BAKKEN WATER OPPORTUNITIES 

ASSESSMENT – PHASE 1 

Final Report Summary 

(for the period of June 19, 2009, through March 15, 2010) 

Prepared for: 

Karlene Fine 

North Dakota Industrial Commission 

Oil and Gas Research Council 

600 East Boulevard Avenue 

State Capitol, 14th Floor 

Bismarck, ND 58505-0840 

Contract No. G018-036 

Prepared by: 

Daniel J. Stepan 

Richard E. Shockey 

Bethany A. Kurz 

Nicholas S. Kalenze 

Robert M. Cowan 

Joshua J. Ziman 

John A. Harju 

Energy & Environmental Research Center 

University of North Dakota 

15 North 23rd Street, Stop 9018 

Grand Forks, ND 58202-9018 

2010-EERC-04-03 April 2010 
NDIC DISCLAIMER 

 This report was prepared by the Energy & Environmental Research Center (EERC) 

pursuant to an agreement partially funded by the Industrial Commission of North Dakota, and 

neither the EERC nor any of its subcontractors nor the North Dakota Industrial Commission nor 

any person acting on behalf of either: 

(A) Makes any warranty or representation, express or implied, with respect to the 

accuracy, completeness, or usefulness of the information contained in this report or 

that the use of any information, apparatus, method, or process disclosed in this report 

may not infringe privately owned rights; or 

(B) Assumes any liabilities with respect to the use of, or for damages resulting from the 

use of, any information, apparatus, method, or process disclosed in this report. 

 Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the North Dakota Industrial Commission. The views and 

opinions of authors expressed herein do not necessarily state or reflect those of the North Dakota 

Industrial Commission. 

DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United 

States Government. Neither the United States Government, nor any agency thereof, nor any of 

their employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The views 

and opinions of authors expressed herein do not necessarily state or reflect those of the United 

States Government or any agency thereof. 

This report is available to the public from the National Technical Information Service, U.S. 

Department of Commerce, 5285 Port Royal Road, Springfield, VA 22161; phone orders 

accepted at (703) 487-4650. 

EERC DISCLAIMER

 LEGAL NOTICE This research report was prepared by the EERC, an agency of the 

University of North Dakota, as an account of work sponsored by North Dakota Industrial 

Commission. Because of the research nature of the work performed, neither the EERC nor any of 

its employees makes any warranty, express or implied, or assumes any legal liability or 
responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed or represents that its use would not infringe privately owned rights. 

Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement 

or recommendation by the EERC. 
i 

TABLE OF CONTENTS 

LIST OF FIGURES ........................................................................................................................ ii 

LIST OF TABLES ......................................................................................................................... iii 

PROJECT SUMMARY ................................................................................................................. iv 

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

OBJECTIVE ................................................................................................................................... 1 

RESULTS AND DISCUSSION ..................................................................................................... 2

Task 1 – Current Water Use Practices .................................................................................. 2

Task 2 – Flowback Water Characteristics ............................................................................. 5

General Description of Hydraulic Fracturing .............................................................. 5

Flowback Water Quantity ............................................................................................ 8

Flowback Water Quality ............................................................................................ 10

Task 3 – Current Water-Handling Costs ............................................................................. 17 

Task 4 – Review of Flowback Water-Recycling Technologies .......................................... 17 

Thermal Treatment .................................................................................................... 18

Membrane Treatment ................................................................................................. 22

Task 5 – Flowback Water Treatment Technology Assessment .......................................... 23

Task 6 – Recommendations for Phase 2 Project Deployment ............................................ 24

Task 7 – Information Dissemination Activities .................................................................. 26

REFERENCES ............................................................................................................................. 27 

BAKKEN FRAC FLOWBACK WATER SALINITY-VERSUSTIME PLOTS................................................................................................................. Appendix A 

CUMULATIVE FLOWBACK PLOTS FOR HYDRAULIC 

FRACTURE EVENTS WITH KNOWN INJECTION VOLUMES ......................... Appendix A-1 

CUMULATIVE FLOWBACK PLOTS FOR HYDRAULIC FRACTURE 

EVENTS WITH ASSUMED INJECTION VOLUME OF 23,000 bbl ..................... Appendix A-2 

BAKKEN FRAC FLOWBACK WATER SALINITY VERSUS 

TIME DATA PLOTS .................................................................................................... Appendix B

CHARGE BALANCE ERROR ..................................................................................... Appendix C 

WATER USE FACT SHEET ........................................................................................ Appendix D 
ii 

LIST OF FIGURES 

1 Existing and proposed water depots as of March 2010 ......................................................... 3 

2 Locations of Bakken oil wells where frac flowback data and information were 

 used in the assessment ........................................................................................................... 6 

3 Cumulative flowback of oil and water for a typical hydraulic fracture event ....................... 8 

4 Conductivity and TDS versus flowback water volume, Producer A .................................. 11 

5 Salinity versus flowback water volume, Producer B .......................................................... 11 

6 Salinity versus flowback water volume, Producer C .......................................................... 12 

7 Salinity versus flowback water volume, Producer E ........................................................... 12 

8 Major ion distribution for wells in Table 4 ......................................................................... 14 

9 Changes in specific constituent concentration in frac flowback water versus time ............ 16 

10 Applicability of various desalination technologies ............................................................. 16 

11 AltelaRain process diagram ................................................................................................ 19 

12 Aqua-Pure mechanical vapor recompression technology process diagram ........................ 20 

13 212 Resources vapor compression process flow diagram ................................................... 21 

14 Frac flowback water storage impoundment ........................................................................ 23 

15 Pretreatment system consisting of coagulation/flocculation, settling, and filter press ....... 24 

16 Aqua-Pure Nomad 2000 mechanical vapor recompression unit ......................................... 25 

17 Water samples: frac flowback, treated water, and MVR concentrate ................................. 25
iii 

LIST OF TABLES 

1 Summary of Data Types Collected ....................................................................................... 7 

2 Summary of Flowback Quantity for Producers A, B, C, and E ............................................ 9 

3 Summary of Flowback Quantity for Producer D ................................................................ 10 

4 Flowback Water Chemical Analytical Results on Three Select Wells ............................... 13 

5 Analytical Results for Producer A, Well 2, Samples Versus Time ..................................... 15 

6 Water-Handling Costs ......................................................................................................... 17 
iv 

BAKKEN WATER OPPORTUNITIES ASSESSMENT – PHASE 1 

PROJECT SUMMARY 

The Energy & Environmental Research Center (EERC) Northern Great Plains Water 

Consortium (NGPWC) identified a potential opportunity to economically treat and reuse water 

that is used in hydraulic fracturing operations in the Bakken oil formation in North Dakota. The 

Bakken Water Opportunities Assessment project was undertaken with funding provided by the 

North Dakota Industrial Commission Oil and Gas Research Council, the North Dakota 

Petroleum Council, and the U.S. Department of Energy. The project compiled information on the 

current water use practices for hydraulic fracturing (frac) in the Bakken play, collected and 

analyzed frac flowback water data from five different oil producers operating at various locations 

in the Bakken, assessed potentially applicable mobile fracture water-recycling technologies, 

worked with industry to disseminate information about the project, and developed 

recommendations and plans for a Phase 2 evaluation. 

Traditional sources of freshwater for hydraulic fracturing include glacial and bedrock 

aquifer systems, surface waters, and municipal supplies. The continued use of these sources to 

satisfy the increasing demand for freshwater will not be practical if future demands are to be met. 

The largest source of freshwater in the Bakken play is Lake Sakakawea, but access to this supply 

and its proximity to future drilling and fracturing activities make the lake less desirable as a longterm supply. 

