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Evaluation of Brackish Groundwater 

Treatment for Use in Hydraulic 

Fracturing of the Bakken Play, North 

Dakota 

Bethany Kurz, Daniel Stepan, John Harju, 

Brad Stevens, and Robert Cowan 

Energy & Environmental Research Center 

Grand Forks, North Dakota 

ABSTRACT 

A pilot-scale, reverse osmosis (RO) treatment project was conducted to evaluate the 

feasibility of brackish groundwater treatment as a freshwater source for hydraulically fracturing 

the Bakken oil play of North Dakota. This paper discusses the current freshwater resource 

demand for Bakken hydraulic fracturing, the RO system design, and preliminary system 

performance. This evaluation was conducted by the Energy & Environmental Research Center’s 

Northern Great Plains Water Consortium® (NGPWC), in partnership with Hess Corporation, the 

U.S. Department of Energy, and the North Dakota Industrial commission Oil and Gas Research 

Council. 

BACKGROUND 

 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 consortium 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. 

 One of the consortium’s key 

activities is to evaluate potential sources of 

water for use in hydraulically fracturing the 

Bakken Formation, located in the Williston 

Basin of North Dakota, Montana, South 

Dakota, and Saskatchewan (Figure 1). The 

Bakken oil play is rapidly emerging as an 

important source of domestic oil, with 

potentially recoverable reserve estimates 

ranging from 4 to 24 billion barrels (Oil and 

Gas Journal, 2011). 

 While the hydrocarbon resource 

within the Bakken is tremendous, the 

formation is characterized by very low 

porosity and permeability which 

necessitates hydraulic fracturing (fracking) 
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Figure 1. The location of the Bakken Formation within the Williston Basin. 

to enhance the flow and recovery of oil. 

Water volumes for fracking the Bakken 

range from approximately 20,000 to 

115,000 barrels (approximately 840,000 to 

5 million gallons), depending on the number 

of stages in the fracture, with more stages 

requiring greater volumes of water. While 

these volumes of water are not especially 

high when compared to those needed for 

municipal and agricultural use within the 

western portion of North Dakota, there are a 

limited number of locations from which to 

obtain the freshwater. For water haulers, the 

lack of water resources translates to long 

transportation distances and excessive 

amounts of time spent waiting in lines at 

water depots. As a result, water acquisition 

costs for Bakken oil producers in the region 

can be quite high. Given the current 

demand for water resources and the high 

costs of acquisition and transportation, 

treatment of nontraditional water supply 

sources may be economically viable. 

 One of the first projects conducted 

by the authors was an assessment of the 

potential to recover, treat, and recycle 

fracturing flowback water from Bakken oil 

wells (Stepan et al., 2010). An array of 

water treatment technologies was 

evaluated, primarily mobile treatment 

systems that could utilize the high-Btu 

associated gas generated during the 

flowback operations to thermally treat 

fracturing flowback. However, extremely 

high dissolved salts in flowback water, 

combined with a relatively low recovery of 

the flowback water, makes recycling very 

challenging and, in most cases, 

economically unattractive. 

 As part of a continuing effort to 

evaluate water supply options for oil 

producers and other industries in the region, 

the consortium teamed with Hess 

Corporation, a major oil producer in the 

state, to conduct a pilot treatment project 

using reverse osmosis (RO) to evaluate the 

technical and economic feasibility of treating 

brackish groundwater as a water supply 

source for fracking. This effort is being 

funded by the industrial partner, DOE, and 

the North Dakota Industrial Commission 

(NDIC) Oil and Gas Research Council 

(OGRC). The pilot system has been in 

operation since July 2010 and will continue 
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to operate through summer 2011 and 

perhaps longer, given the success of the 

project and the utility of the freshwater being 

produced. The following paper discusses 

the current state of water use practices for 

Bakken fracking and summarizes the results 

of the RO pilot project to date. 

CURRENT WATER USE PRACTICES 

 Fracking is increasingly being 

employed by oil producers in western North 

Dakota to produce the tremendous oil and 

gas resources of the Bakken Formation. 

Fracking entails the injection of water, 

proppants, and various other chemical 

constituents at high pressures into reservoir 

rock in order to increase the permeability of 

the formation and enhance the flow of oil. 

