CO2 Sequestration in Saline Formation

Deep saline aquifers are reported to have the largest estimated capacity for CO2 sequestration. Knowledge of possible geochemically-induced changes to the porosity and permeability of host CO2 storage sandstone and seal rock will enhance our capability to predict CO2 storage capacity and long-term reservoir behavior. An experimental study of the potential interaction of CO2/brine/rock on saline formations in a static system under CO2 sequestration conditions was conducted. Chemical interactions in the Mount Simon sandstone environment upon exposure to CO2 mixed with brine under sequestration conditions were studied. Samples were exposed to the estimated in-situ reaction conditions for six months. The experimental parameters used were two core samples of Mount Simon sandstone; Illinois Basin model brine; temperature of 85°C, pressure of 23.8 MPa (3,500 psig), and CO2. Micro-CT, CT, XRD, SEM, petrography, and brine, porosity, and permeability analyses were performed before and after the exposure. Preliminary permeability measurements obtained from the sandstone sample showed a significant change after it was exposed to CO2saturated brine for six months. This observation suggests that mineral dissolution and mineral precipitation could occur in the host deposit altering its characteristics for CO2 storage over time.


INTRODUCTION
Concern has been expressed with regard to global climate change and growing atmospheric concentrations of carbon dioxide (DOE, 1999).To decrease the impact of anthropogenic CO 2 on global climate, several strategies are under development that will potentially remove CO 2 from the atmosphere or decrease CO 2 emissions.One such strategy involves the capture of CO 2 from large point sources such as fossil fuel-fired power plants coupled with the longterm storage of CO 2 underground.Carbon dioxide may be sequestered in various geological formations, including depleted oil and gas reservoirs, unmineable coal seams, basalt formations, and deep saline aquifers.Deep saline aquifers have been reported to have the highest estimated CO 2 sequestration capacity.
A recent Intergovernmental Panel on Climate Change (IPCC) report (Pachauri and Reisinger, 2007) has indicated that injection of CO 2 into confined geological formations, given their potentially massive carbon storage capacity and widespread geographic distribution, represents one of the most promising options for mitigating anthropogenically-induced global climate change.The Mount Simon sandstone in the Midwest region of the U.S. is recognized as a promising candidate host reservoir for carbon sequestration.The Mount Simon formation is a deep saline aquifer and is a primary reservoir target for large scale carbon dioxide injection tests due to its proximity to CO 2 sources, favorable depth, thickness, permeability, porosity, and the presence of the overlying Eau Claire Formation as a seal.The Midwest Geological Sequestration Consortium (MGSC) has selected the Mount Simon formation as the reservoir at its major demonstration project (Rodosta et al., 2011;Liu et al., 2011).While the Mount Simon sandstone has ideal reservoir characteristics in some areas, there are significant variations in porosity, permeability, and mineralogy through the deposit.
Numerous studies have been conducted to investigate changes in host rock properties when exposed to CO 2 (Morse and Arvidson, 2002;Jove-Colon et al., 2004;Luquot and Gouze, 2009;Liu et al., 2011).Study indicated that the nature of these changes depend on the rock composition, and the progressive dissolution of CO 2 in the brine that leads to a decrease in pH (Luquot and Gouze, 2009).As a result, the main expected process involves dissolution of carbonates and eventually silicates, depending on the kinetics of the individual reactions (Morse and Arvidson, 2002).Near the injection well, where disequilibrium is maximal, dissolution processes are expected to affect irreversibly the mechanical and hydrodynamic properties of the host rock.Specifically, dissolution leads to an increase in porosity and permeability as well as changes in the mineral reactive surface area.Eventually, the increase of cation concentration produced by carbonate dissolution can supersaturate fluids with respect to carbonate minerals.In this case, precipitation processes are expected leading to the change of porosity and permeability.Luquot and Gouze (2009) conducted CO 2 -enriched fluid flow through a carbonate core sample under in situ sequestration conditions (T = 100°C and P = 12 MPa).Under these conditions, a decrease in permeability and porosity is seen that is linked to precipitation of Mg-rich calcite.They indicated that changes of permeability and porosity in the samples are attributed to dissolution and/or precipitation (Luquot and Gouze, 