### 773 San Marin Drive, Suite 2115, Novato, CA 94998 415.899.0700 ENVIRON International Corporation



## Final Report

**DEVELOPMENT OF 2015 OIL AND GAS EMISSIONS PROJECTIONS**

**FOR THE WILLISTON BASIN**

Prepared by

Amnon Bar-Ilan

Rajashi Parikh

John Grant
Yesica Alvarez 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

Phase III Oil & Gas Emissions Inventory Project

July 25, 2013

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## i **TABLE OF CONTENTS**

**Page**

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

GEOGRAPHIC GROUPING ......................................................................................................2

PARAMETERS PROJECTED ....................................................................................................3

PROJECTION METHODOLOGIES FOR THE WILLISTON BASIN .......................................6
Associated Gas Flaring and Venting ........................................................................................6

Bakken Formation Counties ....................................................................................................8
Cedar Creek Anticline Counties ............................................................................................ 12

Other Counties ...................................................................................................................... 17

SCALING FACTOR DEVELOPMENT AND UNCONTROLLED 2015

EMISSIONS ....................................................................................................................... 23

CONTROLLED 2015 EMISSIONS .......................................................................................... 25
Nonroad Diesel Engine Standards and Fuel Sulfur Standards ................................................ 26 New Source Performance Standards for Stationary Spark-Ignited Engines ............................ 27
New Source Performance Standards for Pneumatic Devices .................................................. 28 New Source Performance Standards and Montana Regulations for Well Completions ........... 28 New Source Performance Standards and Montana and North Dakota Regulations for Crude

Oil and Condensate Tanks ..................................................................................................... 29

SUMMARY RESULTS ............................................................................................................ 30

REFERENCES ......................................................................................................................... 39

**LIST OF TABLES**

Table 1. Scaling parameter for each oil and gas source category considered in this inventory. ..................................................................................................................3

Table 2. Scaling factors for five parameters used in the projection analysis for all
counties in the Williston Basin. ................................................................................ 23

Table 3. Summary of federal and state “on-the-books” regulations affecting the oil and gas source categories considered in this inventory. ............................................ 25

Table 4. Federal NSPS emissions standards for engines less than 25 horsepower. .................. 27

Table 5. Federal NSPS emissions standards for engines greater than 25 horsepower but less than 100 horsepower. ............................................................... 28

Table 6. Federal NSPS emissions standards for engines greater than 25 horsepower but less than 100 horsepower. ............................................................... 28

Table 7. Crude oil tank controls assumptions in the 2015 Williston Basin midterm
emissions. ................................................................................................................ 29

Table 8. 2015 emissions of all criteria pollutants by county for the Williston Basin. .............. 33

Table 9. 2015 NOx emissions by county and by source category for the Williston
Basin. ...................................................................................................................... 35

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## ii Table 10. 2015 VOC emissions by county and by source category for the Williston
Basin. ...................................................................................................................... 37

**LIST OF FIGURES**

Figure 1. Fraction of gas produced that is processed and sold in the Bakken
Formation in North Dakota and Montana. ..................................................................7

Figure 2. Total well count historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. ...........................8

Figure 3. Spud count historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. ............................................9

Figure 4. Total gas production historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. ......................... 10

Figure 5. Oil production historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. ......................... 11

Figure 6. Condensate production historical data (from the IHS database) for the Bakken Formation Counties in the Williston Basin and projections to

2015......................................................................................................................... 12

Figure 7. Total well count historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. .......................... 13

Figure 8. Spud count historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. .......................... 14

Figure 9. Total gas production historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. ................ 15

Figure 10. Oil production historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. .......................... 16

Figure 11. Condensate production historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. ............... 17

Figure 12. Total well count historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. .......................................... 18

Figure 13. Spud count historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. ............................................................ 19

Figure 14. Total gas production historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. .......................................... 20

Figure 15. Oil production historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. ........................................................ 21

Figure 16. Condensate production historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. .......................................... 22

Figure 17. 2015 NOx emissions by source category and by county in the Williston
Basin. ...................................................................................................................... 31

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## iii Figure 18. 2015 VOC emissions by source category and by county in the Williston
Basin. ...................................................................................................................... 31

Figure 19. 2015 NOx emissions contributions by source category in the Williston
Basin. ...................................................................................................................... 32

Figure 20. 2015 VOC emissions contributions by source category in the Williston
Basin. ...................................................................................................................... 32

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## 1 **INTRODUCTION**

This document outlines the projection methodologies used in generating the 2015 emissions projections from oil and gas sources in the Williston Basin. These methodologies will use as a starting point the 2009 baseline Williston Basin oil and gas emissions inventory, described in the baseline emissions report entitled “Development of Baseline 2009 Emissions from Oil and Gas Activity in the Williston Basin”. Like the midterm inventory for the Powder River Basin, the Williston Basin projected inventory is for calendar year 2015 rather than 2012. The 2015 calendar year was chosen because of the long duration of the project and the Montana Department of Natural Resources (MTDNR) and North Dakota Department of Health (NDDOH) need for a farther future year projection than 2012.

The methodology used to develop the 2015 projections for the Williston Basin is described

below in subsections:

 Geographic grouping of data – regional differences in production or activity are factored into the projection methodology by geographic region;

 Projected parameters – seven basic parameters are projected forward to 2015 for purposes of developing scaling factors: total well counts, conventional gas well counts, spud counts, total gas production, oil well oil production, condensate production and total gas processed;

 Scaling factors and developing uncontrolled emissions projections – the projected parameters are used to develop scaling factors (incorporating geographic groupings), and these scaling factors are applied to the 2009 baseline emissions;

 Application of “on-the-books” regulations and control measures – existing regulations are summarized for their impacts on the future year emissions and applied to adjust the uncontrolled 2015 inventory.

Projections for years beyond 2015 (not addressed in this methodology) will likely include additional parameters and will be based on these 2015 projections as the start year. The methodology for developing far future year projections will be detailed in a separate analysis.

Following the discussion of the methodology, the results of the 2015 emissions projections for the Williston Basin are presented in graphical and tabular formats.

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## 2 **GEOGRAPHIC GROUPING**

The projections for 2015 have been conducted for three geographic groupings in the Williston

Basin. These include:

 Bakken Formation Counties – this grouping represents the core Bakken oil development area in the basin including Daniels, McCone, Richland, Roosevelt, Sheridan, and Valley Counties in Montana and Billings, Bottineau, Burke, Divide, Dunn, Golden Valley, McHenry, McKenzie, Mclean, Mercer, Morton, Mountrail, Oliver, Pierce, Renville, Rolette, Sheridan, Stark, Ward and Williams Counties in North Dakota;

 Cedar Creek Anticline – this grouping represents the other major concentrated development area in the basin including Dawson, Fallon, Prairie and Wibaux Counties in Montana, Bowman and Slope Counties in North Dakota, and Harding County in South Dakota;

 All Other Counties – this grouping contains primarily conventional gas and oil production areas outside of the Bakken and Cedar Creek Anticline and includes all remaining counties in the basin in Montana, North Dakota and South Dakota;

As noted above, the geographic groupings were constructed to group similar production types or to group counties that do not represent significant fractions of the total production in the Williston Basin. The Williston Basin contains the core Bakken oil shale production area, representing significantly greater oil production than any other Phase III basin studied to date (Bar-Ilan, et al., 2009a; Bar-Ilan, et al., 2009b; Bar-Ilan, et al., 2009c; Bar-Ilan, et al., 2008). In addition to the Bakken formation, the Cedar Creek Anticline represents another major concentration of development and thus was projected independently of the Bakken formation. Finally all other counties in the basin were grouped together as “minor” counties, not representing significant fractions of basin-wide oil or gas production. This approach of identifying a core production area and a larger grouping of “minor” production counties is similar to that used for the Piceance Basin (Bar-Ilan, et al., 2009d).

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## 3 **PARAMETERS PROJECTED**

The 2015 projections for oil and gas emissions in the Powder River Basin rely on scaling 7
parameters:

 Total well counts

 Spud counts

 Total gas production

 Oil well oil production

 Condensate production

 Total gas processed

 Total casinghead gas flared

These seven parameters are considered because each parameter applies to the emissions projections of one or more source categories. Note that the analysis uses data from the IHS database, which defines condensate production as liquid hydrocarbon production from wells which are classified as gas wells. Similarly, oil well oil production is defined as liquid hydrocarbon production from wells which are classified as oil wells. The classification of gas vs. oil wells is obtained directly from the IHS database is based on the gas-oil ratio (GOR) of the well, using a cutoff GOR defined either by the Montana Board of Oil and Gas or North Dakota

Industrial Commission Division of Oil and Gas. This is the distinction made between condensate and oil production. Because of the large amount of primary oil production in the Bakken formation, the effect of this definition of condensate and oil is minor. Most of the liquid hydrocarbon production in the basin is in the form of primary oil.