Common constituents of fracturing fluid 

makeup are shown in Table 1, with water 

and proppants typically comprising 99.5% of 

the fracturing fluid makeup (U.S. 

Department of Energy, 2009). Fracturing 

fluid makeup water must typically contain 

low total dissolved solids (TDS), be free of 

bacteria, and be of consistent quality to 

ensure the ability typically contain low total 

dissolved solids (TDS), be free of bacteria, 

and be of consistent quality to ensure the 

ability of individual producers to generate 

and replicate the desired fracture results. 

 Within western North Dakota, 

common freshwater acquisition points for 

frac fluid makeup are existing water depots 

and municipalities; however, these have a 

limited capacity to supply the large demand 

for water. Those depots and municipalities 

that have extra capacity to provide water to 

the oil industry must first request an 

industrial permit from the North Dakota 

State Water Commission (SWC), which can 

be time-consuming. 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 typically 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. 

 In addition, SWC is reluctant to 

permit new allocations from potable 

groundwater resources for use in the oil 

industry because of concerns over depletion 

of the resource and declining hydraulic 

pressures of the aquifers. With the 

exception of the Missouri River System, 

most regional surface waters do not provide 

a reliable source of water because of 

seasonal flow variations. Sufficient flows 

typically exist only in the spring of the year, 

during periods of snowmelt.

Table 1. Common Constituents of Fracturing Fluid Makeup 

Frac Fluid Component Purpose 

Freshwater The primary mechanism for delivering the desired 

proppants and chemicals into the formation; usually 

high quality 

Proppant Typically sand or ceramic beads that help keep the 

fractures open upon release of pressure from the 

fracking operation 

Biocides Reduces the risk of well souring from microbes 

Friction-Reducing Agents Surfactants that promote fracturing fluid flow 

Polymers Form gels to keep proppants in suspension 

Scale inhibitors Reduces scale formation in pipes 

Weak acids Helps dissolves minerals that cement formation pore 

spaces 
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 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. The 

Missouri River System, specifically Lake 

Sakakawea, is a tremendous resource that 

is located adjacent to many of the Bakken 

drilling areas (Figure 2). However, there are 

several issues related to using Lake 

Sakakawea water, key among them being 

access to the lake and looming fees for use 

of the resource. 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 so as 

not to disturb existing cultural sites and/or 

threatened and endangered species. While 

the Corps is studying the potential impacts 

of increased access to and water use from 

the lake (estimated to be a multiyear study), 

it agreed to allow a temporary annual 

allocation of water from the lake for 

municipal, rural, and industrial (MR&I) use 

for a fee. The state of North Dakota strongly 

objected to the Corps’ plan to charge a fee 

for access to water that is being stored on 

North Dakota lands. It is unclear at this time 

when the issues surrounding access to 

Lake Sakakawea will be resolved. 

Figure 2. The location of the Missouri River System and Lake Sakakawea with respect to 

Bakken drilling locations (Energy Information Administration, 2011). 
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 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 access issues and 

potential fees associated with this water use 

remain unresolved. In addition, the Missouri 

River and Lake Sakakawea are not always 

adjacent to areas of Bakken drilling, and 

therefore, the high costs associated with 

long transportation distances may diminish 

the appeal of the resource. 

 As part of the consortium’s study to 

evaluate the feasibility of fracturing flowback 

recycling, cost data for water acquisition 

were provided by several producers working 

in North Dakota (Stepan et al., 2010). The 

reported costs of current water handling for 

hydraulic fracturing can vary significantly, 

depending on acquisition costs and 

transportation costs (including wait time). 

Table 2 lists a range of current waterhandling costs for Bakken fracture water. 

The cost to purchase raw water ranged from 

$0.25/bbl up to $1.75/bbl ($5.95 to $25 per 

1000 gallons), and the cost of transporting 

that water to the fracture location ranged 

from $0.63/bbl up to an estimated $5.00/bbl 

($15 to $119.05 per 1000 gallons). 

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. 

 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 treatment of 

nonpotable groundwater resources. 

PILOT PROJECT BACKGROUND 

SITE DESCRIPTION – This project is being 

conducted near Tioga, North Dakota, at an 

existing groundwater well site that is 

screened at a depth of approximately 

5500 feet in the Dakota Formation (Dakota). 

