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

ENVIRON International Corporation 

Final Report 

DEVELOPMENT OF BASELINE 2009 EMISSIONS 

FROM OIL AND GAS ACTIVITY IN THE 

WILLISTON BASIN 

Prepared by 

Amnon Bar-Ilan 

John Grant 

Rajashi Parikh 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

Kathleen Sgamma 

Western Energy Alliance 

410 17th Street, Suite 1920 

Denver, CO 80202 

June 25, 2013 
June 2013 

Final Report i

TABLE OF CONTENTS 

 Page 

EXECUTIVE SUMMARY .................................................................................................... ES1

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

Temporal and Geographic Scope .............................................................................................1

Well Count and Production Data .............................................................................................4

MIDSTREAM SOURCES ..........................................................................................................9

Permit Data for Midstream Facilities from Montana and North Dakota State Agencies ...........9

Permit Data for Major Sources from EPA Region 8 .................................................................9

SURVEYED SOURCES ........................................................................................................... 10

SURVEY-BASED SOURCES EMISSION CALCULATION METHODOLOGIES ................. 12

Amine Units .......................................................................................................................... 12

Artificial Lift (Pumpjack) Engines......................................................................................... 12

Well Blowdowns ................................................................................................................... 13

CBM Pump Engines .............................................................................................................. 14

Well Completions and Recompletions ................................................................................... 15

Compressor Engines .............................................................................................................. 16

Compressor Engine Startups and Shutdowns ......................................................................... 17

Dehydrators ........................................................................................................................... 19

Drill Rigs – Drilling Operations ............................................................................................ 20

Flaring................................................................................................................................... 22

Fugitive Emissions (Leaks) ................................................................................................... 24

Gas Plant and NGL Plant Truck Loading ............................................................................... 25

Heaters .................................................................................................................................. 25

Oil and Gas Well Truck Loading ........................................................................................... 27

Pneumatic Control Devices ................................................................................................... 27

Pneumatic (Gas Actuated) Pumps .......................................................................................... 29

Condensate and Oil Tanks ..................................................................................................... 30

Workover Rigs ...................................................................................................................... 31

SUMMARY RESULTS ............................................................................................................ 32

REFERENCES ......................................................................................................................... 43

 
June 2013 

Final Report ii

LIST OF TABLES 

Table ES-1. Summary of emissions from oil and gas operations in the Williston 

Basin. ....................................................................................................................2

Table ES-2. Comparison of Williston Basin emissions with those of other basins in 

this study. ..............................................................................................................4

Table ES-3. Comparison of production characteristics of all basins inventoried in 

this study to date. ...................................................................................................4

Table 1. 2009 well count by well type and by county for the Williston Basin ......................5

Table 2. 2009 production by production type and by county for the Williston 

Basin .....................................................................................................................6

Table 3. 2009 spud counts by county for the Williston Basin. ..............................................7

Table 4. 2009 emissions of all criteria pollutants by county for the Williston 

Basin ................................................................................................................... 37

Table 5. 2009 NOx emissions [ton/yr] by source category for the Williston 

Basin. .................................................................................................................. 39

Table 6. 2009 VOC emissions [ton/yr] by source category for the Williston 

Basin. .................................................................................................................. 41

LIST OF FIGURES 

Figure 1. Williston Basin boundaries overlaid with 2009 oil and gas well 

locations ................................................................................................................3

Figure 2. 2009 NOx emissions by source category and by county in the 

Williston Basin .................................................................................................... 34

Figure 3. 2009 NOx emissions by tribal and non-tribal land in the Williston 

Basin ................................................................................................................... 34

Figure 4. 2009 VOC emissions by source category and by county in the 

Williston Basin .................................................................................................... 35

Figure 5. 2009 VOC emissions by tribal and non-tribal area in the Williston 

Basin ................................................................................................................... 35

Figure 6. Williston Basin NOx emissions proportional contributions by source 

category. .............................................................................................................. 36

Figure 7. Williston Basin VOC emissions proportional contributions by source 

category. .............................................................................................................. 36
June 2013 

Final Report ES-1 

EXECUTIVE SUMMARY 

This study provides an analysis of the criteria pollutant emissions for oil and gas exploration and 

production operations in the Williston Basin in Montana and North Dakota. The analysis is part 

of an effort sponsored by the Western Energy Alliance (formerly the Independent Petroleum 

Association of Mountain States – IPAMS) jointly with the Western Regional Air Partnership 

(WRAP) for the development of a Phase III regional oil and gas emission inventory for the interMountain West. The overall effort will build on the Phase I and Phase II oil and gas inventory 

projects previously sponsored by WRAP. The Williston Basin emissions inventory is part of an 

overall effort that is focused on creating a comprehensive criteria pollutant emissions inventory 

for all activities associated with oil and gas field operations in the basins throughout the study 

region for a baseline year and future projection years; that includes all point and area sources 

related to the oil and gas industry. 

The primary sources of information were a survey outreach effort to the producers in the 

Williston Basin, and detailed permit data from the Montana Department of Natural Resources 

(MTDNR), North Dakota Department of Health (NDDOH), and US EPA for larger midstream 

sources operating in the basin. Survey forms consisting of 26 Excel spreadsheets were 

forwarded to major participating operators in the Williston Basin. Each spreadsheet contained a 

request for specific data related to the identified oil and gas source categories. All data requested 

from participating companies were for these companies’ activities in the calendar year 2009. 

Well count and production data for the basin were obtained from a commercially available 

database of oil and gas data maintained by IHS Corporation (“the IHS database”). As with the 

emissions estimates, the focus of the IHS database was calendar year 2009. 

The companies participating in the survey process for the Williston Basin represented 

approximately 20% of well ownership in the basin, 30% of gas production in the basin, and 33% 

of oil production in the basin. The ownership percentages in the Williston Basin survey 

responses were significantly lower than in past basins, primarily due to the rapidly changing 

nature of oil production in the Bakken Shale formation, the large geographic area of the basin, 

and production distribution among many companies in the basin. The project sponsors 

determined that despite these limitations, there was a need to develop an initial inventory for the 

Williston Basin. There are other efforts currently ongoing to develop a more comprehensive and 

recent inventory for the Williston Basin such as that sponsored by the Bureau of Land 

Management (BLM) (WRAP, 2013). Considering the low survey response rate, insufficient 

detailed information was available to estimate emissions for some source categories. This may 

be due to the participating companies not having access to this data, not using this equipment, or 

being unable to provide this data. In some cases the categories with insufficient survey data 

were determined to be significant to the overall inventory based on past experience, and broader 

state or national data, or average input factors from other basins were used to gap-fill. Source 

categories for which no data was obtained and which were therefore excluded from the study 

include amine units, CBM pump engines, truck loading at gas and NGL processing plants, water 

disposal pits, water tanks, saltwater disposal engines, and vapor recovery units (VRUs). This 

study does not consider fugitive emissions from oil and gas pipelines from well heads to the 

main compressor stations. Accurate quantitative information on the length of pipeline in the 

basin was not available from sources queried as part of this effort or other data bases that were 

analyzed, and therefore a reasonable estimate of basin-wide pipeline fugitive emissions could not 

be derived. Because of the prevalence of venting and/or flaring of produced gas from oil wells 
June 2013 

Final Report ES-2 

(casinghead gas), casinghead gas venting and flaring was added as a separate source category in 

this study. 

The Williston Basin was defined as consisting of Carter, Custer, Daniels, Dawson, Fallon, 

Garfield, McCone, Prairie, Richland, Roosevelt, Sheridan, Valley, and Wibaux Counties in 

Montana; Butte and Harding Counties in South Dakota; and all counties in North Dakota. For 

purposes of this report only those counties in North Dakota with some oil and gas activity or 

midstream sources were included, consisting of Barnes, Billings, Bottineau, Bowman, Burke, 

Burleigh, Divide, Dunn, Golden Valley, McHenry, McIntosh, McKenzie, McLean, Mercer, 

Morton, Mountrail, Renville, Slope, Stark, Stutsman, Ward and Williams Counties in North 

Dakota. The Williston Basin had significantly more oil production in 2009 than any other basin 

studied thus far in the Phase III project for any calendar year, with approximately 105.9 million 

barrels of oil produced in 2009, primarily from the Bakken Shale formation. The gas production 

in the Williston Basin in 2009 consisted of primary gas from gas wells and associated gas from 

oil wells. There is minimal CBM gas production in the Williston Basin in 2009. 

The total emissions of NOx in the Williston Basin were 14,387 tons in 2009 while total 

emissions of VOCs in the Williston Basin were 357,798 tons in 2009. Overall, compressor 

engines accounted for approximately 34% of NOx emissions basin-wide, including wellhead and 

midstream compressor engines, and drilling rigs accounted for approximately 35% of NOx 

emissions basin-wide. Flashing emissions from oil storage tanks accounted for approximately 

63% of basin-wide VOC emissions, with venting of casinghead gas, condensate tank flashing 

and pneumatic devices and pumps accounting for an addition approximately 30% of VOC 

emissions. Approximately 71% of NOx emissions were derived from the survey data, with the 

remaining approximately 29% of NOx emissions being derived from permit data for primarily 

midstream sources from NDDOH, MTDEQ and EPA. The vast majority of VOC emissions 

were derived from the survey data, with only a small fraction being derived from permit data. 

Table ES-1 below contains a summary of the total emissions from oil and gas operations in the 

Williston Basin. 

Table ES-1. Summary of emissions from oil and gas operations in the Williston Basin. 

County 

NOx

[tons/yr] 

VOC

[tons/yr] 

CO

[tons/yr] 

SOx

[tons/yr] 

PM

[tons/yr] 

Carter (MT) 5 157 4 0 0

Custer (MT) 19 23 4 0 1

Daniels (MT) 1 39 1 0 0

Dawson (MT) 59 704 63 0 5

Fallon (MT) 1,111 14,198 1,543 15 69

Garfield (MT) 2 98 2 0 0

McCone (MT) 35 66 19 0 1

Prairie (MT) 4 130 4 0 0

Richland (MT) 1,149 19,516 1,987 5 64

Roosevelt (MT) 341 3,192 363 33 28

Sheridan (MT) 124 2,740 200 0 10

Valley (MT) 487 1,821 459 9 25

Wibaux (MT) 39 1,214 41 0 2

Barnes (ND) 92 2 7 3 6

Billings (ND) 473 16,139 694 356 16
June 2013 

Final Report ES-3 

County 

NOx

[tons/yr] 

VOC

[tons/yr] 

CO

[tons/yr] 

SOx

[tons/yr] 

PM

[tons/yr] 

Bottineau (ND) 383 10,601 485 1 44

Bowman (ND) 733 48,743 970 1 36

Burke (ND) 285 7,474 366 56 26

Burleigh (ND) 18 5 17 0 0

Divide (ND) 268 6,395 365 1 30

Dunn (ND) 1,381 32,895 1,931 7 155

Golden Valley (ND) 51 2,247 84 0 4

McHenry (ND) 107 236 9 3 6

McIntosh (ND) 39 5 39 2 3

McKenzie (ND) 1,727 43,336 2,132 456 105

McLean (ND) 69 518 78 0 9

Mercer (ND) 21 17 22 0 3

Morton (ND) 113 23 130 6 6

Mountrail (ND) 2,795 102,447 4,643 7 271

Renville (ND) 104 4,859 140 0 9

Slope (ND) 46 2,249 58 0 4

Stark (ND) 151 4,438 160 0 3

Stutsman (ND) 8 3 12 0 0

Ward (ND) 46 339 51 0 6

Williams (ND) 1,830 24,439 1,356 1,118 75

Butte (SD) 28 4 29 0 4

Harding (SD) 241 6,488 298 1 18

TOTAL 14,387 357,798 18,765 2,081 1,045

Daniels, (MT) (Tribal) 0 31 1 0 0

Roosevelt, (MT) (Tribal) 99 1,585 153 26 13

Sheridan, (MT) (Tribal) 0 41 1 0 0

Valley, MT (Tribal) 17 674 21 0 2

Dunn, ND (Tribal) 222 2,638 272 1 29

McKenzie, ND (Tribal) 38 637 47 0 4

McLean, ND (Tribal) 69 518 78 0 9

Mountrail, ND (Tribal) 668 18,678 1,008 2 75

TOTAL (Tribal) 1,114 24,802 1,581 29 132

Daniels, (MT) 

(Non-Tribal) 0 8 0 0 0

Roosevelt, (MT) 

(Non-Tribal) 242 1,606 210 7 15

Sheridan, (MT) 

(Non-Tribal) 124 2,699 199 0 10

Valley, MT 

(Non-Tribal) 470 1,147 438 9 24

Dunn, ND 

(Non-Tribal) 1,159 30,257 1,658 6 126

McKenzie, ND 

(Non-Tribal) 1,689 42,699 2,085 456 100

McLean, ND 

(Non-Tribal) 0 0 0 0 0

Mountrail, ND 

(Non-Tribal) 2,127 83,768 3,636 5 196

a

 – numbers in the table may not sum exactly to the total value listed due to rounding 
June 2013 

Final Report ES-4 

Table ES-2 below shows a summary of the emissions inventory results for the basins which have 

already been inventoried as part of this Phase III effort – the D-J, Uinta, Piceance, North San 

Juan, South San Juan, Wind River, Powder River, and Southwest Wyoming Basins. This table is 

intended for comparison purposes and therefore should be considered in conjunction with Table 

ES-3, which shows a summary of the production and well count characteristics of each of these 

basins. As these two tables show, significant differences in production characteristics are 

observed among these basins, with subsequent effects on the emissions inventories for NOx and 

VOC. It should also be noted that significant variations in gas compositions and operational 

practices were observed among these basins, which also account for differences in the final 

basin-wide emissions. 

