.0 30.9 30.9 - 3.1 9.3 Hydraulic Fracturing 0.6 0.1 0.0 0.0 0.0 0.0 - 0.0 0.0 
December 2012 

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Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

Lateral/Gathering Line Compressors

 372.3 534.5 10.6 0.1 4.0 4.0 - 5.2 103.4 

Loading Emissions - - 6.9 - - - 0.0 0.1 0.2 Mud Degassing - - 43.2 - - - 0.6 0.2 104.5 Pneumatic Devices - - 2,894.0 - - - 24.9 10.8 10,660.2 Produced Water - - 49.0 - - - 0.8 0.2 99.9 Well Completions 0.1 0.6 20.7 1.1 - - - 0.2 45.4 Wellhead Compressor Engines 4,794.8 6,554.0 183.0 2.0 56.8 56.8 - 78.5 1,855.8 Permian Basin 166,428.8 226,582.7 386,201.5 8,625.6 3,437.3 3,431.6 3,288 6,910.9 626,541.9 Artificial Lift Engines 24,576.8 38,001.9 320.5 6.4 210.1 210.1 - 247.5 2,490.2 Blowdowns 107.8 569.7 27,390.3 - - - - 61.6 78,473.1 Casinghead Gas Venting - - - - - - - - -Condensate Tanks 16.8 88.9 15,190.4 - - - - 159.9 6,109.3 Crude Oil Tanks 107.4 567.8 180,759.1 7,904.5 - - - 4,425.8 25,338.2 Dehydrators 0.0 0.0 134.1 - 0.0 0.0 - 64.3 150.1 Drill Rigs 5,506.9 1,244.8 347.5 9.4 214.4 208.7 - 43.3 5.7 Fugitives - - 19,903.1 - - - 890.9 - 65,917.4 Gas-Actuated Pumps - - 6,409.2 - - - 246.1 - 20,833.8 Heaters 21,945.3 18,434.1 1,207.0 0.2 1,667.8 1,667.8 - 169.0 504.7 Hydraulic Fracturing 33.3 7.5 2.1 0.1 1.3 1.3 - 0.3 0.0 Lateral/Gathering Line Compressors

 6,984.0 10,026.1 199.4 2.5 74.1 74.1 - 97.7 1,940.2 

Loading Emissions - - 393.1 - - - 0.0 4.9 11.4 Mud Degassing - - 3,617.0 - - - 158.9 - 11,952.2 Pneumatic Devices - - 124,290.1 - - - 1,881 - 375,892.9 
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Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

Produced Water - - 3,279.4 - - - 110.3 - 10,508.6 Well Completions 53.4 282.1 71.1 661.2 - - - 30.5 38.9 Wellhead Compressor Engines 107,097.0 157,359.7 2,688.1 41.3 1,269.5 1,269.5 - 1,606.2 26,375.2 Salina Basin 82.2 85.6 610.3 0.0 4.1 4.1 0.8 2.2 994.6 Artificial Lift Engines 26.4 40.9 0.3 0.0 0.2 0.2 - 0.3 2.7 Blowdowns - - 0.2 - - - - 0.0 3.5 Casinghead Gas Venting 0.0 0.0 11.2 - - - - 0.0 21.3 Condensate Tanks - - 73.4 - - - - 0.4 16.8 Crude Oil Tanks - - 47.6 - - - - 1.1 6.7 Dehydrators 0.0 0.0 0.0 - 0.0 0.0 - 0.0 0.0 Drill Rigs 5.8 1.6 0.3 0.0 0.2 0.2 - 0.0 0.0 Fugitives - - 103.2 - - - - 0.0 198.2 Gas-Actuated Pumps - - 16.0 - - - 0.8 0.0 49.7 Heaters 48.2 40.5 2.6 0.0 3.7 3.7 - 0.4 1.1 Hydraulic Fracturing - - - - - - - - -Lateral/Gathering Line Compressors

 0.4 0.5 0.0 0.0 0.0 0.0 - 0.0 0.1 

Loading Emissions - - 0.6 - - - 0.0 0.0 0.0 Mud Degassing - - 15.3 - - - - - 29.2 Pneumatic Devices - - 332.1 - - - - 0.0 641.8 Produced Water - - 0.7 - - - - - 10.2 Well Completions - - 6.8 - - - - - 12.9 Wellhead Compressor Engines 1.5 2.2 0.0 0.0 0.0 0.0 - 0.0 0.3 Sedgwick Basin 11,948.0 17,337.3 25,363.9 3.3 160.8 160.7 0.0 321.0 41,127.4 Artificial Lift Engines 5,100.9 7,887.3 66.5 1.3 43.6 43.6 - 51.4 516.8 
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Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

Blowdowns - - 26.3 - - - - 0.1 69.8 Casinghead Gas Venting - - 19.6 - - - - 0.1 50.5 Condensate Tanks - - 10,583.9 - - - - 50.9 2,425.4 Crude Oil Tanks - - 297.2 - - - - 7.2 41.6 Dehydrators 0.0 0.0 124.0 - 0.0 0.0 - 101.7 127.8 Drill Rigs 96.6 26.0 5.3 0.2 4.0 3.9 - 0.7 0.1 Fugitives - - 1,666.6 - - - - 4.0 4,349.2 Gas-Actuated Pumps - - 604.2 - - - - 1.4 1,587.1 Heaters 798.1 670.4 43.9 - 60.7 60.7 - 6.1 18.4 Hydraulic Fracturing - - - - - - - - - Lateral/Gathering Line Compressors

 1,199.8 1,663.7 42.8 0.4 11.0 11.0 - 15.7 417.7 

Loading Emissions - - 110.3 - - - 0.0 1.4 0.9 Mud Degassing - - 170.6 - - - - 0.4 351.1 Pneumatic Devices - - 11,301.1 - - - - 26.7 29,756.3 Produced Water - - - - - - - - -Well Completions - - 202.8 - - - - 0.5 533.0 Wellhead Compressor Engines 4,752.5 7,089.8 98.7 1.4 41.6 41.6 - 52.8 881.9 Southern Oklahoma 7,491.5 9,423.2 30,292.2 26.7 194.7 194.6 16.7 377.0 56,053.5 Artificial Lift Engines 3,380.2 5,226.6 44.1 0.9 28.9 28.9 - 34.0 342.5 Blowdowns - - 1,906.1 0.5 - - - 3.3 10,495.8 Casinghead Gas Venting - - 287.1 0.3 - - - - 325.3 Condensate Tanks 22.9 120.9 1,092.9 - - - - 26.5 1,047.2 Crude Oil Tanks 0.0 0.1 6,873.3 17.9 - - - 209.9 594.5 Dehydrators 0.0 0.0 22.0 - 0.0 0.0 - 18.0 22.6 
December 2012 

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Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

Drill Rigs 75.8 17.9 4.7 0.1 3.0 2.9 - 0.6 0.1 Fugitives - - 3,056.3 - - - 2.8 0.6 5,103.8 Gas-Actuated Pumps - - 1,298.4 - - - 1.3 0.1 1,852.4 Heaters 1,635.1 1,373.5 89.9 0.0 124.3 124.3 - 12.6 37.6 Hydraulic Fracturing 14.7 3.3 0.9 0.0 0.6 0.6 - 0.1 0.0 Lateral/Gathering Line Compressors

 652.6 759.0 40.2 0.4 10.7 10.7 - 15.6 431.2 

Loading Emissions - - 110.3 - - - 0.0 0.9 7.3 Mud Degassing - - 159.1 - - - 0.2 0.0 205.5 Pneumatic Devices - - 15,046.4 - - - 12.4 6.8 34,160.3 Produced Water - - - - - - - - - Well Completions 11.7 62.1 143.2 5.5 - - - 6.7 172.7 Wellhead Compressor Engines 1,698.5 1,859.7 117.3 1.1 27.2 27.2 - 41.2 1,254.6 Western Gulf 142,581.7 187,678.0 433,119.4 8,495.6 2,425.3 2,419.9 1,010 6,969.1 566,775.2 Artificial Lift Engines 7,071.5 10,934.3 92.2 1.8 60.5 60.5 - 71.2 716.5 Blowdowns - - 12,719.8 1.0 - - - 33.6 62,538.4 Casinghead Gas Venting 0.4 2.3 5,568.6 5,674.2 - - - 26.5 7,785.8 Condensate Tanks 355.0 1,876.6 232,906.5 - - - - 2,506.4 93,676.2 Crude Oil Tanks 6.7 35.2 69,960.2 2,604.2 - - - 1,694.1 9,793.1 Dehydrators 0.0 0.0 104.5 - 0.0 0.0 - 114.0 119.2 Drill Rigs 4,611.3 1,163.1 274.8 9.1 185.3 180.1 - 34.0 4.4 Fugitives - - 13,142.9 - - - 228.5 67.0 34,670.8 Gas-Actuated Pumps - - 4,658.8 - - - 58.6 20.4 12,461.9 Heaters 9,973.7 8,377.9 548.6 0.0 758.0 758.0 - 76.8 229.4 Hydraulic Fracturing 163.4 36.9 10.3 0.3 6.4 6.2 - 1.3 0.2 
December 2012 

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Basin/Source Category 

 2011 Emissions (Tons per year) 

 NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

Lateral/Gathering Line Compressors

 8,920.8 12,806.4 254.7 3.2 94.7 94.7 - 124.8 2,478.2 

Loading Emissions - - 4,084.2 - - - 0.0 45.7 122.0 Mud Degassing - - 3,579.7 - - - 44.9 14.8 9,296.2 Pneumatic Devices - - 70,510.7 - - - 622.1 264.0 257,480.2 Produced Water - - 7,513.8 - - - 55.9 26.2 25,744.1 Well Completions 16.6 87.6 2,934.5 154.8 - - - 23.8 6,517.7 Wellhead Compressor Engines 111,462.4 152,357.7 4,254.4 46.9 1,320.5 1,320.5 - 1,824.6 43,141.0 Grand Total (rounded to the nearest whole number)

 836,191 1,092,020 1,616,981 21,110 17,406 17,374 8,002 28,891 3,708,820

Emissions for the regional portion of each basin within each CenSARA State are shown in Table 7-2. Table 7-2. Emissions Inventory for 2011 oil and gas sources in CenSARA States. 

Basin/Source Category

2011 Emissions (Tons per year)

NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

AR 9,048.5 6,482.1 9,227.7 169.5 289.6 286.4 204.8 231.4 136,216.5 Arkoma Basin 7,682.3 5,093.8 5,593.4 7.1 230.8 227.9 0.3 129.3 130,901.3 Illinois Basin 15.3 13.5 15.6 0.0 0.4 0.4 0.0 0.3 372.7 Louisiana-Mississippi Salt Basins 1,350.9 1,374.7 3,618.6 162.5 58.4 58.1 204.6 101.8 4,942.5 Ozark Uplift - - - - - - - - - KS 79,531.7 104,801.3 208,158.0 145.5 2,172.8 2,172.1 354.9 2,128.9 548,165.2 Anadarko Basin 31,393.4 39,462.1 99,226.2 23.7 1,153.5 1,153.4 18.7 1,109.0 261,528.0 Cambridge Arch-Central Kansas Uplift 8,814.5 11,000.5 31,512.0 2.2 274.6 274.3 0.0 164.7 79,331.9 Cherokee Platform 19,295.5 25,686.3 36,924.6 114.4 415.2 415.1 314.0 424.5 131,460.5 
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Basin/Source Category

