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 Technol ogies 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 Sa line Formations That Have

Geochemical Data Available ........................................................................ 33iv 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 CO 2 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 .............................................................................. 26v TABLES (Cont.)

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

12 Cost for Transporting Water ......................................................................................... 27vivii ACKNOWLEDGEMENTS

The authors would like to thank the U.S. Department of Energy’s (DOE’s) National Energy Technology Laboratory (NETL) Carbon Seque stration Program for providing funding to support the project. We offer a special acknowledgement to the NETL project manager, Andrea McNemar. The work was supported th rough Field Work Proposal 49607.viii1 1 INTRODUCTION

1.1 Background

Throughout the past decade, frequent discussions and de bates have centered on the geological sequestration of carbon dioxide (CO 2 ). For sequestration to have a reasonably positive impact on atmospheric carbon levels, the anticipated volume of CO 2 that would need to be injected is very large (many millions of tons per year). Many stakeholders have expressed concern about elevated formation pressu re following the extended injection of CO 2 . The injected

CO 2 plume could potentially extend for many kilometers from the in jection well. If not properly managed and monitored, the increased formati on pressure could stimul ate new fractures or enlarge existing natural cracks or faults, so the CO 2 or the brine pushed ahead of the plume could migrate vertically.

One possible tool for management of form ation pressure would be to extract water already residing in the formation where CO 2 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 grad ients caused by injection could be reduced, and additional pore space could be freed up to sequester CO 2 . Such water extraction would occur away from the CO 2 plume to avoid extracting a portion of the sequestered CO 2 along with the

formation water. While water extraction would not be a mandatory component of large-scale carbon storage programs, it could provide many benef its, such as reduction of pressure, increased space for CO 2 storage, and potentia lly, “plume steering.”

1.2 Purpose and Structure of the Report

Argonne National Laboratory is developing in formation for the U.S. Department of Energy’s (DOE’s) National Energy Technology Labor atory (NETL) to evaluate management of extracted water. If water is extracted from geol ogical formations designated to receive injected

CO 2 for sequestration, the project op erator 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 t ypically contains large quantities of dissolved solids. Therefore, many of th e same practices that are esta blished and used for managing produced water also may be appl icable for extracted water.

This report describes the probable compositi on of the extracted wa ter that is removed from the formations, options for managing the ex tracted 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 CO 2 sequestration and provides a general evaluation of the geoc hemical 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 t echnologies and practices for managing extracted water. For each technology or management practice, pros and cons are provided.

 Chapter 5 explores the potentia l 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 op tions for managing the water that would be extracted from formations receiving CO 2 , it was first necessary to gain an understanding of the location, quality, and quant ity of the water that would be managed. According to NETL, deep saline formations have the greatest potentia l storage capacity for sequestration; therefore, they we re 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 dept hs below 2,500 feet due to the high density of CO 2 at the typical pressures and temperat ures encountered at those dept hs (Bentham and Kirby 2005). In general, much less is known about these form ations than hydrocarbon-containing formations. Despite the more limited characte rization, it has been estimated th at saline formations may be capable of sequestering between 1.7 and 20 trillion metric tons of CO 2 (NETL 2010). This is at least an order of magnitude grea ter than the estimated sequestration potential of oil and gas

reservoirs and unmineable coal seams combined. Table 1 contai ns a summary of the estimated storage resource of saline form ations within each of the DOE regional carbon sequestration partnerships.

TABLE 1 Estimated Saline Formation Storage Resources; billion metric tons CO 2 (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 CO 2 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 re gional carbon sequestrati on partnerships. Data sources included both published reports and unpublished data obt ained by directly contacting researchers at the partnerships. A total of 99 basins or formati ons were identified through this

search. The list is not considered exhaustive or complete, but it provides a useful starting point4 for the characterization of the sa line brines that may be encounter ed. It should be noted that the list contains some geographical ov erlap as different sources reporte d data at either the basin or

formation level. The list of formation name s can be found in Appendix A along with storage capacity estimates and formation dept hs where data were available.

