iii

CONTENTS 

Acknowledgements ................................................................................................................... vii

1 Introduction ........................................................................................................................ 1

 1.1 Background ............................................................................................................. 1

 1.2 Purpose and Structure of the Report ....................................................................... 1

2 Evaluation of Formations and Water Quality Data ........................................................... 3

 2.1 Evaluation of Formations Likely To Be Used for Carbon Sequestration ............... 3

 2.2 Water Quality Data for Geological Formations Likely To Be Used 

 for Sequestration ..................................................................................................... 4

 2.3 Data About pH and TDS ......................................................................................... 4

 2.4 Data About Other Chemical Constituents............................................................... 9

3 Extracted Water Quantity Estimates .................................................................................. 13

4 Water Management Technologies and Practices ............................................................... 15

 4.1 Water Management Hierarchy for Evaluation of Management 

 Technologies and Options....................................................................................... 16

 4.1.1 Tier 1 — Minimization ............................................................................... 16

 4.1.2 Tier 2 — Recycle and Reuse ...................................................................... 16

 4.1.3 Tier 3 — Disposal ....................................................................................... 17

 4.2 Use of Extracted Water for Secondary Purposes .................................................... 17

 4.2.1 Geothermal Energy ..................................................................................... 19

 4.2.2 Extraction of Mineral Commodities ........................................................... 22

5 Cost of Extracted Water Management ............................................................................... 25

6 Conclusions ........................................................................................................................ 29

7 References .......................................................................................................................... 31

APPENDIX A: Table of Deep Saline Formations That Have 

 Geochemical Data Available ........................................................................ 33
iv

FIGURES 

1 Histogram of Median Formation pH ............................................................................. 5

2 Histogram of Median Formation TDS .......................................................................... 6

3 BSCSP and PCOR Partnerships Formation TDS Box Plot .......................................... 7

4 MRCSP and MGSC Partnerships Formation TDS Box Plot ........................................ 7

5 SECARB Partnership Formation TDS Box Plot .......................................................... 8

6 SWP Partnership Formation TDS Box Plot .................................................................. 8

7 WESTCARB Partnership Formation TDS Box Plot .................................................... 9

8 Brine Composition — Major Constituents ................................................................... 10

9 Brine Composition — Minor Constituents ................................................................... 10

10 Illustration of CO2 Density Variation with Depth. ....................................................... 13

TABLES 

1 Estimated Saline Formation Storage Resources ........................................................... 3

2 Brine Constituent Classification Scheme ...................................................................... 11

3 Comparison with National Primary Drinking Water Standards ................................... 12

4 Comparison with National Secondary Drinking Water Standards ............................... 12

5 Water Minimization Technologies for Extracted Water ............................................... 16

6 Water Reuse and Recycle Management Options for Extracted Water ......................... 18

7 Water Disposal Technologies for Extracted Water ...................................................... 20

8 Water Technologies for Removing Salt Content .......................................................... 21

9 Water Technologies for Removing Oil and Grease Content ........................................ 22

10 Costs for Produced Water Disposal .............................................................................. 26
v

TABLES (Cont.) 

11 Costs for Treatment to Remove TDS............................................................................ 27

12 Cost for Transporting Water ......................................................................................... 27
vi
vii

ACKNOWLEDGEMENTS 

 The authors would like to thank the U.S. Department of Energy’s (DOE’s) National 

Energy Technology Laboratory (NETL) Carbon Sequestration Program for providing funding to 

support the project. We offer a special acknowledgement to the NETL project manager, Andrea 

McNemar. The work was supported through Field Work Proposal 49607. 
viii
1

1 INTRODUCTION 

1.1 Background 

 Throughout the past decade, frequent discussions and debates have centered on the 

geological sequestration of carbon dioxide (CO2). For sequestration to have a reasonably positive 

impact on atmospheric carbon levels, the anticipated volume of CO2 that would need to be 

injected is very large (many millions of tons per year). Many stakeholders have expressed 

concern about elevated formation pressure following the extended injection of CO2. The injected 

CO2 plume could potentially extend for many kilometers from the injection well. If not properly 

managed and monitored, the increased formation pressure could stimulate new fractures or 

enlarge existing natural cracks or faults, so the CO2 or the brine pushed ahead of the plume could 

migrate vertically. 

 One possible tool for management of formation pressure would be to extract water 

already residing in the formation where CO2 is being stored. The concept is that by removing 

water from the receiving formations (referred to as “extracted water” to distinguish it from “oil 

and gas produced water”), the pressure gradients caused by injection could be reduced, and 

additional pore space could be freed up to sequester CO2. Such water extraction would occur 

away from the CO2 plume to avoid extracting a portion of the sequestered CO2 along with the 

formation water. While water extraction would not be a mandatory component of large-scale 

carbon storage programs, it could provide many benefits, such as reduction of pressure, increased 

space for CO2 storage, and potentially, “plume steering.” 

1.2 Purpose and Structure of the Report 

 Argonne National Laboratory is developing information for the U.S. Department of 

Energy’s (DOE’s) National Energy Technology Laboratory (NETL) to evaluate management of 

extracted water. If water is extracted from geological formations designated to receive injected 

CO2 for sequestration, the project operator will need to identify methods for managing very large 

volumes of water most of which will contain large quantities of salt and other dissolved minerals. 

Produced water from oil and gas production also typically contains large quantities of dissolved 

solids. Therefore, many of the same practices that are established and used for managing 

produced water also may be applicable for extracted water. 

 This report describes the probable composition of the extracted water that is removed 

from the formations, options for managing the extracted water, the pros and cons of those 

options, and some opportunities for beneficial use of the water. Following the introductory 

material in Chapter 1, the report is divided into chapters covering the topics listed below: 

 
2

 Chapter 2 examines the formations that are likely candidates for CO2 sequestration 

and provides a general evaluation of the geochemical characteristics of the formations. 

 Chapter 3 makes some preliminary estimates of the volume of water that could 

be extracted. 

 Chapter 4 provides a qualitative review of many potential technologies and practices for 

managing extracted water. For each technology or management practice, pros and cons 

are provided. 

 Chapter 5 explores the potential costs of water management. 

 Chapter 6 presents the conclusions. 
3

2 EVALUATION OF FORMATIONS AND WATER QUALITY DATA 

2.1 Evaluation of Formations Likely To Be Used for Carbon Sequestration 

 Although the main focus of this study is evaluating different options for managing the 

water that would be extracted from formations receiving CO2, it was first necessary to gain an 

understanding of the location, quality, and quantity of the water that would be managed. 

According to NETL, deep saline formations have the greatest potential storage capacity for 

sequestration; therefore, they were the focus of this study (2010). 

 The first activity involved compiling a list of deep saline formations with potential for 

carbon sequestration. Deep saline formations are characterized by high porosity and are typically 

saturated with brine. Formations suitable for sequestration have an overlying, impermeable, low 

porosity capping layer that confines the sequestered gas and prevents migration. Sequestration is 

also expected to be more effective at depths below 2,500 feet due to the high density of CO2 at 

the typical pressures and temperatures encountered at those depths (Bentham and Kirby 2005). In 

general, much less is known about these formations than hydrocarbon-containing formations. 

Despite the more limited characterization, it has been estimated that saline formations may be 

capable of sequestering between 1.7 and 20 trillion metric tons of CO2 (NETL 2010). This is at 

least an order of magnitude greater than the estimated sequestration potential of oil and gas 

reservoirs and unmineable coal seams combined. Table 1 contains a summary of the estimated 

storage resource of saline formations within each of the DOE regional carbon sequestration 

partnerships. 