The mapping of source category to projection parameter is shown below in Table 1.

**Table 1.** Scaling parameter for each oil and gas source category considered in this inventory.

**Source SCC**  **Description Projection Parameter**  Unpermitted 2310000100 Heaters Total Well Count Unpermitted 2310000220 Drill rigs Spuds Unpermitted 2310000230 Workover rigs Total Well Count Unpermitted 2310000300 Pneumatic devices Total Well Count Unpermitted 2310000700 Unpermitted Fugitives Total Well Count

Unpermitted 2310000801 Gas Well Truck Loading Gas Well Condensate
Production Unpermitted 2310000802 Oil Well Truck Loading Oil Well Oil Production

Unpermitted 2310000820 Gas Plant Truck Loading Gas Well Condensate
Production Unpermitted 2310001610 Venting - initial completions Spuds Unpermitted 2310001620 Venting - recompletions Spuds Unpermitted 2310001630 Venting - blowdowns Total Gas Production Unpermitted 2310001640 Venting - Compressor Startup Total Gas Production Unpermitted 2310001650 Venting - Compressor Shutdown Total Gas Production

Unpermitted 2310002230 Condensate tank Gas Well Condensate
Production Unpermitted 2310002240 Oil Tank Oil Well Oil Production

Unpermitted 2310002231 Condensate tank flaring Gas Well Condensate
Production Unpermitted 2310003100 Miscellaneous engines Total Well Count Unpermitted 2310003200 Pneumatic pumps Total Well Count Unpermitted 2310020600 Compressor engines Total Gas Production

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## 4 **Source SCC**  **Description Projection Parameter**  Unpermitted 2310021410 Dehydrator Total Gas Production Unpermitted 2310000330 Artificial Lift Oil Well Oil Production Unpermitted 2310002241 Oil Tank Flaring Oil Well Oil Production Unpermitted 2310003500 Other Flaring Total Gas Production

Unpermitted 2310003501 Associated Gas Flaring Based on volume of gas flared in 2015
MTDEQ Permitted
Sources 10200603 Process Heaters Total Gas Processed

MTDEQ Permitted
Sources 10500106 Process Heaters Total Gas Processed

MTDEQ Permitted
Sources 20100202 Compressor Engines Total Gas Processed

MTDEQ Permitted
Sources 20200102 Compressor Engines Total Gas Processed

MTDEQ Permitted
Sources 20200201 Compressor Engines Total Gas Processed

MTDEQ Permitted
Sources 20200202 Compressor Engines Total Gas Processed

MTDEQ Permitted
Sources 20200253 Compressor Engines Total Gas Processed

MTDEQ Permitted
Sources 20200254 Compressor Engines Total Gas Processed

MTDEQ Permitted
Sources 30200699 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 30301012 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 30501050 Natural Gas Production, Other Not Classified Total Gas Processed

MTDEQ Permitted
Sources 30502504 Natural Gas Production, Other Not Classified Total Gas Processed

MTDEQ Permitted
Sources 31000101 Permitted Fugitives Total Gas Processed

MTDEQ Permitted
Sources 31000107 Natural Gas Production, Other Not Classified Total Gas Processed

MTDEQ Permitted
Sources 31000129 Oil Production, Gas/Liquid Separation Total Gas Processed

MTDEQ Permitted
Sources 31000202 Natural Gas Production, Gas Stripping Operations Total Gas Processed

MTDEQ Permitted
Sources 31000205 Natural Gas Production, Flares Total Gas Processed

MTDEQ Permitted
Sources 31000207 Permitted Fugitives Total Gas Processed

MTDEQ Permitted
Sources 31000220 Permitted Fugitives Total Gas Processed

MTDEQ Permitted
Sources 31000227 Dehydrator Total Gas Processed

MTDEQ Permitted
Sources 31000228 Dehydrator Total Gas Processed

MTDEQ Permitted
Sources 31000301 Dehydrator Total Gas Processed

MTDEQ Permitted
Sources 31000404 Process Heaters Total Gas Processed

MTDEQ Permitted
Sources 31000405 Process Heaters Total Gas Processed

MTDEQ Permitted
Sources 40301008 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40301009 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40301010 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40301012 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40301021 Permitted Tank Losses Total Gas Processed

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## 5 **Source SCC**  **Description Projection Parameter** 
MTDEQ Permitted
Sources 40301117 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40400116 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40400140 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40400151 Permitted Fugitives Total Gas Processed

MTDEQ Permitted
Sources 40400250 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40400302 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40400311 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40400312 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40600131 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40600132 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40600135 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40700809 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40700810 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40781602 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40781604 Permitted Tank Losses Total Gas Processed

MTDEQ Permitted
Sources 40781605 Permitted Tank Losses Total Gas Processed

NDDOH Permitted
Sources 20200201 Compressor Engines Total Gas Processed

NDDOH Permitted
Sources 20200202 Compressor Engines Total Gas Processed

NDDOH Permitted
Sources 31000205 Natural Gas Production, Flares Total Gas Processed

NDDOH Permitted
Sources 31000299 Natural Gas Production, Other Not Classified Total Gas Processed

NDDOH Permitted
Sources 31000301 Dehydrator Total Gas Processed

NDDOH Permitted
Sources 31000404 Process Heaters Total Gas Processed

NDDOH Permitted
Sources 40400302 Permitted Tank Losses Total Gas Processed

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## 6 **PROJECTION METHODOLOGIES FOR THE WILLISTON BASIN**

For the Williston Basin, the methodology for obtaining the 2015 value of each projection parameter (total well counts, spud counts, total gas production, oil well oil production, condensate production, total gas processed, and casinghead gas flared) is described below. In general, spud count projections were developed by obtaining the historical spud count and well count data for the geographic grouping using the IHS database, and reviewing the historic rate of spuds to new wells added in each geographic grouping. Well count and production projections for the basin were developed by developing extrapolated trend lines from historical data, or conservatively holding well counts and project constant into the future if historic data indicated decline. Condensate production projections were assumed to follow the trends for gas production. “Total gas processed” and “casinghead gas flared” are related parameters. The “total gas processed” projection factor applies to permitted midstream gas gathering and processing sources, and the “casinghead gas flared” projection factor applies only to the casinghead gas flaring source category. These are described below as they are not projected similarly to the other parameters.

Because of the recent increase in activity in the Bakken formation, additional annual data on oil and gas production and well counts was gathered from the IHS database for calendar years 2010, 2011 and 2012 in order to better track these recent trends. Therefore extrapolations and projections were made for the period 2012-2015, but it should be noted that projection factors represent the ratio of 2015 values of the parameters to 2009 values of the parameters.

The IHS database is a tool to query oil and gas statistical well and production data, and uses as its reference data the databases maintained by various state OGCC’s (or equivalent).

**Associated Gas Flaring and Venting**

Special consideration is given to develop projections of the total amount of gas processed in the Williston Basin in 2015, relative to the total amount of gas processed in 2009. Information obtained from the state and federal agencies as well as industry participants indicates that some associated gas produced from the Bakken formation is flared due to a lack of gas gathering and processing infrastructure. This was discussed in the technical report for the Williston Basin baseline 2009 inventory (Bar-Ilan, et al., 2013). The amount of gas sold was used as a surrogate for the amount of gas processed, as this information was tracked for the basin by the North Dakota oil and gas commission. Historic data on the fraction of gas sold was plotted and extrapolated to 2015; the 2015 fraction of gas sold was then combined with the projected total gas production to derive the projected 2015 total gas processed. The ratio of 2015 to 2009 total gas processed was used to project midstream gas gathering emission sources. The inverse of this value represents the fraction flared, and therefore a similar approach was used to derive the projection factor for the casinghead gas flaring source category. Figure 1 below shows the projected fraction of gas sold in the Williston Basin.

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## 7 **Figure 1.** Fraction of gas produced that is processed and sold in the Bakken Formation in North
Dakota and Montana.



## This analysis was conducted for the Bakken geographical grouping, where the majority of new gas production is occurring in the Williston Basin in this time period. It was assumed that for the Cedar Creek Anticline and “Other Counties” geographical groupings, all gas produced was processed. In practical application, the “total gas processed” projection factor is dominated by the activities in the Bakken formation as shown in Figure 1.

