Characteristics of Salt-Precipitation and the Associated Pressure Build-Up during CO2 Storage in Saline Aquifers

Abstract

Mitigation and control of borehole pressure at the bottom of an injection well is directly related to the effective management of well injectivity during geologic carbon sequestration activity. Researchers have generally accepted the idea that high rates of CO 2 injection into low permeability strata results in increased bottom-hole pressure in a well. However, the results of this study suggested that this is not always the case, due to the occurrence of localized salt precipitation adjacent to the injection well. A series of numerical simulations indicated that in some cases, a low rate of CO 2 injection into high permeability formation induced greater pressure build-up. This occurred because of the different types of salt precipitation pattern controlled by buoyancy-driven CO 2 plume migration. The first type is non-localized salt precipitation, which is characterized by uniform salt precipitation within the dry-out zone. The second type, localized salt precipitation, is characterized by an abnormally high level of salt precipitation at the dry-out front. This localized salt precipitation acts as a barrier that hampers the propagation of both CO 2 and pressure to the far field as well as counter-flowing brine migration toward the injection well. These dynamic processes caused a drastic pressure build-up in the well, which decreased injectivity. By modeling a series of test cases, it was found that low-rate CO 2 injection into high permeability formation was likely to cause localized salt precipitation. Sensitivity studies revealed that brine salinity linearly affected the level of salt precipitation, and that vertical permeability enhanced the buoyancy effect which increased the growth of the salt barrier. The porosity also affected both the level of localized salt precipitation and dry-out zone extension depending on injection rates. High temperature injected CO 2 promoted the vertical movement of the CO 2 plume, which accelerated localized salt precipitation, but at the same time caused a decrease in the density of the injected CO 2 . The combination of these two effects eventually decreased bottomhole pressure. Considering the injectivity degradation, a method is proposed for decreasing the 123 398 K.-Y. Kim et al.pressure build-up and increasing injectivity by assigning a 'skin zone' that represents a local region with a transmissivity different from that of the surrounding aquifer.

Global Sensitivity Analysis to Assess Salt Precipitation for CO2 Geological Storage in Deep Saline Aquifers

“…The Morris method and Sobol method give a different sensitivity arrangement for CO 2 . In the Morris method, CO 2 is one of the main factors causing the change in , which is consistent with the conclusion of Pruess et al [9,[38][39][40]. However, in the Sobol method, the influence of the CO 2 on is much smaller than that of NaCl , , and lr .…”

“…2 Injection Rate on Solid Saturation. Many researchers have studied the effect of CO 2 on by numerical simulation; they consider that an increase in CO 2 decreases the , and their results are shown in Figure 15 [9,[38][39][40]. The Morris method and Sobol method give a different sensitivity arrangement for CO 2 .…”

Fundamental study of CO2-H2O-mineral interactions for carbon sequestration, with emphasis on the nature of the supercritical fluid-mineral interface.

“…The supercritical CO 2 (scCO 2 ) will be essentially anhydrous as surface transportation and pipeline operations require low-water-content CO 2 and no free water to limit corrosion of typical carbon-manganese steels [15]. Conceptual models in the literature assume a region of anhydrous separate-phase scCO 2 developing immediately around the wellbore as the formation brine is displaced and remaining water is evaporated [16,17]. The anhydrous region is encompassed by a multiphase region of separate-phase scCO 2 and formation brine (i.e., the aqueous fluid) with mutually-dissolved CO 2 and water in each fluid phase, which is finally surrounded by native formation brine [8,17,18].…”

“…Previous work in the CO 2 storage literature related to the changing magnitude of the chemical potential of water and/or adsorptive and capillary water focuses mainly on: 1) near-wellbore saline water evaporation and concomitant salt precipitation that may reduce scCO 2 injection rates due to permeability losses [16,17,[28][29][30]; 2) chemical reactivity under humid scCO 2 including precipation-dissolution and water intercalation in clays as a function of water content in scCO 2 [7,10,[31][32][33][34][35][36]; and 3) laboratory observation or theoretical estimation of thickness of water films in scCO 2 [26,27,37]. Common approaches for assessing near-wellbore dry-out, in calculating water activity in the CO 2 -rich phase, typically neglect any effects of capillary potential or surface adsorption potential on the total chemical potential of water [e.g., see 36,38].…”

Two-phase flow effects on the CO2injection pressure evolution and implications for the caprock geomechanical stability

“…Thus, overpressure evolution in the field is more similar to that predicted by the semi-analytical solution of Vilarrasa et al [23] than to that derived from other analytical solutions. Numerical solutions also predict the sharp increase in injection pressure at the beginning of injection followed by a progressive pressure drop [25][26][27][28][29]. Nevertheless, little attention has been paid to understand the driving mechanisms of overpressure evolution induced by CO 2 injection.…”