Numerical Study of CO2 Geological Storage in Saline Aquifers without the Risk of Leakage

The purpose of this study is to reduce the risk of leakage of CO2 geological storage by injecting the dissolved CO2 solution instead of the supercritical CO2 injection. The reservoir simulation method is used in this study to evaluate the contributions of the different trapping mechanisms, and the safety index method is used to evaluate the risk of CO2 leakage. The function of the dissolved CO2 solution injection is performed by a case study of a deep saline aquifer. Two scenarios are designed in this study: the traditional supercritical CO2 injection and the dissolved CO2 solution injection. The contributions of different trapping mechanisms, plume migrations, and the risk of leakage are evaluated and compared. The simulation results show that the risk of leakage via a natural pathway can be decreased by the approach of injecting dissolved CO2 solution instead of supercritical CO2. The amount of the CO2 retained by the safe trapping mechanisms in the dissolved CO2 solution injection scenario is greater than that in the supercritical CO2 scenario. The process of CO2 mineralization in the dissolved CO2 solution injection scenario is also much faster than that in the supercritical CO2 scenario. Changing the injection fluid from supercritical CO2 to a dissolved CO2 solution can significantly increase the safety of the CO2 geological storage. The risk of CO2 leakage from a reservoir can be eliminated because the injected CO2 can be trapped totally by safe trapping mechanisms.

A Numerical Analysis of the Effects of Supercritical CO2 Injection on CO2 Storage Capacities of Geological Formations

One of the most promising means of reducing carbon content in the atmosphere, which is aimed at tackling the threats of global warming, is injecting carbon dioxide (CO2) into deep saline aquifers (DSAs). Keeping this in mind, this research aims to investigate the effects of various injection schemes/scenarios and aquifer characteristics with a particular view to enhance the current understanding of the key permanent sequestration mechanisms, namely, residual and solubility trapping of CO2. The paper also aims to study the influence of different injection scenarios and flow conditions on the CO2 storage capacity and efficiency of DSAs. Furthermore, a specific term of the permanent capacity and efficiency factor of CO2 immobilization in sedimentary formations is introduced to help facilitate the above analysis. Analyses for the effects of various injection schemes/scenarios and aquifer characteristics on enhancing the key permanent sequestration mechanisms is examined through a series of numerical simulations employed on 3D homogeneous and heterogeneous aquifers based on the geological settings for Sleipner Vest Field, which is located in the Norwegian part of the North Sea. The simulation results highlight the effects of heterogeneity, permeability isotropy, injection orientation and methodology, and domain-grid refinement on the capillary pressure–saturation relationships and the amounts of integrated CO2 throughout the timeline of the simulation via different trapping mechanisms (solubility, residual and structural) and accordingly affect the efficiency of CO2 sequestration. The results have shown that heterogeneity increases the residual trapping of CO2, while homogeneous formations promote more CO2 dissolution because fluid flows faster in homogeneous porous media, inducing more contact with fresh brine, leading to higher dissolution rates of CO2 compared to those in heterogeneous porous medium, which limits fluid seepage. Cyclic injection has been shown to have more influence on heterogenous domains as it increases the capillary pressure, which forces more CO2 into smaller-sized pores to be trapped and exposed to dissolution in the brine at later stages of storage. Storage efficiency increases proportionally with the vertical-to-horizontal permeability ratio of geological formations because higher ratios facilitate the further extent of the gas plume and increases the solubility trapping of the integrated gas. The developed methodology and the presented results are expected to play key roles in providing further insights for assessing the feasibility of various geological formations for CO2 storage.