TABLE 1 Estimated Saline Formation Storage Resources; billion metric tons CO2 (Gt) 

Partnership Low Estimate High Estimate 

 

Big Sky Carbon Sequestration Partnership (BSCSP) 221 3,041 

Midwest Geological Sequestration Consortium (MGSC) 12 160 

Midwest Regional Carbon Sequestration Partnership (MRCSP) 46 183 

Plains CO2 Reduction Partnership (PCOR) 165 165 

Southeast Regional Carbon Sequestration Partnership (SECARB) 908 12,527 

Southwest Regional Partnership on Carbon Sequestration (SWP) 219 3,013 

West Coast Regional Carbon Sequestration Partnership (WESTCARB) 82 1,124 

 

Total 1,653 20,213 

Source: Table adapted from NETL (2010).

 A working list of deep saline formations suitable for carbon storage was pieced together 

from data available from the seven DOE regional carbon sequestration partnerships. Data 

sources included both published reports and unpublished data obtained by directly contacting 

researchers at the partnerships. A total of 99 basins or formations were identified through this 

search. The list is not considered exhaustive or complete, but it provides a useful starting point 
4

for the characterization of the saline brines that may be encountered. It should be noted that the 

list contains some geographical overlap as different sources reported data at either the basin or 

formation level. The list of formation names can be found in Appendix A along with storage 

capacity estimates and formation depths where data were available. 

2.2 Water Quality Data for Geological Formations Likely To Be Used for Sequestration 

 Data on the chemical composition of saline ground water was obtained from the Kansas 

Geological Survey which maintains a large dataset in partnership with NETL for the NatCarb 

database. The raw data set contains over 125,000 data records, including much of the data from 

the USGS produced water database (http://energy.cr.usgs.gov/prov/prodwat/data2.htm). 

 This data set was cross-referenced with the saline formations identified in the previous 

section to evaluate the brines that would likely be encountered during carbon sequestration. This 

resulted in a smaller data set containing around 41,000 samples, including at least one data point 

for 61 of the 99 total identified basins and formations. Samples taken at depths shallower than 

2,500 ft were not included in this trimmed data set, except where no other data points were 

available for a specific formation. The 2,500-ft depth limit was selected to eliminate data points 

at depths that do not meet the pressure requirements for successful carbon sequestration 

(Kobos et al. 2009). 

 The trimmed data set was reviewed and analyzed to help understand the typical 

conditions that may be encountered in deep saline formations used for carbon sequestration. 

Brine characteristics discussed here include pH, total dissolved solids (TDS), and concentrations 

of several other individual chemical constituents. It should be noted that throughout this section, 

units of mg/L are used instead of ppm. Both units are commonly used when discussing water 

composition and quality and can be used interchangeably when the density of a fluid is one. 

However, as density diverges from one, as is the case in highly saline brines, the use of mg/L is 

more appropriate. 

2.3 Data About pH and TDS 

 Two important factors determining treatment requirements for produced or extracted 

water are pH and TDS. The graph shown in Figure 1 represents the distribution of the median 

pH across all the formations for which data was available. The pH appears to be roughly 

normally distributed around a mean between 7 and 7.5. While not shown here, further analysis of 

the data found that for individual formations there is a spread of approximately two units on the 

pH scale between the 5th and 95th percentiles. The median pH values for specific formations are 

listed in the table in appendix A. 
5

FIGURE 1 Histogram of Median Formation pH. The number on the 

horizontal axis of the graph for each bin represents the upper limit of the 

bin. The lower limit of the bin is equal to the upper limit of the bin to the 

left. 

 The concentration of TDS is a key parameter determining the feasibility of a number of 

water treatment technologies. In general, treatment becomes more difficult and expensive as 

TDS increases. Variation in this parameter was explored both by looking at the distribution of 

the median TDS for all formations in Figure 2 and further by producing box plots representing 

the distribution of TDS within each individual formation. These plots are grouped based upon 

the NETL carbon sequestration partnership regions and are shown in Figures 3 to 7. 

 When compared to pH, the distribution of TDS is less easily defined. Median values 

range from less than 5,000 mg/L to over 300,000 mg/L. The distribution is more heavily 

weighted toward the low end, with 59% of the formations having a value less than 40,000 mg/L. 

However, the distribution also has an elongated tail at the high end, with 15% of the formations 

having TDS of greater than 160,000 mg/L. Extracted water from these formations will be 

particularly challenging to treat. It should also be noted that formations with TDS below 10,000 

mg/L may face regulatory challenges. 

The U.S. Environmental Protection Agency (EPA) defines underground sources of 

drinking water (USDW) as aquifers having TDS of less than 10,000 mg/L. According to the final 

regulations adopted on December 10, 2010 by the EPA [75 FR 77230], CO2 may not be injected 

into or above the lowermost USDW. The new section 40 CFR 146.95 outlines a waiver 

mechanism from the depth requirement to inject only below the lowermost USDW. To obtain a 

waiver, an owner or an operator of the injection well must prepare a demonstration that is 

subsequently approved by the state or U.S. EPA director. 
6

FIGURE 2 Histogram of Median Formation TDS. The number on the 

horizontal axis of the graph for each bin represents the upper limit of the 

bin. The lower limit of the bin is equal to the upper limit of the bin to the 

left. The scale on the axis is log base 2. 

 The box plots show that TDS not only varies significantly between formations but that it 

can also vary quite a bit within the same formation. This indicates that water management 

practices will likely have to be tailored not just to individual formations, but also to specific 

project sites within a given formation. General regional trends are hard to pinpoint, although it 

does appear that the Midwest (MRCSP and MGSC partnerships) contains many of the 

formations with the highest TDS, while the Northwest (PCOR and Big Sky partnerships) 

contains a number of the formations with the lowest TDS. This is an encouraging trend, given 

that the estimated sequestration capacities of formations within the Big Sky and PCOR regions 

are about an order of magnitude greater than those in the MRCSP and MGSP regions. The region 

with the highest estimated sequestration capacity, SECARB, has TDS values that mostly fall in 

the middle of the range, with median values between 20,000 and 60,000 (with one exception). 

While the data provided in Figures 3 to 7 can provide rough screening for which regions and 

specific formations may be most suitable for specific water management practices, decisions on 

specific projects will depend on thorough characterization of local conditions. 
7

FIGURE 3 Box plot of TDS for formations in the BSCSP and PCOR partnership regions. The box 

represents the 25th and 75th percentiles, the line represents the median, the whiskers represent the 

minimum and maximum of the data, and a diamond indicates the mean. 

FIGURE 4 Box plot of TDS for formations in the MRCSP and MGSC partnership regions. The 

box represents the 25th and 75th percentiles, the line represents the median, the whiskers represent 

the minimum and maximum of the data, and a diamond indicates the mean. 

 
8

FIGURE 5 Box plot of TDS for formations in the SECARB partnership region. The box 

represents the 25th and 75th percentiles, the line represents the median, the whiskers represent the 

minimum and maximum of the data, and a diamond indicates the mean. 

FIGURE 6 Box plot of TDS for formations in the SWP partnership region. The box represents the 

25th and 75th percentiles, the line represents the median, the whiskers represent the minimum and 

maximum of the data, and a diamond indicates the mean. 
9

FIGURE 7 Box plot of TDS for formations in the WESTCARB partnership region. The box 

represents the 25th and 75th percentiles, the line represents the median, the whiskers represent the 

minimum and maximum of the data, and a diamond indicates the mean. 