2.2 Water Quality Data for Geological Formatio ns Likely To Be Used for Sequestration

Data on the chemical composition of saline ground water was obtained from the Kansas Geological Survey which maintain s a large dataset in partnership with NETL for the NatCarb

database. The raw data set cont ains over 125,000 data records, incl uding 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 4 1,000 samples, including at least one data point
for 61 of the 99 total identified basins and format ions. 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 dept h 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 he re include pH, total dissolved so lids (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 intercha ngeably when the density of a fluid is one. However, as density diverges from one, as is th e 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 Figur e 1 represents the distribution of the median pH across all the formations for which data wa s available. The pH appears to be roughly normally distributed around a mean between 7 and 7.5. While not show n here, further analysis of

the data found that for individual formations ther e is a spread of approximately two units on the pH scale between the 5 th and 95 th percentiles. The median pH va lues 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 paramete r determining the feasibility of a number of water treatment technologies. In general, trea tment 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 produci ng box plots representing

the distribution of TDS within each individual formation. These plots are grouped based upon the NETL carbon sequestration part nership 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 300,00 0 mg/L. The distribution is more heavily weighted toward the low end, with 59% of the formations having a valu e less than 40,000 mg/L. However, the distribution also has an elongated ta il at the high end, with 15% of the formations having TDS of greater than 160,000 mg/L. Extrac ted 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], CO 2 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 injec tion well must prepare a demonstration that is subsequently approved by the st ate 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 i ndividual formations, but also to specific project sites within a given form ation. General regional trends are hard to pinpoint, although it does appear that the Midwest (MRCSP and MG SC partnerships) contains many of the formations with the highest TDS, while th e Northwest (PCOR and Big Sky partnerships)

contains a number of the formati ons with the lowest TDS. This is an encouraging trend, given that the estimated sequestration ca pacities of formations within the Big Sky and PCOR regions are about an order of magnitude greater than those in the M RCSP 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 sp ecific water management practices, decisions on specific projects will depend on thorough ch aracterization of lo cal conditions.7 FIGURE 3 Box plot of TDS for formations in th e BSCSP and PCOR partnership regions. The box
represents the 25 th and 75 th 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 25 th and 75 th 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 25 th and 75 th 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 th e SWP partnership region. The box represents the

25 th and 75 th 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 25 th and 75 th 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 contai ns concentrations of ot her 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 th e constituents with lower concentrations.10 FIGURE 8 Brine Composition — Majo r Constituents across formations

FIGURE 9 Brine Composition — Minor Constituents across formations11 There is clearly a significant spread in th e concentrations of in dividual ions across the different formations. However, the concentratio ns, at least for the more common elements, tend to scale somewhat linearly with TDS. By looking at the data, a rough cl assification 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 on ly elements with typical concentrations above 10,000 mg/L while the bottom tier contains elements with typical concentra tions below 1 mg/L.

Looking at Figures 8 and 9 and Table 2 it is cl ear that the vast majority of brines are dominated by sodium chloride. Other common co nstituents 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. Specif ically, the distributions for copper, fluoride, nitrate, and zi nc each contain 20 or fewer da ta 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 dr inking water standards based upon human health impacts. Table 4 provides a comparison with na tional secondary drinking water standards that

account for aesthetic and cosmetic effects such as color and ta ste. Both tables include the drinking water standard limit, the mean con centration, the median c oncentration, the total number of samples that included data for that co ntaminant, and the fraction of all the samples in

the data set that meet th e 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, nitr ate, 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 treatmen t will be required, especially for barium and TDS, before water extracted from most saline fo rmations can be used as a drinking water source. The limited number of data points available fo r 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 Limit a (mg/L) Standard Mean (mg/L) Median (mg/L) Number of Samples Fraction Meeting

Standard

Antimony 0.006 MCL b - - 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 TT c 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 Limit a (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 ex tracting water from receiving formations, the quantity of water that would need to be mana ged was estimated and compared to volumes of produced water currently being managed by the o il 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 volu me of water equal to the volume of CO 2 injected would

be extracted to maintain a constant aver age formation pressure. The density of CO 2 also varies significantly at different temperat ures and pressures. This is i llustrated in Figure 10. For these

estimates CO 2 density values of 0.65 to 0.78 g/cm 3 were used (Bentham and Kirby 2005 and Kobos et al. 2009). Using these assumptions, 1,300 to 1,500 L of wa ter could be extracted and managed for every metric ton of CO 2 sequestered. In alternate units this is 8.1 to 9.5 barrels of water (1 barrel = 42 gallons) with an av erage of 8.8 barrels per metric ton of CO 2

.

FIGURE 10 Illustration of CO 2 Density Variation with Depth. Density is displayed on the x-axis of the graph, while the relative volume occupied by the CO 2 at different depths is illustrated with bubbles/water droplets of varying sizes wi th numerical values indexed to 100. (NETL 2010)14 Clark and Veil (2009) estimated that approxi mately 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 CO 2 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 wate r is extracted to the volume of CO 2 sequestered, this would require that about 5 billion barrels of water woul d need to be extracted and managed per year.