Treatment and recycling of frac flowback water was investigated as a means to reduce the 

demand for freshwater and provide a supplemental supply near drilling and fracturing activities. 

The character of the frac flowback water with respect to both quantity and quality presented 

significant challenges for widespread water-recycling opportunities. A relatively small 

percentage (17% to 47%) of the water used in hydraulic fracturing in the Bakken is typically 

recoverable in a reasonable time (2 to 10 days). Further, the dissolved solids levels in the frac 

flowback water increase rapidly and to levels as high as 220,000 mg/L. These factors provide 

significant challenges for developing cost-effective treatment strategies, even with the most 

robust technologies. While there will certainly be niche opportunities using certain technologies 

to recycle frac flowback water, widespread recycling will not likely be economically viable. 

The regional and national importance of providing sufficient volumes of water for such an 

extremely high-value use cannot be overstated. These water supplies will need to come from a 

variety of resources. One opportunity is to upgrade marginal-quality groundwater resources to 

satisfy a portion of the demand. An evaluation of a membrane technology for the treatment of 

nonpotable groundwater to supply water for hydraulic fracturing in the same geographic area is 

being conducted as a Phase 2 Bakken Water Opportunities Assessment project. 
1 

BAKKEN WATER OPPORTUNITIES ASSESSMENT – PHASE 1 

INTRODUCTION 

 Water is the most critical limiting resource throughout the world. Sufficient quantities of 

good-quality water are needed for several competing uses, including energy production, growing 

and processing high-value crops, industrial manufacturing, and expanding populations. The 

Northern Great Plains Water Consortium (NGPWC) is a partnership between the Energy & 

Environmental Research Center (EERC), the U.S. Department of Energy (DOE), and key 

stakeholders representing oil and gas companies, power generation utilities, industry, 

municipalities, and other entities interested in addressing critical water issues in the north-central 

United States. The primary goal of the NGPWC is to assess, develop, and demonstrate 

technologies and methodologies that minimize water use and reduce impacted water discharges 

from a range of energy technologies, including coal combustion, coal gasification, coalbed 

methane, and oil and natural gas production. 

 The NGPWC identified a potential opportunity to economically recover and reuse water 

that is used in the oil field to pressurize and fracture oil-bearing formations to increase 

permeability and enhance the flow and recovery of oil. In North Dakota’s Bakken play, water 

used in hydraulic fracturing ranges from approximately 10,000 to 60,000 barrels (bbl) (0.5 to 

3 million gallons), depending on the number of stages in the fracture. Multistage fractures, which 

require more water than single-stage fractures, are increasingly being employed in the Bakken 

Formation because they generate fractures more effectively. 

 Relatively low-total-dissolved-solids and bacteria-free water is required for hydraulic 

fracturing. Typically, the freshwater comes from glacial and bedrock aquifer systems, surface 

waters, and municipal supplies. The use of municipal supplies can have a profound effect on 

small community water supplies, many of which have a relatively low treatment capacity. The 

additional demand on shallow groundwater systems can also have a significant impact, 

particularly on small glacial channel aquifers that have low recharge rates. 

 Recycling the water used to hydraulically fracture oil wells could have a positive effect on 

available resources, conserving the supply for other beneficial uses. Fracture water is typically 

hauled to the well site in 7500- to 8000-gallon (180- to 190-bbl) tanker trucks. Once the 

formation fracturing is completed, the water flows back (frac flowback) as the pressure in the 

well is released. After sand removal and oil recovery, the frac flowback water is typically 

disposed of via deep-well injection. Transportation costs, particularly for long haul distances, can 

be excessive for both freshwater and flowback water. Treatment and reuse of frac flowback 

water may be an extremely attractive economic alternative to disposal via deep-well injection. 

OBJECTIVE 

 The overall goal of the project was to provide industry with data and information on the 

technical and economic potential to recycle frac flowback water. Specific Phase 1 objectives 
2 

included 1) gathering data on current water use practices, 2) investigating flowback water quality 

with respect to time and location, 3) assessing current water-handling costs, 4) assessing the use 

of water-recycling technologies and evaluating technical and economic suitability for application 

to Bakken Formation flowback water, 5) evaluating the current state of existing water-recycling 

technologies, 6) developing plans for a full-scale field evaluation at a host Bakken location, and 

7) information dissemination. 

RESULTS AND DISCUSSION 

Task 1 – Current Water Use Practices 

 There are different types of fracture fluids used in the Bakken play, and each has a 

different formulation. While fracture fluids can range from water to slickwater to gels, they 

require freshwater as a makeup fluid. This ensures the ability of individual producers to develop 

consistency in the composition of the fracturing fluid and the desired fracture results. 

 Common freshwater acquisition points for frac fluid makeup are from existing water 

depots and municipalities. Figure 1 depicts the location of existing and proposed water depots, as 

well as the permitted (or requested) water allocation at each location. While some municipalities 

have extra capacity to provide water to the oil industry, they must first request an industrial 

permit from the North Dakota State Water Commission (SWC), and it should be noted that the 

additional available capacity would still not meet all of the industry needs. 

 In response to the increasing demand for freshwater, SWC has received numerous permit 

applications for additional groundwater appropriation for withdrawals at existing water depots as 

well as permit applications for new water wells. Prescribed permitting procedures require a 

published public notice, followed by a 30-day comment period. New permit applications are 

being contested by environmental groups, which results in significant delays in the overall 

permitting process. Permits that would normally be issued within a 70- to 90-day period are 

taking in excess of 9 months. 

 SWC is also concerned about mining of fresh groundwater resources, specifically surficial 

glacial aquifers (which are of limited extent in western North Dakota) and the Fox Hills–Hell 

Creek Aquifer. The Fox Hills–Hell Creek Aquifer is a widespread, reliable artesian aquifer. 

Because it is artesian and flows at the surface, it provides a valuable supply of water for remote 

areas with no electricity for pumping. However, over the past several decades, the hydraulic 

pressure of the formation has been declining as a result of the large number of wells that are 

withdrawing water from the formation (Honeyman, 2007). SWC estimates that at the current rate 

of decline in hydraulic pressure, wells screened in the Fox Hills–Hell Creek Formation will stop 

flowing within the next 100 years (Honeyman, 2007). Because of the low recharge rate of the 

Fox Hills–Hell Creek Aquifer, SWC is reluctant to permit new appropriations for withdrawals 

from this formation, particularly for industrial use. 
3 

Figure 1. Existing and proposed water depots as of March 2010 

(Source: North Dakota State Water Commission). 
4 

 With the exception of the Missouri River system, most surface waters in the Bakken region 

do not provide a reliable source of water because of seasonal flow variations. Sufficient flows 

exist only in the spring of the year, during periods of snowmelt. Given the concerns over mining 

of surficial aquifers, groundwater-permitting issues, and the relative lack of surface water 

supplies in many areas of the state, SWC is encouraging the oil industry to seek withdrawals 

from the Missouri River System for use in Bakken development. However, there are several 

issues related to using Lake Sakakawea water, key among them being access to the lake and 

proximity of the resource to drilling locations. 

 

 While SWC handles water appropriations from the lake, permission for access at a 

particular point of diversion must be granted by the U.S. Army Corps of Engineers (Corps). This 

creates additional delays in accessing the resource because having to obtain permission from 

multiple agencies can slow the permitting process. In addition, it is not yet clear where access to 

the lake may or may not be allowed because of the potential disturbance of cultural sites and/or 

threatened and endangered species. SWC is working with the Corps and the U.S. Fish and 

Wildlife Service to identify corridors of access to the lake for industrial purposes and to publish 

access maps. It is unclear at this time when these maps will be available. 