Table ES-2. Comparison of Williston Basin emissions with those of other basins in this study.

Basin 

Emissions (tons/yr) 

NOx VOC CO SOx PM 

D-J Basin 20,783 81,758 12,941 226 636

Uinta Basin 13,093 71,546 8,727 396 623

Piceance Basin 12,390 27,464 7,921 314 992

North San Juan Basin 5,700 2,147 6,450 15 52

South San Juan Basin 42,075 60,697 23,471 305 574

Wind River Basin 1,814 11,981 2,840 1,792 37

Powder River Basin 21,086 14,367 12,873 609 681

Southwest Wyoming Basin 21,569 94,013 13,150 5,259 541

Williston Basin 14,387 357,798 18,765 2,081 1,045

Table ES-3. Comparison of production characteristics of all basins inventoried in this study to date. 

Basin 

Well Count 

Oil/Condensate Production 

(bbl) 

Gas Production 

(MCF) 

Spud 

Counts 

Total Conv. CBM Total Oil Well Oil 

Gas Well 

Condensa

te Total CONV CBM Total 

D-J Basin 16,774 16,774 0 14,242,088 0 14,242,088 234,630,779 234,630,779 0 1500 

Uinta Basin 6,881 6,018 863 11,528,121 9,758,247 1,769,874 331,844,336 254,219,432 77,624,904 1069 

Piceance Basin 6,315 6,255 60 7,158,305 5,755,076 1,403,229 421,358,666 420,165,237 1,193,429 1186 

N. San Juan Basin 2,676 1,009 1,667 32,529 27,962 4,567 443,828,500 28,642,418 415,186,082 127 

S. San Juan Basin 20,649 16,486 4,163 2,636,811 1,002,060 1,634,751 1,020,014,851 520,060,869 499,953,982 919 

Wind River Basin 1,350 1,330 20 3,043,459 2,563,912 479,547 198,190,024 197,166,868 1,023,156 98 

Powder River Basin 25,652 7,793 17,859 19,662,896 19,144,596 518,300 452,813,743 64,019,159 388,794,584 3,275 

SW WY Basin 9,173 9,023 150 16,109,922 6,324,849 9,785,073 1,468,167,385 1,462,748,978 5,418,407 1,146 

Williston Basin 8,144 8,141 3 105,868,409 101,729,112 4,139,297 150,025,060 149,979,559 45,501 716 
June 2013 

Final Report 1

INTRODUCTION 

The Western Energy Alliance, formerly the Independent Petroleum Association of Mountain 

States (IPAMS), is sponsoring the development of a Phase III regional oil and gas emission 

inventory for the inter-Mountain West jointly with the Western Regional Air Partnership 

(WRAP), to build on the WRAP Phase I and Phase II inventory projects (Russell, et al., 2005; 

Bar-Ilan, et al., 2007). This effort is focused on creating a comprehensive criteria pollutant 

emissions inventory for all activities associated with oil and gas field operations in the basins 

throughout the study region for a baseline year (primarily 2006, but for the Williston Basin 2009 

was used) as well as future projection years; that includes all point and area sources related to the 

oil and gas industry. 

The inventory presented in this analysis is for the Williston Basin in Montana, North Dakota and 

South Dakota and is the ninth such inventory conducted to date as part of this work, including 

the Denver-Julesburg Basin, Uinta Basin, Piceance Basin, North San Juan Basin, South San Juan 

Basin, Wind River Basin, Powder River Basin and Southwest Wyoming Basin. The 2009 

baseline inventory consists of four primary categories: sources that were permitted by the State 

of Montana; sources that were permitted by the State of North Dakota; sources that were 

permitted by US EPA (for tribal land); and sources that were either exempt from any permitting 

or for which data was collected from surveys of major companies operating in the Williston 

Basin, which are collectively termed “survey-based” sources in this document. This document 

describes the methodologies by which the 2009 inventory was constructed. This methodology is 

specific to the Williston Basin and has additions and changes relative to the other basins in the 

Phase III project. For each source category, a basic description is given of the methodology used 

to estimate emissions from a single source or from all sources belonging to companies that 

participated in the survey effort (“participating companies”), and a description of how those 

emissions were scaled up to the county and basin-wide level. 

In general, the inventory was developed using a combination of well count and production 

activity from a commercially available database of oil and gas data maintained by IHS 

Corporation (“the IHS database”), extensive data on large sources from state and EPA permits, 

and detailed survey responses of oil and gas activity from a number of major participating 

companies that operate in the Williston Basin. Some additional data sources were also used, 

including the US Environmental Protection Agency’s (EPA) AP-42 emissions factor technical 

guidance (EPA, 1995), the US EPA’s NONROAD emissions model (EPA, 2005), and the US 

EPA’s Natural Gas Star program technical guidance (EPA, 2008). 

The survey response rate in the Williston Basin was significantly lower than in other basins. The 

data gathered through surveys is therefore not considered to be as representative of operations 

across the basin as compared to survey data gathered in other Phase III basins. Nevertheless, as 

this represented the only data that was available, the inventory was developed using the limited 

survey data available. For some source categories, other sources of data were used to estimate 

emissions including state agency-developed emission factors, broad national emission factors or 

data from other basins used to gap-fill or supplement the missing data in the Williston Basin. 

Temporal and Geographic Scope 

This inventory considers a base year of 2009 for purposes of estimating emissions. This differs 

from other Phase III basins, but 2009 was selected to reflect the recent boom in oil production 
June 2013 

Final Report 2 

activity in the Williston Basin, and to allow operators to submit more current data given the time 

frame for completion of the Williston Basin baseline inventory. All data requested from 

participating companies were for these companies’ activities in the calendar year 2009. 

Similarly, all well count and production data for the basin obtained from the IHS database were 

for the calendar year 2009. Emissions from all source categories are assumed to be uniformly 

distributed throughout the year except for heaters and pneumatic pumps, which are assigned 

seasonality fractions as they are typically used primarily in winter. 

The geographic scope of this inventory is the Williston Basin in Northeastern Montana, North 

Dakota, and including a small portion of Northwestern South Dakota. For the purposes of this 

study, the boundaries for the Williston Basin were modified from those of the US Geological 

Survey (USGS) (USGS, 2008) to wholly include Carter, Custer, Daniels, Dawson, Fallon, 

Garfield, McCone, Prairie, Richland, Roosevelt, Sheridan, Valley, and Wibaux Counties in 

Montana; Butte and Harding Counties in South Dakota; and all counties in North Dakota. For 

purposes of this report only those counties in North Dakota with some oil and gas activity or 

midstream sources were included, consisting of Barnes, Billings, Bottineau, Bowman, Burke, 

Burleigh, Divide, Dunn, Golden Valley, McHenry, McIntosh, McKenzie, McLean, Mercer, 

Morton, Mountrail, Renville, Slope, Stark, Stutsman, Ward and Williams Counties in North 

Dakota. The geographic scope of the analysis also considers activities on tribal and non-tribal 

land for the Fort Berthold and Fort Peck Indian Reservations. Only those counties for which 

there are tribal and/or non-tribal oil and gas activities are presented in the tables in this report, in 

order to minimize presenting duplicate information. Adjacent areas of oil and gas development 

are covered in the inventories for other basins, including the Powder River Basin. 

Figure 1 shows the boundaries of the Williston Basin, with the 2009 well locations extracted 

from the IHS database overlaid. The Williston Basin includes activity on Indian Tribal land in 

the Fort Berthold and Fort Peck Indian Reservations. 
June 2013 

Final Report 3

Figure 1. Williston Basin boundaries overlaid with 2009 oil and gas well locations.

1

 

 

1

 Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2009) all rights reserved. 
June 2013 

Final Report 4

Well Count and Production Data 

Oil and gas related activity data across the entire Williston Basin were obtained from the IHS 

Enerdeq database queried via online interface. The IHS database uses data from each state’s Oil 

and Gas Conservation Commission (OGCC or equivalent) as sources of information for oil and 

gas activity. This data is also available directly through database querying tools maintained by 

the respective agencies, however it was determined that the IHS database is more accurate and 

complete than these state databases and therefore was chosen as the basis for production statistics 

for this analysis. Two types of data were queried from the Enerdeq database: production data 

and well data. Production data includes information relevant to producing wells in the basin 

while well data includes information relevant to drilling activity (“spuds”) and completions in 

the basin. 

Production data were obtained for all counties in the Williston Basin in the form of PowerTools 

input files. PowerTools is an IHS application which, given PowerTools inputs queried from an 

IHS database, analyzes, integrates, and summarizes production data in an ACCESS database. 

The Williston Basin PowerTools input files were loaded into the PowerTools application. From 

ACCESS database created by PowerTools, extractions of the following data relevant to the 

emissions inventory development were made: 

1. 2009 active wells, i.e. wells that reported any oil or gas production in 2009. 

2. 2009 oil, gas, and water production by well and by well type. 

The production data are available by API number. The API number in the IHS database consists 

of 14 digits as follows: 

 Digits 1 to 2: state identifier 

 Digits 3 to 5: county identifier 

 Digits 6 to 10: borehole identifier 

 Digits 11 to 12: sidetracks 

 Digits 13 to 14: event sequence code (recompletions) 

Based on the expectation that the first 10 digits, which include geographic and borehole 

identifiers, would predict unique sets of well head equipment, the unique wells were identified 

by the first 10 digits of the API number. 

Well data were also obtained from the IHS Enerdeq database for the counties that make up the 

Williston Basin in the form of “297” well data. The “297” well data contain information 

regarding spuds and completions. The “297”well data were processed with a PERL script to 

arrive at a database of by-API-number, spud and completion dates with latitude and longitude 

information. Drilling events in 2009 were identified by indication that the spud occurred within 

2009. If the well API number indicated the well was a recompletion, it was not counted as a 

drilling event, though if the API number indicated the well was a sidetrack, it was counted as a 

drilling event. 

The well counts by well type and by county and tribal/non-tribal land in the basin are presented 

in Table 1, and the oil, gas and water production by county and by tribal/non-tribal land in the 

basin are presented in Table 2. The spuds by county and by tribal/non-tribal land in the basin are 

presented in Table 3. There are significant amounts of primary oil production relative to other 
June 2013 

Final Report 5 

Phase III study basins. All of these production types are accounted for in the emissions 

inventory analysis. 

Table 1. 2009 well count by well type and by county for the Williston Basin. 

County 

Well Count

Conventional Gas Conventional Oil CBM

Carter (MT) 17 1 0 

Custer (MT) 3 0 0 

Daniels (MT) 0 3 0 

Dawson (MT) 1 63 0 

Fallon (MT) 896 507 2 

Garfield (MT) 0 12 0 

McCone (MT) 0 5 0 

Prairie (MT) 1 12 0 

Richland (MT) 1 937 1 

Roosevelt (MT) 0 180 0 

Sheridan (MT) 2 210 0 

Valley (MT) 136 42 0 

Wibaux (MT) 35 86 0 

Barnes (ND) 0 0 0 

Billings (ND) 5 453 0 

Bottineau (ND) 6 517 0 

Bowman (ND) 207 347 0 

Burke (ND) 5 370 0 

Burleigh (ND) 0 0 0 

Divide (ND) 5 138 0 

Dunn (ND) 10 375 0 

Golden Valley (ND) 0 63 0 

McHenry (ND) 0 17 0 

McIntosh (ND) 0 0 0 

McKenzie (ND) 49 819 0 

McLean (ND) 0 17 0 

Mercer (ND) 0 1 0 

Morton (ND) 0 0 0 

Mountrail (ND) 4 506 0 

Renville (ND) 6 285 0 

Slope (ND) 5 16 0 

Stark (ND) 0 71 0 

Stutsman (ND) 0 0 0 

Ward (ND) 0 16 0 

Williams (ND) 39 428 0 

Butte (SD) 0 0 0 

Harding (SD) 85 126 0 

TOTAL 1,518 6,623 3

Daniels, (MT) (Tribal) 0 2 0 

Roosevelt, (MT) (Tribal) 0 67 0 

Sheridan, (MT) (Tribal) 0 1 0 

Valley, MT (Tribal) 0 42 0 

Dunn, ND (Tribal) 0 24 0 

McKenzie, ND (Tribal) 0 21 0 

McLean, ND (Tribal) 0 17 0 

Mountrail, ND (Tribal) 0 112 0 

TOTAL (Tribal) 0 286 0

Daniels, (MT) (Non-Tribal) 0 1 0 

Roosevelt, (MT) (Non-Tribal) 0 113 0 

Sheridan, (MT) (Non-Tribal) 2 209 0 

Valley, MT (Non-Tribal) 136 0 0 

Dunn, ND (Non-Tribal) 10 351 0 

McKenzie, ND (Non-Tribal) 49 798 0 

McLean, ND (Non-Tribal) 0 0 0 

Mountrail, ND (Non-Tribal) 4 394 0 
June 2013 

Final Report 6 

Table 2. 2009 production by production type and by county for the Williston Basin. 