2011 Emissions (Tons per year)

NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

Forest City Basin 4,313.7 6,048.6 7,891.5 1.0 88.5 88.4 11.4 57.1 18,637.9 Nemaha Uplift 3,684.5 5,180.9 6,704.2 0.9 76.1 76.0 10.0 50.8 15,111.9 Salina Basin 82.2 85.6 535.6 0.0 4.1 4.1 0.8 1.8 967.6 Sedgwick Basin 11,948.0 17,337.3 25,363.9 3.3 160.8 160.7 0.0 321.0 41,127.4 LA 42,316.2 52,600.5 103,011.3 3,172.4 1,092.8 1,089.5 1,324 2,643.2 205,568.8 Louisiana-Mississippi Salt Basins 38,481.1 47,681.0 36,722.2 296.2 995.5 992.5 1,199 1,624.4 153,658.4 Western Gulf 3,835.1 4,919.5 66,289.1 2,876.2 97.3 97.1 124.8 1,018.9 51,910.4 MO 16.7 23.5 57.4 1.6 0.4 0.4 0.1 0.8 73.3 Cherokee Platform 2.5 3.4 18.9 1.6 0.1 0.1 0.1 0.4 11.5 Forest City Basin 14.2 20.1 38.6 0.0 0.3 0.3 0.0 0.4 61.9 Illinois Basin - - - - - - - - - Ozark Uplift - - - - - - - - - NE 2,089.7 2,952.8 16,305.9 0.6 29.4 29.4 0.2 99.0 19,418.6 Cambridge Arch-Central Kansas Uplift 525.5 728.3 8,281.7 0.2 8.2 8.2 0.0 45.1 7,092.5 Denver Basin 1,547.2 2,203.1 7,693.4 0.4 20.8 20.8 0.2 52.4 11,984.2 Forest City Basin 17.0 21.4 256.1 0.0 0.4 0.4 0.0 1.1 315.0 Nemaha Uplift - - - - - - - - - Salina Basin - - 74.7 - - - - 0.4 27.0 OK 71,339.9 88,497.6 198,543.7 533.2 2,069.6 2,067.4 354.3 2,731.2 617,260.1 Anadarko Basin 33,265.4 40,916.0 103,940.2 30.4 1,213.8 1,212.1 19.5 1,515.5 259,066.3 Arkoma Basin 7,933.2 7,368.0 10,680.2 10.2 197.8 197.4 3.2 211.5 163,325.1 Bend Arch-Fort Worth Basin 39.8 45.2 240.5 9.7 1.7 1.7 3.1 3.1 298.8 Cherokee Platform 17,018.4 22,800.2 37,007.3 451.4 376.1 376.0 306.0 477.1 108,565.1 Nemaha Uplift 5,396.9 7,686.1 15,997.6 1.4 82.0 82.0 4.8 141.5 28,671.5 Palo Duro Basin 194.5 258.8 385.7 3.4 3.6 3.6 0.9 5.6 1,279.8 
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Basin/Source Category

2011 Emissions (Tons per year)

NOx CO VOC SO2 PM10 PM2.5 H2S HAPs CH4

Southern Oklahoma 7,491.5 9,423.2 30,292.2 26.7 194.7 194.6 16.7 377.0 56,053.5 TX 631,848 836,662 1,081,677 17,087 11,751 11,729 5,764 21,056 2,182,117 Anadarko Basin 44,293.0 53,266.4 69,899.1 35.0 1,400.6 1,396.0 10.7 1,463.1 187,888.6 Bend Arch-Fort Worth Basin 143,992 189,165.7 147,405.8 1,657.6 2,467.2 2,463.1 1,102 3,096.3 458,243.6 East Texas Basin 128,840 171,678.3 100,631.5 944.4 1,975.3 1,972.9 439.8 3,417.4 364,708.0 Marathon Thrust Belt 3,863.2 5,585.2 4,525.2 1.6 51.9 51.9 0.5 64.8 13,172.8 Palo Duro Basin 5,684.7 7,626.1 6,184.3 203.4 91.2 91.2 36.9 154.0 16,698.2 Permian Basin 166,428 226,582.7 386,201.5 8,625.6 3,437.3 3,431.6 3,288 6,910.9 626,541.9 Western Gulf 138,746 182,758.4 366,830.3 5,619.4 2,327.9 2,322.9 885.2 5,950.2 514,864.8 Total CenSARA domain (rounded to the nearest whole number)

 836,191 1,092,020 1,616,981 21,110 17,406 17,374 8,002 28,891 3,708,820 
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7.2 Discussion 

7.2.1 Major oil and gas area sources 

Oil and gas activities in the upstream sector often involve the use of internal combustion 

engines and external combustion equipment during the drilling and production phases such as 

compressor engines, drilling rigs, artificial lift engines, heaters, etc. Hence, several major 

sources of NOx emissions can be found in this sector. The CenSARA 2011 inventories suggest 

that in almost every basin, wellhead compressor engines are the largest source of NOx 

emissions across the CenSARA domain, representing on average at least 50% of the total basinlevel NOx emissions in some of the basins such as Permian, Western Gulf, Anadarko, Bend Arch 

Fort Worth and East Texas. NOx sources are shown in Figure 7-1 for each basin. 

Figure 7-1. NOx emissions by source category (in tons per year). 

Lateral compressors are another major source of NOx in the CenSARA region. NOx compressor 

emissions are generally large in older gas producing basins that have lower wellhead pressures 

and thus higher compression requirements. The compression requirements of a basin are 

reflected in the usage fraction of wellhead compressors and lateral compressors which varies 

significantly by basin. For wellhead compression, this can range from 8 percent of wells 

requiring wellhead compressors in the Louisiana Mississippi Salt Flats to 99 percent of wells 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

NOx Emission (TPY) 

WELL COMPLETIONS

WELLHEAD

COMPRESSOR ENGINES

CASINGHEAD GAS

VENTING

LATERAL/GATHERING

LINE COMPRESSORS

CRUDE OIL TANKS

HYDRAULIC

FRACTURING

HEATERS

BLOWDOWNS

DRILL RIGS

DEHYDRATORS

CONDENSATE TANKS

ARTIFICIAL LIFT

ENGINES Basin 
December 2012 

118 

requiring wellhead compression in some counties in Texas. Usage of lateral compressors is less 

common with usage fractions ranging from two percent in the Salt Flats to 8 percent in 

Anadarko. Heaters also appear to be a major source of NOx emissions in the region, especially 

in the oil producing basins where this equipment is more commonly used. Vented gas sources 

in Figure 7-1 can have associated NOx emissions when flaring or other combustion-device 

controls are applied. In the current inventories, flaring emissions are embedded in many 

venting source categories such as well completions, condensate tanks, crude oil tanks, 

blowdowns and dehydrators. 

VOCs emissions from venting and fugitives are commonly emitted in upstream oil and gas 

operations. Other sources of VOCs include incomplete fuel combustion in equipment such as 

engines and flares, but emissions from these are very minimal compared to direct sources. The 

distribution of VOCs emissions by source category within each basin is shown in Figure 7-2. 

Figure 7-2. VOCs emissions by source category (in tons per year). 

Major sources of VOC emissions vary greatly by basin. Results suggest that the distribution of 

VOC emissions amongst area sources is highly dependent on regional factors of the oil and gas 

producing regions that describe their production and operations, that is, the concentration of 

VOCs in the produced gas, the amount of condensate production, the level of crude oil 

production, regional controls for venting sources, etc. One source that appears to be 

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

VOCs emissions (TPY) 

WELLHEAD COMPRESSOR

ENGINES

WELL COMPLETIONS

PRODUCED WATER

HEATERS

MUD DEGASSING

LOADING EMISSIONS

CASINGHEAD GAS VENTING

LATERAL/GATHERING LINE

COMPRESSORS

HYDRAULIC FRACTURING

DRILL RIGS

DEHYDRATORS

GAS-ACTUATED PUMPS

FUGITIVES

BLOWDOWNS

PNEUMATIC DEVICES

CONDENSATE TANKS

CRUDE OIL TANKS

Basin 
December 2012 

119 

consistently significant for VOCs among all basins is pneumatic devices. The use of nobleed/low-bleed devices in each basin plays an important role in the level of VOC emissions 

from this source. This source is also driven by the well counts of each basin and the amount of 

VOCs in the gas. For example, the Anadarko, Western Gulf, Permian and Bend Arch-Fort Worth 

Basins have the largest numbers of active wells within the CenSARA domain, and thus show a 

large portion of basin-wide VOC emissions coming from pneumatic devices. Another important 

source of VOCs is related to tank losses for the storage of condensate and crude oil. This is 

particularly relevant in basins with significant condensate and crude oil production such as 

Permian, Anadarko and Western Gulf. Basin-wide venting emissions from sources such as 

these, along with well completions, blowdowns and dehydrators can be significantly reduced by 

regional practices on the use of controls involving capture and flaring. Some basins were found 

through the surveys to commonly control tank emissions by flare, such as Anadarko and 

Arkoma. Similarly, high concentrations of non-methane hydrocarbons in the produced gas from 

a basin can generally have a large impact on the overall VOC emissions of that region; thus, 

basins like Arkoma and Louisiana Mississippi Salt Flats which produce large amounts of dry gas 

(shale gas from the Fayetteville Shale and Haynesville Shale) have a limited amount of VOCs 

emissions due to the low concentration of these pollutants in the gas. 

Methane is a gas species commonly emitted by area sources in natural gas production facilities 

since it makes up the bulk of the mass of the produced gas. Similar to VOCs, the majority of 

methane emissions are originated by direct sources such as vented gas from blowdowns, well 

completions, pneumatic devices, gas actuated pumps, and fugitives. Unless capturing or flaring 

methods are used, these direct sources can release a significant amount of methane. Figure 7-3 

shows all sources of methane for each of the CenSARA basins. Results suggest that pneumatic 

devices are commonly the largest source of methane emissions across all basins. This is 

comparable to VOC emissions, as pneumatic devices bleed the produced gas which contains 

both methane and VOC pollutants. Another major source of methane appears to be blowdowns 

and fugitives which are also direct sources. Blowdown emissions are driven by gas well counts 

and basin specific vent rates, hence basins that have a substantial number of active gas wells 

such as Anadarko, Arkoma and Western Gulf, among others, show large methane emissions for 

this source. 
December 2012 

120 

Figure 7-3. Methane emissions by source category (in tons per year). 

7.2.2 Data Gap Findings 

A series of data gaps have been identified during the development of this regional inventory 

which affect the quality of emissions estimates. There is an ongoing need for additional 

information at the basin level on equipment and activities related to oil and gas area emissions 

sources to address data gaps. Data gaps include information on equipment usage and size, local 

gas compositions, usage of control methods, venting rates for particular sources, etc. 

Given the scope and resources of this Project, not all basins in the CenSARA region were part of 

the industry survey outreach and thus, those basins for which local data could not be gathered 

through industry surveys or any other means like permit data, were based on national default 

literature values or regional averages of other basins (as delineated in Section 5.3.2). Similarly, 

a defined set of source categories were included in the surveys, those considered significant 

sources of air pollutants or “high-tier”, thus availability of local data for the remaining “lowtier” source categories was limited. Table 7-3 provides an assessment on the quality of the 

input data used to estimate emissions for key sources identified in this inventory. This 

evaluation is qualitative and based on the level of representativeness that each data input is 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

Methane emissions (TPY) 

WELLHEAD COMPRESSOR

ENGINES

PRODUCED WATER

HEATERS

LOADING EMISSIONS

LATERAL/GATHERING LINE

COMPRESSORS

HYDRAULIC FRACTURING

CONDENSATE TANKS

DRILL RIGS

CRUDE OIL TANKS

ARTIFICIAL LIFT ENGINES

MUD DEGASSING

WELL COMPLETIONS

DEHYDRATORS

GAS-ACTUATED PUMPS

CASINGHEAD GAS

VENTING

PNEUMATIC DEVICES

BLOWDOWNS

FUGITIVES
December 2012 

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believed to have for the basin it was applied to. The following classifications have been made to 

evaluate input data: 

x High: Data based on a significant number of useful survey entries for a particular source 

category and data field; or data obtained from the compilation of local data through state 

air agencies’ determinations. 

x Medium: Data based on a limited number of survey entries for a particular source category 

and data field; or data obtained through the compilation and averaging of data from minor 

source permit applications. Permit applications were available for minor sources located at 

specific basins, and thus data from this information source was regionally representative, 

although it may present the caveats of permit data (conservative assumptions, year of 

permit, etc.). 

x Low: Data based on averages of all industry survey data available for a particular source 

category and data field regardless of the geographical specificity; or data based on default 

values derived from other regional or national emissions inventory studies. 

The analysis in Table 7-3 includes each of the surveyed basins, as well as the non-surveyed 

basins which are divided in two distinctive groups: “other basins in Texas (except Permian and 

Marathon Thrust Belt)”, and “non-surveyed basins outside of Texas”. As explained in Section 

5.3.2, input data was managed differently for basins in each of these two groups; for instance, 

basin-specific averaging rules (Table 5-5) were applied to data fields for non-surveyed basins 

outside of Texas. Nevertheless, input values for basins in this group were derived from regional 

averages and thus fall under the “low” quality input data classification. The Marathon Thrust 

Belt is a small basin bordering south of the Permian and it is assumed to have very similar 

operational characteristics to it, thus, MTB data is assumed to be equivalent to that of the 

Permian basin, which may qualify from high to low depending on the source of data for 

Permian. For “other basins in Texas”, data sources varied on a case by case basis. Many source 

categories inventoried in this study have not yet been included in previous Texas inventories 

and thus averages of survey data were applied in these cases, while when regional data from 

other studies were available, these were used. Based on this, Texas’ basins input data may be 

classified under the various designations shown above. 
December 2012 

122 

Table 7-3. Quality assessment of input data used to estimate emissions for each area source category and basin in CenSARA. 

