773 San Marin Drive, Suite 2115, Novato, CA 94998 415.899.0700 

ENVIRON International Corporation 

Final Report 

RECOMMENDATIONS FOR IMPROVEMENTS TO THE 

CENRAP STATES’ OIL AND GAS 

EMISSIONS INVENTORIES 

Prepared for 

Central States Regional Air Partnership 

10005 S. Pennsylvania, Ste. C 

Oklahoma City, OK 73159 

Prepared by 

Amnon Bar-Ilan 

Rajashi Parikh 

John Grant 

Tejas Shah 

Alison K. Pollack 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

November 13, 2008 
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TABLE OF CONTENTS 

Page 

EXECUTIVE SUMMARY .................................................................................................... ES-1 

Task 1: Identification of Major CENRAP Basins................................................................ES-1 

 Task 2: Literature Review and Limited Industry Survey.....................................................ES-3 

 Recommendations................................................................................................................ES-5 

INTRODUCTION..........................................................................................................................1 

OBJECTIVES ................................................................................................................................1 

TEMPORAL AND GEOGRAPHIC SCOPE..............................................................................2 

POLLUTANTS CONSIDERED...................................................................................................2 

TASK 1: BASIN IDENTIFICATION ........................................................................................3 

Oklahoma ..................................................................................................................................4 

 Kansas ..................................................................................................................................6 

 Nebraska ..................................................................................................................................8 

 Arkansas ..................................................................................................................................9 

 Texas ................................................................................................................................10 

 Louisiana ................................................................................................................................11 

 Condensate Production ............................................................................................................12 

 Coal-Bed Methane Wells.........................................................................................................13 

 Summary Statistics...................................................................................................................14 

TASK 2a: LITERATURE REVIEW .........................................................................................16 

TASK 2b: LIMITED INDUSTRY SURVEY ............................................................................18 

TASK 3a: RECOMMENDED SOURCE CATEGORY EMISSION 

 CALCULATION METHODOLOGIES AND INPUT DATA 

 FOR BASELINE 2002 EMISSIONS........................................................................22 

Wellhead Compressor Engines................................................................................................23 

 Lateral Compressor Engines....................................................................................................27 

 Artificial Lift (Pumpjack) Engines ..........................................................................................30

 Drill Rigs – Drilling Operations ..............................................................................................32 

 Heaters ................................................................................................................................36 

 Flaring ................................................................................................................................39 

 Oil and Condensate Tanks .......................................................................................................44 

 Dehydrators..............................................................................................................................46 

 Well Completions ....................................................................................................................48 

 Well Blowdowns......................................................................................................................50 

 Fugitive Emissions (Leaks)......................................................................................................51 

 Pneumatic Control Devices......................................................................................................55 

 Natural Gas Composition.........................................................................................................57 
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TASK 3b: RECOMMENDED PROJECTION METHODOLOGIES 

 AND INPUT DATA FOR GENERATING 2018 EMISSIONS .............................57

Growth Factors.........................................................................................................................58 

 Control Factors.........................................................................................................................61 

CONCLUSIONS ..........................................................................................................................63 

REFERENCES.............................................................................................................................64 

APPENDICES 

APPENDIX A: Detailed Oil and Gas Production Statistics for All CENRAP Basins 

APPENDIX B: Survey Questionnaire for Oil and Gas Companies 

APPENDIX C: Master Data Matrix of Input Data for Emissions Inventory Calculations for All 

CENRAP Basins 

TABLES 

Table ES-1. 2002 gas production, oil production, active well counts 

 and spud counts for all basins in the CENRAP domain ....................................ES-2 

Table ES-2. Summary of companies contacted as part of the survey 

 process including their regions of operation and the status 

 of their responses to the survey..........................................................................ES-4 

Table 1. 2002 total oil and gas production by state for each state in 

 the CENRAP domain...............................................................................................3 

Table 2. 2002 by-basin condensate production for the State of Texas ................................13 

Table 3. 2002 gas production, oil production, active well counts and 

 spud counts for all producing basins in the CENRAP domain..............................14 

Table 4. 2002 gas production, oil production, active well counts and spud 

 counts for each basin in the CENRAP domain organized by state 

 including state totals ..............................................................................................15 

Table 5. List of studies and other literature reviewed as part of Task 1 ..............................17 

Table 6. Summary of companies contacted as part of the survey process 

 including their regions of operation and the status of their responses 

 to the survey...........................................................................................................20 

Table 7. Recommended engine operating parameters for use in estimating 

 wellhead compressor emissions for all major CENRAP basins ............................25 

Table 8. Recommended rich-burn and lean-burn engine emissions factors 

 for use in estimating wellhead compressor emissions for all 

 major CENRAP basins ..........................................................................................26 

Table 9. Recommended engine operating parameters for use in estimating 

 lateral compressor engine emissions for all major CENRAP basins.....................28 

Table 10. Recommended rich-burn and lean-burn engine emissions factors 

 for use in estimating lateral compressor engine emissions for all 

 major CENRAP basins ..........................................................................................29 

Table 11. Recommended engine operating parameters for use in estimating 

 artificial lift engine (pumpjack) emissions for all major CENRAP basins............31 

Table 12. Recommended engine emissions factors for use in estimating artificial lift engine 

emissions for all major CENRAP basins...............................................................31 
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Table 13. Recommended engine operating parameters for use in estimating 

 drilling rig emissions for all major CENRAP basins.............................................34 

Table 14. Recommended engine emissions factors for use in estimating 

 drill rig emissions for all major CENRAP basins..................................................34 

Table 15. Recommended heater operating parameters for use in estimating 

 heater emissions for all major CENRAP basins ....................................................37 

Table 16. Recommended heater emissions factors for use in estimating 

 heater emissions for all major CENRAP basins ....................................................38 

Table 17. Recommended input data parameters for use in estimating flaring 

 emissions for all major CENRAP basins...............................................................42 

Table 18. Recommended emissions factors for use in estimating flaring 

 emissions for all major CENRAP basins...............................................................43 

Table 19. Recommended input data parameters for use in estimating 

 working & breathing and flashing emissions from oil and condensate 

 tanks in all major CENRAP basins........................................................................45 

Table 20. Recommended emissions factors for use in estimating dehydrator 

 emissions for all major CENRAP basins...............................................................47 

Table 21. Recommended input data parameters for use in estimating 

 completion venting emissions in all major CENRAP basins.................................49 

Table 22. Recommended input data parameters for use in estimating 

 blowdown emissions in all major CENRAP basins...............................................51 

Table 23. Recommended fugitive component emissions factors for use 

 in estimating fugitive emissions in all major CENRAP basins .............................53 

Table 24. Recommended number of fugitive components per typical 

 well by component service type in all major CENRAP basins .............................54 

Table 25. Recommended pneumatic device input data for use in estimating 

 pneumatics emissions in all major CENRAP basins .............................................56 

Table 26. Growth or decline factors for the three regions in the CENRAP 

 domain, from the AEO...........................................................................................59 

Table 27. 2018 growth or decline factors by basin and source category 

 for all major CENRAP basins................................................................................60 

Table 28. Federal and state regulations applicable to various oil and gas area 

 source categories in the CENRAP domain and recommended 

 methodologies for developing control factors to account for 

 these regulations.....................................................................................................61 

FIGURES 

Figure 1. The CENRAP geographic domain including state and basin 

boundaries, overlaid with 2002 oil and gas well locations. .....................................2 

Figure 2. Map of Oklahoma showing exact alignment between county 

boundaries and the boundaries of the basins in the state .........................................5 

Figure 3. Map of Kansas showing exact alignment between county boundaries 

and the boundaries of the basins in the state............................................................7 

Figure 4. Map of Texas showing county boundaries and the boundaries of the 

basins in the state, and showing that the Marathon Thrust Belt and 

Permian Basin do not align exactly with county boundaries.................................11 

Figure 5. Definitions of model regions in the EIA’s AEO forecasting analysis...................59 
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EXECUTIVE SUMMARY 

CENRAP has identified the need to improve the oil and gas area source inventories for the 2002 

base year and 2018 future year for the entire CENRAP region, encompassing the oil- and gasproducing states of Texas, Louisiana, Oklahoma, Arkansas, Kansas and Nebraska. This is being 

driven by the high levels of oil and gas production activity that occur at hundreds of thousands of 

individual well sites, the large fleet of equipment that supports this activity, and the potential for 

this equipment to significantly contribute to emissions of NOx, VOC, SOx, greenhouse gases 

(GHG) and other pollutants in the region. Previous CENRAP and state inventories have been 

limited by data availability and the geographic specificity of this data. Often these inventories 

have relied on broad, regional assumptions to generate oil and gas area source emissions 

inventories. Following the work of ENVIRON, under contract to the Western Regional Air 

Partnership (WRAP) in generating the WRAP Phase I and II, and the joint Phase III project with 

the Independent Petroleum Association of Mountain States (IPAMS), CENRAP has contracted 

with ENVIRON to provide improved input information and methodology descriptions to update 

these inventories. 

This work consisted of three principal tasks: 

1. Identification of major CENRAP basins: the objective of this task was to generate oil and 

gas production statistics for all of the major geological basins in the CENRAP domain to 

determine which are the “major” basins. Major basins are those basins ranked highest by 

production of gas, oil or by active well counts. 

2. Literature review and limited industry survey: the objective of this task was to gather 

input data used to calculate emissions from a wide variety of source categories associated 

with oil and gas exploration, production, transmission and gathering activities by 

reviewing published literature and studies on oil and gas emissions and equipment, and 

by conducted a limited industry survey to gather information about specific source 

categories in specific basins. 

3. Develop recommendations: the objective of this task, and the subject of this report, was 

to synthesize the information gathered in Tasks 2 and 3 and recommend input data and 

methodologies to improve CENRAP’s oil and gas area source inventories for the 2002 

base year and 2018 future year projections. 

These tasks and their results are described in detail in this report, and the accompanying 

recommendation data matrix spreadsheets. 

Task 1: Identification of Major CENRAP Basins

ENVIRON obtained and analyzed databases of oil and gas production statistics from all six 

CENRAP states with significant oil and gas production, and obtained state-wide oil and gas 

production totals from all other CENRAP states. The determination was made to focus on the 

states of Texas, Louisiana, Oklahoma, Arkansas, Kansas and Nebraska because these states 

collectively represent the overwhelming majority of oil and gas production and active wells in 

the CENRAP region. 
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The databases were obtained from each state’s oil and gas conservation commission (OGCC) or 

equivalent agency. The databases required significant work to remove missing, incorrect or 

inconsistent data, and to summarize the data for 2002 only, in a format that could be used to 

determine the production statistics of interest. The production statistics that were estimated in 

this analysis are: 

• Gas production 

• Oil production 

• Condensate production (if available) 

• Active well counts (by well type if available) 

• Drilling event (spud) counts 

These production statistics were determined for each state, and then geographic information 

system (GIS) analysis was used to intersect the spatially allocated statistical information with the 

boundaries of geologic basins to determine basin-level statistics. This was done for each state 

and combined where basin boundaries crossed state lines. The resulting oil and gas statistics 

summary from Task 1 are presented in Table ES-1. 

Table ES-1. 2002 gas production, oil production, active well counts and spud counts for all 

basins in the CENRAP domain. 

Basin 

Gas 

Production 

[MCF] 

Oil 

Production 

[bbl] 

Active Well 

Count 

Spud 

Count 

Anadarko Basin 1,732,269,135 40,279,230 88,406 2,327 

Arkoma Basin 364,833,847 3,019,091 12,401 739 

Bend Arch-Ft. Worth 

Basin 321,056,553 24,156,879 106,173 1,662 

Cambridge ArchCentral Kansas Uplift 6,442,698 14,649,639 10,366 387 

Cherokee Platform 31,040,321 16,693,567 33,779 862 

Denver Basin 1,192,111 1,321,300 1,288 11 

East Texas Basin 980,666,377 23,944,407 33,453 1,159 

Forest City Basin 415,029 946,580 5,850 131 

Louisiana-Mississippi 

Salt Basins 391,332,732 13,146,248 34,805 63 

Marathon Thrust Belt 63,294,963 56,723 278 15 

Nemaha Uplift 27,773,241 8,419,664 11,913 249 

Ozark Uplift 48,946 0 5 0 

Palo Duro Basin 31,360,922 6,215,265 2,556 48 

Permian Basin 679,260,325 256,544,364 113,598 2,957 

Salina Basin 0 227,996 247 3 

Sedgwick Basin 24,983,651 3,196,023 3,455 137 

Southern Oklahoma 

Basin 60,355,759 18,586,235 24,651 349 

Western Gulf Basin 3,410,532,407 100,096,887 108,403 2,417 

From these summary statistics, the following eleven basins were identified as the “major” oil and 

gas production basins in the CENRAP region because they collectively represent greater than 

95% of production of oil, production of gas, and active well counts: 
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• Anadarko Basin 

• Arkoma Basin 

• Bend Arch-Fort Worth Basin 

• Cambridge Arch-Central Kansas Uplift 

• Cherokee Platform 

• East Texas Basin 

• Louisiana-Mississippi Salt Basins 

• Nemaha Uplift 

• Permian Basin 

• Southern Oklahoma Basin 

• Western Gulf Basin 

Recommendations for emissions calculations and specific input data for those calculations are 

provided for these specific basins, based on this analysis, in the report. 

Task 2: Literature Review and Limited Industry Survey

This task required gathering information obtained from a review of relevant literature and 

published studies on emissions, processes and equipment used in oil and gas exploration and 

production activities, as well as development of a limited survey on specific source categories 

that was distributed to major oil and gas companies operating in the CENRAP region. 

ENVIRON reviewed a wide range of published studies and reports on quantifying oil and gas 

emissions through analysis of equipment and processes in the field. The literature review 

included the WRAP studies, authored by ENVIRON, which developed the methodologies for 

estimating some of the oil and gas area source categories that had not been previously 

inventoried. The reports and studies that were selected for review in this analysis were analyzed 

for their applicability to the CENRAP inventories. The specific criteria used to evaluate 

literature reviewed in this task included: 

1. Geographic scope: The most important criterion applied to determine the applicability of 

a literature source was the geographic scope which the study or report covers. Since 

production characteristics and the composition of the produced gas and oil vary widely 

from basin to basin, these regional differences can affect the usage of particular 

equipment and would necessarily affect the development of oil and gas emissions 

inventories for a particular basin. To the extent possible, data from regionally applicable 

studies were used to gather useful input data for emissions calculations. 

2. Age of study: It was determined that older studies may not well represent the equipment 

and emissions characteristics in use in the oil and gas industry in the past decade, and that 

newer studies are more relevant and applicable to this task. To the extent possible this 

criterion was applied to the selection of specific data from some of the studies and 

reports. 

3. Consistency of data with other sources: Data consistency was used as a QA/QC tool to 

evaluate the usefulness and applicability of data extracted from all of these studies and 

reports. Data were reviewed to be consistent both with other studies, and with detailed 

information collected by ENVIRON as part of the development of oil and gas inventories 

in the western states. 
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The data obtained from the literature reviewed, with the above criteria applied, were compiled 

into a master data matrix that was then supplemented by data obtained as part of the limited 

industry survey task. These data form the basis of the recommended input data for calculating 

emissions from a variety of oil and gas source categories. 

The limited industry survey was conducted in anticipation of not being able to find information 

on all of the needed input parameters to estimate emissions from a wide variety of source 

categories. The survey asked for basin-level representative data on specific major oil and gas 

NOx and VOC source categories (which are also the major SO2 source categories). It is 

ENVIRON’s experience that only the oil and gas companies can provide highly detailed and 

highly geographically-specific data on equipment, configuration, usage, processes, and emissions 

factors to generate the most accurate emissions estimates. For this task ENVIRON relied on its 

contacts with the oil and gas industry through the WRAP work to survey specific major 

companies operating in the CENRAP region. A survey questionnaire was developed that asked 

for data on the following major oil and gas source categories: 

• Drilling rigs 

• Compressor engines 

• Artificial lift engines 

• Heaters 

• Condensate and Oil tanks 

• Fugitive emissions 

• Pneumatic devices 

• Completion/recompletion venting and well blowdowns 

These source categories were determined to be the top contributors to NOx, VOC and SO2

emissions from ENVIRON’s development of the detailed Phase III inventories for the western 

regional U.S. These are also source categories with high basin-to-basin variability and thus 

would benefit most from industry data on their usage in specific basins. Table ES-2 shows the 

companies that ENVIRON considered and/or contacted for this survey process, and the outcome 

of the survey outreach effort. 

Table ES-2. Summary of companies contacted as part of the survey process including their 

regions of operation and the status of their responses to the survey. 

Company 

Geographic Area of 

Major Operations 

(by basin) 

Survey 

Sent 

(Y/N) 

Survey 

Received 

(Y/N) 

BP America 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, Cambridge Arch-Central 

Kansas Uplift, East Texas, 

Marathon Thrust Belt, Palo Duro, 

Permian, Sedgwick, Western Gulf 

Y N 

Conoco-Phillips 

Anadarko, Bend Arch-Ft. Worth, 

East Texas, Marathon Thrust Belt, 

Nemaha Uplift, Palo Duro, Permian, 

Sedgwick, Western Gulf 

Y N 

Chevron Southern Oklahoma Y N 

Anadarko Petroleum 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, Cambridge Arch-Central 

Kansas Uplift, East Texas, Permian, 

Southern Oklahoma, Western Gulf 

Y Y 
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Company 

Geographic Area of 

Major Operations 

(by basin) 

Survey 

Sent 

(Y/N) 

Survey 

Received 

(Y/N) 

Encana USA Bend Arch-Ft. Worth, East Texas, 

Permian, Western Gulf Y Y 

Devon Energy 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, East Texas, LouisianaMississippi Salt, Nemaha Uplift, 

Permian, Sedgwick, Western Gulf 

Y Y 

Noble Energy 

Anadarko, Arkoma, Cambridge 

Arch-Central Kansas Uplift, 

Cherokee Platform, East Texas, 

Louisiana-Mississippi Salt Basins, 

Nemaha Uplift, Permian, Southern 

Oklahoma, Western Gulf 

Y Y 

EOG Resources 

Anadarko, Bend Arch-Ft. Worth, 

Cambridge Arch-Central Kansas 

Uplift, East Texas, Nemaha, 

Permian, Southern Oklahoma, 

Sedgwick 

Y N 

XTO 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, Cambridge Arch-Central 

Kansas Uplift, Cherokee Platform, 

East Texas, Nemaha Uplift, Palo 

Duro, Permian, Southern 

Oklahoma, Western Gulf 

Y N 

ExxonMobil Arkoma, Louisiana-Mississippi Salt 

Basins N – 

Occidental Petroleum Permian N – 

El Paso Corporation Louisiana-Mississippi Salt Basins N – 

Petro-Chem Operating Louisiana-Mississippi Salt Basins N – 

Table ES-2 shows that not many companies responded with completed surveys, and that some 

companies that ENVIRON had specifically targeted for the survey outreach (such as BP 

America) were not willing to participate in this process. Despite the small number of completed 

surveys, these surveys did form part of the data gathered in the master data matrix and used as 

recommended inputs in this analysis. 

Task 3: Recommendations

The majority of this analysis focuses on providing detailed methodologies to estimate base year 

2002 emissions from the major oil and gas area source categories, both for individual sources 

and for basin-level emissions totals. This input data includes the fractional usage of equipment 

at well sites, equipment characteristics such as size, annual usage and emissions factors, process 

information such as venting rates and well component configurations, and chemical composition 

analyses used to determine pollutant emissions rates. These input data and methodologies for 

emissions estimation are provided in this report for the following major oil and gas source 

categories: 

• Wellhead Compressor Engines 

• Lateral Compressor Engines 

• Artificial Lift Engines (Pumpjacks) 

• Drilling Rigs 
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• Heaters 

• Flaring 

• Oil Tanks (Flashing and Working & Breathing Losses) 

• Condensate Tanks (Flashing and Working & Breathing Losses) 

• Dehydrators 

• Completion Venting 

• Well Blowdowns 

• Fugitive Emissions 

• Pneumatic Devices 

The data are also provided in detailed spreadsheets that accompany this report, and for some 

source categories the detailed data are provided only in the accompanying spreadsheets. These 

recommendations can be used directly to update the 2002 oil and gas area source inventories for 

all major CENRAP basins, and can be extended to include all CENRAP basins. 

It is important to note that this is a broad, regional study aimed at helping CENRAP improve 

their domain-wide oil and gas area source emissions. The broad scope of the geographic domain 

covered in this work necessarily limits the ability to generate highly detailed and highly 

spatially-resolved input data and recommendations. This has been ENVIRON’s experience in 

developing the WRAP regional inventories. Where appropriate, the analysis indicates caveats 

associated with the use of the input data and the assumptions that were made to arrive at the 

recommendations. If in the future CENRAP has access to more detailed information from local 

studies, or a further industry survey effort, these recommendations should be revisited and 

revised as appropriate. 

Recommendations have also been developed for scaling emissions from 2002 to 2018. The 

projection methodology focuses on developing growth or decline factors for activity, scaling the 

emissions of specific source categories by specific growth or decline factors, and then controlling 

these emissions to account for federal and state regulations that may affect future emissions. 

Because of the lack of project-specific growth estimates for individual oil and gas developments 

in the CENRAP region, the 2018 growth/decline factors rely on broad regional estimates derived 

from the Energy Information Administration’s Annual Energy Outlook (AEO). This is an 

economic analysis that is used to predict future gas and oil production in regions of the 

continental U.S. and can be used to predict drilling activity. 

Methodologies for developing control factors to represent future impacts of federal or state 

regulations are also presented in this work. The methodologies cover all federal and state 

regulations of which ENVIRON is aware, but it should be noted that regulations covering oil and 

gas area sources were only found for the State of Texas. The report does not provide the control 

factors, but rather indicates how these control factors can be derived for each state. 
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INTRODUCTION 

The last decade has seen a tremendous growth in oil and gas exploration and production 

throughout the continental United States, but centered primarily on the Rocky Mountain states, 

many of the central states, and the Gulf of Mexico. In 2002, the states comprising the Central 

States Regional Air Partnership (CENRAP) – Texas, Louisiana, Oklahoma, Arkansas, Kansas, 

Nebraska, Missouri, Iowa, and Minnesota – had a combined gas production total of 

approximately 8.5 trillion cubic feet and a combined oil production total of approximately 615 

million barrels (EIA, 2008). This represents nearly 43% of total U.S. gas production and nearly 

30% of total U.S. oil production. 

In order to support this level of oil and gas production, the oil and gas companies employ a large 

fleet of equipment used in a wide variety of oil and gas exploration, drilling, production, 

processing and transmission activities. This equipment, much of which has traditionally been 

classified as an area source, has not been well inventoried in the past (Russell, et al., 2005; BarIlan, et al., 2007) and can represent a substantial source of many criteria pollutants (NOx, CO, 

SOx, VOC) as well as greenhouse gas (GHG) emissions for these CENRAP states. 

Some of the CENRAP states have made efforts to inventory these emissions sources in the past 

(Reid, et al., 2008; Pendleton, et al., 2008), but CENRAP has identified the need to improve 

these inventories for both the baseline year of 2002 and the future year of 2018. These 

inventories relied on broad, regional data to generate emissions estimates per unit of production, 

and these emissions estimates were then scaled to the state level by using total state production 

statistics. While this approach is useful in generating some emissions estimates where these 

sources had never been inventoried before, the broad-based activity and equipment assumptions 

used in creating these emissions inventories do not apply to all major regions of oil and gas 

activity. In the past work of ENVIRON in developing oil and gas emissions inventories for the 

Rocky Mountain states (Russell, et al., 2005; Bar-Ilan, et al., 2007; Bar-Ilan, et al. 2008; Pollack, 

et al., 2006), it has been observed that oil and gas activity is best grouped on the basin level. 

Basins are large-scale oil and gas geologic formations in which the exploration and production 

activities are relatively consistent across the basin (USGS, 2008). The basin thus provides a 

geographic unit to use as the basis for generating a regional emissions inventory. This report 

summarizes the input data and methodology needed to improve the CENRAP regional oil and 

gas area source emissions inventory at the basin level. Considering the previous inventory 

efforts of CENRAP at the regional scale, the work presented here provides an opportunity to 

increase the types of oil and gas source categories considered to be major contributors to NOx, 

VOC and SOx emissions beyond those originally considered in past inventory efforts. 