The decline in the fraction of gas processed in the Bakken from 2009 through 2011 is due to the increase in associated gas production without sufficient gas gathering and processing infrastructure. During the period from 2011 through October 2012, this trend reverses as additional infrastructure is established in this geographic area; this was the time period used to project a trendline forward to 2015. There are three primary observations from this analysis:

(1) The “gas processed” projection factor is a combination of growth in the total amount of gas produced and the increase in gas gathering infrastructure; (2) This projection factor would be lower if the increase in gas gathering and processing infrastructure were not accounted for; and (3) Similarly the projection factor for casinghead gas flaring would be higher if the increase in gas gathering and processing infrastructure were not accounted for;

It should be noted that this analysis used the available data on recent trends in the increase in gas gathering and processing infrastructure, however more detailed survey data from industry would improve these projections. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

2008 2009 2010 2011 2012 2013 2014 2015**Percentage of Gas Sold**

**Year** Bakken Historical Percent of Gas

Sold

Bakken Forecasted Percent of

Gas Sold

North Dakota Statewide Monthly

Fraction of Gas Sold

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## 8 **Bakken Formation Counties**

Total Well Counts

Total well counts in the Bakken Formation counties in the Williston Basin have been plotted for the years 1970 – 2012 below in Figure 2, including projections to 2015.

**Figure 2.** Total well count historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. 1



## Total well count projections were developed for the period 2012 – 2015 by linear extrapolation of the well counts in the period 2010-2012. This period represented the recent historic increase in oil wells and oil production activity in the Bakken Formation and was considered a reasonable historic period from which to project the remaining data.

Spud Counts

Spud counts in the Bakken Formation Counties in the Williston Basin have been plotted for the years 1970 – 2010 below in Figure 3, including projections to 2015.

1 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

### 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015Well Count



### Year Conv. Well Count
projected

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## 9 **Figure 3.** Spud count historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. 2



## Historic spud counts in the Bakken Formation Counties, as obtained from the IHS database for the period 1970-2010 are erratic, making an extrapolation from historical data infeasible. Rather the change in the number of active wells each year in the period 2006-2010 was compared to the number of spuds that occurred in that same period. A ratio of the average number of annual spuds to the number of annual active wells added was developed. This ratio of 2.01 was then applied to the projected number of wells in the Bakken Formation Counties as described in Figure 2 above to estimate the projected number of spuds.

Total Gas Production

Total gas production in the Bakken Formation Counties in the Williston Basin has been plotted for the years 1970 – 2012 below in Figure 4, including projections to 2015.

2 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 500 1,000 1,500 2,000 2,500 3,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Number of Spuds**

**Year** Spuds

projected (well count basis)

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## 10 **Figure 4.** Total gas production historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. 3



## Total gas production was linearly projected from 2012 - 2015 based on the rate of increase from the period 2010-2012 in order to account for the recent growth in Bakken Formation activity. The majority of gas production in the Bakken Formation geographical grouping is from casinghead gas production at Bakken oil wells.

Oil Well Oil Production

Oil well oil production in the Bakken Formation Counties in the Williston Basin has been plotted for the years 1970 – 2012 below in Figure 5, including projections to 2015.

3 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 100,000,000 200,000,000 300,000,000 400,000,000 500,000,000 600,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Gas Production [mcf]**

**Year** Conv. Gas Prod (mcf)

projected

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## 11 **Figure 5.** Oil production historical data (from the IHS database) for Bakken Formation Counties in the Williston Basin and projections to 2015. 4



## Oil production in the Bakken Formation was linearly projected forward to 2015 based on the growth period from 2010 to 2012. Because of the sensitivity of this projection to the selection of projection parameters (extrapolation type, data period from which to project) and the importance of this projection to the overall 2015 midterm emission inventory, reference data was obtained from other studies to confirm the plausibility of this projection. A study conducted by Bentek Energy for the North Dakota Pipeline Association (NDPA) and North Dakota Industrial Commission (NDIC) was used to compare the midterm projections of oil production in the Bakken Formation (Bentek, 2012). The Bentek study presented a range of oil production projections based on a variety of parameters used to define three scenarios: (1) a low scenario; (2) a base case scenario; and (3) a high growth scenario. The linearly projected oil production shown in Figure 5 falls within a reasonable range between the base case and low scenarios developed in the Bentek study for calendar year 2015, more closely approximating the base case scenario. Because the consistency with the Bentek study appeared reasonable, this linear projection was used for Bakken Formation oil production in 2015.

Condensate Production

Condensate production in the Bakken Formation Counties in the Williston Basin has been plotted for the years 1970 – 2010 below in Figure 6, including projections to 2015.

4 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 50,000,000 100,000,000 150,000,000 200,000,000 250,000,000 300,000,000 350,000,000 400,000,000 450,000,000 500,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Oil Production [bbl]**

**Year** Oil Well Oil Production (bbl)

projected

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## 12 **Figure 6.** Condensate production historical data (from the IHS database) for the Bakken Formation Counties in the Williston Basin and projections to 2015. 5



## Condensate production in the Bakken Formation Counties is low relative to primary oil production. Large increases in annual condensate production were observed in the period 2005- 2008 with subsequent decline in 2009 and a slight increase in 2010. This may reflect economic conditions which favored the development of primary oil wells over gas wells producing condensate. Given the erratic nature of recent condensate production activity in the Bakken Formation, the analysis conservatively assumed that 2010 condensate production levels would remain constant in the period 2010-2015.

**Cedar Creek Anticline Counties**

Total Well Counts

Total well counts in the Cedar Creek Anticline Counties in the Williston Basin have been plotted for the years 1970 – 2010 below in Figure 7, including projections to 2015.

5 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Condensate Production [bbl]**

**Year** Gas Well Condensate Production (bbl)

projected

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## 13 **Figure 7.** Total well count historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. 6



## Total active well counts in the Cedar Creek Anticline formation have been steadily increasing since approximately the mid-1990’s and this trend was continued. Total well counts were linearly extrapolated to 2015 based on historic data from the period 2006-2010.

Spud Counts

Spud counts in the Cedar Creek Anticline Counties in the Williston Basin have been plotted for the years 1970 – 2010 below in Figure 8, including projections to 2015.

6 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 500 1,000 1,500 2,000 2,500 3,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Well Count**

**Year** Conv. Well Count

projected

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## 14 **Figure 8.** Spud count historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. 7



## Historic spud counts in the Cedar Creek Anticline Counties, as obtained from the IHS database for the period 1970-2010 are erratic, making an extrapolation from historical data infeasible. The change in the number of active wells each year in the period 2006-2010 was compared to the number of spuds that occurred in that same period, and determined the number of spuds required to match the increase or decrease in well counts for each year in that period. An average total spud count needed to maintain the observed number of active wells in the period 2006-2010 was developed, with a value of 99 spuds per year. The annual number of spuds estimated using this methodology was held constant for the period 2011-2015.

Total Gas Production

Total gas production in the Cedar Creek Anticline Counties in the Williston Basin have been plotted for the years 1970 – 2010 below in Figure 9, including projections to 2015.

7 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 

### 0 50 100 150 200 250 300 350 400

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Number of Spuds**



### Year Spuds

projected (well count historic basis)

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## 15 **Figure 9.** Total gas production historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. 8



## Total gas production in the Cedar Creek Anticline Counties was generally increasing during the entire historical period tracked through 2008. Data from 2009 and 2010 show that gas production levels have declined during these past two years likely due to economic circumstances that favor oil production over gas production, and therefore this analysis conservatively assumed that gas production would remain at 2010 levels through the period

2011-2015.

Oil Well Oil Production

Oil well oil production in the Cedar Creek Anticline Counties in the Williston Basin has been plotted for the years 1970 – 2010 below in Figure 10, including projections to 2015.

8 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 10,000,000 20,000,000 30,000,000 40,000,000 50,000,000 60,000,000 70,000,000 80,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Gas Production [mcf ]** 

**Year** Conv. Gas Prod (mcf)

projected

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## 16 **Figure 10.** Oil production historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. 9



## Oil production has been generally increasing in the Cedar Creek Anticline Counties in the Williston Basin throughout the historical period until 2007. During the period 2007-2010 oil production in the Cedar Creek Anticline declined by approximately 35%. Given that no additional information was available on anticipated trends in this formation, it was conservatively assumed that oil production would remain at 2010 levels in the period 2011-2015.

Condensate Production

Condensate production in the Cedar Creek Anticline Counties in the Williston Basin has been plotted for the years 1970 – 2010 below in Figure 11, including projections to 2015.

9 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 5,000,000 10,000,000 15,000,000 20,000,000 25,000,000 30,000,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Oil Production [bbl]**

**Year** Oil Well Oil Production (bbl)

projected

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Final Report 

## 17 **Figure 11.** Condensate production historical data (from the IHS database) for Cedar Creek Anticline Counties in the Williston Basin and projections to 2015. 10



## Condensate production in the Cedar Creek Anticline has been steadily increasing in the period 2005-2010. Although gas production in the Cedar Creek Anticline experienced a decline after 2008, this trend was not observed in the condensate production. Therefore condensate production was linearly extrapolated to 2015 based on the historic data in the period 2006-2010.