The Dakota is one of the most widespread 

aquifers in North America and is present in 

most states of the Great Plains, from 

western Iowa to Montana and from the 

Arctic Circle to New Mexico (Kansas 

Geological Survey, 1996). In eastern North 

Dakota, groundwater from the Dakota has 

been used as a water source for livestock 

since the beginning of the 20th century, but 

because of its marginal quality and 

increased costs associated with treatment 

and pumping, it has been marginalized as a 

municipal or industrial water source. 

However, recent developments in water 

treatment technologies, coupled with the 

current water acquisition costs of water for 

Bakken fracking, may render treatment of 

the Dakota and other brackish groundwater 

formations as economical for oil industry 

uses. 

 The well at the Tioga location 

provides water that is used as part of a 

secondary oil recovery operation 

(waterflood) and is capable of sustaining 

moderate to high yields. The well has been 

pumped nearly continuously at a rate of 

11,000 to 12,000 barrels (bbl) a day (320 to 

350 gallons per minute [gpm]) for several 

decades with no measurable impacts to 

hydrostatic water levels; therefore, the 

additional pumping rate required for the 

relatively short duration of the pilot project 

was inconsequential.

Table 2. Water-Handling Costs 

 Cost, $/bbl Cost, $/1000 gallons 

Acquisition Costs 

 Raw Water $0.25–$1.05 $5.95–$25.00 

 Transportation $0.63–$5.00 $15.00–$119.05 

Total Costs $0.83–$6.05 $20.98–$144.05 
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 Water samples collected from the 

well revealed that the water chemistry is 

predominantly sodium chloride in nature, 

with lesser amounts of sulfate and 

bicarbonate. TDS average about 

8500 mg/L. (More specific formation on 

water chemistry is listed in Table 4 later in 

this paper.) Because the Dakota Formation 

is at such a great depth beneath the 

surface, the water exits the well at a 

temperature of approximately 155°F (68°C). 

TECHNOLOGY TREATMENT SYSTEM – 

After evaluating several mobile technology 

treatment system providers, the industrial 

partner selected General Electric (GE) 

Water and Process Technologies as the 

preferred pilot system provider. The 

technology provider’s MobileRO® unit is a 

mobile RO water treatment system, 

consisting of two semitrailers and several 

skid-mounted components, including all the 

hardware and electronics necessary to 

monitor the system operation and 

performance. Given the quality of the 

feedwater at the pilot project site, the 

technology provider estimated that, at full 

capacity, the system would be capable of 

producing approximately 160 gpm of 

permeate (treated water) at a 75% recovery 

rate. Because the system contains two 

independently operated filter arrays, it can 

also be operated at reduced capacity, 

equivalent to approximately 80 gpm of 

permeate at a 75% recovery rate. The 

mobile system contains all necessary 

prefilters, the antiscalant treatment system, 

controls, piping, valves, and 

instrumentation. All operations associated 

with the mobile RO unit were the 

responsibility of the technology provider’s 

personnel for the duration of the pilot test. 

SITE PREPARATION – In order to prepare 

the site for the pilot project, several activities 

were conducted, including: 

• Installation of the RO treatment and 

pretreatment units. 

• Installation of the feedwater cooling 

system and heat exchangers. 

• Construction of a lined and covered 

pond for storage of the treated water 

(RO permeate). 

• Installation of five 400-barrel tanks that 

are used to store the feedwater, excess 

permeate (if needed), and RO 

concentrate. (The RO concentrate tank 

is designed to meet saltwater storage 

standards.) 

• Installation of the necessary piping to 

connect the system components. 

• Installation of the electrical power supply 

and necessary connections. 

• Construction of a truck-loading station 

that is used to transport the RO 

permeate to fracking locations within the 

Bakken play. 

• Installation of corrosion test racks to 

evaluate the corrosivity of the feedwater, 

permeate, and concentrate on various 

metals and metal/alloys. 