OBJECTIVES 

CENRAP has identified the need to improve the emissions inventory for oil and gas area sources 

for each of the CENRAP states with major oil and gas production and activity. The first step in 

improving these state-level oil and gas emissions inventories is to obtain improved information 

on equipment, activity, configurations, and production statistics to feed into updated inventory 

calculations. Obtaining this information and providing recommendations on data to use are the 

objectives of this study. Specifically the objectives of this study are: 
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1. Identify major CENRAP oil and gas basins and their production statistics: For this task 

ENVIRON was to identify major oil and gas basins within the boundaries of the 

CENRAP states by obtaining each state’s oil and gas production statistics and intersect 

them with the boundaries of basins as defined by the USGS. The resulting data would be 

basin-level summaries of oil (condensate) production, gas production, active well counts 

by well type, and drilling event (spud) counts. This was to allow for the identification of 

those basins in the CENRAP domain that make up the majority of oil and/or gas 

production and are therefore considered “major” basins. 

2a. Gather information on equipment and activity from a literature review: For this task 

ENVIRON was to compile a list of studies, reports and other literature, including those 

reports specifically identified by CENRAP, to review for possible usefulness in 

developing an improved oil and gas area source inventory. Information obtained from 

the literature would include, if possible, equipment counts, emissions factor and activity 

factors of this equipment (e.g., load factors, annual hours of operation, etc.) and gas 

composition data. Where possible this literature would be specific to a particular basin. 

ENVIRON was to use our extensive work in developing oil and gas emissions 

inventories to expand on the list of studies and reports recommended by CENRAP to 

include those additional studies which may provide useful data. 

2b. Gather supplemental information on equipment and activity from a limited industry 

survey: For this task ENVIRON was to supplement the information gathered from the 

literature review, which was likely to not be specific to individual basins except in 

limited some limited studies, with detailed basin-specific data on operations obtained 

from surveying companies operating in these basins. ENVIRON would draw on its 

extensive contacts among the oil and gas industry to survey the major companies, 

identified by proportional ownership of production in each major basin. The survey was 

to ask for targeted information on the major oil and gas source categories to aid in 

improving the inventories for these source categories in the major basins. 

3. Provide recommendations for data and emissions estimations for 2002 and 2018: For this 

task ENVIRON was to summarize the findings of Tasks 1 & 2 above and provide 

recommendations for both the methodology and input data to be used to estimate 

emissions from each major oil and gas source category for each of the major basins 

identified. The recommendations would also include a description of the methodology to 

project 2002 baseline emissions to 2018 and recommendations of where projection data 

should be obtained. 

TEMPORAL & GEOGRAPHIC SCOPE 

This inventory improvement project considers a base year of 2002 for purposes of obtaining data 

on activity and equipment in the field, and for all analysis of production statistics. All data 

requested from companies that were surveyed were for these companies’ activities in the 

calendar year 2002. Similarly, all well count and production data for all basins obtained as part 

of Task 1 were for the calendar year 2002. It is assumed that all emissions from all source 

categories are evenly distributed throughout the year –no seasonal allocation fractions are 

derived because the vast majority of all oil and gas area source equipment operates throughout 

the year. All methodology descriptions presented in this report are for estimating emissions on 

an annual basis. 
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A future year of 2018 is considered for purposes of projecting emissions. The methodology for 

conducting the emissions projections requires the development of scaling factors which are used 

to project emissions to the future year. These scaling factors are specific to the future year of the 

projection and this work therefore considers only the 2018 future year. 

The geographic scope of this inventory is the CENRAP domain, which wholly includes the states 

of Texas, Louisiana, Arkansas, Oklahoma, Kansas, Nebraska, Missouri, Iowa and Minnesota. 

As is shown in the discussion of oil and gas production statistics below, Missouri, Iowa and 

Minnesota do not have substantial (or have no) oil and gas activity and are thus not considered as 

part of the geographic scope of this work. Within the states of Texas, Louisiana, Arkansas, 

Oklahoma, Kansas and Nebraska the USGS definitions are used to define the boundaries of the 

major oil and gas geological basins. The complete list of basins is:

• Western Gulf Basin 

• Permian Basin 

• Marathon Thrust Belt 

• Bend Arch-Fort Worth Basin 

• East Texas Basin 

• Louisiana- Mississippi Salt Basins 

• Palo Duro Basin 

• Southern Oklahoma Basin 

• Arkoma Basin 

• Cherokee Platform 

• Anadarko Basin 

• Sedgwick Basin 

• Nemaha Uplift 

• Salina Basin 

• Cambridge Arch-Central Kansas 

Uplift 

• Denver-Julesburg Basin 

As is detailed in the discussion of oil and gas production statistics below, not all of these basins 

are considered major basins of oil and gas activity, but their production statistics are provided 

and thus they are considered part of the geographic scope of this work. 

Figure 1 shows a map of the CENRAP domain with state and basin boundaries demarcated, as 

well as the location of oil and gas wells in 2002. 
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Figure 1. The CENRAP geographic domain including state and basin boundaries, overlaid with 

2002 oil and gas well locations. 

POLLUTANTS CONSIDERED 

This work considers the following major pollutants from oil and gas area sources, per the 

CENRAP scope of work for this project: 

• NOx 

• VOC 

• CO 

• SOx 

• PM10/PM2.5

• H2S 

• CO2

• CH4
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It should be noted that oil and gas exploration and production, processing, and transmission 

activities are not significant sources of PM emissions. H2S and CH4 emissions are only emitted 

as a result of direct venting of produced gas that contains these two species. CH4 is a major 

component of produced gas while H2S is a minor species that is present in some locations. To 

the extent possible information is presented on the H2S content of gas but it should be noted that 

this information is not extensive or detailed at the level of the individual oil or gas field. VOC 

emissions are either the result of direct venting of produced gas that contains VOC species, or 

from combustion emissions. All other pollutants above are combustion-generated. 

TASK 1: BASIN IDENTIFICATION 

As the first task in the project, ENVIRON obtained and analyzed 2002 oil and gas production 

and well statistics for each of the CENRAP states in order to identify the extent of oil and gas 

activity in each state, and further to quantify the production and well statistics for all of the 

basins in the CENRAP domain to identify the major basins of oil and gas activity. This task 

required obtaining detailed oil and gas data, usually in the form of electronic databases, 

maintained by the oil and gas conservation commissions (OGCC, or equivalent) of each state in 

the CENRAP domain. It should be noted that these databases vary greatly with respect to the 

detailed information tracked by each OGCC, the format of the database, and ultimately the oil 

and gas statistical information available. Early in the development of this task, ENVIRON 

contacted IHS Corporation, which offers a commercially available database of oil and gas 

statistics for all of the United States of extremely high quality. It was determined that the access 

cost of using the IHS database (also known as the P.I. Dwight database) was beyond the budget 

and resources of this project, so the work described here is ENVIRON’s analysis of the detailed 

oil and gas databases obtained from each state’s OGCC or equivalent, with the limitations of 

each database described in detail below. 

Prior to obtaining and analyzing each state’s oil and gas statistics, ENVIRON investigated the 

total oil and gas production from all of the states in the CENRAP domain to determine if some 

states had little or no oil and gas activity. This would allow for the elimination of these states 

from the detailed analysis. The state-by-state oil and gas production totals were obtained from 

the Energy Information Administration state summary database (EIA, 2008) and are presented in 

Table 1. 

Table 1. 2002 total oil and gas production by state for each state in the CENRAP domain. 

State 

Oil Production 

[bbl] 

% of Total 

CENRAP Oil 

Production 

Gas Production 

[MCF] 

% of Total 

CENRAP Gas 

Production 

Minnesota 0 0% 0 0% 

Iowa 0 0% 0 0% 

Missouri 93,000 0.02% 0 0% 

Nebraska 2,779,000 0.45% 1,188,000 0.01% 

Kansas 32,721,000 5.3% 454,901,000 5.3% 

Oklahoma 66,642,000 10.8% 1,581,606,000 18.6% 

Arkansas 7,345,000 1.2% 161,871,000 1.9% 

Texas 411,985,000 67.0% 5,084,012,000 59.7% 

Louisiana 93,476,000 15.2% 1,226,613,000 14.4% 

CENRAP States Total 615,041,000 100% 8,510,191,000 100% 

CENRAP States Total Production 

as Percentage of U.S. Total 29.3% 42.8% 
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Table 1 shows that oil and gas production activity in the states of Minnesota, Iowa, and Missouri 

is negligible, and therefore these states are not included further in any of the oil and gas 

production statistics analysis, or in the literature review or survey information summary portions 

of this project. 

For the remainder of the CENRAP states with significant oil and gas production – Texas, 

Louisiana, Oklahoma, Arkansas, Nebraska and Kansas – the databases of oil and gas production 

and well statistics for each state were obtained from the states’ respective OGCC or equivalent. 

Separately, definitions of the geographic boundaries of the major geological basins were 

obtained from the USGS (USGS, 2008) and were analyzed using Geographic Information 

Systems (GIS) tools to intersect the boundaries of the basins with the production and well 

statistics from all of the CENRAP states. Below are detailed descriptions of the methodologies 

used to analyze each state’s oil and gas statistics data. 

Oklahoma

Oklahoma historical well-level monthly gas production data and other well information were 

obtained from the Oklahoma Corporation Commission (OCC). These well-level data included 

owner/operator name, location of the gas well (latitude and longitude), purchaser, formation, 

lease number, and volume of gas production per month. The data were imported into a 

Microsoft ACCESS database so that querying and database analysis could be conducted as 

needed. The data were cleaned by removing well records with zero production in order to 

estimate active well counts only. Then basin boundaries were intersected with well locations to 

determine well counts in each basin in the state, as well as gas production in each basin in the 

state. 

Oil production has not been tracked by the Commission for several years, and is not available 

from the database. Since the OCC does not track detailed oil production or maintain a database 

of oil wells, ENVIRON contacted OCC to find out how 2002 specific state-wide oil production 

data by well might be obtained. OCC suggested contacting two private commercial firms for oil 

production data in Oklahoma. However, both of these private databases would require access 

fees beyond the budget and resources of this project. 

The alternative approach used was to obtain county-level oil production estimates and allocate 

these to the basins in which the counties are located. It should be noted that this approach is only 

accurate if basin boundaries align with county boundaries exactly. Therefore, the first step in 

determining oil production was to conduct a GIS analysis to intersect county and basin 

boundaries for Oklahoma. It was determined from this analysis that county boundaries align 

exactly with USGS-defined basin boundaries, as shown in Figure 2 (i.e. no county is sub-divided 

into more than one basin). 2002 county-level oil production was obtained from the Oklahoma 

Department of Environmental Quality, and basin total oil production was determined by 

summing county total oil production for each county located in the basin. 
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Figure 2. Map of Oklahoma showing exact alignment between county boundaries and the 

boundaries of the basins in the state.

Because of the unavailability of oil production data except at the broad county level, the data 

presented here does not contain a count of active oil wells in the state. Due to the level of oil 

production in Oklahoma, it is strongly recommended that any future analysis by CENRAP 

consider the use of commercial databases to obtain detailed well-level data on the active oil wells 

in the state. 

Spud counts for 2002 were estimated using well completion dates provided in the Oklahoma oil 

and gas database. The well records having completion dates between January 1st, 2002 and 

December 31st, 2002 were selected as spud events for 2002. 2002 spud events were spatially 

allocated to the basin level using ARC/GIS. It should be noted that this would only represent 

spuds of gas wells, since OCC does not track oil well information. 

Specifically, the following database analysis steps were performed to calculate oil and gas 

statistics by basins and counties: 

1. Well-level gas production data was obtained from the OCC for the calendar year of 

interest. 

2. The data was cleaned up by removing well records with no gas production. 

3. Monthly production data was totaled to calculate annual production by wells. 
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4. Basin-level production and well counts – The USGS-defined basin boundaries were 

intersected with well locations to determine well counts in each basin in the state, as well 

as gas production in each basin in the state, using ARC/GIS. 

5. County-level production and well count – Each well record in the OCC data file had an 

associated county FIPS code. The well data was linked with a county lookup table. Gas 

production and well count was summed by county. 

6. Spud-counts – Spud counts for 2002 were estimated using well completion dates 

provided in the OCC oil and gas database. The well records having completion dates 

between January 1st, 2002 and December 31st, 2002 were selected as spud events for 

2002. 2002 spud events were spatially allocated to the basin using ARC/GIS. The 

county code associated with a well record was used to obtain spud count by county. 

Kansas

A master database of oil and gas wells was obtained from the Kansas Geological Survey (KGS). 

KGS does not maintain oil and gas production data by lease/wells and therefore well data could 

not be linked to production data. However county level production data was obtained for the 

calendar year 2002 from KGS. As in the case of Oklahoma, Kansas county boundaries align 

exactly with USGS-defined basin boundaries, as shown in Figure 3. Basin level production was 

obtained by summing corresponding county-level production for all counties located within the 

boundaries of each basin in Kansas. 

In order to estimate active well count by basin, a methodology was developed to determine the 

status of wells in 2002 from the master oil and gas wells database. Wells producing in 2002 

were estimated by adding wells with valid completion dates and no plugging dates, or plugging 

dates after January 2002. If a data record was encountered with a workover code, this was not 

counted towards a unique active well but assumed to be a workover of a well already counted 

with the original unique API number. A certain percentage of older wells that were plugged do 

not have a plugging date listed in the KGS database. In this case, the date of completion of the 

well was determined from the database and if the well was completed more than 25 years before 

2002 (in 1977 or earlier) it was assumed to be plugged and no longer an active well. This choice 

of well age cutoff was based on ENVIRON’s previous experience examining the typical lifetime 

of a gas or oil well in the Rocky Mountain States, as well as specific data received from 

operators with active wells in Kansas. Service wells were also not included in the active well 

count. Service wells are those with a well status of "EOR," "SWD," or "WATER" indicating that 

they are enhanced recovery, water, or saltwater disposal wells which are not expected to have the 

same types of traditional gas and oil well equipment present. Therefore these wells should not 

be considered for use in emissions estimations that are based on well count. Dry holes (wells) 

with "D&A" status were not included because they were assumed to be depleted or never having 

produced either oil or gas. 
November 2008 

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Figure 3. Map of Kansas showing exact alignment between county boundaries and the 

boundaries of the basins in the state.

Spud counts for 2002 were estimated using the well completion date field provided in the Kansas 

oil and gas database. The well records having completion dates between January 1st, 2002 and 

December 31st, 2002 were selected as spud event for 2002. 2002 spud events were spatially 

allocated to the basin level using ARC/GIS. 

Specifically, the following database analysis steps were performed to obtain oil and gas statistics 

by basins and counties 

1. A master database of oil and gas wells and county level production data was obtained 

from KGS. 

2. As shown in Figure 3, Kansas county boundaries align exactly with USGS-defined 

basin boundaries. The county-basin cross reference was created by using the spatial 

join tool in ARC/GIS. The cross reference was used to obtain basin-level statistics 

from county-level data. 

3. Basin-level production and well counts – County level production data was obtained 

for calendar year 2002 from KGS. Basin level production was obtained by summing 

corresponding county-level production for all counties located within the boundaries 

of each basin in Kansas. Wells producing in 2002 were estimated by adding wells 

with valid completion dates (those without missing entries) and no plugging dates, or 

plugging dates after January 2002; and those wells without a workover code 

identified by nonzero last four characters of the API number; and those wells without 

a status code of "EOR," "SWD," or "WATER". Those wells completed more than 25 
November 2008 

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years before 2002 (in 1977 or earlier) were assumed to have been already beyond 

their active life spans and therefore were excluded from the active well count. 

4. County-level production and well counts – County level production and well counts 

were directly available from the resulting dataset created in Step #3. 

5. Spud-counts – Spud counts for 2002 were estimated using the well completion date 

field provided in the Kansas oil and gas database. The well records having 

completion dates between January 1st, 2002 and December 31st, 2002 were selected as 

spud events for 2002. 2002 spud events were spatially allocated to the basin level 

using ARC/GIS. 

Nebraska 

The master cumulative oil and gas well database containing owner, county, location (latitude and 

longitude), well type, well status, spud date, and completion date information; and a lease-level 

historical production database were obtained from the Nebraska Oil and Gas Conservation 

Commission (NOGCC) in two separate data sets. The data were obtained in MS ACCESS format 

from the commission allowing for detailed analysis and queries to be conducted. These two 

databases were linked together by lease identification number, and therefore could be queried to 

obtain active producing wells in 2002. These 2002 wells (and leases) were then plotted and 

spatially assigned to a basin using GIS analysis. The oil and gas production from the 2002 active 

leases were then added by basin and by owner/operator to obtain 2002 total basin-level 

owner/operator production statistics. 

Spud counts for 2002 were estimated using the well completion dates provided in the Nebraska 

oil and gas database. The well records having completion dates between January 1st, 2002 and 

December 31st, 2002 were selected as spud events for 2002. 2002 spud events were spatially 

allocated to the basin level using ARC/GIS. 

Specifically, the following database analysis steps were performed to obtain oil and gas statistics 

by basins and counties: 

1. A master cumulative oil and gas well database and a lease-level historical production 

database were obtained from the NOGCC 

2. These two databases were linked together by lease identification number (<Lease_No>). 

Active producing wells in 2002 were extracted using the <Rpt_Date> field. The wells in 

leases that reported production between January 1st, 2002 and December 31st, 2002 were 

selected as producing wells for 2002. 

3. Basin-level production and well counts – The extracted 2002 wells (and leases) were 

plotted and spatially assigned to a basin using the spatial join tool in ARC/GIS to obtain 

basin-level production and well count. 

4. County-level production and well counts – The database obtained from the NOGCC had 

a county code assigned to each well record. The production and well count of 2002 

producing wells were added at the county level from the extracted 2002 wells. 

5. Spud counts – Spud counts for 2002 were estimated using the well completion dates 

provided in the NOGCC database. The well records having completion dates between 

January 1st, 2002 and December 31st, 2002 were selected as spud events for 2002. 2002 

spud events were spatially allocated to the basin and county level using ARC/GIS. 
November 2008 

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Arkansas 

Arkansas oil and gas production and other well information were obtained from the Arkansas Oil 

and Gas Commission. Well data included well location (latitude and longitude), county, 

company name, well type and well status information. The other database obtained contained 

historical production data by PRUID, a well identifier. The wells database was linked with the 

production database using the well identification number (PRUID) so that producing wells in 

2002 could be estimated. Many wells did not have location in latitude/longitude format but 

rather in Town/Section/Range (TSR) data format. The TRS2LL program was used to convert 

these TRS data into latitude/longitude format in batch file mode 

(http://www.geocities.com/jeremiahobrien/trs2ll.html). 

The 2002 active wells were plotted and spatially joined with oil and gas basins using GIS 

analysis. Well production was aggregated by basin and operator/owner to obtain production total 

by basins and owner/operator. 

Spud count for 2002 was estimated using the well completion date field provided in the Arkansas 

oil & gas database (AOGC). The well records having completion dates between January 1st

, 

2002 and December 31st, 2002 were selected as spud events for 2002. However the spud count 

obtained using this methodology was unreasonably low as compared to the count reported by the 

EIA for the entire state. Given the limitations of the database, it was determined to use the statelevel spud count provided by EIA. The spud event was spatially allocated at the county level 

using well-count as surrogate and then aggregated to obtain basin-level spud count. 

Specifically, the following database analysis steps were performed to obtain oil and gas statistics 

by basins and counties: 

1. Arkansas oil and gas production and other well information were obtained from the 

AOGC. 

2. Well data included well location (latitude and longitude), county, company name, well 

type and well status information. A second database obtained from AOGC contained 

historical production data by PRUID, a well identifier. The wells database was linked 

with the production database using the well identification number (PRUID). The 

producing wells in 2002 were identified using the <RptDate> field. Wells that reported 

production between January 1st, 2002 and December 31st, 2002 were selected as 

producing wells for 2002. 

3. Many wells did not have location in latitude/longitude format but rather in 

Town/Section/Range (TSR) data format. The TRS2LL program was used to convert 

these TRS data into latitude/longitude format in batch file mode. 

4. Basin-level production and well counts – The 2002 active wells were plotted and 

spatially joined with oil and gas basins using the spatial join tool in ARC/GIS. Well 

production was aggregated by basin to obtain the production total and well count by 

basins. 

5. County-level production and well counts – The database obtained from the AOGC had a 

county code assigned to each well record. The production and well count of 2002 wells 

were added at the county level from the extracted 2002 wells. 

6. Spud counts – The spud count for 2002 was estimated using the well completion date 

field provided in the AOGC database. The well records having completion dates between 

January 1st, 2002 and December 31st, 2002 were selected as spud events for 2002. 

However, the spud count obtained using this methodology was unreasonably low as 
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compared to the count reported by the EIA for the entire state. Given the limitations of 

the AOGC database, it was determined that the state-level spud count provided by EIA 

would be used. The spud events were spatially allocated at the county level using wellcount as a surrogate and then aggregated to obtain basin-level spud counts. 

Texas 

ENVIRON attempted to obtain detailed oil and gas production and well databases from the 

Texas Railroad Commission (RRC), but several attempts to obtain this data were unsuccessful. 

The cost to access the complete database library from the RRC was determined to be beyond the 

budget and resources of this project, and further it could not be determined whether these 

databases would maintain historic information which could be used to determine 2002-specific 

statistics. ENVIRON discussed this issue with the Texas Commission on Environmental Quality 

(TCEQ) staff, and determined that further attempts to obtain this data from the RRC would not 

be useful. 

However, the TCEQ has in the past obtained some data from the RRC which were determined to 

be useful for this analysis. RRC provided to TCEQ a complete dataset of well locations for the 

month of June 2001, in GIS shape file format. TCEQ provided these shape files to ENVIRON 

for use in this analysis. GIS analysis was used to intersect the well location dataset with the 

USGS-defined basin boundaries to determine basin-level well counts, assuming that these would 

not have changed substantially from June 2001 to the 2002 calendar year. It should be noted that 

well counts were not identifiable by well type from this data. 

A summary of 2002 annual oil and gas production by county was obtained from the RRC. The 

GIS analysis of basin and county boundaries indicated that not all county boundaries align 

exactly with basin boundaries, as shown in Figure 4. The Marathon Thrust Belt and Permian 

Basin boundaries divide several Texas counties into partial counties. The county-level 

production in these divided counties was assigned to each of these two basins based on the 

fraction of 2001 wells in these counties located in each of the basins, as determined from the GIS 

shape file of 2001 well locations. For any other basin in which there was alignment between 

county and basin boundaries, basin total production was determined by summing county-level 

production for all counties within each basin. 

For purposes of estimating spud counts in Texas, it should be noted that well completion date 

information was missing in the Texas oil and gas dataset obtained from TCEQ. Spud counts by 

Rail Road District were obtained from RRC. The spud counts were mapped to counties using a 

district-county cross reference obtained from the RRC. These 2002 spud events were spatially 

allocated to the basin level using a county-basin cross reference. 

Specifically, the following database analysis steps were performed to obtain oil & gas statistics 

by basins and counties: 

1. A complete dataset of well locations for the month of June 2001, in GIS shape file 

format, was obtained from TCEQ. 

2. A summary of 2002 annual oil and gas production by county was obtained from the RRC 

online database. 

3. The Marathon Thrust Belt and Permian Basin boundaries divide several Texas counties 

into partial counties. The county-level production in these divided counties was assigned 
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to each of these two basins based on the fraction of 2001 wells in these counties located 

in each of the basins, as determined from the GIS shape file of 2001 well locations. 

4. Basin-level production and well counts – Wells having a status code of "OW," "OG," or 

"GW" were considered as active producing wells (these codes refer to “oil well”, “oil and 

gas well” and “gas well” respectively). The basin total production was determined by 

summing county-level production for all counties within each basin. The active well 

count by basins was obtained using the spatial join tool in ARC/GIS. 

5. County-level production and well counts – The dataset obtained from TCEQ had a 

county code assigned to each well record. The active well counts for each basin were 

obtained by adding wells with a status code of OW, OG, or GW. County-level 

production was obtained directly from the RRC online database. 

6. Spud Counts – Spud counts by Rail Road District were obtained from the RRC. The 

spud counts were mapped to counties using a District-County cross reference obtained 

from the RRC. These 2002 spud events were spatially allocated to the basin level using a 

county-basin cross reference. 

Figure 4. Map of Texas showing county boundaries and the boundaries of the basins in the 

state, and showing that the Marathon Thrust Belt and Permian Basin do not align exactly with 

county boundaries.

