Nanoscale Reactions at CO2—H2Ο–Mineral Interfaces: Challenges in Monitoring CO2 in Geologic Sequestration

Recently, to help mitigate global climate-change and energy problems, much effort has recently been devoted to developing methods for sequestering anthropogenic CO₂ from coal-fired power plants. One of the most promising methods is geological CO₂ sequestration (GS). To be successful, the techniques and practices of sequestration must be effective, cost-competitive, and environmentally friendly, as well as providing stable and secure, long-term storage.^1-3 In comparison with other types of sequestration, carbon dioxide capture and storage in deep geological formations looks to be the most promising option for mitigating the large volumes of CO₂ emissions over the next century^1-3

Some prior studies of geological CO₂ sequestration have mainly examined the physical processes that occur during the sequestration of CO₂ in brine-saturated geological formations. These studies take advantage of numerical modeling techniques that employ such simulation programs as TOUGH2, or are primarily hydrological and geophysical approaches. Such approaches are based on the assumption that supercritical CO₂, under sufficient pressure and temperature (a minimum of  P = 7.4 MPa and T = 31.1 °C), is very stable for long periods of time, and that the aqueous-phase diffusion of dissolved species and leakage of dissolved CO₂ is insignificant.^4-7 However, these modeling exercises do not sufficiently take into account the effects of dissolution/precipitation within mineral phases, the adsorption/desorption of dissolved ions, or the passivation/activation of mineral surfaces by free-phase or dissolved CO₂. Neither do they consider how all these different reactivities may adversely affect the effectiveness of confinement and overall safety of the CO₂ that has been injected.

Most recently, a Nature paper by Gilfillan et al. reported that in seven gas fields with siliciclastic or carbonated reservoir lithologies, dissolution of CO₂ in formation water is the dominant sink for CO₂.⁸ They also reported that maximum of 18% of loss of CO₂ can result in carbonate precipitation. Therefore, long-term CO₂ storage models in similar geologic systems should focus on the potential mobility in dissolved CO₂ in water. However, one important thing aspect is missing in this report that even small quantities of carbonate precipitation can contribute significant changes in porosity and permeability depending on the location of precipitates. Therefore, we need to investigate the physical property changes at CO₂–H₂O-mineral interfaces in GS sites.

Changes in the porosity of the mineral phases at the geological formation sites, especially the dissolution of the mineral phase or precipitation of secondary minerals in the pores, will affect the fate and transport of CO₂ and the integrity of seals and the matrix within the reservoirs. So far, little is known about the kinetics of the possible geochemical reactions of supercritical CO₂ in brine and pre-existing mineral interfaces, or about the ultimate fate and transport of the injected CO₂. Because porosity and permeability can influence the physical properties of the reservoir, it is important to be able to predict the porosity-permeability evolution, as a function of the extent of reaction.

We investigated the physico-chemical property changes of reference mineral samples (clay minerals) as well as field site samples (sandstone and caprock from the Illinois Basin) by chemical reactions at CO₂–H₂O-mineral interfaces. Our experiments were conducted under high pressures and temperatures, which are comparable to those of GS sites. We investigated whether reactions between caprock and CO₂ (dissolved or supercritical) can change the integrity of caprock and thus lead to leakage of CO₂. In general, thick caprock is required for CO₂ sequestration, and its integrity is prerequisite to the long-term safe storage of CO₂. However, the minimum requirement for the thickness of caprock is still not determined. Knowing the reaction rates of caprock in the presence of supercritical CO₂, as well as the factors influencing the reaction rates, will help estimate the minimum safe thickness of the caprock.

Our experimental results with caprock samples (CONSOL coal mine sites, West Virginia) from the National Energy Technological Laboratory indicate that after 14 days in contact with 1 atm CO₂ saturated saline water at 80°C, the concentrations of dissolved metals have increased from zero to as high as 47,000 ppm. This suggests that the effects of CO₂ on the integrity of caprock could be significant and need to be further evaluated. In our experiments with caprocks and sandstones from GS sites of the Midwest Geological Sequestration Consortium (MGSC), we found that the most significant extent of dissolution occurs within a day with saline water at P_CO2 = 1 atm and 80°C. This result implies that monitoring the earliest stage of reactions of sandstone with CO₂ is crucial to understanding the CO₂-water-rock interactions in deep saline aquifers.

The second experiments investigated the effects of different reaction conditions (related the different GS site conditions) on the reaction pathways and the extents of reaction. Freshly cleaved (001) surfaces of phlogopite (KMg₃(Si₃Al)O₁₀(F,OH)₂) were prepared as thin layers (19-21 µm). Using in situ high pressure and temperature small angle x-ray scattering (SAXS) reactor, the real time reactions were monitored. Phlogopite was used to simulate the reactions in deep saline aquifers in the presence of high pressure CO₂. The experiments were conducted at P_CO2 = 1000 psi and different temperatures (55, 75, and 95°C) in the presence of water. After CO₂ was injected into the microreactor, the scattering pattern changed due to surface morphology changes (dissolution/precipitation) with time. This reaction occurs significantly, even within one hour. After each experiment, each sample was taken out of the reactor, and conducted atomic force microscope (AFM) imaging to compare with our observations in SAXS setup.

By incorporating aqueous chemistry with in situ SAXS and AFM, we monitored real-time nanoscale reactions resulting from dissolution of pre-existing minerals and precipitation of new mineral phases at CO₂-water-rock interfaces under high pressure and temperature conditions. Those morphological changes can be key information to understand the changes in porosity and permeability in GS sites. The results will aid in designing secure and environmentally acceptable CO₂ sequestration techniques.

References

1.    http://www-esd.lbl.gov/CO2GeoStorage/index.html

2.    Bruant, R. G.; Guswa, A. J.; Celia, M. A.; Peters, C. A., Safe storage of CO2 in deep saline aquifers. Environ. Sci. Technol. 2002, 36, (11), 240A-245A.

3.    Bachu, S., Sequestration of CO₂ in geological media: criteria and approach for site selection in response to climate change. Energy Conversion and Management 2000, 41, (9), 953-970.

4.    Doughty, C.; Pruess, K., Modeling supercritical carbon dioxide injection in heterogeneous porous media. Vadose Zone Journal 2005, 3, (3), 837-847.

5.    Spycher, N.; Pruess, K.; Ennis-King, J., CO₂-H₂O mixtures in the geological sequestration of CO₂. I. Assessment and calculation of mutual solubilities from 12 to 100 degrees C and up to 600 bar. Geochim. Cosmochim. Acta 2003, 67, (16), 3015-3031.

6.    van der Meer, L. G. H., The CO₂ storage efficiency of aquifers. Energy Converv. Manage. 1995, 36, (6-9), 513-518.

7.    Talman, S. J.; Adams, J. J.; Chalaturnyk, R., Adapting TOUGH2 for general equations of state with application to geological storage of CO2. Computers & Geosciences 2004, 30, (5), 543-552.

8.    Gilfillan, S. M. V.; Lollar, B. S.; Holland, G.; Blagburn, D.; Stevens, S.; Schoell, M.; Cassidy, M.; Ding, Z. J.; Zhou, Z.; Lacrampe-Couloume, G.; Ballentine, C. J., Solubility trapping in formation water as dominant CO2 sink in natural gas fields. Nature 2009, 458, (7238), 614-618.