 It is interesting to note that in late 2009 and early 2010, several permit applications were 

submitted to SWC for allocations exceeding 1000 acre-feet from Lake Sakakawea. These 

requests are primarily to supply water to the oil industry. The largest requested appropriation of 

24,000 acre-feet was made by International Western Company, a Texas-based company, which 

has identified four proposed points of diversion on Lake Sakakawea (each at a requested 

appropriation of 6000 acre-feet) from which it is planning to pump water into a series of small 

reservoirs interconnected by underground pipeline (International Western Company, personal 

communication, February 2010). The reservoirs will be strategically located near areas of drilling 

activity, including locations south of Tioga, northwest and southwest of New Town, and north of 

Dodge. 

 The city of Dodge is also in the process of applying for a permit to allow its additional 

water capacity to be used for the oil industry. It currently estimates that it has an additional 

capacity of nearly 1500 acre-feet from the appropriation that it receives via the Southwest 

Pipeline project. 

 While there are some projects in the works that will improve the availability of freshwater 

resources for use in Bakken development, in the near-term, there appears to be a significant 

water shortage. The Missouri River System has more than enough water available for Bakken 

development, but preferred access points to the lake are still undefined by the Corps. 

Additionally, there will be high costs associated with long transportation distances from the lake 

to new drilling locations. Given the current need for water, coupled with high water acquisition, 

transportation, and disposal costs, nontraditional options for water supplies may be viable, such 

as municipal wastewater treatment or treatment of nonpotable groundwater resources. 
5 

Task 2 – Flowback Water Characteristics 

 Task 2 was designed to identify information and collect new data regarding the quantity 

and quality of Bakken play hydraulic fracture flowback water. The hope was that sufficient data 

could be collected to evaluate the effect of geographic, geologic, and hydraulic fracture 

characteristics (e.g., water frac, gel frac, slickwater frac, length of shut-in) on the quantity and 

quality of water recovered. These quantity and quality data could then be used to help assess the 

potential for treatment and reuse of the water in additional hydraulic fracture events. 

 Five different companies that practice hydraulic fracturing in the Bakken participated in 

this assessment by providing frac flowback water information and data from a total of 89 wells 

(Figure 2). While the data were extensive, they were not comprehensive. Table 1 presents a 

summary of the data collected. The data varied in detail with respect to quantity and quality, with 

portions of the data set lacking the information critical for a detailed and accurate assessment but 

adequate for use as a basis in making generalized conclusions. Water samples from several frac 

flowback events were sent to a contract laboratory for detailed chemical analysis to document 

water quality changes over time and flowback volume. EERC personnel attended the flowback 

event from one long-shut-in time hydraulic fracture event. Very little flowback water was 

recovered during the flowback period, and the system was quickly converted from flowback to 

production mode because the well was producing mostly oil. Samples collected during that 

flowback period were also submitted for detailed chemical analysis. 

 This section of the report presents representative data concerning flowback water quantity, 

flowback water quality, and a generalized interpretation of what the quantity and quality 

information collected suggests regarding the potential for Bakken hydraulic frac flowback water 

treatment and reuse. 

General Description of Hydraulic Fracturing 

 After wells have been drilled, a well field service company comes in with large waterholding tanks and pumps. Water is brought in (usually by tanker truck) to fill the water tanks. 

This water is mixed with sand (proppant) and chemicals (e.g., surfactants, gels, oil) and injected 

at a high flow rate and pressure into the formation in order to hydraulically fracture the 

formation. This opens channels in the formation and increases the near-field porosity to provide 

flow paths for the oil. The fluid pumped into the formation may be pumped in all at once (singlestage fracture) or in several stages (multistage fracture) over a period of one to several days (up 

to five is common). The fluid is then shut in for a period of time before it is allowed to flow 

back. The length of time from finishing the fracturing process to the start of flowback can be as 

short as 4 hours (no shut-in) to as long as 30 days. The most common shut-in procedures seem to 

be none, overnight, and over-the-weekend shut-in times. 

 After the shut-in period is over, the fracture fluid is allowed to flow back out of the 

formation. In the Bakken, this typically occurs without the need for pumping because of the 

formation pressure and residual pressure associated with fracturing operations; hence, pumping 

in the Bakken is not required. The material that comes out of the well during flowback includes 

residual proppant (sand), water (enriched in dissolved salts from the formation), oil, and gas. The 
6 

Figure 2. Locations of Bakken oil wells where frac flowback data and information were used in 

the assessment. 
7 

Table 1. Summary of Data Types Collected

Company 

Frac Fluid 

Volume 

Flowback 

Volume 

Flowback 

Salinity or 

TDS 

Detailed 

Chemistry Location 

ClosedIn Time 

or Frac 

Water 

Contact 

Time 

Number 

of Wells 

A Estimated Versus 

time 

Salinity Yes X 

B Known 

(three of 

five wells) 

Versus 

time 

TDS1 X 5 

C Estimated Versus 

time 

Salinity 

and TDS 

Yes X 30 days 

D Known Total and 

initial 

volume to 

TDS 

cutoff 

Only as 

cutoff at 

TDS = 

60,000 

ppm 

 X 62 in 10 

areas 

E2 Known Versus 

time 

Salinity X 4 hours 

to 7 

days 

4 

E3 Unknown Unknown TDS Major 

ions, 

hardness 

X 7 

1 Total dissolved solids. 2 Service Provider A performed hydraulic fracture. 3

 Service Provider B performed hydraulic fracture. 

sand and gas are typically separated from the oil and water in a cyclone or gravity separator, and 

the gas is utilized on-site, sent to a gas-processing facility, or flared. The oil and water are 

separated in an API (American Petroleum Institute) oil–water separator. The water is collected in 

a pit and/or in fracture tanks used to hold the water prior to the fracture event. The water 

collected during flowback is the focus of this investigation. The oil is sent to the production 

separators (heater–treaters) for the removal of any remaining water and collected in tanks in 

preparation for shipping to a refinery. Because the Bakken Formation has little to no free water, 

any water collected over time with the oil might be considered flowback because its origin was 

likely the fracture event. However, operationally, the period of flowback is considered over when 

the well operation switches to a normal production mode. The actual fraction of water in the 

produced fluid that is consistent with the end of flowback might vary from operator to operator 

but, commonly, it can be considered to occur when the liquid well product contains less than 

25% water. 
8 

Flowback Water Quantity 

 Flowback consists of both water and oil. Initially, frac flowback is water, but the amount 

of oil in the flowback increases over time. The relative amount of oil in the flowback typically 

dictates the length of flowback operations and, thus, the corresponding period of time when 

water recovery may be feasible based on the relative amount of water in the flowback. Figure 3 

presents frac flowback data from a selected well. The figure shows cumulative total flowback 

(oil plus water), cumulative water flowback, cumulative oil flowback, the volume of frac water 

not recovered, and the percent of oil in a grab sample of flowback versus time. In the example, 

12,775 bbl of water was injected during hydraulic fracturing, and the duration of the flowback 

period was approximately 45 hours, at which time the well was switched to a production mode. 

At that point, the total flowback contained 63% oil and 37% water. The water recovered during 

the flowback period represented 33% of the total used in the fracturing process. 

 Flowback quantity data, similar to those presented in Figure 3, were obtained for a total of 

12 wells from data provided from four of the participating producers. The volume of freshwater 

used in the fracturing was known for seven of those wells. For the other five wells, a frac water 

volume of 23,000 bbl was assumed. Plots of these data (similar to Figure 3) are provided in 

Appendices A-1 (known frac fluid volume) and A-2 (assumed 23,000 bbl frac fluid volume). 

