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dc.contributor.authorLi, Zihaoen
dc.date.accessioned2019-02-02T09:01:19Zen
dc.date.available2019-02-02T09:01:19Zen
dc.date.issued2019-02-01en
dc.identifier.othervt_gsexam:18573en
dc.identifier.urihttp://hdl.handle.net/10919/87406en
dc.description.abstractConventional and unconventional reservoirs are both critical in oilfield developments. After waterflooding treatments over decades, the petrophysical properties of a conventional reservoir may change in many aspects. It is crucial to identify the variations of these petrophysical properties after the long-term waterflooding treatments, both at the pore and core scales. For unconventional reservoirs, the productivity and performance of hydraulic fracturing in shales are challenging because of the complicated petrophysical properties. The confining pressure imposed on a shale formation has a tremendous impact on the permeability of the rock. The correlation between confining pressure and rock permeability is complicated and might be nonlinear. In this thesis, a series of laboratory tests was conducted on core samples extracted from four U.S. shale formations to measure their petrophysical properties. In addition, a special 2D microfluidic equipment that simulates the pore structure of a sandstone formation was developed to investigate the influence of injection flow rate on the development of high-permeability flow channels. Moreover, the multiple linear regression (MLR) model was applied with the predictors based on the development stages to quantify the variations of reservoir petrophysical properties. The MLR model outcome indicated that certain variables were effectively correlated to the permeability. The 2D microfluidic model demonstrated the development of viscous fingering when the injection water flow rate was higher than a certain level, which resulted in reduced overall sweep efficiency. These comprehensive laboratory experiments demonstrate the role of confining pressure, Klinkenberg effect, and bedding plane direction on the gas flow in the nanoscale pore space in shales.en
dc.format.mediumETDen
dc.publisherVirginia Techen
dc.rightsIn Copyrighten
dc.rights.urihttp://rightsstatements.org/vocab/InC/1.0/en
dc.subjectrock propertiesen
dc.subjectin-lab experimenten
dc.subjectKlinkenberg effecten
dc.subjectmultiple linear regressionen
dc.titleUsing data analytics and laboratory experiments to advance the understanding of reservoir rock propertiesen
dc.typeThesisen
dc.contributor.departmentMining Engineeringen
dc.description.degreeMaster of Scienceen
thesis.degree.nameMaster of Scienceen
thesis.degree.levelmastersen
thesis.degree.grantorVirginia Polytechnic Institute and State Universityen
thesis.degree.disciplineMining Engineeringen
dc.contributor.committeechairChen, Chengen
dc.contributor.committeememberRipepi, Nino S.en
dc.contributor.committeememberSarver, Emily Allynen
dc.description.abstractgeneralConventional and unconventional hydrocarbon reservoirs are both important in oil-gas development. The waterflooding treatment is the injection of water into a petroleum reservoir to increase reservoir pressure and to displace residual oil, which is a widely used enhanced oil recovery method. However, after waterflooding treatments for several decades, it may bring many changes in the properties of a conventional reservoir. To optimize subsequent oilfield development plans, it is our duty to identify the variations of these properties after the long-term waterflooding treatments, both at the pore and core scales. In unconventional reservoirs, hydraulic fracturing has been widely used to produce hydrocarbon resources from shale or other tight rocks at an economically viable production rate. The operation of hydraulic fracturing in shales is challenging because of the complicated reservoir pressure. The external pressure imposed on a shale formation has a tremendous impact on the permeability of the rock. The correlation between pressure and rock permeability is intricate. In this thesis, a series of laboratory tests was conducted on core samples to measure their properties and the pressure. Moreover, a statistical model was applied to quantify the variations of reservoir properties. The results indicated that certain reservoir properties were effectively correlated to the permeability. These comprehensive investigations demonstrate the role of pressure, special gas flow effect, and rock bedding direction on the gas flow in the extremely small pore in shales.en


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