Source Category Data field/Inputs 

Anadarko Basin 

Arkoma Basin 

Cambridge ArchCentral Kansas Uplift 

Permian Basin (and Marathon Thrust Belt) 

LouisianaMississippi Salt Basins 

Sedgwick Basin 

Other basins in Texas (except Permian and MTB) 

Nonsurveyed basins outside of Texas 

ARTIFICIAL LIFT ENGINES 

Fraction of oil wells with artificial lift engines high low high low medium medium low low 

ARTIFICIAL LIFT ENGINES Rated Horsepower high low high low medium high high low ARTIFICIAL LIFT ENGINES Annual Activity (hours/yr) high medium high low medium high high low ARTIFICIAL LIFT ENGINES Load Factor high low high low medium high high low ARTIFICIAL LIFT ENGINES % of artificial lift engines that are 

electrified medium low high low medium medium high low 

ARTIFICIAL LIFT ENGINES Emissions Factors (g/hp-hr) low low low low low low high low WELLHEAD COMPRESSORS 

Fraction of wells with wellhead compressors high medium low medium medium low low low 

WELLHEAD COMPRESSORS Annual Activity (hr) high medium low low medium medium high low WELLHEAD COMPRESSORS 

Fraction Rich Burn (RB) versus Lean Burn (LB) medium medium low medium low low high low 

WELLHEAD COMPRESSORS - LEAN LB Rated Horsepower high medium low low low low high low WELLHEAD COMPRESSORS - LEAN LB Load Factor low medium low low low low high low WELLHEAD COMPRESSORS - LEAN % LB Engines Controlled medium medium low low low low high low WELLHEAD COMPRESSORS - LEAN CO Control Factor Cat. Oxidizer low low low low low low high low WELLHEAD COMPRESSORS - LEAN LB Emissions Factors (g/hp-hr) low low low low low low high low WELLHEAD COMPRESSORS - RICH RB Rated Horsepower high medium low low medium low high low WELLHEAD COMPRESSORS - RICH RB Load Factor medium medium low low medium low high low WELLHEAD COMPRESSORS - RICH % RB Engines Controlled medium medium low low low low high low WELLHEAD COMPRESSORS - RICH NOx, CO Control Factor NSCR medium medium low low low low high low WELLHEAD COMPRESSORS - RICH VOC Control Factor NSCR medium medium low low low low high low WELLHEAD COMPRESSORS - RICH RB Emissions Factors (g/hp-hr) low low low low low low high low 
December 2012 

123 

Source Category Data field/Inputs 

Anadarko Basin 

Arkoma Basin 

Cambridge ArchCentral Kansas Uplift 

Permian Basin (and Marathon Thrust Belt) 

LouisianaMississippi Salt Basins 

Sedgwick Basin 

Other basins in Texas (except Permian and MTB) 

Nonsurveyed basins outside of Texas 

LATERAL/GATHERING COMPRESSORS 

No. wells served by a single lateral compressor medium medium medium low medium low low low 

LATERAL/GATHERING COMPRESSORS Annual Activity (hr) medium medium medium low medium low low low LATERAL/GATHERING COMPRESSORS 

Fraction Rich Burn (RB) versus Lean Burn (LB) medium medium low low medium low low low 

LATERAL/GATHERING COMPRESSORS - LEAN BURN LB Rated Horsepower medium low medium low low low low low LATERAL/GATHERING COMPRESSORS - LEAN BURN LB Load Factor medium medium medium low medium low low low LATERAL/GATHERING COMPRESSORS - LEAN BURN % LB Engines Controlled medium medium low low medium low low low LATERAL/GATHERING COMPRESSORS - LEAN BURN CO Control Factor Cat. Oxidizer low low low low low low low low LATERAL/GATHERING COMPRESSORS - LEAN BURN LB Emissions Factors (g/hp-hr) low low low low low low low low LATERAL/GATHERING COMPRESSORS - RICH BURN RB Rated Horsepower low medium medium low medium low low low LATERAL/GATHERING COMPRESSORS - RICH BURN RB Load Factor low low medium low low low low low LATERAL/GATHERING COMPRESSORS - RICH BURN % RB Engines Controlled medium medium low low medium low low low LATERAL/GATHERING COMPRESSORS - RICH BURN NOx, CO Control Factor NSCR medium medium low low medium low low low LATERAL/GATHERING COMPRESSORS - RICH BURN VOC Control Factor NSCR medium medium low low medium low low low LATERAL/GATHERING COMPRESSORS - RICH BURN RB Emissions Factors (g/hp-hr) low low low low low low low low 
December 2012 

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Source Category Data field/Inputs 

Anadarko Basin 

Arkoma Basin 

Cambridge ArchCentral Kansas Uplift 

Permian Basin (and Marathon Thrust Belt) 

LouisianaMississippi Salt Basins 

Sedgwick Basin 

Other basins in Texas (except Permian and MTB) 

Nonsurveyed basins outside of Texas 

DRILLING RIGS 

Fraction of drill-rigs that are dieselelectric medium low low low low low low low 

DRILLING RIGS 

Individual data on engines for horizontal and vertical drilling medium medium low low low low low low 

DRILLING RIGS Number of engines per rig high high medium low medium low low low DRILLING RIGS Depth per spud (ft) medium medium medium low medium low low low DRILLING RIGS 

Rated Horsepower (hp) for each engine high high medium low medium low low low 

DRILLING RIGS Load Factors medium medium medium low medium low low low DRILLING RIGS Hours of use (hr/spud) per engine medium medium medium low medium low low low DRILLING RIGS Emissions Factors (g/hp-hr) medium medium medium medium medium medium medium medium CONDENSATE TANKS Fraction of Production to Tanks low low low low low low low low CONDENSATE TANKS Fraction of Tanks Flared high medium low low medium low low low CONDENSATE TANKS VOC Fraction of the flash gas medium medium medium low medium medium low low CONDENSATE TANKS 

Average losses per unit throughput (lb-VOC/bbl of condensate) high medium medium high medium medium high low 

CONDENSATE TANKS 

Condensate tank flash gas composition medium medium medium low medium medium low low 

WELL COMPLETIONS 

Volume of Gas Vented Per Completion (MCF/event) uncontrolled medium high high low medium low low low 

WELL COMPLETIONS Fraction of Completions with Flaring medium high high low medium low low low WELL COMPLETIONS 

Fraction of Completions with Green Completion medium high high low medium low low low 

WELL COMPLETIONS Flaring Control Efficiency (%) low high high low low low low low WELL COMPLETIONS Flaring Capture Efficiency (%) low high high low low low low low 
December 2012 

125 

Source Category Data field/Inputs 

Anadarko Basin 

Arkoma Basin 

Cambridge ArchCentral Kansas Uplift 

Permian Basin (and Marathon Thrust Belt) 

LouisianaMississippi Salt Basins 

Sedgwick Basin 

Other basins in Texas (except Permian and MTB) 

Nonsurveyed basins outside of Texas 

WELL COMPLETIONS 

Criteria pollutant and GHGs speciation of vented gas high high high medium high high low low 

WELL COMPLETIONS HAPS speciation of vented gas medium low low low medium low low low WELL COMPLETIONS Local Heating Value (BTU/SCF) medium high high low medium low low low WELL COMPLETIONS Molecular Weight of the Gas medium low low low medium low low low HYDRAULIC FRACTURING Rated Horsepower low medium medium low low low low low HYDRAULIC FRACTURING Load Factor low medium low low low low low low HYDRAULIC FRACTURING No. Stages per Well (stages/well) low medium medium low low low low low HYDRAULIC FRACTURING Duration per Stage (hr/stage) low medium medium low low low low low HYDRAULIC FRACTURING No. Engines Used per Fracing Event low medium medium low low low low low HYDRAULIC FRACTURING Total HP-HR per well medium medium medium low low low low low BLOWDOWNS 

Average Blowdown Frequency (events/well-year) medium medium low medium medium medium low low 

BLOWDOWNS 

Volume of Gas Vented Per Blowdown (MCF/event) uncontrolled medium medium low medium medium medium low low 

BLOWDOWNS 

Fraction of Blowdowns that are Controlled medium medium low medium low low low low 

BLOWDOWNS Control Method Efficiency (%) low low low low low low low low BLOWDOWNS 

Criteria pollutant and GHGs speciation of vented gas high high high medium high high low low 

BLOWDOWNS HAPS speciation of vented gas medium low low low medium low low low CASING GAS 

Venting Rate of Casing Gas per Unit of Oil Production (MCF/bbl) medium low medium low low medium low low 

CASING GAS 

Fraction of Vents Controlled by Flaring (Fflare) low low medium low low medium low low 
December 2012 

126 

Source Category Data field/Inputs 

Anadarko Basin 

Arkoma Basin 

Cambridge ArchCentral Kansas Uplift 

Permian Basin (and Marathon Thrust Belt) 

LouisianaMississippi Salt Basins 

Sedgwick Basin 

Other basins in Texas (except Permian and MTB) 

Nonsurveyed basins outside of Texas 

CASING GAS Flaring Control Efficiency (%) low low low low low low low low CASING GAS Flaring Capture Efficiency (%) low low low low low low low low PNEUMATIC DEVICES 

No. of Devices by Bleed Rate Classification medium medium low medium medium low low low 

PNEUMATIC DEVICES Bleed Rates (by device) low low low low low low low low PNEUMATIC DEVICES 

Criteria pollutant and GHGs speciation of vented gas high high high medium high high low low 

PNEUMATIC DEVICES HAPS speciation of vented gas medium low low low medium low low low DEHYDRATORS Fraction of Dehydrators with Flares low low low low low low low low DEHYDRATORS 

Still Vent VOC Emissions (lbVOC/MMSCF) medium medium medium low medium medium low low 

DEHYDRATORS Heater MMBTU Rating (MMBTU/hr) medium medium medium low low low low low DEHYDRATORS Local Heating Value (BTU/SCF) medium medium medium low medium medium low low DEHYDRATORS Annual Heater Usage (hr) medium medium medium low low low low low DEHYDRATORS Dehydrator still vent gas speciation low low low low low low low low DEHYDRATORS 

Dehydrator reboiler emissions factors (lb/MMSCF) low low low low low low low low 

CRUDE TANKS Fraction of Production to Tanks low low low low low low low low CRUDE TANKS Fraction of Tanks Flared medium medium medium medium medium medium low low CRUDE TANKS 

Average Loss Emissions (lbVOC/bbl) medium medium medium low medium medium low low 

CRUDE TANKS Local Heating Value (BTU/SCF) medium medium low low medium low low low CRUDE TANKS VOC fraction of the gas medium medium low low medium low low low CRUDE TANKS Molecular weight of the gas medium medium low low medium low low low CRUDE TANKS 

Oil tank losses gas analysis - Criteria Pollutants and GHGs medium medium low low medium low low low 
December 2012 

127 

Source Category Data field/Inputs 

Anadarko Basin 

Arkoma Basin 

Cambridge ArchCentral Kansas Uplift 

Permian Basin (and Marathon Thrust Belt) 

LouisianaMississippi Salt Basins 

Sedgwick Basin 

Other basins in Texas (except Permian and MTB) 

Nonsurveyed basins outside of Texas 

CRUDE TANKS 

Oil tank losses gas analysis - HAPs speciation low medium low low medium low low low 

GAS-ACTUATED PUMPS 

Kimray pumps venting rate per unit throughput (SCF-CH4/MMSCF gas) low low low low low low low low 

GAS-ACTUATED PUMPS 

Annual gas pumped per well (MMSCF/yr/well) low low low low low low low low 

GAS-ACTUATED PUMPS 

Chemical injection pump venting rate per pump (SCF-CH4/pump/day) low low low low low low low low 

GAS-ACTUATED PUMPS 

Average number of pumps per gas/oil well low low low low low low low low 

GAS-ACTUATED PUMPS 

Criteria pollutant and GHGs speciation of vented gas high high high medium high high low low 

GAS-ACTUATED PUMPS HAPS speciation of vented gas medium low low low medium low low low FUGITIVES 

No. of devices per typical well by device type and by service medium medium medium medium medium low low low 

FUGITIVES 

Pollutant to TOC fraction in leaked gas - criteria pollutants and GHGs high high high medium high high low low 

FUGITIVES 

Pollutant to TOC fraction in leaked gas - HAPs medium low low low medium low low low 

FUGITIVES 

Compressor seals leaking rate per engine (SCF-CH4/hr/compressor) low low low low low low low low 

FUGITIVES 

Fraction of wells serviced by wellhead compressors high medium low medium medium low low low 

FUGITIVES 

No. wells served by single lateral compressor [wells/compressor] medium medium medium low medium low low low 

FUGITIVES Annual Activity (hr) low low low low low low low low 
December 2012 

128 

Data fields with “low quality” designation would benefit from further research and collection of 

operator data. These fields are generally in source categories that, individually, are not the 

most significant area sources of key pollutants (VOC, NOx) but combined provide a significant 

emissions contribution to area source inventories. These data are also generally poorly 

characterized at the basin level in many oil and gas inventories, thus making it difficult to find 

regionally-representative data in the literature. 