 One of the challenging aspects of 

the pilot project is the cooling of the 

feedwater, which exits the production well at 

a temperature of approximately 155°F 

(68°C), down to the required 90°F (32°C) 

prior to membrane treatment. While the high 

temperatures of the feedwater present a 

problem for the membrane modules, the 

heat from the water can also be a potential 

resource, given that the desired 

temperature of the fracturing fluid prior to 

injection is approximately 80°F (27°C). 

During the winter months, the cost to heat 

the fracturing fluid prior to injection is 

considerable and can sometimes exceed 

$150,000 or more to heat the water required 

for one well fracturing (Industrial partner, 

personal communication, 2010). Therefore, 

heat exchangers were installed at the pilot 

project site to partially cool the feedwater 

using the RO permeate, which exits the 

system at approximately 90°F (32°C), and, 

in turn, to heat the permeate prior to use as 

fracturing water makeup. 

 Another issue of concern related to 

treatment of brackish groundwater 

(especially when dealing with elevated 

temperatures) is corrosion of piping, pumps, 

cooling system components, and other 

materials that come in contact with the 

water. Because salinity levels of the 

formation water are elevated, corrosion 

could lead to costly equipment failures and 
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corresponding inability to produce permeate 

at a higher rate. Corrosion can be affected 

by chemical composition, temperature, pH, 

degree of aeration, flow velocity, and 

pressure. Therefore, system-specific testing 

is helpful to most accurately evaluate 

corrosion potential. As such, corrosion rate 

testing of the feedwater, concentrate, and 

permeate streams was conducted to 

determine proper heat exchanger, piping, 

and valve material selection for a full-scale 

plant. 

 As part of the corrosion testing 

research, aqueous chemistry modeling 

calculations were determined using OLI 

Systems, Inc., Stream Analyzer and 

Corrosion Analyzer software to predict the 

potential for scale formation and corrosion 

based on the chemistry of the formation 

water and the predicted concentrate 

chemistry (at 60% recovery). The potential 

corrosion rates of 19 metals and alloys 

when exposed to the system feedwater at a 

range of temperatures (70° to 170°F [21° to 

77°C]) and flow velocities (0 to 20 feet/ 

second) were modeled. The results of the 

modeling were used to select and order 

metal and metal alloy test coupons that 

were installed in test racks at the pilot test 

site to evaluate the corrosion and scaling 

potential of the feedwater, RO permeate, 

and RO concentrate. A total of six test 

racks, each equipped to hold either three or 

five test coupons, were installed at various 

locations in the treatment train at the pilot 

site (Figure 3). The metal/alloy coupons 

selected for evaluation include some 

standard materials, like carbon steel (API 

5LX42), stainless steel (316L), copper–

nickel alloy (CDA706), and titanium (Ti), as 

well as a more exotic alloy (Hastelloy C276) 

that is designed to be resistant to saltwater 

corrosion. The corrosion testing results are 

being used to assess the best materials to 

use for a full-scale RO treatment system 

using groundwater of this chemistry. 

PILOT TEST OPERATION 

 The pilot project system began 

treating water on July 21, 2010, at a 

permeate flow rate of 80 gpm and 50% 

recovery. Higher permeate recovery rates 

were not achievable until system which time 

the recovery rates increased to 

modifications were made (specifically orifice 

plate replacement) on August 3, 2010, at 

approximately 70%. The RO system 

continues to operate at a reduced flow rate 

(80 gpm of permeate production) to be 

consistent with the truck hauling cycle 

demands and maintain a more constant, 

steady operation. The permeate produced 

from the system is being used for fracking of 

the Bakken, and the concentrate is blended 

with the waterflood injection system 

feedwater into an oil reservoir. 

 Shortly after start-up of the system, 

six corrosion test racks were installed at the 

subject site. A description of each rack is 

included in Table 3. The discharge from 

Racks S-1, 2, 3, and 4 were manifolded 

together and plumbed to discharge into the 

feed tank. Figure 4 is a photograph of Rack 

S-2, a 5-place corrosion test rack assembly. 

The discharge from Racks S-5 and S-6 

were plumbed to discharge into the reject 

tank. During the installation and testing of 

the racks, enough water flow through Racks 

S-3 and S-4 was unable to be attained. This 

was caused by insufficient water pressure 

on the influent side of the rack to overcome 

the pressure at the discharge point. While 

the test racks could have been relocated, it 

would have entailed shutting down the 

system, plus the permeate corrosivity was 

expected to be minimal; therefore, no test 

coupons were installed in Racks S-3 and 

S-4. 

