Characterization and Construction of 3D Numerical Simulators for Oil and Liquids-Rich Multi-Porosity Shale Reservoirs

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atmire.migration.oldid5641
dc.contributor.advisorAguilera, Roberto
dc.contributor.authorLopez Jimenez, Bruno Armando
dc.contributor.committeememberMehta, Sudarshan A.
dc.contributor.committeememberMoore, Robert Gordon
dc.contributor.committeememberHarding, Thomas Grant
dc.contributor.committeememberBentley, Laurence Robert
dc.contributor.committeememberCamacho-Velazquez, Rodolfo
dc.date.accessioned2017-05-30T17:40:00Z
dc.date.available2017-05-30T17:40:00Z
dc.date.issued2017
dc.date.submitted2017en
dc.description.abstractProduction from oil and shale gas-condensate reservoirs in the United States and Canada has increased during the past few years. However, an understanding of shale rocks and fluid flow through them is still limited. Thus, the objective of this research is to develop methodologies for characterizing multi-porosities in shale petroleum reservoirs and for simulating fluid flow of oil and condensates through these types of rocks. The characterization part is carried out with the use of (1) an original petrophysical model built for quantification of total organic carbon (TOC), Knudsen number, water saturation, and multiple porosities in shales, (2) measurement of gas permeability from shale samples in the laboratory using commercial equipment, and (3) an original laboratory-based correlation for estimating stress-dependent permeability, porosity and compressibility of tight rocks. The simulation part is carried out with the use of (1) an original radial numerical model developed for calculating sorption-dependent permeability of shales, (2) a commercial 3D model for investigating pore size-dependency of pressure-temperature envelopes in shale gas-condensate reservoirs, and (3) an original fully-implicit 3D-3phase pseudo-compositional model for oil and condensate shale reservoirs developed with capabilities to handle multiple porosities and stress-dependent properties of natural and hydraulic fractures. Key challenges include the handling of (1) adsorbed porosity, (2) organic porosity, (3) inorganic porosity, (4) natural fracture porosity, (5) hydraulic fracture porosity, (6) diffusion from solid kerogen, and (7) fluid transport in the small pores of shales, which deviate significantly from the behavior in conventional reservoirs. It is concluded that the methods developed in this thesis provide important foundation for the characterization and simulation of shale petroleum reservoirs.en_US
dc.identifier.citationLopez Jimenez, B. A. (2017). Characterization and Construction of 3D Numerical Simulators for Oil and Liquids-Rich Multi-Porosity Shale Reservoirs (Doctoral thesis, University of Calgary, Calgary, Canada). Retrieved from https://prism.ucalgary.ca. doi:10.11575/PRISM/25260en_US
dc.identifier.doihttp://dx.doi.org/10.11575/PRISM/25260
dc.identifier.urihttp://hdl.handle.net/11023/3847
dc.language.isoeng
dc.publisher.facultyGraduate Studies
dc.publisher.institutionUniversity of Calgaryen
dc.publisher.placeCalgaryen
dc.rightsUniversity of Calgary graduate students retain copyright ownership and moral rights for their thesis. You may use this material in any way that is permitted by the Copyright Act or through licensing that has been assigned to the document. For uses that are not allowable under copyright legislation or licensing, you are required to seek permission.
dc.subjectGeology
dc.subjectEngineering--Petroleum
dc.subject.otherQuintuple porosity system
dc.subject.otherDiffusion from solid kerogen
dc.subject.otherLiquids-rich shale reservoirs
dc.subject.otherAdsorption
dc.subject.otherOrganic porosity
dc.titleCharacterization and Construction of 3D Numerical Simulators for Oil and Liquids-Rich Multi-Porosity Shale Reservoirs
dc.typedoctoral thesis
thesis.degree.disciplineChemical and Petroleum Engineering
thesis.degree.grantorUniversity of Calgary
thesis.degree.nameDoctor of Philosophy (PhD)
ucalgary.item.requestcopytrue
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