2.4 Data About Other Chemical Constituents 

 In addition to pH and TDS, the data set contains concentrations of other specific chemical 

constituents. However, these data are less complete, with many records only including values for 

a few of the dozens of possible constituents. For this reason, all data for each individual 

constituent were aggregated across formations. Figures 8 and 9 are box plots representing the 

distribution of ion concentrations. Figure 8 represents the constituents with the highest 

concentrations, while Figure 9 represents the constituents with lower concentrations. 
10

FIGURE 8 Brine Composition — Major Constituents across formations 

FIGURE 9 Brine Composition — Minor Constituents across formations 
11

 There is clearly a significant spread in the concentrations of individual ions across the 

different formations. However, the concentrations, at least for the more common elements, tend 

to scale somewhat linearly with TDS. By looking at the data, a rough classification scheme was 

developed and is shown in Table 2. The scheme, as devised, has four tiers that represent ranges 

of typical concentrations. The top tier includes only elements with typical concentrations above 

10,000 mg/L while the bottom tier contains elements with typical concentrations below 1 mg/L. 

 Looking at Figures 8 and 9 and Table 2 it is clear that the vast majority of brines are 

dominated by sodium chloride. Other common constituents grouped into the second tier include 

sulfate, magnesium, nitrate, potassium, calcium, bromine, and bicarbonate. It should be noted 

that while a large number of data points were available for these more common ions, there was 

significantly less data for many of the minor constituents. Specifically, the distributions for 

copper, fluoride, nitrate, and zinc each contain 20 or fewer data points. Because of this, care 

should be taken in drawing broad conclusions based upon these specific concentrations. 

 To provide context to the chemical constituent concentrations, they were compared with 

both the primary and secondary national drinking water standards for inorganic contaminants. 

Table 3 provides a comparison with primary drinking water standards based upon human health 

impacts. Table 4 provides a comparison with national secondary drinking water standards that 

account for aesthetic and cosmetic effects such as color and taste. Both tables include the 

drinking water standard limit, the mean concentration, the median concentration, the total 

number of samples that included data for that contaminant, and the fraction of all the samples in 

the data set that meet the drinking water standard. 

TABLE 2 Brine Constituent Classification Scheme 

Classification 

Typical 

Concentration (mg/L) Constituents 

 

Tier 1 1000+ Sodium, chloride 

Tier 2 100-1000 Sulfate, magnesium, nitrate, calcium, bromine, bicarbonate 

Tier 3 1-100 Strontium, silica, manganese, potassium, lithium, iron, iodine, 

 fluoride, barium 

Tier 4 <1 Zinc, rubidium, copper, aluminum 

 These two tables demonstrate that treatment will be required, especially for barium and 

TDS, before water extracted from most saline formations can be used as a drinking water source. 

The limited number of data points available for many of the primary drinking water standards 

precludes strong conclusions from being drawn about specific contaminants. 
12

TABLE 3 Comparison with National Primary Drinking Water Standards 

Constituent 

Limita

(mg/L) Standard 

Mean 

(mg/L) 

Median 

(mg/L) 

Number of 

Samples 

Fraction Meeting 

Standard 

 

Antimony 0.006 MCLb - - 0 - 

Arsenic 0.01 MCL - - 0 - 

Barium 2 MCL 656 42.1 100 0.09 

Beryllium 0.004 MCL - - - - 

Cadmium 0.005 MCL - - 0 - 

Chromium 0.1 MCL - - 0 - 

Copper 1.3 TTc 0.23 0.01 16 0.91 

Cyanide 0.2 MCL - - 0 - 

Fluoride 4 MCL 11.3 12.0 4 0.35 

Lead 0.015 TT 0.025 0.02 6 0.00 

Mercury 0.002 MCL - - 0 - 

Nitrate 10 MCL 731 188 6 0.32 

Nitrite 1 MCL - - 0 - 

Selenium 0.05 MCL - - 0 - 

Thallium 0.002 MCL - - 0 - 

a Source: USEPA (2010a). 

b Maximum contaminant level allowed for drinking water. 

c Regulated by a treatment technique; beyond this action level, additional steps must be taken 

to control these contaminants. 

TABLE 4 Comparison with National Secondary Drinking Water 

Standards (NSDWRs) 

Constituent 

Limita

(mg/L) Standard 

Mean 

(mg/L) 

Median 

(mg/L) 

Number of 

Samples 

Fraction Meeting 

Standard 

 

Aluminum 0.2 NSDWR 2.06 0.51 42 0.23 

Chloride 250 NSDWR 36,000 13,600 41,295 0.08 

Iron 0.3 NSDWR 96.8 13.0 326 0.06 

Manganese 0.05 NSDWR 29.68 6.00 18 0.14 

Silver 0.1 NSDWR - - 0 - 

Sulfate 250 NSDWR 1,291 510 39,569 0.41 

Zinc 5 NSDWR 1.78 0.46 16 0.88 

TDS 500 NSDWR 61,176 24,601 40,356 0.00 

pH 6.5-8.5 NSDWR 7.3 7.4 35,621 0.74 

a Source: USEPA (2010a). 
13

3 EXTRACTED WATER QUANTITY ESTIMATES 

 To understand the potential feasibility of extracting water from receiving formations, the 

quantity of water that would need to be managed was estimated and compared to volumes of 

produced water currently being managed by the oil and gas industry. The estimates presented are 

first order estimates and are based upon a number of simplifying assumptions. The most 

important key assumption is that a volume of water equal to the volume of CO2 injected would 

be extracted to maintain a constant average formation pressure. The density of CO2 also varies 

significantly at different temperatures and pressures. This is illustrated in Figure 10. For these 

estimates CO2 density values of 0.65 to 0.78 g/cm3 were used (Bentham and Kirby 2005 and 

Kobos et al. 2009). Using these assumptions, 1,300 to 1,500 L of water could be extracted and 

managed for every metric ton of CO2 sequestered. In alternate units this is 8.1 to 9.5 barrels of 

water (1 barrel = 42 gallons) with an average of 8.8 barrels per metric ton of CO2. 

FIGURE 10 Illustration of CO2 Density Variation with Depth. Density is displayed on the x-axis 

of the graph, while the relative volume occupied by the CO2 at different depths is illustrated 

with bubbles/water droplets of varying sizes with numerical values indexed to 100. (NETL 2010) 
14

 Clark and Veil (2009) estimated that approximately 21 billion barrels of water were 

produced from almost 1 million active oil and gas wells in the United States in 2007. Based 

upon the EPA’s most recent complete greenhouse gas inventory, the United States emitted 

5.9 billion metric tons of CO2 in 2008 (EPA 2010b). Assuming at some point in the future 

carbon capture and sequestration (CCS) is scaled up to be equivalent to 10% of 2008 emissions 

and an equivalent volume of water is extracted to the volume of CO2 sequestered, this would 

require that about 5 billion barrels of water would need to be extracted and managed per year. 

This is about one-fourth of the water volume currently managed by the oil and gas industry. 

 Management of an incremental 25% of water could pose challenges, particularly if the 

extracted water is located in regions that do not have suitable formations to receive saline water 

through injection wells. The exact volume of water that will eventually need to be managed will 

depend on a large number of variables including the: 

 market penetration of CCS technology, 

 cost of selected water management options, 

 demand for water, 

 specific receiving formation characteristics, and 

 operating conditions determined by individual operators. 
15

4 WATER MANAGEMENT TECHNOLOGIES AND PRACTICES 

 The characteristics of produced water vary by location and over time. Different locales 

have different climates, regulatory or legal structures, and degrees of existing infrastructure. As a 

result, no single treatment technology is used at all locations. Many different technology options 

are available that can be employed at specific locations. Selection of a management option for 

produced water at a particular site varies, depending on the: 

 chemical and physical properties of the water; 

 volume, duration, and rate of water generation; 

 desired end use or disposition of the water; 

 treatment and disposal options allowed by state and federal regulations; 

 technical and economical feasibility of any particular option, including 

transportation and logistics; 

 availability of suitable infrastructure for disposal; 

 willingness of companies to employ a particular technology or management 

option, including their concerns about potential liability; and 

 cost involved with meeting the requirements and restrictions set by the 

regulatory agency. 