Louisiana 

Louisiana data were obtained from the Louisiana Department of Natural Resources (LADNR) 

with assistance from the Louisiana Department of Environmental Quality (LA DEQ). LADNR 

maintains a very detailed Oracle database of well locations, well type, well status, field-level 

production and field locations which was queried for 2002-specific data. From this query, the 

active well counts were determined by well location and spatially joined with the boundaries of 
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the Louisiana-Mississippi Salt Basins and the Western Gulf Basin using GIS analysis to 

determine basin-level well counts. Spud counts for each basin were determined by summing all 

wells that had a completion occurring between January 1 2002 and December 31 2002 and 

assigning these spuds to each basin using the well location. 

Oil and gas production data were provided by field. The field locations data table was merged 

with the production by field using field ID, to determine the fraction of total Louisiana 

production occurring in each of the two basins. 

Specifically, the following database analysis steps were performed to obtain oil & gas statistics 

by basins and counties: 

1. The 2002 active wells dataset was obtained from LA DEQ. The 2002 production by field 

dataset was also obtained from LA DEQ. 

2. The well database had duplicate well entries. Unique well records were selected from the 

well database. 

3. The parish-basin cross reference was created using the spatial join tool in ARC/GIS. 

Separately, the field-parish cross reference table was obtained from LA DEQ, where field 

refers to active oil and gas well fields. 

4. Basin-level production and well counts – The unique well records were linked with the 

parish-basin cross reference table to obtain the active well counts by basin. The field 

production was linked to the field-parish cross reference table on using the <Field_Id> 

data field to obtain parish level production. It should be noted that some oil and gas 

fields span more than one parish. Production from these fields was apportioned to each 

parish using a well count surrogate. 

5. County-level production and well counts – County level production and well count was 

obtained directly from the dataset created in Step#3. 

6. Spud counts – Spud counts for each basin and county were determined by summing all 

wells that had a completion occurring between January 1 2002 and December 31 2002 

and assigning these spuds to each basin using the well location. The county level spud 

count was obtained by adding well completions occurring between January 1 2002 and 

December 31 2002 for each parish in the well database 

Condensate Production 

Condensate, for purposes of this analysis, is defined as liquid hydrocarbon production at gas 

wells. In practice, it is difficult to clearly distinguish between condensate and oil production 

since many state OGCC databases label all liquid hydrocarbon production as oil, and furthermore 

the distinction between oil and gas well designations is defined only by a gas-to-oil ratio (GOR) 

cutoff decided upon by each state OGCC. Except in very clear circumstances, in which a 

geographical region is dominated by gas production with only incidental oil production, it is 

difficult to distinguish between condensate and oil production. 

Due to the organizational structures of the state OGCC databases that were used to develop the 

oil and gas statistics for this project, as described above, it was not always possible to link a 

production database to a well-level database, in which case it was impossible to determine if the 

“oil” production occurred at a true oil well, or at a gas well (in which case it should be termed 

condensate). For basins that span multiple states, including states where well-level production 

could not be determined, it was therefore not possible to determine the sum of condensate 
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production for the entire basin. Because of this lack of geographic consistency due to the 

limitations of the OGCC databases, this work does not present estimates of condensate 

production, but rather only total oil production for each basin. 

However, because condensate tanks can be an important VOC source category, the 

recommendations section does present information on determining condensate tank emissions 

per unit of condensate production. If CENRAP or individual states are able to obtain more 

detailed well-level production data, such as potentially from use of a commercial database, these 

emissions factors could be used to determine condensate tank emissions. 

In the case of Texas basins, it should be noted that the Texas Railroad Commission does track 

condensate production separately from oil production. The condensate production for all basins 

in Texas is shown in Table 2. 

Table 2. 2002 by-basin condensate production for the State of Texas. 

Basin

Condensate 

Production 

[bbl] 

Anadarko Basin (portion in Texas) 939,154

Bend Arch-Ft. Worth Basin (portion in Texas) 1,310,103

East Texas Basin 3,875,885

Marathon Thrust Belt 320,014

Palo Duro Basin (portion in Texas) 39,148

Permian Basin 2,563,403

Western Gulf Basin (portion in Texas) 30,527,660

Texas Total 39,575,367

Note that the Anadarko, Bend Arch-Ft.Worth, Palo Duro and Western Gulf Basins’ boundaries 

include sections of the basins outside of Texas. Condensate production for only the Texas 

portions of these basins is presented here. It should also be noted that the oil production totals 

for Texas, obtained from the RRC, are for true oil only since the RRC has already separately 

totaled the condensate production. 

Coal-Bed Methane Wells 

Coal-bed methane (CBM) wells are gas wells in which the gas reservoir is trapped in 

underground flooded coal seams. These wells are typically shallow wells with well depths 

ranging from 3,000 – 5,000 feet, and require dewatering before any production can begin. Once 

production does begin the produced CBM well gas is characterized by high methane content, and 

an extremely low (or negligible) VOC content. This low VOC content affects estimates of VOC 

emissions from venting or fugitive sources such as blowdowns, dehydrators, or pneumatic 

devices. In analysis of some Rocky Mountain States basins, ENVIRON has made efforts to 

track CBM well counts and production separately from conventional wells to properly account 

for VOC emissions from these wells. However, due to the limitations in the CENRAP states’ 

OGCC databases used for this analysis, well type was not identifiable from much of the oil and 

gas statistical data. 
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From the Arkansas and Kansas databases, it was possible to determine a count of CBM wells, 

although in the case of Kansas well-level production cannot be determined. In Arkanas, of the 

3,776 active wells in the state, only 19 CBM wells were identified representing 0.5% of the 

active well count, a negligible proportion. In Kansas 804 individual CBM wells were identified, 

but these CBM wells represent only 1.7% of the active wells identified in the state for 2002. 

From the Texas RRC and Nebraska OGCC databases, no CBM wells were identified in either 

state. In Oklahoma the OCC database for gas wells identified no CBM wells. For Louisiana, the 

LADNR database does not identify a well type classification except by production values. 

Therefore Louisiana wells were classified only as oil or gas wells. 

Due to these limitations, CBM wells and CBM gas production are not considered further in this 

analysis. 

Summary Statistics 

The summary by basin of all of the individual state oil and gas statistics analyses is presented in 

Table 3, including gas production, oil production, condensate production, active well count, and 

spud count for each basin. These data are also presented in Appendix A, which references a MS 

Excel spreadsheet included as an attachment with this report that provides all detailed oil and gas 

production statistics derived as part of this task. 

Table 3. 2002 gas production, oil production, active well counts and spud counts for all 

producing basins in the CENRAP domain. 

Basin 

Gas 

Production 

[MCF] 

Oil 

Production 

[bbl] 

Active Well 

Count 

Spud 

Count 

Anadarko Basin 1,732,269,135 40,279,230 88,406 2,327 

Arkoma Basin 364,833,847 3,019,091 12,401 739 

Bend Arch-Ft. Worth 

Basin 321,056,553 24,156,879 106,173 1,662 

Cambridge ArchCentral Kansas Uplift 6,442,698 14,649,639 10,366 387 

Cherokee Platform 31,040,321 16,693,567 33,779 862 

Denver Basin 1,192,111 1,321,300 1,288 11 

East Texas Basin 980,666,377 23,944,407 33,453 1,159 

Forest City Basin 415,029 946,580 5,850 131 

Louisiana-Mississippi 

Salt Basins 391,332,732 13,146,248 34,805 203 

Marathon Thrust Belt 63,294,963 56,723 278 15 

Nemaha Uplift 27,773,241 8,419,664 11,913 249 

Ozark Uplift 48,946 0 5 0 

Palo Duro Basin 31,360,922 6,215,265 2,556 48 

Permian Basin 679,260,325 256,544,364 113,598 2,957 

Salina Basin 0 227,996 247 3 

Sedgwick Basin 24,983,651 3,196,023 3,455 137 

Southern Oklahoma 

Basin 60,355,759 18,586,235 24,651 349 

Western Gulf Basin 3,410,532,407 100,096,887 108,403 2,641 

TOTAL 8,126,859,017 531,500,098 591,627 13,880 
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In addition, the data were summarized by basin for each state individually, for the use of each 

state’s department of environmental quality. Table 4 shows the sum of gas production, oil 

production, active well counts and spud counts for all basins in each state, for all 6 states for 

which there is significant oil and gas production in the CENRAP domain. 

Table 4. 2002 gas production, oil production, active well counts and spud counts for each basin 

in the CENRAP domain organized by state including state totals. 

State Basin 

Gas 

Production 

[MCF] 

Oil 

Production 

[bbl] 

Active Well 

Count 

Spud 

Count 

Arkoma Basin 86,578,335 1,690 2,270 97

Louisiana-Mississippi 

Salt Basins 13,895,085 4,699,223 1,438 63

Ozark Uplift 48,946 0 5 0

Arkansas 

Arkansas Total 100,522,366 4,700,913 3,713 160

Anadarko Basin 420,610,798 11,902,176 11,838 665

Cambridge ArchCentral Kansas Uplift 6,442,210 13,349,217 9,383 371

Cherokee Platform 6,187,659 1,826,639 12,942 386

Forest City Basin 415,029 929,653 5,802 131

Nemaha Uplift 438,666 1,958,147 2,603 61

Salina Basin 0 216,420 237 3

Sedgwick Basin 24,983,651 3,196,023 3,455 137

Kansas 

Kansas Total 459,078,013 33,378,275 46,260 1,754

Louisiana-Mississippi 

Salt Basins 377,437,647 8,447,025 33,367 140

Western Gulf Basin 972,402,468 51,658,179 15,533 224 Louisiana 

Louisiana Total 1,349,840,115 60,105,204 48900 364

Cambridge ArchCentral Kansas Uplift 488 1,300,422 983 16

Denver Basin 1,192,111 1,321,300 1,288 11

Forest City Basin 0 16,927 48 0

Salina Basin 0 11,576 21 0

Nebraska 

Nebraska Total 1,192,599 2,650,225 2,340 27

Anadarko Basin 980,495,277 22,751,853 50,037 1,327

Arkoma Basin 278,255,512 3,017,401 10,131 642

Bend Arch-Ft. Worth 

Basin 0 220,116 279 5

Cherokee Platform 24,852,662 14,866,928 20,837 476

Nemaha Uplift 27,334,575 6,461,517 9,310 188

Palo Duro Basin 2,769,295 126,406 303 6

Southern Oklahoma 

Basin 60,355,759 18,586,235 24,650 349

Oklahoma 

Oklahoma Total 1,374,063,080 66,030,456 115,547 2,993

Anadarko Basin 331,163,060 5,625,201 26,531 335

Bend Arch-Ft. Worth 

Basin 321,056,553 23,936,763 105,894 1,657

East Texas Basin 980,666,377 23,944,407 33,453 1,159

Marathon Thrust Belt 63,294,963 56,723 278 15

Palo Duro Basin 28,591,627 6,088,859 2,253 42

Permian Basin 679,260,325 256,544,364 113,598 2,957

Western Gulf Basin 2,438,129,939 48,438,708 92,870 2,417

Texas 

Texas Total 4,842,162,844 364,635,025 374,877 8,582

GRAND TOTAL 8,126,859,017 531,500,098 591,637 13,880
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From these summary statistics, the following eleven basins were identified as the “major” oil and 

gas production basins in the CENRAP region because they collectively represent greater than 

95% of production of oil, production of gas, and active well counts: 

• Anadarko Basin 

• Arkoma Basin 

• Bend Arch-Fort Worth Basin 

• Cambridge Arch-Central Kansas Uplift 

• Cherokee Platform 

• East Texas Basin 

• Louisiana-Mississippi Salt Basins 

• Nemaha Uplift 

• Permian Basin 

• Southern Oklahoma Basin 

• Western Gulf Basin 

Recommendations for emissions calculations and specific input data for those calculations are 

provided for these specific basins, based on this analysis, in the sections below. 

TASK 2a: LITERATURE REVIEW 

A literature review was conducted to obtain information from published studies or reports on 

activity, equipment, configuration, emissions, and usage of typical oil and gas area sources to 

improve the input data used to generate emissions inventories for the CENRAP states. This task 

consisted of obtaining inventory input data from one of the two sources considered in this work – 

the other source is the survey process described in the following section – and was modeled after 

the specific literature review request by CENRAP. 

CENRAP identified the need to improve input information used to generate state-level and 

CENRAP regional inventories of oil and gas area sources and this represents the bulk of the 

work product of this project. This information includes such data as: 

• engine types 

• engine counts 

• horsepower 

• annual usage 

• emissions factors 

• configuration 

• natural gas compositions 

• venting statistics 

• fugitive components 

• pneumatic device counts 

• pneumatic device and fugitive component bleed rates 

• dehydrator configurations 

• heater usage 
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This list is not intended as a complete list, but only a sample of the type of data used in 

calculations of various source categories related to oil and gas. The complete description of the 

methodology and input data recommended for each major oil and gas source category considered 

in this work is found in the recommendations section of the report, along with a list of the 

specific major source categories for which literature data was sought. 

Two sources were used to select specific literature to include in this task: (1) a list compiled by 

CENRAP and specifically cited in the workplan for this project; and (2) additional studies of 

which ENVIRON is aware that could provide useful input to oil and gas inventory calculations. 

The detailed list of literature considered in this work is presented below in Table 5: 

Table 5. List of studies and other literature reviewed as part of Task 1. 

Study Number Title Geographic Domain 

1 WRAP Phase III Oil and Gas Emissions 

Inventory (Bar-Ilan, et al., 2008) 

Western regional U.S. 

2 WRAP Phase II Oil and Gas Emissions 

Inventory (Bar-Ilan et al., 2007) 

Western regional U.S. 

3 WRAP Phase I Oil and Gas Emissions 

Inventory (Russell, et al., 2005) 

Western regional U.S. 

4 

MMS Analysis to Quantify Oil and Gas 

Activity in the Gulf of Mexico Region 

(Wilson, et al., 2007) 

Gulf of Mexico offshore oil and gas wells 

5 

Ozone Precursors Emission Inventory 

for San Juan and Rio Arriba Counties, 

New Mexico (Russell, et al., 2006) 

San Juan and Rio Arriba Counties in the 

Four Corners region of New Mexico 

6 

NETAC Tyler/Longview/Marshall 

Flexible Attainment Region Emission 

Inventory for Ozone Precursors 

(Pollution Solutions, 2005) 

Boundaries of the 

Tyler/Longview/Marshall attainment 

region in Northeast Texas 

7 

“VOC Emissions from Oil and 

Condensate Tanks” Study performed 

for HARC by URS (Hendler et al., 2006) 

Generally applicable to oil and gas 

development in Texas 

8 

Oil and Gas Area Source Emissions 

Estimates provided by TCEQ 

(Pendleton, et al., 2008) 

State of Texas 

9 

Inventory of Nitrogen Oxide Emissions 

in Alberta’s Upstream Oil and Gas 

Industry (Bhardwaj, 2002) 

Province of Alberta, Canada 

10 

DIAL Measurements of Fugitive 

Emissions from Natural Gas Plants and 

Comparison with Emissions Factors 

(Chambers, et al., 2006) 

Province of Alberta, Canada 

11 

NETAC Tyler/Longview/marshall 

flexible Attainment Region Special 

Study Relating to Oil and Gas 

Production: 2005 and 2007 Emissions 

from Compressor Engines with 

Consideration for Load Factor (Pollution 

Solutions, 2007) 

Boundaries of the 

Tyler/Longview/Marshall attainment 

region in Northeast Texas 

In all cases, literature was reviewed for useful information and to determine the applicability of 

that information to oil and gas inventory calculations in the CENRAP domain. Specifically, 

ENVIRON used the following criteria to analyze the literature and determine its applicability to 

the recommended data: 
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4. Geographic scope: The most important criterion applied to determine the applicability of 

a literature source was the geographic scope which the study or report covers. Production 

characteristics vary on the basin level, with some basins being dominated by oil or gas 

production, or having significant CBM gas production where other basins do not, or 

incorporating oil shale activities where other basins do not. Drilling operations vary 

significantly from region to region, driven primarily by the type and depth of well drilled 

and the associated rig horsepower requirements. Composition of the produced gas and 

oil vary widely from basin to basin, with respect to the condensate content of gas, VOC 

content of gas, oil composition, and presence of sulfur. These are some of the regional 

differences that can affect the usage of particular equipment and would necessarily affect 

the development of oil and gas emissions inventories for a particular basin. ENVIRON’s 

experience in the development of oil and gas emissions inventories leads us to conclude 

that regional differences in oil and gas production activities are sufficient that local data 

must be used where possible. 

5. Age of study: There has been increased interest in emissions from oil and gas exploration 

and production activities in the past decade, driven by the substantial growth in this 

activity particularly in the Rocky Mountain States. Because of this, new studies have 

been conducted which may result in older studies becoming out of date. To the extent 

possible this criterion was applied to the selection of specific data from some of the 

studies and reports listed in Table 5. Where a more recent study investigating a particular 

subject was available, the more recent study was used. 

6. Consistency of data with other sources: Data consistency was used as a QA/QC tool to 

evaluate the usefulness and applicability of data extracted from all of these studies and 

reports. Data were reviewed to be consistent both with other studies, and with detailed 

information collected by ENVIRON as part of the development of oil and gas inventories 

in the western states. This consistency was evaluated for sources where it is expected 

that the configuration, emissions and usage would be similar from region to region, such 

as for a particular make and model of engine. 

These criteria were applied to the sources listed in Table 5 and data that were determined to be 

useful were extracted and compiled in a master matrix of data fields for estimation of emissions 

from all the major oil and gas source categories. This information was supplemented by data 

obtained from a limited survey of select oil and gas companies, which is described further in the 

survey section below. From the combined literature review and survey data recommended data 

were determined for specific data fields. 

TASK 2b: LIMITED INDUSTRY SURVEY 

In addition to the literature review described above in Task 2a, ENVIRON also undertook a 

limited survey targeted at major oil and gas companies operating in the CENRAP region to 

obtain additional data from these companies for use as input data to emissions inventory 

calculations for oil and gas area sources. This was done primarily for two reasons. First, 

through the development of the Rocky Mountain States oil and gas emissions inventories under 

the various WRAP projects it has been ENVIRON’s experience that industry participation is 

essential to develop the most accurate database of information on equipment, usage of the 

equipment, field processes, and emissions factors and other support data. This is because oil and 

gas field operations vary greatly from basin to basin and only these companies can provide 

accurate information about the equipment they own and its usage. Second, through the WRAP 
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regional inventories in the western U.S., ENVIRON has developed working relationships and 

contacts with many of the major oil and gas companies operating in this region, and therefore it 

was supposed that ENVIRON’s use of those contacts could result in a good response to a survey. 

In the past decade, the oil and gas industry has seen considerable consolidation, so that a large 

fraction of oil and gas production in most of the continental U.S. is now owned by a smaller 

number of companies. As a result of this consolidation, many of the same companies with which 

ENVIRON has developed contacts particularly through the ongoing IPAMS/WRAP Phase III 

project (Bar-Ilan, et al., 2008) are those with a large ownership of production in the CENRAP 

domain. 

Companies that were targeted for the survey process were identified by analysis of the oil and 

gas production statistics developed as part of Task 1. To the extent possible, a list of the top 

ownership of gas production, oil production and well counts was developed for each basin. 

However, for Texas, Louisiana, and Kansas the production and well statistics were unavailable 

by owner/operator, and it was not possible to generate a ranked list of ownership by basin. For 

these states, the respective OGCC’s did provide a list of top ownership of oil and gas production 

for the state as a whole and this was assumed to apply to all basins in these states. For 

Oklahoma, well-level oil production data were not available, and a similar methodology to that 

in Texas, Louisiana and Kansas was applied to determine top oil producing companies in 

Oklahoma. These lists were then reviewed to determine which companies had significant past 

interaction with ENVIRON through the WRAP Phase I, Phase II, Phase III western regional oil 

and gas projects and the NMED ozone precursors project in the Four Corners region. These 

were the primary projects in which ENVIRON interacted with industry participants in survey 

processes. The top companies list was then evaluated in order to condense the list to only those 

companies that ENVIRON determined from past experience would be likely to participate in a 

survey process. Since the industry has consolidated, those companies operating in the same 

basin are likely to use similar processes and equipment configurations, therefore the goal of 

condensing the list to a select number of companies was to ensure that each basin was 

represented by at least one company that ENVIRON determined might be likely to respond to 

the survey. 

The final condensed list of companies that were selected for consideration in this survey process 

is presented in Table 6, which indicates the geographic areas of major operations owned by each 

company. Of the companies listed in Table 6, ExxonMobil, Occidental Petroleum, El Paso 

Corporation, and Petro-Chem Operating were not included in the survey process because of 

ENVIRON’s past experience in developing a survey process for the WRAP and separately for 

the NMED. These companies were ones that were resistant to participation in the past survey 

efforts and thus deemed unlikely to agree to participate in this CENRAP survey process. These 

companies were not sent a survey form. 

The remaining nine companies were sent a survey form, but of these companies only four 

responded with a sufficiently complete survey response to be usable. It should be noted that 

ENVIRON has worked extensively with BP America in several oil and gas related projects and 

has very good contacts with this company. BP America is notable among the oil and gas 

companies with which ENVIRON has worked for the extensive and detailed emissions inventory 

recordkeeping documents that the company produces, and has made available to ENVIRON as 

part of the western regional work. It was hoped that BP would also be willing to participate in 

this CENRAP survey process, but to date no survey response has been received from the 

company. If a survey response is received by ENVIRON from BP America beyond the end date 

of this project, ENVIRON will make the survey responses available to CENRAP as these will 
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likely be useful additional data covering the regions where BP America has major oil and gas 

operations. 

Table 6. Summary of companies contacted as part of the survey process including their regions 

of operation and the status of their responses to the survey. 

Company 

Geographic Area of 

Major Operations 

(by basin) 

Survey 

Sent 

(Y/N) 

Survey 

Received 

(Y/N) 

BP America 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, Cambridge Arch-Central 

Kansas Uplift, East Texas, 

Marathon Thrust Belt, Palo Duro, 

Permian, Sedgwick, Western Gulf 

Y N 

Conoco-Phillips 

Anadarko, Bend Arch-Ft. Worth, 

East Texas, Marathon Thrust Belt, 

Nemaha Uplift, Palo Duro, Permian, 

Sedgwick, Western Gulf 

Y N 

Chevron Southern Oklahoma Y N 

Anadarko Petroleum 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, Cambridge Arch-Central 

Kansas Uplift, East Texas, Permian, 

Southern Oklahoma, Western Gulf 

Y Y 

Encana USA Bend Arch-Ft. Worth, East Texas, 

Permian, Western Gulf Y Y 

Devon Energy 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, East Texas, LouisianaMississippi Salt, Nemaha Uplift, 

Permian, Sedgwick, Western Gulf 

Y Y 

Noble Energy 

Anadarko, Arkoma, Cambridge 

Arch-Central Kansas Uplift, 

Cherokee Platform, East Texas, 

Louisiana-Mississippi Salt Basins, 

Nemaha Uplift, Permian, Southern 

Oklahoma, Western Gulf 

Y Y 

EOG Resources 

Anadarko, Bend Arch-Ft. Worth, 

Cambridge Arch-Central Kansas 

Uplift, East Texas, Nemaha, 

Permian, Southern Oklahoma, 

Sedgwick 

Y N 

XTO 

Anadarko, Arkoma, Bend Arch-Ft. 

Worth, Cambridge Arch-Central 

Kansas Uplift, Cherokee Platform, 

East Texas, Nemaha Uplift, Palo 

Duro, Permian, Southern 

Oklahoma, Western Gulf 

Y N 

ExxonMobil Arkoma, Louisiana-Mississippi Salt 

Basins N – 

Occidental Petroleum Permian N – 

El Paso Corporation Louisiana-Mississippi Salt Basins N – 

Petro-Chem Operating Louisiana-Mississippi Salt Basins N – 

The four companies that did provide survey responses – Andarko Petroleum, Devon Energy, 

Encana USA, and Noble Energy – cover a wide geographic range of activities in the CENRAP 

domain including many of the major basins of interest for this study. The data provided in these 

surveys were evaluated for quality, applicability and usefulness and combined with literature 
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review data for particular fields to generate a combined data matrix as described below in the 

recommendations section of the report. The survey data from the four responding companies 

were evaluated using the same general criteria that were used to evaluate literature review 

sources. The specific criteria used to evaluate the surveys were: 

1. Geographic specificity: Survey responses were evaluated to determine if the data 

provided were sufficiently specific to individual basins where the respondent had 

significant operations. Broad, company-wide data and assumptions were generally not 

included in the summary data matrix because these data could not then be applied to 

specific geographic regions. 