The quality of survey data was greatly affected by the level of response from operators. This is 

not only manifested through the number of operators that returned survey forms for each 

basin, but also by the actual number of survey data requests that were completed and proved 

useful towards deriving basin-wide input values. Some source categories received a larger 

number of responses than others, and this in addition varied by basin. Surveys for artificial lifts, 

drilling rigs, wellhead compressors, condensate tanks, and well completions yielded a good 

level of responsiveness in terms of participating companies and the amount of data provided. 

Other source categories did not have such a good response rate, such as dehydrators, lateral 

compressors and hydraulic fracturing pumps. Moreover, with some source categories surveys 

only partially completed, certain data fields within a source category yielded different levels of 

response and quality than other fields. This suggests the importance of survey outreach to be 

wide-ranging and supported by incentives for operators to fully collaborate in the provision of 

high quality and complete data. 

Results suggest much of VOC and HAPs are generated by direct emissions from venting and 

fugitive sources, thus speciation of the local gas is essential to accurately characterize those 

emissions. This requires the compilation of local gas compositions at various points throughout 

natural gas and oil systems where these emissions occur; for example wellhead venting, piping 

and equipment emissions at the well-site, flashing and breathing emissions from oil/condensate 

tanks, and venting from gas dehydration. Gas analyses for vented gas from tanks and 

dehydrators are scarce and highly dependent on the basin where the gas is produced, thus it is 

imperative data is compiled by basin. 

7.2.3 Future work opportunities 

Many source categories would benefit from future work that aims at collecting updated 

regional field level data for certain sources within the CenSARA domain. Improvements are 

needed to better understand emissions from source categories associated with hydraulic 

fracturing such as well completions and frac pump engines as this region houses several key 

unconventional gas resources that require hydraulic fracturing. Available oil and gas emissions 

studies suggest that fugitive emissions are also not well characterized and regional and detailed 

emissions factors are yet to be developed for this source. Fugitive leaking rates used in this 

inventory and commonly used in other available inventories are based on EPA and GRI studies 

from the 1990’s and may not be representative of conditions at many unconventional gas wells. 

Additional research is needed to improve these fugitive emissions factors. Produced water is 

perhaps one of the most poorly understood source categories. This includes holding ponds or 

tanks, evaporation ponds, and wastewater disposal facilities. Evolution of VOC emissions from 

produced water may be a significantly underestimated source category in the CenSARA domain, 
December 2012 

129 

especially in those basins housing shale gas plays where water consumption and production is 

high. In addition, water production statistics are not recorded consistently throughout all 

CenSARA states, thus restricting the ability of characterizing produced water emissions at the 

basin-level. Mud degassing is another poorly-understood VOC emissions source. The recent 

EPA Subpart W reporting requirements for GHG emissions from oil and gas systems could yield 

significant quantities of detailed data on equipment, processes and gas compositions that could 

be used to extract regionally specific data on this source (and many others) within the CenSARA 

domain. 

A survey outreach is a recommended method to collecting data; however the efficacy of data 

collection will always be tied to the level of responsiveness and collaboration from oil and gas 

operators. Thus it is imperative that state agencies provide incentives and support to surveyed 

companies to encourage their participation. Certain key categories could benefit from 

additional information, particularly usage fractions of wellhead and lateral compressors within 

certain basins, manufacturer emissions factors for stationary compressors, and engine 

configurations and usage data for drilling rigs. For VOC emissions source categories, fugitive 

emissions represent one of the least studied emissions sources. It should be noted that 

significant quantity and detail of data on equipment, usage, configuration, and processes has 

now been gathered for the first time by EPA as part of Subpart W reporting of GHG emissions 

by oil and gas companies. To the extent that this data is made available to state agencies or the 

public for use in future emissions inventories, it may allow for checks on assumptions used in 

this inventory as well as revisions to lower quality input data. 

Direct measurement of emissions rates and derivation of emissions factors from measured or 

monitored data is likely to produce accurate and regionally specific data but it is often not 

feasible to conduct this type of data collection from a large group of sources operating in a 

broad geographic region. When possible, direct measurement studies could be conducted to 

further characterize basin-wide average emission factors. 
December 2012 

130 

8.0 CONCLUSIONS 

Oil and gas area source emissions inventories were developed in this work for oil and gas 

producing states within the CenSARA region. These inventories included a substantial level of 

detail in terms of geographical specificity (detail by basin, state and county), in the array of 

pollutants included (16 total) and the number of source categories analyzed (18 area sources, 

34 SCCs). The development of detailed emissions inventories by source category led to several 

key conclusions: 

x NOx emissions are dominated by wellhead compressors, particularly for gas producing 

basins with a large number of active gas wells; 

x Other significant sources of NOx include lateral compressors and heaters, followed by 

drilling rigs and artificial lift engines; 

x Other NOx emissions sources (e.g. flaring of vented sources and hydraulic fracturing 

engines) do not appear to contribute significantly to NOx emissions across the CenSARA 

domain; 

x Pneumatic devices are the most significant source of VOC and methane emissions in most 

basins. In basins where the production of condensate and crude oil is extraordinary 

(Permian and Western Gulf), VOC emissions are dominated by condensate tank and crude 

oil tank losses; 

x The VOC fraction of the gas and the use of flaring controls appear to be key variables in 

determining total VOC emissions with a basin (Arkoma, for example, has low VOC emissions 

relative to its substantial gas production, due to the low VOC content of the gas and flaring 

controls on condensate tanks). 

x Other significant VOC and methane emissions source categories include blowdowns, 

fugitive emissions and wellhead compressor engine exhaust gas, particularly from lean burn 

compressor engines. 

A series of data gaps were identified during the development of this work that ultimately affect 

the quality of emissions estimates in the inventory. This is related to an ongoing need for 

additional information at the basin level for equipment and activities specific to that basin’s oil 

and gas area emissions sources. Some of the surveyed basin response levels in this work were 

relatively thorough while others were incomplete or not surveyed at all. Many source 

categories would benefit from future work that aims at collecting additional regional or basinlevel data within the CenSARA domain. Work is also needed to better characterize emissions 

from source categories not surveyed in this study including fugitives, mud degassing and 

produced water . Future efforts should target gathering basin specific data so that higher 

quality calculation inputs may be developed and applied in the Emissions Calculator Tool 

developed here, enabling an effective and more accurate estimation of future year inventories 

for the CenSARA domain. 
December 2012 

131 

9.0 REFERENCES 

Bar-Ilan, A., R. Parikh, J. Grant, T. Shah, and A. Pollack. 2008. “Recommendations for 

Improvements to the CENRAP States’ Oil and Gas Emissions Inventories.” ENVIRON. 

Accessed online at: http://www.wrapair.org/forums/ogwg/documents/2008-

11_CENRAP_O&G_Report_11-13.pdf 

Drillinginfo, Inc. 2012. “DI Desktop Database powered by HPDI.” Internet address: 

http://www.didesktop.com/

Eastern Research Group, 2009. “Drilling Rig Emission Inventory for the State of Texas.” Final 

Report. Prepared for Texas Commission on Environmental Quality (TCEQ). Accessed 

online at: 

http://www.tceq.state.tx.us/assets/public/implementation/air/am/contracts/reports/ei

/5820783985FY0901-20090715-ergi-Drilling_Rig_EI.pdf

Eastern Research Group, 2010. “Characterization of Oil and Gas Production Equipment and 

Develop a Methodology to Estimate Statewide Emissions.” Final Report for the Texas 

Commission on Environmental Quality, November 24, 2010. Accessed online at: 

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

5820784003FY1026-20101124-ergi-oilGasEmissionsInventory.pdf. 

Eastern Research Group. 2012. “Condensate Tank Oil and Gas Activities.” Final Report. Prepared 

for the Texas Commission on Environmental Quality. October 10, 2012. Available online 

at: 

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

5821199776FY1211-20121031-ergi-condensate_tank.pdf

Energy Information Administration (EIA). 2012. Accessed online at: http://www.eia.gov/

ENVIRON International Corporation. 2009. “Development of Emissions Inventories for Natural 

Gas Exploration and Production Activity in the Haynesville Shale.” Draft Report to the 

Northeast Texas Air Care. , August 31, 2009. Accessed online at: 

http://www.netac.org/UserFiles/File/NETAC/9_29_09/Enclosure_2b.pdf 

ENVIRON International Corporation. 2012. “Emissions from Natural Gas Exploration and 

Production Activity in the Haynesville Shale.” Draft Report (In Progress). Prepared for 

the East Texas Council of Governments. December 19, 2012. 

The Climate Registry, 2010. “Oil and Gas Production Protocol, Annex II to the General Reporting 

Protocol, Version 1.0”. The Climate Registry, 2010. Internet address: 

http://www.theclimateregistry.org/downloads/2010/04/Final-OGP-Protocol.pdf

U.S. Environmental Protection Agency, 1991. “AP 42, Fifth Edition, Volume I, Chapter 13: 

Miscellaneous Sources, Section 13.5 Industrial Flares,” U.S. Environmental Protection 

Agency, Research Triangle Park, NC, 1991. Internet address: 

http://www.epa.gov/ttn/chief/ap42/ch13/final/c13s05.pdf 
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U.S. Environmental Protection Agency, 1995. “Protocol for Equipment Leak Emission 

Estimates,” U.S. Environmental Protection Agency, Research Triangle Park, NC, 1995. 

Internet address: http://www.epa.gov/ttn/chief/efdocs/equiplks.pdf

U.S. Environmental Protection Agency, 1998. “AP 42, Fifth Edition, Volume I, Chapter 1: External 

Combustion Sources,” U.S. Environmental Protection Agency, Research Triangle Park, 

NC, 1998. Internet address: http://www.epa.gov/ttn/chief/ap42/ch01/index.html

U.S. Environmental Protection Agency, 2000. “AP 42, Fifth Edition, Volume I, Chapter 3: 

Stationary Internal Combustion Sources,” U.S. Environmental Protection Agency, 

Research Triangle Park, NC, 2000. Internet address:

http://www.epa.gov/ttn/chief/ap42/ch03/index.html

U.S. Environmental Protection Agency, 2005. “User’s Guide for the Final NONROAD2005 

Model,” U.S. Environmental Protection Agency, Research Triangle Park, NC, 2005. EPA 

420-R-05-013. 

U.S. Environmental Protection Agency, 2006a. “Installing Plunger Lift Systems in Gas Wells.” 

Lessons Learned from Natural Gas STAR Partners. October. Accessed online at: 

http://epa.gov/gasstar/documents/ll_plungerlift.pdf

U.S. Environmental Protection Agency, 2006b. “Speciate 4.0 Speciation Database Development 

Documentation,” U.S Environmental Protection Agency, Research Triangle Park, NC, 

November 2006. EPA/600/R-06/161 

U.S. Environmental Protection Agency, 2008. “AP 42, Fifth Edition, Volume I, Chapter 5: 

Petroleum Industry, Section 5.2 Transportation and Marketing of Petroleum Liquids,” 

U.S. Environmental Protection Agency, Research Triangle Park, NC, 2008. Internet 

address: http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf

U.S. Environmental Protection Agency (EPA). 2011. “Inventory of Greenhouse Gas Emissions 

and Sinks: 1990-2009”, Washington DC, April. Accessed online at: 

http://www.epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-

Complete_Report.pdf 

U.S. Environmental Protection Agency, 2012. “Inventory of Greenhouse Gas Emissions and 

Sinks: 1990-2010,” Washington DC, April. Accessed online at: 

http://www.epa.gov/climatechange/emissions/usinventoryreport.html

Western Regional Air Partnership (WRAP). 2012. “Phase III Inventories for the Rocky Mountain 

Region.” Prepared by ENVIRON International Corporation. Basin-specific reports 

available at: http://wrapair2.org/PhaseIII.aspx
December 2012 

APPENDIX A 

CenSARA States County List 
December 2012 

A-1 

Appendix A: CenSARA States County List 

This includes counties that have not yet been assigned to a Basin. 

