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Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter.  As a result of this process, there is

repetition in the response text.  The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.   

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.  

Responses on each topic area are compiled and are also available in the rulemaking docket.
General Comment 

Over 3 trillion standard cubic feet (TCF) or 150 million metric tons of CO2 have been injected 

for enhanced oil recovery (EOR) at the SACROC oilfield in west Texas since 1972. Roughly 

half of the injected CO2 has been produced and reinjected as part of a recycling effort; an 

estimated 35 million tons is permanently sequestered in the subsurface at SACROC. Clearly this 

is a large scale CO2 injection site. As with the other four CO2 injection sites referenced in 

Section II of this Notice, there has been no documented leakage of CO2 at SACROC. 

The attached document is a status report submitted to EPA Region 6 offices in Dallas, TX in 

April 2009. This report summarizes DOE/NETL-funded, through the Southwest Regional 

Carbon Sequestration Partnership (SWP), research at SACROC. Objectives of the combined 

research efforts of the Bureau of Economic Geology, Los Alamos National Laboratory, New 

Mexico Tech, University of Pittsburgh, and University of Utah are to (1) assess potential impacts 

to the shallow subsurface over SACROC, (2) model the fate of CO2 injected into the subsurface 

at SACROC, and (3) use geophysical methods to image the ~35 million tons of CO2 assumed to 

be trapped in the subsurface. 
1

Update on SWP Research Activities at the SACROC Oilfield, 

Scurry County, Texas and Status of GCCC 

Studies on Risk to Aquifers from CO2 Sequestration 

Prepared by: Rebecca C. Smyth, Gulf Coast Carbon Center, 

Bureau of Economic Geology, Jackson School of Geosciences, 

The University of Texas at Austin 

Prepared for: United States Environmental Protection Agency and Department 

of Energy National Energy Technology Laboratory Interim Data Request 

April 26, 2009 

Contents 

Status of SWP Research Activities at SACROC .............................. 3 

 Introduction ...................................................................................... 3 

 Geophysics ....................................................................................... 3 

 Groundwater ..................................................................................... 4 

 Reservoir/Injection Zone Modeling ................................................. 4 

 Surface Flux...................................................................................... 4 

Status of GCCC Studies on Risk to Aquifers ................................... 4 

 Executive Summary ......................................................................... 4 

 Introduction ..................................................................................... 4 

 CO2-rock Reaction Fundamentals ............................................... 4 

 Laboratory Experiments ................................................................... 7 

 SACROC Groundwater Studies ..................................................... 11 

 Methods ..................................................................................... 11 

 Groundwater Data Analysis ...................................................... 12 

 Conclusions .................................................................................... 24 

 Acknowledgments .......................................................................... 25 

 References ...................................................................................... 26 

 Appendix A. Federal Requirements Under the Underground 

 Injection Control (UIC) Program for Carbons Dioxide (CO2) 

 Geologic Sequestration (GS) Wells, Fall 2008 Proposed Rule ..... 28 

 
2

List of Figures 

Figure 1. Laboratory experiment reaction vessels. ......................................... 8 

Figure 2. Cation concentrations during laboratory experiment ...................... 9 

Figure 3. pH values during experiment for all reactors. ............................... 10 

Figure 4. Locations of SACROC oilfield, local extent of Dockum aquifer, 

 and BEG and TWDB water wells used in study. .......................... 11 

Figure 5. TWDB (1956-2008) and BEG (2007-2008) pH data. .................. 14 

Figure 6. Contours of pH measured by TWDB in Scurry County between 

 1956 and 1980. ............................................................................... 14 

Figure 7. Contours of pH measured by BEG and TWDB in Scurry County 

 between 1995 and 2008. ................................................................. 15 

Figure 8. TWDB (1936-2008) and BEG (2007-2008) total dissolved 

 solids (TDS) data. .......................................................................... 15 

Figure 9. Scaled cross sections of selected BEG-sampled wells ................ 17 

Figure 10. Locations of wells monitored for SWP SACROC 

 groundwater study ........................................................................ 18 

Figure 11. Piper diagram showing large variation in water chemistry 

 for BEG and TWDB wells ............................................................ 19 

Figure 12. Piper diagram of BEG wells only ................................................ 19 

Figure 13. Sulfate vs. chloride concentrations of all BEG samples .............. 20 

Figure 14. Locations of transect plots relative to SACROC and potentiometric 

 surface contours ............................................................................ 21 

Figure 15. Calcium, magnesium, and strontium concentrations 

 along flow path ............................................................................ 22 

Figure 16. Total dissolved solids, sodium, potassium, and chloride 

 concentrations along flow path .................................................... 22 

List of Tables 

Table 1. Chemical analyte ranges and median values for 113 BEG 

 freshwater samples collected from private wells in Fisher, 

 Garza,Kent, and Scurry counties ..................................................... 13 

Table 2 Stratigraphic units in the subsurface below the 

 SACROC oilfield. ............................................................................. 16 

Table 3. Comparison of EPA drinking water standards with BEG 

 Dockum aquifer well data. ............................................................... 23 

 
3

Status of SWP Research Activities at SACROC 

Introduction 

One of three Southwest Regional Partnership for Carbon Sequestration (SWP) Phase 

II research projects, being funded by the Department of Energy National Energy Technology 

Laboratory (DOE NETL), is taking place at the Scurry Area Canyon Reef Operators 

Committee (SACROC) oilfield near the eastern edge of the Permian Basin in Scurry County, 

Texas. Dr. Brian McPherson of University of Utah and Dr. Reid Grigg of New Mexico 

Institute of Mining and Technology (NMT) are principal investigator and acting project 

manager, respectively, of the SWP. Rebecca C. Smyth of the Gulf Coast Carbon Center 

(GCCC) at the Bureau of Economic Geology (BEG) is site manager for SWP SACROC 

research. 

Since 1972 over 150 million metric tons (MMt) (3 trillion standard cubic feet (TCF)) 

of carbon dioxide (CO2) have been injected for enhanced oil recovery at SACROC. As of 

October 2008 only 75 MMt (1.5 TCF) of the injected CO2 have been recovered, making this 

site a natural laboratory for research on subsurface CO2 storage. SACROC is currently 

operated by Kinder Morgan Company (KM), which serves as the major industrial partner for 

this project. Schlumberger Carbon Services division is also providing project support. Two 

scales of SWP MVA research are ongoing in and around SACROC. 

Deep subsurface research components (geophysics and reservoir zone modeling) are 

underway near a ~1 km2 (~0.4 mi2) injection experiment site centered on production well 56-

17; four water-alternating-gas (WAG) wells lie at corners of the nearly square-shaped-pattern. 

The 56-17 pattern is located at the southern end of the North Platform area of SACROC in 

what is now designated the South Platform production development area. Three SWP 

monitoring wells are within 100 to 300 ft from new injection wells located to the NE, SE, and 

SW of well 56-17. These monitoring wells are old production wells reentered and sidetracked through the 6,000 to 7,000 ft deep production/injection interval by KM in 2008 to 

benefit SWP research. WAG injection began in the 56-17 injection pattern in September and 

October 2008. All four WAG wells were injecting CO2 before the end of October 2008. 