2. Quality of data: ENVIRON reviewed survey responses for data quality to determine if 

responses to specific survey data requests were beyond the typical range of these 

responses as determined by comparison to similar data collected by ENVIRON as part of 

other oil and gas survey efforts. In these cases, efforts were made to clarify responses by 

contacting individual companies and by reviewing their operations for any unusual 

activities that would warrant extremely high or low data for particular data fields. Data 

that were determined to be beyond the range of typical values for a particular data field 

were generally rejected from further consideration in this analysis. 

3. Applicability and usefulness: Data were reviewed for applicability and usefulness in 

terms of the basin-level emissions estimates that are described in the recommendations 

section below. Responses to the survey that could not be easily converted into 

representative equipment or process input data were rejected from consideration in this 

analysis. An example of this is a response indicating the total number of wellhead 

compressors operated by the company in a basin or for the entire regional operations of 

the company. Without detailed active well count ownership by the company, it would be 

impossible to determine the fraction of wells with wellhead compressors, which is the 

necessary input data field for estimating basin-level wellhead compressor emissions. 

The surveys requested information on the following major oil and gas source categories: 

• Drilling rigs 

• Compressor engines 

• Artificial lift engines 

• Heaters 

• Condensate and Oil tanks 

• Fugitive emissions 

• Pneumatic devices 

• Completion/recompletion venting and well blowdowns 

These source categories were selected based on ENVIRON’s past work and current 

IPAMS/WRAP Phase III analysis (Bar-Ilan, et al., 2008) as being the most significant 

contributors to NOx and VOC emissions sources from combustion and fugitive/venting source 

categories. In addition to these, surveys requested information on basin-level average natural gas 

composition analyses, which provide necessary input information on the VOC content of gas for 

estimating VOC emissions from fugitive and venting sources, and for H2S content of gas to 

separately track these emissions. 

The survey forms asked for basic data that would be used to determine necessary input values for 

basin-level emissions calculations. These included data fields such as: equipment counts; 
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horsepower, load factors, firing rates, usage and emissions factors; equipment configuration for 

multi-engine equipment (e.g. drilling rigs); venting rates and event counts for venting source 

categories; well configurations for estimating emissions from pneumatics and fugitives; and 

basic emissions rate data for estimating flashing and working/breathing losses from stock tanks. 

The complete set of data requests for all source categories considered in the survey process are 

presented in the survey questionnaire form, which is provided as Appendix B. 

TASK 3a: RECOMMENDED SOURCE CATEGORY EMISSION CALCULATION 

METHODOLOGIES AND INPUT DATA FOR BASELINE 2002 EMISSIONS 

This section describes the recommended methodologies and input data to be used in estimating 

basin-level emissions of each major oil and gas source category for all of the CENRAP basins 

for the 2002 baseline year. This section presents the detailed methodologies as an equation or 

series of equations, and defines the values of the terms of these equations for each major oil and 

gas basin identified as part of Task 1. Equations are presented for estimating emissions for a 

single source in a category, and then to scale that source category to basin-level emissions. The 

major oil and gas area source categories considered in this analysis, and whose emissions 

estimation methodologies and input data are presented below, are: 

• Wellhead Compressor Engines 

• Lateral Compressor Engines 

• Artificial Lift Engines (Pumpjacks) 

• Drilling Rigs 

• Heaters 

• Flaring 

• Oil Tanks (Flashing and Working & Breathing Losses) 

• Condensate Tanks (Flashing and Working & Breathing Losses) 

• Dehydrators 

• Completion Venting 

• Well Blowdowns 

• Fugitive Emissions 

• Pneumatic Devices 

While this does not represent a complete list of all oil and gas area source categories, this list 

comprises the major area source categories that contribute the vast majority of emissions to a 

basin-level inventory per ENVIRON’s experience in development of these inventories. These 

are also the source categories with the most complete set of input data that can be obtained 

through literature review and survey efforts, and thus result in the least inaccuracy and error in 

emissions estimation. 

Following the information collected as part of the literature review and limited survey efforts, 

described in Tasks 2a and 2b, ENVIRON gathered these data together on all of the major oil and 

gas area source categories and developed a master data matrix to determine the most suitable 

data for each source category emissions estimate. From the data matrix specific values were 

selected as input data for emissions estimates for each source category for each major basin, and 

a rationale is provided for the choice of input data. In general the selection of input data made 

use of information from the industry survey responses to the extent possible. The survey data 

was assessed as described above for geographic specificity, quality of data, and applicability and 
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if the data passed all of these criteria the survey data was recommended. This is because the 

operators of these sources are believed to have the most accurate information on equipment 

types, horsepower, usage, and emissions factors. If the surveys were unable to provide usable, 

high quality data for a particular input data field, the next choice was to recommend similar data 

from the literature review. As discussed above, the data obtained from literature review were 

also subject to specific criteria regarding geographic scope, age of the study and consistency of 

the data with other known or published data with which ENVIRON has worked. Where neither 

survey nor literature data were available for a particular data input for a particular basin, the 

average of that value across all other CENRAP basins was used. For each data field for each 

source category and for all of the major basins, a summary is provided of the rationale for 

selection of the data source. 

It should be noted that these input data are intended for use in developing CENRAP’s broad 

regional inventory and as such provide information necessary to estimate emissions on the basin 

level only. There are various studies, conducted by regional government agencies or state DEQs 

and other agencies and organizations that have focused on a specific aspect of oil and gas area 

source emissions for very specific regions. ENVIRON is aware that the TCEQ and other Texas 

agencies have sponsored studies that focus on inventorying equipment or emissions for very 

specific geographical regions, but we are not aware of similar studies in other CENRAP states. 

Due to the need to make broad, basin-level assumptions in order to tractably estimate emissions 

for the entire CENRAP domain, it is not always possible to incorporate data from localized 

studies. However, CENRAP should consider analyzing the results of any detailed study to 

determine if some synthesis is possible that would produce improved emissions estimates for the 

region covered by the study. 

Finally, it should be noted that these data are intended as inputs to emissions inventory 

calculations at the basin level. The inventory calculations themselves are not a part of the scope 

of this work, but the data are presented in a form that would allow for conducting these 

calculations in the future. For this reason the data are also provided in the accompanying 

recommended data spreadsheet. 

Wellhead Compressor Engines 

Methodology: 

Wellhead compressor engines represent one of the most significant oil and gas NOx area source 

categories. Depending on the basin and the fractional usage of these engines, there may be many 

thousands of individual wellhead compressor engines located at many well sites. These engines 

are used to boost produced gas pressure from downhole pressure to the required pressure for 

delivery to a transmission pipeline. Generally these engines are natural-gas powered, using the 

produced gas (after some separation and dehydration) as fuel for a spark-ignited internal 

combustion engine. Based on numerous survey responses as part of this analysis and previous 

ENVIRON experience, it has been determined that natural gas produced with a high sour gas 

content (H2S) is used directly in wellhead compressor engines once they have been properly 

modified to handle H2S. Therefore wellhead compressor engines are only a source of sulfur 

emissions if H2S is present in the gas. They generally operate 8760 hours per year with a 

minimum of down-time. Any down-time is typically associated with repairs or routine 

maintenance, but gas production companies attempt to minimize this down-time to the extent 

possible. 
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The most common makes of wellhead compressor engines are Caterpillar, Waukesha, and Ajax. 

Generally wellhead compressor engines are uncontrolled, but two distinct types are utilized: 

“rich-burn” engines that are characterized by NOx emissions factors in the range of 

approximately 10 – 20 g/bhp-hr; and “lean-burn” engines that are characterized by NOx 

emissions factors in the range of approximately 1.0 – 5.0 g/bhp-hr. The exact NOx emissions 

factors depend on the horsepower of the engine, the make and model, the model year of the 

engine, and whether the engine has been converted from a rich-burn to a lean-burn engine. 

Wellhead compressor engines are distinct from lateral or central compressor engines in that they 

are smaller in size. Generally wellhead compressor engines have a horsepower range of 

approximately 50 – 250 hp. The actual brake horsepower of the wellhead compressor engine in 

use in the field depends primarily on the field gas pressure. Larger engines installed at a time 

when field pressure was high may be running at very low load factors if the well is in significant 

decline in production. 

Again it should be noted that the information presented below is intended to generate basin-level 

emissions estimates for wellhead compressor engines. There have been very detailed studies that 

have attempted to inventory these engines for specific gas fields or other localized geographic 

regions, but these studies often cannot present the data in a manner that allows for a basin-level 

calculation. The methodology and recommended data are for a basin-level calculation that 

necessitates relying on assumptions of wellhead compressor engine composition to make the 

calculation tractable. However, CENRAP should continue to consider additional studies that 

inventory these engines in specific geographic regions and incorporate them into a basin-level 

analysis. 

The basic methodology for estimating emissions from wellhead compressor engines is shown in 

Equation (1): 

Equation (1) 907 ,185

i annual

engine

EF HP LF t E× × × =

where: 

Eengine are emissions from a rich-burn or lean-burn 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] 

Extrapolation to Basin-Wide Emissions

Each basin is represented in this work by a single representative rich- and lean-burn wellhead 

compressor engine make/model. The emissions are then scaled to the basin level using the ratios 

of rich-burn engines to total engines, lean-burn engines to total engines, the fraction of wells 

with wellhead compressor engines, and the total well count in the basin, according to Equation 

(2): 

Equation (2) ( ) engine TOTAL Rich engine Rich Lean engine Lean TOTAL wellhead E = C E + C E ×W × f , , ,
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 25

where: 

Eengine,TOTAL is the total emissions from compressor engines in the basin [ton/yr] 

Eengine,Rich is the total emissions from a single representative rich-burn compressor engine per 

Equation (1) [ton/yr] 

Eengine,Lean is the total emissions from a single representative lean-burn compressor engine 

per Equation (1) [ton/yr] 

CRich is the fraction of wellhead compressors in the basin that are rich-burn 

CLean is the fraction of wellhead compressors in the basin that are lean-burn 

WTOTAL is the total well count in the basin 

fwellhead is the fraction of all wells in the basin with wellhead compressor engines 

It is recommended to use well count as a surrogate for scaling wellhead compressor emissions to 

the basin level as gas production estimates may underestimate the number of wellhead 

compressors in use. County-level emissions estimates would then be derived by allocating basin 

total wellhead compressor engine emissions to the county level by the fraction of total basin 

wells in each county. 

Input Data

The recommended input data are presented in Tables 7 and 8: 

Table 7. Recommended engine operating parameters for use in estimating wellhead 

compressor emissions for all major CENRAP basins. 

Typical Engine Operating Parameters 

Basin 

Fraction of wells 

with wellhead 

compressors 

Rated 

Horsepower

[hp] 

Annual 

Activity 

[hrs] 

Load 

Factor 

Fraction 

Rich Burn 

Fraction 

Lean Burn 

Anadarko Basin 0.045 130 8760 0.75 0.872 0.128

Arkoma Basin 0.025 73 8760 0.93 1.000 0.000

Cambridge ArchCentral Kansas 

Uplift 0.003 48 8760 1.00 1.000 0.000

Cherokee Platform 

Basin 0.029 101 8760 0.85 0.910 0.090

East Texas Basin 0.015 242 8760 0.66 0.970 0.030

Fort Worth Basin 0.100 124 8760 0.85 0.862 0.138

LouisianaMississippi Salt 

Basins 0.073 46 8760 0.85 0.872 0.128

Nemaha Uplift 0.019 36 8760 0.88 1.000 0.000

Permian Basin 0.025 73 8760 0.85 0.700 0.300

Southern 

Oklahoma Basin 0.020 30 8760 0.90 1.000 0.000

Western Gulf 

Basin 0.450 207 8760 0.80 0.825 0.175
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 26

Table 8. Recommended rich-burn and lean-burn engine emissions factors for use in estimating 

wellhead compressor emissions for all major CENRAP basins. 

Rich-Burn Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

Anadarko Basin 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

Arkoma Basin 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

Cambridge ArchCentral Kansas 

Uplift 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

Cherokee Platform 

Basin 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

East Texas Basin 14.28 4.63 0.84 0.0095 N/A 3.69 110 0.23

Fort Worth Basin 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

LouisianaMississippi Salt 

Basins 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

Nemaha Uplift 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

Permian Basin 14.28 4.63 0.84 0.0095 N/A 14.19 110 0.23

Southern 

Oklahoma Basin 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

Western Gulf 

Basin 14.28 4.63 0.84 0.0095 N/A 0 110 0.23

Lean-Burn Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

Anadarko Basin 3.10 2.29 1.51 0.038 N/A 0 110 1.45

Arkoma Basin 3.10 2.29 1.51 0.038 N/A 0 110 1.45

Cambridge ArchCentral Kansas 

Uplift 3.10 2.29 1.51 0.038 N/A 0 110 1.45

Cherokee Platform 

Basin 3.10 2.29 1.51 0.038 N/A 0 110 1.45

East Texas Basin 3.10 2.29 1.51 0.038 N/A 3.69 110 1.45

Fort Worth Basin 3.10 2.29 1.51 0.038 N/A 0 110 1.45

LouisianaMississippi Salt 

Basins 3.10 2.29 1.51 0.038 N/A 0 110 1.45

Nemaha Uplift 3.10 2.29 1.51 0.038 N/A 0 110 1.45

Permian Basin 3.10 2.29 1.51 0.038 N/A 14.19 110 1.45

Southern 

Oklahoma Basin 3.10 2.29 1.51 0.038 N/A 0 110 1.45

Western Gulf 

Basin 3.10 2.29 1.51 0.038 N/A 0 110 1.45

Data Sources

Engine operating parameters were derived from survey data for most basins. Where survey data 

was not available for a specific basin, the average of all CENRAP basins was used. For the East 

Texas Basin, the recent study by NETAC (Pollution Solutions, 2007) on load factors for 

wellhead compressor engines was used as a source for the load factors. 

Most engine emissions factors were obtained from the NMED ozone precursors study in 

Northwest New Mexico (Russell, et al., 2006), which contained an extensive database of 

emissions factors for a range of wellhead compressor engine makes/models. From this database 

average rich-burn and lean-burn engine emissions factors were derived. PM10, CO2, and CH4

emissions factors were obtained from AP-42 (EPA, 2000). 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 27

SO2 emissions from wellhead compressor engines occur only if there is a significant sulfur 

concentration in the fuel as H2S (sour gas). In the case that there is a significant H2S 

concentration, the wellhead compressors are specially fitted with stainless steel components 

(“trimmed”) to allow the compressor to run this fuel. Therefore it is assumed that all H2S in the 

fuel is combusted and emitted as SO2. The SO2 emissions factors presented in Table 8 are 

calculated from the H2S concentration using the brake-specific fuel consumption (BSFC) of a 

natural-gas fired, spark-ignited engine of the appropriate horsepower obtained from the EPA’s 

NONROAD model (EPA, 2005a). 

Lateral Compressor Engines 

Methodology: 

Lateral compressor engines are mid-sized compressor engines used to gather gas from a large 

number of individual well sites. Although these engines are generally significantly larger than 

wellhead compressor engines, the lateral compressor stations are generally smaller than central 

compressor stations and often do not trigger Title V or other permitting requirements. Whereas 

wellhead compressor engines may be used quite extensively – and in certain basins most gas 

wells will have a wellhead compressor engine – lateral compressor engines generally serve 

groups of 20 – 100 individual wells. Lateral compressors are generally in the range of 1000 – 

1500 hp, and may also have rich-burn and lean-burn models. Unlike wellhead compressors, 

more lateral compressors are likely to be lean-burn engines. 

Emissions from lateral compressors are estimated using a similar methodology to that of 

wellhead compressors. The basic methodology for estimating emissions from later compressor 

engines is shown in Equation (3): 

Equation (3) 907 ,185

i annual

engine

EF HP LF t E× × × =

where: 

Eengine are emissions from a rich-burn or lean-burn 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] 

Extrapolation to Basin-Wide Emissions

Basins are considered to be composed of a single representative rich- and lean-burn lateral 

compressor engine make/model. The emissions are then scaled to the basin level using the ratios 

of rich-burn engines to total engines, lean-burn engines to total engines, the fraction of wells 

with lateral compressor engines, and the total well count in the basin, according to Equation (4): 

Equation (4) ( ) ⎟

⎠

⎞ ⎜

⎝

⎛ = + × × ×

lateral engine TOTAL Rich engine Rich Lean engine Lean TOTAL lateral N E C E C E W f 1 , , ,
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 28

where: 

Eengine,TOTAL is the total emissions from lateral compressor engines in the basin [ton/yr] 

Eengine,Rich is the total emissions from a single representative rich-burn compressor engine per 

Equation (1) [ton/yr] 

Eengine,Lean is the total emissions from a single representative lean-burn compressor engine 

per Equation (1) [ton/yr] 

CRich is the fraction of lateral compressors in the basin that are rich-burn 

CLean is the fraction of lateral compressors in the basin that are lean-burn 

WTOTAL is the total well count in the basin 

flateral is the fraction of all wells in the basin that are served by lateral compressor engines 

Nlateral is the number of wells served by a single lateral compressor engine 

As with wellhead compressor engines, it is recommended that well count be used as a surrogate 

for scaling lateral compressor emissions to the basin level. County-level emissions estimates 

would then be derived by allocating basin total lateral compressor engine emissions to the county 

level by the fraction of total basin wells in each county. It should be noted that not in all basins 

are lateral compressors used, and this is dependent on a complex combination of factors that 

include field pressures, gas production in the basin, pipeline infrastructure, and the configuration 

of central compressor stations. 

Input Data

The recommended input data are presented below in Tables 9 and 10: 

Table 9. Recommended engine operating parameters for use in estimating lateral compressor 

engine emissions for all major CENRAP basins. 

Typical Engine Operating Parameters 

Basin 

Fraction of 

wells with 

lateral 

compressors 

Number of 

wells per 

lateral 

compressor

Rated 

Horsepower

[hp] 

Annual 

Activity 

[hrs] 

Load 

Factor 

Fraction 

Rich 

Burn 

Fraction 

Lean 

Burn 

Anadarko Basin 0.015 20 1100 8760 0.74 0.44 0.56

Arkoma Basin 0 N/A N/A N/A N/A N/A N/A

Cambridge ArchCentral Kansas 

Uplift 0 N/A N/A N/A N/A N/A N/A

Cherokee 

Platform Basin 0 N/A N/A N/A N/A N/A N/A

East Texas 

Basin 0.045 20 1128 8760 0.581 0.45 0.55

Fort Worth Basin 0.01 20 1340 8760 0.7405 0.5 0.5

LouisianaMississippi Salt 

Basins 0 N/A N/A N/A N/A N/A N/A

Nemaha Uplift 0 N/A N/A N/A N/A N/A N/A

Permian Basin 0.02 20 1340 8760 0.7405 0.38 0.63

Southern 

Oklahoma Basin 0 N/A N/A N/A N/A N/A N/A

Western Gulf 

Basin 0.03 20 1340 8760 0.7405 0.25 0.75
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 29

Table 10. Recommended rich-burn and lean-burn engine emissions factors for use in estimating 

lateral compressor engine emissions for all major CENRAP basins. 

Rich-Burn Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

Anadarko Basin 11.88 0.95 1.44 0.0095 N/A 0 110 0.23

Arkoma Basin N/A N/A N/A N/A N/A 0 N/A N/A

Cambridge ArchCentral Kansas 

Uplift N/A N/A N/A N/A N/A 0 N/A N/A

Cherokee Platform 

Basin N/A N/A N/A N/A N/A 0 N/A N/A

East Texas Basin 11.88 0.95 1.44 0.0095 NA 3.69 110 0.23

Fort Worth Basin 11.88 0.95 1.44 0.0095 NA 0 110 0.23

LouisianaMississippi Salt 

Basins N/A N/A N/A N/A N/A 0 N/A N/A

Nemaha Uplift N/A N/A N/A N/A N/A 0 N/A N/A

Permian Basin 11.88 0.95 1.44 0.0095 NA 14.19 110 0.23

Southern 

Oklahoma Basin N/A N/A N/A N/A N/A 0 N/A N/A

Western Gulf 

Basin 11.88 0.95 1.44 0.0095 NA 0 110 0.23

Lean-Burn Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

Anadarko Basin 3.22 1.77 1.73 0.038 N/A 0 110 1.45

Arkoma Basin N/A N/A N/A N/A N/A 0 N/A N/A

Cambridge ArchCentral Kansas 

Uplift N/A N/A N/A N/A N/A 0 N/A N/A

Cherokee Platform 

Basin N/A N/A N/A N/A N/A 0 N/A N/A

East Texas Basin 3.22 1.77 1.73 0.038 NA 3.69 110 1.45

Fort Worth Basin 3.22 1.77 1.73 0.038 NA 0 110 1.45

LouisianaMississippi Salt 

Basins N/A N/A N/A N/A N/A 0 N/A N/A

Nemaha Uplift N/A N/A N/A N/A N/A 0 N/A N/A

Permian Basin 3.22 1.77 1.73 0.038 N/A 14.19 110 1.45

Southern 

Oklahoma Basin N/A N/A N/A N/A N/A 0 N/A N/A

Western Gulf 

Basin 3.22 1.77 1.73 0.038 N/A 0 110 1.45

Data Sources

Engine operating parameters – and particularly the number of wells per lateral compressor and 

the fraction of wells using lateral compressors, by basin – were derived from survey data for 

most basins. Where survey data was not available for a specific basin, the average of all 

CENRAP basins was used. As noted above, many basins do not have any significant usage of 

lateral compressors, as indicated in Table 9 with the entry “N/A”. 

Most engine emissions factors were obtained from the NMED ozone precursors study in 

Northwest New Mexico (Russell, et al., 2006), which contained an extensive database of 

emissions factors for a range of compressor engine makes/models. From this database average 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 30

rich-burn and lean-burn engine emissions factors were derived. PM10, CO2, and CH4 emissions 

factors were obtained from AP-42 (EPA, 2000). 

SO2 emissions factors for lateral compressor engines are calculated using the H2S concentration 

in the fuel, similar to the method used for wellhead compressor engines. 

Artificial Lift (Pumpjack) Engines 

Methodology

Artificial lift engines (or pumpjacks) in this analysis refer specifically to engines located at oil 

wells to provide lift to the bring liquid from a well up to the wellhead. These engines are, from 

an emissions standpoint, very similar to wellhead compressor engines for gas wells in that they 

are usually small, natural gas-fired engines. Generally pumpjacks have smaller engines than 

wellhead compressor engines, but they are similarly in use almost constantly at oil wells. In 

basins with substantial numbers of oil wells, pumpjacks may be a significant NOx source 

category. Some pumpjack engines are electrified, if the electrical grid is located sufficiently near 

the oil field and if the economics of drawing electrical power make electrification attractive to 

the operators. If pumpjacks are electrified, their emissions are assumed to be zero. 

The basic methodology for estimating emissions from a single non-electrified artificial lift 

engine is very similar to that of a wellhead compressor engine. The methodology is shown in 

Equation 5: 

Equation (5) 907,185

i annual

engine

EF HP LF t E× × × =

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] 

Extrapolation to Basin-Wide Emissions

Similarly to wellhead compressor engines, it is recommended that artificial lift engine emissions 

be scaled up to the basin level on the basis of well count. Using a scaling on the basis of oil 

production may understate the usage of artificial lift engines, since when oil fields are in decline 

these artificial lift engines may be increasingly used to provide the necessary lift to bring the 

product up to the wellhead. The methodology for scaling up artificial lift engine emissions is 

shown below in Equation 6: 

Equation (6) ( ) engine TOTAL engine pumpjack pumpjack WTOTAL E , = E × f × 1− e ×

where: 

Eengine,TOTAL is the total emissions from artificial lift engines in the basin [ton/yr] 

Eengine is the total emissions from an artificial lift engine (as shown in Equation 5) [ton/yr] 

WTOTAL is the total number of wells in the basin 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 31

fpumpjack is the fraction of oil wells with artificial lift engines 

epumpjack is the fraction of artificial lift engines that are electrified 

County-level emissions would be estimated by allocating the total basin-wide artificial lift engine 

emissions into each county according to the fraction of basin wells located in each county. 

Because it is not possible in all basins to provide well counts by well type (e.g. oil vs. gas wells) 

it is recommended that the total well count be used to scale artificial lift engine emissions. If 

more detailed oil and gas well databases that track wells by well type become available to 

CENRAP in the future, it is recommended that the scale-up methodology use a count of oil wells 

in the basin, rather than all wells in the basin. 