County 

Oil/Condensate

Production 

[bbl] 

Gas Production 

[mcf] 

Water 

Condensate Oil Production [bbl] 

Conventional 

Gas CBM Gas 

Carter (MT) 0 47,422 69,526 0 69,720

Custer (MT) 0 0 52,151 0 0

Daniels (MT) 0 4,938 0 0 15,420

Dawson (MT) 2,969 385,040 142,820 0 3,205,703

Fallon (MT) 14,210 6,052,817 26,202,607 43,204 39,306,771

Garfield (MT) 0 15,519 2,190 0 76,231

McCone (MT) 0 5,978 0 0 124,907

Prairie (MT) 0 73,478 8,421 0 2,181,456

Richland (MT) 24,353 15,030,932 15,498,756 2,297 5,952,063

Roosevelt (MT) 0 1,231,753 676,550 0 13,516,282

Sheridan (MT) 7,598 1,399,251 719,352 0 13,004,061

Valley (MT) 0 108,677 1,651,676 0 1,013,884

Wibaux (MT) 0 683,784 506,487 0 11,416,417

Barnes (ND) 0 0 0 0 0

Billings (ND) 10,777 3,851,040 4,402,467 0 22,465,786

Bottineau (ND) 47,970 1,886,460 102,700 0 33,193,774

Bowman (ND) 1,508,525 11,775,394 19,532,334 0 28,673,365

Burke (ND) 24,719 1,339,403 2,785,165 0 5,375,969

Burleigh (ND) 0 0 0 0 0

Divide (ND) 71,387 1,466,984 2,142,065 0 2,032,633

Dunn (ND) 212,131 8,593,878 6,055,051 0 4,795,596

Golden Valley (ND) 0 541,708 633,197 0 2,492,158

McHenry (ND) 0 32,431 0 0 501,299

McIntosh (ND) 0 0 0 0 0

McKenzie (ND) 1,088,712 8,836,117 17,798,936 0 14,942,503

McLean (ND) 0 116,514 66,804 0 159,446

Mercer (ND) 0 2,107 1,292 0 25,981

Morton (ND) 0 0 0 0 0

Mountrail (ND) 254,811 29,356,264 16,006,648 0 5,923,604

Renville (ND) 32,934 744,115 70,976 0 9,251,276

Slope (ND) 149,412 374,320 2,055,894 0 537,777

Stark (ND) 0 1,194,054 570,527 0 9,424,025

Stutsman (ND) 0 0 0 0 0

Ward (ND) 0 60,132 18,029 0 714,831

Williams (ND) 676,574 4,914,674 19,596,192 0 14,450,513

Butte (SD) 0 0 0 0 0

Harding (SD) 12,215 1,603,928 12,610,746 0 3,610,035

TOTAL 4,139,297 101,729,112 149,979,559 45,501 248,453,486

Daniels, (MT) 

(Tribal) 0 4,862 0 0 15,056

Roosevelt, (MT) 

(Tribal) 0 324,432 34,454 0 9,947,157

Sheridan, (MT) 

(Tribal) 0 10,137 4,359 0 34,457

Valley, MT (Tribal) 0 108,677 7,355 0 995,592

Dunn, ND (Tribal) 0 717,598 509,263 0 257,790

McKenzie, ND 

(Tribal) 0 135,712 384,867 0 260,199

McLean, ND (Tribal) 0 116,514 66,804 0 159,446

Mountrail, ND 

(Tribal) 0 5,368,044 2,596,906 0 916,642

TOTAL (Tribal) 0 6,785,976 3,604,008 0 12,586,339

Daniels, (MT) 

(Non-Tribal) 0 76 0 0 364

Roosevelt, (MT) 

(Non-Tribal) 0 907,321 642,096 0 3,569,125
June 2013 

Final Report 7 

County 

Oil/Condensate

Production 

[bbl] 

Gas Production 

[mcf] 

Water 

Condensate Oil Production [bbl] 

Conventional 

Gas CBM Gas 

Sheridan, (MT) 

(Non-Tribal) 7,598 1,389,114 714,993 0 12,969,604

Valley, MT 

(Non-Tribal) 0 0 1,644,321 0 18,292

Dunn, ND 

(Non-Tribal) 212,131 7,876,280 5,545,788 0 4,537,806

McKenzie, ND 

(Non-Tribal) 1,088,712 8,700,405 17,414,069 0 14,682,304

McLean, ND 

(Non-Tribal) 0 0 0 0 0

Mountrail, ND 

(Non-Tribal) 254,811 23,988,220 13,409,742 0 5,006,962

Table 3. 2009 spud counts by county for the Williston Basin. 

County 

Total Number of 

Spuds in 2009 

Carter (MT) 0 

Custer (MT) 0 

Daniels (MT) 0 

Dawson (MT) 3 

Fallon (MT) 31 

Garfield (MT) 0 

McCone (MT) 0 

Prairie (MT) 0 

Richland (MT) 16 

Roosevelt (MT) 7 

Sheridan (MT) 5 

Valley (MT) 10 

Wibaux (MT) 0 

Barnes (ND) 0 

Billings (ND) 2 

Bottineau (ND) 35 

Bowman (ND) 15 

Burke (ND) 19 

Burleigh (ND) 0 

Divide (ND) 27 

Dunn (ND) 138 

Golden Valley (ND) 3 

McHenry (ND) 0 

McIntosh (ND) 0 

McKenzie (ND) 77 

McLean (ND) 9 

Mercer (ND) 3 

Morton (ND) 0 

Mountrail (ND) 239 

Renville (ND) 5 

Slope (ND) 3 

Stark (ND) 1 
June 2013 

Final Report 8 

County 

Total Number of 

Spuds in 2009 

Stutsman (ND) 0 

Ward (ND) 6 

Williams (ND) 45 

Butte (SD) 4 

Harding (SD) 13 

TOTAL 716 

Daniels, (MT) (Tribal) 0 

Roosevelt, (MT) 

(Tribal) 2 

Sheridan, (MT) 

(Tribal) 0 

Valley, MT (Tribal) 1 

Dunn, ND (Tribal) 28 

McKenzie, ND 

(Tribal) 4 

McLean, ND (Tribal) 9 

Mountrail, ND (Tribal) 69 

TOTAL (Tribal) 113 

Daniels, (MT) 

(Non-Tribal) 0 

Roosevelt, (MT) 

(Non-Tribal) 5 

Sheridan, (MT) 

(Non-Tribal) 5 

Valley, MT 

(Non-Tribal) 9 

Dunn, ND 

(Non-Tribal) 110 

McKenzie, ND 

(Non-Tribal) 73 

McLean, ND 

(Non-Tribal) 0 

Mountrail, ND 

(Non-Tribal) 170 
June 2013 

Final Report 9 

MIDSTREAM SOURCES 

Permitted sources in the Williston Basin analysis refer to three types of sources for which data 

was gathered: (1) Title V or major sources in use in midstream, gas gathering applications from 

permit data from the MTDNR; (2) Title V or major sources in use in midstream applications 

from NDDOH; and (3) Part 71 major sources on tribal land from US EPA Region 8. The three 

source types are described below. In general, these permitted sources were used to supplement 

the emissions associated with well-site sources which were derived from survey data. Most 

permitted emissions used in this inventory were for midstream facilities which were not included 

in the exploration and production (E&P) sector surveys described in the next section. Although 

the MTDNR registers production-site equipment, this study used the detailed survey of operators 

to estimate emissions from these sources rather than permit data for individual production sites 

due to the availability of the data and the resources available for processing this data. 

Permit Data for Midstream Facilities from Montana and North Dakota State Agencies 

As noted in previous inventories, midstream companies were generally not participants in the 

survey process conducted in the Williston Basin, with the exception of some gas and oil 

producers who may also own and operate midstream facilities. Because NDDOH and MTDNR 

permit large midstream sources on non-tribal land in each state respectively, it was determined 

that these permit databases would be the most comprehensive source of data on midstream 

facilities such as gas plants, compressor stations and associated equipment. Requests were made 

to the MTDNR and NDDOH to query their database of permitted facilities to identify midstream 

oil and gas sources in the Williston Basin using a combination of NAICS (SIC) and SCC codes 

corresponding to onshore oil and gas sources. The queries were conducted in several iterations, 

with review of the resulting database of sources and clarification of any issues with the sources 

in subsequent iterations. This query was focused on facilities and to the extent possible excluded 

production sites. It is noted that both NDDOH and MTDNR require registration of production 

sites including registration of equipment at the sites, but discussions with both agencies indicated 

that this information was not considered readily available and of sufficient quality for use in the 

inventory. 

Permit Data for Major Sources from EPA Region 8 

Title V and Part 71 permits were requested from EPA Region 8 covering the Williston Basin, 

primarily for the Fort Berthold and Fort Peck Indian Reservations. Data provided by EPA 

indicated only a single source in the Fort Peck Indian Reservation meeting the Title V emission 

thresholds, and at the time of the request no additional permit data was available for sources 

operating in the Fort Berthold Indian Reservation. EPA Region 8 did indicate that they were 

aware of existing sources on the Fort Berthold Indian Reservation but that these sources had not 

yet received Title V permits at the time of the data request and therefore data were not readily 

available on these sources. It is acknowledged that other large midstream sources may be 

operating on tribal land that have not been captured in this inventory, and that minor midstream 

sources below the Title V thresholds operating on tribal lands may also be missing from this 

inventory. Additional data on these sources would be required in order to incorporate these 

emissions into future inventories of the Williston Basin. 
June 2013 

Final Report 10 

SURVEYED SOURCES 

Survey forms consisting of 24 Excel spreadsheets were forwarded to participating operators in 

the Williston Basin. Each spreadsheet contained a request for specific data related to one of the 

following source categories: 

 Amine units 

 Artificial lift engines 

 Well blowdowns 

 CBM pump engines 

 Well completions 

 Compressor engines 

 Compressor startups and shutdowns 

 Dehydrators 

 Drilling rigs 

 Flaring 

 Fugitive emissions 

 Gas plant truck loading 

 Heaters 

 Miscellaneous engines 

 Gas composition analyses for the basin 

 NGL plant truck loading 

 Oil and gas well truck loading 

 Pneumatic devices 

 Pneumatic pumps 

 Salt water disposal engines 

 Condensate and oil tanks 

 Water disposal pits 

 Water tanks 

 Workover rigs 

The companies participating in the survey process for the Williston Basin represented 

approximately 20% of well ownership in the basin, 30% of gas production in the basin, and 33% 

of oil production in the basin. The ownership percentages in the Williston Basin survey 

responses were significantly lower than in past basins, primarily due to the rapidly changing 

nature of oil production in the Bakken Shale formation, the large geographic area of the basin, 

and production distribution among many companies in the basin. The project sponsors 

determined that despite these limitations, there was a need to develop an initial inventory for the 

Williston Basin. 

Insufficient survey data was obtained to estimate emissions for certain source categories. These 

source categories were therefore excluded from the study and include amine units, CBM pump 

engines, truck loading at gas and NGL processing plants, water disposal pits, water tanks, and 

saltwater disposal engines. Finally, potential fugitive emissions from oil and gas pipelines from 

well heads to the main compressor stations were not estimated, consistent with other basins. 

Insufficient data was available on the components of pipelines or the complete extent of 

pipelines to tractably estimate basin-wide pipeline fugitive emissions. 
June 2013 

Final Report 11 

Considering the low survey response rate, insufficient detailed information was available to 

estimate emissions for some source categories that were otherwise considered significant to the 

overall inventory, or were demonstrated to be significant sources of criteria pollutants in past 

Phase III inventories. The lack of data may be due to the participating companies not having 

access to this data, or being unable to provide this data. Where surveys were unable to provide 

sufficient data to estimate emissions for key source categories, broader state or national data, or 

average input factors from other basins were used to gap-fill. This includes condensate and oil 

tank flashing and working and breathing losses, flaring of condensate and oil tanks, and 

casinghead gas flaring. Emission factor data from studies conducted in the Bakken and data 

gathered by NDDOH on flaring controls for tanks were used to estimate crude oil and 

condensate tank emissions. 

