BAKKEN WATER OPPORTUNITIES

ASSESSMENT – PHASE 2

EVALUATION OF BRACKISH GROUNDWATER

TREATMENT FOR USE IN HYDRAULIC 

FRACTURING OF THE BAKKEN PLAY,

NORTH DAKOTA

Final Report

Prepared for:

North Dakota Industrial Commission

600 East Boulevard Avenue, Department 405

State Capitol, 14th Floor

Bismarck, ND 58505-0840

Prepared by:

Bethany A. Kurz

Daniel J. Stepan

John A. Harju

Brad G. Stevens

Robert M. Cowan

Energy & Environmental Research Center

University of North Dakota

15 North 23rd Street, Stop 9018

Grand Forks, ND 58202-9018

2011-EERC-12-05 December 2011
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. 

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 Industrial Commission of North 

Dakota. 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 ......................................................................................................................... iv 

PROJECT SUMMARY ................................................................................................................. vi

BACKGROUND .............................................................................................................................1

CURRENT WATER USE PRACTICES ........................................................................................2

BRACKISH GROUNDWATER RESOURCES .............................................................................5

DESALINATION TECHNOLOGIES ............................................................................................7

MEMBRANE TECHNOLOGY ....................................................................................................15

RO FEEDWATER PRETREATMENT ........................................................................................18

RO Pretreatment Goals ........................................................................................................ 18

Pretreatment Processes ........................................................................................................ 19

Permeate Treatment ............................................................................................................. 20

Concentrate Disposal ........................................................................................................... 20

PILOT PROJECT BACKGROUND .............................................................................................20

Site Description ................................................................................................................... 20

CORROSION AND SCALE FORMATION MODELING ..........................................................21

Dakota Aquifer Water Composition ................................................................................... 23

Scaling Tendency ................................................................................................................ 23

Corrosion Evaluation ........................................................................................................... 24

Corrosion and Scaling Analysis for Anticipated RO Concentrate ...................................... 28

MOBILE RO TREATMENT SYSTEM .......................................................................................29

SITE PREPARATION ..................................................................................................................30

PILOT TEST OPERATION AND PERFORMANCE ..................................................................32

FIELD-BASED CORROSION TESTING ....................................................................................39

ECONOMIC EVALUATION .......................................................................................................45

Continued . . . 
ii 

TABLE OF CONTENTS 

RO Treatment Plant Costs ................................................................................................... 45

Production Well Costs ......................................................................................................... 46 

Brine Disposal Costs ........................................................................................................... 46 

Land Acquisition ................................................................................................................. 49 

Permeate and Concentrate Storage ...................................................................................... 49 

CONCLUSIONS ...........................................................................................................................51

REFERENCES ..............................................................................................................................52

LIST OF FIGURES 

1 The location of the Bakken Formation within the Williston Basin ....................................... 1

2 The location of the Missouri River system and Lake Sakakawea with respect to 

Bakken drilling locations ...................................................................................................... 4

3 Stratigraphic column showing the age and rock units associated with each of the five 

aquifer systems within the Northern Great Plains Aquifer System ...................................... 6

4 Approximate extent of the Lower Tertiary aquifer system ................................................... 8

5 Approximate extent of the Upper Cretaceous aquifer system and generalized 

TDS concentrations ............................................................................................................... 9

6 Approximate extent of the Lower Cretaceous aquifer system and generalized 

TDS concentrations ............................................................................................................. 10

7 Approximate extent of the Upper Paleozoic aquifer system and generalized 

TDS concentrations ............................................................................................................. 11

8 Approximate extent of the Lower Paleozoic aquifer system and generalized 

TDS concentrations ............................................................................................................. 12

9 MSF distillation ................................................................................................................... 13

10 Cumulative worldwide desalination capacity...................................................................... 14

11 Desalination feedwater sources in the desalination market................................................. 15

Continued . . . 
iii 

LIST OF FIGURES (continued) 

12 Distribution of desalination capacity ................................................................................... 16

13 Photo of RO treatment membranes used to desalinize water in El Paso, Texas ................. 17

14 Block diagram of RO system .............................................................................................. 18

15 Predicted corrosion rates of carbon steel (A221B), stainless steel (316), and 

Hastelloy C-276 by raw Dakota water ................................................................................ 25

16 Predicted corrosion of Carbon Steel A212B by Dakota water over a range of 

temperatures and flow velocities ......................................................................................... 26

17 Flow diagram with corrosion test rack locations ................................................................ 31

18 Pilot-scale RO system flow rates ........................................................................................ 33

19 Pilot-scale RO system operating pressures ......................................................................... 33

20 Pilot-scale RO system permeate conductivity ..................................................................... 34

21 Pilot-scale RO system feedwater temperature .................................................................... 34

22 Treatment Train 2 feedwater and permeate conductivity .................................................... 37

23 Treatment Train 2 flux versus time ..................................................................................... 37

24 Flux versus temperature ...................................................................................................... 38

25 Flux versus pressure differential ......................................................................................... 38

26 Photograph showing the installation of corrosion test Rack S-2 ........................................ 40

27 Comparison of measured and predicted corrosion rates ..................................................... 42

28 Profiler images of select stainless steel coupons ................................................................. 43

29 Profiler images of select stainless steel coupons ................................................................. 44

30 Profiler image of carbon steel coupon zoomed in to pitted area ......................................... 44
iv 

LIST OF TABLES 

1 Common Constituents of Frac Fluid Makeup ....................................................................... 3

2 Water-Handling Costs ........................................................................................................... 5

3 General Description of Each of the Five Major Aquifer Units Comprising the 

Northern Great Plains Aquifer System .................................................................................. 7

4 Classification of Water Type Based on TDS Concentration .............................................. 13

5 Comparative RO and NF Species Rejection Rates ............................................................. 17

6 Water Chemistry Results for Dakota Aquifer Samples ...................................................... 22

7 Lab Analysis Values Entered into OLI Lab Analyzer Software and Values after 

Reconciling Charge Balance, pH and Alkalinity ................................................................ 23

8 Scaling Tendency Values for the Ten Minerals Having the Highest Scaling Tendencies 

for Dakota Aquifer Water at 152°F and pH 8.2 .................................................................. 24

9 Range of Corrosion Rates Calculated for All 19 Metals and Alloys Studied ..................... 25

10 Quantitative Classification of Carbon Steel Corrosion Rates for Open 

Recirculating Cooling Water Systems ................................................................................ 27

11 Quantitative Classification of Carbon Steel Corrosion Rates for Closed 

Recirculating Cooling Water Systems ................................................................................ 27

12 General Classification of Metals and Alloys Based on the Calculated Corrosion 

Rates With Dakota Water .................................................................................................... 27

13 RO Concentrate Water Analysis and Reconciliation .......................................................... 28

14 Scaling Tendency for RO Concentrate ................................................................................ 28

15 Range of Corrosion Rates Calculated for Carbon Steel A212B and S316 Stainless 

Steel by the Anticipated RO Concentrate ........................................................................... 29

16 Summary of Water Analysis Results .................................................................................. 36

17 Summary of Flux Calculations ............................................................................................ 37

Continued . . . 
v 

LIST OF TABLES (continued) 

18 Corrosion Rack Description ................................................................................................ 39

19 Comparison of Measured and Predicted Corrosion Rates .................................................. 41

20 Cost Estimate Assumptions – 1.5-MGD RO Plant ............................................................. 47

21 Total Cost Summary – 1.5-MGD RO Plant with Truck Transportation Disposal .............. 50

22 Total Cost Summary – 1.5-MGD RO Plant with Dedicated Pipeline Disposal .................. 51
vi 

EVALUATION OF BRACKISH GROUNDWATER TREATMENT FOR USE IN 

HYDRAULIC FRACTURING OF THE BAKKEN PLAY, NORTH DAKOTA 

PROJECT SUMMARY 

The Northern Great Plains Water Consortium® (NGPWC) is a partnership between the 

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

stakeholders in the north-central region of the United States. The overall 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. One of the NGPWC’s 

current activities is to evaluate potential sources of water for use in hydraulically fracturing the 

Bakken oil play of North Dakota. Because of the current high costs for acquisition and 

transportation of existing water resources in western North Dakota, treatment of nontraditional 

water supplies may be economically feasible. 

To evaluate the feasibility of treating nonpotable groundwater as a means of providing a 

freshwater supply for hydraulic fracturing in the Bakken play, the EERC teamed with Hess 

Corporation to conduct a pilot treatment project using reverse osmosis (RO) to treat brackish 

groundwater from an existing water well screened in the Dakota Formation at a depth of 

approximately 5500 feet. GE Water Process and Technologies (GE) was contracted to provide a 

mobile pretreatment and RO system. Agrekko heat exchangers were used to reduce groundwater 

temperature to desired levels before RO treatment. The project demonstrated greater than 70% 

treated water recovery and greater than 90% removal of major ions. Over 25 million gallons of 

brackish groundwater was treated during the demonstration, producing over 17.8 million gallons 

of high-quality freshwater for use in hydraulic fracturing. 

Metal test coupons were installed at various locations during the pilot demonstration to 

assess corrosion of standard plumbing and heat exchange materials of construction. The 

corrosion study suggested that stainless steel would be a superior material compared to carbon 

steel pipe commonly used in the oil field; however, more exotic metals and alloys would not be 

required. 

The success of the pilot project has led Hess to partner with GE to build and operate a fullscale, 1- to 2-million-gallon/day (MGD) RO treatment plant. While the exact costs of the plant 

are not available to the public, the estimated costs to build and operate a 1.5-MGD (35,700 bpd) 

RO plant were compiled by the EERC with input from GE. Capital costs associated with 

construction of the RO plant and associated buildings, land acquisition, well field and pipeline 

costs, water storage ponds, and concentrate disposal costs were also assessed. Annual operating 

and maintenance (O&M) costs were also included for the RO plant, well field, and concentrate 

disposal options. Given the relatively high volume of concentrate that would be produced 

(15,300 bpd), two different options were considered for disposal: truck transport to an existing 

commercial injection site and pipeline transport to a dedicated injection site. 