Likewise, extracted water will vary in chemical and physical properties from location to location. 

The options that can be employed for managing the extracted water will depend on the same set 

of factors that are listed above for produced water. 

 Argonne has extensive experience in evaluating management of produced water from oil 

and gas wells (Veil et al. 2004; Clark and Veil 2009). In 2007, Argonne created the Produced 

Water Management Information System (PWMIS) website, now housed on DOE’s website at 

http://www.netl.doe.gov/technologies/PWMIS/. PWMIS provides separate fact sheets on 

25 different produced water management practices and technologies in the Technology 

Description module (with several more fact sheets scheduled for addition in early 2011). As both 

produced water and extracted water are typically brackish or saline, many of the management 

practices used for produced water management may be applicable to extracted water. Most of 

the technologies and practices described in the following section have fact sheets in PWMIS that 

can be consulted for additional information. 

 Although many of the produced water management options described in PWMIS can be 

applied equally well to extracted water, some produced water practices may not make sense. For 

example, the two technologies described for keeping produced water from entering a well as a 
16

form of water minimization (i.e., shut off chemicals and mechanical blocking devices) make 

great sense for managing produced water but would be counterproductive for extracted water. In 

the latter case, the goal is to remove water from a formation that will be used for sequestration to 

make available more pore space. 

4.1 Water Management Hierarchy for Evaluation of Management Technologies 

and Options 

 Extracted water management technologies and strategies can be described in terms 

of a three-tiered water management or pollution prevention hierarchy (i.e., minimization, 

recycle/reuse, and disposal). Examples of technologies and practices for each group are shown 

in Tables 59. 

4.1.1 Tier 1 — Minimization 

 In the water-minimization tier, processes are modified, technologies are adapted, or 

products are substituted so that less water is generated. When feasible, water minimization can 

save money for operators and it results in greater protection of the environment. An example of a 

water minimization approach and technology is shown in Table 5. 

TABLE 5 Water Minimization Technology for Extracted Water 

Approach Technology Pros Cons 

 

Avoid handling 

extracted water 

at the surface. 

Pump extracted water 

directly to another 

disposal formation 

without ever bringing 

the water to the 

surface. 

If a suitable disposal formation 

is nearby and has adequate 

capacity to take the water, this 

could be a low-cost alternative. 

Need to have the right formation(s) 

located nearby. Need to make sure 

that the extracted-water chemistry 

is compatible with the injectionformation water to avoid forming 

precipitants or undesirable 

chemicals. Could compete with 

formation space for disposing 

produced water. 

4.1.2 Tier 2 — Recycle and Reuse 

 For the extracted water that remains following water minimization, operators move next 

to the second tier, where water is reused in a beneficial manner or recycled. The most common 

way to reuse produced water is to reinject it into a producing formation to enhance production. 

Reinjection for enhanced recovery occurs in tens of thousands of injection wells throughout the 

United States (Clark and Veil 2009). Injection for enhanced recovery could also be a good 

management option for extracted water. 
17

 Water is a scarce commodity in many parts of the world. Substantial efforts are ongoing 

to develop economical methods to treat produced water, most of which is quite salty, and put it 

to a new use. Some produced water, particularly the water associated with coalbed methane 

production in the Rocky Mountain region of the United States, has low salinity (EAA 2006). 

That water may be suitable for reuse without any treatment. This is unlikely to be the case with 

extracted water from CCS operations, as demonstrated in Figures 2 through 7. It may not make 

sense to expend high amounts of energy to treat very salty produced water, when a smaller 

amount of energy could be used more efficiently to treat an alternative water source (i.e., treated 

municipal wastewater, brackish ground water, and maybe even seawater, depending on the 

quality of the produced water). A similar situation applies to extracted water; it could serve as 

source water for many uses as long as the cost of treating and transporting the water is not 

prohibitive. Examples of water reuse and recycle management options as well as some of the 

specific uses are shown in Table 6. 

4.1.3 Tier 3 — Disposal 

 When water cannot be managed through minimization, reuse, or recycling, operators 

must dispose of it. Table 7 lists water disposal technologies that could be employed for extracted 

water. 

 Prior to disposing of or reusing water, operators may need to employ different treatment 

processes and technologies. The final disposition of the water determines the type and extent of 

treatment. Treatment technologies can be divided into two general categories, technologies for 

removing salt and other inorganics and technologies for removing oil and grease. Table 8 lists 

treatment technologies designed to remove salt and other inorganics from produced water. Most 

of the formations from which water could be extracted are likely to require some treatment for 

removing TDS, salt, and other inorganic chemicals. 

 Table 9 lists treatment technologies designed to remove oil and grease and other organics 

from produced water. Since more of the storage resources for sequestration is in deep saline 

formations rather than hydrocarbon-producing formations, the levels of oil and grease and other 

organics are likely to be considerably lower than what is found in produced water when saline 

formations are used. Nevertheless, these technologies are listed here, since CO2 storage is also 

anticipated in depleting or depleted oil and gas formations and unmineable coal seams. 

4.2 Use of Extracted Water for Secondary Purposes 

 Another potential future opportunity for deriving value from extracted water is to use the 

material for purposes other than just as water. Two ways in which extracted water can be used 

again are for geothermal power generation and as a feedstock for desirable mineral products. 
18

TABLE 6 Water Reuse and Recycle Management Options for Extracted Water 

Management 

Option Specific Use Pros Cons 

 

Reinjection 

for enhanced 

recovery 

Water flood; steam 

flood; SAGD (steam 

assisted gravity 

drainage) for oil 

sands 

Commonly used for produced 

water for onshore wells. May 

be a way to defray some 

project costs if the oil and gas 

company currently pays for 

their water. 

Need to ensure chemical compatibility 

with receiving formation. 

Need to have a hydrocarbon-producing 

formation nearby. 

 

Injection for 

future water 

use 

Aquifer storage and 

recovery 

Great option when possible. 

Only one known example for 

produced water (Wellington, 

Colorado). 

May encounter public opposition. Will 

require treatment to meet drinking 

water standards prior to injection. 

 

Use for 

hydrological 

purposes 

Subsidence control Can help solve a local problem 

(e.g., Long Beach, California). 

Need to ensure chemical compatibility 

with receiving formation. 

 

Saltwater intrusion 

control 

Could be used as a barrier to 

hold back saltwater intrusion 

from coastal aquifers. 

Only likely to be applicable in coastal 

areas. 

 

Stream flow 

augmentation 

Where extracted water is 

treated to allowable discharge 

standards, it can help to 

augment declining water 

levels in streams. Some 

interstate rivers are subject to 

compacts that require 

upstream states to provide a 

minimum flow level for the 

downstream states. 

Requires treatment to allowable 

discharge standards. 

 

Agricultural 

use 

Irrigation; 

subsurface drip 

irrigation 

Could be a great benefit to 

arid areas. 

May need to treat the water before 

applying it to the soil or adding soil 

supplements. 

 

Livestock and 

wildlife watering 

Could provide a source of 

water for animals. 