Research groups from Los Alamos National Laboratory (LANL), NMT, University of 

Pittsburg and DOE NETL, and University of Utah are leading the deep subsurface research 

projects at SACROC. 

Shallow subsurface and surface SWP MVA research is taking place on a more 

regional scale looking for differences within SACROC versus outside of SACROC. Bureau 

of Economic Geology (BEG) researchers have sampled water wells in a ~3300 km2

 (~1275 

mi2), multicounty area to look for potential impacts to freshwater resources from long-term 

CO2 injection at SACROC. Researchers from NMT are measuring CO2 surface flux within 

and outside of SACROC. The multiple components of SWP research are detailed in the 

following sections of this interim data report. 

Geophysics 

 Three parts of the geophysics component of MVA at SACROC SWP Phase II 

research are: (1) borehole geophysical logging, (2) surface reflection geophysical survey, (3) 

rock physics modeling, and (4) vertical seismic profiling survey. 

 The SWP partnership and KM are sharing the cost of borehole geophysical logging at 

the 56-17 injection experiment site; SWP is paying for pre- and post-CO2-injection in one of 
4

the monitoring wells and KM is paying for logging in the other two monitoring wells. KM 

has also agreed to share borehole logs collected in the new injection wells with SWP 

researchers. Schlumberger and Weatherford companies completed pre-CO2-injection 

borehole geophysical logging in three monitoring wells in the 56-17 injection experiment 

pattern by July 2008. Types of cased hole logs run in the monitoring wells were cement bond, 

neutron, RST (sigma and CO modes), and sonic. The same suite of logs were run in injection 

wells after casing was installed; density, gamma, neutron, resistivity, and sonic open hole 

logs were run in the injection wells before casing was installed. Repeat or post-injection cased 

hole logs were run in two of the monitoring wells in February 2009. Data processing and 

interpretation by Schlumberger, KM, and BEG are in progress. 

 Multiple surface reflection geophysical surveys cover the SWP injection experiment 

site. In 2003 KM conducted a 3-D seismic survey of the SACROC North Platform area, the 

southern edge of which overlaps the SWP 56-17 site. BEG researcher Dr. Bob Hardage and 

and Dr. William Harbert of University of Pittsburgh (UPitt) and DOE NETL have acquired 

pre-stacked, pre-migrated seismic data from this survey courtesy of KM. Further processing 

of this pre-injection dataset is ongoing. Harbert, using outside funding from DOE NETL and 

technical assistance from Hardage, has completed two smaller scale (~4 km2 or 1.5mi2) 

surface seismic surveys centered on injection well 59-2A at the northeastern corner of the 

SWP injection experiment pattern. Harbert and Hardage conducted the two surface seismic 

surveys in November 2008 and March 2009. Data processing and interpretation of surface 

seismic data are in progress. 

 Data for rock physics modeling are being collected by Harbert’s research group at 

DOE NETL and UPitt. This group is collecting computed tomography (CT) and rock 

mechanics data from SACROC reservoir zone core to aid in estimations of seismic velocities 

and interpretation of surface geophysical data. These data will also be used in BEG rock 

physics modeling to aid interpretation of SACROC reservoir zone pore-filling fluids. 

 LANL is conducting vertical seismic profile (VSP) surveys in monitoring well 59-2, 

which is ~200 ft to the SW of injection well 59-2A in the SWP injection experiment site. The 

pre-injection survey took place in July 2008. The post-injection VSP survey was just 

completed in mid-April 2009. SWP SACROC VSP data processing is in progress. 

Groundwater 

Groundwater studies being conducted by BEG researchers under direction of Rebecca 

C. Smyth are detailed in a later section of this report entitled: “Status of GCCC Studies on 

Risk to Aquifers.”

Reservoir/Injection Zone Modeling 

This work is being conducted by SWP research groups at the University of Utah under 

direction of Dr. Brian McPherson and New Mexico Tech under direction of Dr. Reid Grigg. 

Progress reports on this component of SWP SACROC research need to be provided by these 

groups. 

Surface Flux 

Measurement of CO2 surface flux is being conducted by researchers at NMT and 

BEG. The NMT team collected data in June 2008 and January 2009 within SACROC and at a 

“background” measurement site approximately 10 miles NW of SACROC. NMT researchers 
5

plan to repeat measurements at the same sites in June 2009 and January 2010 if project 

extensions are granted. Interpretation of NMT CO2 surface flux data is in progress. 

A second set of CO2 surface flux measurements were collected at SACROC by BEG 

and Applied Nanotech Inc. (ANI) personnel in January 2009 using ANI experimental sensors. 

This work is being funded primarily through direct support to ANI from DOE. 

Status of GCCC Studies on Risk to Aquifers 

Executive Summary 

The Gulf Coast Carbon Center (GCCC) of the BEG has interim results from two 

studies related to the potential for damage to freshwater resources as a consequence of failure 

to adequately sequester injected carbon dioxide (CO2). Questions posed by studies detailed 

here are: 

(1) Can changes in chemistry of freshwater aquifers provide evidence of CO2 leakage 

from a deep-injection/sequestration reservoir? 

(2) What parameters can we use to assess potential impacts on water quality? 

(3) If CO2 leakage to freshwater aquifers occurs, will groundwater quality be 

degraded? 

One study is a series of laboratory batch experiments to test what happens when 

aquifer rocks and freshwater react with CO2. Reactions occurred within a day, including 

decreased pH and increased dissolved constituents. In some samples, cations Ba, Ca, Fe, Mg, 

Mn, and Sr increased significantly. Different aquifer-rock–freshwater reaction experimental 

vessels showed different magnitudes of increase in cation concentration. From this result we 

conclude that simple but aquifer-specific laboratory tests would help in the design of earlywarning freshwater monitoring plans. In addition, such tests would allow a realistic 

determination if a constituent of concern would be released in the event of an accidental 

major CO2 leak to freshwater. This study was funded by GCCC (gulfcoastcarbon.org). 