Detailed inventory methodologies for each of the source categories follow. Extrapolation of 

these data was necessary to account for emissions from all oil and gas activity in the basin. The 

extrapolation methodology to obtain county-level, tribal county-level, non-tribal county-level 

and basin-wide emissions for each source category is described below, but is largely based on 

scaling by the proportional representation of the respondents of basin-wide well count or oil or 

gas production, as appropriate. For source categories for which emissions were not derived from 

survey data, county-level, tribal and non-tribal and basin-wide emissions were estimated directly 

using the appropriate surrogate. 

For emissions from those source categories that relied on estimates of volume of gas vented or 

leaked, such as well blowdowns, completions, and fugitive emissions, gas composition analyses 

were requested from all participating companies for gas produced from oil wells (casinghead or 

associated gas) and gas produced from gas wells (primary gas). These composition analyses 

were averaged using two methodologies to derive two basin-wide produced gas composition 

averages: (1) weighted average by oil well vs. gas well count; and (2) weighted average by 

associated gas production vs. primary gas production. The average composition analyses were 

used to determine the average VOC volume and mass fractions of the vented gas basin-wide and 

each composition was applied to those source categories which use well counts and gas 

production as surrogates, respectively. In both the well-count weighted and gas productionweighted average gas compositions, the average is closer to that of associated gas since that is 

the dominant gas production type in the basin. 73% of basin-wide gas production is associated 

gas from oil wells, and 81% of active wells are oil wells. Finally, because of the minimal 

volume of CBM gas produced in the basin, no separate gas composition was derived for CBM 

gas and all CBM gas production was treated equivalent to other gas production for purposes of 

emission estimates. 

It should be noted that the emission estimates calculated for unpermitted sources rely on data that 

is not as rigorously documented as permitted sources. Much of the data provided for these 

sources is based upon estimates and extrapolation from the survey responses. Given the extent 

of participation in the survey effort these estimates reflect greater uncertainty and variability than 

other past Phase III basins. 
June 2013 

Final Report 12 

SURVEY-BASED SOURCES EMISSION CALCULATION METHODOLOGIES 

Amine Units 

As noted above, the production companies surveyed as part of this work indicated minimal or no 

usage of amine units in field operations. Insufficient data was gathered to estimate emissions for 

this source category. It is possible that some amine units or other acid gas removal systems are 

in use at large gas processing facilities and their vented emissions would be counted with the 

facility total VOC emissions for purposes of the inventory. 

Artificial Lift (Pumpjack) Engines 

Methodology 

The participating companies provided data on artificial lift engine usage in their operations. 

Emission calculations for artificial lift engines are based on engine parameters including 

horsepower, and break-horsepower-based emissions factors. 

The basic methodology for estimating emissions from an artificial lift engine is shown in 

Equation 1: 

Equation (1) 185,907

annuali

engine

tLFHPEF 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] 

Emission factors were adjusted to account for deterioration due to engine wear and tear and also 

the sub-optimal field conditions under which the engines operate. To make this adjustment the 

deterioration factors from the EPA NONROAD2005 model were applied (EPA, 2005). Given 

the lack of survey data regarding engine age, all engines were assumed fully deteriorated. 

Note that SO2 emissions are estimated using the BSFC of the engine, and the assumed sulfur 

content of the fuel, assuming that all sulfur emissions are in the form of SO2. For natural gasfired engines, it is assumed that sour gas containing H2S would not be used for direct combustion 

in engines; therefore SO2 emissions were also assumed negligible from artificial lift engines 

powered by natural gas. 

Extrapolation to Basin-Wide Emissions 

Emissions from all artificial engines from the participating companies were summed. The total 

emissions from all participating companies were scaled by the ratio of total oil production in the 

basin to oil production ownership by the participating companies according to Equation 2: 
June 2013 

Final Report 13 

Equation (2) P

P EE TOTAL

,  engineTOTALengine

where: 

Eengine,TOTAL is the total emissions from artificial lift engines in the basin [ton/yr] 

Eengine is the total emissions from artificial engines owned by the participating companies 

[ton/yr] 

PTOTAL is the total oil production from oil wells in the basin 

P is the oil production from oil wells by the participating companies 

County-level emissions were estimated by allocating the total basin-wide artificial lift engine 

emissions into each county according to the fraction of total 2009 oil production from oil wells 

located in each county. Tribal and non-tribal emissions were estimated in each county by 

allocating the county total emissions into tribal land according to the fraction of total 2009 oil 

production from oil wells occurring on tribal land in that county and into non-tribal land 

according to the fraction of total 2009 oil production from oil wells not occurring on tribal land 

in that county. 

Well Blowdowns 

Methodology 

Emissions from well blowdowns were calculated using the estimated volume of gas vented 

during blowdown events, the frequency of the blowdowns, and the VOC content of the vented 

gas as documented by representative compositional analyses. 

The calculations applied the ideal gas law and gas characteristics defined from laboratory 

analyses to estimate emissions according to Equations 3 to 5: 

Equation (3)  VfV ,TOTALventedvented

where: 

Vvented is the volume of vented gas per blowdown [mscf/event] 

f is the frequency of blowdowns [events/year] 

Vvented,TOTAL is the total volume of vented gas from the participating companies [mscf/year] 

Equation (4) 

PCO

PCOCONV

TOTALventedCONVvented P

P VV , ,, 

where: 

Vvented,CONV is the total volume of vented gas from participating companies conventional oil 

and gas well production [mscf] 

PCONV,PCO is the total conventional oil and gas well gas production in the basin in 2009 by 

the participating companies [mscf] 

PPCO is the total gas production in the basin in 2009 by the participating companies [mscf] 

Equation (5)  YRMW1000VE ,,,, CONVVOCCONVVOCCONVventedCONVblowdown
June 2013 

Final Report 14 

where: 

Eblowdown,CONV is the total VOC emissions from blowdowns conducted by the participating 

companies [lb-VOC/yr] 

MWVOC,CONV is the molecular weight of the VOC for conventional oil and gas well vented 

gas [lb/lb-mol] 

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

Y VOC,CONV is the volume fraction of VOC in the conventional oil and gas well vented gas 

The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions 

The total VOC emissions from conventional well blowdowns reported by participating 

companies were scaled by the proportional production ownership of the participating companies 

according to Equation 6: 

Equation (6) 

CONVPCO

CONVTOTAL

CONVblowdownTOTALCONVblowdown P

P EE ,

,

,,, 

where: 

Eblowdown,CONV,TOTAL are the total emissions basin-wide from blowdowns at conventional wells 

[tons/year] 

Eblowdown,CONV are the blowdown emissions from the participating companies at conventional 

wells [tons/year] 

PTOTAL,CONV is the total gas production in the basin in 2006 from conventional wells [mscf] 

PPCO,CONV is the total gas production in the basin in 2006 by the participating companies 

from conventional wells [mscf] 

County-level emissions from conventional oil and gas wells were estimated by allocating the 

total basin-wide blowdown emissions from conventional oil and gas wells into each county 

according to the fraction of conventional 2009 gas production occurring in that county. Tribal 

and non-tribal emissions from conventional oil and gas wells were estimated in each county by 

allocating the county conventional well blowdown emissions into tribal land according to the 

fraction of 2009 conventional oil and gas well gas production occurring on tribal land in that 

county and into non-tribal land according to the fraction of total 2009 conventional oil and gas 

well gas production not occurring on tribal land in that county. 

CBM Pump Engines 

As noted above, there is minimal CBM activity in the Williston Basin and producers responding 

to the surveys did not indicate any usage of CBM pump engines at gas wells in the Williston 

Basin. Insufficient data was gathered to estimate emissions for this source category. 

 
June 2013 

Final Report 15 

Well Completions and Recompletions 

Methodology 

Emissions from well completions were estimated on the basis of the volume of gas vented during 

completion and the average VOC content of that gas, obtained from the gas composition 

analyses. The “well completion” source category refers to initial completions of wells after 

drilling, and the “well recompletion” category refers to recompletions occurring at existing 

production wells. 

The calculation methodology for completion emissions is very similar to the method for well 

blowdown emissions, and follows Equations 7 to 9: 

Equation (7)  VfV ,TOTALventedvented

where: 

Vvented is the volume of vented gas per initial completion or re-completion [mscf/event] 

f is the frequency of completions [events/year] 

Vvented,TOTAL is the total volume of vented gas from completions for participating companies 

[mscf/year] 

Equation (8) 

PCO

PCOCONV

TOTALventedvented W

W VV , , 

where: 

Vvented is the total volume of vented gas from participating companies conventional well 

production [mscf] 

WCONV,PCO is the total conventional well count ownership in the basin in 2009 by the 

participating companies [mscf] 

WPCO is the total well count ownership in the basin in 2009 by the participating companies 

[mscf] 

Equation (9) ,  YRMW1000VE VOCVOCTOTALventedcompletion

where: 

Ecompletions is the total VOC emissions from completions conducted by all participating 

companies [lb-VOC/yr] 

MWVOC is the molecular weight of the VOC [lb/lb-mol] 

R is the universal gas constant [lb-mol/379scf] 

Y is the volume fraction of VOC in the vented gas 

The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions 

The total VOC emissions from all completions reported by participating companies was scaled 

by the total number of completions in the basin to the number of completions conducted by the 

participating companies according to Equation 10: 
June 2013 

Final Report 16 

Equation (10) 

PCO

TOTAL

completionTOTALcompletion C

C , EE 

where: 

Ecompletion,TOTAL are the total emissions basin-wide from completions at conventional wells 

[tons/year] 

Ecompletion, are the completion emissions from the participating companies at conventional 

wells [tons/year] 

CTOTAL is the total number of conventional well completions in the basin in 2006 [mscf] 

CPCO is the total number of conventional well completions in the basin in 2006 by the 

participating companies [mscf] 

A similar procedure was used to estimate total basin-wide VOC emissions from recompletions. 

County-level emissions from conventional oil and gas well completions were estimated by 

allocating the total basin-wide completion emissions from conventional oil and gas wells into 

each county according to the fraction of conventional 2009 oil and gas well count occurring in 

that county. Tribal and non-tribal emissions from conventional oil and gas wells were estimated 

in each county by allocating the county conventional oil and gas well completion emissions into 

tribal land according to the fraction of 2009 conventional well count occurring on tribal land in 

that county and into non-tribal land according to the fraction of total 2009 conventional oil and 

gas well count not occurring on tribal land in that county. 

Compressor Engines 

Methodology: 

The participating companies provided survey data on wellhead and lateral compressor engines in 

use for their operations. Large central compressor engines were assumed to be part of midstream 

point sources, as described above under permitted sources. It was assumed that all wellhead and 

lateral compressor engines are natural-gas fired. 

Emission calculations for compressor engines follow a similar methodology as for artificial lift 

engines. Emission factors for the compressor engines were directly obtained from the survey 

respondents where such information was provided. If emissions factors were not provided, 

emissions factors from engines of a similar make/model were used. If make/model were also 

unavailable, average emission factors from engines with similar horsepower were used or 

average emissions factors from all engines were used. In the case of PM10 emissions factors, 

EPA AP-42 emissions factors were used as most survey respondents did not provide PM10

emissions factors for these engines (EPA, 1995). Efforts were made to track emissions 

separately from lean-burn and rich-burn wellhead compressor engines where such a distinction 

was clear. An engine was determined to be rich-burn or lean-burn based on either information 

directly from the survey data, from the model number of the engine, or from examining the 

engine’s brake-specific NOx emissions factor. Load factors were directly obtained from survey 

respondents where such information was provided. For engines where a load factor was not 

provided, the load factor was estimated by taking the average of compression engine load factors 

supplied in producer surveys. 
June 2013 

Final Report 17 

The basic methodology for estimating emissions from compressor engines is shown in Equation 

11: 

Equation (11) 185,907

annuali

engine

tLFHPEF E 

where: 

Eengine are emissions from a compressor 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] 

It was assumed (and confirmed through discussions with operators) that gas-fired engines would 

not use gas high in H2S content due to operational issues; therefore SO2 emissions were assumed 

negligible from these engines. 

