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, 2013June 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 ......................................................................................................................... 43June 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. .............................................................................................................. 36June 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 wellsJune 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 16June 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 roundingJune 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 716June 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 productionJune 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 otherJune 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 0June 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 Production [bbl]**  **Condensate Oil**  **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 3,569,125June 2013

Final Report 7 **County Oil**  **/Condensate Production**  **[bbl] Gas Production**  **[mcf]**
**Water Production [bbl]**  **Condensate Oil**  **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) 1June 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) 170June 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 gasproduction 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:
E engine are emissions from an artificial lift engine [ton/year/engine]
EF i is the emissions factor of pollutant i [g/hp-hr]
HP is the horsepower of the engine [hp]
LF is the load factor of the engine

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

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 SO 2 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 SO 2 . For natural gasfired engines, it is assumed that sour gas containing H 2 S would not be used for direct combustion in engines; therefore SO 2 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:
E engine,TOTAL is the total emissions from artificial lift engines in the basin [ton/yr]
E engine is the total emissions from artificial engines owned by the participating companies [ton/yr]
P TOTAL 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) TOTALventedvented VfV

, 

where:
V

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

is the frequency of blowdowns [events/year]
V

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

Equation (4)

PCO PCOCONV TOTALventedCONVvented 

### P P VV
,

,, 

### 

where:
V

vented,CONV is the total volume of vented gas from participating companies conventional oil and gas well production [mscf]
P CONV,PCO is the total conventional oil and gas well gas production in the basin in 2009 by the participating companies [mscf]
P

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

Equation (5) CONVVOCCONVVOCCONVventedCONVblowdown YRMW1000VE

,,,, June 2013

Final Report 14 where:
E blowdown,CONV is the total VOC emissions from blowdowns conducted by the participating companies [lb-VOC/yr]
MW VOC,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:
E blowdown,CONV,TOTAL are the total emissions basin-wide from blowdowns at conventional wells [tons/year]
E blowdown,CONV are the blowdown emissions from the participating companies at conventional wells [tons/year]
P TOTAL,CONV is the total gas production in the basin in 2006 from conventional wells [mscf]
P

PCO,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) TOTALventedvented VfV

, 

where:
V

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

is the frequency of completions [events/year]
V

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

Equation (8)

PCO PCOCONV TOTALventedvented 

### W W VV
,

, 

### 

where:
V

vented is the total volume of vented gas from participating companies conventional well production [mscf]
W

CONV,PCO is the total conventional well count ownership in the basin in 2009 by the participating companies [mscf]
W

PCO is the total well count ownership in the basin in 2009 by the participating companies [mscf]

Equation (9) VOCVOCTOTALventedcompletion YRMW1000VE 

,

where:
E completions is the total VOC emissions from completions conducted by all participating companies [lb-VOC/yr]
MW VOC 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:
E completion,TOTAL are the total emissions basin-wide from completions at conventional wells [tons/year]
E completion, are the completion emissions from the participating companies at conventional wells [tons/year]
C TOTAL is the total number of conventional well completions in the basin in 2006 [mscf]
C

PCO 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 PM 10 emissions factors, EPA AP-42 emissions factors were used as most survey respondents did not provide PM 10 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:
E engine are emissions from a compressor engine [ton/year/engine]
EF i is the emissions factor of pollutant i [g/hp-hr]
HP is the horsepower of the engine [hp]
LF is the load factor of the engine

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

It was assumed (and confirmed through discussions with operators) that gas-fired engines would not use gas high in H 2 S content due to operational issues; therefore SO 2 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:
E engine,TOTAL is the total emissions from compressor engines in the basin [ton/yr]
E engine is the total emissions from compressor engines owned by the participating companies [ton/yr]
W

TOTAL 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 andJune 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) fnVV ventedTOTALvented 

,

where:
V

vented,TOTAL is the total volume of vented gas from the participating companies for startup or shutdown[mscf/year]
V

vented 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) VOCVOCTOTALventedS YRMW1000VE 

,

where:
E

S

is the total VOC emissions from well compressor engine startups or shutdowns conducted by the participating companies [lb-VOC/yr]
MW VOC 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]
Y

VOC 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:
E

S,TOTAL are the total emissions basin-wide from compressor engine startup or shutdown at conventional wells [tons/year]
E

S

are the compressor engine startup or shutdown emissions from the participating companies at conventional wells [tons/year]June 2013

Final Report 19 P TOTAL is the total gas production in the basin in 2009 from conventional wells [mscf]
P

PCO 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 GLYCalcsoftware 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:
E

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

DEHY,Field are the VOC emissions basin-wide from all field dehydrators operated by companies participating in the survey [tons/year]
P TOTAL is the total gas production in the basin in 2009 from conventional oil and gas wells [mscf]
P

PCO 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:
E reboiler is the emissions from reboilers operated by the participating companies [ton/yr]

n is the number of reboilers operated by participating companiesJune 2013

Final Report 20 EF reboiler is the emission factor for a reboiler for a given pollutant [lb/million scf] Q reboiler is the reboiler MMBTU/hr rating [MMBTU rated /hr]
HV local is the local natural gas heating value [BTU local /scf]

t annual 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:
E

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

Reboiler are the dehydrator reboiler emissions from the participating companies [tons/year]
P TOTAL is the total gas production in the basin in 2009 from conventional wells [mscf]
P

PCO 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:
E drilling,engine is the emissions from one engine on the drilling rig for drilling one well [ton/engine/spud]
EF i 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

t drilling 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 ienginedrillingdrilling 

### EE

,,

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

It should be noted that SO 2 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 SO 2

.

