Impacts of Geochemical Reactions on Geologic Carbon

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Impacts of Geochemical Reactions on Geologic Carbon Sequestration Young-Shin Jun,†,* Daniel E. Giammar,† and Charles J. Werth‡ †

Department of Energy, Environmental and Chemical Engineering, Washington University in St. Louis, St. Louis, Missouri 63130, United States ‡ Department of Civil and Environmental Engineering, University of Illinois at Urbana−Champaign, Urbana, Illinois 61801, United States dissolve in the brine (solubility trapping).3 Mineral trapping occurs when carbonate minerals precipitate from the reaction of dissolved CO2 and aquifer minerals or dissolved solids.4−6 Geochemical reaction rates affect trapping mechanisms and vary considerably. These reaction processes can occur soon after injection and over time scales of hundreds or thousands of years.1,7−11 Dissolution of CO2 into brine can vary as a function of temperature, pressure, brine composition, and injected fluid composition.3 Dissolution of pre-existing rocks and precipitation of new aluminosilicates,7,9 carbonate minerals,12 halite,12 and sulfates5 can also occur soon after injection.13 These dissolution and precipitation reactions can change the porosity, permeability, and wettability of the reservoirs, altering the In the face of increasing energy demands, geologic CO2 transport pathways of the injected CO2.9 In addition, sequestration (GCS) is a promising option to mitigate the adverse effects of climate change. To ensure the environmental geochemical reactions can affect the integrity of caprocks and sustainability of this option, we must understand the rates and wellbores (Figure 1), and should CO2 leakage occur, they can mechanisms of key geochemical reactions and their impacts on govern the environmental impacts on shallow groundwater.12 GCS performance, the multiphase reactive transport of CO2, Therefore, it is imperative to advance our understanding of and the management of environmental risks. Strong intergeochemical reaction kinetics and mechanisms and their linkage disciplinary collaborations are required to minimize environto changes in physical properties of reservoirs at GCS sites. mental impacts and optimize the performance of GCS There are pilot-scale and full-scale CO2 sequestration sites operations. currently operating around the world.1 Most of these sites have some geophysical (e.g., seismic) characterization of the fate of INTRODUCTION the injected CO2, but only a few have full geochemical data to Geologic CO2 sequestration (GCS) is a promising option for monitor postinjection processes. The nature and extent of stemming the increase in atmospheric CO2 and allaying the geochemical reactions has been observed to vary based on siteassociated impacts on global climate change. Methods of GCS specific conditions. For example, at the Weyburn CO2-EOR site include direct injection into nearly depleted oil and gas (Saskatchewan, Canada), the Frio-pilot test site (Texas), and reservoirs, unmineable coal seams, and deep saline aquifers. the Nagaoka pilot test (Japan), the aqueous concentrations of Geologic CO2 sequestration is also possible when combined Ca, Mg, Fe, Mn, and HCO3− in brine increased after CO2 with enhanced oil recovery (EOR) and enhanced coalbed injection. These increases resulted from dissolution of methane recovery, and this method may be financially carbonate minerals and some silicate minerals, which was advantageous.1 Among these GCS methods, deep saline induced by the decrease in pH caused by CO2 injection and aquifers are estimated to have the greatest capacity for carbon 13−15 1 3 4 In contrast, mineral CO storage and sequestration (10 −10 gigatons of CO2). 2 dissolution into the brine. reactions in the reservoir were minor, and the brine Geologic CO2 sequestration relies on multiple trapping composition remained almost unchanged at the Cranfield mechanisms. During injection, a pressure gradient causes CO2 to migrate through porous media away from the injection well CO2-EOR and sequestration site (Mississippi) during CO2 and to move upward due to buoyant forces. Slow transport of injection. The limited geochemical reactions at the Cranfield CO2 over long distances during migration leads to hydrosite are associated with the reservoir rocks being composed of dynamic trapping.1 Upward CO2 migration is typically hindered less reactive minerals (e.g., quartz, chlorite, kaolinite, and Illite) by low permeability caprocks, and this results in structural or and not having significant amounts of the reactive minerals stratigraphic trapping.1 Injected supercritical CO2 (scCO2) (e.g., carbonates and feldspars) present at other sites.16 moves through the porous rock and displaces brine. As the CO2 continues to move, brine will again replace it, leaving some CO2 Special Issue: Carbon Sequestration trapped in the pore spaces by capillary forces.2 This is residual Published: November 6, 2012 trapping. When CO2 contacts brine in the reservoir, it will