The total estimated capital costs for a 1.5-MGD RO plant with concentrate disposal at an 

existing commercial site were $24.9 million, and O&M was approximately $22.8 million a year. 

The capital costs for the second option (a dedicated concentrate injection site) were estimated at 

$38.2 million, and annual O&M was estimated at approximately $1.2 million. Depending on the 

economic assumptions used, per-barrel costs ranged from $1.28 to $2.95 over a payback period 

of 3 years or less. When compared to traditional frac water makeup costs, this approach appears 

viable if the cost savings associated with lower transportation costs and reduced heating costs are 

taken into account. Given the current pace of Bakken development, coupled with limited access 

to water, treatment of brackish groundwater sources for use in Bakken fracturing appears 

economically viable.
1 

EVALUATION OF BRACKISH GROUNDWATER TREATMENT FOR USE IN 

HYDRAULIC FRACTURING OF THE BAKKEN PLAY, NORTH DAKOTA 

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 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. 

One of the NGPWC’s key activities is to evaluate potential sources of water for use in 

hydraulically fracturing the Bakken Formation (Bakken), located in the Williston Basin of North 

Dakota, Montana, South Dakota, and Saskatchewan (Figure 1). The Bakken oil play is rapidly 

Figure 1. The location of the Bakken Formation within the Williston Basin. 
2 

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 fracturing to enhance the flow and recovery of oil. Water 

volumes for fracturing 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 frac, and, 

to a lesser extent, differences in varying fracture techniques. More fracturing stages require 

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 NGPWC was an assessment of the potential to 

recover, treat, and recycle fracturing (frac) flowback water from Bakken oil wells (Stepan et al., 

2010). The EERC evaluated an array of water treatment technologies, primarily mobile treatment 

systems that could utilize the high-Btu associated gas generated during the flowback operations 

to thermally treat frac flowback. However, extremely high dissolved salts in flowback water, 

combined with a relatively low recovery rate 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 EERC teamed with Hess Corporation 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 fracturing. This effort was funded by Hess, 

DOE, and the North Dakota Industrial Commission Oil and Gas Research Council. The pilot 

system was in operation from July 2010 through mid-April 2011. The following report discusses 

the current state of water use practices for Bakken fracturing, summarizes the RO pilot project 

results, and discusses the feasibility of brackish groundwater treatment for fracturing given the 

current state of water availability within North Dakota. 

CURRENT WATER USE PRACTICES 

Fracturing is increasingly being employed by oil producers in western North Dakota to 

produce the tremendous oil and gas resources of the Bakken Formation. Fracturing 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 frac fluid makeup are shown in Table 1, with water and proppants 

typically comprising 99.5% of the frac fluid makeup (U.S. Department of Energy, 2009). Frac 

fluid makeup water typically contains low total dissolved solids (TDS), will be free of bacteria, 

and be of consistent quality to ensure the ability of individual producers to generate and replicate 

the desired fracture results. 
3 

Table 1. Common Constituents of Frac 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 fracturing operation. 

Biocides Reduces the risk of well souring from microbes. 

Friction-Reducing Agents Surfactants that promote frac fluid flow. 

Polymers Forms gels to keep proppants in suspension. 

Scale Inhibitors Reduces scale formation in pipes. 

Weak Acids Helps dissolves minerals that cement formation pore spaces. 

In 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. In response to the increasing demand for freshwater, the North Dakota 

State Water Commission (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 resources and 

declining hydraulic pressures of bedrock aquifers. With the exception of the Missouri River 

system, most regional surface waters do not provide a reliable supply of water because of 

seasonal flow variations. Sufficient flows typically exist only in the spring of the year, during 

periods of snowmelt. 

Given the concerns over mining of groundwater resources, groundwater-permitting issues, 

and the relative lack of small surface water availability 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, 

several issues arise 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 an easement to 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 
4 

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

drilling locations (Energy Information Administration, 2011). 

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 and industrial (M&I) use for a fee. The Corps recommended that 100,000 acre-feet of 

water yield be made available from Lake Sakakawea for temporary M&I use over a period of 

5 years for an annual fee of $20.91 per acre-foot of yield (U.S. Army Corps of Engineers, 2010). 

While water depot and pipeline projects are in the works to improve the availability of 

freshwater resources for use in Bakken development, in the near-term, there are significant water 

access issues. 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 
5 

unresolved. In addition, the Missouri River and Lake Sakakawea are not always adjacent to areas 

of Bakken drilling; therefore, the high costs associated with long transportation distances may 

diminish the appeal of the resource. 

As part of the EERC study to evaluate the feasibility of fracturing flowback recycling 

(Bakken Water Opportunities Assessment – Phase 1), cost data for water acquisition were 

provided by several producers working in North Dakota (Stepan and others, 2010). The reported 

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

acquisition and transportation costs (including wait time). Table 2 lists a range of water-handling 

costs for Bakken frac water as of 2010. The cost to purchase raw water ranged from $0.25/barrel 

(bbl) up to $1.05/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 depended 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 ($11.90 to $41.66 per 1000 gallons). Again, 

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

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

Given the current need for water, coupled with high water acquisition, transportation, and 

disposal costs, nontraditional options for water supplies, such as desalination of brackish 

groundwater resources, are worthy of further investigation. As a result of the work conducted 

during Phase 1 of the Bakken Water Opportunities Assessment, the EERC, with the 

encouragement of the project sponsor, decided to pursue a pilot project to evaluate the feasibility 

of treating brackish groundwater. 

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 

Disposal Costs 

 Transportation $0.63–$9.00 $15.00–$214.29 

 Deep Well Injection $0.50–$1.75 $11.90–$41.66 

Total Costs $2.00–$16.80 $47.62–$400.00 

BRACKISH GROUNDWATER RESOURCES 

One advantage to utilizing brackish groundwater as a potential water supply is that the 

region is not limited by a lack of potential resources. Much of the region is underlain by what the 

U.S. Geological Survey has classified as the Northern Great Plains Aquifer System, a large 

(approximately 300,000 square miles) regional flow system comprising five major aquifers of 
6 

varying quality. These aquifers include sandstones of Tertiary and Cretaceous age, carbonate 

rocks of Pennsylvanian and Mississippian age, and sandstones and carbonates of Cambrian and 

Ordovician age (Figure 3 and Table 3). The rocks that comprise these aquifer systems were 

formed by sediment erosion from mountains to the west and subsequent deposition to the east in 

the Williston and Powder River Basins and adjacent areas (Downey and Dinwiddie, 1988). 

Water movement through these systems generally occurs from recharge areas in the 

southwestern part of the region to the northeast. Recharge occurs where the rocks are exposed at 

or near the surface in areas that were uplifted as part of the Laramide Orogeny (Bachu and 

Figure 3. Stratigraphic column showing the age and rock units associated with each of the five 

aquifer systems within the Northern Great Plains Aquifer System. 
7 

Table 3. General Description of Each of the Five Major Aquifer Units Comprising the 

Northern Great Plains Aquifer System (adapted from Whitehead, 1996) 

Hydrogeologic 

System Age Unit General Composition 

Lower Paleozoic 

 (Basal Cambrian 

 Aquifer) 

Cambrian, 

Ordovician 

Sandstone, shale, limestone, and 

dolomite; formed in a shallow marine 

environment. 

Upper Paleozoic 

 (Madison Aquifer) 

Mississippian, 

Pennsylvanian 

Limestone and dolomite with lesser 

amounts of clay, chert, and anhydrite; 

deposited in a marine environment. 

Lower Cretaceous 

 (Dakota Aquifer) 

Lower Cretaceous Sandstone; formed in marine, deltaic, and 

fluvial environments. 

Upper Cretaceous Upper Cretaceous Sandstone interbedded with siltstone, 

claystone, and local thin beds of coal or 

lignite; deposited in a continental 

environment. 

Lower Tertiary Eocene, Paleocene Interbedded sandstone, siltstone, 

claystone, and coal; deposited in a 

continental environment. 

Hitchon, 1996), including the Black Hills, Pryor Mountains, Bighorn Mountains, Beartooth 

Mountains, and Little Rocky Mountains (Iampen and Rostron, 2000). Because water within these 

systems moves along very long flow paths and remains in contact with aquifer minerals for long 

periods of time (sometimes thousands of years [Gerla, 1992]), the water is typically enriched in 

various chemical species, reflected by moderate to high TDS concentrations. In many parts of the 

system, TDS concentrations exceed the secondary drinking water maximum contaminant level of 

500 mg/L established by the U.S. Environmental Protection Agency (Whitehead, 1996). 

Figures 4–8 show the approximate extent of each of the five aquifer systems and generalized 

TDS concentrations of each (no TDS data were available for Figure 4). As a general rule of the 

thumb, the TDS concentrations are lower adjacent to uplift areas (reflecting recharge of 

freshwater) and higher in the middle of the Williston and Powder River Basins. 

While the quality of the water in many areas of these aquifers is unsuitable for drinking, at 

many locations it is of a quality suitable for cost-effective treatment. In fact, the water in many 

areas of the aquifers (mostly excluding the Williston Basin) could be classified as only 

moderately saline (Table 4). The suitability of any of these aquifers as a water supply source 

would require a site-specific evaluation, not only to assess water quality, but also to assess 

aquifer yield, depth, temperature, and sustainability. 

DESALINATION TECHNOLOGIES 

While many options exist for treatment of brackish groundwater, recent and ongoing 

improvements in desalination technology have made this an increasingly viable water treatment 
8 

Figure 4. Approximate extent of the Lower Tertiary aquifer system. 
9 

Figure 5. Approximate extent of the Upper Cretaceous aquifer system 

and generalized TDS concentrations (in mg/L).
10 

Figure 6. Approximate extent of the Lower Cretaceous aquifer system 

and generalized TDS concentrations (in mg/L).
11 

Figure 7. Approximate extent of the Upper Paleozoic aquifer system 

and generalized TDS concentrations (in mg/L).
12 

Figure 8. Approximate extent of the Lower Paleozoic aquifer system 

and generalized TDS concentrations (in mg/L). 
13 

Table 4. Classification of Water Type Based on TDS 

Concentration (Downey and Armstrong, 1977) 

Water Source TDS Concentration, mg/L 

Fresh <1000 

Slightly Saline 1000–3000 

Moderately Saline 3000–10,000 

Saline 10,000–35,000 

Seawater >35,000 

option around the world. Whereas desalination was limited by high costs in recent decades, it is 

now a cost-competitive option for many communities as available freshwater resources become 

limited or nonexistent. Because desalination is capable of treating water with varying degrees of 

salinity, including seawater, brackish ground and surface water, and wastewater, desalination has 

wide-scale applications across the globe. Since the early 1970s, desalination has gained a 

foothold in the United States as a practical source of high-quality water supply and is now 

providing high-quality water for municipal and industrial use. 