 Following installation of the 

corrosion test racks, water was allowed to 

flow through the racks for several weeks 

prior to coupon installation to flush the 

system, as recommended by the test rack 

manufacturer. The test coupons were 

installed in the racks in the order shown in 

Table 3, which represents their anticipated 

resistance to corrosion from most to least. 

This was done to minimize the potential of 

corrosion from one test coupon influencing 

the corrosion rate of subsequent test 

coupons. The only notable issue observed 
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Figure 3. Flow diagram with rack locations. 

Table 3. Corrosion Rack Description 

Rack 

No. 

Rack 

Material 

Number of 

Coupons 

Coupon 

Order Fluid 

Fluid Design 

Temperature 

Observed 

Temperature

S-1 CPVC1 5 Ti 

C276 

316L 

CDA706 

API 5LX42 

Feedwater 155°F 

(68°C) 

127°F 

(53°C) 

S-2 PVC2 5 Ti 

C276 

316L 

CDA706 

API 5LX42 

Feedwater 90°F (32°C) 80°F (27°C) 

S-3 PVC 3 No 

coupons 

Permeate 90°F (32°C) – 

S-4 CPVC 3 No 

coupons 

Permeate 130°F 

(54°C) 

110°F 

(43°C) 

S-5 PVC 3 Ti 

316L 

API 5LX42 

Concentrate 90°F (32°C) 96°F (36°C) 

S-6 CPVC 3 Ti 

316L 

API 5LX42 

Concentrate 155°F 

(68°C) 

118°F 

(48°C) 

1

 Chlorinated polyvinyl chloride. 

2

 Polyvinyl chloride. 
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Figure 4. Picture of corrosion test Rack S-2. 

during coupon installation was the presence 

of a black residue on the Rack S-1 

flowmeter and coupon holders. This residue 

was later determined to be some form of 

hydrocarbon, although detailed testing to 

determine the exact nature and source of 

the compound was never conducted. 

 After approximately 37 days of RO 

operation, water samples of the feedwater, 

permeate, and concentrate were collected 

and submitted to a commercial laboratory 

for analyses. A summary of the results of 

these analyses is shown in Table 4. 

 The RO system continued to operate 

at a permeate flow rate of 80 gpm with 70% 

permeate recovery until September of 2010, 

when the system was shut down to make 

adjustments to the permeate holding pond, 

to address electrical issues at the truck 

loading station, and to winterize the site. 

Based on operational logs, from July 21, 

2010, through September 6, 2010, a total of 

6,084,700 gallons of groundwater was 

processed through the RO system, resulting 

in approximately 4.26 million gallons of 

permeate and approximately 1.83 million 

gallons of concentrate. Although no flow 

measurements were recorded during the 

shutdown period, the RO system was 

operated for approximately 1 hour each day 

to prevent membrane fouling. 

 After all the necessary system 

modifications were made, full-capacity 

operation of the RO system began on 

November 29, 2010, and as of April 13, 

2011, approximately 19 million gallons of 

Dakota Aquifer water was processed. Since 

lower flow rates, lower operating pressures, 

and higher permeate conductivity were 

observed in RO Train 2, RO Train 2 was 

utilized more frequently, and Train 1 was 

operated only occasionally to prevent the 

accumulation of biological activity. The 

cause of the operational differences 

between the two trains is unknown at this 

time. Train 1 was operated for 

approximately 39 days, resulting in the 

treatment of 5.5 million gallons, and Train 2 

was operated for approximately 88 days, 

resulting in the treatment of approximately 

13.5 million gallons. 

