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dc.contributor.advisorDaigle, Hughen
dc.creatorAhmad, Yusra Khanen
dc.date.accessioned2015-10-29T15:28:42Zen
dc.date.available2015-10-29T15:28:42Zen
dc.date.issued2015-08en
dc.date.submittedAugust 2015en
dc.identifierdoi:10.15781/T24C84en
dc.identifier.urihttp://hdl.handle.net/2152/32048en
dc.descriptiontexten
dc.description.abstractTransport of emulsions through porous media has the ability to play a significant role in many EOR processes. Nanoparticles can act as efficient emulsifying agents, producing emulsions that can improve sweep efficiencies leading to improved oil recoveries. This thesis has explored emulsion stability and flow through porous media whilst also assessing emulsion capabilities in residual oil recovery. Hydrophilic nanoparticle-stabilized oil-in-water emulsions of two different average droplet sizes were injected into hydrophobic beadpacks of varying bead size diameters. The smaller sized emulsion appeared to be more stable in its properties, more frequently being regenerated in the effluent in comparison to the larger droplet sized emulsion. With a decrease in bead diameter, the smaller droplet sized emulsion could not survive passage with regeneration. Smaller bead pack sizes also did not allow passage of the less stable emulsions with larger droplet sizes. The fastest emulsion regeneration was seen for emulsions with small droplet sizes through a beadpack of larger sized beads. Through the largest bead sized beadpack, small amounts of the less stable emulsion were seen to be regenerated but much later in the life of the experiment. Higher flow rates were able to regenerate emulsion for smaller droplet sizes but were unable to do so for the less stable larger sized emulsion. Pressure profiles appeared to similar for most runs where approximately the first 0-10 pore volumes show the greatest pressure buildup followed by what appears to be a more stable and slower increase in pressure. Coreflood experiments were performed to assess residual oil recovery for various oil-in-water emulsions. Higher percentage recoveries were seen to be dependent on a few leading factors. For more viscous, stable emulsions, it appeared that lower flow rates lead to higher percentage recoveries. At lower flow rates, no emulsion would also be produced in the effluent for the duration of the experiment. As pressure profiles were seen to increase throughout the experiment, attempted coalescence and regeneration were likely taking place. However, as regeneration was less successful, complete coalescence might be the reason for increased miscibility in the core, leading to higher recovery potentials. Encouraging recoveries were seen when a more viscous stable emulsion was used to recover residual oil less viscous than that of the continuous oil in the emulsion. Increasing the slug size of the emulsion injected helped recover more residual oil. Increasing the slug size however is only advantageous up till a limiting value where the injected emulsion slug would produce the same result as injected emulsion continuously through the sandstone core. Where enough emulsion was injected and therefore available inside the core, emulsion regeneration was seen. Lighter organic phases in emulsion form were used for oil recovery coreflood experiments. Similar to experiments performed with heavier organic phases in emulsion form i.e. mineral oil-in-water emulsion, octane-in-water emulsion was also not regenerated for low flow rates, completely coalescing inside the sandstone core. For higher flow rates, small amounts of octane emulsion were regenerated. In this case, similar to that of the mineral oil emulsion, increasing the flow rate seemed to have a negative effect on the percentage oil recovery. Surfactant stabilized octane-in-water emulsions showed the highest amount of percentage residual oil recovery. The pressure plot of these emulsions was different to those of nanoparticle stabilized emulsions where although the initial pressure increase matched up with the movement of the oil bank through the core, the latter part of the pressure profile appeared to decrease. This pressure profile was seen in both cases where the octane emulsion was injected into a fully brine saturated core as well as a core at residual oil saturation. It is interesting to note, however that surfactants by themselves are not capable of recovering any residual oil. It is only in emulsion form that this recovery is possible. Pentane-in-water emulsions were not seen to be stable for days unlike the other emulsions stated above. This was due to partial and continuous evaporation of pentane from the emulsion form at room temperature and pressure. When pressurized to 100 psi, however, the emulsion was seen to be stable for a number of days. All experiments were performed at high flow rates however emulsion was not seen to be regenerated in the effluent. This would suggest a lack of stability of the emulsion. Due to complete coalescence of the emulsion inside the core, miscibility would increase and this might be a reason for the higher percentage recoveries. Pressure profiles seemed to mimic all other oil-in-water emulsion injection experiments to sandstone cores at residual oil saturation.en
dc.format.mimetypeapplication/pdfen
dc.language.isoenen
dc.subjectNanoparticleen
dc.subjectResidual oil recoveryen
dc.subjectEmulsionen
dc.titleNanoparticle stabilized oil-in-water emulsions for residual oil recoveryen
dc.typeThesisen
dc.date.updated2015-10-29T15:28:42Zen
dc.contributor.committeeMemberHuh, Chunen
dc.description.departmentPetroleum and Geosystems Engineeringen
thesis.degree.departmentPetroleum and Geosystems Engineeringen
thesis.degree.disciplinePetroleum engineeringen
thesis.degree.grantorThe University of Texas at Austinen
thesis.degree.levelMastersen
thesis.degree.nameMaster of Science in Engineeringen
dc.creator.orcid0000-0001-9608-5886en


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