Desalination can be defined in simple terms as a water treatment process that removes 

dissolved minerals from water. There are two commonly employed water desalination 

technologies: thermal (distillation) and membrane. Thermal technologies heat water and collect 

the condensed vapor to produce distilled water. The most common thermal technology is 

multistage flash (MSF) distillation (Figure 9), which employs thermal heating and reduced 

pressure to flash liquid water to vapor in a series of stages, each of which is at a lower pressure. 

Thermal desalination is most commonly practiced in areas with abundant fossil fuels to 

capitalize on cogeneration of power and water, such as in the Middle East. Rarely are thermal 

Figure 9. MSF distillation (Miller, 2003). 
14 

processes used to desalinate water with less than 10,000 mg/L of TDS; indeed, the vast majority 

of these applications use seawater as the feed source, which typically has a TDS concentration of 

35,000 mg/L. Thermal technologies are generally not cost-effective for low-TDS waters. 

Membrane technologies are much younger in development than thermal technologies. 

Membrane technologies were developed for commercial and municipal water supplies in the 

1970s, while thermal technologies have been in practice for over a century. As the name implies, 

membrane treatment removes dissolved minerals from solution using filtration through a 

semiporous membrane. The three main types of membrane treatment for dissolved salts include 

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

The International Desalination Association’s (IDA) Desalination Yearbook 2011–2012 

(IDA, 2011) indicates the global capacity for desalination grew to 77.4 million m3

/day 

(20.4 billion gallons/day) with 71.9 million m3

/day (19.0 billion gallons/day) of this currently 

online and 5.5 million m3

/day (1.4 billion gallons/day) of capacity under construction. Figure 10 

illustrates that this capacity represents substantial growth over the last decade which is 

anticipated to continue well into the next. The information in the figure also reveals that while 

the capacity of thermal desalination plants continues to grow at a steady pace, membrane-based 

capacity is expanding at an accelerating pace. 

The total global desalination output comes from approximately 16,000 desalination plants 

which vary in size from very small systems producing less than 0.365 million m3/year 

(96.4 million gallons/year) of product water to very large systems producing up to 321.2 million 

m3/year (84.8 billion gallons/year) (IDA, 2011). The bulk of this capacity is for production of 

Figure 10. Cumulative worldwide desalination capacity (Birkett, 2010).
15 

municipal supplies. The primary source of feedwater is seawater followed by brackish water as 

illustrated in Figure 11. The distribution of desalination capacity around the world is illustrated 

in Figure 12. The figure shows that greater that 53.4% of existing capacity is located in the 

Middle East, 17% in North America, 10.6% in Asia, and 10.1% in Europe. Africa, Central 

America, South America and Australia together account for another 9%. 

Within the United States, approximately 180 municipal and rural water systems use 

desalination for part or all of their water supply. Approximately 94% of this capacity is generated 

using membrane technology. Together, these processing facilities produce over 787 MGD of 

water for municipal use. Historically, the source water for these desalination plants was seawater, 

but with advances in RO treatment technology, brackish surface or groundwater sources are 

increasingly being used. 

MEMBRANE TECHNOLOGY 

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. 

Figure 11. Desalination feedwater sources in the desalination market (DesalData.com, 2011). 
16 

Figure 12. Distribution of desalination capacity (Tinos and Culligan, 2009). 

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 3 to 4 times per 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% (compared to 

RO’s 75%–85% permeate recovery capacity and 99% salt rejection rate). A significant 

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

2008). 

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

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

seen in Table 5. As a result, NF is most commonly used for water softening and for nondesalting 

applications, such as removal of organic compounds. Given the high concentration of 

monovalent ions (such as sodium and chloride) in Dakota water, NF is not the best membrane 

treatment option for producing a low-TDS water. 

RO is a membrane-based technology that employs dynamic pressure to overcome the 

osmotic pressure of the saline feedwater. RO uses thin, semipermeable membranes (Figure 13) to 

separate the feed stream into two streams of differing TDS concentration: a low-TDS product 

(permeate) and a high-TDS brine (concentrate). Pressure forces pure water through a membrane 

that retains dissolved solids. The retained dissolved solids are rejected from the system in the 

concentrate stream. The concentrate is disposed of either by introduction into a receiving water 

Body (ocean), evaporation ponds, or deep well injection into a geologic formation. The permeate 

is collected as product for beneficial uses. 
17 

Table 5. Comparative RO and NF Species Rejection Rates 

(Bisconer, 1998) 

Species RO, % NF, % 

Sodium Chloride, NaCl 99 0–50 

Sodium Sulfate, Na2SO4 99 99 

Calcium Chloride, CaCl2 99 0–60 

Magnesium Sulfate, MgSO4 >99 >99 

Sulfuric Acid, H2SO4 98 0 

Hydrochloric Acid, HCl 90 0 

Fructose, MW* 180 >99 >99 

Sucrose, MW 360 >99 >99 

Humic Acid >99 >99 

Viruses 99.99 99.99 

Proteins 99.99 99.99 

Bacteria 99.99 99.99 

* Molecular weight. 

Figure 13. Photo of RO treatment membranes used to desalinize water 

in El Paso, Texas (Hutchinson, 2007).
18 

For the purposes of this study, RO was deemed the most appropriate and cost-effective 

technology for treatment of Dakota water. ED and EDR were not considered because of their 

reduced salt rejection rates and high system cost. As previously mentioned, NF was not 

considered because of its inability to remove monovalent ions. Figure 14 is a simplified 

schematic of an RO system. 

RO FEEDWATER PRETREATMENT 

Pretreatment of the feedwater for a RO plant is required to ensure that constituents present 

in the raw water supply do not cause plugging, fouling, or damage to the membranes, with a 

resulting loss of performance and a reduction in output of the facility. 

RO Pretreatment Goals 

 Biological activity and fouling – Biological fouling is generally not an issue with water from 

deep aquifers, such as the Dakota, that typically do not contain organic carbon at levels that 

support biological growth. However, given that the Dakota is a commonly targeted zone for 

produced-water disposal, residual hydrocarbons may create issues for treatment.

 Iron oxide fouling – Water from deep aquifers often contains dissolved ferrous iron (Fe2+). 

Reduced iron remains in solution and will be removed by RO membranes; however, if any 

air is inadvertently introduced into the system, insoluble iron oxide will be formed. Iron 

oxide will foul the membrane, which requires, at a minimum, system shutdown and cleaning. 

Figure 14. Block diagram of RO system. 
19 

There is a very real possibility that the iron fouling will destroy the permeability of the RO 

membrane, necessitating membrane replacement. Iron oxide formation is prevented by 

chlorine addition to induce iron precipitation, with subsequent filtration for iron removal 

prior to RO treatment. Excess free chlorine can damage membranes, so it is removed with the 

addition of bisulfite. 

 Mineral scale – CaCO3 or CaSO4 scale formation occurs when the solubility limit of these 

compounds is exceeded on the concentrate side of the RO membrane. These scales can foul 

the membrane, requiring costly cleaning or replacement of RO membranes. Scale prevention 

can be successfully accomplished by adding antiscaling chemicals to the feedwater after iron 

removal. 

 Silica precipitation – SiO2 can precipitate out of the concentrate and form scale deposits that 

are very difficult to remove and may irreversibly damage membranes. Scale prevention can 

be successfully accomplished by adding SiO2 antiscaling chemicals to the feedwater. 

 Colloidal and particulate fouling – Some particulates and colloids, such as colloidal silica, 

are effectively removed via sand, cartridge, or stainless steel mesh filtration systems. 

Pretreatment Processes 

Pretreatment processes appropriate for RO systems include chlorine injection to precipitate 

iron, a scale inhibitor injection system to prevent scale formation, a fine filtration system to 

remove suspended solids and iron precipitate, and a cleaning system to periodically perform 

cleaning of the membranes and piping system. 

 Iron oxidation system – Iron oxide formation is prevented by chlorine addition to induce iron 

precipitation, with subsequent filtration for iron removal. If iron removal is required, the 

chlorine additive step precedes the filtration step, and the precipitated iron is removed by the 

filtration system. Systems for storing and introducing these chemicals include bulk and day 

storage tanks, metering pumps, monitoring and control systems, and safety equipment. 

 Fine filtration system – This usually involves the use of sand, cartridge, or stainless steel 

mesh filters with a 5–10-μm particle-size nominal retention. These filters are designed to 

prevent total suspended solids (TSS) from damaging either the feed pump or the membranes. 

Sometimes, the filters are located downstream of the feed pumps, in which case a fine mesh 

strainer would be included upstream to protect the pump from TSS. 

 Scale control system – Most RO systems require adding a scale inhibitor and, perhaps, acid 

addition, for CaCO3 or CaSO4 scale control in the membrane array, since at least one 

constituent of the feedwater will often be supersaturated in the concentrate. Silica 

antiscalants may also be added as necessary. Systems for storing and introducing these 

chemicals include bulk and day storage tanks, metering pumps, monitoring and control 

systems, and safety equipment. The antiscalant chemicals are added after the fine filtration 

system. 
20 

 Cleaning system – It is good engineering practice to include a cleaning system in the 

requirements for a commercially sized RO system. A typical cleaning system consists of one 

or two tanks, a recirculation pump, a fine filtration device, and control and monitoring 

instrumentation. 