Additional flowback quantity data were provided for 62 additional wells, but the nature of those 

data did not allow for a similar analysis. Data from these wells will be discussed later. 

Figure 3. Cumulative flowback of oil and water for a typical hydraulic fracture event. Flowback 

continued until the proportion of oil in the fluid being produced was 63%. At that point, 33% of 

the injected water had been recovered. 
9 

 Table 2 summarizes the flowback water quantity data, including fracture fluid volume, the 

duration of flowback, and percent water recovery at the end of flowback, as well as statistical 

information (maximum, minimum, mean, median, standard deviation) for four of the producers. 

The observed flowback periods ranged from around 2 days to as long as 10 days, with a median 

time of almost 2 days and an average of 3 days. During the first 24 hours of flowback, the 

amount of water recovered ranged from as little as 3% to as much as 26%, with a median value 

of 12%. At the end of the flowback period (as indicated by the end of flowback data collection 

by the producer), flowback water recovery ranged from 5% to 41% of the fracture water injected, 

with a median value of 17%. 

 Table 3 summarizes flowback water recovery information from data provided for 62 wells 

from a single producer. These data were originally provided as barrels of water recovered that 

had TDS levels of less than 60,000 ppm and barrels of water at the end of the flowback period 

and the duration of flowback. The flowback period for this producer ranged from nearly 31⁄2 to 

almost 18 days, with a median flowback period of just over 91⁄2 days, much longer than those 

reported by the other producers. The percentage of water recovered ranged from 7% to 75% of 

the original fracture water injected, with a median value of 47%, which was also higher than 

typical values of the other producers. The water recovered with TDS <60,000 mg/L represented 

0% to 39% of the injected volume, with a median of 5%. Five of the 62 wells produced no water 

with salinity levels under 60,000 ppm, and the median well produced only 974 bbl of water at 

less than 60,000 mg/L of TDS, which represented 5% of the injected water volume for that well. 

Overall, of the 1,088,590 bbl of water injected during fracturing operations, only 10.5% 

(114,172 bbl) was recovered at a salinity of less than 60,000 mg/L. 

Table 2. Summary of Flowback Quantity for Producers A, B, C, and E 

Producer Well 

Fracture Fluid 

Volume 

Length of 

FlowBack 

Water Recovered 

in 24 hours 

Cumulative Water 

Recovered 

 bbl hours % of injected % of injected 

A 1 23,000 124.0 3 13 

 2 23,000 120.0 4 9 

B 1 19,105 95.0 25 41 

 2 19,007 95.5 23 33 

 3 19,106 93.5 22 36 

C 1 23,000 36.5 4 5 

 2 23,000 33.5 7 8 

 3 23,000 37.5 4 5 

E 1 8326 36.0 16 21 

 2 12,775 45.2 25 33 

 3 52,000 44.0 4 6 

 4 13,065 36.0 26 30 

 Minimum 33.5 3 5 

 Maximum 124.0 26 41 

 Median 44.6 12 17 

 Mean 66.4 14 20 

 Standard Deviation 36.0 10 14
10 

Table 3. Summary of Flowback Quantity for Producer D 

Fluid 

Pumped, bbl 

Duration of 

Flowback, 

days 

Flowback Water 

with TDS 

<60,000 mg/L , % 

Total Flowback 

Water Recovered, 

% 

Minimum 10,966 3.42 0 7 

Maximum 36,333 17.75 39 75 

Median 17,476 9.58 5 47 

Mean 17,587 9.92 12 45 

Standard Deviation 4417 3.21 12 16

 In general, the volume of water recovered in the flowback is significantly less than what 

was originally anticipated. The reason for the low initial water recovery is not readily 

understood, but can be attributed in part to the formation being oil-wet (little to no free formation 

water), and the water being retained in the fracture and pore space and in spaces where salts were 

dissolved by frac water. Based on the available data, it was not possible to develop a correlation 

between flowback water recovery and shut-in time, nor was it possible to develop any correlation 

between well location and the amount of flowback water recovered. While the water may be 

recovered over a long period of time with continued oil production, the amount of water that can 

be readily recovered and recycled in a timely manner is typically a relatively small percentage of 

the original water used to fracture the formation. This will significantly impact the widespread 

economic viability of frac flowback water recycling in the Bakken play. The low recovery of 

water, however, will reduce the overall cost for disposal by reducing the total volume requiring 

disposal. 

Flowback Water Quality 

 Oil producers typically measure frac flowback water quality in terms of salinity using a 

refractometer. Salinity and/or conductivity levels of flowback water versus time were provided 

by four of the five participating producers, and one of the producers provided data in terms of 

water recovered with salinity levels less than 60,000 ppm. Selected samples of frac flowback 

water over time from two of the producers were submitted to contract laboratories for a more 

detailed chemical characterization. A third producer provided concentration data for major ions. 

 Figures 4–7 illustrate dissolved solids content of the flowback water versus flowback water 

throughout the flowback period. Figure 3 presents the data in terms of specific conductance and 

TDS concentration calculated as the sum of measure ion concentrations, and the other figures 

show salinity values. There is a wide range in the concentration of dissolved salts in the frac 

flowback water, not only between different producers, but among different wells of a single 

producer (Figure 7). These data show that the flowback water salinity values typically range 

from 60,000 ppm to over 200,000 ppm. Values around 100,000 ppm are typical, and levels 

greater than 200,000 ppm are not uncommon. Very little frac flowback was shown to have 

salinity levels less than 60,000 ppm. Additional plots of salinity versus time of flowback are 

provided in Appendix B. The data in Appendix B are from the same flowback events as the data 

in Appendix A. 
11 

Figure 4. Conductivity and TDS versus flowback water volume, Producer A. 

Figure 5. Salinity versus flowback water volume, Producer B. 
12 

Figure 6. Salinity versus flowback water volume, Producer C. 

Figure 7. Salinity versus flowback water volume, Producer E. 
13 

 Detailed chemical composition data were collected on selected flowback water samples 

from three of the producers participating in the project. Characterization results from 

representative samples collected at a time around 3500 bbl of cumulative total flowback are 

listed in Table 4, with the major ion concentrations compared graphically in Figure 8. All 

analyses were confirmed to have charge balance errors (CBE) of less than ±5% (see explanation 

of CBE in Appendix C). Sodium chloride (NaCl) is the dominant salt comprising 91.1%, 89.8%, 

and 95.0% of the TDS in the Producer A, C, and E well flowback waters, respectively. Calcium 

is present at concentration ranges between 7540 and 13,500 mg/L. Other ions detected at 

concentrations of 1000 ppm or greater in at least one sample are magnesium, potassium, 

strontium, and sulfate. Boron, bicarbonate, and iron were each detected at concentrations above 

100 ppm in at least one sample. The pH was found to be mildly acidic, ranging from 5.47 in the 

sample from Producer E to 6.53 in the sample from Producer A. 