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response (by releasing cations such as Ca2+, Mg2+, or Fe2+ and buffering pH changes)13 and affect flow properties (by porosity and permeability increases)21 in GCS sites. Feldspar and clay mineral dissolution kinetics are slower (10−10.4 −10 −11.2 mol·m−2·sec−1),20 but reactions with these minerals can yield leached layers and secondary mineral phases such as amorphous silica, kaolinite, or illite within a very short time (hours to days).7,9,11 Iron and magnesium-rich minerals like olivine, which are present in peridotite and basalt, are also very reactive and are important for promoting both in situ and ex situ metal carbonation.4,18 Geochemical reactions can create new reactive surfaces by dissolution and precipitation, resulting in a reservoir with evolving reactivity, including evolving wettability with respect to supercritical CO2 and brine. Changes in mineral wettability affect capillary pressures, and subsequently CO2 migration and storage.9,22 A better understanding of mineral dissolution and precipitation mechanisms and kinetics leads to a better understanding of the corresponding effects on reservoir wettability and permeability. This, in turn, can improve the prediction of CO2 fate and transport in reservoirs and caprocks, increase the potential of engineered systems to enhance carbonate precipitation, and elucidate the impacts of precipitation-dissolution reactions on creating or mitigating risks of leakage. Multiple environmental factors affect geochemical reactions in GCS sites. Reaction rates generally increase with temperature and pressure, and these parameters at GCS sites vary greatly with injection depth. Marini’s gradients give good estimates of temperature (33 °C km−1) and pressure (99 atm/km) variation with depth, 23 and observations at field sites range from 31 to 128 °C for temperature and from 72.8 to 592 atm for pressure.2,6,12 The salinity of formation fluids varies from several mg/L to several hundred g/L.10 Higher ionic strength can increase mineral dissolution rates10 and alter reservoir wettability.24 In addition to the field site conditions, the geochemistry of the storage zone can be influenced by impurity gases (e.g., H2S, SOx, NOx, and O2). For example, at the Weyburn CO2 injection project, the injected gas contains approximately 2% H2S.1 If impurity gases are coinjected with CO2, to reduce gas treatment costs,3 they can dissolve into brine and affect the pH and oxidation−reduction potential of the brine.3,12 Furthermore, injected scCO2 can trigger the mobilization of organic compounds present in the aquifer into the formation waters. The organic compounds can change the rates and extents of dissolution−precipitation reactions as well as the wettability of the rocks.11 Therefore, it is important to identify and understand crucial environmental factors. Microbial communities at GCS sites can also play an important role in geochemical reactions by mediating surface reactions, providing exopolysaccharides, and affecting redox reactions (Figure 1).25 Fe(III) reducing microorganisms have been found to reduce Fe(III)-bearing oxides more effectively when the pH is lowered by CO2 injection. Such microbial activity can help raise the pH of the brine and then lead to the precipitation of carbonates.25 Data from a pilot-scale CO2 storage project in a saline aquifer (near Ketzin, Germany) suggest that scCO2 injection may induce shifts in the composition of the microbial community and the dominant metabolic processes by changing the pH, pressure, temperature, salinity, and other abiotic characteristics of the aquifer.26 It is evident that reactions between microorganisms and formation rocks (or caprock) can affect the structure and chemical composition of the rock formations, and cause corrosion at the

