Assessment of Water and Proppant Quantities Associated with 

Petroleum Production from the Bakken and Three Forks Formations, 

Williston Basin Province, Montana and North Dakota, 2016

Extending and building on a geology-based assessment of undiscovered, technically recoverable petroleum resources in the Bakken and 

Three Forks Formations of the Williston Basin Province in Montana and North Dakota, the U.S. Geological Survey has estimated the water 

and proppant demands and water-production volumes associated with possible future development of those petroleum resources. The water 

and proppant assessment results are presented here, along with related drilling information and relevant water budget volumes for the region.

Introduction

The U.S. Geological Survey (USGS) has completed an assessment 

of water and proppant requirements and water production associated 

with the possible future production of undiscovered oil and gas resources 

in the Three Forks and Bakken Formations (Late Devonian to Early 

Mississippian) of the Williston Basin Province in Montana and North 

Dakota (fig. 1). This water and proppant assessment is directly linked to 

the geology-based assessment of the undiscovered, technically recoverable continuous oil and gas resources that is described by Gaswirth and 

others (2013), and it is the first of its kind conducted by the USGS.

The production of oil and gas from continuous accumulations, 

such as the Bakken and Three Forks Formations, is commonly made 

possible by hydraulic fracturing stimulation, which involves pumping 

fluids containing water and proppant (granular material, often sand, 

that is intended to hold open the newly generated fractures) into the 

petroleum reservoir to improve fluid-flow characteristics. Water is also 

used during the process of drilling a production well and cementing 

the well casing in place, and the horizontal wells that are often (but not 

always) involved with producing petroleum from continuous reservoirs 

typically require larger water volumes for drilling and cement than 

comparable vertical wells. When petroleum production commences, 

water is generally produced along with oil and gas. This produced water 

includes hydraulic fracturing water, which returns as “flowback water” 

early in the life of the well, and “formation water,” which resides in or 

adjacent to the petroleum reservoir formation and is produced throughout the duration of petroleum production.

Between the time of the 2013 petroleum assessment (Gaswirth 

and others, 2013) and this water and proppant assessment (conducted in 

2016 using data current up to August 2016), more than 6,000 additional 

production wells have been drilled in the Bakken and Three Forks 

Formations involving at least 22 billion gallons of water and 12 million 

tons of proppant used for hydraulic fracturing. Between January 2013 

and August 2016, approximately 42 billion gallons of water, along with 

1.3 billion barrels of oil, have been produced from these two formations.

Assessment Approach and Input Values

The USGS methodology for assessing the water and proppant 

requirements and water production associated with possible future 

production of oil and gas from continuous accumulations is described 

by Haines (2015). The methodology incorporates many elements of the 

USGS assessment approach for continuous petroleum accumulations 

(Charpentier and Cook, 2010), including estimated ultimate recovery 

of petroleum per well (EUR) and the input values and calculations for 

estimating the number of wells potentially associated with production of 

the petroleum in each assessment unit (AU). In addition, the water and 

proppant assessment methodology includes input values for the water 

per well for drilling and cement and for hydraulic fracturing treatment, 

the proppant-to-water ratio for hydraulic fracturing, the percentage of 

hydraulic fracturing water that returns as flowback, and the long-term 

water-to-oil or water-to-gas ratio. The long-term produced water-topetroleum ratio represents formation water (water that exists along with 

petroleum in the geologic formation) and the volume of water exceeding 

this ratio during the first few months after hydraulic fracturing is considered to be flowback water. A Monte Carlo approach provides probabilistic outputs based on probabilistic inputs (Haines, 2015). 

