RESUMEN
Nowadays, high-phase-inversion in situ emulsification technology has shown great potential in enhancing oil recovery from high-water-cut thin-oil reservoirs. However, emulsification characteristics, interfacial properties, and the mechanism of high phase inversion have not been systematically described. In this study, an emulsification experiment was conducted to investigate the effects of shear time, shear rate, and temperature on the phase inversion of thin oil. Furthermore, the influence of resin and wax on the dispersion of asphaltene was studied through microscopic morphology analysis. Interfacial tension measurement and interfacial viscoelasticity analysis were carried out to determine the interaction characteristics of asphaltene, resin, and wax at the interface. The results showed that, at 50 °C, the phase-inversion point of thin oil reached as high as 75%, and even at 60 °C, it remained at 70%. The shear time and shear rate did not affect the phase-inversion point of thin oil, while an increase in temperature led to a decrease in the phase-inversion point. Moreover, compared to the 20% phase-inversion point of base oil, the phase-inversion point increased with different proportions of asphaltene, resin, and wax. Particularly, at the ratio of asphaltene/resin/wax = 1:5:9, the phase-inversion point reached as high as 80%, indicating the optimal state. In this proportion, asphaltene aggregates exhibited the smallest and most uniform size, best dispersion, lower interfacial tension, and higher interfacial modulus. These findings provide reference and guidance for further enhancing oil recovery in medium-to-high-water-cut thin-oil reservoirs.
RESUMEN
The structure of amphiphilic spherical brushes, consisting of the nano-SiO2 core, the hyperbranched polyamidoamine subshell, and a grafted layer of long hydrophobically modified polyacrylamide (HMPAM) chains, in aqueous solution was analyzed and described in the framework of the original mean-field approach. The scaling estimations of the hydrodynamic radius of such polymer brushes as a function of the number of grafted macromolecules allow concluding that the HMPAM shells are in a globular state and that the region of the stretched chains adjacent to the grafting surface is a minor part of the grafted macromolecules and does not have a significant impact on the self-assembly of the HMPAM shell caused by the complex hydrophobic-hydrophilic composition of their monomer units. In mean-field theory, the amphiphilic nature of HMPAM was taken into account by attaching the hydrophobic side group H to some fraction of monomer units of the hydrophilic P backbone. The strong attraction of H groups causes the aggregation of macromolecules, whereas the affinity of hydrophilic P groups to solvent forces the aggregates to increase their surface. Due to such effective surface activity, in poor solvent, the grafted amphiphilic macromolecules could form a spherical compacted structure around the nanoparticle or self-assemble into a "hedgehog" structure with several "spines" having hydrophobic core and hydrophilic shell. State diagrams, obtained theoretically, reveal that the "hedgehog" structure is preferable for a wide range of energetic parameters.
RESUMEN
On account of the intralayer and interlayer heterogeneity, high temperature (110 °C), and high salinity (224,919 mg/L) of Tahe channel sand reservoir, single profile control or chemical flooding cannot greatly enhanced oil recovery. The goal of the current research was to optimize a polymer gel formula that was suitable for high-temperature and high-salinity reservoirs, screen an appropriate chemical flooding method, and determine the efficiency of the combination of profile control and chemical flooding. Experimental results indicated that the formed polymer gel could maintain relatively high strength after aging for 30 days. Moreover, the combination of profile control and surfactant flooding could result in an enhanced oil recovery of 17.9%, and the combination of profile control and foam flooding could result in an enhanced oil recovery of 23.0%, which was ascribed to the improvement of sweeping efficiency and displacement efficiency. All the results indicated that the formed polymer gel and the combination of profile control and chemical flooding have great application potential in Tahe high-temperature and high-salinity channel sand reservoir.
