3D Hydro-Mechanical Modeling of Shaly Caprock Response to CO2 Long-Term Periodic Injection Experiment (CO2LPIE)

Abstract

ABSTRACT: Carbon capture and storage in deep geological formations is necessary to achieve a meaningful reduction of anthropogenic CO2 emissions into the atmosphere. Given the buoyancy of the injected CO2, it is essential to adequately characterize the sealing caprocks commonly comprised of clay-rich formations, including shales. If the inherent anisotropy of shales is not considered, model prediction errors will propagate with time and space. To limit errors, the accurate experimental laboratory measurements should be scaled up and the in-situ behavior of the caprock should be studied in detail. Underground rock laboratories (URLs) offer a unique opportunity to investigate the caprock sealing capacity at a few meters scale in a well-defined and well-monitored environment. This perspective applies to the CO2 Long-term Periodic Injection Experiment (CO2LPIE) at the Swiss Mont Terri URL. In the experiment, it is planned to inject gaseous CO2 into Opalinus Clay, which is considered as a representative caprock for underground storage. Opalinus Clay shows large-scale anisotropic behavior due to the presence of bedding planes and heteorogeneities. We numerically simulate the CO2LPIE experiment using a 3D hydro-mechanical model and assuming linear poroelastic transverse isotropic behavior of the rock. We find that the CO2 is unlikely to penetrate the rock in free phase, while the diffusive front of dissolved CO2 in resident brine hardly propagates half a meter after two years of injection. The overpressure and induced deformation and stress changes preferentially develop along the bedding planes, although not sufficiently to lead to shear failure. 1. INTRODUCTION To limit global warming to 1.5 °C, net carbon removal after 2050 should be targeted (IPCC, 2014). To reach this goal, it is critical to develop novel technologies and a promising approach is Carbon Capture and Storage (CCS). CCS is generally understood as the set of CO2 capture from a large stationary source, transport to an injection site, and permanent storage in the subsurface (Benson and Cook, 2005). CO2 density at the pressure and temperature of typical underground storage formations in sedimentary basins is approximately 65 % of the in-situ brine density. As a result, the plume of the injected CO2 will not only migrate outwards from the injection well, but also upwards until it finds a sealing layer called caprock (Tsang and Niemi, 2017). To assure long-term CO2 trapping, it is of fundamental importance to properly characterize the caprock sealing capacity, commonly presented in terms of permeability, porosity, capillary entry pressure and relative permeability curves, and their evolution with time (Kaldi et al., 2011).