The other study is on fresh groundwater above the SACROC oil field in Scurry 

County, Texas, USA, where CO2 has been injected to a depths between 6,000 and 7,000 ft for 

enhanced oil recovery (EOR) since 1972. From 2006 through 2008, BEG researchers sampled 

68 water wells and 1 spring and analyzed major, minor, and trace-element chemistry of water 

samples taken over a 3300 km2

 (1275 mi2) area. Work completed to date has used pH and 

dissolved constituents identified in the laboratory study as indicators of impacts to 

groundwater. We find no diagnostic patterns of changes through time or over the area above 

the injection. This result leads to a preliminary conclusion, subject to limitations of the 

approach, that no leakage of injectate-CO2 into the aquifer has occurred. However, the 

groundwater system is complex and includes numerous water-bearing zones with diverse 

rocks and water types. In addition, natural recharge may be contributing CO2 from 

organic/microbial sources and salinization of isolated portions of the aquifer has resulted 

from historic oil-field practices. Work on this extensive, complex database continues to assess 

whether any other indicators of leakage of CO2 from depth can be identified. This study was 

funded by the U.S. Department of Energy (DOE) through the Southwest Regional Carbon 

Sequestration Partnership through NMT. Additional financial and logistical support are being 

provided by Los Alamos National Laboratory and SACROC operator Kinder Morgan. 
6

Introduction 

Site selection for geologic sequestration (GS) is the key element in ensuring that 

carbon dioxide (CO2) will be retained in an appropriate receiving formation for geologically 

significant periods of time. Restriction of fluid-injection permits to properly selected sites is 

mandated by the Safe Drinking Water Act of 1974 (U.S. House of Representatives, 1974) and 

managed by the U.S. Environmental Protection Agency (EPA) Underground Injection 

Control (UIC) Program. In a correctly selected GS site, transport of CO2 out of the injection 

formation should be negligible, and migration would be limited to diffusion into confining 

zones. Underground sources of drinking water (USDWs) near a correctly selected site would 

not be impacted by CO2 injection, thereby meeting EPA requirements to protect drinkingwater supplies. 

However, it is prudent to assess potential impacts of (1) failure to contain injected 

CO2 in the receiving formation and (2) displacement of high-salinity fluid (brine) into 

USDWs. Potential errors in site selection considered here are presence of moderate- to highpermeability flowpaths, such as a vertically transmissive fault or improperly plugged well, 

along which CO2 and/or brine could migrate. The possibility of impacts to USDWs is the 

focus of this brief. A USDW is defined in the EPA Proposed Rule for Permitting Full-Scale 

Geologic Sequestration Projects (July 2008) as: 

An aquifer or portion of an aquifer that supplies any public water system or that 

contains a sufficient quantity of groundwater to supply a public water system, and 

currently supplies drinking water for human consumption, or that contains fewer than 

10,000 mg/l total dissolved solids and is not an exempted aquifer. 

In the proposed rule, CO2 would be isolated from USDWs by a confining zone (i.e., lowpermeability seal). 

In the following sections we present results of laboratory experiments conducted to 

assess chemical byproducts of reactions between injected CO2, aquifer host rocks, and fresh 

groundwater. We then present results from a field-based study of groundwater quality 

overlying the Scurry Area Canyon Reef Operators Committee (SACROC) oil field in Scurry 

County, Texas. CO2 has been injected at SACROC for enhanced oil recovery (EOR) since 

1972, making it an ideal natural laboratory for observing potential impacts of CO2 to 

groundwater. 

This work has been funded by the Gulf Coast Carbon Center (GCCC) industrial 

sponsor program at the Bureau of Economic Geology (BEG), the Department of Energy 

National Energy Technology Laboratory (DOE/NETL) through the Southwest Regional 

Partnership for Carbon Sequestration (SWP) administered by New Mexico Tech, and Kinder 

Morgan pipeline and production companies. 

CO2-rock reaction fundamentals

Most studies of how CO2 dissolves in water and reacts with the host rock have 

considered injection zones at depths >1 km and focus on trapping of CO2 in mineral phases 

(Gunter et al., 2004; Rochelle et al., 2004; Worden and Smith, 2004). CO2-solubility 

dependence on pressure, temperature, and salinity is well known. Field observations at Frio 

(e.g., Karaka et al., 2006 and Hovorka et al., 2006), Weyburn (IEA, 2005) test sites, and 

simulations based on observations at the sites, have documented rock-brine-CO2 reactions at 

1,500-m depths in 100,000 mg/L basinal brines. Under these conditions, fluids are strongly 

reducing (methane saturated), and CO2 is supercritical (Knauss et al., 2005). 
7

Under most circumstances, CO2 will dissolve in water and lower pH, which is a 

process represented by the following chemical reactions: 

 CO2(g) + H2O ↔ H2CO3(aq); H2CO3(aq) ↔ HCO3(aq)–

 + H+; HCO3(aq)– ↔ CO3(aq)

2– + H+

(aq). 

In a system containing reactive mineral phases, decrease in pH is buffered by dissolution of 

carbonate or Ca/Mg/Fe-bearing silicate minerals (Gunter et al., 1993). High CO2 content 

causes continued dissolution of silicates and precipitation of clay minerals, carbonates, and 

quartz when acidity has been reduced by silicate dissolution (Gunter et al., 1997; Hitchon et 

al., 1999). Dissolution or precipitation of carbonates depends on mineralogy and water 

chemistry. In each case, dissolution and precipitation reactions are a function of 

thermodynamics. Rates of these reactions are controlled by chemical kinetics (e.g., Wang and 

Jeffe, 2004). 

Studies of CO2 being introduced into a potable aquifer setting are few. Shallow 

aquifer conditions are unlike studies done at depth. Rocks have been flushed by freshwater, 

CO2 is present as a gas rather than a supercritical fluid, and temperature, pressure, and salinity 

are lower than in deep-reservoir conditions. Whereas potable waters high in CO2 occur in 

nature (e.g., the Perrier region of France), these rock-water aquifer systems have had a long 

period in which to react and equilibrate with CO2. Hence, they may be an imperfect analog 

for short-term reactions that could result from accidental leakage of CO2 into a freshwater 

aquifer. 

Laboratory Experiments 

BEG researchers conducted laboratory batch experiments to investigate the extent to 

which injected CO2 migrating upward into a shallow aquifer could mobilize major and minor 

ions bound to aquifer host rocks. A series of batch experiments was designed to cause diverse 

aquifer rocks to react with CO2 in the medium of water. We selected core samples from the 

Core Research Center at BEG in order to represent various aquifers present in Texas and 

throughout the Gulf Coast region. 

For each reactor, 95 g of disaggregated, unwashed rock sample was combined with 

500 mL of deionized (DI) water in a wide-mouth 500-mL Erlenmeyer flask (Figure 1). 

Rubber stoppers facilitated air-tight placement of inflow and outflow tubes. To minimize the 

corrosiveness of DI water, sodium chloride (NaCl) was added to approximate natural 

groundwater activity (~40 ppm Cl-

). The experiment was split into two periods. In the first 

period, argon (Ar) gas was bubbled through the reactors for 2 weeks. CO2 was bubbled 

through the reactors for a second 2-week period immediately following. When the gas supply 

was switched from Ar to CO2 on Day 14, 70 mL of DI water was added to each reactor to 

replace the water that had been removed during the Ar run (dilution factor 1.14). Ten flasks 

containing samples of aquifer rock and a blank (DI water only) were run simultaneously. The 

outflow manifold system was open to room atmospheric pressure. 
8

Figure 1. Laboratory experiment reaction vessels. 

