Spontaneous Imbibition Studies in Shale Gas Reservoirs: Insight into Origins of High Salinity Flowback Water

dc.contributor.advisorHathon, Lori A.
dc.contributor.committeeMemberMyers, Michael T.
dc.contributor.committeeMemberEhlig-Economides, Christine
dc.contributor.committeeMemberLapen, Thomas J.
dc.contributor.committeeMemberTorres-Verdín, Carlos
dc.creatorPalencia Hernandez, Clara
dc.creator.orcid0000-0003-2857-0796
dc.date.accessioned2022-06-17T21:03:27Z
dc.date.createdDecember 2021
dc.date.issued2021-12
dc.date.submittedDecember 2021
dc.date.updated2022-06-17T21:03:28Z
dc.description.abstractAlthough hydraulic fracturing fluid is typically fresh water, in shale gas reservoirs, produced water or flowback, is often very saline. This observation suggests that flowback water is gaining salt from the formation. It is not currently known whether the recovered salt comes from dissolution of mineral salts, or interaction between bound water and frac fluid. In the absence of flowback water data, spontaneous imbibition experiments, can provide insight into the physics that governs the principal controls on flowback water salinity. This is the primary objective of this research. In addition, imbibition experiments can be related to clay mineral content (brittleness), total porosity, the relative volume of mineral hosted (water wet) and organic matter hosted (hydrocarbon wet) pore systems, and the in-situ pore fluid salinity. We propose to show that through the use of a novel multidisciplinary experimental approach the origin of high salinity flow back waters in shale reservoirs can be understood. Dual spontaneous imbibition (water and oil), ion expulsion experiments and sample characterization are combined to develop rock properties models. These techniques provide insight into effective characteristic time to reach equilibrium in salinity and imbibed volume, anticipated magnitude of flowback salinity, total porosity and clay mineral content for shale reservoirs. Experimental and modelling results suggest that the summation of the equivalent NaCl in the fluid due to anhydrite (salt dissolution) plus the equivalent NaCl due to the presence of clay minerals, result in the high salinity water associated with the Haynesville, Bossier and the La Luna Formations. Cation exchange capacity and salt volumes from geochemical analysis of equilibrated fluids obtained from imbibition experiments, might be used as a proxy to predict flowback salinity. Imbibition experiment provides a promising technique for estimating organic porosities in gas shale reservoirs and it could provide a basis for a possible GRI total porosity measurement correction, particularly in high carbonate content rocks.
dc.description.departmentPetroleum Engineering, Department of
dc.format.digitalOriginborn digital
dc.format.mimetypeapplication/pdf
dc.identifier.urihttps://hdl.handle.net/10657/9255
dc.language.isoeng
dc.rightsThe author of this work is the copyright owner. UH Libraries and the Texas Digital Library have their permission to store and provide access to this work. Further transmission, reproduction, or presentation of this work is prohibited except with permission of the author(s).
dc.subjectImbibition, petrophysic, shale gas, unconventional, salinity, flowback
dc.titleSpontaneous Imbibition Studies in Shale Gas Reservoirs: Insight into Origins of High Salinity Flowback Water
dc.type.dcmiText
dc.type.genreThesis
dcterms.accessRightsThe full text of this item is not available at this time because the student has placed this item under an embargo for a period of time. The Libraries are not authorized to provide a copy of this work during the embargo period.
local.embargo.lift2023-12-01
local.embargo.terms2023-12-01
thesis.degree.collegeCullen College of Engineering
thesis.degree.departmentPetroleum Engineering, Department of
thesis.degree.disciplinePetroleum Engineering
thesis.degree.grantorUniversity of Houston
thesis.degree.levelDoctoral
thesis.degree.nameDoctor of Philosophy

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