 RO recovery rates remained 

relatively consistent while operating both 

trains, averaging nearly 72% over the
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Table 4. Summary of Water Analysis Results 

Analyte 

Feedwater 

(S-1) 

Permeate 

(S-4) 

Concentrate 

(S-5, S-6)* Units 

Ca 15.8 3.0 44.4 mg/L 

Na 3300 103 10,750 mg/L 

K 9.9 <1 42.8 mg/L 

Cl 3710 130 13,200 mg/L 

SO4 456 <5 1460 mg/L 

NO3 <0.1 <0.1 0.14 mg/L 

HCO3 1220 74 3820 

Ba <0.5 <0.1 <1 mg/L 

F 3.57 0.14 12.8 mg/L 

Fe <0.5 0.66 <1 mg/L 

Mg 2.6 <1 7.9 mg/L 

Mn <0.25 <0.05 <0.5 mg/L 

P, Total <0.1 <0.1 0.96 mg/L 

Si 17.2 <1.1 56.3 mg/L 

Cu <0.25 <0.05 <0.5 mg/L 

Sr 0.98 <0.1 2.92 mg/L 

Temperature (field, °F) 127 110 96, 118* 

pH (lab) 7.4 6.2 7.8 

pH (field) 7.32 6.06 7.55 

Conductivity (lab) 13,590 568 37,700 μS/cm 

Conductivity (field) 15,400 610 41,500 μS/cm 

Total Dissolved Solids 

(calculated) 

8230 280 27,800 mg/L 

Alkalinity (as CaCO3) 1220 74 3820 mg/L 

Hardness (as CaCO3) 50.2 7.49 144 mg/L 

Total Organic Carbon 5.9 4.9 7.1 mg/L 

* Because the water chemistry results from Racks S-5 and S-6 were not significantly different, they were 

averaged in this column, with the exception of temperature, which is listed separately for Racks S-5 and 

S-6, respectively. 

current operating period. As indicated 

earlier, feedwater flow rates were lower 

while operating Train 1 (103 gpm) versus 

operating Train 2 (124 gpm). Resulting 

permeate flow rates were also impacted, 

averaging 73 gpm on Train 1 compared to 

90 gpm on Train 2. Permeate conductivity 

also showed a difference, averaging 585 

microseimens per centimeter (μS/cm) on 

Train 1 and 395 μS/cm on Train 2. 

 To date, no membrane cleaning has 

been necessary and no scaling has been 

observed. Low-turbidity feedwater has been 

credited for the lack of membrane fouling. 

Silt density index (SDI 15) averaged 3.00. 

Backwash operations were performed on a 

once-per-week basis as preventive 

maintenance. Since pressure readings did 

not indicate the need for more frequent 

backwashing, this frequency appeared to be 

sufficient to maintain appropriate 

operational pressures. The operational 

records also indicate that once the system 

was stabilized, the feedwater conductivity 

was consistently around 14,000 μS/cm, the 

permeate averaged 700 μS/cm, and the 
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concentrate was approximately 

39,000 μS/cm. 

CORROSION TEST RESULTS 

 On November 9, 2010, the corrosion 

racks and associated piping were retrieved 

prior to any damage occurring from freezing 

temperatures. The corrosion coupons were 

removed from their respective racks, 

visually inspected, photographed, and 

allowed to dry overnight. 

 Upon retrieval, the corrosion 

coupons from Rack S-1 (127°F feedwater) 

were covered in the same black coating that 

appeared on the coupon holder and the 

flowmeter during the August 26, 2010, site 

visit. Coupons removed from Rack S-2 

(80°F feedwater) also exhibited a slight 

black coating. The black residue was not 

observed in any of the other test racks. As 

previously mentioned, a sample of the black 

residue was collected, and some 

preliminary testing indicated that it was a 

type of hydrocarbon. Additional testing of 

the compound to determine its exact 

composition has not been conducted. 

 An initial visual corrosion 

assessment revealed that in each case the 

carbon steel (API 5LX42) and the copper–

nickel, if present, showed significant 

corrosion while the stainless steel, Hastelloy 

(if present), and the titanium coupons did 

not show visible corrosion, although slight 

scaling was present. 

 Once the coupons were dry, they 

were individually weighed (without 

cleaning), placed in individual glass vials, 

and sent to the supplier of the corrosion 

coupons, Metal Samples Company (MSC) 

for postexposure analysis. MSC cleaned 

and weighed the coupons in accordance 

with ASTM International Standard G-1, 

conducted a corrosion analysis, and then 

returned the coupons upon completion of 

the analysis. These results are shown in 

Table 5. 