 Table 4. Flowback Water Chemical Analytical Results on Three Select Wells 

Producer/Well A/2 C/2 E/ 

Total Flowback, bbl 3688 3283 Unknown 

Water Flowback, bbl 2090 1611 Unknown 

Charge Balance Error, % 1.74 −0.752 −0.220 

Cations/Conc. mg/L mg/L mg/L 

Calcium (Ca) 8010 13,500 7540 

Barium (Ba) 7 24.6 0 

Magnesium (Mg) 630 1440 1750 

Iron (Fe) ND1 72 120 

Potassium (K) 3140 5770 0 

Sodium (Na) 47,100 62,700 74,600 

Phosphorus (P) ND 0.03 NR2

Silica (Si) 7 6.41 NR 

Strontium (Sr) 518 1010 NR 

Boron (B) 192 39.9 NR 

Manganese (Mn) 4 10.2 NR 

Copper (Cu) ND 0.21 NR 

Molybdenum (Mo) ND <0.2 NR 

Zinc (Zn) 2 11.3 NR 

Aluminum (Al) ND <1 NR 

Anions/Conc. mg/L mg/L mg/L 

Sulfate 680 300 1000 

Chloride 90,000 133,000 133,000 

Bicarbonate 122 140 610 

Other Measurements 

pH 6.53 5.62 5.47 

Specific Gravity 1.0961 1.155 1.14 

Specific Cond., mS/cm 205 220.8 NR 

TDS (calculated), mg/L 150,000 218,000 219,000 1

 Not detected, 

2

 Not reported. 
14 

Figure 8. Major ion distribution for wells in Table 4. 

 Table 5 presents detailed chemical characterization data over time during the flowback 

period from Producer A, Well 2 (Figure 3). Figure 9 shows the changes in specific ion 

concentration and illustrates increasing concentration with time during the flowback period. 

 The very high TDS levels in the Bakken frac flowback water will present a significant 

treatment challenge. Figure 10 presents information on the applicability of desalination 

technologies over a range of TDS concentrations. Traditional desalination technologies such as 

reverse osmosis (RO) typically are capable of treating waters with TDS levels up to 

40,000 mg/L. Thermal treatment technologies such as mechanical vapor recompression (MVR) 

are more applicable to treating high-TDS waters, such as those found in certain Bakken flowback 

situations, particularly if MVR is coupled with pretreatment to reduce the concentration of 

divalent ions typically associated with scaling. Even with pretreatment, the very high sodium 

chloride in Bakken flowback water will require special consideration of metallurgy for treatment 

components. Expensive metals such as titanium that are resistant to corrosion and chloride stress 

corrosion will be required for high-temperature thermal recovery processes treating chloride 

Bakken flowback water. 
15 

Table 5. Analytical Results for Producer A, Well 2, Samples Versus Time 

Sample No. 1 2 3 4 5 

Total Cumulative 

Flowback Water, bbl 

54 487 633 2778 3688 

CBE, % 5.35 −1.54 1.03 0.418 1.74 

Cations/Conc. mg/L mg/L mg/L mg/L mg/L 

Calcium (Ca) 105 3496 5350 6740 8010 

Barium (Ba) <1 2 5 6 7 

Magnesium (Mg) 36 290 425 537 630 

Iron (Fe) 3 8 40 ND ND 

Potassium (K) 28 1816 2466 2790 3138 

Sodium (Na) 540 22,285 33,225 40,980 47,080 

Phosphorus (P) 18 2 2 ND ND 

Silica (Si) 12 16 16 8 7 

Strontium (Sr) 4 225 351 441 518 

Boron (B) 1 102 147 174 192 

Manganese (Mn) <1 3 4 4 4 

Copper (Cu) ND ND ND ND ND 

Molybdenum (Mo) ND ND ND ND ND 

Zinc (Zn) ND ND ND 1 2 

Aluminum (Al) ND ND ND ND ND 

Anions/Conc. mg/L mg/L mg/L mg/L mg/L 

Sulfate 627 688 742 719 681 

Chloride 500 45,000 64,000 80,000 90,000 

Bicarbonate 244 229 183 151 122 

Other Measurements 

pH 7.11 6.98 6.92 6.66 6.53 

Specific Gravity 1.0010 1.0495 1.0696 1.0860 1.0961 

Specific Cond., mS/cm 3 102 149 182 205 
16 

Figure 9. Changes in specific constituent concentration in frac flowback water versus time. 

Figure 10. Applicability of various desalination technologies. 
17 

Task 3 – Current Water-Handling Costs 

 Cost data were provided by several of the participating producers. The reported costs of 

current water handling for hydraulic fracturing can vary significantly, depending on acquisition 

costs, transportation costs (including wait time), and disposal costs. Table 6 lists a range of 

current water-handling costs for Bakken fracture water. The cost to purchase raw water ranged 

from $0.25/bbl up to $1.75/bbl, and the cost of transporting that water to the fracture location 

ranged from $0.63/bbl up to an estimated $5.00/bbl. Transportation costs represented the highest 

level of variability in water acquisition costs and depend on several factors, including trucking 

charges, haul distances, and wait time. Trucking charges were reported to range from $110 to 

$150/hr, and the charges that are incurred during wait time are included in the overall 

transportation costs. The costs for deep-well injection ranged from $0.50/bbl to $1.75/bbl. Again, 

transportation costs were the most significant cost for disposal, and the higher overall 

transportation costs were associated with long wait times to unload at a disposal facility. It is 

unlikely that water-handling costs would consistently be as high as $16/bbl, but considering that 

transportation costs represent anywhere from 56% to 84% of the total water-handling costs, an 

assessment of the economic potential of frac flowback water recycling is justified. Recycling 

could reduce the overall transportation and disposal costs through a reduction in the amount of 

water that would require disposal. 

Table 6. Water-Handling Costs 

Cost, $/bbl 

Acquisition Costs 

 Raw Water $0.25–$1.05 

 Transportation $0.63–$5.00 

Disposal Costs

 Transportation $0.63–$9.00 

 Deep-Well Injection $0.50–$1.75 

Total Costs $2.00–$16.80 

Task 4 – Review of Flowback Water-Recycling Technologies 

 A review of available literature and Internet searches revealed that frac flowback waterrecycling technologies were in various stages of development. These technologies, however, 

were being evaluated for use in treating frac flowback from natural gas-bearing shale formations 

such as the Barnett and Marcellus shales. Because the Bakken Formation contains oil-wet rock 

with little to no free water, the chemical composition of the flowback water is very different 

from the natural gas shales. Bakken flowback waters are more highly concentrated with salts 

than are comparable gas formations. Preliminary Bakken flowback water data collected early in 

the study showed relatively low concentrations of salts in the flowback water, albeit at relatively 

low volumes, but there still appeared to be a limited opportunity for recycling. 

 Treatment of Bakken flowback water will require extremely robust technologies built on 

highly mobile platforms. Based on the character of the Bakken flowback water, the most 
18 

applicable technologies include thermal or membrane processes coupled with pretreatment to 

reduce levels of scale-forming constituents. Pretreatment will be required of any technology 

treating Bakken frac flowback water. 

Thermal Treatment 

 Thermal treatment uses heat to distill high-salt-content water to steam, which is condensed 

into clean water. The process also produces a lower-volume concentrate, or brine stream. 

Thermal treatment processes have high energy input requirements, which would normally make 

it economically impractical for the treatment of frac flowback water. However, the use of 

associated gas that would normally be flared early in flowback operations to power thermal 

treatment processes makes distillation an economical alternative. 

 Several companies offer thermal treatment processes for the treatment of flowback and 

produced waters. Thermal treatment technology vendors in this assessment included 

AltelaRainSM, Aqua-Pure, and 212 Resouces. 

AltelaRain 

 AltelaRain desalinates and decontaminates water using a low-pressure, low-temperature 

countercurrent-flow evaporation/condensation process (Figure 11). Altela claims this 

configuration provides 3 gallons of treated water from the same amount of heat energy that 

would normally be required to produce 1 gallon of water through a 300% energy reuse. 