**Other Counties**

Total Well Counts

Total well counts in the “Other Counties” grouping in the Williston Basin have been plotted for the years 1970 – 2010 below in Figure 12, including projections to 2015.

10 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 3,500,000 4,000,000 4,500,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Condensate Production [bbl ]** 

**Year** Gas Well Condensate Production (bbl)

projected

### July 2013

Final Report 

## 18 **Figure 12.** Total well count historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. 11



## Total well counts in the “Other Counties” grouping have generally increased in the period 2005- 2010. Total well counts were linearly extrapolated to 2015 based on historical data in the period

2006-2010.

Spud Counts

Spud counts in the “Other Counties” grouping in the Williston Basin have been plotted for the years 1970 – 2010 below in Figure 13, including projections to 2015.

11 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 10 20 30 40 50 60

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Well Count**

**Year** Conv. Well Count

projected

### July 2013

Final Report 

## 19 **Figure 13.** Spud count historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. 12



## Historic spud counts in the “Other Counties” grouping, as obtained from the IHS database for the period 1970-2010 are erratic, making an extrapolation from historical data infeasible. The change in the number of active wells each year in the period 2006-2010 was compared to the number of spuds that occurred in that same period, and determined the number of spuds required to match the increase or decrease in well counts for each year in that period. An average total spud count needed to maintain the observed number of active wells in the period 2006-2010 was developed, with a value of 2.7 spuds per year. The annual number of spuds estimated using this methodology was held constant for the period 2012-2015.

Total Gas Production

Total gas production in the “Other Counties” grouping in the Williston Basin has been plotted for the years 1970 – 2010 below in Figure 14, including projections to 2015.

12 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 20 40 60 80 100 120

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Number of Spuds**

**Year** Spuds

projected (well count historic basis)

### July 2013

Final Report 

## 20 **Figure 14.** Total gas production historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. 13



## Total gas production in the “Other Counties” grouping has been generally in decline from a peak in the early 1970’s, although gas production levels in this grouping are minimal compared to the other geographic groupings in the Williston Basin. This analysis conservatively assumed that total gas production would remain at 2010 levels through the period 2011-2015.

Oil Well Oil Production

Oil well oil production in the “Other Counties” grouping in the Williston Basin has been plotted for the years 1970 – 2010 below in Figure 15, including projections to 2015.

13 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Gas Production [mcf ]** 

**Year** Conv. Gas Prod (mcf)

projected

### July 2013

Final Report 

## 21 **Figure 15.** Oil production historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. 14



## Oil production in the “Other Counties” grouping has been generally decreasing since a peak in the mid-1970’s. This analysis conservatively assumed that oil production would remain at 2010 levels through the period 2011-2015.

Condensate Production

Condensate production in the “Other Counties” grouping in the Williston Basin has been plotted for the years 1970 – 2010 below in Figure 16, including projections to 2015.

14 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 50,000 100,000 150,000 200,000 250,000 300,000

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Oil Production [bbl]**

**Year** Oil Well Oil Production (bbl)

projected

### July 2013

Final Report 

## 22 **Figure 16.** Condensate production historical data (from the IHS database) for Other Counties in the Williston Basin and projections to 2015. 15



## There has been negligible condensate production in the “Other Counties” grouping in the Williston Basin throughout the historical period from 1970-2010. It was assumed that there would be no condensate production in 2015 in this geographical grouping.

15 (Includes data supplied by IHS Inc., its subsidiary and affiliated companies; Copyright (2011) all rights reserved). 0 100 200 300 400 500 600

1970 1975 1980 1985 1990 1995 2000 2005 2010 2015**Condensate Production [bbl ]** 

**Year** Gas Well Condensate Production (bbl)

projected

### July 2013

Final Report 

## 23 **SCALING FACTOR DEVELOPMENT AND UNCONTROLLED 2015 EMISSIONS**

Scaling factors were generated for the Williston Basin geographic groupings described above, for each parameter considered here: total well counts, spud counts, total gas production, oil well oil production, and condensate production. Total gas processed and casinghead gas flared are not projected in a similar methodology to the other parameters, as described above. These are presented for each county below, and it is noted that all geographic groupings are comprised of more than one county in which the scaling factors for each parameter are identical for all counties in the grouping. The ratio of the value of each of these parameters in 2015 to their values in 2009 is the scaling factor for that parameter for purposes of this projection. This is shown in Equation 1 below:

2009,, 2015,,

, ji ji ji 

## W W f  

## Equation (1)

where: f

i,j



## is the scaling factor for geographic grouping j in the Williston Basin for parameter i (total well count, spud count, total gas production, oil well oil production, and condensate production)

W

i,j,2006 

## is the value of parameter i in geographic grouping j in 2009

W

i,j,2012 

## is the projected value of parameter i in geographic grouping j in 2015

The scaling factor based on the appropriate parameter is selected for each source category as described in Table 1. The scaling factors for the eight parameters used in this analysis for each county in the Williston Basin are presented in Table 2 below.

**Table 2.** Scaling factors for five parameters used in the projection analysis for all counties in the
Williston Basin.

**County Total Well** 
**Count Spud** 
**Count Total Gas** 
**Production Oil** 
**Production Condensate** 
**Production**
Carter (MT) 1.25 0.67 0.90 0.77 1.00
Custer (MT) 1.25 0.67 0.90 0.77 1.00
Daniels (MT) 2.30 4.30 5.51 5.46 1.04
Dawson (MT) 1.14 1.53 0.86 0.85 2.46
Fallon (MT) 1.14 1.53 0.86 0.85 2.46
Garfield (MT) 1.25 0.67 0.90 0.77 1.00
McCone (MT) 2.30 4.30 5.51 5.46 1.04
Prairie (MT) 1.14 1.53 0.86 0.85 2.46
Richland (MT) 2.30 4.30 5.51 5.46 1.04
Roosevelt (MT) 2.30 4.30 5.51 5.46 1.04
Sheridan (MT) 2.30 4.30 5.51 5.46 1.04
Valley (MT) 2.30 4.30 5.51 5.46 1.04
Wibaux (MT) 1.14 1.53 0.86 0.85 2.46
Barnes (ND) 1.25 0.67 0.90 0.77 1.00
Billings (ND) 2.30 4.30 5.51 5.46 1.04
Bottineau (ND) 2.30 4.30 5.51 5.46 1.04
Bowman (ND) 1.14 1.53 0.86 0.85 2.46
Burke (ND) 2.30 4.30 5.51 5.46 1.04

### July 2013

Final Report 

## 24 **County Total Well** 
**Count Spud** 
**Count Total Gas** 
**Production Oil** 
**Production Condensate** 
**Production**
Burleigh (ND) 1.25 0.67 0.90 0.77 1.00
Divide (ND) 2.30 4.30 5.51 5.46 1.04
Dunn (ND) 2.30 4.30 5.51 5.46 1.04
Golden Valley (ND) 2.30 4.30 5.51 5.46 1.04
McHenry (ND) 2.30 4.30 5.51 5.46 1.04
McIntosh (ND) 1.25 0.67 0.90 0.77 1.00
McKenzie (ND) 2.30 4.30 5.51 5.46 1.04
McLean (ND) 2.30 4.30 5.51 5.46 1.04
Mercer (ND) 2.30 4.30 5.51 5.46 1.04
Morton (ND) 2.30 4.30 5.51 5.46 1.04
Mountrail (ND) 2.30 4.30 5.51 5.46 1.04
Renville (ND) 2.30 4.30 5.51 5.46 1.04
Slope (ND) 1.14 1.53 0.86 0.85 2.46
Stark (ND) 2.30 4.30 5.51 5.46 1.04
Stutsman (ND) 1.25 0.67 0.90 0.77 1.00
Ward (ND) 2.30 4.30 5.51 5.46 1.04
Williams (ND) 2.30 4.30 5.51 5.46 1.04
Butte (SD) 1.25 0.67 0.90 0.77 1.00
Harding (SD) 1.14 1.53 0.86 0.85 2.46

### July 2013

Final Report 

## 25 **CONTROLLED 2015 EMISSIONS**

This methodology considered any “on-the-books” federal or state regulations that would affectthe uncontrolled 2015 emissions projections described above. Table 3 below lists the “on-thebooks” federal and state regulations that affect emissions source categories in the oil and gas industry, and the action taken to adjust the 2015 emissions inventory appropriately. A more detailed description follows of the methodology used to address each of these regulations as they affected the uncontrolled 2015 Williston Basin emissions projections. The uncontrolled 2015 emissions were adjusted based on the proposed actions or control factors developed for each regulation described in Table 3 to account for how these regulations may affect any oil and gas source category considered in this inventory.

