Injection of fluids into deep saline aquifers is practiced in several industrial activities, and is being considered as part of a possible mitigation strategy to reduce anthropogenic emissions of carbon dioxide into the atmosphere. Injection of CO 2 into deep saline aquifers involves CO 2 as a supercritical fluid that is less dense and less viscous than the resident formation water. These fluid properties lead to gravity override and possible viscous fingering. With relatively mild assumptions regarding fluid properties and displacement patterns, an analytical solution may be derived to describe the space-time evolution of the CO 2 plume. The solution uses arguments of energy minimization, and reduces to a simple radial form of the Buckley-Leverett solution for conditions of viscous domination. In order to test the applicability of the analytical solution to the CO 2 injection problem, we consider a wide range of subsurface conditions, characteristic of sedimentary basins around the world, that are expected to apply to possible CO 2 injection scenarios. For comparison, we run numerical simulations with an industry standard simulator, and show that the new analytical solution matches a full numerical solution for the entire range of CO 2 injection scenarios considered. The analytical solution provides a tool to estimate practical quantities associated with CO 2 injection, including maximum spatial extent of a plume and the shape of the overriding less-dense CO 2 front.

Implementation of CO2 capture and geological storage (CCGS) technology at the scale needed to achieve a significant and meaningful reduction in CO2 emissions requires knowledge of the available CO2 storage capacity. CO2 storage capacity assessments may be conducted at various scales-in decreasing order of size and increasing order of resolution: country, basin, regional, local and sitespecific. Estimation of the CO2 storage capacity in depleted oil and gas reservoirs is straightforward and is based on recoverable reserves, reservoir properties and in situ CO2 characteristics. In the case of CO2-EOR, the CO2 storage capacity can be roughly evaluated on the basis of worldwide field experience or more accurately through numerical simulations. Determination of the theoretical CO2 storage capacity in coal beds is based on coal thickness and CO2 adsorption isotherms, and recovery and completion factors. Evaluation of the CO2 storage capacity in deep saline aquifers is very complex because four trapping mechanisms that act at different rates are involved and, at times, all mechanisms may be operating simultaneously. The level of detail and resolution required in the data make reliable and accurate estimation of CO2 storage capacity in deep saline aquifers practical only at the local and site-specific scales. This paper follows a previous one on issues and development of standards for CO2 storage capacity estimation, and provides a clear set of definitions and methodologies for the assessment of CO2 storage capacity in geological media. Notwithstanding the defined methodologies suggested for estimating CO2 storage capacity, major challenges lie ahead because of lack of data, particularly for coal beds and deep saline aquifers, lack of knowledge about the coefficients that reduce storage capacity from theoretical to effective and to practical, and lack of knowledge about the interplay between various trapping mechanisms at work in deep saline aquifers

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An extensive laboratory program was conducted for the measurement of the interfacial tension between CO 2 and water or brine covering the ranges of (2 to 27) MPa pressure, (20 to 125) °C temperature, and (0 to 334 010) mg • L -1 water salinity. The laboratory experiments were conducted using the pendant drop method combined with the solution of the Laplace equation for capillarity for the profile of the brine drop in the CO 2 -brine equilibrium environment. The analysis of the resulting set of 378 IFT measurements reveals that: (1) under conditions of constant temperature and water salinity, IFT steeply decreases with increasing pressure in the range P < P c and mildly decreases for P > P c with an asymptotic trend toward a constant value at higher pressures; (2) under the same conditions of constant pressure and temperature, IFT increases with increasing water salinity, reflecting decreasing CO 2 solubility in brine as salinity increases;(3) the dependence of IFT on temperature is more complex than that on either pressure or salinity, depending on the CO 2 phase. For T < T c , IFT increases with increasing temperature, and around the critical point (T ≈ T c ), IFT significantly decreases (believed to be associated with the fact that at T c the IFT between CO 2 liquid and vapor phases tends to zero) and then increases again with increasing temperature for T > T c with an asymptotic trend toward a constant value for high temperatures. The dependence of IFT on pressure, temperature, and water salinity for CO 2 and water/brine systems can be well approximated by a power function of pressure whose coefficient and exponent depend on temperature and water salinity. These results indicate that, in the case of CO 2 storage in deep saline aquifers as a climate-change mitigation strategy, the formation water displacement by injected CO 2 during the injection (drainage) phase of CO 2 storage and the possible subsequent CO 2 displacement by invading brine during the CO 2 migration (imbibition) phase depend on in situ conditions of pressure, temperature, and water salinity through the effects that these primary variables have on the IFT between CO 2 and aquifer brine.