The experimental study presented in this thesis was designed and conducted to determine the mechanisms of gas injection enhanced oil recovery (EOR) at the pore-scale level in low permeability shale reservoirs. Two separate sets of experiments were conducted. The first set pertained to depletion drive and second set pertained to gas injection EOR. In both cases, the experiments consisted of pore fluid compression-decompression laboratory experiments (1) in ultratight Wolfcamp carbonate shale outcrop, (2) siliciclastic formation cores from U.S. Permian Basin, and (3) stacked porous ceramic and Teflon discs as synthetic analogs to shale. The oil used in the experiments was n-dodecane (n-C12H26) with API gravity of 57. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium, nitrogen, methane, and methane-carbon dioxide gas mixtures into unfractured and fractured cores, followed by depressurization. Using the oil recovery volumes from cores with a different number of fractures, we quantified the effect of fracture distribution intensity on oil recovery—both for shale and synthetic cores. We also observed that the amount of oil recovered was significantly affected by the pore network complexity and pore-size distribution.
Laboratory EOR tests were conducted at pore pressure of 1500 psia and a temperature of 160 °F using a unique core flooding apparatus capable of measuring small effluent oil volumes of 1 cm3 or less. The laboratory procedure consisted of (1) injecting pure n-dodecane into a vessel containing a core that had been moistened hygroscopically and evacuated and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to the laboratory conditions. Thus, the gas injection EOR is a ‘huff-and-puff’ process.
Light oil recovery from primary production (liquid-expansion-drive) from fractured, ultratight Wolfcamp carbonate outcrop cores and fractured Wolfcamp siliciclastic reservoir cores were 5.6 and 6.3 percent of the initial oil in place (IOIP) which compares with 3.6 percent of the IOIP from fractured synthetic porous media. After injecting carbon dioxide and methane gas mixtures, the EOR oil recovery by fluid expansion drive increased to 14.8 and 15.2 percent of the IOIP in fractured Wolfcamp carbonate outcrop cores and fractured Wolfcamp siliciclastic reservoir cores. In contrast, such gas injection EOR was considerably smaller in stacked synthetic porous media (8.2 percent of the IOIP) than in shale cores. Wolfcamp carbonate cores with no fractures yielded 7.1 percent of the IOIP compared to the case of one fracture and two fractures which produced 11.9 and 17.6 of the IOIP. Furthermore, more EOR oil was produced by increasing the CO2 fraction in the injection gas mixture in these unfractured and fractured carbonate cores.
The volume of the fluid-expansion-drive produced oil from fractured Wolfcamp core was 0.42 cm3 based on the initial oil in place of 362 cm3. Similarly, the fluid-expansion-drive produced oil was 7 cm3 from the initial oil in place of 328 cm in fractured synthetic porous media. Thus, synthetic cores did not necessarily represent shale cores under expansion drive and gas injection EOR because of pore structure and pore volume differences; however, these experiments provided a foundation to quantify the oil recovery mechanism of an expansion drive in shale reservoirs.
This research provides a basis for interpreting core flooding oil recovery results under expansion drive and gas injection EOR—both in the presence and absence of interconnected micro-and macro-fractures in the flow path. The CO2 injection results of this thesis provide an estimate of the amount of sequestered CO2 in the reservoir oil; however, future core pressurization-depressurization studies should include brine in cores to quantify the amount
of sequestered CO2 in formation oil, brine, and rock matrix.