Input Data

The recommended input data are presented below in Tables 11 and 12: 

Table 11. Recommended engine operating parameters for use in estimating artificial lift engine 

(pumpjack) emissions for all major CENRAP basins. 

Typical Engine Operating Parameters 

Basin 

Fraction of wells 

with artificial lift 

(pumpjack) engines 

Rated 

Horsepower

[hp] 

Annual 

Activity 

[hrs] 

Load 

Factor 

[%] 

Fraction 

Electrified 

Anadarko Basin 1.00 25 8760 0.65 0.31

Arkoma Basin 1.00 13 8760 0.65 0.45

Cambridge ArchCentral Kansas Uplift 1.00 29 8760 0.65 0.97

Cherokee Platform 

Basin 1.00 23 8760 0.65 0.80

East Texas Basin 1.00 42 8760 0.65 0.00

Fort Worth Basin 1.00 15 8760 0.65 0.74

Louisiana- Mississippi 

Salt Basins 1.00 N/A N/A N/A 0.67

Nemaha Uplift 1.00 27 8760 0.65 0.87

Permian Basin 1.00 25 8760 0.65 1.00

Southern Oklahoma 

Basin 1.00 29 8760 0.65 0.97

Western Gulf Basin 1.00 60 8760 0.65 0.67

Table 12. Recommended engine emissions factors for use in estimating artificial lift engine 

emissions for all major CENRAP basins. 

Artificial Lift Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

Anadarko Basin 11.99 40.93 1.28 0.05 N/A 0 631 30.5

Arkoma Basin 11.99 40.93 1.28 0.05 N/A 0 631 30.5

Cambridge ArchCentral Kansas 

Uplift 11.99 40.93 1.28 0.05 N/A 0 631 30.5

Cherokee Platform 

Basin 11.99 40.93 1.28 0.05 N/A 0 631 30.5

East Texas Basin 11.99 40.93 1.28 0.05 N/A 3.69 631 30.5

Fort Worth Basin 11.99 40.93 1.28 0.05 N/A 0 631 30.5

LouisianaMississippi Salt 

Basins 11.99 40.93 1.28 0.05 N/A 0 631 30.5
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 32

Artificial Lift Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

Nemaha Uplift 11.99 40.93 1.28 0.05 N/A 0 631 30.5

Permian Basin 11.99 40.93 1.28 0.05 N/A 14.19 631 30.5

Southern 

Oklahoma Basin 11.99 40.93 1.28 0.05 N/A 0 631 30.5

Western Gulf 

Basin 11.99 40.93 1.28 0.05 N/A 0 631 30.5

Data Sources

Engine operating parameters were derived primarily from survey data for most basins. Where 

survey data was not available for a specific basin, the average of all CENRAP basins was used. 

However for artificial lift engine load factor, most survey respondents were unable to provide 

any data on this parameter, and no literature survey data was obtained. Therefore the average 

artificial lift engine load factor derived from all basins studied in the IPAMS/WRAP Phase III 

work was used (Bar-Ilan, et al., 2008). 

All engine emissions factors – except those for SO2 – were obtained from the EPA’s 

NONROAD model (EPA, 2005a), which contained default emissions factors for a natural gasfired engine of the type considered here as an artificial lift engine. All pollutant species’ 

emissions factors were obtained from the NONROAD model for the artificial lift engine source 

category. Since the NONROAD model was the only source of emissions factors for this source 

category, the same set of emissions factors is recommended for all basins. 

SO2 emissions factors for artificial lift engines are calculated using the H2S concentration in the 

fuel, similar to the method used for wellhead and lateral compressor engines. 

Drill Rigs – Drilling Operations

Methodology

Drilling rigs are most commonly powered by one or more diesel-fired compression-ignition 

engines. These are configured in either a direct-drive configuration, or a diesel-electric 

configuration. In the former, the diesel engines are used to directly power specific activities of 

the drilling rig, and in the latter the diesel engines are used as generators to drive electric motors 

that power some or all of the activities of the drilling rig. In either case, there are three primary 

functions of these engines: 

(1) Draw works – the draw works engine(s) provides power to the rotating drill bit and is 

responsible for the actual cutting operation of the rig 

(2) Mud pumps – the mud pump engine(s) provides pumping of the working fluid (often 

referred to as “mud”) into the bore hole for lubrication and cooling as well as pumping 

the spent fluid and debris material out of the bore hole 

(3) Generators – the generator engine(s) provides power to the drilling crew and incidental 

power for the entire site operation (lighting, HVAC, crew quarters, etc.), or provides 

power to drive the draw works and pump motors in a diesel-electric configuration 

Although there are three primary functions of the rig engines, there may be more than one of 

each engine type with the additional engines either required for additional horsepower or used as 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 33

back-up engines. Each of these three engine types is used for differing durations throughout a 

drilling process and is likely to have different load factors. In addition, each of the three engine 

types is likely to be of differing model years and hence Tier levels, since individual engines on 

rigs may be replaced on independent turnover schedules. 

For purposes of this analysis, detailed information on individual rig configurations including the 

numbers of each engine type, model years of each engine type, load factors of each engine type 

and usage of each engine type was not available from survey data and could only be derived 

from the IPAMS/WRAP Phase III analysis (Bar-Ilan et al., 2008). However, survey data did 

indicate the average depth of drilling in each CENRAP basin, and so a total rig horsepower could 

be derived. The total rig horsepower was derived by scaling the average total rig horsepower 

from the WRAP Phase III work for a well of 8,000 ft depth by the ratio of the depth of wells in 

each CENRAP basin to this 8,000-ft benchmark. This scaling was done to reflect the assumption 

that deeper average well depths in a basin would require greater total rig horsepower. The well 

of 8,000 ft depth was chosen as a benchmark because in the WRAP Phase III analysis of the 

Denver-Julesburg Basin this was the average well depth for this particular basin, and the survey 

data collected for this basin provided the most detailed rig configuration data thus far in the 

Phase III project. This scaling to determine total rig horsepower is shown explicitly in Equation 

7: 

Equation (7) 

average D J

average i

total i total D J D

D

HP HP

−

= −

,

,

, ,

where: 

HPtotal,i is the total horsepower of all engines on the drilling rig in CENRAP basin i [hp] 

HPtotal,D-J is the average total horsepower of all engines on a drilling rig in the DenverJulesburg Basin [hp] 

Daverage,i is the average well depth in CENRAP basin i [ft] 

Daverage,D-J is the benchmark well depth in the Denver-Julesburg basin [8000 ft] 

Since the exact engine configurations were not known for the CENRAP basins, it was 

determined to use only total horsepower and a single average load factor as derived from the 

WRAP Phase III analysis. All engines are conservatively assumed to be used for the duration of 

a drilling event. 

Using the assumptions described above, emissions from a single drilling are determined 

according to Equation 8: 

Equation (8) 907,185

i total average drilling

drilling

EF HP LF t

E

× × × =

where: 

Edrilling,engine is the emissions from a drilling rig for drilling one well [ton/spud] 

EFi is the emissions factor for all drilling rig engines for pollutant i [g/hp-hr] 

HPtotal is the total horsepower of all engines on the drilling rig [hp] 

LFaverage is the average load factor for all engines on the drilling rig 

tdrilling is the actual on-time of all engines on the drilling rig for a typical drilling event in the 

basin [hr/spud] 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 34

Extrapolation to Basin-Wide Emissions

Drilling emissions from a single spud are scaled to basin-wide emissions according to Equation 

9: 

Equation (9) Edrilling,TOTAL = Edrilling × STOTAL

where: 

Edrilling,TOTAL is the total emissions in the basin from drilling activity [tons/yr] 

Edrilling is the total emissions in the basin from drilling a single well [tons/spud] 

STOTAL is the total number of spuds that occurred in the basin in 2002 

County-level emissions would be estimated by allocating the total basin-wide drilling rig 

emissions into each county according to the fraction of total 2002 spuds that occurred in each 

county. 

Input Data

The recommended input data are presented below in Tables 13 and 14: 

Table 13. Recommended engine operating parameters for use in estimating drilling rig 

emissions for all major CENRAP basins. 

Typical Engine Operating Parameters 

Basin 

Average Well 

Depth [ft] 

Duration of 

Drilling 

[hr] 

Total Rig 

Horsepower 

[hp] 

Load 

Factor 

[%] 

Actual Engine 

On-Time 

[hr] 

Engine 

BSFC 

[lb-fuel/bhphr] 

Anadarko Basin 13,750 1,080 4,720 0.67 261 0.367 

Arkoma Basin 13,000 720 4,463 0.67 247 0.367 

Cambridge ArchCentral Kansas Uplift 10,821 689 3,715 0.67 205 0.367 

Cherokee Platform 

Basin 10,821 689 3,715 0.67 205 

0.367 

East Texas Basin 10,500 480 3,605 0.67 199 0.367 

Fort Worth Basin 8,000 360 2,746 0.67 152 0.367 

LouisianaMississippi Salt 

Basins 8,500 504 2,918 0.67 161 

0.367 

Nemaha Uplift 10,821 689 3,715 0.67 205 0.367 

Permian Basin 7,000 480 2,403 0.67 133 0.367 

Southern Oklahoma 

Basin 10,821 689 3,715 0.67 205 

0.367 

Western Gulf Basin 15,000 1,200 5,149 0.67 285 0.367 

Table 14. Recommended engine emissions factors for use in estimating drill rig emissions for all 

major CENRAP basins. 

Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

Anadarko Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Arkoma Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Cambridge ArchCentral Kansas Uplift 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Cherokee Platform 

Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

East Texas Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Fort Worth Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 35

Engine Emissions Factors [g/bhp-hr] 

Basin NOx CO VOC PM10 H2S SOx CO2 CH4 

LouisianaMississippi Salt 

Basins 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Nemaha Uplift 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Permian Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Southern Oklahoma 

Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

Western Gulf Basin 8.00 5.00 1.26 1.00 N/A See below 527 1.142 

The SO2 emissions factors are estimated using the brake-specific fuel consumption (BSFC) of 

the engine, from the US EPA's NONROAD model for a similarly sized drill rig engine, and the 

sulfur content of the off-road diesel fuel (EPA, 2005a). Using the NONROAD model guidance, 

for drilling rig engines the fraction of fuel sulfur that would form PM emissions is 2.2% of the 

sulfur content and it is assumed that the remaining sulfur in the fuel would be emitted as SO2. 

Therefore the SO2 emission factors in g/bhp-hr can be calculated using Equation 10: 

Equation (10) ( ) 0.01 2 1.053 453.6 1 2 ⎟× × × ⎠

⎞ ⎜

⎝

⎛ ⎟

⎠

⎞ ⎜

⎝

⎛ = × × − − SOxdsl EF EF BSFC soxcnv VOC

SO

where: 

SO2 EF is the emissions factor of SO2 for a drilling rig engine [g/bhp-hr] 

BSFC is the brake-specific fuel consumption for a drilling rig engine [0.367 lb-fuel/bhp-hr] 

soxcnv is the percentage of fuel sulfur by mass converted to PM [2.2%] 

EFVOC is the VOC emissions factor for a drill rig engine [g/bhp-hr] 

SOxdsl is the weight percent of sulfur in the off-road diesel fuel [%] 

Individual CENRAP states can obtain the fuel sulfur content by county for each CENRAP state 

from the EPA’s NONROAD model or other specific inventory modeling that these states have 

conducted. 

Data Sources

As described above, the drilling rig total horsepower was derived from detailed data obtained as 

part of the development of basin-wide emissions for the Denver-Julesburg Basin in the 

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

was also used to determine an average load factor for all engines on a drilling rig. The average 

depth of wells in each basin as well as drilling duration information was obtained from surveys 

of the oil and gas companies. Where survey data was not available for a specific basin, the 

average of all CENRAP basins was used. The BSFC of drilling rig engines was obtained from 

the EPA’s NONROAD model (EPA, 2005a). 

Emissions factors for all pollutants – except for SO2 – were obtained from the EPA’s 

NONROAD model for a drill rig engine (EPA, 2005a). Since engine age information was not 

available, this analysis conservatively considers all engines in the 2002 calendar year to be 

baseline uncontrolled engines for purposes of estimating emissions factors. This is consistent 

with information provided to ENVIRON by oil and gas companies on the average age of drill rig 

engines, since many of these engines are frequently rebuilt and can be in service for 20 years or 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 36

more before being replaced. As noted above, the SO2 emissions factor must be estimated from 

the BSFC of the engine and the sulfur content of the off-road diesel fuel. 

Heaters

Methodology

Heaters and boilers in use at oil and gas production facilities are generally natural gas-fired 

external combustors. They are typically used as either separator heaters (to provide heat input to 

the separators), or as tank heaters (to maintain tank temperatures). It should be noted that this 

source category considers only tank and separator heaters, not heaters or boilers used in 

dehydrators. This latter usage is covered under the dehydrator source category methodology 

description below. 

Heaters are primarily considered an oil and gas NOx emissions source category, although they 

are also a minor source of CO, VOC and PM emissions. Heater emissions are calculated on the 

basis of the emissions factor of the heater, and the annual flow rate of gas to the heater. The 

annual gas flow rate is calculated from the BTU rating of the heater and the local BTU content of 

the gas. Although this may vary between oil and gas wells, the lack of information on well 

counts by well type requires the calculation for this analysis to consider heater configurations to 

be identical for all wells. 

The basic methodology for estimating emissions for all pollutants except SO2 for a single heater 

is shown in Equation 11: 

Equation (11) ( ) 10 2000 6 × ×

× × × =

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 [MMBTUlocal/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 available)

The local heating value in Equation 11 refers to the fact that the volumetric heating value of the 

gas, expressed as [MMBTU/scf] varies with local gas composition. 

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 12: 

Equation (12) ( ) ⎟

⎟

⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎜

⎜

⎝

⎛

⎟

⎟

⎠

⎞ ⎜

⎜

⎝

⎛ ⎟× ×

⎠

⎞ ⎜

⎝

⎛ ×

× ×

×

× =

0.035 907200

2 2

2 ,

T MW

R

P

HV

f Q t hc E

gas

lcoal

H S heater annual

heater SO
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 37

where: 

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

SO2 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] 

hc is a heater cycling fraction to account for the fraction of operating hours that the heater is 

firing (if available) 

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] 

Extrapolation to Basin-Wide Emissions

Basin-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 13: 

Equation (13) ( ) 2000 2 Eheater,TOTAL = Eheater + Eheater,SO × Nheater ×WTOTAL

where: 

Eheater,TOTAL is the total heater emissions in the basin [ton/yr] 

Eheater is the total emissions from a single heater [lb/yr] 

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

WTOTAL is the total number of wells in the basin 

Nheater is the typical number of heaters per well in the basin 

County-level emissions are estimated by allocating the total basin-wide heater emissions into 

each county according to the fraction of basin total well counts that are located in each county. 

Again it should be noted that ideally a separate heater emissions calculation would be conducted 

for oil and gas wells and scaled up to the basin level by the count of each well type respectively. 

If a more detailed database of well counts by well type is made available to CENRAP in the 

future it is recommended that this methodology be modified to account for this change. 

Input Data

The recommended input data are presented below in Tables 15 and 16: 

Table 15. Recommended heater operating parameters for use in estimating heater emissions 

for all major CENRAP basins. 

Typical Heater Operating Parameters 

Basin 

Number of heaters in 

a typical well setup 

Heater Firing 

Rate 

[MMBTU/hr] 

Annual 

Activity 

[hrs] 

Local Heating 

Value 

[MMBTU/scf] 

Heater 

Cycling 

Anadarko Basin 0.94 0.92 4601 1209 1 

Arkoma Basin 0.5 1.19 2738 1209 1 

Cambridge Arch-Central 

Kansas Uplift 0 N/A N/A N/A N/A 

Cherokee Platform Basin 0 N/A N/A N/A N/A 

East Texas Basin 0.95 0.64 2982 1209 1 

Fort Worth Basin 1 0.5 4380 1209 1 

Louisiana- Mississippi 0.95 0.67 2982 1209 1 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 38

Typical Heater Operating Parameters 

Basin 

Number of heaters in 

a typical well setup 

Heater Firing 

Rate 

[MMBTU/hr] 

Annual 

Activity 

[hrs] 

Local Heating 

Value 

[MMBTU/scf] 

Heater 

Cycling 

Salt Basins 

Nemaha Uplift 0.31 0.38 126 1209 1 

Permian Basin 0.54 0.69 4121 1209 1 

Southern Oklahoma 

Basin 0.63 0.38 574 1209 1 

Western Gulf Basin 1.1 0.46 4297 1209 1 

Table 16. Recommended heater emissions factors for use in estimating heater emissions for all 

major CENRAP basins. 

Heater Emissions Factors 

Basin 

NOx 

[lb/106-

SCF] 

CO 

[lb/106-

SCF] 

VOC 

[lb/106-

SCF] 

PM10

[lb/106-

SCF] 

H2S 

Mass 

Fraction 

MWgas 

[g/mol] 

CO2

[lb/106-

SCF] 

CH4

[lb/106-

SCF] 

Anadarko Basin 100 84 5.5 7.6 0 N/A 12000 2.3 

Arkoma Basin 100 84 5.5 7.6 0 N/A 12000 2.3 

Cambridge ArchCentral Kansas 

Uplift N/A N/A N/A N/A 0 N/A N/A 2.3 

Cherokee 

Platform Basin N/A N/A N/A N/A 0 N/A N/A 2.3 

East Texas 

Basin 100 84 5.5 7.6 0.01 23 12000 2.3 

Fort Worth Basin 100 84 5.5 7.6 0 N/A 12000 2.3 

LouisianaMississippi Salt 

Basins 100 84 5.5 7.6 0 N/A 12000 2.3 

Nemaha Uplift 100 84 5.5 7.6 0 N/A 12000 2.3 

Permian Basin 100 84 5.5 7.6 0.03 26 12000 2.3 

Southern 

Oklahoma Basin 100 84 5.5 7.6 0 N/A 12000 2.3 

Western Gulf 

Basin 100 84 5.5 7.6 0 N/A 12000 2.3 

Data Sources

Heater operating parameters were derived primarily from survey data for most basins. Where 

survey data was not available for a specific basin, the average of all CENRAP basins was used. 

The average local heating value could only be obtained from survey responses, since the 

CENRAP state OGCC’s did not track any gas composition or thermochemical information. 

However, there were not sufficient responses to the request for local heating value data to be able 

to estimate this separately for each basin. Therefore the local heating value presented in Table 

15 represents an average natural gas heating value obtained from the IPAMS/WRAP Phase III 

analysis (Bar-Ilan, et al., 2008). 

All heater emissions factors were obtained from the EPA’s AP-42 emissions factor database 

(EPA, 1998) for natural gas-fired heaters/boilers, under the external combustion sources 

category. As discussed above, heaters are primarily a NOx and CO source category with only 

minor emissions of other species, as shown in Table 16. 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 39

Flaring 

Methodology

Flaring is used for a number of processes in the oil and gas industry to control VOC and other 

emissions from various processes. The three processes considered in this analysis which use 

flaring as a control process are stock tanks (condensate and oil), gas dehydration, and completion 

venting. For stock tanks, the flashing emissions from the tanks may be controlled by flaring, and 

for dehydrators the still vent emissions may be controlled by flaring. For completion venting, 

operators may use flares to control the emissions from raw vented gas during completion of a 

well. In each of these processes the vented or flashed gas is routed to a combustor which then 

burns the gas to remove upwards of 95% of VOC emissions. However, these flares are 

themselves a source of NOx and CO emissions. They are also potentially a source of SO2

emissions if the flared gas contains H2S. The control of VOC emissions from these 3 processes 

by use of flaring is covered separately in the methodology description for each process 

respectively. 

The methodologies for estimating emissions from flaring vary depending on the process for 

which the flare is used. The methodologies for the three processes considered in this analysis are 

described below. Note that the flaring emissions methodologies are used to directly estimate 

basin-level flaring emissions, and thus no additional calculation is needed to extrapolate the 

emissions to the basin level. Note also that a separate methodology is used to estimate SO2

emissions from flaring, as described below. 

The methodology for estimating emissions from flaring of oil and condensate stock tank flash 

gas is described in Equation 14: 

Equation (14) 2000

1000 1000

, ,

, ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

×

× × = i flare tank basin liquid

flare tank

EF Q HV P

E

where: 

Eflare,tank is the basin-wide flaring emissions from flaring of stock tank flash gas [ton/yr] 

EFi is the emissions factor for pollutant i [lb/MMBtu] 

Qflare,tank is the volume of flash gas flared per unit of oil or condensate produced in the basin 

[MCF/1000 bbl] 

HV is the local heating value of the gas [BTU/scf] 

Pbasin,liquid is the basin-wide oil or condensate production [bbl] 

The methodology for estimating emissions from dehydration processes is described in Equation 

15: 

Equation (15) 2000

1000 106

, ,

, ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

×

× × = i flare dehydrator basin gas

flare dehydration

EF Q HV P

E

where: 

Eflare,dehydration is the basin-wide flaring emissions from flaring of dehydrator vent gas [ton/yr] 

EFi is the emissions factor for pollutant i [lb/MMBtu] 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 40

Qflare,dehydrator is the volume of dehydrator still vent gas flared per unit of gas produced in the 

basin [MCF/million MCF produced] 

HV is the local heating value of the gas [BTU/scf] 

Pbasin,gas is the basin-wide gas production [MCF] 

The methodology for estimating emissions from completion venting processes is described in 

Equation 16: 

Equation (16) 2000

1000

,

, ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

×

× × = basin

i flare completion

flare completion S

EF Q HV

E

where: 

Eflare,completion is the basin-wide flaring emissions from flaring of completion vent gas [ton/yr] 

EFi is the emissions factor for pollutant i [lb/MMBtu] 

Qflare,completion is the volume of completion venting gas flared per spud in the basin 

[MCF/spud] 

HV is the local heating value of the gas [BTU/scf] 

Sbasin is the basin-wide spud count for calendar year 2002 

Emissions of SO2 occur if there is H2S present in the gas (i.e. sour gas). Emissions of SO2 are 

estimated using the H2S mass fraction in the produced gas under the assumption that all H2S is 

converted to SO2 in the flaring process. Given the limited information obtained on H2S 

concentrations, the same H2S concentration in produced gas is used as the H2S concentration in 

flared gas. For the completion venting and dehydrator venting processes, this assumption is 

accurate. For flash gas flaring, a separate flash gas composition analysis would need to be 

conducted to quantify the H2S content of the flash gas. A flash gas composition analysis was not 

available for this analysis. The methodology for estimating SO2 emissions from flaring of oil 

and condensate flash gas is shown below in Equation 17: 

Equation (17) ( )

907200

2

3.5 10

1000

2 2

5

, ,

, , × ×

⎟

⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎜

⎝

⎛

⎟× × × ⎠

⎞ ⎜

⎝

⎛

× × = −

H S

gas

flare tank basin liquid

flare tank SO f

T MW

R

P Q P

E

where: 

2 Eflare,tank ,SO is the basin-wide SO2 flaring emissions from flaring of stock tank flash gas 

[ton/yr] 

P is atmospheric pressure [1 atm] 

Qflare,tank is the volume of flash gas flared per unit of oil or condensate produced in the basin 

[MCF/1000 bbl] 

Pbasin,liquid is the basin-wide oil or condensate production [bbl] 

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 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 41

The methodology for estimating SO2 emissions from flaring of dehydrator vent gas is shown 

below in Equation 18: 

Equation (18) ( )

907200

2

3.5 10

10

2 2

5

6

, ,

, , × ×

⎟

⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎜

⎝

⎛

⎟× × × ⎠

⎞ ⎜

⎝

⎛

× × = −

H S

gas

flare dehydrator basin gas

flare dehydrator SO f

T MW

R

P Q P

E

where: 

2 Eflare,dehydrator,SO is the basin-wide SO2 flaring emissions from flaring of dehydrator vent gas 

[ton/yr] 

P is atmospheric pressure [1 atm] 

Qflare,dehydrator is the volume of dehydrator still vent gas flared per unit of gas produced in the 

basin [MCF/million MCF produced] 

Pbasin,gas is the basin-wide gas production [MCF] 

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 

The methodology for estimating SO2 emissions from flaring of completion vent gas is shown 

below in Equation 19: 

Equation (19) ( )

907200

2

3.5 10 2 2

5

,

, , × ×

⎟

⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎜

⎝

⎛

⎟ × × ×

⎠

⎞ ⎜

⎝

⎛

× × = −

H S

gas

flare completion basin

flare completion SO f

T MW

R

P Q S

E

where: 

2 Eflare,completion,SO is the basin-wide SO2 flaring emissions from flaring of completion vent gas 

[ton/yr] 

P is atmospheric pressure [1 atm] 

Qflare,completion is the volume of completion venting gas flared per spud in the basin 

[MCF/spud] 

Sbasin is the basin-wide spud count for calendar year 2002 

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 

Extrapolation to Basin-Wide Emissions

As noted above, Equations 14-16 provide methodologies to estimate basin-wide flaring 

emissions from flaring of flash gas, dehydration vent gas, and completion vent gas for all 

pollutants except SO2. Basin-wide emissions from all flaring activities are estimated according 

to Equation 20: 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 42

Equation (20) Eflare,TOTAL = Eflare,tank + Eflare,dehydration + Eflare,completion

where: 

Eflare,TOTAL is the total flaring emissions in the basin [ton/yr] 

Eflare,tank is the basin-wide flaring emissions from flaring of stock tank flash gas [ton/yr] 

Eflare,dehydration is the basin-wide flaring emissions from dehydrator venting [ton/yr] 

Eflare,completion is the basin-wide flaring emissions from completion venting [ton/yr] 

Basin-wide emissions of SO2 from flaring are estimated according to Equation 21: 

Equation (21) 2 2 2 2 Eflare,TOTAL,SO = Eflare,tank ,SO + Eflare,dehydration,SO + Eflare,completion,SO

where: 

2 Eflare,TOTAL,SO is the total SO2 flaring emissions in the basin [ton/yr] 

2 Eflare,tank ,SO is the basin-wide SO2 flaring emissions from flaring of stock tank flash gas 

[ton/yr] 

2 Eflare,dehydrator,SO is the basin-wide SO2 flaring emissions from dehydrator venting [ton/yr] 

2 Eflare,completion,SO is the basin-wide SO2 flaring emissions from completion venting [ton/yr] 

County-level emissions are estimated by allocating the total basin-wide flaring emissions into 

each county according to the fraction of total surrogate (oil production, gas production, or spud 

counts for tank, dehydrator and completions, respectively) that are located in each county. 