Extrapolation to Basin-Wide Emissions 

Emissions from all compressor engines from the participating companies were summed. The 

total emissions from all participating companies were scaled by the ratio of total gas production 

in the basin to gas production from the wells owned by the participating companies according to 

Equation 12: 

Equation (12) W

W EE TOTAL

,  engineTOTALengine

where: 

Eengine,TOTAL is the total emissions from compressor engines in the basin [ton/yr] 

Eengine is the total emissions from compressor engines owned by the participating companies 

[ton/yr] 

WTOTAL is the total gas production in the basin 

W is the total gas production from the wells owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide compressor engine 

emissions into each county according to the fraction of total 2009 gas production that are located 

in each county. Tribal and non-tribal emissions were estimated in each county by allocating the 

county total emissions into tribal land according to the fraction of total gas production on tribal 

land in that county and into non-tribal land according to the fraction of total gas production that 

are not on tribal land in that county. 

Compressor Engine Startups and Shutdowns 

Methodology 

Compressor engine startups and shutdowns refer to the emissions associated with venting of gas 

contained in compressor engines when they are restarted or shut down for maintenance, repairs 

or any other routine or non-routine reason. Emissions from compressor engine startups and 
June 2013 

Final Report 18 

shutdowns were calculated separately using the estimated volume of gas vented during 

compressor engine startup and shutdown events, the frequency of the startup and shutdown 

events, the number of compressor engines, and the VOC content of the vented gas as 

documented by representative compositional analyses. This source category does not consider 

combustion-related emissions associated with compressor start-ups and shutdowns. Insufficient 

survey data was provided on volumes of gas vented from compressor startups and shutdowns in 

the Williston Basin, so an average volume was derived based on survey data provided for other 

Phase III basins. 

The calculations applied the ideal gas law and gas composition to estimate emissions according 

to Equations 13 to 14: 

Equation (13) , ventedTOTALvented  fnVV

where: 

Vvented,TOTAL is the total volume of vented gas from the participating companies for startup or 

shutdown[mscf/year] 

Vvented is the average volume of vented gas per startup or shutdown as indicated by survey 

respondents [mscf/event/engine] 

n is the number of compressor engines for which startup and shutdown data was provided by 

producing companies [engines] 

f is the frequency of startup or shutdown [events/year] 

f] 

Equation (14) ,  YRMW1000VE VOCVOCTOTALventedS

where: 

ES is the total VOC emissions from well compressor engine startups or shutdowns conducted 

by the participating companies [lb-VOC/yr] 

MWVOC is the molecular weight of the VOC for conventional well vented gas [lb/lb-mol] 

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

YVOC is the volume fraction of VOC in the conventional well vented gas 

The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions 

The total VOC emissions from all startups and shutdowns reported by participating companies 

were scaled by the proportional production ownership of the participating companies according 

to Equation 15: 

Equation (15) 

PCO

TOTAL

STOTALS P

P , EE 

where: 

ES,TOTAL are the total emissions basin-wide from compressor engine startup or shutdown at 

conventional wells [tons/year] 

ES are the compressor engine startup or shutdown emissions from the participating 

companies at conventional wells [tons/year] 
June 2013 

Final Report 19 

PTOTAL is the total gas production in the basin in 2009 from conventional wells [mscf] 

PPCO is the total gas production in the basin in 2009 by the participating companies from 

conventional wells [mscf] 

County-level emissions from conventional wells were estimated by allocating the total basinwide compressor startup and shutdown emissions from conventional oil and gas wells into each 

county according to the fraction of conventional 2009 gas production occurring in that county. 

Tribal and non-tribal emissions from conventional oil and gas wells were estimated in each 

county by allocating the county conventional well compressor startup and shutdown emissions 

into tribal land according to the fraction of 2009 conventional well gas production occurring on 

tribal land in that county and into non-tribal land according to the fraction of total 2009 

conventional well gas production not occurring on tribal land in that county. 

Dehydrators 

Minimal data on field dehydrators was provided by the participating companies. These 

companies provided direct VOC emissions estimates for these dehydrators. These VOC 

emissions estimates were derived by the participating companies using the GRI GLYCalc 

software or other process simulation. These emissions were used directly to estimate total basinwide dehydration still vent VOC emissions according to Equation 16: 

Total basin-wide dehydration still vent emissions were estimated according to Equation 16: 

Equation (16) 

PCO

TOTAL

FieldDEHYTOTALDEHY P

P EE ,, 

where: 

EDEHY,TOTAL are the total VOC emissions basin-wide from all dehydrators [tons/year] 

EDEHY,Field are the VOC emissions basin-wide from all field dehydrators operated by 

companies participating in the survey [tons/year] 

PTOTAL is the total gas production in the basin in 2009 from conventional oil and gas wells 

[mscf] 

PPCO is the total gas production in the basin in 2009 by the participating companies from 

conventional oil and gas wells [mscf] 

A separate emissions estimate was made for NOx, CO and PM emissions from dehydrator 

reboilers. The limited data available on field dehydrators was used to determine the emissions 

from dehydrator reboilers operated by participating companies. This methodology is show in 

Equation 17: 

The basic methodology for estimating emissions for a single reboiler is shown in Equation 10: 

Equation (17) hct

HV QEFnE annual

local

reboilerreboilerreboiler 

1

where: 

Ereboiler is the emissions from reboilers operated by the participating companies [ton/yr] 

n is the number of reboilers operated by participating companies 
June 2013 

Final Report 20 

EFreboiler is the emission factor for a reboiler for a given pollutant [lb/million scf] 

Qreboiler is the reboiler MMBTU/hr rating [MMBTUrated/hr] 

HVlocal is the local natural gas heating value [BTUlocal/scf] 

tannual is the annual hours of operation [hr/yr] 

hc is a heater cycling fraction to account for the fraction of operating hours that the heater is 

firing (if available)

Extrapolation to Basin-Wide Emissions 

The total VOC emissions from all dehydrator still vents as described in Equation 16already 

represent basin-wide dehydration VOC emissions. For the NOx, CO and PM emissions from 

dehydrator reboilers, all emissions from participating companies were scaled by the proportional 

production ownership of the participating companies according to Equation 18: 

Equation (18) 

PCO

TOTAL

boilerTOTALboiler P

P EE Re,Re 

where: 

EReboiler,TOTAL are the total emissions basin-wide from dehydrator reboilers [tons/year] 

EReboiler are the dehydrator reboiler emissions from the participating companies [tons/year] 

PTOTAL is the total gas production in the basin in 2009 from conventional wells [mscf] 

PPCO is the total gas production in the basin in 2009 by the participating companies from 

conventional wells [mscf] 

County-level emissions from dehydration were estimated by allocating the total basin-wide 

dehydration emissions from conventional gas production into each county according to the 

fraction of conventional 2009 gas production occurring in that county. Tribal and non-tribal 

emissions from conventional gas production were estimated in each county by allocating the 

county dehydration emissions into tribal land according to the fraction of 2009 conventional well 

gas production occurring on tribal land in that county and into non-tribal land according to the 

fraction of total 2009 conventional well gas production not occurring on tribal land in that 

county. 

Drill Rigs – Drilling Operations 

Methodology 

The participating companies were surveyed for information on drilling rigs operating in 2009 in 

the Williston Basin. Because many drill rigs are operated by contractors to the oil and gas 

producers, data were not always available to the level of detail requested in the surveys. Some of 

the companies surveyed were able to provide exact configurations for all rigs used in their 

operations, while others were able to provide information on only one or several representative 

rigs. In all cases, complete information for every parameter needed to estimate drilling rig 

emissions was not available, and in these cases engineering analysis was used to fill in missing 

information. Because the nature of the survey responses for drilling rigs varied so much by 

company, the methodology used was to first estimate each company’s total drilling rig emissions 

given the nature of the data available for that company, and then to sum the emissions and scale 

up to the basin level. 
June 2013 

Final Report 21 

In general, the emissions for an individual rig engine were estimated according to Equation 19: 

Equation (19) 185,907 ,

drillingi

enginedrilling

tLFHPEF

E

   

where: 

Edrilling,engine is the emissions from one engine on the drilling rig for drilling one well 

[ton/engine/spud] 

EFi is the emissions factor for the engine for pollutant i [g/hp-hr] 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

tdrilling is the actual on-time of the engine for a typical drilling event in the basin [hr/spud] 

A single drilling rig may contain from 3 – 7 or more engines, including draw works, mud pump, 

and generator engines. The total emissions from drilling one well are thus the sum of emissions 

from each engine, according to Equation 20: 

Equation (20)  

i

EE ,, ienginedrillingdrilling

where: 

Edrilling is the total emissions from drilling one well [tons/spud] 

Edrilling,engine,i is the total emissions from engine i from drilling one well [tons/engine/spud] 

It should be noted that SO2 emissions were estimated using the brake-specific fuel consumption 

(BSFC) of the engine, as obtained from the US EPA’s NONROAD model (EPA, 2005) for a 

similarly sized drill/bore rig engine, and the 2006 sulfur content of the off-road diesel fuel (2,700 

ppm) as obtained from the WRAP Mobile Sources Emission Inventory Update (Pollack, et al., 

2006). The EPA NONROAD model guidance was used to determine the fraction of fuel sulfur 

that would go to forming PM emissions – for drilling rig engines this was only 2.2% of sulfur 

content. It was assumed that the remaining sulfur in the fuel would be emitted as SO2. 

Emissions factors were either provided by the survey respondent or were obtained from the US 

EPA’s NONROAD model (EPA, 2005). For emissions factors taken from the NONROAD 

model, in cases where it was not possible to ascertain the engine’s technology type, uncontrolled, 

undeteriorated drill/bore rig engines of the same size class were assumed. When a producer 

supplied emission factors for some, but not all pollutants, the technology type of the engine was 

estimated based on the supplied emission factors and emissions factors from the NONROAD 

model were taken for the estimated technology type for drill/bore rig engines of the same size 

class. This allowed the calculations to incorporate information about specific rig engines when it 

was available, and defaulted to the NONROAD model where this information was not available. 

Load factors were similarly estimated by using respondent information where such detailed 

information was available. 

The resulting rig configurations included engines of several Tier models, several different counts 

of number of engines per rig, and differing load factors for the different engines on a rig. 

 
June 2013 

Final Report 22 

Extrapolation to Basin-Wide Emissions 

Due to the variability in the type of information provided by the participating companies, it was 

decided to sum the drilling emissions for each company separately using the data and 

assumptions for that company, and then to sum all participating companies’ drilling emissions 

and scale this to the basin-wide drilling emissions. Participating companies’ drilling emissions 

were estimated using the emissions from drilling one well using that company’s representative 

rig or rigs, and then multiplying by the number of spuds drilled by that company in 2006. If 

more than one representative rig was provided, all spuds drilled by that company were divided 

evenly among the representative rigs. 

The basin-wide drilling emissions were derived by scaling up the combined participating 

companies’ drilling emissions according to Equation 21: 

Equation (21) S

S EE TOTAL

, drillingTOTALdrilling 

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 activity conducted by the participating 

companies (summed as described above) [tons/yr] 

STOTAL is the total number of spuds that occurred in the basin in 2009 

S is the total number of spuds in the basin in 2009 drilled by the participating companies 

County-level emissions were estimated by allocating the total basin-wide drilling rig emissions 

into each county according to the fraction of total 2009 spuds that occurred in each county. 

Tribal and non-tribal emissions were estimated in each county by allocating the county total 

emissions into tribal land according to the fraction of total 2009 spuds that occurred on tribal 

land in that county and into non-tribal land according to the fraction of total 2009 spuds that did 

not occur on tribal land in that county. 

Flaring 

Methodology 

Flaring emissions in the Williston Basin were developed differently than for other Phase III 

basins. Four categories of flaring emissions were considered explicitly: (1) oil tank flaring; (2) 

condensate tank flaring; (3) flaring of casinghead gas; and (4) all other flaring such as dehydrator 

controls, well blowdowns, and completions. 

The basic methodology for estimating flaring emissions was similar among all the flaring 

categories. The AP-42 methodology (EPA, 1995) was applied, combining flared volumes with 

the heat content of the gas being flared and the appropriate AP-42 emission factor to determine 

the NOx and CO emissions. This basic methodology following AP-42 methodology is shown 

below in Equation 22: 

Equation (22) flareiflare  HVQPEFE
June 2013 

Final Report 23 

where: 

Eflare is the basinwide flaring emissions [lb/yr] 

EFi is the emissions factor for pollutant i [lb/MMBtu] 

Q is the vent rate as supplied by participating companies [scf/bbl] 

HV is the heating value of the gas as estimated by participating companies [BTU/scf] 

Pflare is the production that is controlled by flare [bbl] 

The specific assumptions for each of the flaring categories are described below: 

Oil Tank Flaring

The vent rate of flash gas was obtained from the NDDOH “Bakken Pool Oil and Gas Production 

Facilities Air Pollution Control Permitting & Compliance Guidance” (NDDOH, 2011), which 

assumed a flash gas rate of 98 scf/bbl of oil produced. Survey data indicated that 12.7% of this 

production was flared in the North Dakota portion of the Williston Basin (including the Fort 

Peck Indian Reservation) and this was also assumed to apply to the South Dakota portion of the 

basin. In the Montana portion of the basin, permitting guidance requires that sites with 15 

ton/year potential-to-emit (PTE) be controlled with flares. An analysis was conducted to 

determine the fraction of the oil production from individual well sites that would exceed the 15 

ton/year PTE and it was assumed that any site exceeding this PTE would be controlled by flares. 