Figure 1. Important geochemical reactions under GCS conditions at different distances from the injection well. (1) Supercritical CO2 dissolution into brine, (2) acidified brine induced reactions, (3) wet scCO2 driven interactions, and (4) scCO2-wellbore interactions can occur to a variety of extents, depending on environmental parameters such as mineralogy, pressure, temperature, and salinity. Impurity gases in the injected fluids, organic compounds in pre-existing reservoirs, and microorganisms can affect these processes. In Interactions 2 and 3, newly formed nanoparticles and surface layers can clog pore throats and change the wettability of rocks, respectively. The heterogeneous mineralogy image (bottom left) is courtesy of Drs. Carl I. Steefel and Gautier Landrot. Gray, red, yellow, blue regimes in SEM-backscattered electron microscopy (BSE) correspond to quartz, Illite, kaolinite, and chlorite. The top left image is an AFM image of a phlogopite surface reacted under water-containing CO2-dominant conditions (Interaction 3). Dissolution pits and surface layers formed at the bottom of the pits.10.

Here we highlight scientific information about geochemical reactions that can impact physical processes during GCS. Specifically, we discuss key geochemical reactions in CO2 storage reservoirs and their impacts on multiphase reactive transport, and environmental risk. We also identify future research directions and enabling technologies and methods that can further develop the scientific basis for GCS operations and long-term management. Understanding Geochemical Reactions at GCS Sites. Key geochemical reactions during GCS are dissolution of injected scCO2 into brine, dissolution of pre-existing formation rocks and caprock, precipitation of secondary mineral phases, and surface reactions that affect wettability of rocks (Figure 1). When scCO2 dissolves into brine, the scCO2 solubility increases nonlinearly with increasing temperature and pressure, and decreases with increasing salt content.3,17 Impurities in injected CO2 (e.g., H2S or SO2) increase the complexity of predicting the solubility of CO2 in brine.3 Hence, nonideal equations of state are required to predict CO2 fugacity and aqueous solubility. The dissolution and precipitation of formation rock and caprock (Figure 1) are functions of their composition; they primarily consist of silicate and aluminosilicate,11 carbonate, and clay minerals.4,8,18 After CO2 injection, the pH variations at GCS sites are a function of both the distance from the injection wells and the time after injection. Near the injection well, the pH will be in the range of 3−6.5,19 At this pH, carbonates have much higher dissolution rates (a range of 10−4.5−10−7.5 mol·m−2·sec−1) than other minerals.20 Carbonate dissolution is important because it can dominate the aqueous chemical 4

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Figure 2. Multiscale spatiotemporal nature of CO2 storage. A: Nano Scale information: (left) Al-substituted goethite precipitation at biotite edge sample;7 (middle) biotite cracking and illite formation;8 (right) molecular simulation of scCO2 dissolution into liquid water.47 B: Pore Scale information: (left) wettability changes in the presence of scCO2;22 (middle) heterogeneity of mineralogy and pore structure in sandstones collected from a carbon sequestration pilot site in Cranfield, Mississippi. Gray, red, yellow, blue regimes in the SEM-BSE image correspond to quartz, illite/ mica, kaolinite, and chlorite. The image is courtesy of Drs. Carl I. Steefel and Gautier Landrot. (right) Numerical simulation of pore-scale reactive transport of calcium concentration for a large 3-D domain.48 C: Reservoir Scale information: (left) Core flooding experiments through cement fracture;31 (right) reactive transport modeling result of CO2 saturation in a cross section from the Illinois basin injection site.49 All images used with copyright permission from the American Chemical Society, Elsevier, and the American Geophysical Union. The figure structure is based on the concept presented in ref 2.