Individual Altela treatment units process about 8 barrels per day (bpd), but units can be deployed 

in parallel when treating larger volumes of water (Veil, 2008). The standard Altela system ARS4000 is delivered in a single, portable 45- × 8-foot shipping container and has been used to treat 

4000 gallons/day (~100 bpd) of produced water in New Mexico. Altela systems can operate on 

low-grade waste heat or wellhead natural gas. This reportedly lowers Altela’s operating costs 

relative to high-pressure, high-electricity-cost technologies such as RO and mechanical vacuum 

compression (MVC). The system reportedly uses no pressure, high temperatures, filters, or 

membranes, allowing it to be manufactured from plastics rather than metals. The applicability of 

the technology to Bakken flowback water is very uncertain. 

Aqua-Pure 

 Fountain Quail Water Management (FQWM) is a technology service provider that 

developed the Nomad mobile evaporator platform based on Aqua-Pure’s patented process 

(Figure 12). The following process description was taken from Aqua-Pure’s Web site 

(www.aqua-pure.com, 2010): 

 Mechanical Vapour Recompression (MVR) Evaporation is an energy efficient 

process that produces pure distilled water from wastewater containing dissolved 

solids. With evaporation, pure water is boiled from wastewater and can be later 

condensed as distilled water. The dissolved solids remain in solution and are 

removed from the system as concentrated blowdown. In an MVR Evaporator, a 
19 

Figure 11. AltelaRain process diagram (www.altelainc.com, 2010). 

compressor is used to add the energy required to boil water. The feedwater passes 

through two preheat exchangers where sensible heat is absorbed from the distillate 

and concentrate products leaving the system. The feed then passes through a deaerator column where dissolved gases are vented. The feed then passes into a 

recirculation loop where concentrate circulates through an evaporator exchanger and 

a vapour/liquid separator. A portion of the concentrate is boiled to steam in the 

evaporator exchanger and separated from the liquid in the separator vessel. A 

compressor draws the steam off the separator and boosts the pressure, which results 

in an increase in temperature. The steam is driven through the opposite side of the 

evaporator exchanger where it condenses to distilled water, releasing its latent heat to 

the boiling concentrate. The distilled water is then pumped through the preheat 

exchanger where remaining sensible heat is transferred to the incoming feed. 

Concentrate is continually pumped from the recirculation loop out of the unit to 

prevent the solution from reaching saturation. The concentrate also passes through a 

preheat exchanger where remaining sensible heat is transferred to the incoming feed. 

 Producing distilled water from direct-fired distillate requires 1000 BTU/lb of 

heat energy. Due to the sophisticated heat exchanger configuration in MVR 
20 

evaporation, distilled water can be theoretically produced with only 25-28 BTU/lb, 

1/40th the energy. 

 The Nomad 2000 MVR units are designed to produce 2000 bpd of treated water from 

nominally 2300 bpd of feedwater. The systems are portable, with each consisting of three skids 

that can be transported with tractor–trailers. The Nomad system uses available wellhead natural 

gas as an energy source so no three-phase power is required. The Nomad can also be monitored 

and controlled remotely via cell phone. 

212 Resources 

 212 Resources owns and operates the platform technology that employs patented vapor 

compression flash evaporation systems. 212 Resources claims to have solved the fouling/scaling 

operational concern through a minimum-fouling, minimum-scaling, high-velocity evaporation 

system. Each unit contains a specially designed heat exchanger along with a high-powered pump 

to cycle water under pressure at many times the evaporation rate. A process flow diagram for the 

212 Resources vapor compression system is shown in Figure 13 (www.212resources.com, 2010). 

Figure 12. Aqua-Pure mechanical vapor recompression technology process diagram 

(www.aqua-pure.com, 2010). 
21 

Figure 13. 212 Resources vapor compression process flow diagram 

(www.212resources.com, 2010). 

 While thermal processes are capable of producing a high-quality effluent, there remains a 

concern regarding the treated water yield that is actually possible when treating high-TDS waters 

like Bakken flowbacks. Pretreatment of these waters will enhance thermal treatment processes 

by both reducing the levels of scale-causing constituents and, ultimately, providing highertreated water yields. 
22 

Membrane Treatment 

Membrane technologies are much younger in development than thermal technologies and 

were developed primarily for commercial and municipal water supplies in the 1970s. As the 

name implies, membrane treatment removes dissolved minerals, such as salts, from solution 

using filtration through a semipermeable membrane. The three main types of membrane 

treatment include RO, electrodialysis (ED), and nanofiltration (NF). 

 Of the membrane technologies commonly employed for seawater desalination, RO 

accounts for about 81%, while ED and NF account for 11% and 8%, respectively. RO is a 

membrane-based technology that employs dynamic pressure to overcome the osmotic pressure of 

the saline feedwater. RO uses thin, semipermeable membranes to separate the feed stream into 

two streams, a low-TDS permeate and a high-TDS concentrate. Pressure forces pure water 

through a membrane that rejects dissolved salts. 

 ED is one of the three common membrane processes in desalination and is primarily used 

to treat brackish water. ED involves the selective movement of ions through a membrane in 

response to a direct electric current. Electric energy is consumed in proportion to the quantity of 

salts to be removed. Economics usually limit its application to feedwaters of less than 

10,000 mg/L TDS. The electrodialysis reversal (EDR) process is based on the same principles of 

electrochemistry as ED. The fundamental difference is that during the EDR process, the polarity 

of the cell is periodically reversed, usually three to four times an hour, to alter the flow of ions 

across the membrane. This action improves the tolerance of the technology to treat scaling-prone 

or turbid feedwater. EDR has largely replaced ED in the United States and in some overseas 

markets. EDR has a permeate recovery capacity and a salt rejection rate of 90%. A significant 

disadvantage of EDR treatment is the cost, which is approximately twice that of RO (Hanson, E., 

GE Osmotics, personal communication, 2008). 

 NF is a membrane process that primarily removes divalent salt ions (such as calcium, 

magnesium, and sulfate) from solution, but not monovalent ions (such as sodium and chloride). 

As a result, NF is most commonly used for water softening and for nondesalting applications, 

such as removal of organic compounds. 

 The use of membrane filtration for treating Bakken frac flowback water will likely have 

limited application. However, the Texas A&M University Global Petroleum Research Institute 

(GPRI) has developed an advanced membrane treatment process for the desalination of oil field 

brine. GPRI licensed the technology and reached a long-term agreement with M-I SWACO to 

commercialize the technology. David Burnett, Director of GPRI, indicated that the process can 

desalinate waters with less than 40,000 ppm TDS, much lower levels than are found in Bakken 

flowback water. 

 Ecosphere Technologies, Inc., has developed the OzonixTM mobile frac flowback water 

treatment system. The advanced oxidation system uses a combination of ozonation, ultrasound, 

electroprecipitation, centrifugation, filtration, and RO to improve the quality of frac flowback 

and produced water. The water is first filtered to remove suspended solids and then treated in the 

Ozonix unit which employs ozone, ultrasound, and electroprecipitation technologies. In the 
23 

presence of an ultrasonic cavitation field, ozone decomposes into two hydroxyl radicals and 

oxygen gas. The hydroxyl radical oxidizes organic compounds and kills bacteria in the water. 

The electroprecipitation causes some chemical species to come out of solution, and the 

precipitated material is removed in the centrifugal separation, media, and cartridge filtration 

units. The final processing step is RO, which removes nearly all remaining dissolved solids. 

