“…4 a, the adsorption capacity of Cd rises proportionally with the initial concentration. Such a phenomenon can be attributed to a more significant amount of Cd in the solution, which implies the increase in driving force for the mass transfer of Cd to the surface of BZ and NaBZ [ [50] , [51] , [52] ]. Fig.…”
Section: Resultsmentioning
confidence: 99%
“…In addition, the Freundlich adsorption parameters show that the K F value is higher in Cd adsorption on NaBZ than on BZ, indicating that the maximum amount of adsorption is higher on NaBZ than on BZ [ 52 ]. Additionally, the parameter of 1/n and K L indicates the adsorption intensity, if the values of 1/n are less than 1 the adsorption is favorable.…”
“…4 a, the adsorption capacity of Cd rises proportionally with the initial concentration. Such a phenomenon can be attributed to a more significant amount of Cd in the solution, which implies the increase in driving force for the mass transfer of Cd to the surface of BZ and NaBZ [ [50] , [51] , [52] ]. Fig.…”
Section: Resultsmentioning
confidence: 99%
“…In addition, the Freundlich adsorption parameters show that the K F value is higher in Cd adsorption on NaBZ than on BZ, indicating that the maximum amount of adsorption is higher on NaBZ than on BZ [ 52 ]. Additionally, the parameter of 1/n and K L indicates the adsorption intensity, if the values of 1/n are less than 1 the adsorption is favorable.…”
“…It provides insights into the physical properties of the interfacial layer, such as its elasticity and resistance to deformation. While analyzing the concentration changes of surfactants in simulated oils using UV–vis absorption spectroscopy is a direct method to detect the adsorption–diffusion behavior of surfactants, it may not be accurate for asphaltene, as it belongs to a mixture, and its adsorption at the oil–water interface is difficult to accurately measure. Therefore, in this study, dynamic interfacial tension measurements were employed as an indirect approach to capture the adsorption behavior of natural surfactants, including asphaltene, at the oil–water interface.…”
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 phaseinversion 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.
“…Nanoemulsion (NE) is selected as the chemical additive for the injection fluid, which mainly consists of mixed surfactants (nonionic and anionic surfactant), cosurfactants (low carbon number alcohol), and oil phase (terpenoids). The details of the production method can be referred to in our previous studies [35,36].…”
The well productivity of high-waxy reservoirs is highly influenced by temperature changes. A decrease in temperature can cause the precipitation of wax from the crude oil, leading to a decrease in the formation’s drainage capacity and a drop in oil production. In this study, the wax precipitation of crude oil is characterized by rheological properties tests and differential scanning calorimetry (DSC) thermal analysis. The wax damage characteristics of cores and the relative permeability curves at different temperatures were investigated through coreflood experiments. Furthermore, nanoemulsion is selected as a chemical agent for injection fluid. The nuclear magnetic resonance (NMR) scanning technique is used to investigate the effects of oil recovery enhancement at different pores by increasing temperature and adding nanoemulsion. By comparing the changes in T2 spectra and the distribution pattern of residual oil before and after liquid injection, the results have shown that both increasing temperature and adding nanoemulsion have a significant effect on oil recovery. The improvement of micropores is less pronounced compared to macropores. The produced oil mainly comes from the large pores. When the temperature is lower than the crude oil dewaxing point temperature, there is a serious dewaxing plugging phenomenon in the pores. Additionally, by observing the pattern of residual oil distribution at the end of the NMR online drive, it is hereby classified into wax deposition retention type, weak water washing retention type, and immobilized type, each with its own distinct characteristics. Wettability alteration and interfacial tension reduction can help to improve the drainage capacity of high-wax oil reservoirs, which is the main mechanism of nanoemulsion for enhanced oil recovery. These findings are highly valuable for enhancing the comprehension of the impact of highly waxed crude oils on drainage capacity and the ultimate oil recovery rate, particularly in relation to wax precipitation deposition.
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