 With an initial and final weight, the 

corrosion rates for the respective metal 

coupons were calculated using the following 

equation: 

CR = (K × W) / (A × T × D) Eq. [1] 

Where: 

CR = Corrosion rate (mils per year) 

K = Conversion constant (3.45 x 106) 

W = Mass loss (g) A = Surface area (cm2

) 

T = Exposure time (hours) 

D = Density (g/cm3

) 

 Results from MSC (Table 5) clearly 

show that the carbon steel and copper 

nickel coupons corroded significantly more 

than the titanium, Hastelloy, or stainless 

steel samples, although even the higher 

corrosion rates are not considered to be 

excessive by industry standards. 

Interestingly, it appears that the more 

susceptible metals (carbon steel and 

copper–nickel) were protected somewhat 

from corrosion by the black substance that 

was present in the feedwater and coated 

the coupons in Rack S-1 (127°F feedwater). 

 A surface analysis of select coupons 

was performed in-house using a Nanovea 

PS-50 Optical Profilometer. The 

profilometer measures the height of the 

sample surface in relation to a fixed optical 

assembly, with a horizontal detection limit of 

0.1 μm and a vertical detection limit of 

5 nanometers. Six corrosion coupons were 

analyzed for comparison: carbon steel and 

stainless steel coupons from Rack S-1 

(127°F feedwater), carbon steel and 

stainless steel coupons from Rack S-6 

(118°F concentrate), and unexposed carbon 

steel and stainless steel coupons. The 

resulting profilometer images provide a 

graphical comparison of corrosion between 

carbon steel and stainless steel in different 

water streams and are shown in Figures 5 

and 6, respectively. It should be noted that 

the color height scales associated with each 

coupon are specific to that coupon and do 

not represent a common datum. More 

clearly explained, the profilometer scans a 

sample, and the deepest measured point on 

that sample is assigned the zero datum, and 

all other heights measured are referenced 

to that sample-specific zero datum. 

 As seen in Figures 5 and 6, the 

carbon steel exhibited more pitting corrosion 

than did the stainless steel (especially in 

Coupon No. 10 from Rack S-1). Figure 7
IWC 11‐8

Table 5. Corrosion Coupon Results 

Rack Fluid Coupon Metal 

Initial 

Weight, g

Final 

Weight, g 

Mass 

Lost, g 

Corrosion 

Rate, 

mil/yr 

S-1 Feedwater, 

127°F 

Ti-2 Titanium 6.6614 6.6564 0.0050 0.0968 

S-1 Feedwater, 

127°F 

C276 Hastelloy 12.6151 12.6104 0.0047 0.0472 

S-1 Feedwater, 

127°F 

316L Stainless 

 steel 

10.6845 10.6780 0.0065 0.0724 

S-1 Feedwater, 

127°F 

CDA706 Copper – 

 nickel 

13.0487 12.9719 0.0768 0.7528 

S-1 Feedwater, 

127°F 

API 

5LX42 

Carbon 

 steel 

16.9932 16.8693 0.1239 1.2684 

S-2 Feedwater, 80°F Ti-2 Titanium 6.6446 6.6413 0.0033 0.0639 

S-2 Feedwater, 80°F C276 Hastelloy 12.5855 12.5815 0.0040 0.0402 

S-2 Feedwater, 80°F 316L Stainless 

 steel 

10.7491 10.7438 0.0053 0.0590 

S-2 Feedwater, 80°F CDA706 Copper – 

 nickel 

13.0904 12.8610 0.2294 2.2485 

S-2 Feedwater, 80°F API 

5LX42 

Carbon 

 steel 

15.6065 15.4184 0.1881 1.9256 

S-5 Concentrate, 

96°F 

Ti-2 Titanium 6.6287 6.6259 0.0028 0.0542 

S-5 Concentrate, 

96°F 

316L Stainless 

 steel 

10.7744 10.7690 0.0054 0.0601 

S-5 Concentrate, 

96°F 

API 

5LX42 

Carbon 

 steel 

17.0656 16.8618 0.2038 2.0864 

S-6 Concentrate, 

118°F 

Ti-2 Titanium 6.6681 6.6644 0.0037 0.0716 

S-6 Concentrate, 

118°F 

316L Stainless 

 steel 

10.7622 10.7577 0.0045 0.0501 

S-6 Concentrate, 

118°F 

API 

5LX42 

Carbon 

 steel 

16.7854 16.5876 0.1978 2.0249 

shows a more detailed projection of a highly 

corroded section of the carbon steel coupon 

from Rack S-1 (Coupon No. 10), illustrating 

the high degree of pitting observed for the 

carbon steel coupon. 