Input Data

The recommended input data are presented below in Tables 17 and 18: 

Table 17. Recommended input data parameters for use in estimating flaring emissions for all 

major CENRAP basins. 

Flaring Process: Oil and Condensate Tank Flash Gas Flaring 

Basin 

Activity Surrogate Gas Flared Per Unit 

of Activity Surrogate 

[MCF-flared/1000 bbl] 

Heating Value of Flared Gas 

[BTU/SCF] 

Anadarko Basin Liquid Production 0.836 1655 

Arkoma Basin Liquid Production 0.836 1655 

Cambridge Arch-Central 

Kansas Uplift Liquid Production 0.836 1655 

Cherokee Platform Basin Liquid Production 0.836 1655 

East Texas Basin Liquid Production 0.836 1655 

Fort Worth Basin Liquid Production 0.836 1655 

Louisiana- Mississippi Salt 

Basins Liquid Production 0.836 1655 

Nemaha Uplift Liquid Production 0.836 1655 

Permian Basin Liquid Production 0.836 1655 

Southern Oklahoma Basin Liquid Production 0.836 1655 

Western Gulf Basin Liquid Production 0.836 1655 

Flaring Process: Dehydrator Vent Gas Flaring 

Basin 

Activity Surrogate Gas Flared Per Unit of Activity 

Surrogate 

[MCF-flared/million MCF produced] 

Heating Value of 

Flared Gas 

[BTU/SCF] 

Anadarko Basin Gas Production 8.84 1209 

Arkoma Basin Gas Production 8.84 1209 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 43

Flaring Process: Oil and Condensate Tank Flash Gas Flaring 

Basin 

Activity Surrogate Gas Flared Per Unit 

of Activity Surrogate 

[MCF-flared/1000 bbl] 

Heating Value of Flared Gas 

[BTU/SCF] 

Cambridge Arch-Central 

Kansas Uplift Gas Production 8.84 1209 

Cherokee Platform Basin Gas Production 8.84 1209 

East Texas Basin Gas Production 8.84 1209 

Fort Worth Basin Gas Production 8.84 1209 

Louisiana- Mississippi Salt 

Basins Gas Production 8.84 1209 

Nemaha Uplift Gas Production 8.84 1209 

Permian Basin Gas Production 8.84 1209 

Southern Oklahoma Basin Gas Production 8.84 1209 

Western Gulf Basin Gas Production 8.84 1209 

Flaring Process: Completion Venting Gas Flaring 

Basin 

Activity Surrogate Gas Flared Per Unit of Activity 

Surrogate 

[MCF-flared/spud] 

Heating Value of 

Flared Gas 

[BTU/SCF] 

Anadarko Basin Spuds 13.4 1209 

Arkoma Basin Spuds 13.4 1209 

Cambridge Arch-Central 

Kansas Uplift Spuds 13.4 1209 

Cherokee Platform Basin Spuds 13.4 1209 

East Texas Basin Spuds 13.4 1209 

Fort Worth Basin Spuds 13.4 1209 

Louisiana- Mississippi Salt 

Basins Spuds 13.4 1209 

Nemaha Uplift Spuds 13.4 1209 

Permian Basin Spuds 13.4 1209 

Southern Oklahoma Basin Spuds 13.4 1209 

Western Gulf Basin Spuds 13.4 1209 

Table 18. Recommended emissions factors for use in estimating flaring emissions for all major 

CENRAP basins. 

Flaring Emissions Factors 

Basin 

NOx 

[lb/MMBTU]

CO 

[lb/MMBTU]

CO2

[lb/MMBTU]

CH4

[lb/MMBTU] 

H2S 

Mass Fraction

MWgas 

[g/mol]

Anadarko Basin 0.068 0.37 102 0.022 0 N/A

Arkoma Basin 0.068 0.37 102 0.022 0 N/A

Cambridge Arch-Central 

Kansas Uplift 0.068 0.37 102 0.022 0 N/A

Cherokee Platform Basin 0.068 0.37 102 0.022 0 N/A

East Texas Basin 0.068 0.37 102 0.022 0.01 23

Fort Worth Basin 0.068 0.37 102 0.022 0 N/A

Louisiana- Mississippi Salt 

Basins 0.068 0.37 102 0.022 0 N/A

Nemaha Uplift 0.068 0.37 102 0.022 0 N/A

Permian Basin 0.068 0.37 102 0.022 0.03 26

Southern Oklahoma Basin 0.068 0.37 102 0.022 0 N/A

Western Gulf Basin 0.068 0.37 102 0.022 0 N/A

Data Sources

All input data parameters for estimating flaring emissions were derived from the IPAMS/WRAP 

Phase III work (Bar-Ilan, et al., 2008), with the exception of H2S mass fraction and gas 

molecular weight, which were derived from survey responses. Note that the survey responses 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 44

only indicated significant H2S mass fractions in the produced gas for two basins: the Permian 

and East Texas Basins. It is recommended that these values be revised for all basins if CENRAP 

is able to obtain more detailed gas composition analyses in the future. 

Flaring emissions factors for NOx, CO, CO2 and CH4 were obtained from EPA’s AP-42 

compendium of emissions factors (EPA, 1991). 

Oil and Condensate Tanks 

Methodology

Oil and condensate tanks are expected to be one of the most significant sources of VOC 

emissions from oil and gas area source categories throughout the CENRAP region. Oil and 

condensate tanks are used to store produced liquid at individual well sites and there may be many 

thousands of such storage tanks throughout a basin. Two primary processes create emissions of 

gas from oil and condensate tanks: (1) flashing, whereby condensate brought from downhole 

pressure to atmospheric pressure may experience a sudden volatilization of some of the 

condensate; and (2) working and breathing losses, whereby some volatilization of stored product 

occurs through valves and other openings in the tank battery over time. Note that flashing 

emissions are associated with condensate tanks, whereas working and breathing losses are 

associated with both oil and condensate tanks. Both flash gas and emitted gas from working and 

breathing losses are expected to have a different composition from gas directly produced at the 

well. In most cases this flash gas is likely to have a composition of volatile species that is 

heavier than produced gas. Very few direct measurements of gas composition from working and 

breathing losses have been taken, and thus this analysis assumes that the gas compositions from 

both loss processes are identical. It should be noted that no information could be obtained on the 

sulfur content of the flash gas or working and breathing losses, and thus this analysis does not 

consider sulfur emissions from tanks. One possible control strategy for eliminating flashing and 

working and breathing losses from tanks is to route liquid production directly into a pipeline, 

essentially eliminating the use of tanks. 

Methodologies are presented below for estimating condensate tank and oil tank emissions. Note 

that condensate production totals are not available for all basins in this analysis, however if this 

information becomes available to CENRAP in the future the methodologies here could be used 

for estimating emissions from both condensate and oil tanks. The emissions factors for oil and 

condensate production are derived from running a process modeling software that predicts the 

volume of flash gas or working and breathing losses from the tank per unit of production. The 

process modeling software, such as GRI GLYCalc or HYSYS, requires input data about tank 

configuration, size and environmental conditions. These emissions factors are typically 

developed by oil and gas companies, or state environmental agencies. 

The methodology for estimating oil tank emissions is shown below in Equation 21: 

Equation (21) ( ) tank oil oil tanks

oil tanks oil tanks

oil tanks f c

P EF

E , ,

, ,

, 1 0.98

2000

× × − × =

where: 

Eoil,tanks is the basin-wide emissions from oil tanks [tons/yr] 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 45

EFoil,tanks is the derived VOC emissions factor for working and breathing losses from oil 

tanks [lb-VOC/bbl] 

Poil,tanks is the basin-wide oil production [bbl] 

ftank,oil is the fraction of oil production that is routed to tanks 

coil,tanks is the fraction of oil production at tanks that are equipped with flares to control VOC 

emissions 

The methodology for estimating condensate tank emissions is shown below in Equation 22: 

Equation (22) ( ) tank condensate condensate tank

condensate tanks condensate tanks

condensate tanks f c

P EF

E , ,

, ,

, 1 0.98

2000

× × − × =

where: 

Econdensate,tanks is the basin-wide emissions from condensate tanks [tons/yr] 

EFcondensate,tank is the derived VOC emissions factor for flashing and working and breathing 

losses from condensate tanks [lb-VOC/bbl] 

Pcondensatetanks is the condensate production from gas wells thoughput [bbl] 

ftank,condensate is the fraction of condensate production that is routed to tanks 

ccondensate,tanks is the fraction of condensate production at tanks that are equipped with flares to 

control VOC emissions 

Extrapolation to Basin-Wide Emissions

Equations 21 and 22 provide methodologies to directly estimate basin-wide oil and condensate 

tank emissions, respectively. 

County-level oil tank emissions are estimated by allocating the total basin-wide oil tank 

emissions into each county according to the fraction of total 2002 oil production occurring in that 

county. County-level condensate tank emissions would be estimated by allocating the total 

basin-wide condensate tank emissions into each county according to the fraction of total 2002 

condensate production occurring in that county. 

Input Data

The recommended input data are presented below in Table 19: 

Table 19. Recommended input data parameters for use in estimating working & breathing and 

flashing emissions from oil and condensate tanks in all major CENRAP basins. 

OIL TANKS CONDENSATE TANKS 

Basin 

Fraction of 

Production to 

Tanks 

Emissions 

Factor 

[lb-VOC/bbl] 

Fraction 

Flared 

Fraction of 

Production to 

Tanks 

Emissions 

Factor 

[lb-VOC/bbl] 

Fraction 

Flared 

Anadarko Basin 100% 2.94 0% 100% 13.86 0%

Arkoma Basin 100% 2.94 0% 100% 13.86 0%

Cambridge Arch-Central Kansas Uplift 100% 2.94 0% 100% 13.86 0%

Cherokee Platform Basin 100% 2.94 0% 100% 13.86 0%

East Texas Basin 100% 1.60 25% 100% 33.30 25%

Fort Worth Basin 100% 1.60 25% 100% 33.30 25%

Louisiana- Mississippi Salt Basins 100% 2.94 0% 100% 13.86 0%

Nemaha Uplift 100% 2.94 0% 100% 13.86 0%

Permian Basin 100% 1.60 25% 100% 33.30 25%

Southern Oklahoma Basin 100% 2.94 0% 100% 13.86 0%

Western Gulf Basin 100% 1.60 25% 100% 33.30 25%
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 46

Data Sources

Information collected about oil and condensate tanks from the industry survey effort was very 

limited and did not provide usable data. It was conservatively assumed that all production would 

be routed to tanks. The fraction of tank production that is flared was obtained from the TCEQ’s 

2005 oil and gas inventory (Pendleton, et al., 2008). Emissions factors for flashing and working 

and breathing losses for oil and condensate tanks were obtained from the IPAMS/WRAP Phase 

III work (Bar-Ilan, et al., 2008) for all basins except the Texas basins (East Texas Basin, Fort 

Worth Basin, Permian Basin, and Western Gulf Basin). Emissions factors for flashing and 

working and breathing losses for tanks in the Texas basins was obtained from TCEQ’s 2005 oil 

and gas inventory calculations (Pendleton, et al., 2008). Given the variability in oil and 

condensate composition from basin to basin, it is recommended that CENRAP revise these 

emissions factors if more detailed basin-level data on tank emissions factors becomes available 

in the future. 

Dehydrators 

Methodology

Dehydrators are devices used to remove excess water from produced natural gas prior to 

transmission into a pipeline or to a gas processing facility. These wellhead devices are normally 

only used in regions where there are significant concentrations of water in the gas that cannot be 

removed by separators. Thus their usage is highly localized depending on the composition of the 

gas. There are both liquid dessicant and solid dessicant dehydrators, but in practice liquid 

dessicant dehydrators are overwhelmingly used. The liquid dessicant is typically either glycol, 

diethylene glycol (DEG) or triethylene glycol (TEG). Glycol dehydrators have two emissions 

sources: the still vent from which some fugitive gas is emitted; and the reboiler which is 

essentially a heater and has similar emissions characteristics to a heater. For both still vent and 

heater emissions from dehydrators, emissions factors are typically developed using the process 

simulation software GLYCalc, developed by the Gas Research Institute. The survey effort in 

Task 2b did not yield usable information to generate per-dehydrator or per-unit production 

emissions factors for dehydrator still vents and reboilers, and therefore broad regional emissions 

factors per unit production from the IPAMS/WRAP Phase III work are used in this analysis 

(except for the Texas Basins, where NETAC and TCEQ data are available on dehydrators). For 

still vents the only emissions factors available from the IPAMS/WRAP Phase III work are for 

VOC and not for other pollutants. For reboilers emissions of NOx, and CO are available. These 

per-unit production emissions factors can be used to directly estimate basin-level dehydrator 

emissions. 

The basic methodology for estimating basin-wide emissions from dehydrator still vents is shown 

in Equation 23: 

Equation (23) 6 2×10

× = stillvent basin

stillvent

EF P E

where: 

Estillvent is the basin-wide emissions from dehydrator still vents [ton-VOC/yr] 

EFstillvent is the emission factor for a still vent per unit production [lb/MMSCF] 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 47

Pbasin is the basin-wide gas production [MCF/yr] 

The basic methodology for estimating basin-wide emissions from dehydrator reboilers is similar 

to that for still vents, and is shown in Equation 24: 

Equation (24) 6 2×10

× = reboiler basin

reboiler

EF P E

where: 

Estillvent is the basin-wide emissions from dehydrator reboilers [ton/yr] 

EFstillvent is the emission factor for a dehydrator reboiler per unit production [lb/MMSCF] 

Pbasin is the basin-wide gas production [MCF/yr] 

Extrapolation to Basin-Wide Emissions

Equations 23 and 24 already provide direct estimates of the VOC, NOx, CO, CO2 and CH4

emissions from dehydrator still vents and reboilers, respectively. Total basin emissions from 

dehydrators would then be estimated according to Equation 25: 

Equation (25) Edehydrator,TOTAL = Estillvent + Ereboiler

where: 

Edehydrator,TOTAL is the total dehydrator emissions in the basin [ton/yr] 

Estillvent is the total dehydrator still vent emissions in the basin [ton-VOC/yr] 

Ereboiler is the total dehydrator reboiler emissions in the basin [ton/yr] 

County-level dehydrator emissions are estimated by allocating the total basin-wide dehydrator 

emissions into each county according to the fraction of total 2002 gas production that is located 

in each county. 

Input Data

The recommended input data are presented below in Table 20: 

Table 20. Recommended emissions factors for use in estimating dehydrator emissions for all 

major CENRAP basins. 

Dehydrator Emissions Factors 

Basin 

NOx 

[lb/MMSCF] 

CO 

[lb/MMSCF] 

VOC 

[lb/MMBTU] 

Anadarko Basin 0.052 0.105 2.622

Arkoma Basin 0.052 0.105 2.622

Cambridge Arch-Central Kansas Uplift 0.052 0.105 2.622

Cherokee Platform Basin 0.052 0.105 2.622

East Texas Basin 0.052 0.105 2.622

Fort Worth Basin 0.052 0.105 2.622

Louisiana- Mississippi Salt Basins 0.052 0.105 5.5

Nemaha Uplift 0.052 0.105 5.5

Permian Basin 0.052 0.105 2.622

Southern Oklahoma Basin 0.052 0.105 5.5

Western Gulf Basin 0.052 0.105 2.622
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 48

Data Sources

Only the IPAMS/WRAP Phase III analysis (Bar-Ilan, et al., 2008) was able to provide broadly 

applicable still vent and reboiler emissions factors per unit of production for all major CENRAP 

basins except the Texas basins. For the East Texas Basins, the still vent VOC emissions factors 

from the NETAC study (Pollution Solutions, 2005) were used and for the remainder of the Texas 

basins the TCEQ oil and gas area source inventory (Pendleton, et al., 2008) was used. 

Well Completions 

Methodology

Once drilling and other well construction activities are finished, a gas well must be completed in 

order to begin producing gas. The completion process requires venting of the well for a 

sustained period of time to remove mud and other solid debris in the well, to remove any inert 

gas used to stimulate the well (such as CO2 and/or N2) and to bring the gas composition to 

pipeline grade. During this process significant amounts of gas may be vented, and this gas can 

be a VOC emissions source, as well as an H2S emissions source if there is significant H2S 

present in the gas. In general this analysis assumes that the composition of the completion 

venting gas is identical to production gas, because no detailed information is available on the 

completion venting gas specifically. 

Emissions from well completions are estimated on the basis of the volume of gas vented during 

completion and the average VOC content of that gas, obtained from gas composition analyses. 

Flaring and/or green completion practices may be used to control emissions from the completion 

process. Flaring typically has 98% control efficiency for VOC emissions, and green completion 

practices have a range of control efficiencies depending on the amount of vented gas that is 

captured during the process. 

The calculation methodology for estimating emissions from a single completion event is shown 

below in Equation 26: 

Equation (26) ( )

907200 3.5 10 5

,

i

gas

vented

completion i

f

T MW

R

P V E ×

⎟

⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎜

⎝

⎛

⎟× × × ⎠

⎞ ⎜

⎝

⎛

× = −

where: 

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

P is atmospheric pressure [1 atm] 

Vvented is the volume of vented gas per completion [MCF/event] 

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

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

T is the atmospheric temperature [298 K] 

fi is the mass fraction of pollutant i in the completion venting gas 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 49

Extrapolation to Basin-Wide Emissions

The total emissions from all completions occurring in a basin are evaluated following Equation 

27: 

Equation (27) ( ) completion TOTAL completion i basin flare green E = E × S × 1− 0.98c − c , ,

where: 

Ecompletion,TOTAL are the total emissions basin-wide from completions [tons/year] 

Ecompletion,i are the completion emissions from a single completion event [tons/event] 

cflare is the fraction of completions in the basin that were controlled by flares 

cgreen is the fraction of completions in the basin that were controlled by green completion 

techniques 

Sbasin is the basin-wide spud count for calendar year 2002 

County-level emissions are estimated by allocating the total basin-wide completion emissions 

into each county according to the fraction of 2002 well count occurring in that county. 

Input Data

The recommended input data are presented below in Table 21: 

Table 21. Recommended input data parameters for use in estimating completion venting 

emissions in all major CENRAP basins. 

Typical Completion Venting Parameters 

Basin 

Volume of Gas Vented 

Per Completion 

[MCF/event] 

Fraction of 

Completions 

Flared 

Fraction of 

Completions with 

Green Completion 

Anadarko Basin 1,737 0 0

Arkoma Basin 31 0 0

Cambridge Arch-Central Kansas 

Uplift 0 0 0

Cherokee Platform Basin 637 0 0

East Texas Basin 2,417 0 0

Fort Worth Basin 637 0 0

Louisiana- Mississippi Salt Basins 333 0 0

Nemaha Uplift 0 0 0

Permian Basin 0 0 0

Southern Oklahoma Basin 18 0 0

Western Gulf Basin 1,200 0 0

Pollutant mass fractions used in estimating completion venting emissions are presented in the 

combined natural gas composition data provided in the master data matrix spreadsheet 

accompanying this report. This composition data is too extensive to present here for all major 

CENRAP basins. 

Data Sources

Completion venting volumes per completion event for each basin were obtained from surveys, or 

where unavailable an average of all CENRAP basins was used. VOC mass fractions of produced 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 50

gas were obtained from survey data or where unavailable an average of all CENRAP basins was 

used. 

Well Blowdowns 

Methodology

Well blowdowns refer to the practice of venting gas from wells that have developed some kind 

of cap or obstruction before any additional intervention work can be done on the wells. 

Typically well blowdowns are conducted on wells that have been shut in for a period of time and 

the operator desires to bring the well back into production. Well blowdowns are also sometimes 

conducted to remove fluid caps that have built up in producing gas wells. Because gas is directly 

vented from the blowdown event, blowdowns can be a source of VOC emissions. In addition, if 

there is a significant concentration of H2S in the gas, blowdowns can also be a source of H2S 

emissions. 

Emissions from blowdowns are estimated on the basis of the volume of gas vented during a 

blowdown and the average pollutant content of that gas, obtained from gas composition analyses. 

This methodology is very similar to that of completion venting. Flaring and/or green practices 

may be used to control emissions from the blowdown process. Flaring typically has a 98% 

control efficiency for VOC emissions, and green practices have a range of control efficiencies 

depending on the amount of vented gas that is captured during the process. 

The calculation methodology for estimating emissions from a single blowdown event is shown 

below in Equation 28: 

Equation (28) ( )

907200 3.5 10 5

,

i

gas

vented

blowdown i

f

T MW

R

P V E ×

⎟

⎟

⎟

⎟

⎠

⎞

⎜

⎜

⎜

⎜

⎝

⎛

⎟× × ×

⎠

⎞ ⎜

⎝

⎛

× = −

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] 

fi is the mass fraction of pollutant i in the vented gas 

Extrapolation to Basin-Wide Emissions

The total emissions from all blowdowns occurring in a basin are evaluated following Equation 

29: 

Equation (29) ( ) blowdown TOTAL blowdown i blowdown wells flare green E = E × N × N × 1− 0.98c − c , ,

where: 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 51

Eblowdown,TOTAL are the total emissions basin-wide from blowdowns [tons/year] 

Eblowdown,i are the blowdown emissions from a single blowdown event [tons/event] 

cflare is the fraction of blowdowns in the basin that were controlled by flares 

cgreen is the fraction of blowdowns in the basin that were controlled by green techniques 

Nblowdown is the number of blowdowns per well in the basin 

Nwells is the total number of active wells in the basin in calendar year 2002 

County-level emissions are estimated by allocating the total basin-wide blowdown emissions 

into each county according to the fraction of 2002 well count occurring in that county. 

Input Data

The recommended input data are presented below in Table 22: 

Table 22. Recommended input data parameters for use in estimating blowdown emissions in all 

major CENRAP basins. 

