The injection of fluids into a compartmentalized formation induces pore pressure buildup and may result in reactivation of sealing faults. Among other variables, the pore volume compressibility (PVC) can affect the amount of pore pressure change during injection. PVC has been traditionally measured with isotropic loading compressibility tests. However, long and thin reservoirs subjected to depletion or injection typically follow a uniaxial strain stress path, rather than an isotropic stress path. Furthermore, injection unloads the reservoir rock by reducing effective stress, whereas depletion causes loading. This research reports experimental measurements of the uniaxial strain unloading compressibility of Frio sand, a member of Tertiary strata in the Gulf of Mexico Basin. Reservoir simulation highlights that using incorrect pore compressibility values considerably underestimates the expected increase of pore pressure in a compartmentalized formation during injection. Uniaxial strain unloading compressibility of target reservoir rocks should be accurately estimated or measured to prevent excessive pressure build up in target storage formations during injection of CO2 or any other fluids. 

Commercial-scale development of CO2 geological storage necessitates robust and real-time monitoring methods to track the injected CO2 plume and provide assurance of CO2 storage. Pressure monitoring above the injection zone is a method to detect potential CO2 leaks into overlying formations. This research present a generic CO2 storage model with a single injector to predict pressure changes above the caprock due to both fast hydraulic communication and partially undrained loading, the latter often neglected in reservoir simulation. The simulation used a compositional simulator coupled with geomechanics to solve the poroelastic equations in the entire storage complex. Pressure monitoring above the caprock is a feasible technology to track the CO2 plume, requires high precision pressure measurements, and must account for partially undrained poroelastic loading to interpret correctly measured pressure signals in the field. 

Faults are key components in defining fluid migration pathways and seals in sedimentary basins. The sealing capacity of faults is closely related to the petrophysical and geomechanical properties of fault gouge. Clay smear, cataclasis, and diagenesis favor a high capillary breakthrough pressure and low permeability in clastic sediments, and therefore fault gouge seal. However, significant uncertainty remains in accurately predicting the sealing capacity of faults for CO2 storage. This research includes a series of experiments, including absolute permeability, breakthrough pressure, and post-breakthrough CO2 permeability measurements on synthetic fault gouge samples, made from homogeneous mixtures of Frio sand and Anahuac shale, lithofacies of tertiary sediments in the Gulf of Mexico basin. The measurements on fault gouge properties are meaningful to quantitatively evaluate fault sealing capability and migration of buoyant fluids through faults in sand-shale sequences. 

Bentonite clay, a fine-grained geologic material rich in smectite clay minerals, is widely used in the isolation of landfills and contaminated sites and is considered for use as an engineered barrier in the disposal of high-level radioactive waste because of its unique properties, such as low hydraulic permeability and high swelling pressure. The heat released by nuclear waste is expected to exert large thermal gradients on this engineered clay barrier and may trigger coupled thermal-hydrologic-mechanical-chemical (THMC) phenomena that must be considered in the design of geologic repositories. This research presents a methodology that aims to generate new insight into the material properties of compacted bentonite using large-scale all-atom molecular dynamic (MD) simulations of clay-water mixtures carried out using the code GROMACS. The presented microscale THMC properties of bentonite buffer materials yield key inputs used in large-scale THMC simulators and enable comparisons with results at multiple scales. This work will facilitate characterization of clay evolution, help evaluate the performance of engineered clay barrier systems, and provide assurance for the long-term isolation of radioactive waste in geologic repositories.

Structural fault trapping of buoyant fluids, such as hydrocarbons and CO2, relies on fault sealing capacity. The traditional approach to quantifying the sealing capacity of fault zone materials is Shale Gouge Ratio (SGR), which implicitly homogenizes fault properties. However, a large range of fault throw and the presence of fault heterogeneity can lead to different trapping capacities for the same structure. This research presents a stochastic study to statistically determine the possible range of CO2 column height at a normal fault in sand-shale sequences. We present the procedures of two stochastic models including the continuous shale gouge model (CSGM) and the discrete smear model (DSM). The models are applied in an example case for the High Island field in the Gulf of Mexico (GOM) basin combining borehole geophysical data and measurements from laboratory experiments. Uncertainty quantification of clay ductility, smear location, and fault heterogeneity is important for determining fault sealing capacity and improving reservoir risk management associated with carbon dioxide geological storage.

Hydraulic fracturing involves injecting the high-pressure fluids into the formation to create fractures and is often used as a stimulation method to extract hydrocarbons from the underground. Channel fracturing generally refers to a kind of novel hydraulic fracturing treatment that relies on the intermittent pumping of proppant-laden and proppant-free fluids to generate highly conductive channels within the formation. The fracture conductivity can increase up to several folds and thus more hydrocarbons can be extracted from the underground. However, how to effectively evaluate the fracture conductivity in channel fracturing remains not fully understood. We revolutionarily applied the Hertz contact theory to determine fracture residue openings and derived the analytical solutions for calculating fracture permeability. Then, we performed a series of simulations to examine the effects of proppant pillar density, pulse time of pumping fluids, and geologic conditions on fracture conductivity. The results demonstrated the feasibility of employing channel fracturing to improve fracture conductivity and thus enhance the hydrocarbon production.