CO2 storage and potential fault instability in the St. Lawrence Lowlands sedimentary basin (Quebec, Canada): Insights from coupled reservoir-geomechanical modeling
- Author(s): Konstantinovskaya, E;
- Rutqvist, J;
- Malo, M
- et al.
Published Web Locationhttps://doi.org/10.1016/j.ijggc.2013.12.008
Coupled reservoir-geomechanical (TOUGH-FLAC) modeling is applied for the first time to the St. Lawrence Lowlands region to evaluate the potential for shear failure along pre-existing high-angle normal faults, as well as the potential for tensile failure in the caprock units (Utica Shale and Lorraine Group). This activity is part of a general assessment of the potential for safe CO2 injection into a sandstone reservoir (the Covey Hill Formation) within an Early Paleozoic sedimentary basin. Field and subsurface data are used to estimate the sealing properties of two reservoir-bounding faults (Yamaska and Champlain faults). The spatial variations in fluid pressure, effective minimum horizontal stress, and shear strain are calculated for different injection rates, using a simplified 2D geological model of the Becancour area, located ~110km southwest of Quebec City. The simulation results show that initial fault permeability affects the timing, localization, rate, and length of fault shear slip. Contrary to the conventional view, our results suggest that shear failure may start earlier for a permeable fault than for a sealing fault, depending on the site-specific geologic setting. In simulations of a permeable fault, shear slip is nucleated along a 60m long fault segment in a thin and brittle caprock unit (Utica Shale) trapped below a thicker and more ductile caprock unit (Lorraine Group) - and then subsequently progresses up to the surface. In the case of a sealing fault, shear failure occurs later in time and is localized along a fault segment (300m) below the caprock units. The presence of the inclined low-permeable Yamaska Fault close to the injection well causes asymmetric fluid-pressure buildup and lateral migration of the CO2 plume away from the fault, reducing the overall risk of CO2 leakage along faults. Fluid-pressure-induced tensile fracturing occurs only under extremely high injection rates and is localized below the caprock units, which remain intact, preventing upward CO2 migration. © 2013.