Table A-1. List of counties in each CenSARA State including Basin designation. 

FIPS Code State County Basin

05001 AR Arkansas Louisiana-Mississippi Salt Basins

05003 AR Ashley Louisiana-Mississippi Salt Basins

05005 AR Baxter Ozark Uplift

05007 AR Benton Ozark Uplift

05009 AR Boone Ozark Uplift

05011 AR Bradley Louisiana-Mississippi Salt Basins

05013 AR Calhoun Louisiana-Mississippi Salt Basins

05015 AR Carroll Ozark Uplift

05017 AR Chicot Louisiana-Mississippi Salt Basins

05019 AR Clark Louisiana-Mississippi Salt Basins

05021 AR Clay Illinois Basin

05023 AR Cleburne Arkoma Basin

05025 AR Cleveland Louisiana-Mississippi Salt Basins

05027 AR Columbia Louisiana-Mississippi Salt Basins

05029 AR Conway Arkoma Basin

05031 AR Craighead Illinois Basin

05033 AR Crawford Arkoma Basin

05035 AR Crittenden Illinois Basin

05037 AR Cross Illinois Basin

05039 AR Dallas Louisiana-Mississippi Salt Basins

05041 AR Desha Louisiana-Mississippi Salt Basins

05043 AR Drew Louisiana-Mississippi Salt Basins

05045 AR Faulkner Arkoma Basin

05047 AR Franklin Arkoma Basin

05049 AR Fulton Ozark Uplift

05051 AR Garland Arkoma Basin

05053 AR Grant Louisiana-Mississippi Salt Basins

05055 AR Greene Illinois Basin

05057 AR Hempstead Louisiana-Mississippi Salt Basins

05059 AR Hot Spring Louisiana-Mississippi Salt Basins

05061 AR Howard Louisiana-Mississippi Salt Basins

05063 AR Independence Arkoma Basin

05065 AR Izard Ozark Uplift

05067 AR Jackson Illinois Basin

05069 AR Jefferson Louisiana-Mississippi Salt Basins
December 2012 

A-2 

FIPS Code State County Basin

05071 AR Johnson Arkoma Basin

05073 AR Lafayette Louisiana-Mississippi Salt Basins

05075 AR Lawrence Ozark Uplift

05077 AR Lee Illinois Basin

05079 AR Lincoln Louisiana-Mississippi Salt Basins

05081 AR Little River Louisiana-Mississippi Salt Basins

05083 AR Logan Arkoma Basin

05085 AR Lonoke Arkoma Basin

05087 AR Madison Arkoma Basin

05089 AR Marion Ozark Uplift

05091 AR Miller Louisiana-Mississippi Salt Basins

05093 AR Mississippi Illinois Basin

05095 AR Monroe Illinois Basin

05097 AR Montgomery Arkoma Basin

05099 AR Nevada Louisiana-Mississippi Salt Basins

05101 AR Newton Arkoma Basin

05103 AR Ouachita Louisiana-Mississippi Salt Basins

05105 AR Perry Arkoma Basin

05107 AR Phillips Illinois Basin

05109 AR Pike Louisiana-Mississippi Salt Basins

05111 AR Poinsett Illinois Basin

05113 AR Polk Arkoma Basin

05115 AR Pope Arkoma Basin

05117 AR Prairie Arkoma Basin

05119 AR Pulaski Arkoma Basin

05121 AR Randolph Ozark Uplift

05123 AR St. Francis Illinois Basin

05125 AR Saline Arkoma Basin

05127 AR Scott Arkoma Basin

05129 AR Searcy Arkoma Basin

05131 AR Sebastian Arkoma Basin

05133 AR Sevier Louisiana-Mississippi Salt Basins

05135 AR Sharp Ozark Uplift

05137 AR Stone Arkoma Basin

05139 AR Union Louisiana-Mississippi Salt Basins

05141 AR Van Buren Arkoma Basin

05143 AR Washington Arkoma Basin

05145 AR White Arkoma Basin

05147 AR Woodruff Illinois Basin

05149 AR Yell Arkoma Basin
December 2012 

A-3 

FIPS Code State County Basin

20001 KS Allen Cherokee Platform

20003 KS Anderson Forest City Basin

20005 KS Atchison Forest City Basin

20007 KS Barber Sedgwick Basin

20009 KS Barton Cambridge Arch-Central Kansas Uplift

20011 KS Bourbon Cherokee Platform

20013 KS Brown Forest City Basin

20015 KS Butler Nemaha Uplift

20017 KS Chase Nemaha Uplift

20019 KS Chautauqua Cherokee Platform

20021 KS Cherokee Cherokee Platform

20023 KS Cheyenne Cambridge Arch-Central Kansas Uplift

20025 KS Clark Anadarko Basin

20027 KS Clay Salina Basin

20029 KS Cloud Salina Basin

20031 KS Coffey Forest City Basin

20033 KS Comanche Anadarko Basin

20035 KS Cowley Nemaha Uplift

20037 KS Crawford Cherokee Platform

20039 KS Decatur Cambridge Arch-Central Kansas Uplift

20041 KS Dickinson Salina Basin

20043 KS Doniphan Forest City Basin

20045 KS Douglas Forest City Basin

20047 KS Edwards Anadarko Basin

20049 KS Elk Cherokee Platform

20051 KS Ellis Cambridge Arch-Central Kansas Uplift

20053 KS Ellsworth Cambridge Arch-Central Kansas Uplift

20055 KS Finney Anadarko Basin

20057 KS Ford Anadarko Basin

20059 KS Franklin Forest City Basin

20061 KS Geary Nemaha Uplift

20063 KS Gove Anadarko Basin

20065 KS Graham Cambridge Arch-Central Kansas Uplift

20067 KS Grant Anadarko Basin

20069 KS Gray Anadarko Basin

20071 KS Greeley Anadarko Basin

20073 KS Greenwood Cherokee Platform

20075 KS Hamilton Anadarko Basin

20077 KS Harper Sedgwick Basin

20079 KS Harvey Sedgwick Basin
December 2012 

A-4 

FIPS Code State County Basin

20081 KS Haskell Anadarko Basin

20083 KS Hodgeman Anadarko Basin

20085 KS Jackson Forest City Basin

20087 KS Jefferson Forest City Basin

20089 KS Jewell Salina Basin

20091 KS Johnson Forest City Basin

20093 KS Kearny Anadarko Basin

20095 KS Kingman Sedgwick Basin

20097 KS Kiowa Anadarko Basin

20099 KS Labette Cherokee Platform

20101 KS Lane Anadarko Basin

20103 KS Leavenworth Forest City Basin

20105 KS Lincoln Salina Basin

20107 KS Linn Forest City Basin

20109 KS Logan Anadarko Basin

20111 KS Lyon Forest City Basin

20113 KS McPherson Sedgwick Basin

20115 KS Marion Sedgwick Basin

20117 KS Marshall Nemaha Uplift

20119 KS Meade Anadarko Basin

20121 KS Miami Forest City Basin

20123 KS Mitchell Salina Basin

20125 KS Montgomery Cherokee Platform

20127 KS Morris Nemaha Uplift

20129 KS Morton Anadarko Basin

20131 KS Nemaha Nemaha Uplift

20133 KS Neosho Cherokee Platform

20135 KS Ness Anadarko Basin

20137 KS Norton Cambridge Arch-Central Kansas Uplift

20139 KS Osage Forest City Basin

20141 KS Osborne Salina Basin

20143 KS Ottawa Salina Basin

20145 KS Pawnee Cambridge Arch-Central Kansas Uplift

20147 KS Phillips Cambridge Arch-Central Kansas Uplift

20149 KS Pottawatomie Nemaha Uplift

20151 KS Pratt Cambridge Arch-Central Kansas Uplift

20153 KS Rawlins Cambridge Arch-Central Kansas Uplift

20155 KS Reno Sedgwick Basin

20157 KS Republic Salina Basin

20159 KS Rice Cambridge Arch-Central Kansas Uplift
December 2012 

A-5 

FIPS Code State County Basin

20161 KS Riley Nemaha Uplift

20163 KS Rooks Cambridge Arch-Central Kansas Uplift

20165 KS Rush Cambridge Arch-Central Kansas Uplift

20167 KS Russell Cambridge Arch-Central Kansas Uplift

20169 KS Saline Salina Basin

20171 KS Scott Anadarko Basin

20173 KS Sedgwick Sedgwick Basin

20175 KS Seward Anadarko Basin

20177 KS Shawnee Forest City Basin

20179 KS Sheridan Cambridge Arch-Central Kansas Uplift

20181 KS Sherman Cambridge Arch-Central Kansas Uplift

20183 KS Smith Salina Basin

20185 KS Stafford Cambridge Arch-Central Kansas Uplift

20187 KS Stanton Anadarko Basin

20189 KS Stevens Anadarko Basin

20191 KS Sumner Sedgwick Basin

20193 KS Thomas Cambridge Arch-Central Kansas Uplift

20195 KS Trego Cambridge Arch-Central Kansas Uplift

20197 KS Wabaunsee Nemaha Uplift

20199 KS Wallace Anadarko Basin

20201 KS Washington Salina Basin

20203 KS Wichita Anadarko Basin

20205 KS Wilson Cherokee Platform

20207 KS Woodson Cherokee Platform

20209 KS Wyandotte Forest City Basin

22001 LA Acadia Western Gulf

22003 LA Allen Western Gulf

22005 LA Ascension Western Gulf

22007 LA Assumption Western Gulf

22009 LA Avoyelles Western Gulf

22011 LA Beauregard Western Gulf

22013 LA Bienville Louisiana-Mississippi Salt Basins

22015 LA Bossier Louisiana-Mississippi Salt Basins

22017 LA Caddo Louisiana-Mississippi Salt Basins

22019 LA Calcasieu Western Gulf

22021 LA Caldwell Louisiana-Mississippi Salt Basins

22023 LA Cameron Western Gulf

22025 LA Catahoula Louisiana-Mississippi Salt Basins

22027 LA Claiborne Louisiana-Mississippi Salt Basins

22029 LA Concordia Louisiana-Mississippi Salt Basins
December 2012 

A-6 

FIPS Code State County Basin

22031 LA De Soto Louisiana-Mississippi Salt Basins

22033 LA East Baton Rouge Western Gulf

22035 LA East Carroll Louisiana-Mississippi Salt Basins

22037 LA East Feliciana Western Gulf

22039 LA Evangeline Western Gulf

22041 LA Franklin Louisiana-Mississippi Salt Basins

22043 LA Grant Louisiana-Mississippi Salt Basins

22045 LA Iberia Western Gulf

22047 LA Iberville Western Gulf

22049 LA Jackson Louisiana-Mississippi Salt Basins

22051 LA Jefferson Western Gulf

22053 LA Jefferson Davis Western Gulf

22055 LA Lafayette Western Gulf

22057 LA Lafourche Western Gulf

22059 LA La Salle Louisiana-Mississippi Salt Basins

22061 LA Lincoln Louisiana-Mississippi Salt Basins

22063 LA Livingston Western Gulf

22065 LA Madison Louisiana-Mississippi Salt Basins

22067 LA Morehouse Louisiana-Mississippi Salt Basins

22069 LA Natchitoches Louisiana-Mississippi Salt Basins

22071 LA Orleans Western Gulf

22073 LA Ouachita Louisiana-Mississippi Salt Basins

22075 LA Plaquemines Western Gulf

22077 LA Pointe Coupee Western Gulf

22079 LA Rapides Western Gulf

22081 LA Red River Louisiana-Mississippi Salt Basins

22083 LA Richland Louisiana-Mississippi Salt Basins

22085 LA Sabine Louisiana-Mississippi Salt Basins

22087 LA St. Bernard Western Gulf

22089 LA St. Charles Western Gulf

22091 LA St. Helena Western Gulf

22093 LA St. James Western Gulf

22095 LA

St. John the 

Baptist Western Gulf

22097 LA St. Landry Western Gulf

22099 LA St. Martin Western Gulf

22101 LA St. Mary Western Gulf

22103 LA St. Tammany Western Gulf

22105 LA Tangipahoa Western Gulf

22107 LA Tensas Louisiana-Mississippi Salt Basins
December 2012 

A-7 

FIPS Code State County Basin

22109 LA Terrebonne Western Gulf

22111 LA Union Louisiana-Mississippi Salt Basins

22113 LA Vermilion Western Gulf

22115 LA Vernon Western Gulf

22117 LA Washington Western Gulf

22119 LA Webster Louisiana-Mississippi Salt Basins

22121 LA West Baton Rouge Western Gulf

22123 LA West Carroll Louisiana-Mississippi Salt Basins

22125 LA West Feliciana Western Gulf

22127 LA Winn Louisiana-Mississippi Salt Basins

29001 MO Adair Not Assigned

29003 MO Andrew Not Assigned