Permeate Treatment 

The permeate from RO plants is often blended with a portion of the feedwater to produce a 

finished water that is less corrosive to metal components in the water system and to increase the 

finished water yield. The secondary drinking water standard for TDS is 500 mg/L and is often 

the target to which the blending is aimed, with consideration to concentrations of sulfate, 

sodium, and perhaps other constituents. Stabilization of the water may require pH adjustment to 

an 8.0–9.0 range and addition of a low concentration of lime (CaO). The permeate is bacteriaand virus-free and is suitable for distribution after stabilization chlorination. 

Concentrate Disposal 

The RO system concentrate contains elevated concentrations of the salts contained in the 

feedwater and must be disposed of in an environmentally acceptable manner. Deep well injection 

is a common method for disposal of industrial, municipal, and liquid hazardous waste and is 

increasingly being considered as an option for disposal of desalination plant concentrate (Glater 

and Cohen, 2003). This method is used quite extensively in the western part of North Dakota for 

disposal of water produced from oil production. While other methods of concentrate disposal are 

available, such as evaporation ponds, evaporation/crystallization systems, and/or atomization/ 

land application, the most cost-effective method of concentrate disposal is likely through deep 

well injection. 

PILOT PROJECT BACKGROUND 

Site Description 

This project was conducted near Tioga, North Dakota, at an existing site where a 

groundwater well site is screened in the Dakota Formation (Dakota) at a depth of approximately 

5500 feet. The Dakota is part of the Lower Cretaceous aquifer system and is one of the most 

widespread aquifers in North America. It 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 fracturing, made the 

economic and technical evaluation of the Dakota’s potential as a water supply source for the oil 

industry a logical endeavor. 
21 

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 bbl per day (320 to 

350 gallons per minute [gpm]) for several decades with no measurable impacts to hydrostatic 

water levels (Hess Corporation, personal communication, 2009); therefore, the additional 

pumping rate required for the relatively short duration of the pilot project was inconsequential. 

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. Specific information on water chemistry is listed in Table 6. Because the Dakota is 

at such a great depth beneath the surface, the water exits the well at a temperature of 

approximately 155°F (68°C). 

A key 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 corresponding inability 

to produce permeate at a high rate. Corrosion can be affected by chemical composition, 

temperature, pH, degree of aeration, flow velocity, and pressure. System-specific testing is 

helpful to most accurately evaluate corrosion potential. Therefore, the EERC conducted 

corrosion rate testing of the feedwater and concentrate streams to determine proper heat 

exchanger, piping, and valve material selection for a full-scale plant. 

CORROSION AND SCALE FORMATION MODELING 

A two-step approach was used to evaluate the corrosion potential of Dakota water during 

the pilot study. The first step was to evaluate the corrosion potential of various metals and alloys 

using computer modeling. The second step was to use the modeling results, coupled with an 

evaluation of materials likely to be used for a full-scale RO plant, to select corrosion coupons for 

installation and testing in conjunction with the pilot project. The following section describes the 

results of the corrosion analysis modeling, which also includes an evaluation of the scaling 

potential of the water. The results of the field-based testing of metal and alloy coupons are 

discussed later in this report. 

The model-based evaluation of Dakota water was conducted 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 RO concentrate 

chemistry (at 60% recovery).1

 Corrosion rates for 19 metals and alloys were calculated for a 

water composition representing raw Dakota Aquifer water. Corrosion rates for carbon steel 

(A212B) and 316 stainless steel were also modeled using water compositions representing RO

 

1

 Dr. Robert Cowan wishes to acknowledge and thank OLI Systems, Inc., for allowing his use of the Lab Analyzer, 

Stream Analyzer, and Corrosion Analyzer software for this project. The software was provided free of charge as part 

of a 3-month “Friends of OLI” license.
22 

Table 6. Water Chemistry Results for Dakota Aquifer Samples

Analyte Average Value Units 

Ba 0.11 mg/L 

Ca 11.85 mg/L 

Cl 4220 mg/L 

F 3.9 mg/L 

Fe 0.17 mg/L 

Mg 2.4 mg/L 

Mn 0.04 mg/L 

NO3 <1 mg/L 

P, Total <0.1 mg/L 

PO4 0.94 mg/L 

K 14.4 mg/L 

Si 16.3 mg/L 

Na 3755 mg/L 

SO4 499.5 mg/L 

HCO3 1763 mg/L 

Al <0.1 mg/L 

Cu 0.0034 mg/L 

Hg <0.1 μg/L 

Pb 0.0024 mg/L 

Sr 0.9 mg/L 

Temperature (field) 152 °F 

pH (lab) 7.8 – 

Conductivity (lab) 14.1 mS/cm 

Conductivity (field) 13.88 mS/cm 

TDS (measured) 8820 mg/L 

TDS (calculated) 10,339 mg/L 

TSS 14.0 mg/L 

Turbidity 2.2 NTU1

Alkalinity (as CaCO3) 1445 mg/L 

Hardness (as CaCO3) 39 mg/L 1

 Nephelometric turbidity units. 

feed and RO reject brine based on water chemistry provided by Hess. The water chemistry was 

based on an RO recovery rate of 60%, slightly less than the 72% average recovery achieved 

during the pilot project; however, at the time that the modeling work was conducted, a target 

recovery had not yet been established for the pilot. Scaling tendencies of all three waters were 

also calculated using the OLI Systems software. All calculations were performed over a 

temperature range of 70° to 170°F. 
23 

Dakota Aquifer Water Composition 

The water chemistry shown in Table 6 was used as the basis for building the water 

chemistry conditions used in the corrosion calculations. The procedure used was to enter the 

Dakota Aquifer water analysis results in the OLI Systems Lab Analyzer software and reconcile 

the charge balance, pH, and alkalinity. The final composition of the water used in corrosion 

modeling is shown in Table 7. 

Scaling Tendency 

Scaling tendency is a measure of the likelihood of a dissolved species to precipitate from 

solution as a solid-phase chemical species. The results of the scaling tendency analysis for 

Dakota Aquifer water at 152°F are shown in Table 8. Only the 10 highest of the 128 scaling 

tendency values calculated are given. The results indicate that dissolved solids are likely to 

precipitate as a scale. A scaling tendency value of 1 indicates the water is supersaturated with 

respect to that mineral. A scaling tendency below 1 indicates mineral components are present at 

concentrations below saturation, but at values near 1, scaling may still be of concern. The scaling 

tendencies shown in Table 8 indicate that fluorapatite (Ca5[PO4]3F) and four carbonates, siderite 

Table 7. Lab Analysis Values Entered into OLI Lab Analyzer Software 

and Values after Reconciling Charge Balance, pH and Alkalinity 

(charge balance adjusted by addition of chloride ion; pH and alkalinity 

did not require adjustment)

 Input Calculated Units % Diff. 

Water 1.00E+06 9.94E+05 mg/L −0.62 

Si 16.3 16.3 mg/L 

Ba 0.11 0.11 mg/L 

Ca 11.85 11.85 mg/L 

Fe 0.17 0.17 mg/L 

Mg 2.4 2.4 mg/L 

Mn 0.04 0.04 mg/L 

K 14.4 14.4 mg/L 

Na 3755 3755 mg/L 

Al 0 0 mg/L 

Cu 0.003 0.003 mg/L 

Hg 0 0 mg/L 

Pb 0.002 0.002 mg/L 

Sr 0.9 0.9 mg/L 

Cl 4220 4390 mg/L 4.03 

F 3.9 3.9 mg/L 

NO 0 0 mg/L 

PO4 0.94 0.94 mg/L 

SO4 499.5 499.5 mg/L 

HCO3 1763 1763 mg/L 
24 

Table 8. Scaling Tendency Values for the Ten Minerals 

Having the Highest Scaling Tendencies for Dakota Aquifer 

Water at 152°F and pH 8.2 (results valid through full 

temperature range evaluated [70°–170°F])

Solids Within Temperature Range Scaling Tendency 

Fluorapatite, Ca5(PO4)3F 1 

Iron(II) Carbonate 1 

Manganese(II) Carbonate 1 

Strontium Carbonate 1 

Calcium Carbonate (calcite) 1 

Barium Sulfate 0.624 

Copper(II) Hydroxide 0.014 

Magnesium Carbonate 0.011 

Strontium Sulfate 0.008 

Iron(II) Hydroxide 0.007 

(FeCO3), magnesite (MgCO3), strontianite (SrCO3), and calcite (CaCO3), will form a precipitate 

or scale unless the chemistry and/or temperature of the water is adjusted. Acid addition and 

removal of CO2 through aeration of the water should eliminate the potential for calcite 

precipitation. The use of other scale inhibitors may be required to prevent fluorapatite 

precipitation. The apparent molecular composition of the solution suggests that the dominant 

solid formed would be calcium carbonate. The fact that the scaling tendency for barium sulfate is 

close to 1 is a potential concern. Barium sulfate scales are often associated with naturally 

occurring radioactive material (NORM) that can cause difficulties with respect to maintenance, 

reuse, and disposal of pipes and process equipment. The NORM issue arises because barium 

(and strontium) scales tend to coprecipitate radioactive radium. 

Corrosion Evaluation 

The 19 metals and alloys selected to evaluate the corrosion potential upon exposure to 

Dakota water are listed in Table 9. These include iron (two grades), carbon steel (four grades), 

stainless steel (four grades), aluminum alloys (two grades), nickel, and six other iron alloys (four 

Inconel® and two Hastelloy®). These are all of the metals and alloys available in the public 

database in OLI Systems Corrosion Analyzer software. Unfortunately, there was no option to 

evaluate titanium. Corrosion rate calculations were performed for flowing water over the 

velocity range of 0 to 20 ft/s and for every 10 degrees of temperature from 70° to 170°F. Table 9 

includes a summary of the corrosion rate range for all of the metals and alloys studied. The 

lowest rate is always for the condition of 70°C and 0 ft/s. The highest rate is always for 170°C 

and 20 ft/s. 