This 2016 water and proppant assessment for the Bakken and 

Three Forks Formations incorporates the geologic information in 

the 2013 assessment of oil and gas in the Bakken and Three Forks 

Formations (Gaswirth and others, 2013; Gaswirth and Marra, 2015), 

and it uses the same values for EUR and the inputs that are part of the 

well count calculation. Gaswirth and others (2013) defined six AUs that 

CANADA

SOUTH

DAKOTA

MONTANA

NORTH

DAKOTA

WYOMING

97°98°99°100°101°102°103°104°105°106°107°108°

49°

48°

47°

46°

45°

44°

Source: U.S. Department of the Interior National Park Service

EXPLANATION

Elm Coulee-Billings Nose Continuous 

 Oil AU

Central Basin Continuous Oil AU

Nesson-Little Knife Continuous Oil AU

Eastern Transitional Continuous Oil AU

Northwest Transitional Continuous 

 Oil AU

Three Forks Continuous Oil AU

Williston Basin Province boundary

Bakken Total Petroleum System

CANADA

MONTANA

WYOMING

NORTH

DAKOTA

SOUTH 50 MILES DAKOTA

0

0

50 KILOMETERS

Figure 1. Map showing the Williston Basin Province, Bakken Total 

Petroleum System (TPS), the five Bakken continuous assessment 

units (AUs), and the Three Forks Formation continuous AU (these six 

AUs are all part of the Bakken TPS) in Montana and North Dakota. 

Modified from Gaswirth and others (2013).

U.S. Department of the Interior

U.S. Geological Survey Printed on recycled paper

Fact Sheet 2017–3044

June 2017
are part of the Bakken Total Petroleum System: five continuous AUs 

for the Bakken Formation and one continuous AU for the Three Forks 

Formation (fig. 1). The 2013 petroleum assessment also included hypothetical conventional AUs for additional areas of the Bakken and Three 

Forks Formations, but those are not included in this water and proppant 

assessment because the water and proppant assessment methodology 

applies only to continuous petroleum resources.

We determined input values for the water and proppant assessment 

using analysis of data relating to water and proppant use and water production for the Bakken and Three Forks Formations from IHS MarkitTM

(2016) and data provided by the North Dakota Industrial Commission. 

All inputs are specified as ranges of possible values, rather than as single 

fixed values, to allow quantification of uncertainty throughout the assessment process. Selected assessment input values are shown in table 1.

Several assessment inputs describe quantities whose specific 

values are driven by technical choices made by oil and gas production 

companies. These inputs were assigned the same values for all AUs 

(table 1) based on the observation that similar technologies are being 

employed throughout the entire assessment area. Based on analysis of 

water use for hydraulic fracturing of wells producing from the Bakken 

and Three Forks Formations (IHS Markit, 2016), the water requirement 

per well for hydraulic fracturing treatment was estimated as a range that 

has a mean value of 4.17 million gallons. From the same data source, 

the proppant-to-water ratio for hydraulic fracturing treatments was 

estimated to have a mean value of 1.2 pounds of proppant per gallon of 

water. Based on trends reported for similar wells, the water requirement 

per well for drilling and cement was estimated to have a mean value 

of 150,000 gallons; data describing actual water use for the drilling 

and cementing of wells producing from the Bakken and Three Forks 

Formations are limited.

Monthly water and oil production data (IHS Markit, 2016) allow 

estimation of two different input values as described by Haines (2015): 

(1) the percent of hydraulic fracturing fluid that returns to the surface as 

flowback and (2) the long-term water-to-oil ratio for production over the 

life of the well. Based on spatial and temporal analysis of all available 

data for wells producing from the Bakken and Three Forks Formations, 

the input value indicating the percentage of hydraulic fracturing fluid 

that returns as flowback water was estimated to be the same for all AUs 

with a mean value of 6 percent. The long-term water-to-petroleum ratio 

was specified uniquely for each AU and for sweet-spot and non-sweetspot areas within each AU because this parameter is tied closely to 

reservoir characteristics, which vary considerably across the province. 

Geologic sweet spots were defined by Gaswirth and others (2013), and 

maps of the sweet spots are shown by Gaswirth and Marra (2015).

Water and Proppant Assessment Results 

and Supporting Information

Results from the 2016 USGS water and proppant assessment are 

shown in table 2. All assessment outputs are distributions that indicate 

the range of possible values and the table summarizes these with the 

95th fractile (F95), 50th fractile or median (F50), 5th fractile (F5), and 

the mean value. Summing over all AUs, the mean estimated total water 

for drilling and cement is 5.9 billion gallons, the mean estimated water 

for hydraulic fracturing is 164.3 billion gallons, the mean estimated 

quantity of proppant for hydraulic fracturing is 101.3 million tons, the 

mean estimated total flowback water volume is 9.9 billion gallons, and 

the mean estimated total produced water is 414.5 billion gallons.