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

Management of an incremental 25% of wate r could pose challenges, particularly if the extracted water is located in regi ons that do not have suitable form ations to receive saline water through injection wells. The exact volume of wate r that will eventually n eed 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 formati on characteristics, and

 operating conditions determined by individual operators.15 4 WATER MANAGEMENT TECHNOLOGIES AND PRACTICES

The characteristics of produ ced water vary by location and over time. Different locales have different climates, regulatory or legal struct ures, and degrees of existing infrastructure. As a result, no single treatment technology is used at all locations. Many diffe rent 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 prope rties of the water;

 volume, duration, and rate of water generation;

 desired end use or disp osition of the water;

 treatment and disposal options allowe d by state and federal regulations;

 technical and economical feasibility of any particular option, including transportation and logistics;

 availability of suitable in frastructure 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 requir ements 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 th e extracted water will depend on the same set

of factors that are listed above for produced water.

Argonne has extensive experien ce in evaluating management of produced water from oil and gas wells (Veil et al. 2004; Clark and Ve il 2009). In 2007, Argonne created the Produced Water Management Information System (PWM IS) website, now housed on DOE’s website at http://www.netl.doe.gov/technologi es/PWMIS/. PWMIS provides separate fact sheets on 25 different produced water management prac tices and technologies in the Technology Description module (with several mo re 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 fo llowing section have fact sheets in PWMIS that

can be consulted for additional information.

Although many of the produced water manageme nt 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 k eeping produced water from entering a well as a16 form of water minimization (i.e., shut off chem icals 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 us ed for sequestration to make available more pore space.

4.1 Water Management Hierarchy for Evalua tion of Management Technologies and Options

Extracted water management technologies a nd strategies can be described in terms of a three-tiered water management or pollu tion prevention hierarc hy (i.e., minimization, recycle/reuse, and disposal). Examples of t echnologies 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 re sults in greater protec tion 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 chemistryis 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 follo wing 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 we lls throughout the United States (Clark and Veil 2009). Injection fo r enhanced recovery could also be a good management option for extracted water.17 Water is a scarce commodity in many parts of the world. Substant ial efforts are ongoing to develop economical methods to treat produced wate r, most of which is quite salty, and put it to a new use. Some produced water, particular ly the water associated with coalbed methane production in the Rocky Mountain region of th e United States, has low salinity (EAA 2006). That water may be suitable for reuse without any tr eatment. This is unlikel y to be the case with extracted water from CCS operations, as demonstr ated 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 wa ter 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 recycl e 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 mini mization, reuse, or r ecycling, 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, ope rators may need to employ different treatment processes and technologies. The fi nal disposition of the water dete rmines the type and extent of treatment. Treatment technologies can be divided into two genera l categories, technologies for removing salt and other inorganics and t echnologies for removing oil and grease. Table 8 lists treatment technologies designed to remove salt and other inorgani cs from produced water. Most

of the formations from which water could be extr acted 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 form ations, the levels of oil and grease and other organics are likely to be considerably lower th an what is found in produced water when saline formations are used. Nevertheless, thes e technologies are listed here, since CO 2 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 derivi ng 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 desira ble 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 en ergy that utilizes heat generated within the earth. Geothermal energy can be used for h eating 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 vapo r. The vapor spins a tu rbine connected to a generator. In general, temperat ures of at least 90°C and pref erably greater than 150°C, are desirable for utility scale geothermal energy production. At lower temp eratures, geothermal energy can be used directly for heating and coo ling, using geothermal heat pumps. They take20 TABLE 7 Water Disposal Technologies for Extracted Water

Technology Pros Cons

Discharge Offers modera te 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 prov ide 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 te mperatures 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 ex isting 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 ope rator, 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 oi l and gas wells as geothermal source wells.

The first actual example in which geotherm al power was generated from a producing oil and gas well was a test conduc ted at DOE’s Rocky Mountain O ilfield Technology Center in21 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 Orga nic Rankine Cycle (ORC) power plant designed to use 40,000 bpd of 170°F produced wate r from the field’s Tensleep Formation to vaporize the working fluid, isopentane. Th e 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 serv ice in September 2008 and opera ted 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 Septembe r 2009. Between September 2009 and the end of February 2010, the unit produced 47 8 MW-hr of power at a more c onsistent rate than before the extended shutdown (Johnson and Walker 2010).22 TABLE 9 Water Technologies for Re moving 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 ta rgeted 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 high est in western states, especially Nevada and California; and thus, these states are the most lik ely to contain deep sali ne formations that may also be useful for geothermal en ergy production (Duffi eld and Sass 2003).