The results of the corrosion analyses were compiled in plots showing the corrosion rate in 

mils per year (mpy) versus the water flow velocity. Figure 15 shows an example of the modelpredicted corrosion rate of carbon steel (212), stainless steel (316), and Hastelloy C-276. It 

should be noted that these are semi-log plots that show corrosion rates over a range of four 

orders of magnitude. The carbon steel exhibited a moderate corrosion rate and would be 
25 

Table 9. Range of Corrosion Rates Calculated for All 19 Metals and Alloys Studied

Metal or Alloy Name 

Lowest Calculated Corrosion 

Rate (mpy) (velocity = 0 ft/s; 

temperature = 70°F) 

Highest Calculated Corrosion 

Rate (mpy) (velocity = 

20 ft/s; temperature = 170°F) 

Fe (zone refined) 0.051 0.278 

Fe (pure) 0.051 0.278 

Carbon Steel A212B 0.102 2.799 

Carbon Steel A216 0.102 2.799 

Carbon Steel G10100 (generic) 0.102 2.709 

Carbon Steel 1018 0.102 2.732 

Stainless Steel 304 0.104 0.275 

Stainless Steel 316 0.018 0.096 

Stainless Steel Alloy 254SMO (alloy

 254, vlx954) 

0.011 0.075 

10% Cr Stainless Steel 0.073 0.346 

Aluminum 1199 (pure) 0.066 16.890 

Aluminum 1100 0.065 16.811 

Ni 0.021 0.230 

Superalloy Inconel 600TM 0.005 0.019 

Inconel Nickel Chromium Alloy 625 0.004 0.008 

Superalloy Inconel 690TM 0.004 0.018 

Incoloy 825® 0.004 0.009 

Hastelloy Alloy C-276 0.004 0.008 

Hastelloy C-22 0.004 0.008 

Figure 15. Predicted corrosion rates of carbon steel (A221B), stainless steel (316), 

and Hastelloy C-276 by raw Dakota water. 
26 

acceptable for use under certain conditions. The stainless steel had a very low rate of corrosion 

and should be acceptable for use over the full range of conditions for which calculations were 

performed. The Hastelloy C-276 alloy exhibited an even lower rate of corrosion and would 

certainly be suitable for use with Dakota water; however, the additional cost of the alloy over 

stainless steel may prohibit its use. 

It is interesting to note that while the stainless steel and Hastelloy C-276 (as well as most 

other alloys evaluated) showed very little variation in the predicted corrosion rate as a function 

of flow velocity, the carbon steels that were evaluated were highly influenced by the flow 

velocity over the range of temperatures evaluated (Figure 16). This may be of significance if 

interest in using water from the Dakota increases since carbon steel pipes are commonly used in 

North Dakota’s oil and gas operations. 

The acceptability of the calculated corrosion rate depends on the material and the 

application. For example, to evaluate the severity of the carbon steel corrosion rates calculated 

using the OLI software, a comparison of corrosion rates was made to guidelines developed by 

Boffardi (2010) and Puckorius (2003) for open and closed recirculating cooling water systems 

(Tables 10 and 11). The modeled corrosion rates for carbon steel ranged from negligible to 

severe, depending on the temperature, velocity, and application. More specifically, the lowest 

rate of corrosion for Carbon Steel A212B was found to be 0.102 mpy for a velocity of 0 ft/s and 

a temperature of 70°F. This is considered to be negligible corrosion for an open recirculating 

cooling water system and mild corrosion for a closed recirculating cooling water system. The 

highest rate of corrosion for Carbon Steel A212B was found to be 2.799 mpy for a velocity of 

20 ft/s and a temperature of 170°F. This is considered mild for open recirculating cooling water 

systems and severe for closed recirculating cooling water systems. 

Figure 16. Predicted corrosion of Carbon Steel A212B by Dakota water over a range of 

temperatures and flow velocities. 
27 

Table 10. Quantitative Classification of Carbon Steel 

Corrosion Rates for Open Recirculating Cooling Water 

Systems 

Description Corrosion Rate, mpy 

Negligible or Excellent Less than or equal to 1 

Mild or Very Good 1 to 3 

Good 3 to 5 

Moderate to Fair 5 to 8 

Poor 8 to 10 

Very Poor to Severe >10 

Table 11. Quantitative Classification of Carbon Steel 

Corrosion Rates for Closed Recirculating Cooling 

Water Systems 

Description Corrosion Rate, mpy 

Excellent Less than or equal to 0.2 

Good 0.2 to 0.5 

Moderate 0.5 to 0.8 

Poor 0.8 to 1 

Very Poor to Severe Greater than or equal to 1 

Within these systems, stainless steel corrosion is more simply classified in both systems as 

acceptable for rates less than 0.1 mpy or unacceptable for rates greater than 0.1 mpy. In these 

systems, pitting of any metal is considered unacceptable. 

Based on the results of the corrosion analyses and the corrosion rate classification of the 

various materials, the metals were ranked into five groups, as shown in Table 12. Corrosion rates 

vary over 4 orders of magnitude, with the lowest rates being <0.004 mpy for Alloys C-22, C276, 625, and 825 and the highest rates being near 16.8 mpy for Aluminum 1100 and Aluminum 

1199. It should be noted that the corrosion rates were calculated for an environment containing 

no dissolved oxygen. 

Table 12. General Classification of Metals and Alloys Based on the 

Calculated Corrosion Rates with Dakota Water

Excellent Alloys C-22, C-276, 625, and 825

Alloys 600 and 690

Very Good Alloy 254SMO and Stainless Steel 316 

Good Fe (pure), Fe (zone refined), Ni, Stainless Steel 

304, and 13% Cr stainless steel

Fair Carbon Steel 10100,1018, A216, and A212B 

Very Poor/Unacceptable Aluminum 1100 and 1199 (pure)
28 

These results, along with information on the price and availability of metals for use in heat 

exchangers, as well as knowledge on standard material use in the oil field were used to help 

guide in the selection of corrosion test coupons. Selected corrosion test coupons were 

subsequently installed at the RO treatment pilot project site for field testing. Those results are 

discussed later in this report. 

Corrosion and Scaling Analysis for Anticipated RO Concentrate (at 60% recovery) 

Additional corrosion calculations were performed based on a predicted brine (concentrate) 

composition of Dakota water after treatment with RO at 60% recovery. These data were much 

less detailed than that used for the raw Dakota water analysis discussed above. No scaling or 

corrosion analyses were done for RO permeate. 

The same methodology used to evaluate the raw Dakota water was used to evaluate the 

anticipated RO concentrate. The water analysis results were entered into the OLI Systems 

software and reconciled with respect to electroneutrality, pH, and alkalinity (Table 13). The 

scaling tendency values were also calculated and are shown in Table 14. The resulting apparent 

molecular composition of the water was obtained and used to calculate corrosion rates for two 

metals (316 stainless steel and Carbon Steel A212B) over the temperature range of 70° to 170°F 

and water velocities of 0 to 20 ft/s. 

Table 13. RO Concentrate Water Analysis and Reconciliation 

 Input Calculated Unit % Diff. 

Water 1.00E+06 9.91E+05 mg/L −0.88 

Si 81 81 mg/L 

Ca 26.2 26.2 mg/L 

Mg 4.5 4.5 mg/L 

K 22.5 22.5 mg/L 

Na 6777 6777 mg/L 

Cl 7875 8203 mg/L 4.16 

SO4 972 972 mg/L 

HCO3 2772 2772 mg/L 

Table 14. Scaling Tendency for RO Concentrate (minerals 

with 5 highest values) (values are valid over the temperature 

range evaluated [70°–170°F]) 

Tendency Scaling 

Calcium Carbonate (calcite) 1 

Calcium Carbonate (aragonite) 0.514 

Calcium Carbonate Monohydrate (vaterite) 0.130 

Sodium Bicarbonate (nahcolite) 0.010 

Calcium Sulfate Dehydrate (gypsum) 0.003 
29 

The only reconciliation required for the RO concentrate was the addition of a small amount 

of chloride ion in order to obtain electroneutrality (Table 15). Scale formation with calcium 

carbonate minerals in the concentrate is possible even at the temperature of the water analysis, 

25°C, as evidenced by the scaling indices given in Table 15. Because the simplified water 

analysis did not include strontium, barium, or fluoride, the analysis could not identify a potential 

for the formation of the other scale minerals identified for the more detailed Dakota Aquifer 

water. 

Table 15 contains the lowest and highest calculated corrosion rates for both carbon steel 

and stainless steel. As would be expected, the results suggest that the RO concentrate would be 

more corrosive to Carbon Steel A212B and 316 stainless steel than the raw Dakota water. While 

the corrosion rate of 316 stainless steel was very similar between the raw Dakota water and RO 

concentrate, the predicted corrosion rate of Carbon Steel A212B was considerably higher with 

the RO concentrate, particularly with increasing flow rate and at higher temperatures. These rates 

suggest that Carbon Steel A212B would be unacceptable for use with the RO concentrate except 

at the lowest flow rate and temperature conditions. The rates predicted for 316 stainless steel 

suggest that it would be acceptable for use with the RO concentrate at 60% recovery. 

MOBILE RO TREATMENT SYSTEM 

After evaluating several mobile technology treatment system providers, Hess selected 

General Electric (GE) Water and Process Technologies as the preferred pilot system provider. 

GE’s MobileRO® 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, GE estimated that, at full capacity, the system would be capable of producing 

approximately 160 gpm of permeate at a 75% recovery rate. Because the system contains two 

independently operated filter arrays, it could also be operated at reduced capacity, equivalent to 

approximately 80 gpm of permeate at a 75% recovery rate. The mobile system contained all 

necessary prefilters, the antiscalant treatment system, controls, piping, valves, and 

instrumentation. All operations associated with the mobile RO unit were the responsibility of GE 

personnel for the duration of the pilot test. 

Table 15. Range of Corrosion Rates Calculated for Carbon Steel A212B and S316 Stainless 

Steel by the Anticipated RO Concentrate 

Metal or Alloy Name/Water 

Lowest Calculated Corrosion 

Rate, mpy (velocity = 0 ft/s; 

temperature = 70°F) 

Highest Calculated Corrosion 

Rate, mpy (velocity = 20 ft/s; 

temperature = 170°F) 

Carbon Steel A212B 0.184 7.919 

316 Stainless Steel 0.018 0.096 
30 

SITE PREPARATION 

In order to prepare the site for the pilot project, several activities were conducted, including 

the following: 

• 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 

fracturing locations within the Bakken play. 