The fundamental assessment outputs (table 2) are estimates of the 

total water and proppant requirements and total water production associated with development of the entire undiscovered petroleum resource in 

the Bakken and Three Forks Formations of the Williston Basin Province. 

Future extraction of this oil resource, if it occurs, would take place with a 

rate and timing that are unknown. Table 3 provides additional information intended to help users understand questions involving the rate of oil 

development on an annual basis (the basis on which most water planning 

occurs). Specifically, the table shows the reported number of oil and gas 

wells drilled annually within each AU from 2011 to 2015 (IHS Markit, 

2016) and estimated quantities of water and proppant associated with 

different scenarios for possible drilling rates. These water and proppant 

volume estimates are based on the mean values of the associated assessment input distributions.

To provide context for the water volumes in tables 2 and 3, 

table 4 shows water quantities for other parts of the hydrologic system 

within each AU. These include the total water produced as part of oil 

and gas production (IHS Markit, 2016), total surface water and groundwater withdrawals (Maupin and others, 2014), and water use in four 

Table 1. Selected input values for the water and proppant assessment. The “long-term produced water ratio” and flowback water volume 

are defined and discussed by Haines (2015).

[AU, assessment unit; Mgal, million gallons; lb/gal, pound per gallon; %, percent; bbl, barrel]

Assessment input value Minimum Mode Maximum Calculated mean

Inputs common among all AUs, for geologic sweet-spot and non-sweet-spot areas

Water per well, for hydraulic fracturing treatment (Mgal) 2.5 4.0 6.0 4.17

Proppant-to-water ratio, for hydraulic fracturing (lb/gal) 1.0 1.2 1.5 1.2

Water per well, for drilling and cement (Mgal) 0.10 0.15 0.20 0.15

Fraction of hydraulic fracturing treatment volume that returns as flowback water (%) 1 5 12 6

Inputs specified separately for each AU

Elm Coulee-Billings Nose Continuous Oil AU

Long-term produced water ratio, for geologic sweet-spot areas (bbl water per bbl oil) 0.3 0.4 0.8 0.5

Long-term produced water ratio, for non-sweet-spot areas (bbl water per bbl oil) 1.0 1.3 2.0 1.43

Central Basin Continuous Oil AU

Long-term produced water ratio, for geologic sweet-spot areas (bbl water per bbl oil) 0.75 0.90 1.20 0.95

Long-term produced water ratio, for non-sweet-spot areas (bbl water per bbl oil) 1.2 1.5 1.8 1.5

Nesson-Little Knife Continuous Oil AU

Long-term produced water ratio, for geologic sweet-spot areas (bbl water per bbl oil) 0.30 0.50 0.65 0.48

Long-term produced water ratio, for non-sweet-spot areas (bbl water per bbl oil) 0.8 1.2 1.6 1.2

Eastern Transitional Continuous Oil AU

Long-term produced water ratio, for geologic sweet-spot areas (bbl water per bbl oil) 0.25 0.4 1.1 0.58

Long-term produced water ratio, for non-sweet-spot areas (bbl water per bbl oil) 1.5 2.0 3.5 2.3

Northwest Transitional Continuous Oil AU

Long-term produced water ratio, for geologic sweet-spot areas (bbl water per bbl oil) 1.5 2.5 5.0 3.0

Long-term produced water ratio, for non-sweet-spot areas (bbl water per bbl oil) 2.0 4.0 6.0 4.0

Three Forks Continuous Oil AU

Long-term produced water ratio, for geologic sweet-spot areas (bbl water per bbl oil) 0.8 1.0 1.5 1.1

Long-term produced water ratio, for non-sweet-spot areas (bbl water per bbl oil) 1.5 2.0 3.5 2.3
Table 2. Assessment results showing resource requirements and production associated with production of continuous petroleum deposits 

in the Bakken Total Petroleum System, Williston Basin Province, Montana and North Dakota.

