Assessing shale caprock permeability evolution during CO₂ injection and multiphase flow

Transitioning to low-emission energy systems increasingly relies on subsurface technologies such as carbon capture and storage (CCS), geological hydrogen storage, and the sealing and abandonment of legacy hydrocarbon wells. All these technologies require reliable long-term containment, which depends strongly on the sealing capacity of caprocks. Shales commonly form the primary barrier above storage reservoirs, benefiting from their very low permeability and relatively ductile deformation behavior. During injection, as the pore pressure in the storage reservoir increases and injected fluids start to invade the shale caprock, pressure-driven changes in pore structure and saturation state may directly impact transport pathways, potentially increasing leakage risk. Given the critical role of shale caprocks in preventing CO₂ migration, laboratory core-scale measurements are essential to assess any such changes in caprock properties.

This study presents a laboratory experimental program designed to quantify how CO₂ and CO₂–water flow alters shale core plug permeability and pressure response. Cylindrical shale core plugs are assembled in an experimental cell with controlled confinement, and permeability is determined from continuous monitoring of inlet and outlet pressures, differential pressure, and flow rate during constant volumetric injection. In the first set of tests, CO₂ is injected CO₂ is injected through shale core plugs under different confining pressures to evaluate how changes in external loading and flow conditions influence measured permeability and pressure transients. These measurements provide insight into stress-sensitive flow behavior and whether permeability changes are reversible or exhibit hysteresis after pressure cycling.

In a second set of experiments, a three-step injection sequence will be performed to mimic saturation-history effects relevant to CO₂ storage. Starting with a water-saturated sample, first CO2 will be injected, followed by water, and then CO2 again. Throughout the sequence, pressure evolution and permeability estimates are tracked to evaluate how switching between injected fluids, and fluid–rock interactions influence transport. The CO₂–water–CO₂ protocol is used to assess whether water introduction modifies flow pathways, and whether the subsequent CO₂ reinjection restores, further reduces, or permanently alters the permeability relative to the initial CO₂ baseline.

The resulting dataset links injection history and confining-pressure changes to permeability evolution in shale caprock analogs, providing experimental constraints for evaluating caprock performance in CCS. In addition, the measurements will be used to calibrate numerical models of flow in low-permeability caprock, strengthening model and improving predictive capability for caprock integrity assessment under realistic injection scenarios.