• Installation of corrosion coupon 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 was the cooling of the feedwater, which 

exited the production well at a temperature of approximately 155°F (68°C), down to the required 

90°F (32°C) prior to membrane treatment during the summer months, when temperatures can 

exceed 90° or 100° and humidity can be high. In fact, the pilot project cooling system did not 

provide sufficient cooling capacity during a couple of the hottest days of the summer, resulting in 

system shutdown during the afternoon hours. While the high feedwater temperature was an 

inconvenience with respect to the RO membranes, 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 (Hess Corporation, personal communication, 2010). Therefore, 

heat exchangers were installed by Aggreko at the pilot project site to partially cool the feedwater 

using the RO permeate, which exited the system at approximately 90°F (32°C), and, in turn, to 

heat the permeate prior to use as frac water makeup. 

As previously mentioned, because of the potential corrosivity of the feedwater and RO 

concentrate, in situ corrosion testing was conducted as part of the pilot test. 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 of the RO system. The location of the test racks as well as a generalized 

layout of the pilot-scale RO system is depicted in Figure 17. Groundwater from the Dakota 
31 

Figure 17. Flow diagram with corrosion test rack locations. 

Aquifer was pumped from the well to a surge tank (pressure vessel). Water was routed from the 

surge tank to a 400-bbl feedwater tank where it was stored prior to entering the cooling, 

pretreatment, and RO systems. The first corrosion coupon test rack (S-1) was installed to 

evaluate feedwater corrosivity just prior to cooling. The first step in the cooling process was a 

tube-and-shell heat exchanger between the hot feedwater and the RO permeate, followed by an 

air-cooled system with foggers. The temperature of the hot feedwater from the storage tank prior 

to cooling was approximately 125°–130°F. After passing through the cooling system, the 

feedwater was lowered to a temperature of approximately 80° to 90°F. The second corrosion 

coupon test rack (S-2) was installed at this point in the system to evaluate the corrosivity of the 

cooled feedwater before undergoing pretreatment. Prior to entering the RO trains, the water 

underwent pretreatment via sand filtration and granulated activated carbon adsorption to remove 

suspended solids and dissolved organics, respectively. It was very important to remove any 

organic carbon from the feedwater, since this can result in membrane fouling. The water was 

then routed through one of the two RO treatment trains. Upon exiting the RO membranes, the 

permeate was routed back through the heat exchangers to help cool the feedwater, prior to 

storage in the lined and covered pond. Corrosion test racks were installed to evaluate the 

permeate upon exiting the system (S-3) and following heat exchange with the permeate (S-4). 

The concentrate was routed to a 400-bbl storage tank prior to blending with raw Dakota water for 

injection into existing waterflood operations. The corrosion potential of the concentrate just after 

exiting the RO system was evaluated at location S-5. In addition to evaluating the corrosivity of 

the concentrate at 80° to 90°F, a titanium plate and frame heat exchanger was installed at the site 

and coupled with the feedwater to heat the concentrate up to approximately 115° to 120°F (S-6). 

This evaluation was conducted to assess the corrosivity of the concentrate in the event that it be 

used in a heat exchanger as part of the cooling system for future applications. 
32 

PILOT TEST OPERATION AND PERFORMANCE 

The pilot project system began operation on July 21, 2010, at a permeate flow rate of 

80 gpm and 50% permeate recovery. Higher permeate recovery rates were not achievable until 

GE performed system modifications on August 3, 2010, at which time the recovery rates 

increased to approximately 70%. GE continued to operate the RO system at a 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 was used for fracturing 

the Bakken, and the concentrate was blended with the waterflood injection system feedwater. 

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 alterations to the 

permeate holding pond, to address electrical issues at the truck loading station, and to winterize 

the site. Based on GE 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, GE did 

operate the RO system approximately 1 hour each day to prevent membrane fouling. 

After the necessary system modifications were made, GE began continuous operation of 

the RO system on November 29, 2010, and as of April 13, 2011, had processed approximately 

19 million gallons of Dakota Aquifer water. Continuous operation of the system was only 

stopped during three short periods: 

• January 1, 2011 

• February 25, 2011, through February 28, 2011 

• March 22, 2011, through March 25, 2011 

GE personnel observed lower flow rates (Figure 18), lower operating pressures (Figure 19), and 

higher permeate conductivity (Figure 20) when operating RO Train 1. Because of those 

conditions, GE primarily operated RO Train 2 throughout the demonstration and only 

occasionally operated Train 1 in order to mitigate membrane scaling. The cause of the 

operational differences between the two trains is unknown. 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. Feed water temperature was monitored during operation and is shown in Figure 21. The 

feed water temperature ranged from 62° to 95.0°F and averaged 81.3°F during continuous 

operation (November 29, 2010, through April 13, 2011). 

Feedwater flow rates were lower while Train 1 (103 gpm) was operated compared to 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. 
33 

Figure 18. Pilot-scale RO system flow rates. 

Figure 19. Pilot-scale RO system operating pressures. 
34 

Figure 20. Pilot-scale RO system permeate conductivity. 

Figure 21. Pilot-scale RO system feedwater temperature. 
35 

As expected, the RO permeate was very high quality, and all major chemical constituents, 

except iron (Fe), were below Environmental Protection Agency secondary drinking water 

standards. As shown in Table 16, there was a 97% reduction in TDS concentration along with a 

96% reduction in conductivity. Most major chemical constituents in the feedwater were reduced 

by greater than 90%. Alkalinity was reduced by 94%, and pH was measured at 6.06 in the 

permeate. Iron was measured at higher levels in the permeate than in the feedwater. However, 

the analytical techniques used to measure the iron concentrations are less susceptible to 

interferences with clean water than with the brackish feedwater, and one could argue that the 

data are inconclusive with respect to iron. RO treatment did not appear to remove any total 

organic carbon (TOC). 

Given the issues with Train 1 operation, system performance was analyzed solely based on 

the operation of Train 2. Permeate recovery rates remained relatively consistent, averaging 

nearly 72% over the current operating period. Throughout the testing period, membrane cleaning 

was not deemed necessary, and no scaling was observed. GE personnel credited the low-turbidity 

feedwater for the lack of membrane fouling. GE performed backwash operations on a once-aweek basis as preventive maintenance. Since pressure readings did not indicate the need for more 

frequent backwashing, this frequency appeared to be sufficient to maintain desired operational 

pressures. GE records also indicated that once the system was stabilized, the feedwater 

conductivity was consistently around 14,000 μS/cm, and the permeate averaged 700 μS/cm. 

Figure 22 is a plot of conductivity of Train 2 during continuous operations. 

Each treatment train consisted of 30 RO elements, and each element was nominally 

365 square feet of surface area. This equates to each treatment train consisting of 10,950 square 

feet of surface area. By dividing the daily flow rate by the surface area of the treatment train, a 

flux rate in gallons per square foot per day (gfd) was calculated. A summary of permeate flux is 

presented in Table 17 and graphically shown in Figure 23. A regression of this data indicates that 

the flux would likely stabilize at approximately 15 gfd. 

Additionally, flux was plotted against temperature and pressure differential as presented in 

Figures 24 and 25, respectively. As expected, the flux decreases with decreasing temperatures 

but not significantly over the range of temperatures experienced during the pilot test. Differential 

pressure also did not greatly influence the system flux over the range from 5 to 15 psig. In both 

cases, the flux maintained nominally between 14 and 16 gfd for the observed range of 

temperature (60o to 95°F) and differential pressure (0 to 20 psi). 
36 

Table 16. Summary of Water Analysis Results (units in mg/L unless otherwise noted) 

Analyte 

Feedwater 

(S-1) 

Permeate 

(S-4) 

Concentrate 

(S-5, S-6)* 

% 

Reduction

Ca 15.8 3.0 44.4 81 

Na 3300 103 10,750 97 

K 9.9 <1 42.8 >90 

Cl 3710 130 13,200 96 

SO4 456 <5 1460 >99 

NO3 <0.1 <0.1 0.14 – 

HCO3 1220 74 3820 94 

Ba <0.5 <0.1 <1 – 

F 3.57 0.14 12.8 96 

Fe <0.5 0.66 <1 – 

Mg 2.6 <1 7.9 >62 

Mn <0.25 <0.05 <0.5 – 

P, total <0.1 <0.1 0.96 – 

Si 17.2 <1.1 56.3 >94 

Cu <0.25 <0.05 <0.5 – 

Sr 0.98 <0.1 2.92 >90 

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), μS/cm 13,600 568 37,700 96 

Conductivity (field), μS/cm 15,400 610 41,500 96 

Total Dissolved Solids 

(calculated) 

8230 280 27,800 97 

Alkalinity (as CaCO3) 1220 74 3820 94 

Hardness (as CaCO3) 50.2 7.49 144 85 

Total Organic Carbon 5.9 4.9 7.1 17 

* 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.
37 

Figure 22. Treatment Train 2 feedwater and permeate conductivity. 

Table 17. Summary of Flux Calculations 

Treatment Train Minimum, gfd Maximum, gfd Average, gfd 

Train 1 11.57 17.23 13.51 

Train 2 14.73 17.75 16.29 

Figure 23. Treatment Train 2 flux versus time. 
38 

Figure 24. Flux versus temperature. 

Figure 25. Flux versus pressure differential.
39 

FIELD-BASED CORROSION TESTING 

Shortly after start-up of the system, six corrosion test racks were installed at the subject 

site. Based on corrosion modeling results presented earlier, the test coupons selected for 

evaluation included four standard materials: 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 a nickel–molybdenum–chromium wrought alloy characterized by versatile 

corrosion resistance. The coupon racks were constructed of 3⁄4-inch Schedule 80 PVC (polyvinyl 

chloride) pipe which has an internal diameter of 0.722 inches. The type of test coupon and 

operating conditions for each rack are included in Table 18. The discharge from Racks S-1, 2, 3, 

and 4 were manifolded together and plumbed to discharge into the feed tank. Figure 26 is a 

photograph of Rack S-2, a five-place corrosion test rack assembly. The discharge from Racks S5 and S-6 were plumbed to discharge into the reject tank. During the installation and testing of 

the racks, EERC personnel were unable to attain enough water flow through Racks S-3 and S-4 

to maintain desired corrosion test conditions. 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. Since permeate 

corrosivity was expected to be minimal, no test coupons were installed in Racks S-3 and S-4. 