During Ar injection, 2-mL water samples were taken at 1-, 5-, 12-hour, 1-, 2-, 4-, 7-, 

10-, 12-, and 14-day time intervals for ion analysis. Water was sampled on the same schedule 

during the CO2 run. After every sampling period, pH, oxidation-reduction potential (ORP), 

dissolved oxygen (DO), and conductivity were measured using a multiparameter probe 

(Hanna Instruments 9828). Cation analysis was done at The University of Texas at Austin 

Department of Geological Sciences on an Agilent 7500ce Quadrupole ICP-MS. Cation 

concentrations measured from the reactors with rock samples were subtracted by 

measurements of the blank reactor. Procedural contamination effects were thus reduced or 

eliminated. Sodium and chloride were normalized as the amount of NaCl added at the 

beginning of the experiment and subtracted. 

Results show that cation concentrations were generally elevated in the CO2

experimental run relative to the Ar run. Rapid geochemical response occurred within hours to 

days of introduction of CO2 with significant liberation of cations Ca, Mg, K, Si, Sr, Mn, Ba, 

B, Fe, and Al. Concentrations of some cations (e.g., Ca, Mg, Mn, Fe, Sr, Ba) increased over 

an order of magnitude. Different aquifer rock reactors displayed different magnitudes of 

increase in cation concentrations. Results of the reactor containing Dockum sandstone aquifer 

rock from Randall County, Texas, are included as an example (Figure 2). 

Figure 2 shows rapid elevation in concentrations of many cations after CO2 was 

introduced on day 14. Release rate of all cations decreased toward the end of the experiment, 

at which point their concentrations increased slowly or remained at a constant level. Good 

correlation between concentrations of Ca and Mg suggests dolomite as their source mineral. 

K and Si may be released from K-feldspar. 

Two types of cation concentration profiles were recognized after introduction of CO2

to reactor vessels: (1) Type I—concentrations increased rapidly then increased slowly or 

remained at constant concentrations and (2) Type II—concentrations increased rapidly then 

gradually decreased. Type I cations include B, Ba, Ca, Co, K, Mg, Mn, Sr, and Zn. Type II 

cations include Al, As, Cs, Cu, Fe, Mo, Ni, Rb, U, and V. 
9

Figure 2. Cation concentrations throughout the experiment on a sandstone sample from the Dockum 

aquifer. CO2 was introduced into the system on Day 14. 

Drop in concentration of Type II cations (e.g., Fe and Al) was unexpected and 

suggests that cation mobilization reached a maximum concentration before resorption and/or 

reprecipitation. Decline in cation concentrations is tentatively interpreted as a result of 

reprecipitation or sorption on reactive grain coatings. In the case of stagnant water, resorption 

suggests that some cation mobilization could be self mediated by the system. This transience 

was also detected at the Frio, Texas, site (written communication 2008; Y. Kharaka, USGS). 

Elevation of concentrations of Type II cations, such as Fe, Al, Mo, U, Cs, Cu, may be a shortterm perturbation and, therefore, a limited risk to water quality. 

As expected, pH dropped at the start of CO2 flux for most reactors (Figure 3). In most 

cases, pH shows a quick rebound after the abrupt decrease at the beginning of the CO2 run 

and then keeps relatively constant. In general, CO2 reduced pH values up to 3 units relative to 

Ar gas. In Reactor 1, for example, pH dropped from over 7.9 to 4.8 within hours after CO2

was added; it then rebounded and remained at ~5.4. The pH rebound is probably due to 

mineral buffering—in this case, dissolution of dolomite and, to a lesser extent, potassium 

feldspar. 

Experimental results provide initial data for the degree and rate at which cations 

would be mobilized from aquifer host rocks if they are affected by CO2 leakage. These data 

can be used as a sensitivity analysis to design field-testing experiments to determine whether 

any constituents elevated in the laboratory tests are detectable in groundwater that has or 

might have come in contact with injectate CO2. However, significance of elevated minor 

cations from samples in solution with minimally reactive gas (Ar) shows that the 
10

concentrations measured cannot be transferred directly to aquifer conditions. Three 

hypotheses are proposed to explain overall high cation concentrations: (1) Because DI water 

with a small amount of NaCl added (Cl ~40 ppm) was used in the experiment instead of 

aquifer water for each sediment, some dissolution of reactive minerals occurred to reach rockwater equilibrium. (2) Disaggregation of rocks exposed more reactive surfaces than would be 

exposed in the aquifer setting. (3) Although some contamination from the experimental 

design was noted and factored out, contamination from sample handling (e.g., drilling mud 

introduced during coring or oxidation of core during storage) cannot be removed. 

Figure 3. pH through the experiment for all reactors. CO2 was introduced into the system on day 14. 

Note that because water was not flushed through the system, the water analyzed was 

representative of what would be mobilized per unit of water under stagnant conditions. As 

follows, water interacted with only one volume of rock, which begs the question of how 

concentrated a unit of water might become upon subsequent interactions with additional 

volumes of rock. The concentration obtained in an aquifer setting would depend on the 

geometry of CO2 flow rate and water migration. If the reactive fluids moved through the same 

rock volume repeatedly along a flowpath, the reactive constituents in the rock might be 

quickly depleted. However, if a geometry were created in which the same volume of water 

were charged with excess gas and migrated through many rock volumes, cation 

concentrations might become quite high. Cation concentrations could also decrease as the 

reacted groundwater moved away from the CO2 source and pH was buffered. Additional 

reactive transport studies are required to understand these relationships. 
11

SACROC Field Study 

 A field study designed to improve understanding of risk to freshwater is under way in 

the vicinity of the ~90-mi2 SACROC oil field in north central Scurry County, Texas, USA 

(Figure 4), where CO2 has been injected for enhanced oil recovery (EOR) since 1972. Most of 

Scurry County is underlain by the Dockum aquifer, which is designated one of the minor 

aquifers of Texas by the Texas Water Development Board (TWDB). To assess whether 

freshwater resources over the SACROC oil field have been impacted by over 35 years of CO2

injection, we must first define the regional variability in Dockum aquifer groundwater 

chemistry. Regionally, throughout the Texas panhandle and southeastern New Mexico, the 

Dockum aquifer has been recognized as being chemically heterogeneous (Dutton and 

Simpkins, 1986). We have gained understanding about why Dockum groundwater is 

chemically heterogeneous, and we recognize no systematic differences in Dockum 

groundwater overlying SACROC versus groundwater overlying areas outside of SACROC. 

Figure 4. Locations of SACROC oilfield, local extent of Dockum aquifer, and BEG and TWDB water 

wells used in study. Location of Scurry County is shown by black-square in insert map of Texas. 

