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dc.contributor.advisorZerpa, Luis E.
dc.contributor.authorRamirez, Alberto
dc.date.accessioned2018-01-11T16:39:44Z
dc.date.accessioned2022-02-03T13:00:59Z
dc.date.available2018-01-11T16:39:44Z
dc.date.available2022-02-03T13:00:59Z
dc.date.issued2017
dc.identifierRamirez_mines_0052N_11417.pdf
dc.identifierT 8418
dc.identifier.urihttps://hdl.handle.net/11124/172043
dc.descriptionIncludes bibliographical references.
dc.description2017 Fall.
dc.description.abstractPolymer injection is an enhanced oil recovery method based on the viscosity increase of the injected aqueous phase to control its mobility. The changes in mobility could affect the pore pressure distribution within the reservoir. The objective of this research work is investigating the effects of polymer injection on the geomechanical stress distribution within a reservoir. Specific objectives include sensitivity analysis of the polymer rheology to determine changes in reservoir stress magnitudes. A coupled fluid flow-geomechanics numerical reservoir simulator is used to investigate the effect of polymer rheology on the stress distribution and magnitude within a reservoir. A hypothetical reservoir model is developed considering a heterogeneous rock properties distribution. A combination of water injection and polymer injection treatments is modeled at different injection rates. For the sensitivity analysis, the effective mean stress changes are compared at different times during the process. Maximum and minimum stresses are used to determine the rock failure criteria at different polymer viscosities and injection rates. We determine the rock failure criteria using the Mohr-Coulomb failure envelope. Water injection efficiency, in terms of oil recovery, increased after the first polymer injection treatment. During polymer injection, effective mean stress increased with time. Compared to the effective mean stress during water injection, polymer injection mean effective stress showed higher values in most cases. At depths where there was high water saturation, the pore pressure was higher causing the decrease of effective mean stress at that time. At a higher polymer injection rate, on average, the effective means stress increases fifty percent at the less water saturated zones. At the high pore pressure zone, the increase in effective mean stress was not as high with the second polymer injection compared with the first one. The maximum stress values decreased with time. Stress magnitudes were affected by both water injection and polymer injection. Their behavior has similar tendencies when compared to reservoir depths. Changes in the stress magnitudes will cause rock failure at different viscosities. Results from this study provide insight on the changes of stress magnitudes of the rock expected during polymer injection. The results and observations presented in this work could lead to feasibility assessment, development and design of monitoring technologies for estimation of polymer slug location, and provide means for estimating of the EOR treatments efficiency.
dc.format.mediumborn digital
dc.format.mediummasters theses
dc.languageEnglish
dc.language.isoeng
dc.publisherColorado School of Mines. Arthur Lakes Library
dc.relation.ispartof2010-2019 - Mines Theses & Dissertations
dc.rightsCopyright of the original work is retained by the author.
dc.subjectgeomechanics
dc.subjectstress distribution
dc.subjectpolymer injection
dc.subjectchemical enhanced oil recovery
dc.titleNumerical investigation of polymer injection effects on geomechanical reservoir properties during enhanced oil recovery
dc.typeText
dc.contributor.committeememberYin, Xiaolong
dc.contributor.committeememberDean, Elio
thesis.degree.nameMaster of Science (M.S.)
thesis.degree.levelMasters
thesis.degree.disciplinePetroleum Engineering
thesis.degree.grantorColorado School of Mines


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