2009).As a general rule, non-uniform dissolution is expected to occur near the injection well in calcite-rich reservoirs because of the high reactivity of calcite at low pH conditions.Gouze and Luquot (2011) also conducted an X-ray microtomography characterization study of porosity, permeability and reactive surface changes during the dissolution of pure calcite in a brine-CO 2 mixture.It showed that the increase in permeability is due to the decrease of the tortuosity for homogeneous dissolution.Gouze and Luquot (2011) concluded that when massively injecting CO 2 in deep saline aquifers which may contain carbonate minerals, dissolution would occur where these minerals are in contact with the CO 2 -enriched pore water.The dissolution-precipitation of carbonate minerals may affect the permeability.Jove-Colon et al. (2004) studied the permeability, porosity and reactive surface area evolution during dissolution of nonfractured/clay-free Fontainebleau sandstone cores using a flow through percolation reactor.The experiments were performed at 80°C with 0.1 M NaOH solution.The permeability was found to vary depending on where the dissolution occurred: in the pore void or pore throat.Thomas (2010) concluded that calcite will dissolve and gypsum will precipitate during CO 2 sequestration in saline aquifers from his experimental study.Geochemical instability due to injected CO 2 may cause carbonate to dissolve and create secondary porosity and preferential pathways for migration of CO 2 .The gypsum that precipitates may plug the pores and reduce the porosity, permeability and storage capacity of the formation.Liu et al. (2011) conducted a simulation study of CO 2 sequestration in the Mount Simon sandstone using TOUGHREACT.They indicated that a strongly acidified zone (pH 3-5) forms in the areas affected by the injected CO 2 and consequently causes extensive secondary mineral precipitation (calcite, magnesite, ankerite, alunite and anhydrite) and dissolution of feldspars.
In addition, Liu et al. (2011) also showed that in the sandstone, dissolution of CO 2 into the native brine reduces the solution pH to ~3 and extensive mineral dissolution and precipitation occur due to the corrosive nature of CO 2impregnated brine.During the injection period of 100 years, the major chemical reactions are dolomite dissolution and calcite, magnesite, and ankerite precipitation.These carbonate reactions caused a slight increase in porosity (1%).As CO 2 continues to be dissolved into the brine, nearly all Kfeldspar (21.2% by volume) is dissolved near the well bore and is replaced by alunite and anhydrite.The impact on permeability is unknown but likely to be significant.
Thus, the injection of CO 2 into a deep saline aquifer affects porosity since it can cause both mineral dissolution and precipitation in the formation.The change of porosity due to mineral reactions may adversely influence the permeability.This permeability change depends not only on the porosity, but also on the details of the pore space geometry and the distribution of precipitates within the pore space.In collaboration with the Indiana Geology Survey (IGS) and University of Utah, an experimental study was conducted to assess the impacts of injected CO 2 .Core samples from the Mount Simon formation were placed in CO 2 saturated brines at sequestration temperature and pressure for a period of six months.These samples were studied via petrography and SEM to determine the mineralogical, textural, and geochemical changes that resulted from CO 2 exposure.Because the ability to predict how CO 2 will behave in subsurface reservoirs relies on a detailed understanding of the mineralogical, geochemical, and petrophysical properties of reservoir and seal materials on microscopic to macroscopic scales, the knowledge of geochemically-induced changes in the porosity and permeability of the Mount Simon sandstone will enhance our capability to predict CO 2 storage capacity and longterm reservoir behavior.

Core Samples and Brine
Core samples approximately 2.54 cm in diameter × 5.08 cm in length were used.Two sandstone samples were obtained; one from a depth of 1,769.7 m from a well located in Vermillion County, IN and the second from a depth of 2634.2 m from a well located in Knox County, IN.The major mineral composition for the Vermillion sandstone sample is 78% quartz, 15% feldspar with less than 2% microcline and trace minerals.The primary mineral composition of the Knox sandstone sample is 70% quartz, 22% feldspar, and 4% illite/muscovite.In addition, major element analyses were also conducted on the core samples.Results are shown in Table 1.The chemical composition of the synthetic brine (Table 2) was based on the fluid chemistry of Mount Simon brine collected from the Vermillion County well.The initial pH of the synthetic brine was 5.4.