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:
E drilling,TOTAL is the total emissions in the basin from drilling activity [tons/yr]
E drilling is the total emissions in the basin from drilling activity conducted by the participating companies (summed as described above) [tons/yr]
S TOTAL 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) HVQPEFE flareiflare June 2013

Final Report 23 where:
E

flare is the basinwide flaring emissions [lb/yr]
EF i 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]
P

flare 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 S E E TOTAL flare TOTALflare  2000 ,

where:
E

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

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

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

1 C

1

 YtNEFE

annualifugitive

where:
E

fugitive is the fugitive VOC emissions for all participating companies [ton-VOC/yr]
EF i 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
C

1 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 TOTAL fugitive TOTALfugitive 

### W W

C E E 

2 ,

where:
E

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

fugitive is the fugitive VOC emissions for all participating companies from conventional wells [lb-VOC/yr]
W

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

PCO is the total number of conventional gas and oil wells in the basin owned by the participating companies
C

2 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) 

### hctQEFE annualheaterheaterheater 

###  HV 1

local

where:
E heater is the emissions from a given heater [lb/yr/heater]
EF heater is the emission factor for a heater for a given pollutant [lb/million scf] Q heater is the heater MMBTU/hr rating [MMBTU rated /hr]
HV local is the local natural gas heating value [BTU local /scf]

t annual 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 nheaternheatercompaniesheater 

### NEE

,,,

where:
E heater,companies is the total emissions from all heaters operated by participating companies [lb/yr]
E heater,n is the emissions from a single heater (of type n ) [lb/yr/heater]
N

heater,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 W E E TOTAL companiesheater

TOTALheater  2000

,

,

where:
E heater,TOTAL is the total heater emissions in the basin [ton/yr]
E heater,companies is the total emissions from all heaters operated by participating companies [lb/yr]
W

TOTAL 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

 PLE

loading

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 ofJune 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:
V

vented,TOTAL is the total volume of vented gas from all pneumatic devices for all participating companies [mscf/year]

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

N

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

t annual is the number of hours per year that devices were operating [hr/yr]

Equation (32) VOCVOCTOTALventedpneumatic YRMW1000VE 

,

where:
E

pneumatic is the total conventional well pneumatic device VOC emissions [lb-VOC/yr]
MW VOC,CONVis 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 CONVTOTAL pneumatic TOTALpneumatic 

### W W E E

, ,

, 

### 2000 

where:
E

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

pneumatic is the pneumatic device VOC emissions for all participating companies’ gas wells [lb-VOC/yr]
W

TOTAL,CONV is the total number of conventional wells in the basin
W

PCO,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 countJune 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) CONVVOCCONVVOCTOTALventedpump YRMW1000VE

,,, 

where:
E

pump is the gas-actuated pump VOC emissions for all participating companies [lb-VOC/yr]
V

vented,TOTAL is the total volume of vented gas from all gas-actuated pumps for all participating companies [mscf/year]
MW VOC,CONVis 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 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 CONVTOTAL pump TOTALpump 

### W W E E

, ,

, 

### 2000 

where:
E

pump,TOTAL is the total pneumatic pump emissions in the basin [ton/yr]
E

pump is the gas-actuated pump VOC emissions for all participating companies [lb-VOC/yr]
W

TOTAL,CONV is the total number of conventional wells in the basinJune 2013

Final Report 30 W

PCO,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:
E oiltanks-county is the county-level emissions from oil tanks [tons/yr]
E condensate,tanks-county is the county-level emissions from condensate tanks [tons/yr]
EF oil-flashing is the derived flashing VOC emissions factor for oil tanks [lb-VOC/bbl]
EF cond-flashingis the derived flashing VOC emissions factor for condensate tanks [lbVOC/bbl]
P

oil is the oil production from oil wells [bbl]
P

cond 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 countyksoilksoil EE tan,tan

and

Equation (39) 

#   

  i countykscondensatekscondensate EE tan,tan

where:
E oiltanks is the basin-wide emissions from oil tanks [tons/yr]
E condensate,tanks is the basin-wide emissions from condensate tanks [tons/yr]
E oiltanks-county is the VOC emissions for oil tanks for each county [tons /yr]
EF condensate,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:
E

workover,engine is the emissions from one workover [ton/workover]June 2013

Final Report 32 EF i 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

t workover is the average duration of a workover event [hr/workover]

It should be noted that SO 2 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 SO 2

.

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:
E

workover,TOTAL are the total emissions basin-wide from workovers [tons/year]
E

workover are the total workover rig emissions from the participating companies [tons/year]
W

TOTAL 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 presentedbelow 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 inJune 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**NO x Emissions (tons/year)** 

**County** Non-Tribal

TribalJune 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 (t ons/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**VO C Emissions (tons/yr)** 

**County** Non-Tribal

TribalJune 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 29June 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 196June 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 46June 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 2,127June 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 4,859June 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 83,768June 2013

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