casing and the casing cement around the well.26 While only limited sampling opportunities and studies have been available for characterizing the response of subsurface microbial communities to CO2 injection, future GCS research, especially method development and sampling at field sites, can advance our understanding of the impacts of coupling of abiotic and biotic processes on GCS performance and environmental risk. Impacts of Geochemical Reaction on Multiphase Reactive Transport of CO2. The suite of reactions that occurs during GCS is highly dependent on fluid transport processes that control the rates of reactant delivery through advection and diffusion. For reactions that are fast relative to transport, one can assume local equilibrium. For reactions that are similar to or slower than transport, concentrations of CO2 and other reactive species change over time, and this must be considered to determine overall reaction rates. Heterogeneity complicates transport, as preferential flow and diffusion lead to greater variability in transport time scales and to variability in the spatial distribution of CO2 and associated reactants. Reactive transport processes of primary interest during GCS include multiphase flow of brine and CO2,27 convective mixing and dissolution of scCO2 into brine,28 and transport of supercritical and aqueous phase CO2 coupled with mineral reactions.21 A crucial milestone in GCS research is determining the temporal and spatial scales of transport and reaction (Figure 2). Multiphase flow behavior affects formation sweep efficiency27 and CO2 leakage through caprock and wellbores.12 Sweep efficiency is a measure of the effectiveness of transport processes in maximizing the reservoir volume contacted by the injected scCO2. During injection, the leading edge of the scCO2 plume is unstable because scCO2 is less viscous than brine. At low scCO2 injection velocities in water-wetted porous media, capillary forces dominate flow, and scCO2 preferentially

enters larger pores.27,29 At high injection velocities, viscous forces become important, and scCO2 advances as relatively uniform, evenly spaced fingers through pores of variable size. Supercritical CO2 can also migrate through fractures and faults in caprock and wellbores. For relatively narrow fractures and faults, scCO2 migration can promote upward brine migration, with the possibility of contaminating shallow aquifers.30 Better characterization of faults, fractures, permeability, and wettability variations is critical for predicting multiphase flow. Transport processes of injected CO2 control the rate of CO2 dissolution into brine.29 At the leading edge of the scCO2 plume and at the scCO2−caprock interface, diffusion controls the rate of CO2 transport away from the scCO2−water interface, and dissolution is slow. However, at the lower boundary of the scCO2 plume trapped by caprock, CO2 dissolves into brine, increases its density, and promotes unstable gravity fingering that leads to convective mixing and enhanced CO2 dissolution.28 The time to the onset of gravity fingering is affected by dispersion, which can be enhanced by varying injection rates over time. Determining the critical time for the onset of convective mixing, and the length scales over which mixing occurs, is required for accurate prediction of GCS performance.28 Transport of supercritical and aqueous phase CO2 is closely coupled with dissolution and precipitation reactions in storage reservoir, caprock, and wellbore materials. During CO2 injection, scCO2 dissolves into brine and can promote mineral dissolution, thereby increasing reservoir permeability.21 If mineral dissolution occurs in caprock or wellbore cement, increasing permeability may promote leakage. Mineral dissolution can be enhanced in pores with small amounts of water within scCO2-dominant regimes, for example, close to injection wells and in caprocks (Interactions 3 and 4 in Figure 1).12 As noted in the previous section, secondary mineral precipitation 5