4.2.2 Extraction of Mineral Commodities

Some chemicals are produced through so lution mining, a process that involves the injection of water and other additives into a form ation 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 of23 liquid. If extracted water from a particular fo rmation contains sufficient concentrations of desirable compounds, it can be a cost-effective f eedstock. The chemical producer would not have to pay for the cost of injecting water and extrac ting the solution since it w ould 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 a ttention as a possible by pr oduct is lithium. Over the past year, the DOE Office of Energy Efficien cy 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 ex tracting sodium carbonate (sodium ash) from produced water (Grimaldi et al. 2010).

Clark et al. (2011) surveyed the historical literature on th e extraction of minerals from geothermal brines. They identified at least 14 projects that attempted to economically produce a range of minerals from geothermal brines in cluding, but not limited to: Li, Zn, Mn, Mg, NaCl, KCl, CaCl 2 , silica, and borax. Of these projects, very few were more than a temporary

commercial success. Reasons for failure varie d, but they included changes to underlying commodity prices and high operating costs re sulting from high temperatures, scale and corrosion, and challenging separatio n processes due to complex br ine chemistry. At least three newer projects are still in the early feasibili ty 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 le ast 26 were commercial operations. The minerals extracted included I, Br, Li, Mg, NaCl, KCl, CaCl 2 , NaCO 3 , 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 commercia lly from some brines in the past.

The potential for mineral extraction from ex tracted water will be highly site specific. While it is possible and even likel y that there will be formations that have favorable conditions for mineral extraction, these will more than likely be the excepti on 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 valu es for many of the minerals that may be of

interest. More data on these c oncentrations will be required be fore more formation-specific screening and analysis can be performed.2425 5 COST OF EXTRACTED WATER MANAGEMENT

The cost of managing water will be an importa nt factor in determining if it makes sense to extract water from a given formation. These costs will vary signifi cantly depending upon the location, specific brine characteri stics, and the management stra tegy selected. To get a better idea of what these costs might be, cost estima tes were obtained for many existing oil and gas produced water management practices. Costs we re obtained for both di sposal 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 publis hed estimates for costs as both treatment providers and well operators are reluctant to shar e detailed cost information. Therefore, the cost estimates provided in this chapte r should be considered as approxi mations. Further, the cited cost values in Tables 10 through 12 are taken from refe rences published in different years. The value of a 1992 dollar is greater than th e value of a 2006 dollar in current times. Readers are advised to use the cost figures in this chap ter as a starting point, then do their own estimation and validation

evaluation.

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

methods for which data were available include d discharge to a surface water body with a NPDES permit, injection underground to an underground injection control permitted disposal well, and evaporation in specially designe d evaporation ponds. Discharge is generally the least expensive management practice, where available, with cost s as low as a few cents per barrel in some locations. However, for commercial treatment a nd disposal, costs can exceed $2/bbl. Permitting is likely to be a major hurdle to the use of su rface 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. Ev aporation 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 deioniza tion. Costs were somewhat lower for RO ($0.45 to $3.50/bbl) and capacitive de ionization ($1/bbl), but thes e 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 a bove 50,000 to 60,000 mg/L. Ongoing research at Lawrence Livermore National Laboratory has i ndicated that the cost s of RO could be significantly reduced for water that is pressurized at the wellhead by the injection of CO 2 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 sy stems can more easily handle higher TDS

concentrations. While lower rec overy rates and higher concentrat e disposal costs are expected, significant increases in the amount of energy requ ired to treat water as TDS concentrations increase are not expected.26 TABLE 10 Costs for Produced Water Disposal

State Management Practice Cost /bbl a Transport

Cost

Included Year Source

PA Discharge $2.90 n 2010 Quote b 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 /bbl a 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 Distillation b $8.45 n 2010 Kohl 2010

PA Thermal Distillation b $6.70 n 2010 Quote c Any Capacitive Deionization $1.00 d 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 trans portation 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) reporte d 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 wa ter management. The two main transportation options are pipelines and tr ucks. Pipelines tend to be more economical for shorter distances and where water production is st able and anticipated for an extended period of time. Trucking is a better option when wate r production is more inte rmittent 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 truc ks can haul from 100 to 150 bbl per load and are us ually contracted out with pri ces 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 CO 2 sequestered. At $1.50/bbl which could include injection with tr ansportation, 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 th e 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 unlik ely that voluntary water extraction would be justified in areas where the costs of manage ment 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 s till 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 addi tional pore space. Wate r extraction will not automatically or always be a mandatory compon ent of large CCS programs. However, if an
operator proposes to extract wate r for project operational and cont rol purposes, the operator must carefully consider how a s ubstantial volume of saline gr ound water can be managed.