Methods of SACROC groundwater study

Because data on groundwater quality prior to CO2 injection at SACROC are spatially 

and temporally limited, there is not a good “background” dataset against which to compare 

post-CO2-injection groundwater quality. For this reason, and to understand why Dockum 

groundwater is chemically heterogeneous, our study covers 3,300 km2 (1,275-mi2) (area 

covered by black dots in Figure 4). In lieu of sampling before and after CO2 injection, BEG 

sampled both inside and outside SACROC during two consecutive years to assess spatial 

variation in groundwater chemistry. 
12

During the SWP SACROC groundwater study BEG researchers: 

• compiled historical (dating back to 1936) to recent (2008) groundwater 

chemistry data for eight counties (Figure 4) from the TWDB online database 

(TWDB, 2009), 

• collected multiple freshwater samples from 60 private water supply wells 

(113 samples) and one spring (1 sample), and brine from eight 

production/injection wells (10 samples); 

• compiled chemical data from SACROC production/injection zone brine 

analyses; data from brine samples are being used in geochemical mixing 

models and are not discussed in this document, 

• conducted a study of shallow subsurface stratigraphy, and 

• measured water levels to construct potentiometric surface maps and 

identify groundwater flow paths in the Dockum aquifer. 

BEG researchers completed six water quality sampling and water level monitoring 

trips between June 2006 and November 2008. Water well sampling methodology included 

continuous measurement of field chemical parameters (temperature, pH, specific 

conductivity, and dissolved oxygen) in a flow cell and monitoring of discharge rate. To 

ensure that samples were from the formation and not stagnant casing-volume-water, we did 

not collect groundwater samples until after field chemical parameters stabilized. We 

performed alkalinity titrations in the field using filtered, unpreserved water samples. Other 

sampling protocol included: (1) field filtering and acid preservation of cation samples and (2) 

storage of all samples at temperature below 4°C immediately after sampling and during 

shipping. 

Laboratory analytes measured in BEG groundwater samples by LANL are: Al, Ag, 

As, B, Ba, Be, Br, Ca, Cd, Cl, CO3, Co, Cr, Cs, Cu, δ13C, dD, δ18O, F, Fe, HCO3, Hg, K, Li, 

Mg, Mn, Mo, Na, Ni, NO3, Pb, PCO2, PO4, Rb, Sb, Se, Si, Sn, SO4, Sr, TDS, Th, Ti, Tl, U, V, 

and Zn. Laboratory analytes measured by The University of Texas at Austin, Department of 

Geological Sciences (UT DGS), are: dissolved inorganic carbon (DIC), dissolved organic 

carbon (DOC), methane (CH4), and CO2 from headspace gas in selected samples. 

Groundwater data analysis

Ranges and median values of 40 chemical analytes, total dissolved solids (TDS), and 

well depths for BEG freshwater samples are shown in Table 1. This table includes results 

from all 60 BEG-sampled water wells in Fisher, Garza, Kent, and Scurry counties (black dots 

in Figure 4). Analytes of particular concern in proposed EPA rules for geologic sequestration 

(Appendix A) are pH, arsenic, lead, mercury. 
13

Table 1. Chemical analyte ranges and median values for 113 BEG freshwater samples 

collected from private wells in Fisher, Garza, Kent, and Scurry counties. 
14

GCCC laboratory tests and results from other studies show that pH will decrease and 

dissolved solids (TDS) will increase when CO2 concentration is in groundwater is increased. 

However, our analysis of TWDB and BEG pH data over time (1956-2008) does not reveal 

anomalous pH or TDS values associated with SACROC (figures 5 through 8). Plots of other 

analytes show similar consistencies in time and space. 

Figure 5. TWDB (1956-2008) and BEG (2007-2008) pH data from Borden, Fisher, Howard, Kent, 

Mitchell, Nolan, and Scurry counties, TX 

Figure 6. Contours of pH measured by TWDB in Scurry County between 1956 and 1980. 

Contour interval = 0.5 pH units. 
15

The pH measured in Dockum aquifer samples collected from 1995 through 2008, after 

CO2 injection had been ongoing for over 20 years, is shown in figure 7. Careful comparison 

with pre-1980 contours reveals either no change or even a slight increase in pH near 

SACROC between the two time periods (figures 6 and 7). We would expect to see the reverse 

trend in pH if either (1) injectate CO2 had leaked into Dockum freshwater zones or (2) 

reservoir brine with lowered pH and increased cation concentrations had been displaced 

upward into Dockum freshwater zones. 

 Figure 7. Contours of pH measured by BEG and TWDB in Scurry County between 1995 and 2008. 

Contour interval = 0.5 pH units. 

Figure 8. TWDB (1936-2008) and BEG (2007-2008) total dissolved solids (TDS) data from Borden, 

Fisher, Howard, Kent, Mitchell, Nolan, and Scurry counties, TX 
16

 Water wells in the region are completed in numerous different and sometimes 

multiple geologic units. The TWDB is a State agency that studies groundwater resources in 

Texas. They have delineated major and minor aquifers throughout Texas based on estimates 

of groundwater quantity and quality. One of the minor aquifers of Texas, the Dockum, 

underlies the SACROC oilfield in Scurry County and surrounding areas (figure 4). The 

majority of water wells in Scurry Co. are classified as Dockum wells by the TWDB. During 

the BEG study of groundwater resources in the vicinity of SACROC we identified large 

variations in well depth, static water level, and water chemistry of freshwater wells. The base 

of fresh water is at approximately 500 ft below ground surface at the base of the Triassic 

Dockum Formation. The SACROC production/injection zones are in the 

Pennsylvanian/Periman age Canyon and Cisco formations at approximately 6,500 ft below 

surface (table 2). 

Table 2. Stratigraphic units in the subsurface below the SACROC oilfield (multiple sources 

for stratigraphic nomenclature) 
17

BEG sampled freshwater from wells constructed in the Ogallala Formation, Dockum 

Formation, Permian-age units, and combinations of these geologic units. By plotting depth of 

water wells and depth to top and bottom of the Dockum Santa Rosa (figure 9), we classified 

wells by stratigraphic unit in which they are completed. Figure 10 shows BEG wells 

classified by geologic formation in which they are completed. We are currently evaluating 

groundwater chemistry trends by grouping data according to stratigraphic unit in which they 

are completed. 

Figure 9. Scaled cross sections of selected BEG-sampled wells relative to top and bottom of Dockum 

Santa Rosa subunit of Dockum aquifer. 

Geologic units present at the surface within our study area range from Permian to 

Quaternary in age. Two significant water-bearing units crop out at the surface within the 

study area. The Triassic-age Dockum Formation (Fm.) (TrD in Figure 10) hosts the Dockum 

aquifer. The second significant water-bearing unit is the Ogallala Fm. (P-EOg in Figure 10). 

This erosional outlier of the Ogallala Fm. is isolated from the Ogallala aquifer of the Texas 

High Plains but provides significant freshwater resources in Scurry and surrounding counties. 

Smaller quantities of fresh groundwater are produced from Permian-age units in the east parts 

of the study area (Figure 10). 
18

Figure 10. Locations of wells monitored for SWP SACROC groundwater study superimposed 

on surface geologic units. Geologic unit abbreviations: Q- undifferentiated Quaternary units; P-EOg – 

Paleocene-Eocene Ogallala Fm.; TrD – Triassic Dockum Fm.; P – undifferentiated Permian units.