**Table 3.** Summary of federal and state “on-the-books” regulations affecting the oil and gas source categories considered in this inventory.

**Source Category**  **Regulation Enforcing**  **Agency Effective** 
**Date Implementation in the 201**  **2**
**Powder River Basin Emissions Projections** 

**Federal**

Drill Rigs, Workover Rigs Nonroad engine Tier standards (1-4) (EPA, 2005) US EPA Phase in from
1996 - 2014 EPA NONROAD model used to create county-level control factors for the drill rig
SCC to account for fleet turnover.

Drill Rigs, Workover Rigs Nonroad diesel fuel sulfur
standards (EPA, 2006 ) US EPA Phase in beginning in
2010 Assume 15 ppm sulfur in nonroad diesel fuel throughout Powder River Basin.
Control factors derived from EPA NONROAD model (see above)

.

All New SparkIgnited Stationary Engines New Source Performance Stds. (NSPS) (EPA, 2008 ; EPA, 2012 ) US EPA Phase in
from 2008 -
2011 Control factors developed considering the specific composition of engines in the inventory (described in more detail below).

Insufficient information to determine the mix of wet/dry seals on compressors therefore no additional control factor applied due to Subpart OOOO requirements.

Pneumatic
Controllers New Source Performance Stds. Subpart OOOO (NSPS) (EPA, 2012) US EPA Beginning Sep. 2011 Assume all new pneumatic controllers after September 2011 are low-bleed
devices.

Condensate and Crude Oil Tanks New Source
Performance Stds. Subpart OOOO (NSPS) (EPA, 2012) US EPA Oct. 15, 2013 Control factors developed for tanks by region (described in more detail below)

Gas Well Completions New Source Performance Stds. Subpart OOOO (NSPS) (EPA, 2012) US EPA Oct. 2012 (low pressure) / Jan. 2015 (all other) Insufficient information to estimate the impact of this regulation requiring reduced emission completions

Dehydrators New Source
Performance Stds. Subpart HH (NSPS) (EPA, 2012) US EPA Phase in from Oct.
2012-Oct.

2015 All dehydration assumed controlled in the baseline 2009 inventory based on limited survey data, therefore no additional effect of this regulation.

Gas Processing
Plants New Source
Performance Stds. Subpart OOOO (NSPS) (EPA, 2012) US EPA Oct. 2013 Not enough information on detailed emissions at gas processing facilities; conservatively assumed that there would be no effect of this regulation on the 2015 inventory.
Minor Source Reporting Requirements on
Indian Tribal Land New Source Performance Stds. Subpart OOOO (NSPS) (EPA, 2012) US EPA Phase-In Beginning Aug. 2011 No information was available from the
minor source reporting regulation.

### July 2013

Final Report 

## 26 **Source Category**  **Regulation Enforcing**  **Agency Effective** 
**Date Implementation in the 201**  **2**
**Powder River Basin Emissions Projections** 

**State**

**– Montana** 

Well Completions MT ARM 36.22.1221 Completion venting controls. MTDEQ 1984 Not enough information was available in producer data; conservatively assume that there would be no effect of this regulation on the 2015 inventory.

Condensate and
Crude Oil Tanks MT ARM 17.8.1603(1)(b) VOC vapors from oil or condensate storage tanks with a PTE > 15 tpy
must be controlled MTDEQ Jan 2006 Control factors developed for tanks by region (described in more detail below)

All VOC sources MT ARM 17.8.1711(1)(a) VOC vapors from each piece of O&G well facility equipment with PTE >15 tpy, must be controlled MTDEQ Apr 2006

Not enough information to make a 2015 specific analysis. Assumed that rates of control in 2015 are similar to rates of
control in 2009 for VOC sources not controlled per other regulations

. MT ARM 17.8.1603(1)(a) VOC vapors must be captured and routed to a gas pipeline if within 1⁄2 mile to control device. MTDEQ Jan 2006
MT ARM 17.8.752 case by case BACT
determination MTDEQ Dec 2002 MT ARM 17.8.1711(1)(a) VOC vapors from each piece of O&G well facility equipment, with a PTE > 15 tpy, must be
controlled MTDEQ Apr 2006

Truck loading MT ARM 17.8.1711(1)(b) Submerged filling on all hydrocarbon liquid loading or unloading MTDEQ Apr 2006 Assumed submerged filling for all tank loading.
**State**

**– North Dakota** 

Condensate and
Crude Oil Tanks NDAC 33

- 15

- 07 and Bakken Pool O&G Control Permitting & Compliance Guidance Flaring controls for tanks NDDOH 2011 Control factors developed for tanks by region (described in more detail below)

Tank loading NDAC 33

- 15

- 07 Submerged filling requirements for tanks > 1000gal NDDOH Initial 2009
Baseline and All Projection
Years Assumed submerged filling for all tank loading.



## Nonroad Diesel Engine Standards and Fuel Sulfur Standards

The EPA NONROAD2005 model was run with fuel inputs based on a 2002 study entitled “WRAP Mobile Sources Emission Inventory Update” (Pollack, et al., 2006). The model outputs were used to develop county-level emissions per unit population for “other oil field equipment” (SCC 2270010010) for the calendar year 2006, and then separately for the calendar year 2012. These emissions per unit population reflect the predicted fleet mix of engines – for various tier standards from baseline uncontrolled engines through Tier IV engines – and are used as a representation of fleet turnover for drilling rigs and workover rigs. The ratios of the per unit emissions in 2012 to those in 2006 for each county of interest were taken to be the control factors accounting for federal non-road tier standards.

### July 2013

Final Report 

## 27 In addition, the NONROAD model runs with the fuel inputs used for developing the tier standards control factors were also used to develop the control factors for SOx emissions factors for drilling rigs and workover rigs. The model is capable of tracking the expected reduction in fuel sulfur content from the baseline 2006 year – assumed to be the same as the WRAP 2002 inventory – and the 2012 future year. A similar approach was used as for the federal tier standards to develop control factors. The ratio of per unit SOx emissions in 2012 to those in 2006 were taken to be a control factor to apply to uncontrolled 2012 SOx emissions for drilling rigs and workover rigs to account for federal non-road diesel fuel standards.

**New Source Performance Standards for Stationary Spark-Ignited Engines**

An analysis was undertaken to implement the US EPA NSPS. In previous basin analyses ofNSPS application (Bar-Ilan, et al., 2009a; Bar-Ilan, et al., 2009b; Bar-Ilan, et al., 2009c; BarIlan, et al., 2008), it was assumed that a flat or declining gas production projection would indicate no need for additional horsepower of compression. This was coupled with the assumption that there would be negligible turnover of engines during the period of the projections to conclude that NSPS did not need to be applied if gas production was declining in any geographic grouping. Where gas production is projected to increase – most notably in the Bakken Formation Counties, NSPS requirements were applied, similar to the assumptions made in developing projected emissions for other basins.

NSPS Regulations

The EPA has promulgated a new regulation covering new stationary, spark-ignited engines of various horsepower classes. The regulation is assumed to apply to central compressor engines, wellhead and lateral compressor engines, and artificial lift engines as well as any other miscellaneous engines that are stationary, spark-ignited natural gas engines. The regulation requires new engines of various horsepower classes to meet increasingly stringent NOx and VOC emission standards over the phase-in period of the regulation.

For engines less than 25 horsepower, Table 4 shows the requirements of the NSPS regulation.