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profiles of risk versus time through an approach that can be customized to specific sites. Information on chemical reactions is integral to the NRAP’s technical focus on the areas of wellbore integrity, natural seal integrity, and groundwater protection.39 In addition, to prevent endangering underground sources of drinking water, the U.S. Environmental Protection Agency recently established a class of wells, Class VI, for GCS in the Underground Injection Control regulations.40 Research Needs on the Role of Geochemical Reactions on GCS Development. The widespread application of GCS has been limited by the lack of a regulatory framework and uncertainty regarding costs and CO2 leakage. These uncertainties can, in turn, hinder the development of a regulatory framework. To improve predictions of the fate of CO2 injected during GCS and to better understand the impacts of geochemical reactions on long-term storage, transport, and environmental risk, future research is needed in three critical areas discussed below. The improved scientific and technical understanding can allow more accurate estimates of cost and identification of paths toward cost and environmental risk reductions related to CO2 leakage. First, better subsurface characterization, especially characterization of preferential flow paths and reactive surface areas, is needed. Preferential flow paths, both in reservoirs and along leakage pathways, can depend on pore size distribution and wettability, larger scale permeability variations, and the presence of faults and fractures. Reactive surface area depends on the distribution of minerals and their surface area available for reaction with CO2 and other aqueous constituents. Geophysical methods have allowed for unprecedented characterization of the stratigraphy, permeability, and CO2 saturation conditions in reservoir materials. Core characterization and reaction experiments have resolved micrometer scale variations in mineral distribution and reactive surface area.21 Future research is needed to improve the resolution of field scale geophysical methods and to correlate core and fieldscale features. A second area is bridging the large spatial and temporal scales of CO2 transport and geochemical reactions (Figure 2). Transport processes of interest occur at the pore and reservoir scale on time scales of days to many decades. Geochemical reactions of interest occur at the nanoscale on time scales that range from essentially instantaneous to geologic. Upscaling is challenging, both because scales of transport and reaction are often poorly understood, and because computational methods that bridge molecular, pore, and reservoir scales are lacking. Research is needed to address these challenges and to determine when assumptions can be made to simplify or ignore processes occurring on very different spatial or temporal scales. A third area is achieving a better mechanistic understanding of key processes important to GCS, especially multiphase flow and mineral reaction kinetics. Challenges in multiphase flow include accurately representing the behavior at fluid−fluid interfaces and representing the physiochemical properties of complex mixtures. The former is being addressed by new thermodynamic theories,41 the latter by improved equations of state.3 A challenge in mineral reaction kinetics is predicting precipitation and dissolution rates under reservoir conditions. This is important in CO2 storage reservoirs, in caprocks and well seals that protect against leakage, and in CO2-impacted groundwater when leakage occurs. Another need is understanding how nanoscale surface features, which can be

is also possible during CO2 injection, and is expected to occur in brine where cation concentrations and buffering capacity are high.31 When newly formed precipitates (amorphous silica, clay minerals, halite, and carbonate) are located close to pore throats (Figure 1),9 the permeability can be significantly decreased while the porosity remains fairly constant. Impacts of Geochemical Reaction on Environmental Risks of GCS. Appropriate assessment and management of environmental risks is critical to technological deployment and public acceptance of GCS. Geochemical processes play an important role in environmental risks associated with CO2 leakage. Leakage pathways include transport through caprocks, fractures, and wellbores.32 Leakage compromises the ability to mitigate the impacts of atmospheric CO2 emissions on global climate change,1 and leakage to shallow depths may also degrade the water quality of drinking water aquifers. Developing capabilities to assess the risks of leakage, to detect and remediate leaks, and to predict impacts on water quality are ongoing challenges. Chemical changes induced by CO2 leakage into shallow aquifers can degrade water quality through the mobilization of toxic trace metals and metalloids.33 Carbonic acid from elevated CO2 concentrations can lower the pH of groundwater. While the response of a given aquifer to CO2 intrusion will depend on site-specific mineralogy and composition, decreasing pH will usually result in increased trace element mobilization. With decreasing pH, cationic heavy metals can be mobilized by desorption from naturally occurring sorbents such as clay and iron oxide minerals34 and also through the accelerated dissolution of heavy metal-containing minerals.33 Reactions of scCO2-acidified brine with well cements can influence their ability to protect against leakage (Figure 1). Cements initially contain calcium silicate hydrate and calcium hydroxide phases that can be partially transformed to calcium carbonate upon exposure to CO2-rich brine.35 Because carbonation can impede diffusion and fill fractures, this process may actually be beneficial to healing fractures in well cements.31 However, continuing reaction with CO2-rich brine can subsequently dissolve the calcium carbonate and degrade the cement as the pH decreases further and the solution composition passes out of the region of calcium carbonate solubility. This degradation is most likely to occur for well cements in poorly buffered locales.35 Methods to seal fractures, such as injecting cations and microorganisms to stimulate biogenic carbonate precipitation,36 are actively being explored. Geophysical and geochemical methods are being developed to detect CO2-leakage in wellbores and shallow aquifers. For example, a recent field study demonstrated the ability of electrical resistivity and phase measurements to detect a CO2rich plume.30 Geochemical measurements, especially changes in pH and electrical conductivity, can also detect CO2 intrusion, although specific responses can be confounded by the content of pH-buffering carbonate minerals and cointrusion of brine with CO2.37 Gas measurements at the surface and in soils can also be useful, but their interpretation is complicated by natural temporal variations and other factors.38 Geochemical reactions influence risk assessments that are used in GCS site selection. System-level computational models for performance assessment of GCS are being developed that include leakage pathways and can track the contact time of wellbores with CO2-rich fluids that may lead to cement degradation.32 The U.S. Department of Energy’s National Risk Assessment Partnership (NRAP) is working to calculate 6