Need to ensure that water is clean 

enough for animal consumption. 

 

Managed/ 

constructed wetlands 

Provides a “natural” form of 

treatment. Creates a good 

habitat for wildlife. 

Large space requirements. Needs 

extensive oversight and management. 

Water may require some degree of 

pretreatment prior to wetland 

application. 

 
19

TABLE 6 (Cont.) 

Management 

Option Specific Use Pros Cons 

 

Industrial use Oil and gas industry 

applications 

Can substitute for fresh water 

supplies in making new 

drilling fluids or frac fluids. 

May need treatment to meet 

operational specifications. Must have a 

new well waiting to be drilled or 

fracced so long-term water storage is 

avoided. 

 

Power plants May be able to supplement 

cooling water sources. 

Will require treatment. The large 

volumes needed for this use could 

result in huge collection and 

transportation costs, depending on the 

distance between extraction wells and 

power plants. 

 

Enhanced 

geothermal power 

Enhanced geothermal systems 

require water to stimulate the 

formations and may require 

additional water to make up 

for water lost to the formation. 

Limited treatment would be 

needed. 

Need to ensure chemical compatibility 

with receiving formation. 

Need to have geothermal resources 

nearby. 

 

Other (e.g., vehicle 

wash, fire-fighting, 

dust control on 

gravel roads) 

Can be a good supplemental 

water supply in arid areas. 

Will need storage facilities. Will 

possibly need treatment. 

 

Treat to 

drinking 

water quality 

Use for drinking 

water and other 

domestic uses 

Can help supply water to 

communities in arid areas. 

Cost to treat may be high. Need good 

quality control. May encounter public 

opposition. Concern over liability. It 

may be more cost-effective and 

energy-conserving to treat other water 

sources such as moderately saline 

ground water rather than treating 

highly saline extracted water. 

4.2.1 Geothermal Energy 

 Geothermal energy is a renewable source of energy that utilizes heat generated within the 

earth. Geothermal energy can be used for heating buildings or for producing electricity. 

Geothermal power plants typically use hot ground water either directly as vapor or indirectly 

through a heat exchange process to create vapor. The vapor spins a turbine connected to a 

generator. In general, temperatures of at least 90°C and preferably greater than 150°C, are 

desirable for utility scale geothermal energy production. At lower temperatures, geothermal 

energy can be used directly for heating and cooling, using geothermal heat pumps. They take 
20

TABLE 7 Water Disposal Technologies for Extracted Water 

Technology Pros Cons 

 

Discharge Offers moderate cost and acceptable 

environmental impact, where permitted. 

Discharge of produced water is not 

approved for most onshore wells. It is 

unclear what regulatory discharge 

standards will ultimately be applied to 

extracted water. Where discharge is 

allowed, treatment is required unless the 

water is already of high quality. May 

encounter public opposition. 

 

Underground injection 

(other than for enhanced 

recovery); different 

from the example in 

Table 6 in that the water 

would be pumped to the 

surface first, treated if 

necessary, then 

reinjected 

Very common practice for onshore 

produced water. Tends to have low cost. 

EPA and state agencies recognize this as 

a safe, widely used, proven, and effective 

method for disposing of produced water. 

Requires the presence of an underground 

formation with suitable porosity, 

permeability, and storage capacity. May 

require treatment to ensure that injectate 

does not plug formation. 

 

Evaporation In arid climates, takes advantage of 

natural conditions of humidity, sun, and 

wind. 

Not practicable in humid climates. May 

create air quality and salt deposition 

problems. Could have large land 

requirements. 

 

Offsite commercial 

disposal 

Many companies provide service to the 

oil and gas community by accepting and 

disposing produced water for a fee. The 

same facilities also may be willing to take 

extracted water. Removes water 

management burden from the operator. 

Requires infrastructure (disposal 

facilities and transportation network to 

move water to disposal site). Can be 

costly. Potential for Superfund liability. 

advantage of relatively constant subsurface temperatures to significantly reduce heating and 

cooling loads (Duffield and Sass 2003). 

 Traditionally, geothermal energy developers seek out high-temperature formations and 

construct new high-volume extraction wells to withdraw the hot ground water. However, in 

recent years, interest has shifted to finding existing sources of ground water for which the wells 

are already drilled. If the cost of constructing a well has already been paid by another user, such 

as an oil and gas producer or a CCS project operator, the geothermal power producer can use 

water of a lower temperature and still produce electricity economically. With this in mind, 

attention has shifted to evaluating operating oil and gas wells as geothermal source wells. 

 The first actual example in which geothermal power was generated from a producing oil 

and gas well was a test conducted at DOE’s Rocky Mountain Oilfield Technology Center in 
21

TABLE 8 Water Technologies for Removing Salt Content 

Technology Subcategory Pros Cons 

 

Membrane 

processes 

Microfiltration, 

ultrafiltration, 

and 

nanofiltration 

These are good pretreatment 

steps for more advanced 

processes such as reverse 

osmosis. They operate at lower 

pressure and lower cost than 

reverse osmosis. 

These levels of filtration cannot remove 

most salinity. Potential for membrane 

fouling. Sensitivity to fluctuating water 

quality. 

 

Reverse 

osmosis 

Reverse osmosis can remove 

salinity (up to about 50,000 

mg/L TDS). 

Requires pretreatment and regular 

membrane cleaning. Not suitable for 

high-salinity water. Potential for 

membrane fouling. Sensitivity to 

fluctuating water quality. 

 

Thermal 

treatment 

Distillation Can process high-salinity waters. 

Generate very clean water as one 

product (can be reused). 

High-energy usage and cost. Generates 

concentrated brine stream that requires 

separate disposal. Potential for scaling. 

 

Evaporation/ 

crystallization 

Can treat to a zero liquid 

discharge standard. 

High-energy usage and cost. Limited 

usage in oil field applications. Potential 

for scaling. Challenges in disposing of 

salt residue. 

 

Ion exchange None Successfully treat low- to 

medium-salinity water. 

Large acid usage. Resins can foul. 

Challenges in disposing of rinse water 

and spent media (resin). Also ineffective 

on high-salinity produced waters. 

 

Capacitive 

deionization 

None Low energy cost. Limited to treating low-salinity waters. 

Limited usage in oil-field applications, 

but could have a role in treating extracted 

water with low to medium TDS. 

Wyoming. The test unit was a 250-kW Organic Rankine Cycle (ORC) power plant 

designed to use 40,000 bpd of 170°F produced water from the field’s Tensleep Formation 

to vaporize the working fluid, isopentane. The projected gross power from the unit was 

180 kW (net of 132 kW). Because of the lack of sufficient cooling water for the system, 

an air-cooled unit was designed. 

 The unit was put into service in September 2008 and operated until February 2009, when 

the unit was shut down because of operational problems. During this period, the unit produced 

586 MW-hr of power. The operational problems, caused by operating in excess of the unit 

capacity, resulted in changes in the control system and repairs to the generator and turbine 

system. The unit was restarted in September 2009. Between September 2009 and the end of 

February 2010, the unit produced 478 MW-hr of power at a more consistent rate than before 

the extended shutdown (Johnson and Walker 2010). 
22

TABLE 9 Water Technologies for Removing Oil and Grease Content 

Technology Subcategory Pros Cons 

 

Physical 

separation 

Advanced 

separators (e.g., 

inclined plate, 

corrugated plate) 

Provide enhanced oil capture 

compared to basic oil or water 

separators 

Works well for free oil, but not as 

effective on dispersed and soluble oil. 

Performance can be improved by 

adding flocculants. 