Reactors and Experimental Procedures
A set of 1.3 liter (17-4PH-1150 stainless steel) highpressure vessels (10.2 cm internal diameter × 16.5 cm depth) manufactured by Thar Technologies, Inc. were used for this study.An open Teflon reaction cell (7.62 cm I.D × 10.16 cm length) was used inside the pressure vessel.An ISCO 260D syringe pump was used to charge each vessel with CO 2 and maintained the pressure in the reactor.Temperature was maintained by a Thar CN6 controller and controlled to within 1°C.In a typical experiment, after loading the Teflon container holding the sample (both core and two small sample chips) and brine into the pressure vessel, the gap between the Teflon container and pressure vessel was also filled with brine to insure that the CO 2 phase was saturated with water vapor without substantially altering the salt concentration in contact with the core sample.The pressure vessel was then purged with CO 2 three times to remove residual air.Finally, the vessel was charged with approximately 4.08 MPa (600 psig) of CO 2 and then slowly heated to a final temperature of 85°C.During the heating period of about four hours, CO 2 was slowly added to the vessel until the desired testing pressure of 23.8 MPa was reached.The vessels were maintained at these conditions for 6 months.Upon completion of the experiment, the temperature of the reactor was reduced to room temperature and then the CO 2 was slowly vented and the sample was removed.The solid samples were rinsed with deionized water and dried in desiccator under a constant flow of nitrogen before further analysis.The liquid from both the Teflon container and the vessel humidification solution were retained for analysis.The reacted brine analysis results are listed in Table 2.

Analytical Methods
Micro-CT, CT, XRD, SEM, petrography, porosity, and permeability analyses were conducted before and after the six month exposure experiment.Metal concentrations in the salt solutions were determined using inductively coupled plasma -optical emission spectroscopy (ICP-OES).Due to the high concentration of salt in these solutions, sample dilutions with deionized, distilled water was required.Solutions were analyzed for the full range of metals quantifiable by ICP-OES including Al, Si, and Fe.

Cation and Anion Analyses
Reactants and products were prepared for analysis by filtration through a 0.45 µm membrane filter (type HA, Millipore Corporation -Billerica, MA, USA) facilitated by positive nitrogen gas pressure.The collected solids were rinsed with deionized water on the membrane and dried in a nitrogen-purged oven at 110°C.The filtered solutions were acidified (pH < 2.0) with trace metal grade nitric acid.Due to the high concentration of alkali and alkaline earth metals in the solutions, 200-fold dilutions were prepared using deionized, distilled water.Metal concentrations were then determined by inductively coupled plasma -optical emission spectroscopy (ICP-OES) using a PerkinElmer Optima 3000 ICP spectrometer (PerkinElmer, Inc. -Wellesley, MA, USA).Filtrate solutions were analyzed for Al, Ba, Ca, Fe, K, Mg, Mn, Na, Ni, P, S, Si, and Sr. Analysis for Cl, Br, and SO 4 was performed using a Dionex DX-100 ion chromatograph equipped with a conductivity detector (Dionex, Inc. -Sunnyvale, CA, USA).The columns and suppressor used for this analysis were also obtained from Dionex.Reliability of cation and anion analyses was verified by a calculated charge balance.In general, charge balance analysis revealed relatively good agreement between total equivalents of solution cations and anions.Solid samples were microwave digested in an aqua regia solution to leach extractable metals as described in EPA Method 3051: Microwave Assisted Acid Digestion of Sediments, Sludges, Solis, and Oils.Digestate samples were also analyzed for cation concentrations.

X-ray Diffraction
Powder X-ray diffraction (XRD) analysis of the mineral composition of the solids was carried out using a PANalytical X'Pert PRO multipurpose diffractometer equipped with a Cu anode operated at 45 kV and 40 mA and a divergent beam monochromator.Samples were prepared for analysis by drying at room temperature followed by grinding in an agate mortar and pestle.Phase identification was verified by comparison to the International Centre for Diffraction Data (ICDD) inorganic compound data base.