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(4) Wang, F.; Giammar, D. E. Forsterite dissolution in saline water at elevated temperature and high CO2 pressure. Environ. Sci. Technol. 2012, DOI: 10.1021/es301231n. (5) Xu, T.; Apps, J. A.; Pruess, K.; Yamamoto, H. Numerical modeling of injection and mineral trapping of CO2 with H2S and SO2 in a sandstone formation. Chem. Geol. 2007, 242 (3−4), 319−346. (6) Xu, T.; Kharaka, Y. K.; Doughty, C.; Freifeld, B. M.; Daley, T. M. Reactive transport modeling to study changes in water chemistry induced by CO2 injection at the Frio-I Brine Pilot. Chem. Geol. 2010, 271 (3−4), 153−164. (7) Hu, Y.; Ray, J. R.; Jun, Y.-S. Biotite−brine interactions under acidic hydrothermal conditions: Fibrous illite, goethite, and kaolinite formation and biotite surface cracking. Environ. Sci. Technol. 2011, 45 (14), 6175−6180. (8) Hu, Y.; Ray, J. R.; Jun, Y. S. Na+, Ca2+, and Mg2+ in brines affect supercritical CO2−brine−biotite interactions: Ion exchange, biotite dissolution, and illite precipitation. Environ. Sci. Technol. 2012, DOI: 10.1021/es301273g. (9) Shao, H.; Ray, J. R.; Jun, Y.-S. Dissolution and precipitation of clay minerals under geologic CO2 sequestration conditions: CO2− brine−phlogopite interactions. Environ. Sci. Technol. 2010, 44 (15), 5999−6005. (10) Shao, H.; Ray, J. R.; Jun, Y.-S. Effects of salinity and the extent of water on supercritical CO2-induced phlogopite dissolution and secondary mineral formation. Environ. Sci. Technol. 2011, 45 (4), 1737−1743. (11) Yang, Y.; Ronzio, C.; Jun, Y.-S. The effects of initial acetate on scCO2-brine-anorthite interactions under geologic CO2 sequestration conditions. Energy Environ. Sci. 2011, 4, 4596−4606. (12) Gaus, I. Role and impact of CO2-rock interactions during CO2 storage in sedimentary rocks. Int. J. Greenhouse Gas Control 2010, 4 (1), 73−89. (13) Kharaka, Y. K.; Cole, D. R.; Thordsen, J. J.; Kakouros, E.; Nance, H. S. Gas-water-rock interactions in sedimentary basins: CO2 sequestration in the Frio Formation, Texas, USA. J. Geochem. Explor. 2006, 89 (1−3), 183−186. (14) Emberley, S.; Hutcheon, I.; Shevalier, M.; Durocher, K.; Mayer, B.; Gunter, W. D.; Perkins, E. H. Monitoring of fluid−rock interaction and CO2 storage through produced fluid sampling at the Weyburn CO2-injection enhanced oil recovery site, Saskatchewan, Canada. Appl. Geochem. 2005, 20 (6), 1131−1157. (15) Mito, S.; Xue, Z.; Ohsumi, T. Case study of geochemical reactions at the Nagaoka CO2 injection site, Japan. Int. J. Greenhouse Gas Control 2008, 2 (3), 309−318. (16) Lu, J.; Kharaka, Y. K.; Thordsen, J. J.; Horita, J.; Karamalidis, A.; Griffith, C.; Hakala, J. A.; Ambats, G.; Cole, D. R.; Phelps, T. J.; Manning, M. A.; Cook, P. J.; Hovorka, S. D. CO2−rock−brine interactions in Lower Tuscaloosa Formation at Cranfield CO2 sequestration site, Mississippi, U.S.A. Chem. Geol. 2012, 291 (0), 269−277. (17) Duan, Z. H.; Sun, R. An improved model calculating CO2 solubility in pure water and aqueous NaCl solutions from 273 to 533 K and from 0 to 2000 bar. Chem. Geol. 2003, 193 (3−4), 257−271. (18) Schaef, H. T.; McGrail, B. P.; Loring, J. L.; Bowden, M. E.; Arey, B. W.; Rosso, K. M. Forsterite [Mg2SiO4] carbonation in wet supercritical CO2: An in situ high pressure X-ray diffraction study. Environ. Sci. Technol. 2012, DOI: 10.1021/es301126f. (19) Kharaka, Y. K.; Hanor, J. S.; Heinrich, D. H.; Karl, K. T., Deep fluids in the continents: I. Sedimentary basins. In Treatise on Geochemistry; Pergamon: Oxford, 2007; pp 1−48. (20) Brantley, S. L., Kinetics of Mineral Dissolution. In Kinetics of Water-Rock Interaction; Brantley, S. L.; Kubicki, J. D.; White, A. F., Eds. Springer: New York, 2008; pp 151−196. (21) Canal, J.; Delgado, J.; Falcón, I.; Yang, Q.; Juncosa, R.; Barrientos, V. Injection of CO2-saturated water through a siliceous sandstone plug from the Hontomin test site (N Spain). Experiment and modeling. Environ. Sci. Technol. 2012, DOI: 10.1021/es-30012222. (22) Kim, Y.; Wan, J.; Kneafsey, T. J.; Tokunaga, T. K. Dewetting of silica surfaces upon reactions with supercritical CO2 and brine: Pore-