[F95 represents a 95-percent chance of at least the amount tabulated; other fractiles are defined similarly. Mgal, million gallons. Gray shading indicates not applicable]

Total petroleum system 

and assessment units (AUs)

Field 

type

Estimated total requirement/production

Water for drilling (Mgal) Water for hydraulic fracturing (Mgal)

F95 F50 F5 Mean F95 F50 F5 Mean

Bakken Total Petroleum System

Elm Coulee-Billings Nose Continuous Oil AU Oil 262 337 427 339 7,190 9,364 11,988 9,440

Central Basin Continuous Oil AU Oil 703 846 1,014 851 19,364 23,522 28,433 23,657

Nesson-Little Knife Continuous Oil AU Oil 576 698 840 701 15,864 19,391 23,580 19,511

Eastern Transitional Continuous Oil AU Oil 401 500 622 504 10,892 13,880 17,674 14,023

Northwest Transitional Continuous Oil AU Oil 152 330 568 341 4,197 9,159 15,880 9,481

Three Forks Continuous Oil AU Oil 1,486 2,968 5,535 3,176 41,248 82,537 153,924 88,208

Estimated total requirement/production 5,912 164,320

Total petroleum system

and assessment units (AUs)

Proppant for hydraulic fracturing (103 tons) Flowback water (Mgal) Produced water (Mgal)

F95 F50 F5 Mean F95 F50 F5 Mean F95 F50 F5 Mean

Bakken Total Petroleum System

Elm Coulee-Billings Nose Continuous Oil AU 4,341 5,751 7,549 5,822 290 546 910 566 9,175 12,703 17,482 12,927

Central Basin Continuous Oil AU 11,626 14,473 17,958 14,590 770 1,385 2,177 1,419 45,538 56,981 71,097 57,477

Nesson-Little Knife Continuous Oil AU 9,541 11,928 14,864 12,032 638 1,142 1,804 1,171 27,091 35,793 46,205 36,119

Eastern Transitional Continuous Oil AU 6,534 8,531 11,158 8,647 401 805 1,397 841 48,792 68,838 98,977 70,740

Northwest Transitional Continuous Oil AU 2,574 5,629 9,866 5,846 208 520 1,092 569 12,021 27,804 53,593 29,681

Three Forks Continuous Oil AU 25,185 50,759 95,469 54,392 1,967 4,751 10,512 5,291 92,650 192,666 374,596 207,572

Estimated total requirement/production 101,329 9,857 414,516

Table 3. Historical number of wells drilled in each assessment unit (AU) during each of the indicated years and quantities of water and 

proppant use and water production potentially associated with various possible future annual drilling rates.

[Mgal, million gallons. Gray shading indicates not applicable]

Total petroleum system 

and assessment units (AUs)

Field 

Type

Historical drilling

(number of wells drilled each year)1

 Co-requirements and co-production 

for various possible annual drilling totals

2011 2012 2013 2014 2015

10 wells

Required

water

(Mgal)

Required

proppant

(103

 tons)

Flowback 

water

(Mgal)

Bakken Total Petroleum System

Elm Coulee-Billings Nose Continuous Oil AU Oil 28 73 87 79 24 43 26 3

Central Basin Continuous Oil AU Oil 392 593 476 515 346 43 26 3

Nesson-Little Knife Continuous Oil AU Oil 360 464 506 532 428 43 26 3

Eastern Transitional Continuous Oil AU Oil 189 226 210 155 86 43 26 3

Northwest Transitional Continuous Oil AU Oil 16 47 24 24 23 43 26 3

Three Forks Continuous Oil AU Oil 288 575 806 949 639 43 26 3

Total 1,273 1,978 2,109 2,254 1,546

Total petroleum system 

and assessment units (AU)

 Co-requirements and co-production for various possible annual drilling totals

100 wells 1,000 wells 5,000 wells

Required 

water 

(Mgal)

Required

proppant

(103

 tons)

