Search

Geological carbon storage is the key to reduce CO₂ emissions and mitigate global warming. The long-term storage of CO₂ in geological formations requires a secure sealing reservoir. Faults are key components in defining fluid migration pathways and sealing integrity in sedimentary basins. The injection of fluids into a compartmentalized formation increases pore pressure and might reactivate pre-existing faults. The rock compressibility determines the extent of pressure build-up and the risks associated with CO₂ injection. The transport properties of fault gouge and the potential clay smear in faults describe the resistance of fluid flow across faults and have direct implications on the height of the trapped CO₂ column. The CO₂ leakage into overlying formations compromises storage efficiency and the detection of subsurface leakages necessitates an effective pressure monitoring technique. Thus, this dissertation includes the determination of rock compressibility, the quantification of fault transport properties, the prediction of CO₂ column height, and the monitoring of unfavorable leakages in CO₂ storage. The dissertation reports the uniaxial strain unloading compressibility of Frio sand for predicting pressure build-up during CO₂ injection. The transport properties of synthetic fault gouge are measured through permeability tests and CO₂ breakthrough pressure tests. A stochastic model is developed to account for the continuity of clay smears and statistically determine the possible range of CO₂ column height. Finally, a compositional model built in a reservoir simulator quantifies injection-induced changes of pore pressure above the injection zone and provides guidance for leakage detection. The major conclusions of this dissertation are: (1) the uniaxial strain compressibility is about one half of the isotropic compressibility and the uniaxial strain unloading compressibility is about one-third of the uniaxial strain loading compressibility at comparable levels of effective stress; using incorrect compressibility values considerably underestimates the risks during injection; (2) the absolute permeability of synthetic fault gouge decreases by about one order of magnitude and the CO₂ breakthrough pressure increases approximately by half order of magnitude with increments of 10 wt% of clay; (3) the ductility, continuity, and location of clay smears add significant variability to the determination of fault sealing capacity; ductile clays favor continuous smears and results in a long CO₂ column; (4) the pore pressure increase above the injection zone as a result of partially undrained loading is up to 1% of the pressure increase in the injection zone for the chosen reservoir model; the pressure increase above the injection zone in the presence of leaks can be one order of magnitude larger than the case without leaks. Together, the understanding of reservoir injectivity and sealing potential improves the reservoir risk management, provides assurance of the long-term CO₂ storage, and mitigates unintended subsurface leakages