29005 MO Atchison Not Assigned

29007 MO Audrain Not Assigned

29009 MO Barry Not Assigned

29011 MO Barton Not Assigned

29013 MO Bates Not Assigned

29015 MO Benton Not Assigned

29017 MO Bollinger Not Assigned

29019 MO Boone Not Assigned

29021 MO Buchanan Not Assigned

29023 MO Butler Not Assigned

29025 MO Caldwell Not Assigned

29027 MO Callaway Not Assigned

29029 MO Camden Not Assigned

29031 MO Cape Girardeau Not Assigned

29033 MO Carroll Not Assigned

29035 MO Carter Not Assigned

29037 MO Cass Not Assigned

29039 MO Cedar Not Assigned

29041 MO Chariton Not Assigned

29043 MO Christian Not Assigned

29045 MO Clark Not Assigned

29047 MO Clay Not Assigned

29049 MO Clinton Not Assigned

29051 MO Cole Not Assigned

29053 MO Cooper Not Assigned

29055 MO Crawford Not Assigned

29057 MO Dade Not Assigned

29059 MO Dallas Not Assigned
December 2012 

A-8 

FIPS Code State County Basin

29061 MO Daviess Not Assigned

29063 MO DeKalb Not Assigned

29065 MO Dent Not Assigned

29067 MO Douglas Not Assigned

29069 MO Dunklin Illinois Basin

29071 MO Franklin Not Assigned

29073 MO Gasconade Not Assigned

29075 MO Gentry Not Assigned

29077 MO Greene Not Assigned

29079 MO Grundy Not Assigned

29081 MO Harrison Not Assigned

29083 MO Henry Not Assigned

29085 MO Hickory Not Assigned

29087 MO Holt Not Assigned

29089 MO Howard Not Assigned

29091 MO Howell Not Assigned

29093 MO Iron Not Assigned

29095 MO Jackson Not Assigned

29097 MO Jasper Not Assigned

29099 MO Jefferson Not Assigned

29101 MO Johnson Not Assigned

29103 MO Knox Not Assigned

29105 MO Laclede Not Assigned

29107 MO Lafayette Not Assigned

29109 MO Lawrence Not Assigned

29111 MO Lewis Not Assigned

29113 MO Lincoln Not Assigned

29115 MO Linn Not Assigned

29117 MO Livingston Not Assigned

29119 MO McDonald Not Assigned

29121 MO Macon Not Assigned

29123 MO Madison Not Assigned

29125 MO Maries Not Assigned

29127 MO Marion Not Assigned

29129 MO Mercer Not Assigned

29131 MO Miller Not Assigned

29133 MO Mississippi Not Assigned

29135 MO Moniteau Not Assigned

29137 MO Monroe Not Assigned

29139 MO Montgomery Not Assigned
December 2012 

A-9 

FIPS Code State County Basin

29141 MO Morgan Not Assigned

29143 MO New Madrid Not Assigned

29145 MO Newton Not Assigned

29147 MO Nodaway Not Assigned

29149 MO Oregon Not Assigned

29151 MO Osage Not Assigned

29153 MO Ozark Not Assigned

29155 MO Pemiscot Not Assigned

29157 MO Perry Not Assigned

29159 MO Pettis Not Assigned

29161 MO Phelps Not Assigned

29163 MO Pike Not Assigned

29165 MO Platte Not Assigned

29167 MO Polk Not Assigned

29169 MO Pulaski Not Assigned

29171 MO Putnam Not Assigned

29173 MO Ralls Not Assigned

29175 MO Randolph Not Assigned

29177 MO Ray Not Assigned

29179 MO Reynolds Not Assigned

29181 MO Ripley Not Assigned

29183 MO St. Charles Not Assigned

29185 MO St. Clair Not Assigned

29186 MO Ste. Genevieve Not Assigned

29187 MO St. Francois Not Assigned

29189 MO St. Louis Not Assigned

29193 MO Ste. Genevieve Not Assigned

29195 MO Saline Not Assigned

29197 MO Schuyler Not Assigned

29199 MO Scotland Not Assigned

29201 MO Scott Not Assigned

29203 MO Shannon Not Assigned

29205 MO Shelby Not Assigned

29207 MO Stoddard Not Assigned

29209 MO Stone Not Assigned

29211 MO Sullivan Not Assigned

29213 MO Taney Not Assigned

29215 MO Texas Not Assigned

29217 MO Vernon Not Assigned

29219 MO Warren Not Assigned
December 2012 

A-10 

FIPS Code State County Basin

29221 MO Washington Not Assigned

29223 MO Wayne Not Assigned

29225 MO Webster Not Assigned

29227 MO Worth Not Assigned

29229 MO Wright Not Assigned

29510 MO St. Louis city Not Assigned

31001 NE Adams Salina Basin

31003 NE Antelope Salina Basin

31005 NE Arthur Cambridge Arch-Central Kansas Uplift

31007 NE Banner Denver Basin

31009 NE Blaine Salina Basin

31011 NE Boone Salina Basin

31013 NE Box Butte Denver Basin

31015 NE Boyd Salina Basin

31017 NE Brown Salina Basin

31019 NE Buffalo Salina Basin

31021 NE Burt Salina Basin

31023 NE Butler Salina Basin

31025 NE Cass Nemaha Uplift

31027 NE Cedar Salina Basin

31029 NE Chase Cambridge Arch-Central Kansas Uplift

31031 NE Cherry Cambridge Arch-Central Kansas Uplift

31033 NE Cheyenne Denver Basin

31035 NE Clay Salina Basin

31037 NE Colfax Salina Basin

31039 NE Cuming Salina Basin

31041 NE Custer Salina Basin

31043 NE Dakota Salina Basin

31045 NE Dawes Denver Basin

31047 NE Dawson Cambridge Arch-Central Kansas Uplift

31049 NE Deuel Denver Basin

31051 NE Dixon Salina Basin

31053 NE Dodge Salina Basin

31055 NE Douglas Nemaha Uplift

31057 NE Dundy Cambridge Arch-Central Kansas Uplift

31059 NE Fillmore Salina Basin

31061 NE Franklin Salina Basin

31063 NE Frontier Cambridge Arch-Central Kansas Uplift

31065 NE Furnas Cambridge Arch-Central Kansas Uplift

31067 NE Gage Nemaha Uplift
December 2012 

A-11 

FIPS Code State County Basin

31069 NE Garden Denver Basin

31071 NE Garfield Salina Basin

31073 NE Gosper Cambridge Arch-Central Kansas Uplift

31075 NE Grant Cambridge Arch-Central Kansas Uplift

31077 NE Greeley Salina Basin

31079 NE Hall Salina Basin

31081 NE Hamilton Salina Basin

31083 NE Harlan Salina Basin

31085 NE Hayes Cambridge Arch-Central Kansas Uplift

31087 NE Hitchcock Cambridge Arch-Central Kansas Uplift

31089 NE Holt Salina Basin

31091 NE Hooker Cambridge Arch-Central Kansas Uplift

31093 NE Howard Salina Basin

31095 NE Jefferson Salina Basin

31097 NE Johnson Nemaha Uplift

31099 NE Kearney Salina Basin

31101 NE Keith Cambridge Arch-Central Kansas Uplift

31103 NE Keya Paha Salina Basin

31105 NE Kimball Denver Basin

31107 NE Knox Salina Basin

31109 NE Lancaster Salina Basin

31111 NE Lincoln Cambridge Arch-Central Kansas Uplift

31113 NE Logan Cambridge Arch-Central Kansas Uplift

31115 NE Loup Salina Basin

31117 NE McPherson Cambridge Arch-Central Kansas Uplift

31119 NE Madison Salina Basin

31121 NE Merrick Salina Basin

31123 NE Morrill Denver Basin

31125 NE Nance Salina Basin

31127 NE Nemaha Forest City Basin

31129 NE Nuckolls Salina Basin

31131 NE Otoe Nemaha Uplift

31133 NE Pawnee Nemaha Uplift

31135 NE Perkins Cambridge Arch-Central Kansas Uplift

31137 NE Phelps Salina Basin

31139 NE Pierce Salina Basin

31141 NE Platte Salina Basin

31143 NE Polk Salina Basin

31145 NE Red Willow Cambridge Arch-Central Kansas Uplift

31147 NE Richardson Forest City Basin
December 2012 

A-12 

FIPS Code State County Basin

31149 NE Rock Salina Basin

31151 NE Saline Salina Basin

31153 NE Sarpy Nemaha Uplift

31155 NE Saunders Salina Basin

31157 NE Scotts Bluff Denver Basin

31159 NE Seward Salina Basin

31161 NE Sheridan Denver Basin

31163 NE Sherman Salina Basin

31165 NE Sioux Denver Basin

31167 NE Stanton Salina Basin

31169 NE Thayer Salina Basin

31171 NE Thomas Cambridge Arch-Central Kansas Uplift

31173 NE Thurston Salina Basin

31175 NE Valley Salina Basin

31177 NE Washington Salina Basin

31179 NE Wayne Salina Basin

31181 NE Webster Salina Basin

31183 NE Wheeler Salina Basin

31185 NE York Salina Basin

40001 OK Adair Cherokee Platform

40003 OK Alfalfa Anadarko Basin

40005 OK Atoka Arkoma Basin

40007 OK Beaver Anadarko Basin

40009 OK Beckham Anadarko Basin

40011 OK Blaine Anadarko Basin

40013 OK Bryan Arkoma Basin

40015 OK Caddo Anadarko Basin

40017 OK Canadian Anadarko Basin

40019 OK Carter Southern Oklahoma

40021 OK Cherokee Cherokee Platform

40023 OK Choctaw Arkoma Basin

40025 OK Cimarron Palo Duro Basin

40027 OK Cleveland Nemaha Uplift

40029 OK Coal Arkoma Basin

40031 OK Comanche Southern Oklahoma

40033 OK Cotton Southern Oklahoma

40035 OK Craig Cherokee Platform

40037 OK Creek Cherokee Platform

40039 OK Custer Anadarko Basin

40041 OK Delaware Cherokee Platform
December 2012 

A-13 

FIPS Code State County Basin

40043 OK Dewey Anadarko Basin

40045 OK Ellis Anadarko Basin

40047 OK Garfield Anadarko Basin

40049 OK Garvin Southern Oklahoma

40051 OK Grady Anadarko Basin

40053 OK Grant Anadarko Basin

40055 OK Greer Anadarko Basin

40057 OK Harmon Bend Arch-Fort Worth Basin

40059 OK Harper Anadarko Basin

40061 OK Haskell Arkoma Basin

40063 OK Hughes Arkoma Basin

40065 OK Jackson Bend Arch-Fort Worth Basin

40067 OK Jefferson Southern Oklahoma

40069 OK Johnston Southern Oklahoma

40071 OK Kay Nemaha Uplift

40073 OK Kingfisher Anadarko Basin

40075 OK Kiowa Anadarko Basin

40077 OK Latimer Arkoma Basin

40079 OK Le Flore Arkoma Basin

40081 OK Lincoln Cherokee Platform

40083 OK Logan Nemaha Uplift

40085 OK Love Southern Oklahoma

40087 OK McClain Nemaha Uplift

40089 OK McCurtain Arkoma Basin

40091 OK McIntosh Arkoma Basin

40093 OK Major Anadarko Basin

40095 OK Marshall Southern Oklahoma

40097 OK Mayes Cherokee Platform

40099 OK Murray Southern Oklahoma

40101 OK Muskogee Cherokee Platform

40103 OK Noble Nemaha Uplift

40105 OK Nowata Cherokee Platform

40107 OK Okfuskee Cherokee Platform

40109 OK Oklahoma Nemaha Uplift

40111 OK Okmulgee Cherokee Platform

40113 OK Osage Cherokee Platform

40115 OK Ottawa Cherokee Platform

40117 OK Pawnee Cherokee Platform

40119 OK Payne Cherokee Platform

40121 OK Pittsburg Arkoma Basin
December 2012 

A-14 

FIPS Code State County Basin

40123 OK Pontotoc Arkoma Basin

40125 OK Pottawatomie Cherokee Platform

40127 OK Pushmataha Arkoma Basin

40129 OK Roger Mills Anadarko Basin

40131 OK Rogers Cherokee Platform

40133 OK Seminole Cherokee Platform

40135 OK Sequoyah Arkoma Basin

40137 OK Stephens Southern Oklahoma

40139 OK Texas Anadarko Basin

40141 OK Tillman Bend Arch-Fort Worth Basin

40143 OK Tulsa Cherokee Platform

40145 OK Wagoner Cherokee Platform

40147 OK Washington Cherokee Platform

40149 OK Washita Anadarko Basin

40151 OK Woods Anadarko Basin

40153 OK Woodward Anadarko Basin

48001 TX Anderson East Texas Basin

48003 TX Andrews Permian Basin

48005 TX Angelina East Texas Basin

