| dc.description.abstract | This dissertation is on measuring the permeability of the unconventional rock samples in the laboratory in order to understand the flow of single-phase and multi-phase fluids in these rocks. Steady-state flow measurements using Darcy law are time-consuming and impractical for the estimation of the permeability; therefore, I used pressure pulse decay method based on analytical numerical solutions to the diffusivity equation is used. It consists of three major parts of investigation.
In the first part, stress-dependence of the permeability of the unconventional rock samples are shown during single-phase (gas) flow measurements. Downhole core plugs from Eagle Ford, Bakken, and Barnett formation and split core plugs of the same formation in presence of mono-layer microproppants are investigated. An analytical permeability model is developed for the investigation, including the interactions between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of shale samples with propped fracture. The analysis provides the propped fracture permeability of the samples and predicts a parameter related to the quality of the proppant placement and areal distribution in the fracture. The proppant-placement quality can be used as a measure of success of the delivery of proppants into the fractures and creation of permeability in the laboratory.
In the second part, sacrificial fluids that have amplified interactions with the organic material in the unconventional rock samples, such as CO2, are considered for enhanced hydrocarbon production and CO2 sequestration. I analyzed in the laboratory the CO2 injection, transport and storage of an unconventional rock sample. I measure the free and adsorbed methane and CO2 storage capacity of these rocks. The results indicate that CO2 has significantly larger adsorption capacity compared to methane and can be used for enhanced shale-gas recovery. The results also show that the depleted shale-gas reservoirs could be alternative locations for CO2 sequestration. However, geomechanical behavior of the rock under confining pressure indicates that the injectivity of the wells due to fractures closing will be significantly lower than their productivity observed during the primary depletion. I show the impact of fracture closure stress on the CO2 injection using a geomechanically coupled compositional flow simulator with the reservoir parameter values obtained in the laboratory.
In the last part of the dissertation, I present a new novel approach to determine relative permeability of two phase (liquid-gas) flow using the established pulse decay method. In this new laboratory method, prior to the pressure pulse, the saturations in the sample are established at the desired levels using the phase diagram of a binary hydrocarbon mixture. The effective permeability for each phase is analyzed under stress and in the presence of capillary pressure effects on the phase diagram and on two-phase flow. For the analysis, I used a simulation-based history-matching and calibration approach. The simulator considers phase change in the presence of capillary pressure and interface curvature effects. The results indicate that the new method can be used to construct the relative permeability curves of oil/gas flow systems reasonably fast compared to the steady-state flow method. | |
