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dc.contributor.advisorKazemi, Hossein
dc.contributor.authorKamruzzaman, Asm
dc.date.accessioned2023-04-26T17:30:51Z
dc.date.available2023-04-26T17:30:51Z
dc.date.issued2022
dc.identifierKamruzzaman_mines_0052E_12505.pdf
dc.identifierT 9445
dc.identifier.urihttps://hdl.handle.net/11124/176602
dc.descriptionIncludes bibliographical references.
dc.description2022 Fall.
dc.description.abstractThe experimental study presented in this thesis was designed and conducted to determine the mechanisms of gas injection enhanced oil recovery (EOR) in low permeability, fractured, and unfractured shale and synthetic cores (ceramic and thermoplastic). The ultimate goal was to understand the mechanism of gas injection and oil recovery in natural shale reservoirs. Two separate sets of experiments were conducted. The first set pertained to depletion drive, and the second set pertained to gas-injection EOR. In both cases, the experiments consisted of pore fluid compression-decompression laboratory experiments in ultratight Wolfcamp shale (carbonate outcrop cores and siliciclastic formation cores from U.S. Permian Basin) and stacked porous ceramic and thermoplastic discs as synthetic analogs to shale. The oil used in the experiments was n-dodecane (n-C12H26) with an API gravity of 57. The EOR assessment strategy involved determining the quantity of oil produced after injection of the following gases—methane, helium, nitrogen, or a mixture of methane-carbon dioxide in separate experiments. The experiments were conducted in unfractured and fractured cores for each gas, 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 observed that the amount of oil recovered was significantly affected by the total fracture surface areas, pore-size distribution, and the pore-network tortuosity. All 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 evacuated and moistened hygroscopically; then raising fluid pressure to 1500 psia 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 pressure and temperature conditions. This gas-injection oil recovery strategy is known as the ‘huff-and-puff’ process. The amount of n-dodecane produced by fluid expansion drive (i.e., primary production) from fractured, ultratight Wolfcamp carbonate outcrop cores and fractured Wolfcamp siliciclastic reservoir cores were 5.6 and 6.3 percent of the initial n-dodecane (oil) in place (IOIP), which compared 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 the subsequent 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, respectively. In contrast, oil recovery by carbon dioxide and methane gas mixture injection into stacked synthetic discs yielded 8.2 percent of the IOIP. Identical experiments with 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 percent of the IOIP. Furthermore, more EOR oil was produced by increasing the CO2 fraction in the injection gas mixture in the fractured and unfractured cores. Synthetic cores, with larger pore volumes than shale cores, did not replicate the magnitude of the shale core oil recoveries under expansion drive and gas injection EOR. We attribute this to the nature of pore structure connectivity and wettability differences. Nonetheless, synthetic core experiments provided great insight into oil recovery because of differences in pore structure, pore-size distribution, and wettability. The results of this research provide a basis for understanding oil recovery under expansion drive and gas injection EOR—both in the presence and absence of interconnected micro-and macro-fractures. Furthermore, we recommend that future core pressurization-depressurization studies include irreducible brine to mimic a natural petroleum reservoir environment and assess the amount of sequestered CO2 in formation oil, formation brine, and rock matrix.
dc.format.mediumborn digital
dc.format.mediumdoctoral dissertations
dc.languageEnglish
dc.language.isoeng
dc.publisherColorado School of Mines. Arthur Lakes Library
dc.relation.ispartof2022 - Mines Theses & Dissertations
dc.rightsCopyright of the original work is retained by the author.
dc.subjectenhanced oil recovery (EOR)
dc.subjectfractured rock
dc.subjectgas injection
dc.subjectPermian shale
dc.subjectsynthetic porous media
dc.subjectunconventional shale
dc.titleLaboratory assessment of gas injection enhanced oil recovery (EOR) in low permeability shales
dc.typeText
dc.date.updated2023-04-22T22:10:25Z
dc.contributor.committeememberYin, Xiaolong
dc.contributor.committeememberOzkan, E.
dc.contributor.committeememberSonnenberg, Stephen A.
dc.contributor.committeememberKneafsey, Timothy
dc.contributor.committeememberTura, Ali
thesis.degree.nameDoctor of Philosophy (Ph.D.)
thesis.degree.levelDoctoral
thesis.degree.disciplinePetroleum Engineering
thesis.degree.grantorColorado School of Mines


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