A novel ASP flood design for CO₂ contaminated sandstone reservoirs at low salinity and low permeability

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dc.contributor.advisorNguyen, Quoc P.
dc.creatorNguyen, Vu Quoc
dc.date.accessioned2017-06-15T22:16:48Z
dc.date.available2017-06-15T22:16:48Z
dc.date.issued2016-12
dc.date.submittedDecember 2016
dc.date.updated2017-06-15T22:16:49Z
dc.description.abstractASP flooding relies the ability of surfactant to reduce the oil-water inter facial tension (IFT) and to alter the wettability towards water-wet conditions in order to promote oil mobilization. During this process surfactants must show long term stability under reservoir conditions as well as low adsorption on to the rock surface. Surfactant screening is particularly challenging for low salinity formation brines with low target salinity injection brine since most commercially available surfactants show optimum salinity ranges above 3 wt% total dissolved solid (TDS). A series of propylene oxide (PO) sulfate surfactants, internal olefin sulfonates (IOS), and alkyl benzene sulfonates (ABS) have been used for surfactant screening. Co-solvents were incorporated to improve aqueous stability of the surfactant mixture, reduce equilibration time, and minimize formation of viscous phases. More than 300 phase behavior scans were performed in order to optimize a chemical formulation for optimum salinity within a range of 1.0 to 2.0 wt% TDS. PO surfactant formulations show viscous oil-water microemulsion, and thus does not meet our criteria due to high surfactant retention. Therefore, PO formulations were not selected for coreflood experiments. ABS and IOS surfactant combination shows the optimum salinity in the desired range and Winsor Type III microemulsion which has low interfacial tension with oil and water within the Type III region. In addition, viscous emulsions were not observed over an incubation period of 60 days. This combination of surfactants has the ability to tune the optimum salinity within the range by changing the ratio of two surfactants. A Na2CO3 preflood was introduced before slug injection to neutralize the acidic nature of the core. ABS and IOS were blended at a 7:3 ratio in the surfactant slug based on our findings from our phase behavior study. Co-solvent (Butoxypolyglycol Basic) was added at 1.0 wt% concentration to achieve suitable low IFT conditions and less viscous microemulsions. We have conducted more than 20 corefloods using the above surfactant combination and with our final optimized coreflood yielding 98% oil recovery with 0.6% S [subscript orc].
dc.description.departmentPetroleum and Geosystems Engineering
dc.format.mimetypeapplication/pdf
dc.identifierdoi:10.15781/T2Q52FJ9Z
dc.identifier.urihttp://hdl.handle.net/2152/47243
dc.language.isoen
dc.subjectASP
dc.subjectCO₂
dc.subjectASP flooding
dc.subjectASP flood design
dc.subjectContaminated reservoirs
dc.subjectSandstone reservoirs
dc.subjectSurfactant screening
dc.subjectOil recovery
dc.subjectOil mobilization
dc.subjectOptimum salinity
dc.subjectSurfactant formulations
dc.subjectCorefloods
dc.titleA novel ASP flood design for CO₂ contaminated sandstone reservoirs at low salinity and low permeability
dc.typeThesis
dc.type.materialtext
thesis.degree.departmentPetroleum and Geosystems Engineering
thesis.degree.disciplinePetroleum Engineering
thesis.degree.grantorThe University of Texas at Austin
thesis.degree.levelMasters
thesis.degree.nameMaster of Science in Engineering

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