Table 18. 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 PVC 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 PVC. 
40 

Figure 26. Photograph showing the installation of corrosion test Rack S-2. 

Following installation of the corrosion test racks, water was allowed to flow through the 

racks for several weeks to flush the system prior to coupon installation, as recommended by the 

test rack manufacturer. Sample flow rates through the coupon racks varied between 0 corrosion 

and 5 gallons per minute, corresponding to a flow velocity in the coupon racks between 0 and 

3.92 ft/s (0 and 1.19 m/s). 

The test coupons were installed in the racks in the order shown in Table 19, 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 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 a 

form of hydrocarbon, although detailed testing to determine the exact nature and source of the 

residue was never conducted. 

On November 9, 2010, the corrosion racks and associated piping were retrieved to prevent 

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 residue to determine its 

exact composition has not been conducted. 
41 

Table 19. Comparison of Measured and Predicted Corrosion Rates

Rack Fluid Coupon Metal

Measured 

Corrosion 

Rate, mpy

Predicted 

Corrosion 

Rate, 

mpy

Temperature 

and Flow 

Rate for 

Predicted 

Rate2

S-1 Feedwater, 127°F Ti-2 Titanium 0.0968 NA

S-1 Feedwater, 127°F C276 Hastelloy 0.0472 0.0061 130°F, 4 ft/s

S-1 Feedwater, 127°F 316L Stainless steel 0.0724 0.0525 130°F, 4 ft/s

S-1 Feedwater, 127°F CDA706 Copper–nickel 0.7528 NA

S-1 Feedwater, 127°F API 5LX42 Carbon Steel 1.2684 0.631 130°F, 4 ft/s

S-2 Feedwater, 80°F Ti-2 Titanium 0.0639 NA

S-2 Feedwater, 80°F C276 Hastelloy 0.0402 0.00407 80°F, 4 ft/s

S-2 Feedwater, 80°F 316L Stainless steel 0.0590 0.0219 80°F, 4 ft/s

S-2 Feedwater, 80°F CDA706 Copper–nickel 2.2485 NA

S-2 Feedwater, 80°F API 5LX42 Carbon steel 1.9256 0.256 80°F, 4 ft/s

S-5 Concentrate, 96°F Ti-2 Titanium 0.0542 NA

S-5 Concentrate, 96°F 316L Stainless steel 0.0601 0.0319 100°F, 4 ft/s

S-5 Concentrate, 96°F API 5LX42 Carbon steel 2.0864 1.10 100°F, 4 ft/s

S-6 Concentrate, 118°F Ti-2 Titanium 0.0716 NA

S-6 Concentrate, 118°F 316L Stainless steel 0.0501 0.0449 120°F, 4 ft/s

S-6 Concentrate, 118°F API 5LX42 Carbon teel 2.0249 1.65 120°F, 4 ft/s 1

 Corrosion rate units on the figures at mm/year. To convert mm/yr to mil/yr multiply by 39.37 mil/yr/mm/yr. 2

 Figures only show values for every 20° of temperature change but calculations were performed at 10° intervals. 

Not available – this metal was not available in the OLI Corrosion Analyzer public database.

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 a slight 

scale 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, provided the EERC with a corrosion analysis, and then 

returned the coupons upon completion of the analysis. MSC results are shown in Table 19. 

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]
42 

Where: 

CR = Corrosion rate (mils per year) 

K = Conversion constant (3.45 × 106

) 

W = Mass loss (g) 

A = Surface area (cm2

) 

T = Exposure time (hours) 

D = Density (g/cm3

) 

Results from MSC (Table 19) 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). 

For comparison, the predicted corrosion rates, calculated at a flow velocity of 4 ft/s and 

fluid temperatures close to what was measured in the field, are also listed in Table 19 and shown 

graphically in Figure 27. While all of the predicted corrosion rates were lower than the observed 

corrosion rates, the modeling calculations did a good job of predicting the observed corrosion 

rates for both 316L stainless steel and API 5LX42 carbon steel. The modeling calculations 

substantially underpredicted the observed corrosion rates for Hastelloy C276 for the two 

conditions tested, feedwater at 80° and 127°F. For the hot feedwater (Rack S-1), this may again 

be a result of the black coating that formed on the test coupons. 

Figure 27. Comparison of measured and predicted corrosion rates.
43 

A surface analysis of select coupons was performed at the EERC 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 28 and 29, 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 28 and 29, the carbon steel exhibited more pitting corrosion than did the 

stainless steel (especially in Coupon No. 10 from Rack S-1). Figure 30 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 of 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 mpy. 

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. 

Figure 28. Profiler images of select stainless steel coupons.
44 

Figure 29. Profiler images of select stainless steel coupons. 

Figure 30. Profiler image of carbon steel coupon zoomed in to pitted area. 
45 

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. 

ECONOMIC EVALUATION 

As summarized in earlier sections, the pilot-scale RO system was operated continuously 

from November 29, 2010, through April 13, 2011. Over this period, approximately 19 million 

gallons of Dakota Aquifer water was processed to produce approximately 13.6 million gallons of 

permeate (average 71.6% recovery rate). Operation of the pilot system was intended to continue 

throughout the summer of 2011 but because of several issues that hampered continuous 

operation, the system was not operated beyond April 2011, except to prevent scaling by 

periodically circulating permeate water. 

Although the pilot RO system experienced periodic interruptions, it provided valuable 

technical and economic information regarding design and operation of a full-scale system. These 

included the operation of modular RO systems in extremely cold and hot climates, identification 

of water-handling issues, and issues of logistical coordination with oil field operations. 

Unfortunately, the intermittent operation of the pilot system made it difficult to estimate fullscale operation and maintenance (O&M) costs based on the pilot-scale operation. 

Based on conversations with Hess personnel during operation of the pilot system, Hess 

was sufficiently confident in the technical and economic viability of the RO system to proceed 

with the design and bidding of a full-scale 1- to 2-MGD RO treatment facility. 

A comparison of the estimated costs of freshwater for frac makeup from three different 

sources was performed by Hess and included 1) water from a 1-MGD RO plant (per barrel cost 

included capital and operating expenses); 2) water from existing municipal, commercial, or 

private sources; and 3) water from the planned Western Area Water Supply (WAWS) system, a 

pipeline project coupled with expansion of Williston’s water treatment plant that is currently 

being constructed in northwestern North Dakota. Hess’s internal evaluation included costs for 

heating and transportation of the water. 

Based on this internal evaluation, Hess determined that the water produced from its own 

RO plant was cost-competitive and logistically favorable compared to the current means of 

acquiring frac make-up water. As a result, Hess, jointly with GE, is proceeding with plans to 

construct a full-scale RO system. The economic details of this contractual arrangement were not 

made available for inclusion in this report. 

RO Treatment Plant Costs 

In the absence of actual bid data, the EERC made an effort to quantify the capital and 

O&M costs associated with a full-scale RO plant similar in size to that being constructed by Hess 

and GE. Estimates for equipment-only capital cost and O&M were provided by GE for a fullscale RO plant producing up to 1.5 MGD of treated water for use as a frac make-up water. 
46 

GE’s estimates of capital showed that an RO system with a treated water capacity of 

1.5 MGD would have an equipment-only capital cost of approximately $3.5 million. This capital 

cost does not include site construction or infrastructure development-related activities. A series 

of assumptions summarized in Table 20 were made to estimate the remaining costs to construct a 

1.5-MGD RO plant. The methodology to calculate each cost was based on an assumed 

percentage of the equipment-only capital cost. Using this method, the total cost to construct a 

1.5-MGD RO plant is estimated at approximately $15.75 million, not including land acquisition 

costs, the cost of providing feed water to the RO system, and the cost of RO concentrate 

disposal. 

The estimated annual O&M cost for operating the RO system, provided by GE, was 

approximately $1,000,000 not including the cost of RO concentrate disposal. 

Production Well Costs 

In addition to the capital costs for the RO plant, costs were estimated for the groundwater 

extraction well field. Based on the EERC’s experience in groundwater extraction wells 

completed in the Dakota Aquifer, five wells completed to a depth of 5500 ft would be required to 

provide the RO plant demands. At an estimated cost of $1.5 million for each well ($7.5 million 

total) and assuming an additional 10% of the total well field cost for the pumps and associated 

infrastructure, the total estimated cost for the water extraction system to provide water to the RO 

plant would be approximately $8.25 million. 

The O&M cost associated with the groundwater extraction operation was based primarily 

on the cost of electricity to run the pumps. Assuming a 30-kW pump in each of five wells 

operating for 7872 hours (328 days) a year and an electrical cost of $0.08/kWh, the electricity 

cost would be approximately $95,000. 