The analysis indicated 94% of the production would be controlled by flare in the Montana 

portion of the Williston Basin. 

Condensate Tank Flaring 

Insufficient survey data was obtained to derive a flashing rate for condensate tanks in the 

Williston Basin. Therefore a flashing rate was derived by averaging data from other basins. 

Insufficient data was obtained to determine the fraction of condensate production that is flared. 

For condensate tanks in the North Dakota and South Dakota portions of the Williston Basin, 

similar assumptions were used as for oil tanks. For condensate tanks in the Montana p[ortion of 

the Williston Basin a similar analysis was conducted as for oil tanks indicating 98% of the 

production would be controlled by flaring. 

Casinghead Gas Flaring

In the Williston Basin, flaring of casinghead gas that is not sold was estimated as a unique source 

category. Casinghead gas flaring was estimated as a source category for the Bakken formation 

only (including portions of the basin in Montana and North Dakota). Data from the North 

Dakota Industrial Commission Department of Mineral Resources was used to determine the 

fraction of 2009 produced gas in all formations in the Bakken pool that were not sold. It was 

assumed that all of the unsold casinghead gas was flared. 

Other Flaring 

Other flaring categories were evaluated using survey data supplied by participating companies 

and followed the same methodologies as used in other Phase III basins. 

 
June 2013 

Final Report 24 

Extrapolation to Basin-Wide Emissions 

Basin-wide flaring emissions for the “other flaring” category were estimated according to 

Equation 23: 

Equation (23) S

E S E flare TOTAL

TOTALflare 

2000 ,

where: 

Eflare,TOTAL is the total flaring emissions in the basin [ton/yr] 

Eflare is the flaring emissions for all participating companies [lb/yr] 

S is the participating company ownership of the surrogate appropriate for each flaring source 

STOTAL is the total surrogate ownership in the basin owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide flaring emissions into 

each county according to the fraction of total surrogate (oil production, gas production, and 

spuds) that are located in each county. Tribal and non-tribal emissions were estimated in each 

county by allocating the county total emissions into tribal land according to the fraction of the 

surrogate that occurred on tribal land in that county and into non-tribal land according to the 

fraction of the surrogate that did not occur on tribal land in that county. 

Fugitive Emissions (Leaks) 

Methodology 

Fugitive emissions from well sites were estimated using AP-42 emissions factors (EPA, 1995) 

and equipment counts provided in the survey responses. The participating companies provided 

total equipment counts for all of their operations in the basin by type of equipment and by the 

type of service to which the equipment applies – gas, light liquid, heavy liquid, or water. 

Equipment counts were identified by the type of well including conventional oil wells, and 

conventional gas wells. As noted above, due to the minimal CBM gas production in the 

Williston Basin, CBM fugitive emissions were not estimated. 

Fugitive VOC emissions for an individual component were estimated similar to blowdown or 

completion emissions, according to Equation 24: 

Equation (24) C1

1 YtNEFE  annualifugitive

where: 

Efugitive is the fugitive VOC emissions for all participating companies [ton-VOC/yr] 

EFi is the emission factor of TOC [kg/hr/source] 

N is the total number of devices from the participating companies 

Y is the ratio of VOC to TOC in the vented gas 

C1 is 907.185 kg/ton

The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 
June 2013 

Final Report 25 

Extrapolation to Basin-Wide Emissions 

Basin-wide fugitive emissions are estimated by scaling the fugitive emissions from all 

participating companies by the ratio of the total number of conventional wells in the basin to the 

number of conventional wells owned by the participating companies, according to Equation 25: 

Equation (25) 

PCO

fugitive TOTAL

TOTALfugitive W

W

C

E

E 

2

 ,

where: 

Efugitive,TOTAL is the total fugitive emissions from conventional wells in the basin [ton/yr] 

Efugitive is the fugitive VOC emissions for all participating companies from conventional 

wells [lb-VOC/yr] 

WTOTAL is the total number of conventional gas and oil wells in the basin 

WPCO is the total number of conventional gas and oil wells in the basin owned by the 

participating companies 

C2 is 2000 lb/ton

County-level emissions from conventional wells were estimated by allocating the total basinwide fugitive emissions from conventional wells into each county according to the fraction of 

conventional 2009 well count occurring in that county. Tribal and non-tribal emissions from 

conventional wells were estimated in each county by allocating the county conventional well 

fugitive emissions into tribal land according to the fraction of 2009 conventional well count 

occurring on tribal land in that county and into non-tribal land according to the fraction of total 

2009 conventional well count not occurring on tribal land in that county. 

Gas Plant and NGL Plant Truck Loading 

Insufficient data was gathered to estimate emissions for this source category. It is possible that 

some truck loading of hydrocarbon liquids occurs at large gas processing facilities and their 

vented emissions would be counted with the facility total VOC emissions for purposes of the 

inventory. 

Heaters 

Methodology 

This source category refers to separator and/or tank heaters located at well sites. As described 

above, emissions from reboilers associated with dehydrators were treated separately in the 

methodology for those emissions. Heater emissions were 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 was calculated from the BTU rating of the heater and the local BTU content of the gas. 

Participating companies’ surveys indicated that the majority of heaters were natural-gas fired, 

but in some instances propane was indicated as the gas combusted. AP-42 emission factors for 

an uncontrolled small boiler for natural gas fuel were used for specific pollutants (EPA, 1995). 

Note that heaters were not assumed to be operated continuously and data on the annual hours of 

operation and the cycling fraction of the heaters were requested in the surveys. 
June 2013 

Final Report 26 

The basic methodology for estimating emissions for a single heater is shown in Equation 26: 

Equation (26) annualheaterheaterheater  hctQEFE HV

1

local

where: 

Eheater is the emissions from a given heater [lb/yr/heater] 

EFheater is the emission factor for a heater for a given pollutant [lb/million scf] 

Qheater is the heater MMBTU/hr rating [MMBTUrated/hr] 

HVlocal is the local natural gas heating value [BTUlocal/scf] 

tannual is the annual hours of operation [hr/yr] 

hc is a heater cycling fraction to account for the fraction of operating hours that the heater is 

firing (if available)

Emissions for all heaters in the basin operated by the participating companies were estimated 

according to Equation 27: 

Equation (27)   n

NEE ,,, nheaternheatercompaniesheater

where: 

Eheater,companies is the total emissions from all heaters operated by participating companies 

[lb/yr] 

Eheater,n is the emissions from a single heater (of type n) [lb/yr/heater] 

Nheater,n is the total number of heaters (of type n) owned by the participating companies 

The participating companies were requested to provide seasonal utilization rates to account for 

changes in usage throughout the year. 

Extrapolation to Basin-Wide Emissions 

Basin-wide heater emissions were estimated according to Equation 28: 

Equation (28) W

E W E companiesheater TOTAL

TOTALheater 

2000

,

,

where: 

Eheater,TOTAL is the total heater emissions in the basin [ton/yr] 

Eheater,companies is the total emissions from all heaters operated by participating companies 

[lb/yr] 

WTOTAL is the total number of wells in the basin 

W is the total number of wells in the basin owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide heater emissions into 

each county according to the fraction of 2009 total well counts that are located in each county. 

Tribal and non-tribal emissions from conventional wells were estimated in each county by 

allocating the county conventional well heater emissions into tribal land according to the fraction 

of 2009 conventional well count occurring on tribal land in that county and into non-tribal land 

according to the fraction of total 2009 conventional well count not occurring on tribal land in that 

county. 
June 2013 

Final Report 27 

Oil and Gas Well Truck Loading 

Methodology 

Based on surveyed producer responses, oil and gas well truck loading emissions were estimated 

based on loading losses per EPA AP-42, Section 5.2 methodology combined with IHS database 

statistics on the total produced oil and condensate volumes basin-wide (EPA, 1995). The loading 

loss rate was estimated based on EPA AP-42, Section 5.2 methodology, following Equation 29: 

Equation (29) 



 



 



T

MVS L 46.12

where: 

L is the loading loss rate [lb/1000gal] 

S is the saturation factor taken from AP-42 default values based on operating mode 

V is the true vapor pressure of liquid loaded [psia] 

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

T is the temperature of the bulk liquid [o

R] 

Total truck loading emissions were then estimated by combining, separately for oil well and gas 

well truck loading, the calculated loading loss rate with the annual total volume of oil and 

condensate produced basin-wide as shown in Equation 30: 

Equation (30) 1000

42

loading PLE 

where: 

E is the oil well or gas well truck loading emissions [lb/yr] 

L is the oil well or gas well loading loss rate [lb/1000gal] 

P is the oil well or gas well hydrocarbon liquid produced [bbl] 

Extrapolation to Basin-Wide Emissions 

It was assumed that all oil and condensate production in the Williston Basin would be truck 

loaded (i.e. that there would be no direct-to-pipeline gathering systems or LGS). Therefore the 

basic emission estimation methodology described in Equations 29 and 30 above already accounts 

for total basin-wide emissions from truck loading losses. 

 

County-level emissions were estimated by allocating the total basin-wide truck loading 

emissions into each county according to the fraction of oil or condensate production for each 

county. Tribal and non-tribal emissions were estimated in each county by allocating the county 

total emissions into tribal land according to the fraction of total 2009 oil or condensate 

production on tribal land in that county and into non-tribal land according to the fraction of total 

2009 oil or condensate production not on tribal land in that county. 

Pneumatic Control Devices 

Methodology 

Pneumatic device emissions were estimated by determining the numbers and types of pneumatic 

devices used at all wells in the basin owned by the participating companies. The bleed rates of 
June 2013 

Final Report 28 

these devices per unit of gas produced were determined by using guidance from the EPA’s 

Natural Gas Star Program (EPA, 2008). 

The methodology for estimating the emissions from all pneumatic devices owned by 

participating companies is shown in Equations 31-32: 

Equation (31) annualiiTOTALvented ,   tNVV

where: 

Vvented,TOTAL is the total volume of vented gas from all pneumatic devices for all participating 

companies [mscf/year] 

Vi

 is the volumetric bleed rate from device i [mscf/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 [hr/yr]

Equation (32) ,  YRMW1000VE VOCVOCTOTALventedpneumatic

where: 

Epneumatic is the total conventional well pneumatic device VOC emissions [lb-VOC/yr] 

MWVOC,CONV is the molecular weight of the VOC for conventional well vented gas [lb/lbmol] 

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

Y VOC,CONV is the volume fraction of VOC in the conventional well vented gas 

The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions 

Basin-wide pneumatic device emissions were estimated according to Equation 33: 

Equation (33) 

CONVPCO

pneumatic CONVTOTAL

TOTALpneumatic W

E W

E

,

,

, 2000



where: 

Epneumatic,TOTAL is the total pneumatic device emissions in the basin from gas wells [ton/yr] 

Epneumatic is the pneumatic device VOC emissions for all participating companies’ gas wells 

[lb-VOC/yr] 

WTOTAL,CONV is the total number of conventional wells in the basin 

WPCO,CONV is the total number of conventional wells in the basin owned by the participating 

companies 

County-level emissions from gas wells were estimated by allocating the total basin-wide 

pneumatic emissions from conventional wells into each county according to the fraction of 

conventional 2009 well count occurring in that county. Tribal and non-tribal emissions from 

conventional wells were estimated in each county by allocating the county conventional well 

pneumatic emissions into tribal land according to the fraction of 2009 conventional well count 
June 2013 

Final Report 29 

occurring on tribal land in that county and into non-tribal land according to the fraction of total 

2009 conventional well count not occurring on tribal land in that county. 

Pneumatic (Gas Actuated) Pumps 

Methodology 

Participating companies provided data indicating either the average gas consumption rate per 

gallon of chemical or compound pumped, or the volume rate of gas consumption per day per 

pump. 

The gas consumption rate per gallon of chemical pumped was multiplied by the total volume of 

chemical pumped by the survey respondent in the basin in 2009 to derive total gas consumption 

from gas-actuated pumps for the survey respondent. If the respondent company did not specify 

the total gas consumption rate or did not specify the total volume of chemical pumped, then the 

average gas consumption rate or average total volume of chemical pumped from other 

participating companies was used. 