Scanning Electron Microscopy-energy Dispersive X-ray Analysis
The samples were analyzed using an FEI Company Quanta 600 field emission scanning electron microscope equipped with secondary and backscatter electron detectors and an Oxford Inca Energy 350 X-act energy dispersive x-ray analyzer (EDS) to determine sample morphological changes and investigate the chemistry of observed phases.Dried samples were mounted on conductive tape on carbon planchets and palladium coated for analysis.An accelerating voltage of 5 kV and a working distance of about 10 mm were used to examine the sandstone sample morphologies in low vacuum secondary electron mode.20 and 30 kV accelerating voltages were used for qualitative EDS analysis.

Permeability and Porosity Measurement
An Autolab 1500 unit from New England Research, Inc. implements pressure transient methods for measurements of low and moderate permeability of samples.The central part of the Autolab 1500 apparatus is a high pressure chamber, where confining pressure is created to simulate underground conditions.A porous core sample is secured in a core holder and placed inside the pressure chamber.The sample is isolated from the confining fluid by a bunan or copper foil jacket, and pore pressure is controlled independently of the confining pressure.A pressure transient method was used for permeability measurements.During every individual measurement, the confining pressure was maintained at a constant value to simulate actual field conditions.A pressure pulse was introduced at the upstream side, and the pressure at the downstream side was recorded.Based on the observed downstream pressure pulse, the permeability of the core sample was determined.The details were reported elsewhere (Siriwardane et al., 2009).In addition, a TEMCO Ultraperm-500 "flow-through" permeameter was also used to measure the permeability of the samples.The porosity of the core samples was measured using a helium porosimeter (HP-41, Temco, Inc) at 0.7 MPa and ambient temperature.The initial porosities were 7.9% for the Vermillion County sandstone and 1.4% for the Knox County's sample.

Micro-CT Scanner
Micro-CT scans were acquired using an Xradia Micro-XCT-400 scanner.The top center portion of the Vermillion sandstone piece (approx.11.5-mm, 8-mm wide, and 2-mm thick) was scanned with at 50KeV/6W using a 20X objective with an Xradia LE#5 filter.The resolution was 1.1 µm/pixel with a field-of-view (FOV) of 1.12 mm.The top center portion of the fresh and exposed Knox sandstone core was scanned at 150KeV/10W using a 104 X objective with an Xradia HE#2 filter.The resolution was 2.1 µm/pixel with a field-of-view (FOV) of 2.08 mm.The raw scan data was processed and exported as sequential 2-D slices normal to the cylindrical FOV length.Pixel spacing is equal to slice spacing, so when data is reconstructed, there are voxels with three equal length sides.Pore space was analyzed by using the 3D object counter plugin for Fiji-ImageJ (Bolte and Cordelieres, 2006).Porosity is first identified by grayscale thresholding, and then the process compares each pixel to the twenty-six adjacent pixels, grouping pore-class pixels together.Statistics calculated from these pore groups include pore volume, surface area, and aspect ratio.Local thickness was computed on images to determine compliant porosity.This image-processing tool allows high aspect ratio areas of a given pore to be recognized by rating pixels based on minimum distance to pore walls.

