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dc.contributor.advisor Hirasaki, George J.
dc.contributor.advisor Miller, Clarence A.
dc.creatorSagi, Aparna Raju
dc.date.accessioned 2017-07-26T20:42:23Z
dc.date.available 2017-07-26T20:42:23Z
dc.date.created 2014-12
dc.date.issued 2015-02-03
dc.date.submitted December 2014
dc.identifier.citation Sagi, Aparna Raju. "Surfactant Enhanced Oil Recovery." (2015) Diss., Rice University. https://hdl.handle.net/1911/95525.
dc.identifier.urihttps://hdl.handle.net/1911/95525
dc.description.abstract The application of surfactants in Enhanced Oil Recovery (EOR) is the central theme of this thesis. The use of different EOR methods, thermal, gas flooding, surfactant flooding, etc. to improve the recovery of oil has become more relevant in recent years with the world’s demand for energy increasing, decreasing oil production from mature fields, and a lower than required rate of addition of new fields to make up for these two trends. Surfactants can be employed in EOR processes in three main ways: (1) to lower the Interfacial tension (IFT) between oil and brine to ultra-low values (lesser than 10-3 mN/m) which will reduce the capillary forces that trap the oil in the pores, and enable the oil to be produced by viscous of gravitational force, (2) by altering the wettability of the reservoir rock from being oil-wet to water-wet thereby resulting in the spontaneous imbibition of brine into the pores and the displacement of oil out of the pores, (3) as foam as to improve the reservoir sweep efficiency of other oil recovery methods like gas floods, surfactant floods, steam floods, etc. This thesis discusses the application of surfactants for a low IFT EOR process tailored to a low temperature (25 °C - 30 °C), low salinity (~11,000 ppm total dissolved solids (TDS) carbonate reservoir, and as a foam based mobility control agent for a miscible enriched hydrocarbon gas flood in a sandstone reservoir at high temperature (68 °C) and moderate salinity (~24,000 ppm TDS). Alcohol Propoxy (PO) Sulfates (APSs) and their blends with Internal Olefin Sulfonates (IOSs) were assessed by surfactant-brine-oil phase behavior studies to identify which of them formed stable aqueous solutions, and were capable of reducing IFT at the given conditions of temperature, salinity and crude oil. The selected surfactant was also evaluated in terms of viscosity of phases, to ensure that no high viscosity phases were formed, and in terms of adsorption on reservoir rock, which needs to be low for the process to be economical. Due to ease of handling initial phase behavior evaluation in this study and in a majority of such studies by others is done with dead crude oil (oil devoid of the light components which come out of the oil when depressurized to atmospheric pressure). But is known that surfactant phase behavior is highly dependent of the composition of the oil. To this end, experiments with live oil were carried out to determine the effect of different gases, methane, ethane, carbon dioxide, and separator gas, on surfactant phase behavior. Some surfactants that were evaluated exhibited non-classical phase behavior, i.e., they did not exhibit the classical Winsor phase transition of Type IType IIIType II, which is accompanied by an increasing oil solubilization parameter (σo) and decreasing water solubilization parameter (σw). These systems did not form a Type III system, and instead showed a Type IType II transition. Moreover, the σo (high σ is an indicator of low IFT) appeared to reach a peak and then decrease in the Type I region. The reasons behind these non-classical aspects of phase behavior were deciphered and are discussed in terms of surfactant partitioning and emulsion stability. In the last part of the thesis, Alpha Olefin Sulfonate (AOS) foam was studied for application in a miscible gas flood, on the principle that foam would form more preferentially in a high permeability low residual oil zone (swept zone), thereby reducing the gas mobility in this zone, resulting in the diversion of the gas to low permeability zones, and reduced bypassing of gas to the production well. AOS foam with nitrogen and enriched hydrocarbon gas at reservoir temperature (68 °C), and pressure (~3,300 psi) was evaluated in consolidated porous media (Berea cores), in terms of foam generation and propagation ability, and foam strength measured as gas apparent viscosity. The effect of miscible flood residual oil saturation on foam strength was evaluated to assess if strong foam could be generated in the presence of oil (which in some cases in known to destabilize foam).
dc.format.mimetype application/pdf
dc.language.iso eng
dc.subjectSurfactant
Ehanced Oil Recovery
Phase behavior
Foam
Live oil
partitioning
dc.title Surfactant Enhanced Oil Recovery
dc.contributor.committeeMember Biswal, Sibani L
dc.contributor.committeeMember Li, Qilin
dc.date.updated 2017-07-26T20:42:23Z
dc.type.genre Thesis
dc.type.material Text
thesis.degree.department Chemical and Biomolecular Engineering
thesis.degree.discipline Engineering
thesis.degree.grantor Rice University
thesis.degree.level Doctoral
thesis.degree.name Doctor of Philosophy
thesis.degree.major Chemical Engineering


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