Chemistry of Dockum aquifer groundwater is highly heterogeneous. The chemistry of 

Dockum aquifer groundwater varies greatly because (1) the Dockum Formation is 

heterogeneous, (2) the history of oil and gas activity in the region is long, and (3) wells 

designated as Dockum aquifer by TWDB are completed in different stratigraphic intervals. 

Wells completed within the Ogallala outcrop are designated by TWDB as Dockum aquifer 

wells even though not all of them extend into the underlying Dockum Formation, which is 

subdivided into different depositional units with depth (McGowan et. al., 1979), not all of 

which are hydraulically connected. A few Dockum aquifer wells penetrate multiple Dockum 

subunits and extend into underlying Permian-age strata. Ranges of analytes measured in all 

freshwater wells sampled by BEG 

A Piper diagram is a graphical display used to show variations in large groundwater 

chemistry datasets. Milliequivalent percentages of major cations (Ca, K, Mg, and Na) and 

anions (Cl, HCO3, and SO4) are plotted on trilinear diagrams, and combined values are 

projected onto a central quadralinear plot. A Piper diagram of TWDB database samples from 

Dockum aquifer wells in Scurry and immediately surrounding counties (figure 11) shows 

tremendous variation in chemical composition, especially for a single aquifer. Most of the 

TWDB historical samples are from areas outside SACROC, but there is no clear distinction 

between samples collected inside versus outside the SACROC oil field (figure 12). 
19

Figure 11. Piper diagram showing large variation in water chemistry for BEG and TWDB wells 

shown in figures 4 and 10. 

Figure 12. Piper diagram of BEG wells only showing no clear distinction between BEG groundwater 

samples collected inside SACROC versus outside SACROC. 
20

A plot of sulfate (SO4) versus chloride (Cl) anions (Figure 13) shows a more distinct 

grouping of samples from inside versus outside SACROC. BEG freshwater samples from 

inside have higher Cl values than those collected outside SACROC. Samples with higher Cl 

and SO4 concentrations (e.g., Permian and produced water samples) have much higher total 

dissolved solids (TDS) than BEG freshwater samples. Trends of major element 

concentrations in Figures 11 and 12 suggest mixing of Dockum aquifer groundwater and 

water with Permian and production-zone geochemical signatures. Mixing models tested using 

PHREEQC code at BEG predict that <1% produced oil field brine or 12% Permian water 

could mix with the lowest TDS BEG Dockum freshwater sample to produce the highest TDS 

Dockum sample. 

Figure 13. Sulfate vs. chloride concentrations of all BEG samples (five sampling periods, inside and 

outside of SACROC) and BEG and KM produced water samples. 

Several mechanisms can be used to explain fluid mixing, especially in oil fields that 

have been operating since the early 1950s. Evidence of fluid mixing over SACROC should 

not be taken as proof of brine (or associated CO2) leakage from compromised production 

and/or injection well casings. Historical oil-field practices did not take the environmental 

impacts of co-produced brine disposal into account. Use of unlined surface pits for disposal 

of co-produced oil-field brine was routine practice up until the mid-1960s and was not 

abandoned in Texas until the mid-1970s. In the US, many cases have been documented of oilfield brine contamination of groundwater resulting from brine discharge into streams or 

ponds, pipeline leaks, and infiltration pits (e.g., Reed, 1961; Fisher and Sublette, 2005; 

Kharaka et. al., 2005). Incidents of casing leaks have most likely occurred over the ~60-yr 

history of oil-field activity at SACROC. However, current KM operational practices, 
21

including use of protective surface casing and extensive cathodic protection networks, make 

conduit flow between the ~7,000-ft-deep production and freshwater zones highly unlikely. 

The main question pertinent to this study remains: Has Dockum aquifer water been 

impacted by the long history of CO2 injection at SACROC? If conduit flow along leaking 

well bores is responsible for increased TDS in Dockum aquifer water overlying SACROC, 

we would also expect to see impacts from high CO2 concentrations. Given the complexity of 

the natural system and the likely signal from early oil-field activities, it is unrealistic to try to 

prove that no upward vertical communication of fluids has occurred in SACROC oil field. 

Evidence presented here allows us to say that no obvious impacts to groundwater are found, 

and that the impacts observed are not a result of interaction of freshwater with large volumes 

of injected CO2. 

More detailed description of the shallow subsurface stratigraphy underneath 

SACROC allowed us to construct a potentiometric surface map using water levels from only 

those wells completed in the Dockum Santa Rosa subunit of the Dockum aquifer. This map 

reveals a groundwater mound over SACROC (insert with cross section location lines in figure 

14). One way to assess if shallow freshwater resources have been impacted by CO2 injection 

at SACROC is to look at profiles of chemical constituents along Dockum aquifer 

groundwater flow paths in vicinity of SACROC (figures 14 through 16). There are no clear 

trends of lower pH, higher TDS, or higher concentrations of other analytes over SACROC 

versus areas downgradient from SACROC. 

Figure 14. (a) Locations of transect plots relative to SACROC and potentiometric surface 

contours of Dockum Santa Rosa and (b) pH along gradient-paralle transects W, X, and ZY. 
22

Figure 15. Calcium (Ca), Magnesium (Mg), and Strontium (Sr) concentrations along flow 

path transect line X. 

Figure 16. Total dissolved solids (tds), sodium (Na), Potassium (K), and Chloride (Cl) 

concentrations along flow path transect line X. 

Another way to evaluate data from Dockum groundwater samples is to assess 

degradation of water quality by comparing analyte concentrations with EPA drinking water 

standards. Data summarized in Table 3 are from BEG samples that were filtered (0.2 to 0.45 

μm) in the field. Cation samples were preserved with nitric acid to pH below 2. No 

preservative was added to anion samples. Some Dockum freshwater samples have 

constituents that exceed drinking water samples. The percentage of BEG Dockum aquifer 

samples taken from 60 wells and 1 spring with analytes exceeding EPA primary maximum 

contaminant levels (MCLs) and secondary drinking water standards are highlighted in yellow 

in Table 3. Without exception, the percentage of samples with analytes in excess of EPA 

standards is higher outside than inside SACROC (Table 3). 

Arsenic (As) and lead (Pb) are listed as contaminants of particular concern in the July 

2008 EPA proposed rule. The concern is that such constituents will be leached from rocks in 

the appropriate GS reservoir and mobilized to impact USDWs. Of the 9.8 percent of wells 

with As levels above MCLs, only 1.6 percent of these are inside SACROC (Table 3). Only 

~12 percent of the filtered BEG Dockum samples had Pb levels above a detection limit of 

0.002 mg/L. Forty-two percent of these samples are from wells inside SACROC. 
23

Table3. Comparison of EPA drinking water standards with BEG Dockum aquifer well data. 