A number of water management strategies ha ve been explored based upon the experience of the oil and gas industry. Quite a few of thes e 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 CO 2 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 ma nagement practices, other important issues to consider in water extraction include the following questions.

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

 How should water be extracted (continuousl y, intermittently, or different rates at different times)?

 Where should water be extracted (at or n ear the injection point, down gradient at one point, or down gradient at multiple points)?

 How many injection wells should be em ployed (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 CO 2 , or other)?

Much of the information needed to answ er these questions ca n be derived by using experience, models, and data alr eady developed for other industries such as the oil and gas and geothermal industries.3031 7 REFERENCES

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Bentham, M. and G. Kirby, 2005, “CO 2 Storage in Saline Aquifers,” Oil & Gas Science and Technology, 60(3):559–567.

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Wolery, T.J., R.D. Aines, Y. Hao, W. Bourcier , T. Wolfe, and C. Haussman, 2009, “Fresh Water Generation from Aquifer-Pressurized Carbon Storage: Annual Report FY09,” prepared by Lawrence Livermore National Laboratory for th e U.S. Department of Energy, December.33 APPENDIX A:

Table of Deep Saline Formations That Have
Geochemical Data Available3435Name Partnership Depth (ft)StorageCapacity (Gt) Data PointspHMedianTDS Median(mg/L)TDS Average(mg/L)Antelope Valley Basin WESTCARB 4 7.5 26,551 23,381Appalachian Basin MRCSP 5,900-8,300 84 5.9 253,767 238,421Arbuckle SWP, SECARB 3043 7 38,442 54,733Astoria-Nehalem Basin WESTCARB 4,700 1-12 0Basal Conasauga Sandstones MRCSP 0.4-1.7 21 7.2 57,014 90,116Bass Islands Group Big Sky 1.6-6 3 8.2 199,704 210,202Big Horn Basin Big Sky 11-146 2113 7.7 5,004 9,015Broom Creek Formation PCOR 5 1 7.9 12,286Cape Fear SECARB 0Cedar Keys, Lawson Formations SECARB 11-153 1 7.8 35,119Cedar Mesa SWP 0Central Valley WESTCARB 20-282 0Cincinnati Arch MRCSP 3,200-3,500 9 6.9 58579 57,355Colorado Plateau WESTCARB 5,000 0Columbia Plateau Big Sky 0Cook Inlet Basin WESTCARB 37 6.3 228,191 219,464Coos Basin WESTCARB 7,500 0Cuyama Basin WESTCARB 1-15 0Cypress Sandstone MGCS 3,000 0.4 -1.7 75 6.6 106,427 106,693Dakota SWP 1535 8 8,113 13,950Devonian SWP 895 6.9 63,973 92,249Dockum SWP 1 7,174Eel River Basin WESTCARB 1 0Entrada SWP 9,000-12,000 48 7.3 12,830 24,935Fountain SWP 2 7.7 5,204Frio SECARB 917 7.1 37,241 54,354Glorieta SWP 231 7.4 79,344 97,864Granite Springs Valley Basin WESTCARB 0Green River Basin SWP, Big Sky 2865 8 10,488 17,362Gulf Coast Eocene SECARB 160-2,200Gulf Coast Miocene SECARB 400-5,500Gulf Coast Oligocene SECARB 130-1,800Gulf Coast Olmos SECARB 0.4-6Gulf Coast Pliocene SECARB 140-1,900Gulf Coast Tertiary Undivided SECARB 17-240Gulf Coast - All SECARB 7453 7.1 56,694 71,12036Name Partnership