**Table 4.** Federal NSPS emissions standards for engines less than 25 horsepower.

**HP Range a**  

### Emissions Standards Requirement in (g/hp

**- hr)**  **b**



### HC + NOx **NMHC + NOx c**  

### CO **≤ 25 Hp** Class I 16.1 (12.0) 14.8 (11.0) 610 (455)
Class I -A 50-37

- - Class I -B 40 (30) 37 (27.6) Class II 12.1 (9.0) 11.3 (8.4)

a Class I-A: Engines with displacement less than 66 cubic centimeters (cc); Class 1-B: Engines with displacement greater than or equal to 66cc and less than 100cc; Class I: Engines with displacement greater than or equal to
100 cc and less than 225 cc

b Modified and reconstructed engines manufactured prior to July 1, 2008, must meet the standards applicable to engines manufactured after July 1, 2008

c NMHC+NOX standards are applicable only to natural gas fueled engines at the option of the manufacturer, in lieu
of HC+NOX standards



## For engines in the horsepower range 25 – 100 horsepower, Table 5 shows the requirements of the NSPS regulation.

### July 2013

Final Report 

## 28 **Table 5.** Federal NSPS emissions standards for engines greater than 25 horsepower but less than 100 horsepower.

**HP Range Manufacture Date**  **Emissions Standards Requirement (g/hp-hr)** 
**HC + NOx CO** 

25<HP<100 1-Jul-08 3.8 6.5

1-Jul-08 (severe duty) 3.8 200



## For engines in the horsepower range 100 – 1,350 horsepower, Table 6 shows the requirements of the NSPS regulation.

**Table 6.** Federal NSPS emissions standards for engines greater than 25 horsepower but less than 100 horsepower.

**Engine Type and Fuel HP Range**  **Manufacture**
**Date Emissions Standards**  **Requirement (g/hp-hr)**
**NOx CO**  **VOC** Non-Emergency SI Natural Gas and Non-Emergency SI Lean Burn LPG 100≤HP<500 1-Jul-08 2 4 1
1-Jan-11 1 2 1 Non-Emergency SI Lean Burn Natural
Gas and LPG 500≥HP<1350 1-Jan-08 2 4 1
1-Jul-10 1 2 1 Non-Emergency SI Natural Gas and Non-Emergency SI Lean Burn LPG (except lean burn 500≥HP<1350) HP≥500 1-Jul-07 2 4 1



## A detailed analysis was carried forward to analyze the effects of this rule on the permitted and survey-based wellhead engine fleet in the Williston Basin. Engines were sorted into bins representing horsepower ranges based on the available compressor engine data gathered as part of the baseline 2009 inventory development. Because the NSPS requirements change over the phase-in period of the regulation, the growth of compression horsepower was tracked for each year in the period 2009-2015. For each year, the additional compression horsepower was sorted into the horsepower range bins, and NSPS was applied to these engines.

**New Source Performance Standards for Pneumatic Devices**

Following the requirements of the NSPS Subpart OOOO, it was assumed that all new pneumatic devices installed after September 2011 would be low-bleed. This analysis assumed new pneumatic device installation tracked the increase in well counts in each geographic grouping.

**New Source Performance Standards and Montana Regulations for Well Completions**

Both the NSPS Subpart OOOO and Montana ARM 36.22.1221 require controls on well completions in the form of either reduced emission completions (NSPS Subpart OOOO) or combustion controls on vented gas during completions. However insufficient information was available from the baseline 2009 survey data to accurately characterize the uncontrolled fraction of well completions or the uncontrolled VOC emissions from these completions, therefore it was not possible to implement these regulations in the 2015 midterm projections for the Williston

Basin.

### July 2013

Final Report 

## 29 **New Source Performance Standards and Montana and North Dakota Regulations for**

**Crude Oil and Condensate Tanks**

Crude oil tanks in the Bakken Formation represent one of the largest VOC sources in the 2015 midterm projected inventory for the Williston Basin, and thus special consideration was given to this source category based on the regulatory requirements of the NSPS, and Montana and North Dakota state regulations. The regulations and control assumptions for oil tanks were considered separately for four geographic areas: (1) North Dakota non-tribal land; (2) Fort Berthold Indian Reservation (tribal land in North Dakota); (3) Montana non-tribal land; and (4) Montana tribal land (primarily the Fort Peck Indian Reservation). These are summarized in Table 7 below.

**Table 7.** Crude oil tank controls assumptions in the 2015 Williston Basin midterm emissions. **Geographic Area Controls Assumptions** 

North Dakota Non-Tribal Land Per NDDOH regulations, any well site with >20tpy uncontrolled emissions requires control at 98% destruction efficiency (DRE); <20tpy requires 90% DRE.

Analysis conducted to determine fraction of sites with greater or less than 20tpy uncontrolled emissions: 84% would require 98% DRE, 16% would require 90% DRE, assumed average of 97% DRE at all tanks.

North Dakota Tribal Land Based on limited survey data and information from industry participants, practices on the Fort Berthold Indian
Reservation were assumed similar to those on non-tribal land. Federal Implementation Plan (FIP) and interim final rule (IFR) for the Fort Berthold reservation confirm these assumptions are reasonable.

Montana Non-Tribal Land For production added through August 2013: Per MTDEQ regulation, any well site with >15tpy uncontrolled emissions requires control at 90% DRE.

Analysis conducted to determine fraction of sites with greater or less than 15tpy uncontrolled emissions; derived average control of 94% of production at 90% DRE. For production added after August 2013: Subpart OOOO was assumed to apply, with a 99% rule penetration (based on fraction of sites meeting thresholds) and a 95% DRE

Montana Tribal Land For production added through August 2013: Assumed flaring rate based on 2009 baseline survey data at a 90%
DRE. For production added after August 2013: Subpart OOOO was assumed to apply, with a 99% rule penetration (based on fraction of sites meeting thresholds) and a 95% DRE



## It should be noted that these assumptions utilized survey data provided by operators as part of the 2009 baseline inventory. Although this survey data was limited, this was the only data available for some geographic areas.

### July 2013

Final Report 

## 30 **SUMMARY RESULTS**

The scaling factors were applied to the baseline 2009 inventory, and “on-the-books” regulations were applied to the uncontrolled 2015 emissions projections to generate the final 2015 emissionsprojections and results are presented below. It should be noted that all figures showing countylevel emissions only include those counties representing 1% or greater of the total emissions in
the basin.

Figure 17 and Table 8 show that NOx emissions are primarily concentrated in Mountrail, Williams, McKenzie and Dunn Counties in North Dakota and Richland County in Montana, representing approximately 69% of total basin-wide NOx emissions. Additional significant NOx emissions occur in Fallon County Montana and Billings County North Dakota. Figure 18 and Table 8 show that VOC emissions are primarily concentrated in Mountrail, McKenzie, Bowman, Dunn and Williams Counties in North Dakota and Richland County in Montana, representing approximately 72% of total basin-wide VOC emissions Additional VOC emissions are observed in Billings County North Dakota and Fallon County Montana. Given the large volume of produced oil and associated gas in the Williston Basin, VOC emissions are driven by the presence of oil production and associated gas production in these counties.

Consistent with the 2009 baseline emissions analysis, compressor engines, drilling rigs and artificial lift engines remain the dominant NOx source categories in the Williston Basin, representing approximately 75% of total basin-wide NOx emissions as shown in Table 9. It is noted that drilling emissions decline over time as expected from turnover of equipment to newer engines meeting more stringent emissions standards. Therefore drilling represents a smaller
fraction of basin-wide NOx in 2015 than in 2009.

VOC emissions in the 2009 baseline inventory are dominated by oil tanks; but in the 2015 midterm projected inventory VOC emissions are comprised of a number of source categories including oil tanks, casinghead gas venting and flaring, and pneumatic devices and pneumatic pumps as shown in Table 10, representing approximately 75% of basin-wide VOC emissions. Oil tank flashing VOC emissions are still projected to be the largest source category, but represent a significantly smaller fraction of the total basin-wide VOC emissions in 2015 than in 2009 as a result of increasing control of these emissions through the use of flares. Venting of casinghead gas is observed to increase significantly from 2009 to 2015, driven by the large growth in associated gas production despite increasing gas gathering and processing infrastructure. Venting from pneumatic devices and pneumatic pumps is observed to increase as a percentage of total basin-wide VOC emissions in 2015 relative to 2009, driven mainly by the large increase in the number of new wells projected to be added to the basin. It should be noted that the VOC emissions are very sensitive to the selection of a “fraction of gas processed” factor, which is based on a limited set of available data on gas gathering infrastructure development. Additional information on the development of gas gathering infrastructure would help to improve this estimate.

