Evaluation of CO _<b>2</b> Sequestration in a Multilayer Leaky Aquifer by Numerical Simulation

CO2 sequestration in subsurface formations is one of the most effective ways to tackle global warming. However, CO2 storage becomes challenging in formations possessing heterogeneity, fractures, or leakage paths in the caprock. Hence, assessing the deep saline aquifers becomes essential prior to real-field CO2 sequestration scenarios. To meet this objective, we have developed a fluid flow model associated with fluid properties’ evolution, in which CO2 is injected via an injection well into the reservoir containing a fractured zone within the caprock at a distance of 100 m from the injection well to investigate CO2 sequestration in heterogeneous and leaky geologic environments. Reservoir anisotropy is observed to influence the normalized leakage rate. A larger normalized leakage rate is observed when the vertical permeability is set equal to horizontal permeability, whereas no leakage is observed when vertical permeability is set to 0.01 times the horizontal permeability. The injection velocity plays an important role in influencing the CO2 leakage rate. A peak normalized leakage rate of 0.11 is observed at a CO2 injection velocity of 7 × 10–7 m/s. However, the reservoir with enhanced permeability in the upward direction in the saline aquifer’s region supports CO2 leakage through the leakage path and causes earlier leakage than the saline aquifers possessing homogeneous permeability and enhanced permeability in a downward direction, respectively. The sensitivity of the leakage path’s porosity and permeability on leakage characteristics is also evaluated, and it is observed that enhancing the permeability reduces the leakage time, whereas enhancing the porosity increases the leakage time.