metastable and cannot be predicted by thermodynamic equilibrium simulations, affect the reactive surface area and the pathway of CO2. The development of analytical tools that can work at the extreme pressure and temperature conditions of GCS environments will be valuable to future research. In situ imaging of CO2−water−mineral reactions at high temperature and CO2 pressure can now be accomplished with atomic force microscopy,42 X-ray computed tomography for 3-dimensional visualization,43 and microfluidic systems.44 Chemical speciation and mineralogical information can be gained from advances in 13 C nuclear magnetic resonance spectroscopy,45 Raman and infrared spectroscopy,46 and X-ray diffraction instrumentation18 that allow these techniques to be performed on hydrated samples at high temperature and pressure. The challenges facing GCS are complex, and addressing them requires interdisciplinary research that is both basic and applied and spans the entire range of relevant scales. Several current GCS demonstration projects are important for testing theories developed in the laboratory and in modeling studies, identifying gaps in our current understanding, and establishing a baseline of data that supports safe GCS. Geologic CO2 sequestration is intimately linked to carbon capture, and the composition of scCO2 (impurities in injected scCO2), injection volumes, injection rates, and injection pressures are all determined by this front-end process. Hence, researchers working on GCS need to collaborate closely with scientists and engineers working on carbon capture. This will result in the most progress on this critically important technology for mitigating climate change. 33

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AUTHOR INFORMATION

Corresponding Author

*Phone: (314) 935-4539; fax: (314) 935-7211 http://encl. engineering.wustl.edu/; e-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Y.-S.J. acknowledges financial support from the U.S. National Science Foundation’s CAREER Award (EAR-1057117) and the U.S. Department of Energy, Office of Basic Energy Sciences (DE-AC02-05CH11231). D.E.G. and Y.-S.J.’s participation has been supported by the Consortium for Clean Coal Utilization at Washington University. C.J.W. acknowledges financial support from the LDRD Program (Grant No. 20100025DR) of the Los Alamos National Laboratory. The authors thank Drs. Carl I. Steefel and Gautier Landrot for providing a SEM-BSE image.

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REFERENCES

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