### July 2013

Final Report 

## 31 **Figure 17.** 2015 NOx emissions by source category and by county in the Williston Basin.

**Figure 18.** 2015 VOC emissions by source category and by county in the Williston Basin. 0 2000 4000 6000 8000 10000 12000**NOx Emissions (ton s/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 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000**VOC E missions (tons/year)** 

**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

### July 2013

Final Report 

## 32 **Figure 19.** 2015 NOx emissions contributions by source category in the Williston Basin.

**Figure 20.** 2015 VOC emissions contributions by source category in the Williston Basin. Compressor engines

32%

Drill rigs

27%

Heaters

3% Miscellaneous engines

2% Artificial Lift

16% Oil tank flaring

7% Casinghead Gas Venting and Flaring

10% Other Categories

3%

Compressor engines

1% Pneumatic devices

10%

Pneumatic pumps

12%

Venting - recompletions

1%

Unpermitted Fugitives

3%

Condensate tank

8%

Oil Tank

23% Oil Well Truck Loading

7% Casinghead Gas Venting and Flaring

30% Other Categories

4%

### July 2013

Final Report 

## 33 **Table 8.** 2015 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) 79 178 129 0 1 Custer (MT) 120 28 104 0 3 Daniels (MT) 2 112 4 0 0 Dawson (MT) 99 1,383 108 0 8 Fallon (MT) 1,798 24,357 2,943 45 97 Garfield (MT) 5 112 6 0 0 McCone (MT) 121 187 65 0 2 Prairie (MT) 4 238 4 0 0 Richland (MT) 4,488 75,047 10,633 15 208 Roosevelt (MT) 1,174 10,743 1,524 112 88 Sheridan (MT) 441 9,004 1,009 0 28 Valley (MT) 1,573 4,813 1,494 30 73 Wibaux (MT) 37 2,218 36 0 2 Barnes (ND) 316 6 24 10 20 Billings (ND) 1,808 18,505 3,388 1,216 51 Bottineau (ND) 1,189 15,018 1,908 1 105 Bowman (ND) 1,111 44,884 1,499 1 43 Burke (ND) 889 10,601 1,433 191 65 Burleigh (ND) 63 17 60 0 0 Divide (ND) 853 7,147 1,456 0 74 Dunn (ND) 4,615 33,667 8,113 11 385 Golden Valley (ND) 187 2,560 411 0 11 McHenry (ND) 365 382 38 10 20 McIntosh (ND) 134 17 134 7 10 McKenzie (ND) 5,919 49,616 9,035 1,552 274 McLean (ND) 196 635 238 0 22 Mercer (ND) 56 32 55 0 7 Morton (ND) 386 77 444 21 21 Mountrail (ND) 10,611 95,234 22,775 1 701 Renville (ND) 337 7,221 620 0 23 Slope (ND) 36 2,721 49 0 3 Stark (ND) 597 4,478 880 0 10 Stutsman (ND) 28 10 42 0 0 Ward (ND) 128 507 149 0 15 Williams (ND) 6,161 27,813 5,476 3,822 210 Butte (SD) 12 2 11 0 1 Harding (SD) 176 4,874 186 0 15 **TOTAL 46,114 454,443 76,480 7,046 2,596** Daniels, (MT) (Tribal) 2 94 3 0 0 Roosevelt, (MT) (Tribal) 342 5,259 606 89 41 Sheridan, (MT) (Tribal) 2 143 6 0 0 Valley, MT (Tribal) 54 2,075 95 0 4 Dunn, ND (Tribal) 667 2,829 951 0 70 McKenzie, ND (Tribal) 112 876 168 0 11 McLean, ND (Tribal) 196 635 238 0 22 Mountrail, ND (Tribal) 2,345 17,868 4,541 0 187 **TOTAL (Tribal) 3,720**  **29,779 6,609**  **90 335**  Daniels, (MT) (Non-Tribal) 0 17 0 0 0 Roosevelt, (MT) (Non-Tribal) 832 5,484 919 23 47 Sheridan, (MT) (Non-Tribal) 438 8,861 1,003 0 28 Valley, MT (Non-Tribal) 1,519 2,738 1,399 30 69 Dunn, ND (Non-Tribal) 3,948 30,838 7,163 11 315 McKenzie, ND 5,807 48,740 8,866 1,552 264

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## 34 **County NOx**  **[tons/yr] VOC**  **[tons/yr] CO**  **[tons/yr] SOx**  **[tons/yr] PM**  **[tons/yr]** (Non-Tribal) McLean, ND (Non-Tribal) 0 0 0 0 0 Mountrail, ND (Non-Tribal) 8,266 77,367 18,233 1 514

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## 35 **Table 9.** 2015 NOx emissions by county and 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) 75 0 2 2 1 0 0 0 79 Custer (MT) 119 0 0 0 0 0 0 0 120 Daniels (MT) 0 0 1 0 0 0 0 0 2 Dawson (MT) 55 20 6 5 5 2 0 6 99 Fallon (MT) 1,046 204 129 109 82 38 0 190 1,798 Garfield (MT) 2 0 1 1 0 0 0 0 5 McCone (MT) 117 0 1 1 1 0 0 0 121 Prairie (MT) 0 0 1 1 1 0 0 0 4 Richland (MT) 887 297 174 147 1,307 612 846 218 4,488 Roosevelt (MT) 750 130 33 28 107 50 69 6 1,174 Sheridan (MT) 12 93 39 33 122 57 79 6 441 Valley (MT) 1,298 186 33 28 9 4 6 9 1,573 Wibaux (MT) 1 0 11 9 9 4 0 1 37 Barnes (ND) 316 0 0 0 0 0 0 0 316 Billings (ND) 752 37 85 72 335 157 217 154 1,808 Bottineau (ND) 1 649 97 82 164 77 106 12 1,189 Bowman (ND) 672 99 51 43 160 10 0 77 1,111 Burke (ND) 114 353 69 59 116 55 75 48 889 Burleigh (ND) 63 0 0 0 0 0 0 0 63 Divide (ND) 29 501 26 22 128 60 83 4 853 Dunn (ND) 331 2,560 71 60 747 350 484 12 4,615 Golden Valley (ND) 9 56 12 10 47 22 31 2 187 McHenry (ND) 353 0 3 3 3 1 2 0 365 McIntosh (ND) 134 0 0 0 0 0 0 0 134 McKenzie (ND) 2,350 1,429 161 136 768 360 498 218 5,919 McLean (ND) 1 167 3 3 10 5 7 0 196 Mercer (ND) 0 56 0 0 0 0 0 0 56 Morton (ND) 386 0 0 0 0 0 0 0 386 Mountrail (ND) 549 4,434 94 80 2,553 1,196 1,653 52 10,611 Renville (ND) 1 93 54 46 65 30 42 7 337 Slope (ND) 5 20 2 2 5 0 0 3 36 Stark (ND) 333 19 13 11 104 49 67 2 597 Stutsman (ND) 28 0 0 0 0 0 0 0 28 Ward (ND) 0 111 3 3 5 2 3 0 128 Williams (ND) 4,024 835 86 73 427 200 277 238 6,161 Butte (SD) 0 12 0 0 0 0 0 0 12 Harding (SD) 28 86 19 16 22 1 0 3 176 **TOTAL 14,839 12,444 1,281 1,086 7,305 3,345 4,545 1,269 46,114** Daniels, (MT) (Tribal) 0 0 0 0 0 0 0 0 2 Roosevelt, (MT) (Tribal) 221 37 12 11 28 13 18 2 342 Sheridan, (MT) (Tribal) 0 0 0 0 1 0 1 0 2 Valley, MT (Tribal) 0 19 8 7 9 4 6 1 54

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## 36 **County Compressor**  **Engines Drill**  **Rigs Heaters**  **Miscellaneous Engines**  **Artificial Lift Engines**  **Oil Tank Flaring**  **Casinghead Gas Flaring**  **Other Categories**  **Totals** Dunn, ND (Tribal) 7 520 4 4 62 29 40 1 667 McKenzie, ND (Tribal) 5 74 4 3 12 6 8 1 112 McLean, ND (Tribal) 1 167 3 3 10 5 7 0 196 Mountrail, ND (Tribal) 35 1,280 21 18 467 219 302 3 2,345 **TOTAL (Tribal) 270 2,097 53 45 590 276 382 8 3,720** Daniels, (MT) (Non-Tribal) 0 0 0 0 0 0 0 0 0 Roosevelt, (MT) (Non-Tribal) 529 93 21 18 79 37 51 5 832 Sheridan, (MT) (Non-Tribal) 12 93 39 33 121 57 78 6 438 Valley, MT (Non-Tribal) 1,298 167 25 21 0 0 0 8 1,519 Dunn, ND (Non-Tribal) 324 2,041 67 57 685 321 443 11 3,948 McKenzie, ND (Non-Tribal) 2,344 1,354 157 133 757 354 490 218 5,807 McLean, ND (Non-Tribal) 0 0 0 0 0 0 0 0 0 Mountrail, ND (Non-Tribal) 513 3,154 74 62 2,086 977 1,351 49 8,266