Typical Blowdown Parameters 

Basin 

Blowdown 

Frequency 

[events/well/year] 

Volume of Gas Vented 

Per Blowdown Per Well 

[MCF/event/well] 

Fraction of 

Blowdowns 

Flared 

Fraction of 

Blowdowns with 

Green Techniques 

Anadarko Basin 3.3 7.28 0 0 

Arkoma Basin 0.18 7.22 0 0 

Cambridge Arch-Central 

Kansas Uplift 0 0 N/A N/A 

Cherokee Platform Basin 0.19 7.22 0 0 

East Texas Basin 1.09 31.67 0 0 

Fort Worth Basin 1.54 38.90 0 0 

Louisiana- Mississippi Salt 

Basins 1.09 31.67 0 0 

Nemaha Uplift 0.74 2.30 0 0 

Permian Basin 5 50 0 0 

Southern Oklahoma Basin 0 0 N/A N/A 

Western Gulf Basin 0.71 173.90 0 0 

Pollutant mass fractions used in estimating well blowdown emissions are presented in the 

combined natural gas composition data provided in the master data matrix spreadsheet 

accompanying this report. This composition data is too extensive to present here for all major 

CENRAP basins. 

Data Sources

Number of blowdowns per well per year and the volume of gas vented per blowdown for each 

basin were obtained from surveys, or where unavailable an average of all CENRAP basins was 

used. Pollutant mass fractions of produced gas were obtained from survey data or where 

unavailable an average of all CENRAP basins was used. 

Fugitive Emissions (Leaks) 

Methodology

Fugitive emissions refer to emissions of produced gas through connectors, flanges, valves and 

other pipeline hardware at the wellhead. These emissions are essentially leaks that result from 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 52

high-pressure gas moving through the various hardware components of a wellhead assembly. It 

should be noted that this source category is distinct from fugitive emissions from pipelines, 

which are not considered here, and refers only to components located at wellheads. Because the 

fugitive emissions are produced gas, this source category can be a source of VOC emissions. In 

addition, if the gas contains significant concentrations of H2S then this source category can also 

be a source of H2S emissions. 

Fugitive emissions from wellheads are estimated using AP-42 emissions factors (EPA, 1995) and 

component counts for typical well setups. The well setup is typically characterized by the type 

of equipment installed and by the type of service to which the equipment applies – gas, light 

liquid, heavy liquid, or water. 

Fugitive emissions for an individual typical well are estimated according to Equation 30: 

Equation (30) = ∑ × × × ×

i

fugitive j i i annual Yj E , EF N t 0.0011

where: 

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

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

Ni is the total number of components of type i

tannual is the annual number of hours the well is in operation [8760 hr/yr] 

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

Extrapolation to Basin-Wide Emissions

Basin-wide fugitive emissions are estimated according to Equation 31: 

Equation (31) Efugitive,TOTAL = Efugitive, j × Nwell

where: 

Efugitive,TOTAL is the total fugitive emissions in the basin [ton/yr] 

Efugitive,j is the fugitive emissions for a single well of pollutant j [ton/yr] 

Nwell is the total number of active wells in the basin for calendar year 2002 

County-level fugitive emissions are estimated by allocating the total basin-wide fugitive 

emissions into each county according to the fraction of 2002 well count occurring in that county. 

Input Data

The recommended input data are presented below in Tables 23 and 24: 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 53

Table 23. Recommended fugitive component emissions factors for use in estimating fugitive 

emissions in all major CENRAP basins. 

Emissions Factors [kg-TOC/hr] 

Equipment Type Gas Heavy Oil Light Oil Water/Oil 

Valves 0.0045 0.0000084 0.0025 0.000098

Pump Seals 0.0024 N/A 0.013 0.000024

Others 0.0088 0.000032 0.0075 0.014

Connectors 0.0002 0.0000075 0.00021 0.00011

Flanges 0.00039 0.00000039 0.00011 0.0000029

Open-ended Lines 0.002 0.00014 0.0014 0.00025

The fractions of pollutants to TOC in the gas, used in estimating fugitive emissions, are 

presented in the combined natural gas composition data provided in the master data matrix 

spreadsheet accompanying this report. This composition data is too extensive to present here for 

all major CENRAP basins. 

Data Sources

The number of devices by service type per well for a typical well in each basin were obtained 

from survey data, or where unavailable an average of all CENRAP basins was used. Emissions 

factors in kg-TOC/hr/device were obtained from EPA AP-42 emissions factor documentation 

(EPA, 1995). Note that these emissions rates are evaluated at standard temperature and pressure 

(STP). Fugitive emissions rates in TOC equivalent should be corrected for temperatures and 

pressures if significantly different from STP. 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc Table 24. Recommended number of fugitive components per typical well by component service type in all majo

Number of Components Per Typical Well 

Device Type Service 

Louisiana 

Mississippi Salt Basins 

Southern 

Oklahoma 

Basin 

Nemaha 

Uplift 

Arkoma 

Basin 

Cambridge 

Arch 

Central 

Kansas 

Uplift 

Fort 

Worth 

Basin 

Cheroke

e 

Platform 

Permian 

Basin 

Ea

Tex

Bas

Valves Gas 12 15 15 12 15 12 15 19 Valves 

Heavy Oil 0 0 0 0 0 0 0 0 

Valves Light Oil 20 19 19 20 19 20 19 16 Valves Water/Oil 0 0 0 0 0 0 0 0 Pump Seals Gas 0 0 0 0 0 0 0 0 Pump Seals 

Heavy Oil 0 0 0 0 0 0 0 0 

Pump Seals Light Oil 0 0 0 0 0 0 0 0 Pump Seals Water/Oil 0 0 0 0 0 0 0 0 Others Gas 0 0 0 0 0 0 0 0 Others 

Heavy Oil 0 0 0 0 0 0 0 0 

Others Light Oil 0 0 0 0 0 0 0 0 Others Water/Oil 0 0 0 0 0 0 0 0 Connectors Gas 35 48 48 35 48 35 48 43 Connectors 

Heavy Oil 0 0 0 0 0 0 0 0 

Connectors Light Oil 90 86 86 90 86 90 86 58 Connectors Water/Oil 0 0 0 0 0 0 0 0 Flanges Gas 18 25 25 18 25 18 25 29 Flanges 

Heavy Oil 0 0 0 0 0 0 0 0 

Flanges Light Oil 0 5 5 0 5 0 5 12 Flanges Water/Oil 0 0 0 0 0 0 0 0 Open-ended Lines Gas 6 5 5 6 5 6 5 3 Open-ended Lines 

Heavy Oil 0 0 0 0 0 0 0 0 

Open-ended Lines Light Oil 3 3 3 3 3 3 3 2 Open-ended Lines Water/Oil 0 0 0 0 0 0 0 0 
November 2008 

 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 55

Pneumatic Control Devices 

Methodology

Pneumatic devices are those devices used for a variety of wellhead processes which are powered 

mechanically by high-pressure produced gas as the working fluid – i.e. pneumatically-powered 

devices. This is necessary for many remote well sites where electrical grid power is not 

available to power these devices. Typical pneumatic devices include pressure transducers, liquid 

level controllers, pressure controllers and positioners. These devices are typically in operation 

continuously throughout the year. All of these devices vent or leak the working fluid, which is 

produced gas, and are therefore a source of VOC emissions. If the gas contains a significant 

concentration of H2S, these devices can also be a source of H2S emissions. Like fugitive 

emissions, the emissions from these devices are typically estimated by obtaining a configuration 

of a typical well, including the count of devices by type at the typical well. Emissions rates of 

gas from these pneumatic devices have been studied extensively by the EPA as part of the 

Natural Gas Star program (EPA, 2004), which are the source of quantitative emissions factors for 

pneumatic devices in this analysis. 

The methodology for estimating the emissions from pneumatic devices for a single typical well 

is shown in Equation 32: 

Equation (32) 

⎟

⎟

⎠

⎞ ⎜

⎜

⎝

⎛ ⎟× × × ⎠

⎞ ⎜

⎝

⎛ ⎟×

⎠

⎞ ⎜

⎝

⎛ = × × −

∑

5

,

3.5 10 907200 T MW

R

P V N t f E

gas

i

i i annual

j

pneumatic j &

where: 

Epneumatic,j is the total emissions of pollutant j from all pneumatic devices for a typical well 

[ton/year/well] 

Vi

& is the volumetric bleed rate from device i [MCF/hr/device] 

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

tannual is the number of hours per year that devices 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] 

fj is the mass fraction of pollutant j in the vented gas 

Extrapolation to Basin-Wide Emissions

Basin-wide pneumatic device emissions were estimated according to Equation 33: 

Equation (33) Epneumatic,TOTAL = Epneumatic, j × Nwell

where: 

Epneumatic,TOTAL is the total pneumatic device emissions of pollutant j in the basin [ton/yr] 

Epneumatic,j is the pneumatic device emissions of pollutant j for a single typical well 

[ton/yr/well] 

Nwell is the total number of active wells in the basin for calendar year 2002 
November 2008 

 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 56

County-level emissions are estimated by allocating the total basin-wide pneumatic emissions into 

each county according to the fraction of 2002 well count occurring in that county. 

Input Data

The recommended input data are presented below in Table 25: 

Table 25. Recommended pneumatic device input data for use in estimating pneumatics 

emissions in all major CENRAP basins. 

Device Type 

Basin 

Liquid Level 

Controller Positioner 

Pressure 

Controller Transducer Other 

No. of Devices 2 0 1 0 0 

Anadarko Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 

Arkoma Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 Cambridge Arch Central 

Kansas Uplift Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 

Cherokee Platform Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 

East Texas Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 

Fort Worth Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 Louisiana Mississippi Salt 

Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 

Nemaha Uplift Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 

Permian Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 Southern Oklahoma 

Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

No. of Devices 2 0 1 0 0 

Western Gulf Basin Bleed Rate 

[SCF/hr] 31 15.2 16.8 13.6 0 

Pollutant mass fractions used in estimating pneumatic device emissions are presented in the 

combined natural gas composition data provided in the master data matrix spreadsheet 

accompanying this report. This composition data is too extensive to present here for all major 

CENRAP basins. 
November 2008 

 

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Data Sources

The number of pneumatic devices by device type per well for a typical well in each basin were 

obtained from survey data, or where unavailable an average of all CENRAP basins was used. 

Bleed rates in [scf/hr/device] were obtained from data gathered as part of EPA’s Natural Gas 

Star Program (EPA, 2004). Note that these bleed rates are evaluated at standard temperature and 

pressure (STP). Pneumatic emissions should be corrected for temperatures and pressures if 

significantly different from STP. 

Natural Gas Composition

Data on the chemical composition of the natural gas produced in the major CENRAP basins was 

obtained primarily from surveys, although where unavailable for a particular basin an average of 

all CENRAP basins was used. This data is needed to estimate emissions from a number of 

source categories, particularly the direct venting source categories, and is needed to estimate SO2

emissions where there is a significant concentration of H2S in the gas. Because of the extensive 

nature of these compositions for all major CENRAP basins, it is not possible to present them 

here. These compositions are presented in the natural gas composition section of the master data 

matrix spreadsheet accompanying this report. 

TASK 3b: RECOMMENDED PROJECTION METHODOLOGIES AND INPUT DATA 

FOR GENERATING 2018 EMISSIONS 

The final task of this analysis is to present a methodology for scaling emissions from oil and gas 

area sources to 2018 in support of CENRAP’s or individual state DEQ’s generation of 2018 

emissions inventories for modeling and other purposes. It should be noted that emissions 

projections of this type are often speculative and can rely only on what data are available from 

which to project emissions. Generally the most accurate emissions projections are achieved by 

utilizing the most localized projection data, but this is not always available and, as discussed 

below, is not available broadly for the CENRAP region. 

Emissions projections to 2018 are generated by developing activity scaling factors to grow or 

decline emissions and then developing control factors to represent the impacts of federal or state 

regulations on these emissions sources. This can be done on a basin or state level, and generally 

follows Equation 34: 

Equation (34) = ∑ × × × × −

i

basin i j federal i state i basin state E E GF CF CF f 2018, 2002, , ,

where: 

E2018,basin is the emissions in calendar year 2018 for the portion of a particular basin lying in 

a particular state [ton/yr] 

E2002,i is the 2002 emissions in the basin from source category i [ton/yr] 

GFj is the growth or decline factor of activity surrogate j from 2002 to 2018 (i.e. well count, 

gas production, etc.) 

CFfederal,i is the control factor (by pollutant) associated with a federal regulation that controls 

emissions from source category i

CFstate,i is the control factor (by pollutant) associated with a state regulation that controls 

emissions from source category i 
November 2008 

 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 58

fbasin-state is the portion of a basin lying in each state (i.e. fraction of land area, fraction of 

wells, etc.) 

It should be noted that this approach relies on growing or declining pollutant emissions by 

activity surrogates, rather than predicting an actual number of wells or specific counts of 

equipment for a particular region. The latter approach is used most frequently in the western 

regional U.S. in the development of Environmental Impact Statements (EIS) or Regional 

Management Plans (RMP) for development of oil and gas leases on federal or state land. In an 

EIS or RMP analysis, it is expected that very detailed information would be available on the 

numbers and types of equipment that the applicant is expecting to utilize in the development 

area. However, regional analyses generally do not consider such specific detail in developing 

emissions projections, and this type of analysis is not considered in this work. 

Growth Factors

The growth or decline factors in Equation 34 are typically developed for gas production, oil 

production, well counts and spud counts. They are the ratio of this activity in a basin in 2018 to 

the activity in 2002. There are four sources of documentation that were considered for 

identifying data needed to generate these growth factors: 

• Broad regional oil and gas production outlooks from the Energy Information 

Administration’s (EIA) Annual Energy Outlook (AEO) (EIA, 2008) 

• Specific project-level growth or decline estimates from submitted, finalized EIS or RMP 

documents 

• Other published studies on planned developments within the boundaries of the CENRAP 

region 

• Extrapolation from historical data 

Of these three sources, only the AEO was obtained and determined to provide sufficient data to 

generate growth or decline factors for the domain of the CENRAP region. It was determined 

that for all of the states with significant oil and gas production in the CENRAP region – Texas, 

Louisiana, Oklahoma, Arkansas, Kansas and Nebraska – neither the individual states nor the 

Bureau of Land Management (BLM) tracks information from EIS or RMP documents that would 

include oil and gas developments. On the state level this is because of the permitting 

requirements for oil and gas development in these states. On the federal level this may be 

because the mineral rights to the oil and gas reserves are not owned by the federal government, 

unlike the western regional U.S. where “split-leases” are very common and the BLM oversees 

significant oil and gas development projects. No other regionally-specific studies were identified 

that would provide more localized data to use in determining the growth or decline factors. 

Growth or decline curves generated on the basis of historical data require very detailed annual 

historical production and well statistics by basin, which were not available from the OGCC 

databases gathered as part of Task 1. It should also be noted that extrapolating historical 

production curves to future years can be inaccurate, as they assume continued growth or decline 

along historical trends. This may not be the case if significant levels of new development are 

occurring in specific regions. 

The EIA’s AEO is an economic forecasting model that uses supply-demand analysis to predict 

the growth or decline in gas and/or oil production for broad regional areas of the continental U.S. 
November 2008 

 

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for a number of future calendar years. The regions considered by the AEO are shown in Figure 

5. The AEO also provides data on drilling estimates for future years in a more detailed analysis 

that was requested from the EIA for this project (EIA, 2008). It should be noted that the 

Louisiana-Mississippi Salt Basins lie in two AEO regions: the Gulf Coast and Midcontinent 

regions. For this analysis, the average of the growth or decline factors for all activity surrogates 

was used for this basin. The AEO does not project active well counts. 

Figure 5. Model regions in the EIA’s AEO forecasting analysis. 

The growth or decline factors derived from the AEO for the three regions that lie within the 

CENRAP domain are presented in Table 26. 

Table 26. AEO growth or decline factors for the three regions in the CENRAP domain. 

Study Value Growth or Decline Factor (2018/2002) 

Activity

EIA, 2008: 

Midcontinent 

EIA, 2008: 

Southwest 

EIA, 2008: 

Gulf Coast 

Natural Gas 

Production 0.978 1.094 0.685 

Crude Oil Production 0.819 0.873 0.305 

Drilling 1.265 0.842 1.596 

These growth or decline factors must be applied to specific source categories for all of the major 

CENRAP basins. The specific mapping of source category to growth or decline factor is 

presented in Table 27 for all major oil and gas area source categories considered in this analysis. 

Because of the broad, regional scope of the AEO, many of the growth or decline factors are 

identical for specific basins and source categories.
October 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc Table 27. 2018 growth or decline factors by basin and source category for all major CENRAP basins. 

Source Category (Activity Surrogate) Anadarko Basin Arkoma Basin Cambridge Arch Central Kansas Uplift Cherokee Platform BasiWellhead Compressor Engines (Natural Gas Prod.) 0.978 0.978 0.978 0.97Lateral Compressor Engines (Natural Gas Prod.) 0.978 0.978 0.978 0.97Pump Jacks (Crude Oil Prod.) 0.819 0.819 0.819 0.81Drilling Rigs (Drilling) 1.265 1.265 1.265 1.26Heaters (Natural Gas Prod. and Crude Oil Prod.) 0.898 0.898 0.898 0.89Flares (Natural Gas Prod. and Crude Oil Prod.) 0.898 0.898 0.898 0.89Oil Tanks (Crude Oil Prod.) 0.819 0.819 0.819 0.81Condensate Tanks (Natural Gas Prod.) 0.978 0.978 0.978 0.97Completion Venting (Natural Gas Prod.) 0.978 0.978 0.978 0.97Dehydrators (Natural Gas Prod.) 0.978 0.978 0.978 0.97Blowdown Venting (Natural Gas Prod.) 0.978 0.978 0.978 0.97Fugitive Emissions (Natural Gas Prod.) 0.978 0.978 0.978 0.97Pneumatic Devices (Natural Gas Prod.) 0.978 0.978 0.978 0.97
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 61

Control Factors

Control factors are developed to reduce uncontrolled 2018 emissions after application of activity 

growth or decline factors to account for federal and/or state regulations that would affect 

particular oil and gas area source categories. The regulations that must be considered in the 

CENRAP region for generation of 2018 control factors, and the methodology by which to use 

these regulations to generate control factors, are presented in Table 28. 

Table 28. Federal and state regulations applicable to various oil and gas area source categories 

in the CENRAP domain and recommended methodologies for developing control factors to 

account for these regulations. 

State Regulations Recommended Methodology 

All Federal onroad diesel 

engine standards (EPA, 

2005b) 

Use emissions standards information for 750+ hp oil field equipment 

diesel engines from EPA’s NONROAD model to adjust drill rig engine 

emissions for future performance standards. This is done by running 

NONROAD for all relevant counties for this equipment/technology 

type in 2002 and then again in 2018. The ratio of fleet average perequipment emissions in 2018 to 2002 is the control factor. 

All Federal mandates for nonroad diesel fuel sulfur 

content (EPA, 2006) 

Use NONROAD modeling inputs for 2002 base year inventories and 

EPA-mandated off-road diesel fuel sulfur levels for the 2018 

calendar year to develop control factors by county for SO2 emissions 

from drill rigs. 

All Federal New Source 

Performance Standards 

(NSPS) for stationary sparkignited natural gas engines 

(EPA, 2008) 

Develop control factor that is the ratio of NSPS-compliant wellhead 

and lateral compressor engine and pumpjack engine emissions 

factor to baseline 2002 emissions factor. Use NONROAD model to 

determine fraction of baseline compressor and pumpjack engines 

that are turned over from 2002 to 2018, and multiply control factor 

and turnover fraction to develop overall control factor. 

Texas TCEQ regulation Chapter 

115, Subchapter B – Control 

of VOC emissions from 

oil/condensate tank batteries 

(TCEQ, 2008) 

Use a 90% control factor (representing the use of vapor recovery 

units) for all oil and/or condensate tanks located in: Hardin, Jefferson, 

Orange, Collin, Dallas, Denton, Tarrant, El Paso, Brazoria, 

Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery and 

Waller Counties. These counties represent the Beaumont/Port 

Arthur, DFW, El Paso, and HGB areas covered by this regulation. 

Texas TCEQ regulation Chapter 

117, Subchapter B Divisions 

1-4 – Control of NOx 

emissions from major 

stationary sources (TCEQ, 

2008) 

It is assumed that this regulation applies to lateral compressor 

engines only, as they are the only source category that would fall 

under the definition of a “major source”. Develop a control factor that 

is the ratio of the NOx emissions standard for engines covered in this 

definition (2.0 g/bhp-hr for rich-burn engines in all areas, 3.0 g/bhp-hr 

for rich-burn in Beaumont/Port Arthur non-attainment area only) to 

the NOx emissions factor of these engines in the base year 

inventory. Apply this control factor to the rich-burn engines only 

using the fractions presented under Task 3a (and for lean-burn 

engines in the Beaumont/Port Arthur non-attainment area only). This 

regulation applies to the Beaumont/Port Arthur nonattainment area, 

the Dallas-Ft. Worth nonattainment area, and the HoustonGalveston-Brazoria nonattainment area. 

For heaters develop a control factor that is the ratio of the NOx 

emissions standard for heaters in this regulation to the NOx 

emissions of heaters in the baseline 2002 inventory (baseline heater 

emissions factors estimated as EFNOx/HVgas). Apply this control 

factor to all heater emissions in the Dallas-Ft.Worth and HoustonGalveston-Brazoria nonattainment areas. 

Texas TCEQ regulation Chapter 

117, Subchapter D Divisions 

1-2 – Control of NOx 

emissions from minor 

stationary sources (TCEQ, 

2008) 

For wellhead compressor engines develop a control factor which is 

the ratio of the NOx emissions standard for engines covered in this 

definition (0.5 g/bhp-hr for all engines in the Houston-GalvestonBrazoria nonattainment area, 0.5 g/bhp-hr for rich-burn engines in the 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 62

State Regulations Recommended Methodology 

Dallas-Ft. Worth non-attainment area only and 0.7 g/bhp-hr for leanburn engines in the Dallas-Ft. Worth non-attainment area only) to the 

NOx emissions factor of these engines in the base year inventory. 

Apply the control factor separately to the rich-burn and lean-burn 

engines only using the fractions presented under Task 3a for the 

Dallas-Ft. Worth nonattainment area. Apply this control factor to all 

engines for the Houston-Galveston-Brazoria nonattainment area. 

Texas TCEQ regulation Chapter 

117, Subchapter E Division 4 

– Control of NOx emissions 

from stationary combustion 

sources in East Texas 

(TCEQ, 2008) 

It is assumed that this regulation applies to lateral compressor 

engines only, as they are the only source category which would fall 

under the definition of sources in this regulation (engine horsepower 

greater than 240 hp). Develop a control factor which is the ratio of 

the NOx emissions standard for engines covered in this definition 

(0.5 g/bhp-hr for rich-burn engines greater than 500 hp) to the NOx 

emissions factor of these engines in the base year inventory. Apply 

this control factor to the rich-burn engines only using the fractions 

presented under Task 3a. This regulation applies to the following 

counties in East Texas: Anderson, Brazos, Burleson, Camp, Cass, 

Cherokee, Franklin, Freestone, Gregg, Grimes, Harrison, Henderson, 

Hill, Hopkins, Hunt, Lee, Leon, Limestone, Madison, Marion, Morris, 

Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, Shelby, 

Smith, Titus, Upshur, Van Zandt, and Wood Counties. 

Contacts at the Oklahoma DEQ indicated no specific regulations in the State of Oklahoma that 

would affect oil and gas area source categories (Warden, 2008). Similarly, the State of 

Arkansas, State of Kansas and State of Nebraska have no regulations that would impact area 

source categories, only major point source categories. The State of Louisiana has regulations 

affecting emissions from oil and gas sources as part of the Title 33 Environmental Quality 

Regulations, Part III (LADEQ, 2008). However, with the exception of glycol dehydrators, these 

regulations affect only major sources. Glycol dehydrators are required to install controls if they 

emit greater than 9 tpy VOC. Based on the data available for the Louisiana basins summarized 

in Task 3a above, dehydrator still vents will not emit more than 9 tpy and therefore this 

regulation is not considered applicable to these area source dehydrators. It should be noted that 

if in the future more detailed data on dehydrators operating in the Louisiana-Mississippi Salt 

Basins or Western Gulf Basin (the portion in Louisiana) is made available to CENRAP, still vent 

VOC emissions from these dehydrators should be reevaluated to determine if the Louisiana 

regulation would apply. 

