Caprock Fracture Dissolution and CO2 Leakage

Abstract

Caprocks are impermeable sedimentary formations that overlie prospective geologic CO2 storage reservoirs. As such, caprocks will be relied upon to trap CO2 and prevent vertical fluid migration and leakage. Natural and industrial analogues provide evidence of long-term performance of caprocks in holding buoyant fluids. However, the large volumes of CO2 that must be injected and stored to meaningfully reduce anthropogenic greenhouse gas emissions will exert unprecedented geomechanical and geochemical burdens on caprock formations due to elevated formation pressures and brine acidification. Caprocks have inherent vulnerabilities in that wellbores, faults and fractures that transect caprock formations may provide conduits for CO2 and/or brine to leak out of the intended storage formation. As a result, a critical criterion for CO2 storage reservoir siting assessments will be to predict and reliably quantify the risk of leakage through caprock formations. We use “flow paths” as a catchall term for any fluid conduit through caprocks including pore networks, fractures and faults along with any combination of the three elements. It is useful to assess leakage rates through flow paths in terms of their individual transmissivity, T [m4], which is the product of the permeability and the cross-sectional area of the flow path. Darcy’s law can be used to relate these intrinsic flow path characteristics and the hydraulic potential (pressure) gradient to determine a volumetric flow rate, Q , or a leakage rate for the individual flow path: ![Formula][1] (1) Where P is the hydraulic potential [Pa], z is the depth [m], μ is the fluid viscosity [Pa s] and A [m2] is the cross-sectional area of the flow path perpendicular to flow, and A equals the product of average fracture aperture and fracture length normal to the flow direction. Predicting leakage potential, however, is extremely complex because assessments … [1]: /embed/mml-math-1.gif