Flowback

water

(Mgal)

Required 

water 

(Mgal)

Required 

proppant 

(103 tons)

Flowback 

water 

(Mgal)

Required 

water 

(Mgal)

Required 

proppant 

(103 tons)

Flowback 

water 

(Mgal)

Bakken Total Petroleum System

Elm Coulee-Billings Nose Continuous Oil AU 432 257 25 4,317 2,569 250 21,583 12,844 1,250

Central Basin Continuous Oil AU 432 257 25 4,317 2,569 250 21,583 12,844 1,250

Nesson-Little Knife Continuous Oil AU 432 257 25 4,317 2,569 250 21,583 12,844 1,250

Eastern Transitional Continuous Oil AU 432 257 25 4,317 2,569 250 21,583 12,844 1,250

Northwest Transitional Continuous Oil AU 432 257 25 4,317 2,569 250 21,583 12,844 1,250

Three Forks Continuous Oil AU 432 257 25 4,317 2,569 250 21,583 12,844 1,250

1

From IHS MarkitTM (2016).

categories: (1) agriculture (including use for irrigation, livestock, and 

aquaculture), (2) industrial (including mining and self-supplied industrial 

use), (3) municipal (public supply and self-supplied domestic use), and 

(4) thermoelectric (Maupin and others, 2014). Each of these volumes 

is the total production, withdrawal, or use within the map area of each 

AU. Because the Three Forks Continuous Oil AU spatially overlaps 

the Bakken continuous AUs (the Three Forks Formation underlies the 

Bakken Formation), the water quantities indicated for the Three Forks 

Continuous Oil AU are also included within the overlying Bakken 

Continuous Oil AUs.

Table 5 provides information to facilitate comparisons between 

the Bakken and Three Forks AUs and comparisons between these AUs 

and areas to be studied in future USGS water and proppant assessments. 

Listed in the table are the estimated water and proppant requirements, 

and flowback water and total produced water production, per barrel 

of undiscovered, technically recoverable oil in each AU. Each of these 

numbers is based on the mean value of the relevant distributions, and 

for completeness, the mean value of the estimated undiscovered oil 

resources in each AU (Gaswirth and others, 2013) is also shown.

Acknowledgments

The authors thank Karen Jenni, Cheryl Woodall, and 

Katie Walton-Day (USGS) for helpful comments and discussions 

and Dave Hvinden and Dave McCusker (North Dakota Industrial 

Commission) for discussion and providing hydraulic fracturing data.
Table 4. Water quantities produced, withdrawn, and used for various purposes within the area of each assessment unit (AU). Note that 

because the Three Forks Continuous Oil AU occupies the same map area as the other AUs, the water quantities listed for the Three Forks 

Continuous Oil AU include the quantities listed for the other AUs.

[Mgal, million gallons]

Total petroleum system 

and assessment units (AU)

Oil/gas total produced water1

(mean annual production, 

2011–2015, total for all producing 

formations within AU map area) 

(Mgal)

Surface water2 Groundwater2

Water use2

(annual total, 2010)

Withdrawal

(annual total, 2010)

(Mgal)

Withdrawal

(annual total, 2010)

(Mgal)

Agriculture

(Mgal)

Industrial

(Mgal)

Municipal

(Mgal)

Thermoelectric

(Mgal)

Bakken Total Petroleum System

Elm Coulee-Billings Nose Continuous Oil AU 1,191 60,760 1,289 53,681 656 394 7,318

Central Basin Continuous Oil AU 4,018 49,740 4,863 50,072 905 1,307 2,319

Nesson-Little Knife Continuous Oil AU 4,360 4,587 2,563 5,421 1,185 544 0

Eastern Transitional Continuous Oil AU 1,793 10,584 1,166 1,169 879 429 9,272

Northwest Transitional Continuous Oil AU 914 18,387 6,765 24,082 450 620 0

Three Forks Continuous Oil AU 14,687 485,359 29,525 182,259 11,580 10,109 310,937 1

From IHS MarkitTM (2016). 2

From Maupin and others (2014).