Finally it should be noted that control factors should also incorporate a “rule effectiveness” or 

“penetration rate” factor. This is usually done multiplicatively – the control factor is multiplied 

by the rule effectiveness and penetration rate factor to determine the overall control factor. Rule 

effectiveness accounts for such things as phase-in schedules of regulations, delays in 

implementation of technology and enforcement/compliance issues. Penetration rates refer to the 

fractions of fleets that comply with regulations that require some kind of phase-in, or the 

fractions of fleets that implement particular technologies when a regulation is performance-based 

(rather than technology based). These factors are typically developed by each state’s DEQ or 

other regulatory agency. This work does not present any information on these factors, and in 

their absence it is assumed either that the factors are 1 or that individual state DEQ’s will use 

their information on rule effectiveness and penetration rates in developing these control factors. 
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 63

CONCLUSIONS

A detailed set of data has been developed to aid CENRAP and each individual CENRAP state 

DEQ in generating improved emissions inventory calculations for oil and gas area sources within 

the CENRAP domain. This work has been presented in three tasks: (1) development of oil and 

gas production statistics; (2) a literature review and survey effort; (3) detailed methodologies and 

input data recommended for estimating emissions from major oil and gas source categories by 

basin. 

From Task 1 of this work, analysis results of detailed oil and gas production statistics, organized 

by basin – the basic geographic unit recommended by ENVIRON for conducting oil and gas 

emissions inventory calculations across a broad region have been provided. These data have 

some limitations based on the availability of data from each state’s respective OGCC or 

equivalent, and more accurate assessments of these statistics could be made if more detailed 

well-level production data were available for each state. 

The Task 2 work was to evaluate data obtained from a literature review and limited survey of 

major oil and gas companies. The literature review focused on those major studies 

recommended by CENRAP and some additional studies of which ENVIRON is aware that 

present data useful for calculating emissions from specific source categories. A limited industry 

survey effort was undertaken to supplement the literature review data with operator survey data 

that are specific to companies’ operations in various basins across the CENRAP domain. 

In Task 3a of this work, the recommended methodology for estimating emissions from major oil 

and gas source categories was determined, and a synthesis of the input data that would be used 

for these calculations by basin was provided. In addition, a methodology similar to that used in 

the WRAP regional oil and gas emissions inventories has been presented to project emissions to 

the future year of 2018 in Task 3b. This methodology also considers state-specific regulations 

and their effects on emissions from specific source categories. 

This work provides CENRAP and state DEQs with updated emissions factor and input data that 

can be used to estimate improved regional oil and gas area source emissions. However, it should 

be noted that these calculation methodologies and input data are intended for broad, regional 

inventories of oil and gas and therefore contain some broad assumptions to make these regional 

emissions inventory calculations tractable. While most major oil and gas source categories are 

represented here, detailed inventories of oil and gas may include other source categories and use 

more local data, if available. 
November 2008 

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REFERENCES 

Bar-Ilan, Amnon; Friesen, Ron; Pollack, Alison and Hoats, Abigail, 2007. “WRAP Area Source 

Emissions Inventory Projections and Control Strategy Evaluation Phase II,” Prepared for 

the Western Governor’s Association. September. 

Bar-Ilan, Amnon; Grant, John; Friesen, Ron and Pollack, Alison, 2008. “Development of 

Baseline 2006 Emissions from Oil and Gas Activity in the Denver-Julesburg Basin,” 

Prepared for Colorado Department of Public Health and Environment Air Pollution 

Control Division. April. 

Bhardwaj, Sachin, 2002. “Inventory of Nitrogen Oxide Emissions and Control Technologies in 

Alberta’s Upstream Oil and Gas Industry,” Prepared for Alberta Environment. March. 

Chambers, Allan; Strosher, Mel; Wootton, Tony; Moncrieff, Jan and McReady, Philip, 2006. 

“DIAL Measurements of Fugitive Emissions from Natural Gas Plants and the 

Comparison with Emission Factor Estimates,” Presented at EPA 15th Annual Emissions 

Inventory Conference, New Orleans. May. 

EIA, 2008. “Annual Energy Outlook 2008 with Projections to 2030,” Energy Information 

Administration. June. Report #:DOE/EIA-0383(2008). Internet address: 

http://www.eia.doe.gov/oiaf/aeo/index.html

EPA, 1991. “AP 42, Fifth Edition, Volume I, Chapter 13: Miscellaneous Sources,” U.S. 

Environmental Protection Agency, Research Triangle Park, NC, 1991. Internet address: 

http://www.epa.gov/ttn/chief/ap42/ch13/index.html

EPA, 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

EPA, 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

EPA, 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

EPA, 2004. Natural Gas Star Program, “Convert Gas Pneumatic Controls to Instrument Air, 

Lessons Learned,” EPA-430-B-04-003, February. 

EPA, 2005a. “User’s Guide for the Final NONROAD2005 Model,” U.S. Environmental 

Protection Agency, Research Triangle Park, NC, 2005. EPA420-R-05-013. 

EPA, 2005b. “Nonroad Diesel Equipment Regulations/Standards,” U.S. Environmental 

Protection Agency, Research Triangle Park, NC, July 2005. Internet address: 

http://www.epa.gov/nonroad-diesel/regulations.htm

EPA, 2006. “Direct Final Rule and Notice of Proposed Rulemaking for Amendments to the 

Nonroad and Highway Diesel Fuel Regulations,” U.S. Environmental Protection Agency, 

Research Triangle Park, NC, April 2006. Internet address: 

http://www.epa.gov/otaq/regs/fuels/diesel/420f06033.pdf
November 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 65

EPA, 2008. “Standards of Performance for Stationary Spark Ignition Internal Combustion 

Engines and National Emission Standards for Hazardous Air Pollutants for Reciprocating 

Internal Combustion Engines; Final Rule,” U.S. Environmental Protection Agency, 

Research Triangle Park, NC, January 2008. 

Hendler, Albert; Nunn, Jim and Lundeen, Joe, 2006. “VOC Emissions from Oil and Condensate 

Storage Tanks,” Prepared for Houston Advanced Research Center. October. 

LADEQ, 2008. “Louisiana Environmental Regulatory Code, Title 33,” Louisiana Department of 

Environmental Quality. Internet address: 

http://www.deq.louisiana.gov/portal/tabid/1674/Default.aspx#Title33

Pendleton, Kathy and Rubick, Charles; 2008. Information on Texas Commission on 

Environmental Quality oil and gas area source inventory provided by Kathy Pendleton of 

TCEQ. June 16, 2008. 

Pollack, Alison; Russell, James; Grant, John; and Friesen, Ron, 2006. “Ozone Precursors 

Emission Inventory for San Juan and Rio Arriba Counties, New Mexico,” Prepared for 

New Mexico Environment Department. August. 

Pollution Solutions, 2005. “Tyler/Longview/Marshall Flexible Attainment Region Emission 

Inventory of Ozone Precursors VOC, NOx and CO,” Prepared for Northeast Texas Air 

Care. February. 

Pollution Solutions, 2007. “Special Study Relating to Oil and Gas Production: 2005 and 2007 

Emissions from Compressor Engines with Consideration for Load Factor" Final report 

prepared for the East Texas Council of Governments, Kilgore, TX. 

Reid, Stephen B.; Sullivan, Dana Coe and Gilliland, Erin K., 2008. “Area Source Emission 

Inventory Assessment,” Prepared for Central States Regional Air Partnership. Draft 

June 2008. 

Russell, James and Pollack, Alison, 2005. “Oil and Gas Emissions Inventories for the Western 

States,” Prepared for Western Governor’s Association. December. 

TCEQ, 2008. “Texas Administrative Code, Title 30: Environmental Quality,” Texas 

Commission on Environmental Quality. Internet address: 

http://info.sos.state.tx.us/pls/pub/readtac$ext.ViewTAC?tac_view=3&ti=30&pt=1

USGS, 2008. “National Oil and Gas Assessment: Supporting Data” United States Geological 

Survey, Reston, VA. Internet address: http://energy.cr.usgs.gov/oilgas/noga/data.html

Warden, Lee, 2008. Oklahoma Department of Environmental Quality, personal communication, 

October. 

Wilson, Darcy; Billings, Richard; Oommen, Regi and Chang, Roger, 2007. “Year 2005 Gulfwide 

Emission Inventory Study,” Prepared for Minerals Management Service. December. 
APPENDIX A 

Detailed Oil and Gas Production Statistics for All CENRAP Basins 

(See attached MS Excel spreadsheet) 
APPENDIX B 

Survey Questionnaire for Oil and Gas Companies 
 773 San Marin Drive, Suite 2115, Novato, CA 94998 415.899.0700 

 ENVIRON International Corporation 

CENRAP OIL AND GAS 

EMISSION SURVEY 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

Contact: 

Amnon Bar-Ilan, Ph.D. 

Tel. (415) 899-0732 

Fax.(415) 899-0707 

Email: abarilan@environcorp.com

May 29, 2008 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc B-1 

ENVIRON Corporation has contracted with the Central Regional Air Partnership (CENRAP) to 

assist in improving the methodology for developing oil and gas air emissions inventories in 

member states and tribal areas including Nebraska, Kansas, Oklahoma, Texas, Minnesota, 

Iowa, Missouri, Arkansas, and Louisiana. This methodology will be used to develop improved 

emissions inventories for planning purposes including future regional haze implementation plans 

as well as the 2008 National Emissions Inventory (NEI) and the initial five-year regional haze 

State Implementation Plan (SIP) review. 

ENVIRON has conducted similar methodologies for other areas in the Western Regional Air 

Partnership (WRAP). Our work has included estimates of air emissions from a number of 

processes and equipment types that stretch from the wellhead to fuel distribution networks. Our 

work has included the quantification of nitrous oxides (NOx), volatile organic compounds (VOC), 

Particulate Matter (PM10), Carbon Monoxide (CO), Sulfur Oxides (SOx) and other pollutants 

from oil and gas operations. While the largest CENRAP oil and gas production facilities such as 

major compressor stations and gas plants had been inventoried in the past (as part of stationary 

source emission inventories), the equipment types that are a major priority for this study are 

geographically distributed and are considered area sources. 

ENVIRON’s experience with the WRAP regional inventories, and particularly the current Phase 

III inventory, is that the best emissions inventory is derived with active participation with and in 

cooperation with the major oil and gas producers. Therefore, we have developed a 

questionnaire to assist in gathering information about equipment, activity, and emissions in the 

major CENRAP regions of interest. Specifically, the purpose of this questionnaire is to assist in 

improving CENRAP’s 2002 and 2018 oil and gas emissions inventories. This document contains 

a detailed list of questions to producers – by emissions category – that will aid in improving 

these emissions inventories. 

Overview 

While there are numerous operations and emissions of several pollutants, we have focused this 

survey on major NOx and VOC source categories. These categories are 1) drilling rigs; 

compressor engines; artificial lift engines (pumpjacks); dehydrators; and heaters (NOx and VOC 

emissions) and 2) completion activities, tank venting and flashing; blowdowns; fugitives; and 

pneumatic devices (VOC emissions). 

This questionnaire is organized into two sections: 

1. Section 1 contains a brief checklist for producers to indicate first, whether or not you have 

operations identified on the checklist and second, whether the information contained in Section 

(2) is available. Section 1 can also be used as a quick reference guide for the information that 

we are requesting. 

2. Section 2 contains the detailed questions for producers by emissions category 

Where possible, detailed information is requested and it is preferable that this information be 

provided in electronic form. In order to meet our schedule for completing the task, the deadlines 

for receiving information is by June 30, 2008. 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc B-2

The figure below shows, in graphical form, the CENRAP states and basins for which data is 

being requested. 

The states and basins of interest are as listed below: 

Nebraska 

• Cambridge Arch-Central Kansas Uplift 

• Denver Basin 

• Forest City Basin 

• Salina Basin 

Arkansas 

• Arkoma Basin 

• Illinois Basin 

• Louisiana-Mississippi Salt Basins 

• Ozark Uplift 

Kansas 

• Anadarko Basin 

• Cambridge Arch-Central Kansas Uplift 

• Cherokee Platform 

• Forest City Basin 

• Nemaha Uplift 

• Salina Basin 

• Sedgwick Basin 

Texas 

• Anadarko Basin 

• Bend Arch-Fort Worth Basin 

• East Texas Basin 

• Marathon Thrust Belt 

• Palo Duro Basin 

• Permian Basin 

• Western Gulf 

Oklahoma 

• Anadarko Basin 

• Arkoma Basin 

• Bend Arch-Fort Worth Basin 

• Cherokee Platform 

• Nemaha Uplift 

• Ozark Uplift 

• Southern Oklahoma 

Louisiana 

• Louisiana-Mississippi Salt Basins 

• Western Gulf 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc B-3

We would like to encourage producers to provide information as soon as possible so that we will 

have sufficient time to conduct a thorough analysis incorporating this information. We are 

requesting a brief response by June 10, 2008 about whether or not the information on the 

specific questions included in this questionnaire will be made available, and for which basins 

this information is available (in which basins your company operates). Please use the checklist 

in Section 1 to indicate the availability of information on your operations. Prompt notice of how 

much data we can or cannot expect in advance of the actual deadline for data transfer will help 

ensure that the best possible analysis is conducted. 

ENVIRON will hold confidential all information provided by producers; we will not share specific 

producer information in response to the operations. We will use the information provided to 

aggregate and report emissions by basin only. ENVIRON will sign a confidentiality agreement 

with your company if that will be necessary for you to provide the information requested. All 

information should be provided in electronic format if possible and preferably in spreadsheet 

format. All data should be returned to: 

Amnon Bar-Ilan 

ENVIRON Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

Tel. (415) 899-0732 

Fax. (415) 899-0707 

Email: abarilan@environcorp.com

If you have any questions regarding this questionnaire, or any of the questions contained here, 

please feel free to contact Mr. Bar-Ilan at the phone number or email address above. 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 4 

CENRAP OIL AND GAS 

EMISSION SURVEY 

SECTION 1 

Checklist 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

Contact: 

Amnon Bar-Ilan, Ph.D. 

Tel. (415) 899-0732 

Fax.(415) 899-0707 

Email: abarilan@environcorp.com

May 29, 2008 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 5 

Below is a brief checklist of the information requested in this questionnaire. Please indicate 

whether or not you operate this equipment and whether information on each emissions category 

is available for each basin in which you operate, before you begin to answer the questions 

and provide quantitative information. Please respond to the checklist below and check “Yes” or 

“No” to whether detailed information is available for each question in each emissions category. If 

some information is available but not all, please check “Yes”. 

Please return this completed checklist to ENVIRON by Tuesday, June 10, 2008. 

All of the detailed responses to questions and any quantitative data should be forwarded to 

ENVIRON by the June 30, 2008 deadline. 

Table I. Drilling Rig Emissions. 

Do you operate 

this 

equipment? 

(Y/N) 

Do you have information 

on this equipment for 

calendar year 2002? (Y/N)

If information is 

unavailable for 2002, 

for which year is it 

available? 

Drilling times 

Drilling depths 

Typical rig configuration 

Fuel type 

Fuel consumption rate 

Table II. Compressor Engine Emissions. 

Do you operate 

this equipment? 

(Y/N) 

Do you have 

information on this 

equipment for 

calendar year 2002? 

(Y/N) 

If information is 

unavailable for 

2002, for which year 

is it available? 

Fraction of wells with 

wellhead/lateral compressor 

engines 

 

Number of central compressor 

stations by basin 

 

Average horsepower of a 

wellhead/lateral/central 

compressor 

Average load on compressors by 

basin 

 

Average makes/models of 

compressors by basin 

Information about controls on 

compressors and rich-burn vs. 

lean-burn compressors 

Emissions data from central 

compressor station permits 

 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 6 

Table III. Artificial Lift Engines.

Do you operate 

this equipment? 

(Y/N) 

Do you have 

information on this 

equipment for 

calendar year 2002? 

(Y/N) 

If information is 

unavailable for 

2002, for which year 

is it available? 

Fraction of oil wells with artificial 

lift engines 

 

Average horse power of artificial 

lift engines 

Average makes/models of 

artificial 

Artificial lift engine fuel 

Controls used on artificial lift 

engines 

 

Table IV. Heaters.

Do you operate 

this equipment? 

(Y/N) 

Do you have 

information on this 

equipment for 

calendar year 2002? 

(Y/N) 

If information is 

unavailable for 

2002, for which year 

is it available? 

Number of heaters for a typical 

well setup 

 

Average heater rating 

Average annual usage 

Table V. Natural Gas Composition Analysis. 

Do you have natural 

gas composition 

analyses (Y/N) 

Natural gas composition analysis lab report 

H2S data available 

Table VI . Oil and Condensate Tank Emissions. 

Do you operate 

this equipment? 

(Y/N) 

Do you have 

information on this 

equipment for 

calendar year 2002? 

(Y/N) 

If information is 

unavailable for 

2002, for which year 

is it available? 

Emission factors of 

lb VOC/barrel of oil/condensate 

produced for oil and condensate 

tanks 

 

Fractions of total production 

transported via pipeline 

 

Fraction of total production 

routed to flares 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 7 

Table VII. Fugitives Emissions. 

Do you operate 

this equipment? 

(Y/N) 

Do you have 

information on this 

equipment for 

calendar year 2002? 

(Y/N) 

If information is 

unavailable for 

2002, for which year 

is it available? 

Typical oil, gas and CBM well 

setup 

 

Number and type of components 

Table VIII. Pneumatic Devices. 

Do you operate 

this equipment? 

(Y/N) 

Do you have 

information on this 

equipment for 

calendar year 2002? 

(Y/N) 

If information is 

unavailable for 

2002, for which year 

is it available? 

Number and type of devices 

used at typical well setup 

 

Information on instrument air or 

low-bleed devices in use 

Table IX. Venting Emissions. 

Do you have this 

equipment or 

conduct these 

operations? 

(Y/N) 

Do you have 

information on this 

equipment or these 

operations for 

calendar year 

2002? (Y/N) 

If information is 

unavailable for 

2002, for which 

year is it available? 

Frequency of venting at wells 

(blowdowns) 

 

Venting volume per event 

(blowdowns, completions) 

Control measures or best 

practices implemented 

(blowdowns, completions) 

Glycol dehydrator usage 

Glycol dehydrator emissions 

rates 

 
Page left intentionally blank 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 9

CENRAP OIL AND GAS 

EMISSION SURVEY 

SECTION 2 

Detailed Questions 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

Contact: 

Amnon Bar-Ilan, Ph.D. 

Tel. (415) 899-0732 

Fax.(415) 899-0707 

Email: abarilan@environcorp.com

May 29, 2008 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 10

GENERAL QUESTIONS/COMMENTS 

1. Please provide an overview of your oil and gas operations in the CENRAP region; 

including 

• Basins in which you operate 

• Basins in which you have production operations 

• Primary product(s) in each basin: oil, gas, CBM gas, sour gas, etc. 

• Primary focus of operation: exploration and production or midstream 

2. In responding to the questions below, please indicate the following for all information that 

you provide to us: 

• Basin to which your information refers 

• Whether the basin has conventional or CBM production or both 

• Whether the basin has significant sour gas (H2S) production. 

3. Please respond to all questions with information from calendar year 2002. 

A. MAJOR NOx EMITTER SOURCE CATEGORIES

I. DRILLING RIG EMISSIONS

1. What are the average drilling times (from beginning to completion of drilling) for your 

drilling operations by basin in all basins in which you operate in the CENRAP states? 

2. What are the average drilling depths for your drilling operations by basin? 

3. Please describe a typical configuration of a drilling rig – the number and type of each 

engine (draw works, mud pump, generator), horsepower, load factor, percentage of time 

the engine is in operation during a drilling event, and makes/models of the engines if 

possible. Please provide this information by basin for each of the basins in which you 

operate. 

4. What type of diesel fuel was used in 2002 and what was the sulfur content of that diesel 

fuel for your drilling operations in each basin? 

5. Please provide, if possible, information on the total fuel consumption, or fuel 

consumption rate of drilling rig engines that you operate in each basin. 

II. COMPRESSOR ENGINE EMISSIONS 

1. This is a two-part question: 

• What fraction of the number of wells in each basin in which you operate use 

wellhead compressors? What is a typical make/model of wellhead compressor? 

What is a typical horsepower of a wellhead compressor? What is the load factor on a 

typical wellhead compressor? Are there controls in place on your wellhead 

compressors? What types of controls and on what fraction of the compressors? 

What fraction of these compressors are rich-burn, and what fraction are lean-burn? 

• What fraction of the number of wells in each basin in which you operate use lateral 

compressors? What is a typical make/model of a lateral compressor? What is a 

typical horsepower of a lateral compressor? What is the load factor on a typical 

lateral compressor? Are there controls in place on your lateral compressors? What 

types and on what fraction of the compressors? 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 11

2. Can you provide information from permits on your permitted central compressor 

stations? Please provide information on the number of central compressor stations you 

operate in each basin, and typical emissions (tons per year) of NOx, CO, VOC, PM, SOx 

from these compressor stations. 

III. ARTIFICIAL LIFT ENGINES (PUMPJACKS): 

1. What fraction of oil wells use artificial lift engines – please reply for each basin in which 

you operate? 

2. What is the average horsepower of artificial lift engines used in your operations in each 

basin? 

3. What is a typical make and model of artificial lift engine in each basin in which you 

operate? 

4. What type of fuel is used for artificial lift engines? What is the sulfur content of the fuel? 

5. What controls, if any, are used for artificial lift engines? What fractions of these engines 

are electrified? Please reply for each basin in which you operate. 

IV. HEATERS: 

1. Please provide the number of heaters at a typical well setup for oil, conventional gas 

and CBM gas wells in each basin in which you operate.

2. What is the average heater rating (MMBtu/hour) of the heaters used for your operations 

in each basin? 

3. What is the average annual usage per heater for your operations in each basin 

(hours/year)? 

B. MAJOR VOC EMITTER SOURCE CATEGORIES

V. NATURAL GAS COMPOSITION ANALYSIS 

Natural gas composition is needed to estimate VOC emissions from such sources as pneumatic 

devices, fugitive emissions, well blowdowns, and completions. 

1. Please provide a sample natural gas composition analysis for a typical well in each basin 

in which you operate. Please indicate whether this analysis is from a coal bed methane 

or conventional well. 

2. Please ensure that any gas composition analysis provided indicates the presence or 

absence of H2S in the gas and the H2S fraction if present 

VI. OIL AND CONDENSATE TANK EMISSIONS 

Flashing, working and breathing losses are significant contributors to VOC emissions. To 

develop emissions from oil or condensate tank please provide the requested information below. 

1. Have you ever developed flashing, working, and breathing loss emission factors of lbVOC/barrel of condensate produced using EPA Tank4 model for the oil and condensate 

tanks for each basin in which you operate? If so, please provide emission factors of lbVOC/barrel of condensate produced for oil and condensate tanks. 

2. What fraction of the total production is directly transmitted to pipelines rather than being 

stored in tanks? 
May 2008 

G:\CENRAP O&G\Reporting\Final\CENRAP_O&G_Final_111408.doc 12

3. What fraction of production is stored in tanks which are equipped with flares to control 

flash gas emissions? 

VII. FUGITIVE EMISSIONS 

Fugitive emissions are due to leakage in the equipment in a processing unit. Please provide 

information on Typical Well configuration for fugitive emissions. 

1. Please provide a typical well setup for oil, conventional gas and CBM gas wells in 

which the type, service, and number of components per well type are specified for each 

basin in which you operate. 

• Typical components which could have fugitive emissions are: valves, pump 

seals, connectors, flanges, open-ended lines, or other devices (please 

specify) 

• For a typical well component count, please indicate if the device is for gas, 

water/oil, light oil, or heavy oil service 

VIII. PNEUMATIC DEVICES 

1. Please provide a typical well setup for oil, conventional gas and CBM gas wells in 

which the type and number of pneumatic devices per well type are specified for each 

basin in which you operate. 

• Typical pneumatic devices are: liquid level controllers, pressure controllers, 

positioners, transducers 

• Please indicate what fraction of your high-bleed pneumatic devices run on 

instrument air, or have been replaced by low-bleed devices 

IX. VENTING EMISSIONS 

1. How frequently do you conduct well blowdowns per well, and what is the vented volume 

and the duration of venting for a typical blowdown for each basin in which you operate? 

2. What is the typical vented volume during a well completion, and what is the duration of 

this venting for each basin in which you operate? 

3. Please quantify any control measures or best practices you have implemented to reduce 

blowdown or completion venting emissions for each basin in which you operate. 

4. For each basin in which you operate, please indicate whether you use glycol 

dehydrators in the field or only at large central gas plants. If you use glycol dehydrators 

in the field, please provide information on the number of these units in each basin in 

which you operate. 

• Are controls used on the dehydrators? If so, what types of controls are used 

(flaring or closed vents) and on what fraction of the dehydrators? 
APPENDIX C 

Master Data Matrix of Input Data for 

Emissions Inventory Calculations for All CENRAP Basins 

(See attached MS Excel Spreadsheet)