VOC emissions from pneumatic pumps were estimated similarly to pneumatic devices, following 

Equation 34: 

Equation (34)  YRMW1000VE ,,, CONVVOCCONVVOCTOTALventedpump

where: 

Epump is the gas-actuated pump VOC emissions for all participating companies 

[lb-VOC/yr] 

Vvented,TOTAL is the total volume of vented gas from all gas-actuated pumps for all 

participating companies [mscf/year] 

MWVOC,CONV is the molecular weight of the VOC for conventional well vented gas [lb/lbmol] 

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

YVOC,CONV is the volume fraction of VOC in the conventional well vented gas 

The participating companies were requested to provide seasonal utilization rates to account for 

changes in usage throughout the year. 

Extrapolation to Basin-Wide Emissions 

Basin-wide gas-actuated pump emissions were estimated according to Equation 35: 

Equation (35) 

CONVPCO

pump CONVTOTAL

TOTALpump W

E W

E

,

,

, 2000



where: 

Epump,TOTAL is the total pneumatic pump emissions in the basin [ton/yr] 

Epump is the gas-actuated pump VOC emissions for all participating companies 

[lb-VOC/yr] 

WTOTAL,CONV is the total number of conventional wells in the basin 
June 2013 

Final Report 30 

WPCO,CONV is the total number of conventional wells in the basin owned by the participating 

companies 

County-level emissions were estimated by allocating the total basin-wide gas-actuated pump 

emissions into each county according to the fraction of total 2009 conventional well counts that 

are located in each county. Tribal and non-tribal emissions from conventional wells were 

estimated in each county by allocating the county conventional well pneumatic emissions into 

tribal land according to the fraction of 2009 conventional well count occurring on tribal land in 

that county and into non-tribal land according to the fraction of total 2009 conventional well 

count not occurring on tribal land in that county. 

Condensate and Oil Tanks 

Methodology 

Flashing emission factors for oil tanks in the Williston Basin were derived from the NDDOH 

guidance described above (NDDOH, 2011) by combining the flashing rate with the VOC content 

of the flash gas. Flashing emissions factors for condensate tanks in the Williston Basin were 

derived as averages of other basin data as described above by combining the flashing rate with 

the VOC content of the flash gas. 

The basin-wide emissions from condensate and oil tanks are the summation of emissions in each 

county for condensate and oil tanks respectively. For each county, condensate and oil tank 

emissions were derived from developed production-based emission factors and IHS estimated oil 

production from oil wells for oil tanks and condensate production from gas wells for condensate 

tanks. Oil and gas wells were identified based on IHS database well designation as either an oil 

or gas well. The fraction of condensate tank throughput controlled by flare was described above 

under the flaring source category. County-level oil and condensate emissions were estimated as 

per Equations 36 and 37

Equation (36) FC

EFP

CFFC

EFP

E flashingoiloilflashingoiloil

countyksoil * 2000 )1(** 2000 tan





   

and 

Equation (37) FC

EFP

CFFC

EFP

E flashingcondcondflashingcondcond

countykscondensate * 2000 )1(** 2000 tan





   

where: 

Eoiltanks-county is the county-level emissions from oil tanks [tons/yr] 

Econdensate,tanks-county is the county-level emissions from condensate tanks [tons/yr] 

EFoil-flashing is the derived flashing VOC emissions factor for oil tanks [lb-VOC/bbl] 

EFcond-flashing is the derived flashing VOC emissions factor for condensate tanks [lbVOC/bbl] 

Poil is the oil production from oil wells [bbl] 

Pcond is the condensate production from gas wells [bbl] 

FC is the fraction of production controlled [%] 

CF is the Control Factor [%] 

 
June 2013 

Final Report 31 

Extrapolation to Basin-Wide Emissions 

Emissions were estimated for basin-wide flashing and working and breathing emissions from 

condensate and oil tanks according to Equations 38 and 39: 

Equation (38)     i EE tan,tan countyksoilksoil

and 

Equation (39)     i EE tan,tan countykscondensatekscondensate

where: 

Eoiltanks is the basin-wide emissions from oil tanks [tons/yr] 

Econdensate,tanks is the basin-wide emissions from condensate tanks [tons/yr] 

Eoiltanks-county is the VOC emissions for oil tanks for each county [tons /yr] 

EFcondensate,tank is the VOC emissions for condensate tanks for each county [tons/yr] 

i is the county in the basin 

Tribal and non-tribal emissions from condensate and oil tanks were estimated in each county by 

allocating the county condensate and oil tank emissions into tribal land according to the fraction 

of 2009 condensate or oil production occurring on tribal land in that county and into non-tribal 

land according to the fraction of total 2009 condensate or oil production not occurring on tribal 

land in that county. 

Workover Rigs 

Methodology: 

The nature of workover engine data provided in the survey responses for workover rigs varied 

significantly by company. In order to utilize the wide range of data provided, the methodology 

used was to first estimate each company’s total workover rig emissions, and then to sum the 

emissions over all companies, and scale up to the basin level (similar to the approach used for 

drilling rigs). When a producer supplied emission factors for some, but not all pollutants, the 

technology type of the engine was estimated based on the supplied emission factors and emission 

factors from the NONROAD model which were taken for the estimated technology type for 

drill/bore rig engines of the same size class. This allowed the calculations to incorporate 

information about specific rig engines when it was available, and defaulted to the NONROAD 

model where this information was not available. Load factors were similarly estimated by using 

respondent information where such detailed information was available. 

The basic methodology for estimating the emissions from a workover rig follows Equation 40: 

Equation (40) 185,907 ,

workoveri

engineworkover

tLFHPEF E 

where: 

Eworkover,engine is the emissions from one workover [ton/workover] 
June 2013 

Final Report 32 

EFi is the emissions factor of the workover rig engine of pollutant i [g/hp-hr] 

HP is the horsepower of the workover rig engine [hp] 

LF is the average load factor of the workover rig engine 

tworkover is the average duration of a workover event [hr/workover] 

It should be noted that SO2 emissions were estimated using the brake-specific fuel consumption 

(BSFC) of the engine, as obtained from the US EPA’s NONROAD model (EPA, 2005) for a 

similarly sized drill/bore rig engine, and the 2006 sulfur content of the off-road diesel fuel (2,700 

ppm) as obtained from the WRAP Mobile Sources Emission Inventory Update (Pollack, et al., 

2006). The EPA NONROAD model guidance was used to determine the fraction of fuel sulfur 

that would go to forming PM emissions – for drilling rig engines this was only 2.2% of sulfur 

content. It was assumed that the remaining sulfur in the fuel would be emitted as SO2. 

Extrapolation to Basin-Wide Emissions 

The total workover rig emissions for the participating companies were derived by multiplying 

the per-workover emissions above for each pollutant by the total number of workovers 

conducted by the participating companies. This was then scaled up by the ratio of total well 

count in the basin to wells owned by the participating companies, following Equation 41: 

Equation (41) W

W EE TOTAL , workoverTOTALworkover 

where: 

Eworkover,TOTAL are the total emissions basin-wide from workovers [tons/year] 

Eworkover are the total workover rig emissions from the participating companies [tons/year] 

WTOTAL is the total number of wells in the basin 

W is the number of wells owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide workover rig emissions 

into each county according to the fraction of total 2009 well counts that are located in each 

county. Tribal and non-tribal emissions were estimated in each county by allocating the county 

total emissions into tribal land according to the fraction of total 2009 well counts on tribal land in 

that county and into non-tribal land according to the fraction of total 2009 well counts not on 

tribal land in that county. 

SUMMARY RESULTS 

Results from the combined permitted sources and the combined surveyed sources are presented 

below for the entire Williston Basin as a series of pie charts and bar graphs including countylevel emissions, basin-wide emissions and emissions on tribal and non-tribal land. The 

quantitative emissions summaries are presented at the end of this document in Tables 4 through 

7. It should be noted that all figures showing county-level emissions only include those counties 

representing 1% or greater of the total emissions in the basin. 

Figure 2 shows NOx emissions by county and source category in the Williston Basin. Figure 2 

shows that NOx emissions are concentrated in Mountrail, Williams, McKenzie and Dunn 

Counties in North Dakota, and to a lesser extent in Fallon and Richland Counties in Montana. 

These counties represent the core Bakken formation area, with the exception of Fallon County in 
June 2013 

Final Report 33 

the Cedar Creek Anticline. Figure 3 shows NOx emissions by tribal and non-tribal land in the 

Williston Basin. Tribal emissions are primarily concentrated in Mountrail County North Dakota 

in the Fort Berthold Indian Reservation. 

Figure 4 shows that VOC emissions are also concentrated in Mountrail, McKenzie and Dunn 

Counties in the core of the Bakken area, but with significant VOC emissions in Bowman County 

in the Cedar Creek Anticline as well. As shown in Figure 5, tribal VOC emissions are also 

concentrated in Mountrail County in North Dakota in the Fort Berthold Indian Reservation. 

Figure 6 shows that compressor engines, drilling rigs and artificial lift engines are the largest 

source categories of NOx emissions in the Williston Basin, accounting for approximately 80% of 

NOx emissions in 2009. Figure 7 shows that VOC emissions from oil tank flashing are the 

largest contributor to basin-wide VOC emissions, accounting for approximately 63% of the 

basin-wide VOC emissions in the Williston Basin in 2009. Condensate tank flashing and 

venting of casinghead gas represent an additional 15% of basin-wide VOC emissions in the 

Williston Basin in 2009. 

 
June 2013 

Final Report 34 

Figure 2. 2009 NOx emissions by source category and by county in the Williston Basin. 

Figure 3. 2009 NOx emissions by tribal and non-tribal land in the Williston Basin. 

0

500

1000

1500

2000

2500

3000

NOx Emissions (tons/year)

County

Other Categories

Casinghead Gas Venting and Flaring

Oil tank flaring

Oil Well Truck Loading

Oil Tank

Condensate tank

Artificial Lift

Miscellaneous engines

Unpermitted Fugitives

Heaters

Venting - recompletions

Pneumatic pumps

Pneumatic devices

Drill rigs

Compressor engines

0

500

1000

1500

2000

2500

3000

NOx Emissions (tons/year)

County

Non-Tribal

Tribal
June 2013 

Final Report 35 

Figure 4. 2009 VOC emissions by source category and by county in the Williston Basin.

Figure 5. 2009 VOC emissions by tribal and non-tribal area in the Williston Basin. 

0

20000

40000

60000

80000

100000

120000 VOC Emissions (tons/yr)

County

Other Categories

Casinghead Gas Venting and Flaring

Condensate tank flaring

Oil Well Truck Loading

Oil Tank

Condensate tank

Artificial Lift

Miscellaneous engines

Unpermitted Fugitives

Heaters

Venting - recompletions

Pneumatic pumps

Pneumatic devices

Drill rigs

Compressor engines

0

20000

40000

60000

80000

100000

120000

VOC Emissions (tons/yr)

County

Non-Tribal

Tribal
June 2013 

Final Report 36 

Figure 6. Williston Basin NOx emissions proportional contributions by source category.

Figure 7. Williston Basin VOC emissions proportional contributions by source category. 

Compressor engines

34%

Drill rigs

35%

Heaters

5%

Miscellaneous engines

4%

Artificial Lift

11%

Oil tank flaring

2%

Casinghead Gas 

Venting and Flaring

6%

Other Categories

3%

Pneumatic devices

7% Pneumatic pumps

8%

Venting -

recompletions

1%

Unpermitted Fugitives

2%

Condensate tank 

7%

Oil Tank

63%

Oil Well Truck Loading

2%

Casinghead Gas 

Venting and Flaring

8%

Other Categories

2%
June 2013 

Final Report 37 

Table 4. 2009 emissions of all criteria pollutants by county for the Williston Basin. 