Table 5. Water demand and production and proppant demand per unit of undiscovered, technically recoverable petroleum based on mean 

values of the assessment outputs. The bottom row of this table shows the mean value across all six assessment units, weighted by the volume 

of undiscovered, technically recoverable oil.

[mmbo, million barrels of oil; Mgal, million gallons. Gray shading indicates not applicable]

Total petroleum system

and assessment units (AUs)

Field 

type

Total

undiscovered oil1

(mmbo)

Water

requirement per oil

(Mgal/mmbo)

Proppant

requirement per oil

(103 tons/mmbo)

Flowback water

production per oil

(Mgal/mmbo)

Total produced

water per oil

(Mgal/mmbo)

Mean Mean Mean Mean Mean

Bakken Total Petroleum System

Elm Coulee-Billings Nose Continuous Oil AU Oil 283 35 21 2.0 46

Central Basin Continuous Oil AU Oil 1,122 22 13 1.3 51

Nesson-Little Knife Continuous Oil AU Oil 1,149 18 10 1.0 31

Eastern Transitional Continuous Oil AU Oil 883 16 10 1.0 80

Northwest Transitional Continuous Oil AU Oil 207 47 28 2.7 143

Three Forks Continuous Oil AU Oil 3,731 24 15 1.4 56

Weighted mean 23 14 1.3 56

1

From Gaswirth and others (2013).

References Cited

Charpentier, R.R., and Cook, T.A., 2010, Improved USGS methodology for assessing continuous petroleum resources (ver. 2.0, November 9, 

2012): U.S. Geological Survey Data Series 547, 22 p. and program, accessed May 31, 2017, at https://pubs.usgs.gov/ds/547/.

Gaswirth, S.B., and Marra, K.R., 2015, U.S. Geological Survey 2013 assessment of undiscovered resources in the Bakken and Three Forks 

Formations of the U.S. Williston Basin Province: AAPG Bulletin, v. 99, no. 4, p. 639–660.

Gaswirth, S.B., Marra, K.R., Cook, T.A, Charpentier, R.R., Gautier, D.L., Higley, D.K., Klett, T.R., Lewan, M.D., Lillis, P.G., Schenk, C.J., 

Tennyson, M.E., and Whidden, K.J., 2013, Assessment of undiscovered oil resources in the Bakken and Three Forks Formations, Williston 

Basin Province, Montana, North Dakota, and South Dakota, 2013: U.S. Geological Survey Fact Sheet 2013–3013, 4 p., accessed May 31, 

2017, at https://pubs.usgs.gov/fs/2013/3013/.

Haines, S.S., 2015, Methodology for assessing quantities of water and proppant injection, and water production associated with development 

of continuous petroleum accumulations: U.S. Geological Survey Open-File Report 2015–1117, 18 p., accessed May 31, 2017, at 

https://doi.org/10.3133/ofr20151117.

IHS MarkitTM, 2016, US Well History and Production Database: Englewood, Colo., IHS MarkitTM, accessed August 2016 at 

http://www.ihsenergy.com. [Available from IHS MarkitTM, 15 Inverness Way East, Englewood, CO 80112.]

Maupin, M.A., Kenny, J.F., Hutson, S.S., Lovelace, J.K., Barber, N.L., and Linsey, K.S., 2014, Estimated use of water in the United States 

in 2010: U.S. Geological Survey Circular 1405, 56 p., accessed May 31, 2017, at https://doi.org/10.3133/cir1405.

For More Information

Assessment results are available at the USGS Energy Resources Program website at https://energy.usgs.gov.

Bakken and Three Forks Water and Proppant Assessment Team

Seth S. Haines, Brian A. Varela, Sarah J. Hawkins, Nicholas J. Gianoutsos, Joanna N. Thamke, Mark A. Engle, Marilyn E. Tennyson, 

Christopher J. Schenk, Stephanie B. Gaswirth, Kristen R. Marra, Scott A. Kinney, Tracey J. Mercier, and Cericia D. Martinez

ISSN 2327-6916 (print) ISSN 2327-6932 (online) https://doi.org/10.3133/fs20173044