 Of all materials tested, the carbon 

steel and copper–nickel coupons exhibited 

higher rates of corrosion in all the water 

streams than did the titanium, Hastelloy, 

and stainless steel coupons. With that said, 

the most severe corrosion observed for 

carbon steel was around 2 mils per year. 

This corrosion rate may not be considered 

excessive if it occurred evenly on the 

surface of a material; however, that does 

not appear to be the case, as localized 

pitting was observed and may be of concern 

in a long-term application. 

 Corrosion results do indicate that 

stainless steel should withstand contact with 

the respective feedwater and concentrate 

streams quite well. Therefore, investment in 

more exotic (and expensive) materials such 

as Hastelloy and titanium are likely not 

warranted for use in the full-scale facility. 

SYSTEM PERFORMANCE 

 As previously mentioned, the RO 

system was not operated continuously 
IWC 11‐8

Figure 5. Profiler images of select carbon steel coupons. 

Figure 6. Profiler images of select stainless steel coupons. 
IWC 11‐8

Figure 7. Profiler image of carbon steel coupon zoomed in to pitted area. 

through the late summer and fall of 2010. 

As a result, the authors decided to allow the 

system to run under steady-state conditions 

for a longer period of time prior to 

conducting a detailed assessment of system 

performance and economic viability. This 

assessment will be completed in the fall of 

2011. That being said, some general 

conclusions on the system performance and 

economics can be made. 

 As a result of the system 

performance, the current shortage of water, 

and the amount of hauling time saved by 

having an on-site truck-filling station, the 

industrial partner has decided to build a fullscale, 1-million-gallon/day RO treatment 

facility. For example, rather than paying for 

one water truck to drive 30 miles and wait in 

line for 1 to 2 hours, four trucks can fill at 

the site in 20 minutes. Preliminary 

calculations show that the water treatment 

costs for the pilot system are higher than 

the costs for conventional water supplies; 

however, the costs savings for reduced 

hauling distances and waiting times more 

than make up for the difference. In addition, 

because of the economy of scale and the 

nature of the contract with the technology 

vendor to provide and operate the mobile 

RO system, the water treatment costs per 

gallon for this pilot are significantly higher 

than what they would be for a full-scale 

plant. As more data become available and 

bids are secured for the full-scale RO plant, 

an economic analysis of the concept will be 

conducted. 

 Given the high demand for fracturing 

water in western North Dakota and the 

widespread nature of brackish groundwater 

formations, like the Dakota, this approach 

may be economically and technically 

feasible for other producers and/or other 

industries in the region. While case-by-case 

assessments will likely be needed, it is 

encouraging to know that this resource is 

available and may be economically 

competitive. 
IWC 11‐8

References: 

Energy Information Administration (2011). Bakken Formation Producing Wells, Williston Basin, 

North Dakota, Montana, Saskatchewan & Manitoba. Retrieved from 

www.eia.gov/oil_gas/rpd/shaleoil1.pdf. 

Kansas Geological Survey (1996). Dakota Aquifer Program Introduction: Extent of the Dakota 

Aquifer. Retrieved from www.kgs.ku.edu/Dakota/vol1/intro/extent.htm. 

Oil and Gas Journal (June 6, 2011). Retrieved from www.ogj.com/index/articledisplay.articles.oil-gas-journal.volume-109.issue-23.general-interest.focusunconventional-oil-gas-sliding-sleeve-fracs.html.html. 

Stepan, DJ, Shockey, RE, Kurz, BA, Kalenze, NS, Cowan, RM, Ziman, JJ, and Harju, JA 

(2010). Bakken Water Opportunities Assessment—Phase 1. Grand Forks, ND: Energy & 

Environmental Research Center, Publication No. 2010-EERC-04-03. 

U.S. Department of Energy (2009). Modern Shale Gas Development in the United States: A 

Primer. GWPC.