CO2 geological storage: Critical insights on plume dynamics and storage efficiency during long-term injection and post-injection periods

Abstract

In the quest for net-zero greenhouse gas emission, CO2 capture and storage technologies play a prominent role. Estimates suggest a potential of sequestering up to several thousand metric gigatons of CO2. However, some of the main challenges in its development are an assessment of reservoir-specific storage capacities due to variabilities and heterogeneities in the underlying properties (structure, formations, facies, petrophysics, reservoir architecture, and others) and understanding the migration of CO2 in the subsurface.This article critically investigates CO2 plume characteristics and determines the evolving contributions of different trapping mechanisms during a 100-year injection and 200-year post-injection periods. CO2 can reside in various forms in saline aquifers. To account for these, we characterized CO2 plumes in multiple ways based on dissolved CO2 in the aqueous phase, free phase CO2, pH change, and finally, change in solid-phase saturation (due to precipitation and dissolution of salts and calcite). Based on how we define the plumes, the sizes, and the shapes of the plumes differ. Emphasis is on the characterization of the plume, its evolution, and the contributing trapping mechanisms. Additionally, we ascertain the impact of various uncertain variables, including heterogeneity and anisotropy in geological formation properties, reservoir-brine composition, and molecular diffusion on CO2 plume dynamics and storage via statistical Design of Experiments.Simulation results indicate that lateral propagation of the CO2 plume is much larger than vertical dispersion typically attributed to the presence of flow baffles and vertical stratification. The ratio of average lateral to vertical propagation ranged between 7 and 44. In general, various geometries and growth patterns evolved for the CO2 plume and are strongly influenced by the total amount of CO2 injected and the permeability directional anisotropies. On average, for all case scenarios investigated, free phase CO2 is the dominant trapping mechanism (in terms of the amount of CO2 stored) during the injection period, storing up to 60% of the CO2 injected. Both residual (20%) and solubility (16%) trapping storage ratios exhibited higher storage with time than structural trapping (10%). Effectively little mineral trapping transpires during the 100-year injection period. Another important observation is the fact that facies-dependency on saturation functions appears to have a substantial effect on different trapping mechanisms. Shale-dominant facies manifests more residual trapping than other facies.