County 

NOx

[tons/yr] 

VOC

[tons/yr] 

CO

[tons/yr] 

SOx

[tons/yr] 

PM

[tons/yr] 

Carter (MT) 5 157 4 0 0 

Custer (MT) 19 23 4 0 1 

Daniels (MT) 1 39 1 0 0 

Dawson (MT) 59 704 63 0 5 

Fallon (MT) 1,111 14,198 1,543 15 69 

Garfield (MT) 2 98 2 0 0 

McCone (MT) 35 66 19 0 1 

Prairie (MT) 4 130 4 0 0 

Richland (MT) 1,149 19,516 1,987 5 64 

Roosevelt (MT) 341 3,192 363 33 28 

Sheridan (MT) 124 2,740 200 0 10 

Valley (MT) 487 1,821 459 9 25 

Wibaux (MT) 39 1,214 41 0 2 

Barnes (ND) 92 2 7 3 6 

Billings (ND) 473 16,139 694 356 16 

Bottineau (ND) 383 10,601 485 1 44 

Bowman (ND) 733 48,743 970 1 36 

Burke (ND) 285 7,474 366 56 26 

Burleigh (ND) 18 5 17 0 0 

Divide (ND) 268 6,395 365 1 30 

Dunn (ND) 1,381 32,895 1,931 7 155 

Golden Valley (ND) 51 2,247 84 0 4 

McHenry (ND) 107 236 9 3 6 

McIntosh (ND) 39 5 39 2 3 

McKenzie (ND) 1,727 43,336 2,132 456 105 

McLean (ND) 69 518 78 0 9 

Mercer (ND) 21 17 22 0 3 

Morton (ND) 113 23 130 6 6 

Mountrail (ND) 2,795 102,447 4,643 7 271 

Renville (ND) 104 4,859 140 0 9 

Slope (ND) 46 2,249 58 0 4 

Stark (ND) 151 4,438 160 0 3 

Stutsman (ND) 8 3 12 0 0 

Ward (ND) 46 339 51 0 6 

Williams (ND) 1,830 24,439 1,356 1,118 75 

Butte (SD) 28 4 29 0 4 

Harding (SD) 241 6,488 298 1 18 

TOTAL 14,387 357,798 18,765 2,081 1,045 

Daniels, (MT) (Tribal) 0 31 1 0 0 

Roosevelt, (MT) (Tribal) 99 1,585 153 26 13 

Sheridan, (MT) (Tribal) 0 41 1 0 0 

Valley, MT (Tribal) 17 674 21 0 2 

Dunn, ND (Tribal) 222 2,638 272 1 29 
June 2013 

Final Report 38 

County 

NOx

[tons/yr] 

VOC

[tons/yr] 

CO

[tons/yr] 

SOx

[tons/yr] 

PM

[tons/yr] 

McKenzie, ND (Tribal) 38 637 47 0 4 

McLean, ND (Tribal) 69 518 78 0 9 

Mountrail, ND (Tribal) 668 18,678 1,008 2 75 

TOTAL (Tribal) 1,114 24,802 1,581 29 132 

Daniels, (MT) 

(Non-Tribal) 0 8 0 0 0 

Roosevelt, (MT) 

(Non-Tribal) 242 1,606 210 7 15 

Sheridan, (MT) 

(Non-Tribal) 124 2,699 199 0 10 

Valley, MT 

(Non-Tribal) 470 1,147 438 9 24 

Dunn, ND 

(Non-Tribal) 1,159 30,257 1,658 6 126 

McKenzie, ND 

(Non-Tribal) 1,689 42,699 2,085 456 100 

McLean, ND 

(Non-Tribal) 0 0 0 0 0 

Mountrail, ND 

(Non-Tribal) 2,127 83,768 3,636 5 196 
June 2013 

Final Report 39

Table 5. 2009 NOx emissions [ton/yr] by source category for the Williston Basin.

County 

Compressor 

Engines 

Drill 

Rigs Heaters 

Miscellaneous 

Engines 

Artificial Lift 

Engines 

Oil Tank 

Flaring 

Casinghead 

Gas Flaring 

Other 

Categories Totals 

Carter (MT) 0 0 1 1 1 0 0 0 5

Custer (MT) 19 0 0 0 0 0 0 0 19

Daniels (MT) 0 0 0 0 0 0 0 0 1

Dawson (MT) 17 21 5 4 6 3 0 2 59

Fallon (MT) 472 215 113 96 96 45 0 75 1,111

Garfield (MT) 0 0 1 1 0 0 0 0 2

McCone (MT) 34 0 0 0 0 0 0 0 35

Prairie (MT) 0 0 1 1 1 1 0 0 4

Richland (MT) 306 111 75 64 239 111 171 72 1,149

Roosevelt (MT) 221 49 14 12 20 7 14 3 341

Sheridan (MT) 6 35 17 14 22 10 16 4 124

Valley (MT) 384 69 14 12 2 0 1 4 487

Wibaux (MT) 4 0 10 8 11 5 0 2 39

Barnes (ND) 92 0 0 0 0 0 0 0 92

Billings (ND) 233 14 37 31 61 4 44 49 473

Bottineau (ND) 1 243 42 36 30 2 21 9 383

Bowman (ND) 320 104 44 38 188 12 0 27 733

Burke (ND) 42 132 30 26 21 1 15 17 285

Burleigh (ND) 18 0 0 0 0 0 0 0 18

Divide (ND) 15 188 11 10 23 1 17 3 268

Dunn (ND) 115 959 31 26 137 9 98 7 1,381

Golden Valley (ND) 4 21 5 4 9 1 6 1 51

McHenry (ND) 103 0 1 1 1 0 0 0 107

McIntosh (ND) 39 0 0 0 0 0 0 0 39

McKenzie (ND) 740 535 70 59 141 9 100 73 1,727

McLean (ND) 0 63 1 1 2 0 1 0 69

Mercer (ND) 0 21 0 0 0 0 0 0 21

Morton (ND) 113 0 0 0 0 0 0 0 113

Mountrail (ND) 209 1,660 41 35 468 29 334 20 2,795

Renville (ND) 0 35 23 20 12 1 8 5 104

Slope (ND) 14 21 2 1 6 0 0 1 46
June 2013 

Final Report 40

County 

Compressor 

Engines 

Drill 

Rigs Heaters 

Miscellaneous 

Engines 

Artificial Lift 

Engines 

Oil Tank 

Flaring 

Casinghead 

Gas Flaring 

Other 

Categories Totals 

Stark (ND) 99 7 6 5 19 1 14 1 151

Stutsman (ND) 8 0 0 0 0 0 0 0 8

Ward (ND) 0 42 1 1 1 0 1 0 46

Williams (ND) 1,235 313 38 32 78 5 56 74 1,830

Butte (SD) 0 28 0 0 0 0 0 0 28

Harding (SD) 88 90 17 14 26 2 0 4 241

TOTAL 4,953 4,974 654 554 1,620 258 918 456 14,387

Daniels, (MT) (Tribal) 0 0 0 0 0 0 0 0 0

Roosevelt, (MT) (Tribal) 65 14 5 5 5 0 4 1 99

Sheridan, (MT) (Tribal) 0 0 0 0 0 0 0 0 0

Valley, MT (Tribal) 0 7 3 3 2 0 1 1 17

Dunn, ND (Tribal) 4 195 2 2 11 1 8 0 222

McKenzie, ND (Tribal) 3 28 2 1 2 0 2 0 38

McLean, ND (Tribal) 0 63 1 1 2 0 1 0 69

Mountrail, ND (Tribal) 18 479 9 8 85 5 61 2 668

TOTAL (Tribal) 90 785 23 19 108 7 77 5 1,114

Daniels, (MT) 

(Non-Tribal) 0 0 0 0 0 0 0 0 0

Roosevelt, (MT) 

(Non-Tribal) 156 35 9 8 14 7 10 2 242

Sheridan, (MT) 

(Non-Tribal) 6 35 17 14 22 10 16 4 124

Valley, MT 

(Non-Tribal) 384 63 11 9 0 0 0 3 470

Dunn, ND 

(Non-Tribal) 111 764 29 25 125 8 90 7 1,159

McKenzie, ND 

(Non-Tribal) 737 507 68 58 139 9 99 73 1,689

McLean, ND 

(Non-Tribal) 0 0 0 0 0 0 0 0 0

Mountrail, ND 

(Non-Tribal) 191 1,181 32 27 382 24 273 18 2,127
June 2013 

Final Report 41

Table 6. 2009 VOC emissions [ton/yr] by source category for the Williston Basin.

County 

Pneumatic 

Devices 

Pneumatic 

Pumps 

Recompletion 

Venting Fugitives 

Condensate 

Tanks Oil Tanks 

Oil Well 

Truck 

Loading 

Casinghead 

Gas Venting 

Other 

Categories Totals 

Carter (MT) 56 59 4 17 0 17 3 0 1 157 

Custer (MT) 9 10 1 3 0 0 0 0 0 23 

Daniels (MT) 9 10 1 3 0 14 0 2 0 39 

Dawson (MT) 198 211 13 62 1 134 28 0 56 704 

Fallon (MT) 4,354 4,629 293 1,352 7 2,109 440 0 1,015 14,198 

Garfield (MT) 37 40 3 12 0 5 1 0 0 98 

McCone (MT) 15 16 1 5 0 2 0 2 23 66 

Prairie (MT) 40 43 3 13 0 26 5 0 1 130 

Richland (MT) 2,910 3,095 196 903 12 5,238 1,092 5,062 1,008 19,516 

Roosevelt (MT) 558 594 38 173 0 1,235 90 415 90 3,192 

Sheridan (MT) 657 699 44 204 4 513 102 471 46 2,740 

Valley (MT) 552 587 37 171 0 308 8 37 122 1,821 

Wibaux (MT) 375 399 25 116 0 238 50 0 10 1,214 

Barnes (ND) 0 0 0 0 0 0 0 0 2 2 

Billings (ND) 1,419 1,511 96 441 70 10,907 280 1,297 118 16,139 

Bottineau (ND) 1,621 1,726 109 503 313 5,343 137 635 214 10,601 

Bowman (ND) 1,717 1,828 116 533 9,836 33,350 856 0 508 48,743 

Burke (ND) 1,162 1,237 78 361 161 3,793 97 451 133 7,474 

Burleigh (ND) 0 0 0 0 0 0 0 0 5 5 

Divide (ND) 443 472 30 138 465 4,155 107 494 91 6,395 

Dunn (ND) 1,193 1,270 80 370 1,383 24,339 624 2,894 739 32,895 

Golden Valley (ND) 195 208 13 61 0 1,534 39 182 14 2,247 

McHenry (ND) 53 56 4 16 0 92 2 11 3 236 

McIntosh (ND) 0 0 0 0 0 0 0 0 5 5 

McKenzie (ND) 2,690 2,864 181 835 7,098 25,025 642 2,976 1,024 43,336 

McLean (ND) 53 56 4 16 0 330 8 39 12 518 

Mercer (ND) 3 3 0 1 0 6 0 1 3 17 

Morton (ND) 0 0 0 0 0 0 0 0 23 23 

Mountrail (ND) 1,580 1,683 106 491 1,661 83,142 2,133 9,887 1,764 102,447 

Renville (ND) 902 960 61 280 215 2,107 54 251 29 4,859 
June 2013 

Final Report 42

County 

Pneumatic 

Devices 

Pneumatic 

Pumps 

Recompletion 

Venting Fugitives 

Condensate 

Tanks Oil Tanks 

Oil Well 

Truck 

Loading 

Casinghead 

Gas Venting 

Other 

Categories Totals 

Slope (ND) 65 69 4 20 974 1,060 27 0 28 2,249 

Stark (ND) 220 234 15 68 0 3,382 87 402 30 4,438 

Stutsman (ND) 0 0 0 0 0 0 0 0 3 3 

Ward (ND) 50 53 3 15 0 170 4 20 23 339 

Williams (ND) 1,447 1,541 97 449 4,411 13,919 357 1,655 561 24,439 

Butte (SD) 0 0 0 0 0 0 0 0 4 4 

Harding (SD) 654 696 44 203 80 4,543 117 0 152 6,488 

TOTAL 25,237 26,861 1,700 7,836 26,692 227,035 7,392 27,184 7,861 357,798 

Daniels, (MT) (Tribal) 6 7 0 2 0 14 0 2 0 31 

Roosevelt, (MT) 

(Tribal) 208 221 14 64 0 919 24 109 27 1,585 

Sheridan, (MT) (Tribal) 3 3 0 1 0 29 1 3 0 41 

Valley, MT (Tribal) 130 139 9 40 0 308 8 37 4 674 

Dunn, ND (Tribal) 74 79 5 23 0 2,032 52 242 130 2,638 

McKenzie, ND (Tribal) 65 69 4 20 0 384 10 46 38 637 

McLean, ND (Tribal) 53 56 4 16 0 330 8 39 12 518 

Mountrail, ND (Tribal) 347 370 23 108 0 15,203 390 1,808 430 18,678 

TOTAL (Tribal) 886 944 60 275 0 19,219 493 2,285 640 24,802 

Daniels, (MT) 

(Non-Tribal) 3 3 0 1 0 0 0 0 0 8 

Roosevelt, (MT) 

(Non-Tribal) 350 373 24 109 0 316 66 306 63 1,606 

Sheridan, (MT) 

(Non-Tribal) 654 696 44 203 4 484 101 468 46 2,699 

Valley, MT 

(Non-Tribal) 421 449 28 131 0 0 0 0 118 1,147 

Dunn, ND 

(Non-Tribal) 1,119 1,191 75 347 1,383 22,307 572 2,653 609 30,257 

McKenzie, ND 

(Non-Tribal) 2,625 2,795 177 815 7,098 24,641 632 2,930 986 42,699 

McLean, ND 

(Non-Tribal) 0 0 0 0 0 0 0 0 0 0 

Mountrail, ND 

(Non-Tribal) 1,233 1,313 83 383 1,661 67,938 1,743 8,079 1,334 83,768 
June 2013 

Final Report 43

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