Task 5 – Flowback Water Treatment Technology Assessment 

 Based on the review of existing frac flowback water treatment technologies and evaluation 

factors, including 1) stage of development; 2) demonstrated application of oil field compatibility; 

3) mobility; 4) robustness, particularly considering climate extremes in North Dakota; and 

5) discussions with producers, technology vendors, and industry experts, the EERC focused 

continued assessment efforts on thermal treatment processes and, in particular, the Aqua-Pure 

MVR process. In April 2009, EERC staff visited sites near Decatur, Texas, in the Barnett shale 

region where Devon Energy was using FQWM and its Aqua-Pure technology to recycle frac 

flowback and produced water. 

 Devon collects frac flowback water and transports it by tanker truck to a centralized 

facility location, where it is unloaded into aboveground storage impoundments (Figure 14). 

Suspended solids are allowed to settle during storage. Flowback water is pumped from the 

storage impoundment to a pretreatment process that consists of flocculation, coagulation, gravity 

settling, and dewatering. Figure 15 shows the pretreatment system. Coagulants are used to 

produce a chemical flocculant that is removed in an inclined plate settler. Supernatant from the 

settler is pumped to the Nomad MVR units. Underflow from the settler is pumped to a filter 

press that dewaters the flocculated solids. Water from the filter press is also conveyed to the 

Figure 14. Frac flowback water storage impoundment. 
24 

Figure 15. Pretreatment system consisting of coagulation/flocculation, settling, and filter press. 

Nomad MVR units (Figure 16). The Nomad MVR units operate as described in the previous 

section. During the site visit, FQWM was treating water that was a blend of frac flowback and 

produced water. The feedwater had a TDS level of around 60,000 mg/L. With a throughput of 

2300 bpd, each unit was able to produce approximately 2000 bpd of high-quality treated water. 

Figure 17 is a photograph of system feedwater, treated water, and concentrate from the MVR 

units. 

 Continued discussions with FQWM focused on the timing of a potential demonstration of 

the Nomad MVR technology at a Bakken host site. At the same time, active data collection and 

assessment activities were providing information that suggested less of an opportunity than 

originally envisioned for widespread frac water-recycling opportunities in the Bakken play. That, 

coupled with the marginal economics of recycling frac water in the Barnett shale, led the EERC 

to refocus research efforts on a more promising opportunity. 

Task 6 – Recommendations for Phase 2 Project Deployment 

 The purpose of this task was to develop detailed plans for the field evaluation of the most 

technically and economically sound mobile frac flowback water-recycling process. The Phase 1 

frac water-recycling feasibility assessment, however, documented significant challenges for 

demonstrating cost-effective treatment and recycling strategies, even with the most robust 

available technologies. While there will certainly be niche opportunities using certain 

technologies to recycle frac flowback water, widespread recycling will not likely be 

economically viable. The increasing demand for limited supplies of freshwater in western North 

Dakota, the often long distances between freshwater sources and well sites (and associated 
25 

Figure 16. Aqua-Pure Nomad 2000 mechanical vapor recompression unit. 

Figure 17. Water samples: frac flowback (left), treated water (center), and MVR concentrate 

(right). 
26 

transportation costs), and the time constraints associated with obtaining new permits to pump 

from fresh groundwater sources all create significant challenges to the oil industry. 

 The regional and national importance of providing sufficient volumes of water for such an 

extremely high-value use cannot be overstated. These water supplies will need to come from a 

variety of resources. One opportunity is to upgrade marginal-quality groundwater resources to 

satisfy a portion of the demand. An evaluation of a membrane technology for the treatment of 

abundant supplies of nonpotable groundwater has been proposed as a Phase 2 Bakken Water 

Opportunities Assessment project. The EERC is teaming with an oil industry partner to 

investigate the treatment of moderately saline groundwater from the Dakota Formation with 

pretreatment and RO technology. The proposed pilot-scale demonstration will treat up to 

215 gpm of groundwater to produce approximately 160 gpm of permeate, assuming an estimated 

75% recovery rate. 

Task 7 – Information Dissemination Activities 

Throughout the course of this project, the EERC has worked proactively with industry 

sponsors to inform the public and others about water issues and opportunities in the Bakken. 

These activities have ranged from general discussions with citizens, to presentations at town hall 

meetings, to technical presentations and at national meetings and conferences. The following is a 

listing of the venues where Bakken Water Opportunities Assessment dissemination and outreach 

activities have been conducted: 

• DOE National Energy Technology Laboratory (NETL) Water/Power Nexus Workshop, 

Pittsburgh, Pennsylvania, October 27–28, 2008 

• NGPWC Kickoff Meeting, NETL, Pittsburgh, Pennsylvania, October 29, 2008 

• Series of townhall meetings in western North Dakota’s oil country – November 12–13, 

2008 

• Milestones and Challenges, 45th Annual Joint North Dakota Water Convention and 

Irrigation Expo, Bismarck, North Dakota, December 2–5, 2008 

• North Dakota Petroleum Council Annual Meeting – Medora, North Dakota, 

September 1–3, 2009 

• North Dakota Solid Waste and Recycling Symposium – Minot, North Dakota, 

September 17, 2009 

• Great Plains Energy Expo – Bismarck, North Dakota, November 9–10, 2009 

• Water Resource Opportunities Meeting – Bismarck, North Dakota, December 10, 2009 

• Oil and Gas Research Council Meeting – January 20, 2010 
27 

 In addition, the EERC developed a NGPWC Water Use Fact Sheet that presents a 

comparison of water use for hydraulic fracturing to more traditional water uses such as centerpivot irrigators and municipal uses, along with unit conversion factors to illustrate the relative 

magnitude of water use in various activities. The fact sheet can be found in Appendix D.

REFERENCES 

Honeyman, R.P., 2007, Pressure head fluctuations of the Fox Hills–Hell Creek Aquifer in 

McKenzie County, North Dakota: North Dakota State Water Commission Water Resources 

Investigation 43, Project File 1442, 130 p. 

Veil, J.A., 2008, Thermal distillation technology for management of produced water and frac 

flowback water: Argonne National Laboratory Water Technology Brief 2008-1, U.S. 

Department of Energy Office of Fossil Energy, National Energy Technology Laboratory, 

12 p. 
APPENDIX A 

BAKKEN FRAC FLOWBACK WATER SALINITYVERSUS-TIME PLOTS 
APPENDIX A-1 

CUMULATIVE FLOWBACK PLOTS FOR 

HYDRAULIC FRACTURE EVENTS WITH 

KNOWN INJECTION VOLUMES 
A-1-1 

CUMULATIVE FLOWBACK PLOTS FOR HYDRAULIC FRACTURE EVENTS WITH 

KNOWN INJECTION VOLUMES 
A-1-2 
A-1-3 
A-1-4 
APPENDIX A-2 

CUMULATIVE FLOWBACK PLOTS FOR 

HYDRAULIC FRACTURE EVENTS WITH 

ASSUMED INJECTION VOLUME OF 23,000 bbl 
A-2-1 

CUMULATIVE FLOWBACK PLOTS FOR HYDRAULIC FRACTURE EVENTS WITH 

ASSUMED INJECTION VOLUME OF 23,000 bbl 
A-2-2 
A-2-3 
APPENDIX B 

BAKKEN FRAC FLOWBACK WATER SALINITY 

VERSUS TIME DATA PLOTS 
B-1 

BAKKEN FRAC FLOWBACK WATER SALINITY VERSUS TIME DATA PLOTS 
B-2 
B-3 
B-4 
B-5 
B-6 

 Note: This figure contains data for samples of Bakken frac flowback water that were 

analyzed for both TDS and electrical conductivity. This relationship was used to coordinate the 

conductivity and TDS axes on the plots presented for Producer A flowback water. The 

magnitude of a conductivity to TDS conversion factor depends on the particular distribution of 

ions in a given water. The literature reports values ranging from 510 to 970 mg/L TDS/(mS/cm). 