RESULTS AND DISCUSSION
The chip sandstone samples were examined by SEM-EDS prior to reaction to examine overall morphology and mineralogy.Fig. 1 shows SEM images of two locations on the Vermillion County sample at different scales.This sandstone consists primarily of quartz grains showing evidence of recrystallization; indicated by faceting on the grains.Minor amounts of feldspar having an etched appearance and clay particles were also observed.The sandstone had visible large pores and channels between the grains.Fig. 2 shows SEM images of two locations on the Knox County sample at different scales.This sandstone also consists primarily of quartz grains although very little regrowth was visible.The Knox County sandstone had a much higher content of non-quartz minerals, primarily feldspars, and appeared to have fewer pores between the grains.These observations correlate well with the permeability values and other results discussed in the following sections.
After removing the core samples from the reactors they were rinsed with deionized water and dried in a desiccator under a constant flow of nitrogen.During the drying period, the porosity and permeability of the sample were periodically measured.Fig. 3 shows that the permeability of the Mount Simon Vermillion County sandstone changed slightly during the drying process.The permeability was measured under a confining pressure of 42 MPa and pore pressure of 17 MPa.The sample was held for several hours under continuous nitrogen "flow through" at the rates of about 0.1-0.2mL/sec.The permeability of the sandstone core after the six month exposure to CO 2 and brine was 0.85 mD compared to 1.6 mD for the fresh sample.The equilibrium permeability was significantly lower after six months exposure to the brine-CO 2 environment.This result suggests that the CO 2 /brine exposure altered the pore characteristics restricting flow resulting in permeability reduction.
The samples were also characterized in detail using the    (Smith et al., 2013).Several studies have correlated bulk flow rates with dissolution regimes.Generally, slower flow rates favoring more strongly localized dissolution morphologies and increasing flow rates creating highly branching channels (Smith et al., 2013).The post-reaction brine was analyzed following contact with the Vermillion sandstone and CO 2 (Table 2).Comparing the reacted brine with the fresh brine, the following trends were observed.The concentration of Al, Ca, Fe, K, Mg, Na, and Si increased after the six months exposure period.Solution chemistry indicated that CO 2 -acidified brine may preferentially dissolved feldspar (KAlSi 3 O 8 , NaAlSi 3 O 8 and CaAl 2 Si 2 O 8 as examples) and to a small extent, quartz.In addition, a decrease in the concentration of Ba and sulfate in the reacted brine was noted (Table 2).The amount of CO 2 dissolved in the brine in-situ was not measured, however it can be estimated via Duan and Sun model (Duan and Sun, 2003).
Figs. 5(a) and 5(b) show the backscattered SEM images of the Vermillion sandstone sample.In the upper left corner of the before and after images (circled) evidence of possible mineral dissolution is observed after the six months exposure to CO 2 /brine.Feldspar dissolution and other factors might contribute to an increase in bulk permeability through the formation of a localized channel, however the precipitation of secondary minerals may also block channels.Secondary mineral precipitation was also observed after the six month exposure.Barite deposition was observed (EDS) on the sample surface after the six month exposure.This may suggest the dissolution of barium-containing minerals such as barium-containing feldspars (BaAl 2 Si 2 O 8 , (K,Na,Ba)(Al,Si) 4 O 8 as examples) within the sandstone as well as the Ba from the synthetic brine and subsequent reprecipitation of barite (BaSO 4 ) on the surface.No direct evidence of Ba-feldspar in the starting sample was observed: however, Ba substitutes easily into the feldspar lattice.In addition, kaolinite precipitation has also been reported in the literature (Smith et al., 2013).When CO 2 is injected into a saline formation, acidic conditions form in the brine in the reservoir reducing the pH of the brine in the system, and minor minerals in the sandstone such as K-feldspar, calcite, microcline etc. that are stable in the native environment but not stable at lower pH can dissolve.Eventually, the increase of cation concentration produced by mineral dissolution can supersaturate the fluids with respect to other minerals.If this occurs, precipitation of new minerals such as the barite seen here and other secondary minerals can result in a decrease in porosity and permeability which could affect both CO 2 storage capacity and fluid movement.In addition to barite, small amounts of other minerals such as carbonates could also have precipitated but in amounts below the detection limits of the techniques used here.Core permeability decreased substantially during the experiment although core porosity remained almost unchanged.The permeability reduction is probably the result of precipitation of new mineral phases like barite.Dissolution of feldspars can result in precipitation of secondary mineral clays.In a host reservoir, the secondary clay particles may be mobile and could be transported in the fluid flow path and accumulate at pore throats.The issue is further complicated by the evolution of pore geometry due to these geochemical reactions which may affect the overall hydrologic properties of the host rock and, therefore, the performance of the unit as an effective reservoir.The Knox County sample changes were characterized by the same techniques.The porosity was 1.4%.The permeability was measured using the Autolab-1500 unit.In situ conditions (2634.2 m depth below surface) imply approximately the following values for confining and pore pressures: cp ≈ 62.6 MPa and pp ≈ 25.8 MPa.The permeability was measured at three lower combinations of cp and pp for extrapolation to pp = 25.8MPa.Fig. 6 shows the permeability as a function of different effective pressures.In general, permeability of the sample after six months exposure to CO 2 /brine exceeds the permeability obtained from the fresh sample.Mineral dissolution could increase the average size of pore throats which could lead to increased permeability.