BEG researchers are studying stable carbon isotopes of fresh groundwater, produced 

water, injectate CO2, solid carbonate phase, and plant matter, which forms the substrate for 

microbial oxidation of CO2. Potential contributions to the carbon isotope signature include 

mixing with Permian and produced water, microbially produced CO2, and injectate CO2. A 

plot of carbon isotope ratios versus dissolved inorganic carbon (DIC) shows an increase in 

light carbon with increasing DIC. This datum is consistent with input from microbial CO2 but 

does not rule out the presence of injectate CO2. Modeling of the system is underway to test if 

it is sensitive to injected CO2 and if so, if any injected CO2 can be identified. 

BEG researchers are currently collecting water levels in Dockum aquifer wells 

throughout Scurry County. Our objective is to generate potentiometric surface maps for the 

various stratigraphic intervals that compose the Dockum aquifer. These maps will aid in 

reactive transport modeling and further interpretation of Dockum aquifer groundwater 

chemistry. 

Conclusions 

Geochemical modeling and reaction experiments plus known occurrences of naturally 

CO2 charged potable water show that common chemical reaction products from dissolution of 

CO2 into freshwater include rapid buffering of acidity by dissolution of calcite and slower 

equilibrium by reaction with clays and feldspars. Results from a series of laboratory batch 

reactions of CO2 with diverse aquifer rocks show geochemical response within hours to days 

after introduction of CO2. Results include decrease in pH and increased concentration of 

cations in CO2 experimental runs relative to control runs using argon (Ar). Some cation (Ba, 

Ca, Fe, Mg, Mn, and Sr) concentrations increased over an order of magnitude during CO2

runs. Results are aquifer dependant in that experimental vessels containing different aquifer 

rocks showed different magnitudes of increase in cation concentrations. 

Laboratory experiments and field observations show that pH will decrease and cation 

concentrations will increase in rock-water systems exposed to injected CO2. Underground 

sources of drinking water contained within multiple stratigraphic horizons of the Dockum 
24

aquifer provides a test case to see if these changes can be detected overlying 6,000- to 7,000-

ft-deep CO2 injection zones of the SACROC oil field. An intensive water sampling program 

was undertaken and shows that Dockum groundwater has both natural and oil-field related 

variability. Our approach is to compare compositions inside SACROC and outside SACROC 

looking for variability that might correspond to the changes expected to result from 

introduction of CO2 into the aquifer. 

Chemical constituents measured in samples of Dockum groundwater throughout the 

study area suggest minor mixing with more saline (higher TDS) Permian water or coproduced oil-field brines. In many oil fields such mixing is the result of former production 

practices, and this mixing is therefore not attributable to the CO2 injection process. Past 

practices preclude attempting to determine the effectiveness of current practices such as brine 

re-injection, protective surface casing, and extensive cathodic protection networks employed 

to protect USDWs. 

One key question can be answered in this progress report – did injection of CO2 at 

depth damage water quality in Dockum USDW? Results show no systematic or widespread 

degradation of water quality inside SACROC as compared to groundwater outside SACROC. 

Dockum aquifer chemical concentrations inside SACROC fall within the range of TWDB 

groundwater chemical analyses of samples taken from a multicounty region surrounding 

SACROC. Dockum wells with chemical constituents in excess of EPA drinking water 

standards are present within our study area. However, a larger percentage of these wells are 

located outside the SACROC oil field. In particular, we see no evidence of As or Pb increase 

in Dockum aquifer zones. 

Analysis is underway of all the factors needed to assess whether any geochemical 

evidence suggests that CO2 injected for EOR at SACROC has mixed with Dockum 

groundwater. Work in progress includes stable isotopic studies, flow path studies, and rockwater interaction modeling. At this time we identify no obvious indications that CO2 from the 

injection zone has interacted with groundwater; however, a definitive conclusion requires 

additional analysis to separate complexities of natural aquifer variability from any CO2 

injection-related change. 

Acknowledgments 

We gratefully acknowledge support of much of this work from the Department of 

Energy National Energy Technology Laboratory and Kinder Morgan CO2 pipeline and 

production companies. LANL performed most chemical analyses on groundwater samples 

collected by BEG as part of the SWP phase-2 project at SACROC. Batch reactor experiments 

were funded by industrial sponsors of the Gulf Coast Carbon Center (www.gulfcoastcarbon.org). 

We thank Bob Reedy for advice in setting up the batch reactor technique and Bridget Scanlon 

for assistance with ion analysis. The text and figures in this document were prepared by 

numerous members of the GCCC research team including: Rebecca C. Smyth, Susan D. 

Hovorka, Jiemin Lu, and Katherine Romanak. 
25

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Doughty C., Pruess, K., Benson S.M. and Freifeld, B.M., 2004, Hydrological and Geochemical Monitoring for a 

CO2 Sequestration Pilot in a Brine Formation. Lawrence Berkeley National Laboratory Report LBNL55104. 15 p. 

Fisher, J.B. and Sublette, K.L., 2005, Environmental releases from exploration and production operations in 

Oklahoma: Type, volume, causes and prevention, Environmental Geoscience, v. 12, p. 89-99. 

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the time scale of experiment for CO2-sequestering reactions by geochemical modelling. Mineralogy and 

Petrology, v. 59, p. 121-140. 

Gunter, W.D., Bachu, S. and Benson, S., 2004, The role of hydrogeological and geochemical trapping in 

sedimentary basins for secure geological storage of carbon dioxide, in Baines, S. and Worden, R., eds., 

Geological Society Special Publications No. 233, p. 129-146. 

Han, W.S., 2008, Evaluation of CO2 Trapping Mechanisms at the SACROC Northern Platform: Site of 35 

Years of CO2 Injection. New Mexico Institute of Mining and Technology, Socorro, Ph.D. Dissertation, 465 

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Hitchon B., Gunter W.D., Gentzis T. and Bailey R.T., 1999, Sedimentary basins and greenhouse gases: a 

serendipitous association. Energy Conversion and Management, v. 40, p. 825-843. 

Hovorka et al., 2004, The impact of geological heterogeneity on storage in brine formations: a case study from 

the Texas Gulf Coast, in Baines, S., and Worden, R., eds, Geological Society Special Publications No. 233, 

p. 147-164. 

Hovorka, S.D., Doughty, C., Benson, S.M., Freifeld, B.M., Sakurai, S., Daley, T.M., Kharaka, Y.K., Holtz, 

M.H., Trautz, R.C., Nance, H.S., Myer, L.R. and Knauss, K.G., 2006, Measuring permanence of CO2

storage in saline formations: the Frio experiment. Environmental Geosciences, v. 13(2), p. 105-121. 

IEA, 2005, IEA GHG Weyburn CO2 Monitoring and Storage Project. IEA Greenhouse Gas R&D Programme. 

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Kharaka, Y.K., Cole, D.R., Hovorka, S.D., Gunter, W.D., Knauss, K.G. and Freifeld, B.M., 2006, Gas-waterrock interactions in Frio Formation following CO2 injection: implications for the storage of greenhouse 

gases in sedimentary basins. Geology, v. 34 (7), p. 577-580. 