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## 37 **Table 10.** 2015 VOC emissions by county and 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) 62 74 3 22 0 13 3 0 2 178 Custer (MT) 10 12 0 4 0 0 0 0 1 28 Daniels (MT) 19 23 3 7 0 50 2 8 0 112 Dawson (MT) 203 241 20 70 3 650 24 0 171 1,383 Fallon (MT) 4,462 5,290 448 1,545 16 10,222 375 0 1,999 24,357 Garfield (MT) 41 49 2 14 0 4 1 0 0 112 McCone (MT) 31 38 4 11 0 10 2 10 80 187 Prairie (MT) 41 49 4 14 0 124 5 0 1 238 Richland (MT) 5,830 7,129 843 2,081 12 24,126 5,964 25,063 3,999 75,047 Roosevelt (MT) 1,118 1,368 162 399 0 4,814 489 2,054 340 10,743 Sheridan (MT) 1,316 1,611 190 470 4 2,334 555 2,333 190 9,004 Valley (MT) 1,105 1,353 160 394 0 1,125 43 181 451 4,813 Wibaux (MT) 384 456 39 133 0 1,155 42 0 9 2,218 Barnes (ND) 0 0 0 0 0 0 0 0 6 6 Billings (ND) 2,844 3,481 411 1,015 73 2,205 1,528 6,421 528 18,505 Bottineau (ND) 3,247 3,975 469 1,159 324 1,080 749 3,146 869 15,018 Bowman (ND) 1,759 2,089 177 609 18,740 19,885 730 0 894 44,884 Burke (ND) 2,328 2,850 337 831 167 767 531 2,233 557 10,601 Burleigh (ND) 0 0 0 0 0 0 0 0 17 17 Divide (ND) 888 1,087 128 317 482 840 582 2,446 377 7,147 Dunn (ND) 2,391 2,926 346 853 1,432 4,921 3,410 14,330 3,060 33,667 Golden Valley (ND) 391 479 57 140 0 310 215 903 65 2,560 McHenry (ND) 106 129 15 38 0 19 13 54 9 382 McIntosh (ND) 0 0 0 0 0 0 0 0 17 17 McKenzie (ND) 5,390 6,597 779 1,924 7,348 5,060 3,506 14,734 4,280 49,616 McLean (ND) 106 129 15 38 0 67 46 194 40 635 Mercer (ND) 6 8 1 2 0 1 1 4 9 32 Morton (ND) 0 0 0 0 0 0 0 0 77 77 Mountrail (ND) 3,167 3,876 458 1,130 1,720 16,809 11,648 48,949 7,477 95,234 Renville (ND) 1,807 2,212 261 645 222 426 295 1,241 112 7,221 Slope (ND) 67 79 7 23 1,856 632 23 0 34 2,721 Stark (ND) 441 540 64 157 0 684 474 1,991 128 4,478 Stutsman (ND) 0 0 0 0 0 0 0 0 10 10 Ward (ND) 99 122 14 35 0 34 24 100 77 507 Williams (ND) 2,900 3,549 419 1,035 4,566 2,814 1,950 8,195 2,385 27,813 Butte (SD) 0 0 0 0 0 0 0 0 2 2 Harding (SD) 670 796 67 232 152 2,709 99 0 150 4,874 **TOTAL 43,230 52,616 5,903 15,348 37,116 103,890 33,329 134,590 28,422 454,443** Daniels, (MT) (Tribal) 12 15 2 4 0 50 2 8 0 94 Roosevelt, (MT) (Tribal) 416 509 60 148 0 3,358 129 541 97 5,259

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## 38 **County Pneumatic** 
**Devices Pneumatic**  **Pumps Recompletion**  **Venting Fugitives**  **Condensate**
**Tanks Oil Tanks**  **Oil Well**
**Truck Loading**  **Casinghead**
**Gas Venting**  **Other Categories**  **Totals** Sheridan, (MT) (Tribal) 6 8 1 2 0 105 4 17 1 143 Valley, MT (Tribal) 261 319 38 93 0 1,125 43 181 15 2,075 Dunn, ND (Tribal) 149 182 22 53 0 411 285 1,197 531 2,829 McKenzie, ND (Tribal) 130 160 19 47 0 78 54 226 163 876 McLean, ND (Tribal) 106 129 15 38 0 67 46 194 40 635 Mountrail, ND (Tribal) 695 851 101 248 0 3,074 2,130 8,951 1,818 17,868 **TOTAL (Tribal) 1,776 2,174 257 634 0 8,268 2,693 11,315 2,664 29,779** Daniels, (MT) (Non-Tribal) 6 8 1 2 0 0 0 0 0 17 Roosevelt, (MT) (Non-Tribal) 702 859 101 250 0 1,456 360 1,513 243 5,484 Sheridan, (MT) (Non-Tribal) 1,310 1,604 189 468 4 2,229 551 2,316 189 8,861 Valley, MT (Non-Tribal) 844 1,034 122 301 0 0 0 0 436 2,738 Dunn, ND (Non-Tribal) 2,242 2,744 324 800 1,432 4,510 3,125 13,133 2,529 30,838 McKenzie, ND (Non-Tribal) 5,259 6,437 760 1,877 7,348 4,982 3,452 14,507 4,117 48,740 McLean, ND (Non-Tribal) 0 0 0 0 0 0 0 0 0 0 Mountrail, ND (Non-Tribal) 2,471 3,025 357 882 1,720 13,736 9,518 39,998 5,659 77,367

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## 39 **REFERENCES**

Bar-Ilan, A., J. Grant, R. Parikh, 2013. “Development of Baseline 2009 Emissions from Oil and Gas Activity in the Williston Basin.” Prepared for Western Governors’ Association. Prepared by ENVIRON International Corporation, Novato, CA. In progress.

Bar-Ilan, A., J. Grant, R. Parikh, A. Pollack, D. Henderer, D. Pring, K. Sgamma, 2009a. “Development of Baseline 2006 Emissions from Oil and Gas Activity in the North San Juan Basin.” Prepared for Western Governors’ Association. Prepared by ENVIRON International Corporation, Novato, CA. http://www.wrapair.org/forums/ogwg/documents/NSanJuanBasin/2009- 09_06_Baseline_and_12_Midterm_Emissions_N_San_Juan_Basin_Technical_Memo_09-01.pdf



## Bar-Ilan, A., R. Friesen, R. Parikh, J. Grant, A. Pollack, D. Henderer, D. Pring, K. Sgamma, 2009b. “Development of Baseline 2006 Emissions from Oil and Gas Activity in the Uinta Basin.” Prepared for Western Governor’s Association. Prepared by ENVIRON International Corporation, Novato, CA. http://www.wrapair.org/forums/ogwg/documents/2009- 03_06_Baseline_Emissions_Uinta_Basin_Technical_Memo_03-25.pdf

Bar-Ilan, A., J. Grant, R. Parikh, A. Pollack, D. Henderer, D. Pring, K. Sgamma, 2009c. “Development of Baseline 2006 Emissions from Oil and Gas Activity in the Piceance Basin.” Prepared for Western Governor’s Association. Prepared by ENVIRON International Corporation, Novato, CA. http://www.wrapair.org/forums/ogwg/documents/2009- 01_06_Baseline_Emissions_Piceance_Basin_Technical_Memo_01-20.pdf



## Bar-Ilan, A., J. Grant, R. Parikh, A. Pollack, D. Henderer, D. Pring, K. Sgamma, 2009d. “Development of 2012 Oil and Gas Emissions Projections in the Piceance Basin.” Prepared for Western Governor’s Association. Prepared by ENVIRON International Corporation, Novato, CA. http://www.wrapair.org/forums/ogwg/documents/2009- 01_12_Projection_Emissions_Piceance_Basin_Technical_Memo_01-21.pdf



## Bar-Ilan, A., J. Grant, R. Friesen, A. Pollack, D. Henderer, D. Pring, K. Sgamma, 2008.“Development of Baseline 2006 Emissions from Oil and Gas Activity in the DenverJulesburg Basin.” Prepared for Western Governor’s Association. Prepared by ENVIRON International Corporation, Novato, CA. http://www.wrapair.org/forums/ogwg/documents/2008- 04_%2706_Baseline_Emissions_DJ_Basin_Technical_Memo_(04-30).pdf



## EPA, 2012 “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews,” U.S. Environmental Protection Agency, Research Triangle Park, NC, April. http://www.epa.gov/airquality/oilandgas/pdfs/20120417finalrule.pdf

EPA, 2008 “Standards of Performance for Stationary Spark Ignition Internal Combustion Engines and National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines; Final Rule,” U.S. Environmental Protection Agency, Research Triangle Park, NC, January.

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## 40 EPA, 2006. “Direct Final Rule and Notice of Proposed Rulemaking for Amendments to the Nonroad and Highway Diesel Fuel Regulations,” U.S. Environmental Protection Agency, Research Triangle Park, NC, April. http://www.epa.gov/otaq/regs/fuels/diesel/420f06033.pdf



## EPA, 2005. Nonroad Diesel Equipment Regulations/Standards , U.S. Environmental Protection Agency, July 7, 2005. Research Triangle Park, NC. http://www.epa.gov/nonroaddiesel/regulations.htm

Pollack, A., L. Chan, P. Chandraker, J. Grant, C. Lindhjem, S. Rao, J. Russell, C. Tran, 2006. “WRAP Mobile Emission Inventories Update.” Prepared for Western Governors’ Association. May.