The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is likely to be limited to lower recovery efficiency than shale gas.However, the recently discovered Eagle Ford shale formations is significantly over pressured, and initial formation pressure is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional shale oil formations.We explain how the Eagle Ford shale is different from other shales such as the Barnett and others. Although, Eagle Ford shale produces oil, condensate and dry gas in different areas, our study focuses in the oil window of the Eagle Ford shale. We used the logarithmically gridded locally refined gridding scheme to properly model the flow in the hydraulic fracture, the flow from the fracture to the matrix and the flow in the matrix. iv The steep pressure and saturation changes near the hydraulic fractures are captured using this gridding scheme. We compare the modeled production of shale oil from the very low permeability reservoir to conventional reservoir flow behavior.We show how production behavior and recovery of oil from the low permeability shale formation is a function of the rock properties, formation fluid properties and the fracturing operations. The sensitivity studies illustrate the important parameters affecting shale oil production performance from the stimulated reservoir volume. The parameters studied in our work includes fracture spacing, fracture half-length, rock compressibility, critical gas saturation (for 2 phase flow below the bubble point of oil), flowing bottomhole pressure, hydraulic fracture conductivity, and matrix permeability.The sensitivity studies show that placing fractures closely, increasing the fracture half-length, making higher conductive fractures leads to higher recovery of oil. Also, the thesis stresses the need to carry out the core analysis and other reservoir studies to capture the important rock and fluid parameters like the rock permeability and the critical gas saturation.

Previous studies have shown that bulk CO 2 injection in deep saline aquifers supplies insufficient aquifer storage efficiency and causes excessive risk due to aquifer pressurization. To avoid pressurization, we propose to produce the same volume of brine as is injected as CO 2 in a CO 2 -brine displacement. Previous work showed that this increases the storage efficiency from 2% to 8%. However, this transforms the CO 2 storage problem into a brine disposal problem. Therefore, we propose to desalinate the native brine and inject the saturated brine into the same aquifer while producing additional brine to maintain voidage balance.A hypothetical case study using documented aquifer properties of the Woodbine aquifer in Texas indicates that the available volume is insufficient volume to store all of the CO 2 being generated by power plants in the vicinity for more than 14 years. However, the CO 2 -brine displacement increases storage efficiency enough to store the CO 2 produced for 84 years at the current rate of coal fired electric power generation. Using the reported brine salinity of the Woodbine aquifer, the energy requirements for CO 2 transport and injection, brine production and transport, desalination, and saturated brine injection are estimated consistent with assumptions about the location of injection and production wells, the desalination unit or units, and whether desalinated water can be used by the power plant or for other uses.While this approach may enable CO 2 storage, the high energy cost ranging from 7.5% to 16% of the total power generation capacity is not insignificant, and comes with significant land use implications for injection and production wells, pipelines, etc. The importance of these results cannot be overstated.

Previous studies have shown that bulk carbon dioxide (CO 2 ) injection in deep saline aquifers supplies insufficient aquifer storage efficiency and causes excessive risk because of aquifer pressurization. To avoid pressurization, we propose to produce the same volume of brine as is injected as CO 2 in a CO 2 /brine displacement. Two approaches to CO 2 /brine displacement are considered-an external brine-disposal strategy in which brine is disposed of into another formation such as oilfield brine and an internal saturated brine-injection strategy with which the produced brine is desalinated and reinjected into the same formation. The displacement strategies increase the storage efficiency from 0.48% for the bulk-injection case to more than 7%. A conceptual case study with documented aquifer properties of the Woodbine aquifer in Texas indicates that the available volume is sufficient to store all the CO 2 being generated by power plants in the vicinity for approximately 20 years only. However, the CO 2 /brine displacement increases storage efficiency enough to store the CO 2 produced for at least 240 years at the current rate of coal-fired electric-power generation. Sensitivity analyses on relative permeability, permeability, and temperature were conducted to see the effects of these reservoir parameters on storage efficiency.For bulk injection, increased permeability resulted in increased storage efficiency, but for the CO 2 /brine-displacement strategies, decreased permeability increased storage efficiency because this resulted in higher average pressure that increased CO 2 storage per unit of pore volume (PV) and increased CO 2 viscosity. Also, storage efficiencies for the displacement strategies were highly sensitive to relative permeability. There is an optimal CO 2 -injection temperature below which the formation-fracturing pressure is lowered and above which CO 2 breakthrough occurs for a smaller injection mass. The CO 2 /brine-displacement approach increased capital expenditures for additional wells and an operating expense for produced-brine disposal, but these additional costs are offset by increased CO 2 -storage efficiency at least 12 times that achieved by the bulk-injection strategy.