The value calculated for the Bakken flowback water was 728 mg/L TDS/(mS/cm). 
APPENDIX C 

CHARGE BALANCE ERROR
C-1 

CHARGE BALANCE ERROR 

 Aqueous solutions must be electrically neutral. The sum of all negative charges must equal 

the sum of all positive charges. An indicator of the quality of a water analysis is the charge 

balance error (CBE). CBE is calculated based on the following formula: 

 The cations and anions in the above equation have units of milliequivalents per liter (m). 

This value is then multiplied by the valence of the ion (z). 

 CBE may be negative or positive, depending on whether anions or cations are more 

abundant in the analysis. For instance, a negative CBE value indicates that the water sample has 

a higher concentration of anions than cations. A CBE of ±5% is acceptable for most groundwater 

samples (Freeze and Cherry, 1979). If the CBE exceeds 5%, it may be because of an anion or 

cation not included in the analysis, an error in the analysis, or a data recording error. Produced 

water flowback after hydraulic fracture is highly brackish. Brackish water can often lead to a 

higher CBE than normal groundwater. However, in the case of these three samples, the CBE was 

very small, an indication likely all of the cations and anions in solution have been accounted for. 

REFERENCE 

Freeze, R.A., and Cherry, J.A., 1979, Groundwater: Englewood Cliffs, New Jersey, PrenticeHall, Inc., 604 p. 
APPENDIX D 

WATER USE FACT SHEET
EER Energy & Environmental

CResearch Center®

Putting Research into Practice Northern Great Plains 

Water Consortium

The Demand for Water

Water is the most critical limiting 

resource throughout the world. 

Sustainable economic growth 

requires a reliable supply of 

water for energy, agriculture, 

and a growing population. Water is necessary 

for urban development, power production, 

growing and processing high-value crops, oil 

and gas development and processing, and 

industrial manufacturing. Satisfying all of these 

competing needs requires a better understanding 

of water resources and new approaches to water 

management. Energy, agriculture, industry, and 

municipalities all urgently need a scientifically 

valid basis upon which to make management 

and regulatory decisions related to water use and 

quality. 

The Energy & Environmental Research Center 

(EERC) is developing a partnership between 

the U.S. Department of Energy (DOE) and 

key energy-producing entities in the northern 

Great Plains to address issues related to water 

availability, reducing freshwater use, and 

minimizing the impacts of facility and industry 

operations on water quality. The key goals of 

this partnership, called the Northern Great Plains 

Water Consortium (NGPWC), are:

•	 To evaluate water demand and consumption from 

competing users in the northern Great Plains 

region, including energy production, agriculture, 

industry, and domestic/municipal users. 

•	 To assess, develop, and demonstrate 

technologies and methodologies that minimize 

water use and reduce wastewater discharge 

from energy production and agricultural 

processing facilities.

•	 To identify nontraditional water supply sources 

and innovative options for water reuse.

Thinking Outside the Box to 

Address Water Issues

As the United States continues to pursue economic 

development and the population increases, 

demand for ever-increasing amounts of energy to 

support that growth will require water. In areas 

where water resources are limited or become 

scarce because of overallocation and/or drought, 

competing interests for water could limit energy development and 

production. With the vibrant oil, gas, and utility interests in the region, 

potential water reuse synergies among energy-related industries 

should be explored. For example, thermoelectric power generation 

is second only to agriculture as the largest domestic user of water, 

accounting for approximately 40% of all freshwater withdrawals in 

the United States, as illustrated in the figure above. A portion of that 

cooling water effluent could be used in other industries, perhaps even 

prior to cooling, to capitalize on the waste heat. Significant volumes 

of water are also used in the drilling and completion of oil and gas 

wells. Wastewater from other industries could be used to supply water 

needed for drilling operations, and options may exist to treat and reuse 

the produced water from oil and gas operations. Finding innovative 

solutions that expand water resource options for the energy industries 

in the region is one of the key goals of the NGPWC. 

Water Use Fact Sheet

39.7%

40.1%

12.7%

5.8%

1.1%

0.7%

Thermoelectric Power

Irrigation

Public Supply

Industrial Use

Aquaculture

Domestic, Livestock,

and Mining

The major users of freshwater within the United States (aquaculture is the 

farming of aquatic organisms).

EERC BK32528.AI

Ag-Related Processing

Electric Utility

Industrial

Petroleum- and Natural 

Gas-Related Facilities

NGPWC region showing the locations of key energy, agricultural, and 

industrial facilities.

EERC . . . The International Center for Applied Energy TechnologySM
The NGPWC is a partnership of key public and private water users in the northern Great Plains region. New members are 

welcome. To learn more, contact:

Bethany A. Kurz, Senior Research Manager, (701) 777-5050

Daniel J. Stepan, Senior Research Manager, (701) 777-5247

John A. Harju, EERC Associate Director for Research, (701) 777-5157

Gerald H. Groenewold, EERC Director, (701) 777-5131

Approximate Volumetric Equivalents

barrels gallons acre-feet cubic feet cubic meters

1 42 0.000129 5.6146 0.15897

7758 325,851 1 43,560 1233

23,810 1,000,000 3.1 133,681 3785

Approximate Flow Equivalents

barrels per day 

(bbl/day)

million gallons 

per day (Mgd)

gallons per 

minute (gpm)

cubic feet per 

second (cfs)

cubic meters per 

second (m3/s)

23,810 1.0 694.4 1.55 0.04381

34.3 0.00144 1.0 0.0022 0.00006

100 0.0042 2.9167 0.0065 0.000184

Water Use Comparisons

Use

gallons 

(millions)

barrels 

(thousands) acre-feet cubic meters

Typical Daily Use for a 50,000-Person Midwestern City 10 238.1 30.7 37,850

Daily Pumping Volume for a Center-Pivot Irrigator for 

130 Acres (irrigated portion of 1⁄4 section) 1.008 24 3.1 3815

Average Daily Water Withdrawal for Once-Through 

Cooling at a 400-MW Coal-Fired Power Plant 365 8691 1120 1,381,525

Water Used to Fracture the Formation for an Oil Well in 

the Bakken Formation (one-time use) 0.5–1.0 11.9–23.8 1.5–3.1 1893–3785

Proposed Maximum Daily Volume of Water Imported 

for the Red River Valley Water Supply Project 77.56 1,847 238 293,556

Putting Regional Water Use in Perspective

The various industries and water users within the region 

often use different units of reference when referring to 

water consumption and discharge. To gain a perspective 

on the relationship between municipal, industrial, and 

agricultural water use, it is helpful to compare some 

common units and examples of water use among the 

sectors. 

EERC BK32526.INDD 1/10

Sponsored in Part by the 

U.S. Department of Energy

NATIONAL ENERGY TECHNOLOGY LABORATORY

Interested in Joining?

The EERC is actively seeking charter members to complement DOE funding and to help direct the program’s efforts. 

The NGPWC is currently engaged in Phase I of the program, wherein future program efforts and demonstration 

projects will be selected and prioritized. Phase II of the effort, scheduled to begin in 2010, will focus on 

demonstrating the water minimization and beneficial reuse strategies and technologies prioritized in Phase I. 

Conversion Factors

1 cubic foot = 7.4805 gallons

1 gallon = 3.785 liters

1 cubic meter = 1000 liters

1 acre = 43,560 square feet

University of

North Dakota Grand Forks