Micro CT scanning was also used to probe the sample obtained from Knox County, IN. before and after six months exposure to the CO 2 /brine environment (Figs.show the side view of the same sample.In this case, a 30 to 50 µm layer of material appears to have been deposited on the external surface of the sample.The precipitation might be due to the low porosity of the sample, thus the precipitation only occurred on the external surfaces of the sample not in internal pores.The dissolution of minerals in the crack may result in the slight increase of permeability after the interaction between CO 2 /brine as observed via permeability measurement.Micro CT imaging showed that CO 2 -induced dissolution proceeded in localized regions resulting in a preferential dissolved channel. We also conducted analysis of the reacted brine following reaction with the Knox County sandstone and CO 2 (Table 2).Comparing the reacted brine with the synthetic brine, the concentration of Al, Ca, Fe, K, Mg, Na, and Si were increased after the six month exposure of Knox County sandstone with CO 2 .The release of Ca, Fe, K, Mg and Si might be attributed to the dissolution of feldspar and to a smaller extent, quartz.Feldspar dissolution could have contributed to increase in bulk permeability through the formation of a localized channel.In addition, a decrease in the concentration of Ba and sulfate in the reacted brine was observed.The main factor leading to these geochemical reactions is the dissolution of CO 2 in water which causes a decrease in the pH of the brine and leads to acid attack of the susceptible minerals.Dissolution of feldspar is commonly reported in CO 2 -exposure experiments (Yu et al., 2012).The Knox County sandstone sample contained approximately 22% feldspars, and the release of Na, Al and K and removal of Ba and sulfate can be linked to the dissolution of feldspar.As described above for the Vermillion sandstone, dissolution of barium-containing feldspars within the sandstone as well as the Ba from the synthetic brine could account for the secondary precipitation of barite (BaSO 4 ) on the external surface.Figs.9(a) and 9(b) show the SEM images of the sample before and after the six month exposure to CO 2 /brine.In those circled areas, mineral dissolution as well as mineral precipitation in the exposed samples is clearly evident.Barite and NaCl were observed on the external surfaces of the exposed sample.A chip was removed from the sample allowing analysis to expose a portion of internal surface (Fig. 10(a)).Barite was not detectable on the freshly chipped surface (Fig. 10(b)), only on the external surface (Fig. 10(c)) which suggests that the precipitation was occurring primarily on the exterior of the sample core.
It has been reported that after injection of CO 2 into depleted oil and gas reservoirs, the initial chemical equilibrium between the saline formation fluid and reservoir rock may be disturbed and trigger new chemical reaction (Fischer et al., 2010).Such interactions might ultimately lead to changes in the physical and chemical properties of the reservoir system (Wigand et al., 2008;Fischer et al., 2010).Reservoir permeability could be particularly susceptible to these interactions.A decrease in permeability resulting from these interactions could have a serious impact on the long-term CO 2 storage capacity ( Van der Meer et al., 1993).As also indicated by Rempel (2011), the injection of CO 2 into an aquifer would lead to chemical interactions in the CO 2 -brine-reservoir rock system which may in turn result in the dissolution, mobilization and re-precipitation of of the brine to leach metals from the reservoir rocks.Rempel et al. (2011) reported that CO 2 at equilibrium with brine at P-T conditions relevant to CO 2 storage reservoirs is capable of dissolving and mobilizing measureable quantities of Fe, Cu, Zn and Na.
Combined information from scanning electron microscopy (SEM), X-ray diffraction (XRD), CT scanning, and brine analysis indicate dissolution of minerals, mostly likely feldspar, in flow pathways along with precipitation of barite on the external surfaces of the Knox County sandstone sample.Gouze and Luquot (2011) have shown that increase of permeability is due to the decrease of the tortuosity for homogeneous dissolution, whereas it is due to the combination of tortuosity decrease and hydraulic radius increase for heterogeneous dissolution.Since the sandstone sample from Knox County has very low porosity, mineral precipitation primarily occurs on the external surfaces.For the sandstone sample from Vermillion Country, mineral dissolution, most likely feldspar, and secondary mineral precipitation in flow pathways had the net effect of decreasing permeability.

