Thermo-poroelastic responses of a pressure-driven fracture in a carbon storage reservoir and the implications for injectivity and caprock integrity

CO2 injection into a reservoir with marginal permeability (less than or similar to 10(-14) m(2)) could induce pressure high enough to fracture the reservoir rock and/or caprock. A pressure-driven fracture can immensely enhance the injectivity and would not compromise the integrity of the overall storage complex as long as the fracture is contained vertically. Conventional models for geologic carbon storage simply treat fractures as high-permeability conduits, ignoring coupled interactions between the fluids, the fracture, the reservoir, and caprock. We employ a high-fidelity model coupling multiphase flow, heat transport, poroelasticity, thermal contraction, as well as fracture mechanics to study thermo-poroelastic responses of a pressure-driven fracture in a carbon storage reservoir. We found that poroelasticity dictates that to maintain an open fracture in the reservoir rock requires a continuous and significant increase of pressure, potentially exceeding the fracturing pressure for the caprock. A closed-form equation is derived to conservatively compute the pressure increase. Although cooling in the near-well region could reduce the fracture-opening pressure, the fracture propagation pressure is still dictated by processes in the far-field rock unaffected by the cooling. This discrepancy causes a high net pressure near the injection well and could further drive the fracture into the caprock. However, while such fracturing is likely, we demonstrate that in many instances we can expect it to be contained.

Automated summary

The study suggests that maintaining an open fracture in the carbon storage reservoir requires a continuous increase in pressure, with cooling near the well potentially reducing the fracture-opening pressure. However, the fracture propagation pressure is still dictated by processes in the far-field rock.