48007 TX Aransas Western Gulf

48009 TX Archer Bend Arch-Fort Worth Basin

48011 TX Armstrong Palo Duro Basin

48013 TX Atascosa Western Gulf

48015 TX Austin Western Gulf

48017 TX Bailey Palo Duro Basin

48019 TX Bandera Bend Arch-Fort Worth Basin

48021 TX Bastrop Western Gulf

48023 TX Baylor Bend Arch-Fort Worth Basin

48025 TX Bee Western Gulf

48027 TX Bell Western Gulf

48029 TX Bexar Western Gulf

48031 TX Blanco Bend Arch-Fort Worth Basin

48033 TX Borden Permian Basin

48035 TX Bosque Bend Arch-Fort Worth Basin

48037 TX Bowie East Texas Basin

48039 TX Brazoria Western Gulf

48041 TX Brazos Western Gulf

48043 TX Brewster Marathon Thrust Belt

48045 TX Briscoe Palo Duro Basin

48047 TX Brooks Western Gulf
December 2012 

A-15 

FIPS Code State County Basin

48049 TX Brown Bend Arch-Fort Worth Basin

48051 TX Burleson Western Gulf

48053 TX Burnet Bend Arch-Fort Worth Basin

48055 TX Caldwell Western Gulf

48057 TX Calhoun Western Gulf

48059 TX Callahan Bend Arch-Fort Worth Basin

48061 TX Cameron Western Gulf

48063 TX Camp East Texas Basin

48065 TX Carson Anadarko Basin

48067 TX Cass East Texas Basin

48069 TX Castro Palo Duro Basin

48071 TX Chambers Western Gulf

48073 TX Cherokee East Texas Basin

48075 TX Childress Palo Duro Basin

48077 TX Clay Bend Arch-Fort Worth Basin

48079 TX Cochran Permian Basin

48081 TX Coke Permian Basin

48083 TX Coleman Bend Arch-Fort Worth Basin

48085 TX Collin Bend Arch-Fort Worth Basin

48087 TX Collingsworth Palo Duro Basin

48089 TX Colorado Western Gulf

48091 TX Comal Western Gulf

48093 TX Comanche Bend Arch-Fort Worth Basin

48095 TX Concho Bend Arch-Fort Worth Basin

48097 TX Cooke Bend Arch-Fort Worth Basin

48099 TX Coryell Bend Arch-Fort Worth Basin

48101 TX Cottle Palo Duro Basin

48103 TX Crane Permian Basin

48105 TX Crockett Permian Basin

48107 TX Crosby Permian Basin

48109 TX Culberson Permian Basin

48111 TX Dallam Palo Duro Basin

48113 TX Dallas Bend Arch-Fort Worth Basin

48115 TX Dawson Permian Basin

48117 TX Deaf Smith Palo Duro Basin

48119 TX Delta East Texas Basin

48121 TX Denton Bend Arch-Fort Worth Basin

48123 TX DeWitt Western Gulf

48125 TX Dickens Permian Basin

48127 TX Dimmit Western Gulf
December 2012 

A-16 

FIPS Code State County Basin

48129 TX Donley Palo Duro Basin

48131 TX Duval Western Gulf

48133 TX Eastland Bend Arch-Fort Worth Basin

48135 TX Ector Permian Basin

48137 TX Edwards Permian Basin

48139 TX Ellis Bend Arch-Fort Worth Basin

48141 TX El Paso Permian Basin

48143 TX Erath Bend Arch-Fort Worth Basin

48145 TX Falls East Texas Basin

48147 TX Fannin East Texas Basin

48149 TX Fayette Western Gulf

48151 TX Fisher Permian Basin

48153 TX Floyd Palo Duro Basin

48155 TX Foard Bend Arch-Fort Worth Basin

48157 TX Fort Bend Western Gulf

48159 TX Franklin East Texas Basin

48161 TX Freestone East Texas Basin

48163 TX Frio Western Gulf

48165 TX Gaines Permian Basin

48167 TX Galveston Western Gulf

48169 TX Garza Permian Basin

48171 TX Gillespie Bend Arch-Fort Worth Basin

48173 TX Glasscock Permian Basin

48175 TX Goliad Western Gulf

48177 TX Gonzales Western Gulf

48179 TX Gray Anadarko Basin

48181 TX Grayson Bend Arch-Fort Worth Basin

48183 TX Gregg East Texas Basin

48185 TX Grimes Western Gulf

48187 TX Guadalupe Western Gulf

48189 TX Hale Palo Duro Basin

48191 TX Hall Palo Duro Basin

48193 TX Hamilton Bend Arch-Fort Worth Basin

48195 TX Hansford Anadarko Basin

48197 TX Hardeman Bend Arch-Fort Worth Basin

48199 TX Hardin Western Gulf

48201 TX Harris Western Gulf

48203 TX Harrison East Texas Basin

48205 TX Hartley Palo Duro Basin

48207 TX Haskell Bend Arch-Fort Worth Basin
December 2012 

A-17 

FIPS Code State County Basin

48209 TX Hays Western Gulf

48211 TX Hemphill Anadarko Basin

48213 TX Henderson East Texas Basin

48215 TX Hidalgo Western Gulf

48217 TX Hill Bend Arch-Fort Worth Basin

48219 TX Hockley Permian Basin

48221 TX Hood Bend Arch-Fort Worth Basin

48223 TX Hopkins East Texas Basin

48225 TX Houston East Texas Basin

48227 TX Howard Permian Basin

48229 TX Hudspeth Permian Basin

48231 TX Hunt East Texas Basin

48233 TX Hutchinson Anadarko Basin

48235 TX Irion Permian Basin

48237 TX Jack Bend Arch-Fort Worth Basin

48239 TX Jackson Western Gulf

48241 TX Jasper Western Gulf

48243 TX Jeff Davis Permian Basin

48245 TX Jefferson Western Gulf

48247 TX Jim Hogg Western Gulf

48249 TX Jim Wells Western Gulf

48251 TX Johnson Bend Arch-Fort Worth Basin

48253 TX Jones Bend Arch-Fort Worth Basin

48255 TX Karnes Western Gulf

48257 TX Kaufman East Texas Basin

48259 TX Kendall Bend Arch-Fort Worth Basin

48261 TX Kenedy Western Gulf

48263 TX Kent Permian Basin

48265 TX Kerr Bend Arch-Fort Worth Basin

48267 TX Kimble Bend Arch-Fort Worth Basin

48269 TX King Permian Basin

48271 TX Kinney Western Gulf

48273 TX Kleberg Western Gulf

48275 TX Knox Bend Arch-Fort Worth Basin

48277 TX Lamar East Texas Basin

48279 TX Lamb Palo Duro Basin

48281 TX Lampasas Bend Arch-Fort Worth Basin

48283 TX La Salle Western Gulf

48285 TX Lavaca Western Gulf

48287 TX Lee Western Gulf
December 2012 

A-18 

FIPS Code State County Basin

48289 TX Leon East Texas Basin

48291 TX Liberty Western Gulf

48293 TX Limestone East Texas Basin

48295 TX Lipscomb Anadarko Basin

48297 TX Live Oak Western Gulf

48299 TX Llano Bend Arch-Fort Worth Basin

48301 TX Loving Permian Basin

48303 TX Lubbock Permian Basin

48305 TX Lynn Permian Basin

48307 TX McCulloch Bend Arch-Fort Worth Basin

48309 TX McLennan Bend Arch-Fort Worth Basin

48311 TX McMullen Western Gulf

48313 TX Madison Western Gulf

48315 TX Marion East Texas Basin

48317 TX Martin Permian Basin

48319 TX Mason Bend Arch-Fort Worth Basin

48321 TX Matagorda Western Gulf

48323 TX Maverick Western Gulf

48325 TX Medina Western Gulf

48327 TX Menard Bend Arch-Fort Worth Basin

48329 TX Midland Permian Basin

48331 TX Milam Western Gulf

48333 TX Mills Bend Arch-Fort Worth Basin

48335 TX Mitchell Permian Basin

48337 TX Montague Bend Arch-Fort Worth Basin

48339 TX Montgomery Western Gulf

48341 TX Moore Anadarko Basin

48343 TX Morris East Texas Basin

48345 TX Motley Palo Duro Basin

48347 TX Nacogdoches East Texas Basin

48349 TX Navarro East Texas Basin

48351 TX Newton Western Gulf

48353 TX Nolan Permian Basin

48355 TX Nueces Western Gulf

48357 TX Ochiltree Anadarko Basin

48359 TX Oldham Palo Duro Basin

48361 TX Orange Western Gulf

48363 TX Palo Pinto Bend Arch-Fort Worth Basin

48365 TX Panola East Texas Basin

48367 TX Parker Bend Arch-Fort Worth Basin
December 2012 

A-19 

FIPS Code State County Basin

48369 TX Parmer Palo Duro Basin

48371 TX Pecos Permian Basin

48373 TX Polk Western Gulf

48375 TX Potter Palo Duro Basin

48377 TX Presidio Permian Basin

48379 TX Rains East Texas Basin

48381 TX Randall Palo Duro Basin

48383 TX Reagan Permian Basin

48385 TX Real Bend Arch-Fort Worth Basin

48387 TX Red River East Texas Basin

48389 TX Reeves Permian Basin

48391 TX Refugio Western Gulf

48393 TX Roberts Anadarko Basin

48395 TX Robertson East Texas Basin

48397 TX Rockwall East Texas Basin

48399 TX Runnels Bend Arch-Fort Worth Basin

48401 TX Rusk East Texas Basin

48403 TX Sabine East Texas Basin

48405 TX San Augustine East Texas Basin

48407 TX San Jacinto Western Gulf

48409 TX San Patricio Western Gulf

48411 TX San Saba Bend Arch-Fort Worth Basin

48413 TX Schleicher Permian Basin

48415 TX Scurry Permian Basin

48417 TX Shackelford Bend Arch-Fort Worth Basin

48419 TX Shelby East Texas Basin

48421 TX Sherman Anadarko Basin

48423 TX Smith East Texas Basin

48425 TX Somervell Bend Arch-Fort Worth Basin

48427 TX Starr Western Gulf

48429 TX Stephens Bend Arch-Fort Worth Basin

48431 TX Sterling Permian Basin

48433 TX Stonewall Permian Basin

48435 TX Sutton Permian Basin

48437 TX Swisher Palo Duro Basin

48439 TX Tarrant Bend Arch-Fort Worth Basin

48441 TX Taylor Bend Arch-Fort Worth Basin

48443 TX Terrell Marathon Thrust Belt

48445 TX Terry Permian Basin

48447 TX Throckmorton Bend Arch-Fort Worth Basin
December 2012 

A-20 

FIPS Code State County Basin

48449 TX Titus East Texas Basin

48451 TX Tom Green Permian Basin

48453 TX Travis Western Gulf

48455 TX Trinity Western Gulf

48457 TX Tyler Western Gulf

48459 TX Upshur East Texas Basin

48461 TX Upton Permian Basin

48463 TX Uvalde Western Gulf

48465 TX Val Verde Permian Basin

48467 TX Van Zandt East Texas Basin

48469 TX Victoria Western Gulf

48471 TX Walker Western Gulf

48473 TX Waller Western Gulf

48475 TX Ward Permian Basin

48477 TX Washington Western Gulf

48479 TX Webb Western Gulf

48481 TX Wharton Western Gulf

48483 TX Wheeler Anadarko Basin

48485 TX Wichita Bend Arch-Fort Worth Basin

48487 TX Wilbarger Bend Arch-Fort Worth Basin

48489 TX Willacy Western Gulf

48491 TX Williamson Western Gulf

48493 TX Wilson Western Gulf

48495 TX Winkler Permian Basin

48497 TX Wise Bend Arch-Fort Worth Basin

48499 TX Wood East Texas Basin

48501 TX Yoakum Permian Basin

48503 TX Young Bend Arch-Fort Worth Basin

48505 TX Zapata Western Gulf

48507 TX Zavala Western Gulf
December 2012 

APPENDIX B 

Field Names for Production Data from HPDI 
December 2012 

B-1 

Appendix B: Field Names for Production Data from HPDI 

Area source categories in the current inventory were assigned source classification code(s) 

(SCC) that best described the emissions source analyzed. The SCCs designation aids in the 

submission of emissions for the NEI. Some source categories are characterized by more than 

one SCC and thus emissions were estimated separately to fit an SCC description. Often source 

categories will be independently estimated by well type (gas versus oil), thus resulting in two 

SCCs for similar equipment/source. Other examples include wellhead and lateral compressors, 

as well as fugitives, which are assigned different SCCs depending on equipment characteristics. 

