RESUMO
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.
RESUMO
Emulsification flooding can effectively enhance crude oil recovery to solve the problem of petroleum shortage. In this work, a modified Janus Nano Calcium carbonate (JNC-12) with a particle size of 30-150 nm was synthesized, and an in situ emulsification nanofluid (ISEN) was prepared with JNC-12 and alkyl polyglycoside (APG). Scanning electron microscope (SEM) showed that the dispersion of JNC-12 in air or APG solution was better than Nano Calcium carbonate (Nano CaCO3). The emulsification properties, interfacial tension, and expansion modulus of ISEN were studied, and the result showed that with the increase in salinity, the emulsification rate decreased, the water yield rate increased, the interfacial tension first decreased and then increased, and the expansion modulus first increased and then decreased. With the increase in temperature, the emulsification rate, emulsion viscosity, and interfacial tension decreased. With the increased oil-water volume, the water yield rate and the emulsion viscosity increased. With increase in the concentration of JNC-12, the water yield rate, the emulsion viscosity, and the interfacial tension decreased but the expansion modulus increased. The emulsion generated by emulsifying ISEN with crude oil was an O/W emulsion, the crude oil viscosity was 4-10 times that of emulsion, and the average particle size of emulsion was 1.107 µm. The addition of ISEN caused the decrease in interfacial tension of oil-water to 0.01-0.1 mN/m. The wettability alteration experiment found that ISEN could change the lipophilic rock to hydrophilic rock. Finally, the core displacement experiments showed that compared with the first water flooding, the oil recovery of the second water flooding after ISEN flooding enhanced by 17.6%. This research has important guiding significance for in situ emulsified nanofluid flooding to enhance oil recovery.
RESUMO
Carbon dioxide (CO2) flooding is a promising method for developing low-permeability heterogeneous glutenite reservoirs (LPHGRs) featured with low natural energy. Herein, the focus of this work was to study the microscopic oil displacement mechanism of CO2 in LPHGRs. First, the micropore structure and mineral composition of LPHGRs were analyzed, and the effect of CO2 on low-permeability reservoirs was then studied. Also, the mechanism of CO2 displacement in low-permeability reservoirs on a pore scale was analyzed using nuclear magnetic resonance technology in different dimensions. The experimental results showed that the mineral composition of the rock mainly included quartz, feldspar, and clay minerals. The core pores were poorly developed and highly heterogeneous. The clay and other mineral particles produced by the dissolution reaction of rocks and minerals migrated and deposited with formation fluid to damage the reservoir. On the contrary, it also improved the pore structure, increased pore space, and increased reservoir permeability. The miscible interaction between CO2 and crude oil formed a stable displacement front, which enabled crude oil to be well displaced from the macropores and medium pores. However, this interaction generated negligible effects on the small pores. The experimental results provided important indicators for CO2 development in LPHGRs.
RESUMO
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.