CONCLUSION
The potential interaction of CO 2 /brine/rock in saline formations was investigated using a static system under CO 2 sequestration conditions.Chemical interactions in the Mount Simon sandstone environment upon exposure to CO 2 mixed with brine under sequestration conditions were studied over a six month exposure period.Micro-CT, CT, XRD, SEM, petrography, brine composition, porosity, and permeability analyses were performed before and after the exposure to CO 2 saturated brine under sequestration conditions.
The 50% decrease in permeability found in the Vermillion County sandstone after it was exposed to CO 2 saturated brine for six months was probably due to feldspar dissolution, migration and secondary mineral precipitation altering the sandstone pore/crack structure.For the case of the sample from Knox County, the increasing permeability may be linked to mineral dissolution (most likely feldspar) in the pathway.Mineral precipitation occurred primarily on the external surfaces of this sample.During CO 2 storage in geologic formations, it is expected that supercritical CO 2 will dissolve into the formation's brine.The CO 2 -charged brine then becomes acidic and can react with minerals in the host deposit leading to dissolution, transport and reprecipitation which could affect the permeability.Investigations are continuing to more clearly elucidate the mechanisms and geochemistry of this system, especially at the pore structure scale.

DISCLAIMER
This report was prepared as an account of work sponsored by an agency of the United States Government.Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights.Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof.The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

Fig. 1 .
Fig. 1.The SEM images of fresh sandstone obtained from Vermillion County, IN.

Fig. 2 .
Fig. 2. The SEM images of fresh sandstone obtained from Knox County, IN.

Fig. 4 .
Fig. 4. Reconstructed slice (side view) from Micro-CT analysis of the Vermillion sandstone sample before (a) and after six months exposure to CO 2 /brine (b).Top circled areas highlight mineral precipitation.Lower circled areas highlight mineral dissolution.The numbers represent measurements in microns both of features and reference points.

Fig. 5 .
Fig. 5. SEM images of Vermillion sand stone samples fresh (a) vs. exposed to CO 2 /brine for six months (b).

Fig. 6 .
Fig. 6.The measured permeability of Knox sandstone.Note that extrapolated values of permeability are shown in bold.The extrapolated values denoted by hollow markers.

Fig. 7 .
Fig. 7. Reconstructed slice (top view) from Micro-CT analysis of the Knox sandstone sample before (a) and after six months exposure to CO 2 /brine (b).Arrows point to an area where some mineral dissolution occurred after exposure to CO 2 /brine.The numbers represent measurements in microns both of features and reference points.

Fig. 8 .
Fig. 8. Reconstructed slice (side view) from Micro-CT analysis of the Knox sandstone sample before (a) and after six months exposure to CO 2 /brine (b).Arrows point to one of several measurements that show mineral deposition on sample top surface.The numbers represent measurements in microns both of features and reference points.

Fig. 9 .
Fig. 9. SEM images of Knox sand stone samples fresh (a) vs. exposed to CO 2 /brine for six months (b).

Fig. 10 .
Fig. 10.SEM images of the CO 2 /brine exposed Knox sand stone sample with a small piece chipped from the surface (10(a)), freshly chipped surface at 500X magnification (10(b)) vs. the external surface (also 500X) showing barite precipitation after exposure to CO 2 /brine for six months (10(c)).

Table 1 .
Major and minor element analysis of Vermillion and Knox sandstone samples.

Table 2 .
The analysis of synthetic brine and the brine interacted with CO 2 /sandstone for six months under CO 2 sequestration conditions.