 

Hydrocyclone No moving parts results in good 

reliability. Separates free oil very 

well. 

Does not work well on dispersed and 

soluble oil. 

 

Filtration Different types of filter media and 

filter operations provide a good 

range of oil and grease removal. 

Requires regular back-flushing. Does 

not treat soluble oil. 

 

Centrifuge Provides good separation of free and 

dispersed oil. 

More expensive than other 

technologies in this group. 

 

Coalescence None Collects small oil droplets and forms 

larger droplets that can be more 

easily removed by the other 

technologies. 

Limited value for dispersed or soluble 

oil. 

 

Flotation Dissolved air 

flotation, 

induced gas 

flotation 

Removes free and dispersed oil. Does not remove soluble oil. 

 

Adsorption Organoclay, 

activated carbon, 

zeolites 

Does a good job at removing oil and 

grease and other organic materials. 

Used primarily for polishing. 

Media cannot be reused or 

regenerated; results in large volume 

of solid waste. 

 At this point, data on the temperatures of targeted deep saline formations appears to be 

limited. Without more data, it is difficult to assess the true geothermal potential of these aquifers. 

It is known that geothermal potential is the highest in western states, especially Nevada and 

California; and thus, these states are the most likely to contain deep saline formations that may 

also be useful for geothermal energy production (Duffield and Sass 2003). 

4.2.2 Extraction of Mineral Commodities 

 Some chemicals are produced through solution mining, a process that involves the 

injection of water and other additives into a formation to dissolve soluble minerals. The mineralladen water is then pumped back to the surface, where the desired constituents are recovered. 

Solution mining is energy-intensive because of the need to inject and extract large volumes of 
23

liquid. If extracted water from a particular formation contains sufficient concentrations of 

desirable compounds, it can be a cost-effective feedstock. The chemical producer would not have 

to pay for the cost of injecting water and extracting the solution since it would already be at the 

surface as a result of formation-water extraction. 

 The concept of extracting saleable minerals from brines is not new, but it is regaining 

interest. One element that has already attracted attention as a possible by product is lithium. Over 

the past year, the DOE Office of Energy Efficiency and Renewable Energy awarded a large grant 

to a company that will develop and validate improved lithium extraction technologies from 

geothermal brines of varying salinity (USDOE 2011). Researchers in Brazil are also studying 

the economic feasibility of extracting sodium carbonate (sodium ash) from produced water 

(Grimaldi et al. 2010). 

 Clark et al. (2011) surveyed the historical literature on the extraction of minerals from 

geothermal brines. They identified at least 14 projects that attempted to economically produce a 

range of minerals from geothermal brines including, but not limited to: Li, Zn, Mn, Mg, NaCl, 

KCl, CaCl2, silica, and borax. Of these projects, very few were more than a temporary 

commercial success. Reasons for failure varied, but they included changes to underlying 

commodity prices and high operating costs resulting from high temperatures, scale and 

corrosion, and challenging separation processes due to complex brine chemistry. At least three 

newer projects are still in the early feasibility stages. Two are focused on lithium and one is 

focused on silica production. 

 Lehr et al. (1982) also surveyed mineral extraction from non-geothermal brines. They 

identified at least 35 projects of which at least 26 were commercial operations. The minerals 

extracted included I, Br, Li, Mg, NaCl, KCl, CaCl2, NaCO3, and borax. A wide range of brine 

sources were used including produced water, seawater, groundwater, surface water bodies, and 

industrial wastewater. Unfortunately most of this data is over 30 years old, and few details are 

provided about these projects, so few conclusions can be drawn other than the fact that some 

minerals have been extracted commercially from some brines in the past. 

 The potential for mineral extraction from extracted water will be highly site specific. 

While it is possible and even likely that there will be formations that have favorable conditions 

for mineral extraction, these will more than likely be the exception rather than the rule, based 

upon the past history of mineral extraction from brines. The geochemical dataset obtained for 

this study is fairly limited on concentration values for many of the minerals that may be of 

interest. More data on these concentrations will be required before more formation-specific 

screening and analysis can be performed. 
24
25

5 COST OF EXTRACTED WATER MANAGEMENT 

 The cost of managing water will be an important factor in determining if it makes sense 

to extract water from a given formation. These costs will vary significantly depending upon the 

location, specific brine characteristics, and the management strategy selected. To get a better 

idea of what these costs might be, cost estimates were obtained for many existing oil and gas 

produced water management practices. Costs were obtained for both disposal options and 

treatment options that would allow for a wide range of beneficial uses. We note that it is 

challenging to find accurate and relevant published estimates for costs as both treatment 

providers and well operators are reluctant to share detailed cost information. Therefore, the cost 

estimates provided in this chapter should be considered as approximations. Further, the cited cost 

values in Tables 10 through 12 are taken from references published in different years. The value 

of a 1992 dollar is greater than the value of a 2006 dollar in current times. Readers are advised to 

use the cost figures in this chapter as a starting point, then do their own estimation and validation 

evaluation. 

 A summary of cost data for produced water disposal is shown in Table 10. The disposal 

methods for which data were available included discharge to a surface water body with a NPDES 

permit, injection underground to an underground injection control permitted disposal well, and 

evaporation in specially designed evaporation ponds. Discharge is generally the least expensive 

management practice, where available, with costs as low as a few cents per barrel in some 

locations. However, for commercial treatment and disposal, costs can exceed $2/bbl. Permitting 

is likely to be a major hurdle to the use of surface discharge for managing extracted water due to 

the typically high concentration of dissolved solids. Injection is the most common disposal 

option for produced water. The costs can vary from a few cents all the way up to $10.00/bbl, but 

more typical values are from $0.30 to $2.00/bbl. The wide variability in costs is due to 

differences in the geological properties of the formations chosen for injection as well as the 

transportation distance to the injection well. Evaporation is also a common disposal method in 

arid regions. Costs range from $0.05 to $4.00/bbl. Cost drivers include the cost of land, pond 

construction, and transportation. 

 Costs for water treatment for the removal of total dissolved solids are shown in Table 11. 

Costs are presented for three different treatment technologies including reverse osmosis (RO), 

thermal distillation, and capacitive deionization. Costs were somewhat lower for RO 

($0.45 to $3.50/bbl) and capacitive deionization ($1/bbl), but these two technologies tend to 

have pretreatment costs that can increase significantly as TDS concentrations increase. RO is 

most economical at concentrations around 30,000 mg/L and below, but becomes technically 

challenging with low recovery rates above 50,000 to 60,000 mg/L. Ongoing research at 

Lawrence Livermore National Laboratory has indicated that the costs of RO could be 

significantly reduced for water that is pressurized at the wellhead by the injection of CO2 into 

the formation (Wolery et al. 2009). The data obtained for thermal distillation systems indicate 

higher prices of $6.70 and $8.45/bbl, but these systems can more easily handle higher TDS 

concentrations. While lower recovery rates and higher concentrate disposal costs are expected, 

significant increases in the amount of energy required to treat water as TDS concentrations 

increase are not expected. 
26

TABLE 10 Costs for Produced Water Disposal 

State Management Practice Cost /bbla 

Transport 

Cost 

Included Year Source 

 