Table B-1. Field Names and Descriptions in the Production Well Table in the EPA Enforcement 

Universe Database (created from HPDI). 

Field Name Description

ENTITY_ID HPDI assigned unique property ID. Note: for instances where duplicate 

API numbers were combined, the minimum value was selected.

API_NO API assigned number of a well on the property.

PROPERTY_TYPE

Property type (e.g., lease, unit, well, completion, other, unknown). 

Note: for instances where duplicate API numbers were combined, the 

minimum value was selected.

PRODUCTION_TYPE

Production type (e.g., oil, gas, coalbed methane, injection). Note: for 

instances where duplicate API numbers were combined, the production 

type fields are comma separated.

WELL_NAME

Operator assigned well/lease name of the property. Note: for instances 

where duplicate API numbers were combined, the minimum value was 

selected.

LEASE_NO

State number assigned to the property or lease or unit the property is 

part of. Note: for instances where duplicate API numbers were 

combined, the minimum value was selected.

WELL_NO

Operator assigned well number of the property. Note: for instances 

where duplicate API numbers were combined, the minimum value was 

selected.

CURR_OPER_NAME Current operator name. Note: for instances where duplicate API 

numbers were combined, the minimum value was selected.

LIQ_GATH_NAME_1

Current primary liquid gatherer for a property. Note: for instances 

where duplicate API numbers were combined, the production type 

fields are comma separated.

GAS_GATH_NAME_1

Current primary gas gatherer for a property. Note: for instances where 

duplicate API numbers were combined, the production type fields are 

comma separated.

COMMON_OPER_NAME

Corporate entity that is determined by HPDI to own the current 

operator. Note: for instances where duplicate API numbers were 

combined, the minimum value was selected.
December 2012 

B-2 

Field Name Description

LATITUDE

Surface latitude the property is located in; for multi-well properties 

HPDI picked a well to designate the location of the property. Note: for 

instances where duplicate API numbers were combined, the minimum 

value was selected.

LONGITUDE

Surface longitude the property is located in; for multi-well properties 

HPDI picked a well to designate the location of the property. Note: for 

instances where duplicate API numbers were combined, the minimum 

value was selected.

LATITUDE_BOTM

Bottom hole latitude of the property; for multi-well properties HPDI 

picked a well to designate the location of the property. Note: for 

instances where duplicate API numbers were combined, the minimum 

value was selected.

LONGITUDE_BOTM

Bottom hole longitude of the property; for multi-well properties HPDI 

picked a well to designate the location of the property. Note: for 

instances where duplicate API numbers were combined, the minimum 

value was selected.

LOCATION Township range of property. Note: for instances where duplicate API 

numbers were combined, the minimum value was selected.

COUNTY County the property is located in. Note: for instances where duplicate 

API numbers were combined, the minimum value was selected.

DISTRICT

District within a given state the property is assigned. Note: for instances 

where duplicate API numbers were combined, the minimum value was 

selected.

STATE State the property is located in. Note: for instances where duplicate API 

numbers were combined, the minimum value was selected.

SECTION Section property is located in. Note: for instances where duplicate API 

numbers were combined, the minimum value was selected.

QTR_QTR

Quarter-quarter the property is located in (note: Texas only). Note: for 

instances where duplicate API numbers were combined, the minimum 

value was selected.

MERID

Meridian legal description is referenced from. Note: for instances 

where duplicate API numbers were combined, the minimum value was 

selected.

OFFSHORE Offshore waters indicator. Note: for instances where duplicate API 

numbers were combined, the minimum value was selected.

FIELD

Field name the property is reporting from. Note: for instances where 

duplicate API numbers were combined, the minimum value was 

selected.

RESERVOIR

Reservoir, formation, zone, or pool that the property is reported as 

producing from. Note: for instances where duplicate API numbers were 

combined, the minimum value was selected.
December 2012 

B-3 

Field Name Description

FORMATION

Formation that the property is reported as producing from. Note: for 

instances where duplicate API numbers were combined, the minimum 

value was selected.

BASIN Basin the property is located in. Note: for instances where duplicate API 

numbers were combined, the minimum value was selected.

STATUS

Current status of the well (e.g., active, inactive, shut in). See Error! 

Reference source not found. for the status codes and descriptions. 

Note: for instances where duplicate API numbers were combined, the 

minimum value was selected.

SPUD_DATE

Latest date drilling commenced on property. Note: for instances where 

duplicate API numbers were combined, the minimum value was 

selected.

DRILL_TYPE

Drill type (e.g., horizontal, vertical, directional). See Error! Reference 

source not found. for the drill type codes and descriptions. Note: for 

instances where duplicate API numbers were combined, the minimum 

value was selected.

COMPLETION_DATE

Latest completion date of the property. Note: for instances where 

duplicate API numbers were combined, the minimum value was 

selected.

TOTAL_DEPTH

Total depth the property was drilled to. Note: for instances where 

duplicate API numbers were combined, the minimum value was 

selected.

LAST_PROD_DATE

Last date HPDI has reported production for the property. Note: Even 

though the date may be represented as mm/dd/yyyy, it is for the 

month listed, not just the individual day. For example, production 

through December 2009 is listed as 12/1/2009.

LATEST_FLOW_

PRESSURE

Latest flow pressure reported. Note: for instances where duplicate API 

numbers were combined, the minimum value was selected.

LATEST_WHSIP

Latest well head shut-in pressure reported. Note: for instances where 

duplicate API numbers were combined, the minimum value was 

selected.

SumOfLIQ_DAILY Average daily liquid production in last 12 months, summed over 

duplicate API numbers.

SumOfGAS_DAILY Average daily gas production in last 12 months, summed over duplicate 

API numbers.

SumOfLIQ_CUM Cumulative liquid production of property, reported in bbl, summed over 

duplicate API numbers.

SumOfGAS_CUM Cumulative gas production of property, reported in MCF, summed over 

duplicate API numbers.

SumOfWRT_CUM Cumulative water production of property, summed over duplicate API 

numbers.
December 2012 

B-4 

Field Name Description

SumOfLIQ_YEAR Liquid production, reported in bbls, for the 12 months ending with 

LAST_PROD_DATE, summed over duplicate API numbers.

SumOfGAS_YEAR Gas production, reported in MCF, for the 12 months ending with 

LAST_PROD_DATE, summed over duplicate API numbers.

SumOfWTR_YEAR Water production, reported in bbls, for the 12 months ending with 

LAST_PROD_DATE, summed over duplicate API numbers.

SumOfLIQ07 Liquid production, reported in bbls, for 2007, summed over duplicate 

API numbers.

SumOfGAS07 Gas production, reported in MCF, for 2007, summed over duplicate API 

numbers.

SumOfWTR07 Water production, reported in bbls, for 2007, summed over duplicate 

API numbers.

SumOfLIQ08 Liquid production, reported in bbls, for 2008, summed over duplicate 

API numbers.

SumOfGAS08 Gas production, reported in MCF, for 2008, summed over duplicate API 

numbers.

SumOfWTR08 Water production, reported in bbls, for 2008, summed over duplicate 

API numbers.

SumOfLIQ09 Liquid production, reported in bbls, for 2009, summed over duplicate 

API numbers.

SumOfGAS09 Gas production, reported in MCF, for 2009, summed over duplicate API 

numbers.

SumOfWTR09 Water production, reported in bbls, for 2009, summed over duplicate 

API numbers.

SumOfLIQ10 Liquid production, reported in bbls, for 2010, summed over duplicate 

API numbers.

SumOfGAS10 Gas production, reported in MCF, for 2010, summed over duplicate API 

numbers.

SumOfWTR10 Water production, reported in bbls, for 2010, summed over duplicate 

API numbers.

SumOfLIQ11 Liquid production, reported in bbls, for 2011, summed over duplicate 

API numbers.

SumOfGAS11 Gas production, reported in MCF, for 2011, summed over duplicate API 

numbers.

SumOfWTR11 Water production, reported in bbls, for 2011, summed over duplicate 

API numbers.

SumOfLIQ12 Liquid production, reported in bbls, for 2012, summed over duplicate 

API numbers.

SumOfGAS12 Gas production, reported in MCF, for 2012, summed over duplicate API 

numbers.
December 2012 

B-5 

Field Name Description

SumOfWTR12 Water production, reported in bbls, for 2012, summed over duplicate 

API numbers.

PROD09_FLAG Yes/No flag indicating if liquid and/or gas production was greater than 

zero in 2009.

PROD10_FLAG Yes/No flag indicating if liquid and/or gas production was greater than 

zero in 2010.

PROD11_FLAG Yes/No flag indicating if liquid and/or gas production was greater than 

zero in 2011.

PROD12_FLAG Yes/No flag indicating if liquid and/or gas production was greater than 

zero in 2012.

ACTIVE_FLAG Yes/No flag indicating active status based on latest production date.

ACTIVE_PROD_FLAG Yes/No flag indicating whether entity produced liquid and/or gas in 

2009-2012, using the production flags.

SHALE_FLAG Yes/No flag for Pennsylvania only indicating if the type of production is 

shale gas.

INITIAL_OIL Initial oil production. Note: Only for Indiana and Illinois.

INITIAL_GAS Initial gas production. Note: Only for Indiana and Illinois.

INITIAL_WATER Initial water production. Note: Only for Indiana and Illinois.

TEST_DATE Date of the most recent well test.

TEST_TIMES_TESTED Total number of times the well was tested.

TEST_GAS_CUM Cumulative reported gas at the time of the most recent well test.

TEST_GOR Gas to oil ratio at the time of the most recent well test.

TEST_FLOW_PRES Well head flowing pressure at the time of the most recent well test.

TEST_FLOWOZ Flowing pressure divided by Z-Factor at the time of the most recent well 

test.

TEST_WHSIP Well head shut-in pressure at the time of the most recent well test.

TEST_SIPOZ Bottom hole pressure divided by the Z-Factor, if well head shut-in 

pressure is provided at the time of the most recent well test.

TEST_GAS_GRAVITY Gas gravity at the time of the most recent well test.

TEST_LIQ_GRAVITY Liquid gravity at the time of the most recent well test.

TEST_GAS_VOLUME Daily gas production at the time of the most recent well test.

TEST_LIQ_VOLUME Daily water production at the time of the most recent well test.

TEST_WAT_VOLUME Daily liquid production at the time of the most recent well test.

TEST_TYPE Type of test conducted for the most recent well test.

TEST_CHOKE_SIZE Choke used during the most recent well test.

TEST_TBG_PRES Pressure present in the tubing at the time of the most recent well test.

HUC12_CODE EPA populated field.

Indian_Lands EPA populated field.
December 2012 

B-6 

Field Name Description

Federal_Lands EPA populated field.

Percent_Minority EPA populated field.

Sole_Source_Aquifer EPA populated field.

Water_Protection_Area EPA populated field.

NA_Pollution_Code EPA populated field.
December 2012 

APPENDIX C 

Electronic Appendix: Industry survey forms (Excel Workbooks) 
December 2012 

APPENDIX D 

Electronic Appendix: CenSARA Emissions Calculator Tools (Excel Workbooks)