Kharaka, Y.K., Thordsen, J.J., Kakouros, E. and Herkelrath, W.N, 2005, Impacts of petroleum production on 

ground and surface waters: results from the Osage-Skiatook petroleum environmental research A site, Osage 

county, Oklahoma. Environmental Geoscience, v. 12, p. 127-138. 

Knauss, K.G., Johnson, J.W. and Kharaka, Y.K., 2005, Preliminary Reactive Transport Modeling and 

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/preliminary.pdf. 

McGowan, J.H., Granata, G.E. and Seni, S.J., 1979, Depositional framework of the Lower Dockum Group 

(Triassic) Texas Panhandle: The University of Texas at Austin, Bureau of Economic Geology Report of 

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CO2 storage in geological formations: a brief review, in Baines, S., and Worden, R., eds., Geological 

Society Special Publications No. 233, p. 87-106. 
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27

Appendix A. 

Federal Requirements under the Underground Injection Control (UIC) 

Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, 

Fall 2008 Proposed Rule 

From the EPA website for public comments: EPA is proposing Federal requirements under 

the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO2) for 

the purpose of geologic sequestration (GS). GS is one of a portfolio of options that could be 

deployed to reduce CO2 emissions to the atmosphere and help to mitigate climate change. 

This proposal applies to owners or operators of wells that will be used to inject CO2 into the 

subsurface for the purpose of long-term storage. It proposes a new class of well and minimum 

technical criteria for geologic site characterization, fluid movement, area of review (AoR) and 

corrective action, well construction, operation, mechanical integrity testing, monitoring, well 

plugging, post injection site care, and site closure for protecting underground sources of 

drinking water (USDWs). Elements of this proposal are based on the existing Underground 

Injection Control (UIC) regulatory framework, with modifications to address the uniqueness 

of CO2 injection for GS. If finalized, this proposal would help ensure consistency in 

permitting underground injection of CO2 at GS operations across the U.S. and provide 

requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to 

reduce CO2 emissions

Summary of Proposed Rule: EPA proposes amending the Safe Drinking Water Act (SDWA) 

by using its authority through the Underground Injection Control (UIC) program to regulate 

geologic sequestration (GS) of carbon dioxide (CO2). It plans to do so by establishing Class 

VI wells. Class VI GS well rules contain minimum requirements to protect underground 

sources of drinking water (USDW), including: 

• geologic site characterization; 

• monitoring of fluid movement; 

• area of review (AoR) and corrective action; 

• well construction, operation, mechanical integrity testing (MIT), monitoring, 

and plugging; and 

• post injection site care and closure. 

Definition of USDW in rule: 

An aquifer or portion of an aquifer that supplies any public water system or that 

contains a sufficient quantity of groundwater to supply a public water system, and 

currently supplies drinking water for human consumption, or that contains fewer than 

10,000 mg/l total dissolved solids and is not an exempted aquifer. 

The main concerns expressed in rule regarding groundwater are (1) mitigating movement of 

fluids containing mobilized contaminants from appropriate CO2 receiving formations into 

USDWs and (2) the fact that injection may force naturally occurring brine from an 

appropriate CO2 receiving formation into USDWs. 

 
28

SACROC groundwater study results are pertinent to the following sections of the rule. 

Section II. What is EPA proposing? 

Subpart D. What are the risks associated with CO2 GS? 

An improperly managed GS site has potential to endanger USDWs. 

Risks can include: 

(1) leaching and mobilization of contaminants (e.g., arsenic (As), lead 

(Pb), and organic compounds), 

(2) changes in regional groundwater flow, and 

(3) movement of saltier appropriate CO2 receiving formation fluids 

into USDWs, causing degradation of water quality. 

Subpart J. Is injected CO2 considered a hazardous waste under CERCLA? 

CO2 is not a hazardous waste if it is a pure stream, but impure streams 

may contain mercury (Hg). Also, CO2 could react with groundwater 

(brine or freshwater unspecified) to produce sulfuric acid (H2SO4). 

Section III. Proposed Regulatory Alternative 

Subpart A. Proposed Alternative 

6. Proposed plume and pressure front monitoring requirements 

Monitoring temperature, pH, salinity, heavy metals, and stable 

isotopes (carbon and oxygen) via designate monitoring wells 

are proposed. This section is ambiguous because although 

monitoring wells completed in the confining layer between 

appropriate CO2 receiving formation (aka injection zone) and 

USDW are specifically mentioned, the freshwater zone is also 

referenced. 

8. Proposed well plugging, post-injection, site care, and site closure 

requirements 

The only pertinent point here is the 50-year time frame for post 

injection monitoring, or time frame to be determined by 

Director of EPA. 
Letter ID: 0379  

Commenter: Rebecca C. Smyth  

Organization: University of Texas at Austin, Bureau of Economic Geology, Jackson School of Geosciences,

Gulf Coast Carbon Center  

Letter ID: 0379 Comment ID: 28184 Letter Lines: 17 to 35  

Comment Code: 2400 2.4. Other Research Offered by Commenters (seeking comment)  

Comment: Over 3 trillion standard cubic feet (TCF) or 150 million metric tons of  

CO2 have been injected for enhanced oil recovery (EOR) at the SACROC oilfield in  

west Texas since 1972. Roughly half of the injected CO2 has been produced and  

reinjected as part of a recycling effort; an estimated 35 million tons is  

permanently sequestered in the subsurface at SACROC. Clearly this is a large  

scale CO2 injection site. As with the other four CO2 injection sites referenced  

in Section II of this Notice, there has been no documented leakage of CO2 at  

SACROC.  

The attached document is a status report submitted to EPA Region 6 offices in  

Dallas, TX in April 2009. This report summarizes DOE/NETL‐funded, through the  

Southwest Regional Carbon Sequestration Partnership (SWP), research at SACROC.  

Objectives of the combined research efforts of the Bureau of Economic Geology,  

Los Alamos National Laboratory, New Mexico Tech, University of Pittsburgh, and  

University of Utah are to (1) assess potential impacts to the shallow subsurface  

over SACROC, (2) model the fate of CO2 injected into the subsurface at SACROC,  

and (3) use geophysical methods to image the ~35 million tons of CO2 assumed to  

be trapped in the subsurface.  

Please refer to the PDF or see further down below for the text of the attachment.  

Individual Response: EPA has reviewed the status report on the SACROC project. EPA acknowledges the

submittal and will continue to review studies related to the evaluation of actual field results and the

limitations of sampling and analysis, as well as the limitations of modeling. EPA adds that is has been

monitoring the progress at SACROC, among other GS projects. EPA intends to continue to collect data on

GS and to incorporate such data and information as it implements its adaptive approach to the GS

rulemaking to incorporate new research, data, and information about GS. For more information on the

adaptive approach, see the responses to comments on the proposed rule in the rulemaking docket.