PA Discharge $2.90 n 2010 Quoteb

PA Discharge $0.75–2.75 n 2006 Puder and Veil 2006 

MT Discharge $0.02–0.10 y 2006 EEA 2006 

MT, WY Discharge and injection $0.01–2.00 y 2001 Boysen et al. 2002 

WY Discharge and injection $0.04–0.35 y 1998 Boysen et al. 2002 

WY Discharge, injection, evaporation $0.01–0.10 y 1998 Boysen et al. 2002 

MT Discharge, injection, evaporation, 

 commercial disposal 

$0.05–2.00 y 2001 Boysen et al. 2002 

MT Injection and discharge $0.02 n 1998 Boysen et al. 2002 

MT Injection $1.26 n 2006 EEA 2006 

AL Injection $0.80 ? 1992 Nakles et al. 1992 

NM Injection $0.50–1.75 ? 1992 Nakles et al. 1992 

CO Injection $1.00 y 1998 Boysen et al. 2002 

CO Injection $0.05–0.70 y 1998 Boysen et al. 2002 

CO Injection $0.50–1.50 y 2000 Boysen et al. 2002 

CO Injection $0.06–1.50 y 1998 Boysen et al. 2002 

CO Injection $0.30–2.80 y 2001 Boysen et al. 2002 

NM Injection $0.50–4.20 y 2001 Boysen et al. 2002 

UT Injection $0.04–2.00 y 1998 Boysen et al. 2002 

UT Injection $0.05–1.00 y 2001 Boysen et al. 2002 

WY Injection $0.40–1.50 y 1998 Boysen et al. 2002 

WY Injection $0.10–0.95 y 1998 Boysen et al. 2002 

AL Injection $0.35–0.50 n 2006 Puder and Veil 2006 

AR Injection $0.40–0.75 n 2006 Puder and Veil 2006 

LA Injection $0.50–10.00 n 2006 Puder and Veil 2006 

MI Injection $0.50–1.75 n 2006 Puder and Veil 2006 

MS Injection $0.37–0.60 n 2006 Puder and Veil 2006 

ND Injection $0.35–0.75 n 2006 Puder and Veil 2006 

NM Injection $0.40–0.88 n 2006 Puder and Veil 2006 

OK Injection $0.30–0.65 n 2006 Puder and Veil 2006 

TX Injection $0.40–4.00 n 2006 Puder and Veil 2006 

WV Injection $1.00 n 2006 Puder and Veil 2006 

WY Injection $2.00–3.00 n 2006 Puder and Veil 2006 

AL Evaporation $2.10 ? 1992 Nakles et al. 1992 

CO Evaporation $0.05 y 1998 Boysen et al. 2002 

WY Evaporation $0.50–1.95 y 1998 Boysen et al. 2002 

WY Evaporation $1.50–4.00 y 1998 Boysen et al. 2002 

CO Evaporation $1.20–3.95 n 2006 Puder and Veil 2006 

NM Evaporation $0.40–0.78 n 2006 Puder and Veil 2006 

UT Evaporation $0.50–1.00 n 2006 Puder and Veil 2006 

a Costs have not been corrected for inflation, the year associated with the cost is given 

b Informal verbal quote given to authors by treatment facility operator. 
27

TABLE 11 Costs for Treatment to Remove TDS 

State Management Practice Cost /bbla 

Transport 

Cost 

Included Year Source 

 

WY Reverse Osmosis $2.50–3.50 n 2006 Puder and Veil 2006 

MT Reverse Osmosis $1.04–1.39 n 2006 EEA 2006 

NM Reverse Osmosis $0.75–1.50 ? 1992 Nakles et al. 1992 

AL Reverse Osmosis $0.45 ? 1992 Nakles et al. 1992 

Any Thermal Distillationb $8.45 n 2010 Kohl 2010 

PA Thermal Distillationb $6.70 n 2010 Quotec

Any Capacitive Deionization $1.00d n 2007 Atlas and Wendell 2007 

a Cost for TDS of 10,000 mg/l; costs increase with higher concentrations.

b Includes all pre-treatment. 

c Informal verbal quote given to authors by treatment facility operator. 

d Cost for TDS of 10,000 mg/l; costs increase with higher concentrations. 

TABLE 12 Cost for Transporting Water 

State 

Transportation 

Mode Cost Year Source 

 

MT Pipeline $0.006–0.010/bbl-mile 2006 EEA 2006 

CO Truck $0.40–0.65/bbl 1998 Boysen et al. 2002 

NM Truck $0.70–3.20/bbl 2001 Boysen et al. 2002 

NM Truck $1.00–3.00/bbl 2006 Puder and Veil 2006 

Many Truck $55–100/hr 2006 Puder and Veil 2006 

 Tables 10 and 11 indicate whether transportation costs are included in the reported 

costs of water management. These costs can make up a significant fraction of the total water 

management costs. Boysen et al. (2002) reported in many specific cases that transportation made 

up the majority of water management costs, including one specific region where producers 

reported that transportation made up 50 to 75% of the total cost of water management. The two 

main transportation options are pipelines and trucks. Pipelines tend to be more economical for 

shorter distances and where water production is stable and anticipated for an extended period 

of time. Trucking is a better option when water production is more intermittent or for longer 

transportation distances. Pipeline costs have been estimated at about $0.01/bbl per mile with 

per barrel costs declining slightly as pipeline length declines. Typical water trucks can haul from 

100 to 150 bbl per load and are usually contracted out with prices ranging from $55 to $100/hr 

with an operator. Costs are highly dependent upon distance and the time it takes to load and 

unload the truck along with any applicable cleaning fees (Puder and Veil 2006). 
28

 Using the values calculated in Chapter 3 for the volume of water that would need to be 

managed, we can get an idea of the extent that water management might add to the cost of 

carbon sequestration. At the low end of the cost spectrum of $0.10/bbl for discharge or injection 

in an adjacent formation, costs would range from $0.80 to $0.95/metric ton of CO2 sequestered. 

At $1.50/bbl which could include injection with transportation, evaporation, or treatment using 

RO or capacitive deionization for recycling of relatively low TDS waters, costs for sequestration 

would increase by $12 to $14/metric ton. At the high end, the costs of $7/bbl for thermal 

treatment and long distance trucking for disposal of high TDS waters, the cost for sequestration 

would increase by $57 to $67/metric ton. Given that carbon sequestration is currently viewed as 

a pure cost to the energy industry, it seems unlikely that voluntary water extraction would be 

justified in areas where the costs of management are high. However, in areas with nearby 

formations, where injection can be performed inexpensively and with minimal transportation 

costs, or where TDS are low and RO systems can take advantage of pressurized wells to 

minimize costs, there may be opportunities to extract water at reasonable costs. 
29

6 CONCLUSIONS 

 Carbon sequestration is still in its infancy. As projects move beyond the pilot and 

demonstration stages, there may be situations in which water extraction from formations is an 

integral part of a large, multi-year injection program. As of the end of 2010, no CCS project has 

intentionally extracted water to create additional pore space. Water extraction will not 

automatically or always be a mandatory component of large CCS programs. However, if an 

operator proposes to extract water for project operational and control purposes, the operator must 

carefully consider how a substantial volume of saline ground water can be managed. 

 A number of water management strategies have been explored based upon the experience 

of the oil and gas industry. Quite a few of these options can be applied to managing extracted 

water. The actual options selected will reflect site-specific technical feasibility and practicality, 

regulatory acceptability, and cost. The water composition of any deep saline formation selected 

for a CO2 injection program will play a critical role in the options selected and the types of 

treatment required for that water. 

 In addition to selecting appropriate water management practices, other important issues to 

consider in water extraction include the following questions. 

 When should water be extracted (before injection or throughout the injection)? 

 How should water be extracted (continuously, intermittently, or different rates at 

different times)? 

 Where should water be extracted (at or near the injection point, down gradient at 

one point, or down gradient at multiple points)? 

 How many injection wells should be employed (one or multiple wells with 

orientation optimized to allow some measure of “plume steering”)? 