Brine Disposal Costs 

Two different brine disposal options were considered: 

1. Truck transportation to an existing commercial injection site 

2. Pipeline transport to a dedicated injection site. 

The cost for disposal of RO concentrate was based on personal communications with 

service companies in the Williston Basin that provide injection and disposal services. Based on 

these conversations, the cost for disposal is estimated to be $1.75 per bbl. Assuming 1.5 MGD of 

RO permeate (at 70% RO recovery), the volume of RO concentrate for disposal would be 

approximately 643,000 gpd or 15,300 bbl/day, which equates to approximately 211 million gpy 

or 5 million bbl per year (assuming 90% plant availability). At the previously stated cost of 

$1.75 per bbl for injection, the annual injection-only cost would be $8.7 million a year. 
47 

Table 20. Cost Estimate Assumptions – 1.5-MGD RO Plant Description 

Direct Labor as 

% of Process 

Equipment 

Material as % 

of Process 

Equipment Labor Cost 

Material 

Cost 

Process Equipment 10.0 100.0 $350,000 $3,500,000 Site Preparation (clearing, grading) 2.8 0.5 $96,250 $17,500 Site Improvement 10.0 15.0 $350,000 $525,000 Concrete 10.0 5.4 $350,000 $189,000 Structural Steel – Platforms, Racks and Supports 6.0 15.0 $210,000 $525,000 Building – Steel, Cladding, Interior and HVAC 5.0 10.0 $175,000 $350,000 Underground Piping 8.0 12.0 $280,000 $420,000 Aboveground Piping 8.0 12.0 $280,000 $420,000 Electrical – MCC, Wiring, Lighting 6.5 12.5 $227,500 $437,500 Instrumentation 5.5 12.7 $192,500 $444,500 Insulation 7.5 5.0 $262,500 $175,000 Painting 3.0 1.7 $105,000 $59,500 Proratables 8.0 2.0 $280,000 $70,000 Total Direct Costs $3,158,750 $7,133,000 Construction Equipment 

% of Direct 

Labor Cost 

Total Indirect 

Cost 

 Rental or Purchase 10.0 $315,875  Service Labor 3.0 $94,763  Fuel, Oil, Supplies 10.0 $315,875 Overhead and Indirects 

 Salaried 10.0 $315,875  Contractor Profit 10.0 $315,875  Office Hourly 6.0 $189,525  Field Hourly 5.0 $157,938  Temporary Construction Facilities 5.0 $157,938  Payroll Burdens and Benefits 32.0 $1,010,800 

 Small Tools and Consumables 7.0 $221,113  Other Indirects 2.0 $63,175 Total Indirect Costs $3,158,750 
48 

Table 20. Cost Estimate Assumptions – 1.5-MGD RO Plant (continued)

% of Total 

Direct and 

Indirect Costs 

Engineering/Design Services 10.0 $1,345,050 Construction Engineering 1.0 134,505 Project General Management 2.0 269,010 Total Engineering and Management Services $1,748,565 Escalation (material – 1 yr) 2.0 $142,660 Summary Total Direct and Indirect Cost $13,450,500 Total Engineering and Management Services $1,748,565 Escalation $142,660 Total Project Costs $15,341,725 
49 

The total cost of disposal must also include the cost of trucking the RO concentrate to the 

injection facility. This cost was estimated to be approximately $11.9 million a year based on the 

following assumptions: 

 30-mile one-way haul to the injection site 

 Three hours per round trip at $150 an hour 

 26,315 round trips annually (190 bbl hauled each trip) 

Using these volumes and costs, the annual total cost for RO concentrate disposal by the 

truck transport method is estimated to be approximately $20.7 million. 

Given the cost of RO concentrate disposal by truck transport method, it is feasible that a 

dedicated pipeline and injection well field would be more cost-effective. Assuming a pipeline 

cost of $1 million dollars per mile and a distance of 10 miles to the injection well field, the cost 

of the pipeline would be approximately $10 million. Using the same per well cost stated in the 

groundwater extraction discussion of $1.5 million, assuming two injection wells, and adding 

10% for injection pumps and infrastructure, the total estimated cost for an injection well field 

would be approximately $3.3 million. The total cost for a dedicated pipeline and injection well 

field is then estimated to be $13.3 million. In this scenario, the $13.3 million cost would be 

added to the total capital cost, and the $20.7 million O&M cost for RO concentrate disposal 

would be reduced to the cost of operating the injection pumps (approximately $75,000). 

The O&M cost for the dedicated pipeline scenario was estimated based on the cost of 

electricity to run the pumps. Assuming a 60-kW pump in each of two wells operating for 

7872 hours (328 days) a year and an electrical cost of $0.08/kWh, the electricity cost would be 

approximately $75,500 per year. 

Land Acquisition 

Assuming that the site area is not currently owned a land acquisition cost was included and 

estimated based on the following assumptions: 

 Required land area: 160 acres 

 Price per acre of land: $1500 

Using these assumptions the estimated cost for acquiring land for the site is $240,000. 

Permeate and Concentrate Storage 

It is necessary to also include storage facilities for the permeate and concentrate produced 

during system operation. Each pond (permeate and concentrate) was sized with a 5-day capacity. 

This resulted in a permeate and concentrate pond volume of approximately 7,500,000 and 

3,200,000 gallons, respectively. The following assumptions were made to calculate the estimated 

product storage capital costs. 

 Excavation: 50,000 cubic yards at $2.00 per cubic yard 
50 

 Liner: 130,000 square feet at $4.00 per square foot 

 Pond cover: 100,000 square feet at $1.50 per square foot 

 Security fence: 1900 linear feet at $25 per linear foot 

 Contingency: 25% of total cost 

Using these assumptions the estimated cost for the total storage facility (permeate and 

concentrate storage) was approximately $1,021,875. 

Total costs associated with a 1.5-MGD RO plant, showing the two RO concentrate 

disposal options summarized in Tables 21 and 22. In addition to a summary of the estimated 

costs, a calculated cost per bbl of treated water for each component is provided. O&M costs per 

bbl were directly calculated by dividing the line item cost by the annual volume of treated water 

produced (11,714,192 bbls). Deriving a per bbl cost for the capital cost items required 

assumptions to be made regarding the financing of capital costs. For these calculations the entire 

capital cost is assumed to be borrowed and the following financial assumptions were made: 

 Interest rate: 5% 

 Term: 3 years 

As shown in Tables 21 and 22 the cost per bbl of treated water for the truck transportation 

disposal is $2.63 per bbl and the cost for the dedicated pipeline and injection well field is $1.28. 

When compared to the average water acquisition costs for traditional sources (water depots 

and pipeline), which range from $0.63 to $1.26 (Hess, personal communication), the total 

estimated costs for option one during the first three years ($2.63/bbl) are high. However, when 

compared to the costs savings achieved from reduced transportation costs and reduced heating 

costs as a result of heating the permeate, the costs become quite competitive (Hess, personal 

communication). The second option, at $1.28/bbl appears quite viable, even without accounting 

for the cost savings associated with reduced transportation and heating costs. In each instance, 

the water costs are reduced substantially after the 3-year capital costs payback period. 

Table 21. Total Cost Summary – 1.5-MGD RO Plant with Truck Transportation 

Disposal

 Cost Cost per bbl

Capital Costs

Land Acquisition $240,000 $0.01 

Groundwater Extraction Well Field $8,250,000 $0.25 

RO Plant $15,750,000 $0.47 

Permeate and Concentrate Storage $1,021,875 $0.03 

Total Capital Cost $24,853,600 $0.76 

 

Annual O&M Costs 

Groundwater Extraction $95,000/yr $0.01 

RO Plant Operation $1,000,000/yr $0.09 

RO Concentrate Disposal $20,700,000/yr $1.77 

Total Annual O&M Cost $21,795,000/yr $1.87 
51 

Table 22. Total Cost Summary – 1.5-MGD RO Plant with Dedicated Pipeline 

Disposal 

 Cost Cost per bbl 

Capital Costs 

Land Acquisition $240,000 $0.01 

Groundwater Extraction $8,250,000 $0.25 

RO Plant $15,341,725 $0.47 

Permeate and Concentrate Storage $1,021,875 $0.03 

RO Concentrate Disposal Well Field $13,300.000 $0.41 

Total Capital Cost $38,153,600 $1.17 

 

Annual O&M Costs 

Groundwater Extraction $95,000/yr $0.01 

RO Plant Operation $1,000,000/yr $0.09 

RO Concentrate Disposal $75,000/yr $0.01 

Total Annual O&M Cost $1,170,000/yr $0.11 

The per-barrel costs determined above were based on an economic model most 

representative of the RO plant capital costs being financed by a third party. An alternate means 

of determining per-barrel costs was also considered. This alternative assumed producer-deployed 

capital and a 15% internal rate of return (IRR) over a 3-yr period. A simplistic spreadsheet model 

was used to determine the per barrel costs for both scenarios using the capital and O&M costs 

provided in Tables 21 and 22. A 40% income tax rate was used, and it was conservatively 

assumed that the plant and all associated equipment fully depreciated in 3 years. The resulting 

payback period was 2.3 years. Given these assumptions, the per-barrel value (or acquisition 

costs) of the water was $2.95/bbl for the commercial disposal well and $1.75/bbl for the 

dedicated pipeline and injection well field. While the costs are higher than those determined 

using a 5% interest rate, they are still economically competitive with other options when the cost 

savings associated with reduced transport and lower heating costs are taken into account. As with 

the previous scenario, it appears economically advantageous to invest in a dedicated pipeline and 

injection well field. 

CONCLUSIONS 

While water resources in the western part of North Dakota are not necessarily scarce, 

especially considering the resources in Lake Sakakawea and the Missouri River system, current 

access to water is limited. This creates a unique environment where unconventional water 

acquisition methods, such as treatment of brackish groundwater resources, are economically 

competitive with conventional approaches. This project demonstrated an approach that may be 

economically competitive with water acquisition from traditional resources. Two of the factors 

driving the costs of frac makeup water are transportation, including the time that water haulers 

spend waiting in line at water depots, and costs of heating the water to the desired 80°F 

temperature for fracturing. The demonstrated approach provided a substantial reduction in both 

transportation and heating costs by considering both a dedicated on-site water hauling station and 
52 

by utilizing the relatively high-temperature groundwater to preheat the permeate. When these 

costs were taken into account, this project demonstrated that RO treatment of groundwater from 

the Dakota Aquifer may be economically feasible compared to existing approaches. 

RO treatment of nonpotable groundwater was demonstrated to be technically feasible with 

pretreatment to remove suspended solid and organic matter, coupled with the use of heat 

exchangers to reduce water temperature. One of the greatest expenses of this type of RO 

treatment system is associated with concentrate disposal, especially when a commercial disposal 

well is utilized. The economic assessment suggested that if a dedicated injection well field were 

constructed, the disposal costs could be reduced substantially and this approach would become 

economically competitive, even without accounting for the reduced transportation and heating 

costs. 

Given the high demand for frac makeup 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-bycase assessments will likely be needed, it is encouraging to know that this resource is available 

and may be economically competitive. 

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