Depth (ft)StorageCapacity (Gt) Data PointspHMedianTDS Median(mg/L)TDS Average(mg/L)Hermosa SWP 283 7 110,022 126,527Illinois Basin MGSC 7,000-8,600 912 7 116,577 104,431Ione Valley Basin WESTCARB 0Jackson SECARB 16 7.4 25,892 80,470Jasper SECARB 0Knox Group MRCSP 30 6 7.6 16,716 25,796La Honda Basin WESTCARB 1 0Lakota PCOR, Big Sky 4,100-6,700 138 8.1 5,484 8,617Leadville SWP 10 7.1 61,800 75,846Livermore Basin WESTCARB <1 0Lockport Group MRCSP 4.5-18 6 6.6 221,090 232,540Los Angeles Basin WESTCARB 5-35 264 7.4 30,354 28,491Lyons SWP 161 7.6 27,742 35,319Madison Formation PCOR 4,000-16,000 37 2280 6.9 51,142 120,112Maha Formation PCOR 3 0Medina/Tuscarora Sandstone MRCSP 7.9 -32 12 6.3 251,276 236,785Mesaverde SWP 4,000-11,000 1517 8.0 9,246 13,754Michigan Basin MRCSP 3,200-3,500 269 5.8 303,516 279,597Montana Thrust Belt Big Sky 2.5 - 34 16 7.3 3,031 2,938Morrison SWP 3,600-12,000 303 8.0 10,984 14,792Mount Simon Sandstone MGSC, MRCSP,SECARB2,000 to 14,000 11-151 0Newcastle Formation PCOR 6,700 1 122 8.0 10,841 11,710North-Central Montana Big Sky 68 - 933 689 7.9 5,236 8,856Ochoco Basin WESTCARB 1-12 0Offshore Atlantic Unit 120 SECARB 36-490 0Offshore Atlantic Unit 90 SECARB 3-43 0Orinda Basin WESTCARB 1 0Oriskany Sandstone MRCSP 1.9 -7.8 207 4.6 253,770 219,423Paradox SWP 467 7.1 80,989 103,021Potomac Group SECARB 2-25 0Potsdam Sandstone MRCSP 0.2-1.7 0Pottsville Formation SECARB 1.1-15 1 361321Powder River Basin PCOR, Big Sky 14-196 2912 8 7,812 18,248Puget Trough Basin WESTCARB 35-475 0Redwall SWP 11 7 9,257 51,78237Name Partnership Depth (ft)StorageCapacity (Gt) Data PointspHMedianTDS Median(mg/L)TDS Average(mg/L)Reese River Valley Basin WESTCARB 0Rome Trough Sandstones MRCSP 0.1 -0.8 0Rose Run Sandstone MRCSP 5.7 -23 1 6.1 201467Sacramento Basin WESTCARB 50 -250 12 6.4 16,665 16,633Salinas Basin WESTCARB 1 -15 1 31094Salton Trough WESTCARB 5 -40 0San Andres SWP 1310 7.1 76,286 105,958San Joaquin Basin WESTCARB 50 -250 195 7.4 21,982 22,424San Juan Basin SWP 283 7.4 19,130 36,585Snake River Plain Big Sky 3 7.8 11,930South Carolina - Georgia Basin SECARB 13-60 0Southwest Montana Big Sky 1.9-26 57 7.9 3,118 3,855Southwestern Wyoming Big Sky 47-640 2425 8 9,177 15,492St. Peter Sandstone MRCSP 8.8 -35 26 6.7 86,737 87,715Sylvania Sandstone MRCSP 1.5 -3.5 0Tapeats SWP 0Tofino-Fuca Basin WESTCARB 5,300 0.5-4 0Tuscaloosa Group SECARB 5-75 935 6.1 147,556 137,298Tyee-Umpqua Basin WESTCARB 5,300 0Ventura Basin WESTCARB 5 -35 16 7.3 30,220 29,598Vicksburg SECARB 156 6.9 25,074 32,627Viking Formation PCOR 60 0Wasatch SWP 2,600-3,400 600 7.9 10,711 16,156Waste Gate Formation MRCSP 0.4 -1.8 0Weber SWP 9,000-14,000 210 7.4 35,700 57,762Western Olympic Basin WESTCARB 3,500 0.5-4 0Whatcom Basin WESTCARB 0.2-3 0Willamette Trough WESTCARB 0Willapa Hills Basin WESTCARB 7,500 1-12 0Williston Basin PCOR, Big Sky 58-804 3027 6.7 138,400 159,589Wind River Basin Big Sky 14-187 1520 8 5,603 10,488Woodbine Formation andPaluxy SandstoneSECARB 5-70 440 7.4 56,773 59,156Woodward Trench SWP 0Wyoming Thrust Belt Big Sky 5.3-74 191 7.3 18,872 34,26138