Evaluation of lean and rich gas injection for improved oil recovery in hydraulically fractured reservoirs

dc.contributor.advisorSharma, Mukul M.
dc.contributor.committeeMemberLake, Larry
dc.contributor.committeeMemberDaigle, Hugh
dc.contributor.committeeMemberOkuno, Ryosuke
dc.contributor.committeeMemberGao, Bo
dc.creatorOzowe, Williams Osagie
dc.date.submittedMay 2021
dc.description.abstractEstimating improvements in oil recovery in shales can be difficult, because of their ultra-low permeability - often in the nanodarcy range. In addition, poroelastic changes occurring within the reservoir during production, have a direct impact on porosity and flow paths. Recovery estimates from simulations are imprecise, because inaccurate capillary pressure curves and liquid permeability estimates are often used for forecasting. This work presents a new method to measure liquid saturation and capillary pressure in shales, by integrating the time-dependent pressure drop data observed within the bulk liquid phase, when a shale sample is under liquid pressure. This work also presents an experimental method to estimate liquid permeability in shale, by using the early time portion of the liquid pressure decay data - that has been corrected for temperature effects – to estimate diffusivity, via a graphical approach that approximates the solution of the radial diffusivity equation coupled with the mass balance equation. In unconventional reservoirs it is quite common to experience a rapid decline in production and reservoir pressure during primary production. For this reason, operators have sought to find ways to improve oil recovery via cyclic gas injection in shale reservoirs. To achieve this, it is important to understand the role of fluid compressibility, miscibility, soak time and injection pressure on oil recovery. The choice of these parameters can have a significant impact on recovery factor, the produced gas-oil ratio and economic viability. This work presents results from an experimental study of these properties on Eagle Ford core plugs and crushed samples, via the injection of liquid and gaseous recovery agents at room temperature. Results show that gaseous solvents perform better than liquid solvents and oil recovery increases with injection pressure, and with increasing surface area to volume ratio of the shale samples. To better understand the role of poroelastic changes on oil recovery, cyclic gas injection simulations were conducted in the Eagle Ford shale using a fully coupled compositional, geomechanical hydraulic fracturing and reservoir simulator. Results obtained show that effective stress changes occurring during injection and production cycles in the stimulated reservoir volume results in a decrease in reservoir permeability, and this reduces oil recovery. Also, simulation results between miscible and immiscible gases show that immiscible gases yield lower oil recovery factors and higher gas-oil ratios, than more miscible gases. Finally, from simulation studies carried out for the Bakken and Wolfcamp shales, it was observed that increasing the mole fraction of the heavier molecular weight hydrocarbon gases in the injection gas improves miscibility with the reservoir fluid, and increases oil recovery. Additional results show that this enhanced degree of miscibility of the injection gas with the reservoir fluid, was not impacted by the substitution of low molecular weight hydrocarbons for carbon dioxide in a hybrid injection gas mixture.
dc.description.departmentPetroleum and Geosystems Engineering
dc.subjectOil recovery
dc.subjectCyclic gas injection
dc.subjectCapillary pressure
dc.titleEvaluation of lean and rich gas injection for improved oil recovery in hydraulically fractured reservoirs
thesis.degree.departmentPetroleum and Geosystems Engineering
thesis.degree.disciplinePetroleum Engineering
thesis.degree.grantorThe University of Texas at Austin
thesis.degree.nameDoctor of Philosophy

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