 How much water should be extracted (as much as possible, match the volume of 

injected CO2, or other)? 

 Much of the information needed to answer these questions can be derived by using 

experience, models, and data already developed for other industries such as the oil and gas and 

geothermal industries. 
30
31

7 REFERENCES 

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Technology,” presented at the 14th International Petroleum Environmental Conference, Houston, 

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Technology, 60(3):559–567. 

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presented at the SPE International Conference on Health, Safety, and Environment in Oil and 

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Johnson, L.A., and E.D. Walker, 2010, “Ormat: Low-Temperature Geothermal Power 

Generation,” (DOE-RMOTC-61022), March. Available at http://www.rmotc.doe.gov/PDFs/ 

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B.P. Dwyer, and A. McNemar, 2009, “Combining Power Plant Water Needs and Carbon Storage 

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Kohl, D.C., 2010, Presentation to the Senate Environmental Resources and Energy Committee, 

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33

APPENDIX A: 

Table of Deep Saline Formations That Have 

Geochemical Data Available 
34
35

Name Partnership Depth (ft) 

Storage 

Capacity (Gt) Data Points 

pH 

Median 

TDS Med

(mg/L

Antelope Valley Basin WESTCARB 4 7.5 26,Appalachian Basin MRCSP 5,900-8,300 84 5.9 253,Arbuckle SWP, SECARB 3043 7 38,Astoria-Nehalem Basin WESTCARB 4,700 1-12 0 Basal Conasauga Sandstones MRCSP 0.4-1.7 21 7.2 57,Bass Islands Group Big Sky 1.6-6 3 8.2 199,Big Horn Basin Big Sky 11-146 2113 7.7 5,Broom Creek Formation PCOR 5 1 7.9 12,Cape Fear SECARB 0 Cedar Keys, Lawson Formations SECARB 11-153 1 7.8 35,Cedar Mesa SWP 0 Central Valley WESTCARB 20-282 0 Cincinnati Arch MRCSP 3,200-3,500 9 6.9 58Colorado Plateau WESTCARB 5,000 0 Columbia Plateau Big Sky 0 Cook Inlet Basin WESTCARB 37 6.3 228,Coos Basin WESTCARB 7,500 0 Cuyama Basin WESTCARB 1-15 0 Cypress Sandstone MGCS 3,000 0.4 -1.7 75 6.6 106,Dakota SWP 1535 8 8,Devonian SWP 895 6.9 63,Dockum SWP 1 7,Eel River Basin WESTCARB 1 0 Entrada SWP 9,000-12,000 48 7.3 12,Fountain SWP 2 7.7 5,Frio SECARB 917 7.1 37,Glorieta SWP 231 7.4 79,Granite Springs Valley Basin WESTCARB 0 Green River Basin SWP, Big Sky 2865 8 10,Gulf Coast Eocene SECARB 160-2,200 Gulf Coast Miocene SECARB 400-5,500 Gulf Coast Oligocene SECARB 130-1,800 Gulf Coast Olmos SECARB 0.4-6 Gulf Coast Pliocene SECARB 140-1,900 Gulf Coast Tertiary Undivided SECARB 17-240 Gulf Coast - All SECARB 7453 7.1 56,
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Name Partnership Depth (ft) 

Storage 

Capacity (Gt) Data Points 

pH 

Median 

TDS Med

(mg/L

Hermosa SWP 283 7 110,Illinois Basin MGSC 7,000-8,600 912 7 116,Ione Valley Basin WESTCARB 0 Jackson SECARB 16 7.4 25,Jasper SECARB 0 Knox Group MRCSP 30 6 7.6 16,La Honda Basin WESTCARB 1 0 Lakota PCOR, Big Sky 4,100-6,700 138 8.1 5,Leadville SWP 10 7.1 61,Livermore Basin WESTCARB <1 0 Lockport Group MRCSP 4.5-18 6 6.6 221,Los Angeles Basin WESTCARB 5-35 264 7.4 30,Lyons SWP 161 7.6 27,Madison Formation PCOR 4,000-16,000 37 2280 6.9 51,Maha Formation PCOR 3 0 Medina/Tuscarora Sandstone MRCSP 7.9 -32 12 6.3 251,Mesaverde SWP 4,000-11,000 1517 8.0 9,Michigan Basin MRCSP 3,200-3,500 269 5.8 303,Montana Thrust Belt Big Sky 2.5 - 34 16 7.3 3,Morrison SWP 3,600-12,000 303 8.0 10,Mount Simon Sandstone MGSC, MRCSP,

 SECARB 

2,000 to 14,000 11-151 0 

Newcastle Formation PCOR 6,700 1 122 8.0 10,North-Central Montana Big Sky 68 - 933 689 7.9 5,Ochoco Basin WESTCARB 1-12 0 Offshore Atlantic Unit 120 SECARB 36-490 0 Offshore Atlantic Unit 90 SECARB 3-43 0 Orinda Basin WESTCARB 1 0 Oriskany Sandstone MRCSP 1.9 -7.8 207 4.6 253,Paradox SWP 467 7.1 80,Potomac Group SECARB 2-25 0 Potsdam Sandstone MRCSP 0.2-1.7 0 Pottsville Formation SECARB 1.1-15 1 361Powder River Basin PCOR, Big Sky 14-196 2912 8 7,Puget Trough Basin WESTCARB 35-475 0 Redwall SWP 11 7 9,
37

Name Partnership Depth (ft) 

Storage 

Capacity (Gt) Data Points 

pH 

Median 

TDS Med

(mg/L

Reese River Valley Basin WESTCARB 0 Rome Trough Sandstones MRCSP 0.1 -0.8 0 Rose Run Sandstone MRCSP 5.7 -23 1 6.1 201Sacramento Basin WESTCARB 50 -250 12 6.4 16,Salinas Basin WESTCARB 1 -15 1 31Salton Trough WESTCARB 5 -40 0 San Andres SWP 1310 7.1 76,San Joaquin Basin WESTCARB 50 -250 195 7.4 21,San Juan Basin SWP 283 7.4 19,Snake River Plain Big Sky 3 7.8 11,South Carolina - Georgia Basin SECARB 13-60 0 Southwest Montana Big Sky 1.9-26 57 7.9 3,Southwestern Wyoming Big Sky 47-640 2425 8 9,St. Peter Sandstone MRCSP 8.8 -35 26 6.7 86,Sylvania Sandstone MRCSP 1.5 -3.5 0 Tapeats SWP 0 Tofino-Fuca Basin WESTCARB 5,300 0.5-4 0 Tuscaloosa Group SECARB 5-75 935 6.1 147,Tyee-Umpqua Basin WESTCARB 5,300 0 Ventura Basin WESTCARB 5 -35 16 7.3 30,Vicksburg SECARB 156 6.9 25,Viking Formation PCOR 60 0 Wasatch SWP 2,600-3,400 600 7.9 10,Waste Gate Formation MRCSP 0.4 -1.8 0 Weber SWP 9,000-14,000 210 7.4 35,Western Olympic Basin WESTCARB 3,500 0.5-4 0 Whatcom Basin WESTCARB 0.2-3 0 Willamette Trough WESTCARB 0 Willapa Hills Basin WESTCARB 7,500 1-12 0 Williston Basin PCOR, Big Sky 58-804 3027 6.7 138,Wind River Basin Big Sky 14-187 1520 8 5,Woodbine Formation and  Paluxy Sandstone 

SECARB 5-70 440 7.4 56,

Woodward Trench SWP 0 Wyoming Thrust Belt Big Sky 5.3-74 191 7.3 18,
38