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Here, Fe2O3 and SiO2 nanoparticles are synthesized and utilized to investigate their effects on foam stability and flowing behavior in porous media. At first, the effect of main operative parameters including surfactant concentration, formation water composition and dosage, and temperature on foam stability are studied at static condition for preparation of an optimal foam solution. Then, the synthesized nanoparticles are dispersed in optimal foam solution for subsequent main experiments. High pressure-high temperature microscopic injection experiments are employed to assess the oil-flow displacement in heterogeneous porous medium pattern by foam injection in the absence and presence of the nanoparticles. The results show that sodium dodecyl sulfonate surfactant concentration of 0.75 wt% provides the optimal dosage independent of other factors. The foam solution becomes unstable with increasing the salinity. Conversely, the presence of more sulfate ions improves the foam stability and foam textural characteristics. In the presence of the synthesized nanoparticles significant enhancement of foam solution stability is observed. Microscopic analysis of the injection experiments in glass micromodel reveals postponement of the displacing fluid breakthrough time, lessening the severity of the finger phenomenon at displacement front, and higher oil recovery for Fe2O3 and SiO2 nanoparticles-assisted foam solutions. However, the enhancement of the foam textural features and flowing behavior are more manifest in the case of SiO2 nanoparticles compared to the Fe2O3 nanoparticles. [ABSTRACT FROM AUTHOR]

In recent years, the use of natural surfactants, instead of chemical surfactants, as surface active agents in chemical methods of oil recovery has been under consideration due to the absence of environmental problems. In this study, a new plant, Albizia Julibrissin (Albizia), was introduced as a natural surfactant. Our novelty resides in a unified approach that deals with the introduction of Albizia Julibrissin as a new natural surfactant, the interpretation of the chemical enhanced oil recovery (EOR) objectives, the interface reactions, and the induced optimization to improve oil recovery. For this purpose, the plant was extracted using the Soxhlet extraction method in aqueous base solutions, and the interfacial tension between the natural surfactant aqueous solutions and kerosene as an oil phase was measured by the pendant drop method. The critical micelle concentration structure formed by this material was determined by the interfacial tension tests and confirmed by the electrical conductivity tests. The results show that Albizia extract begins to form micelles at a concentration of 3.5 wt %, which is the critical concentration of Albizia plant micelles. At this concentration, the interfacial tension between the deionized water and the oil phase was reduced from 34 to 10 mN/m, which indicates a significant decrease in the interfacial tension by this plant. Carbonate rock was employed for the core flooding experiments in order to investigate the effect of Albizia extract (AE) on oil recovery. Also, based on the results, by using AE, the wettability of the oil-wet carbonate rocks was altered from about 165.02° to 86.59°. Finally, the AE enhanced ultimate oil recovery by about 11.6% of original oil in place in tertiary recovery for a carbonate rock. [ABSTRACT FROM AUTHOR]

In this article, the effect of one well-known inhibitor namely palmitic acid is investigated on particle size distribution of asphaltenes by imaging techniques. Pure asphaltene is extracted from crude oil to prepare Heptol (n-heptane+toluene) solutions of suspended asphaltenes. Different concentrations of inhibitors are then added to the solution. Afterward, image analysis of microscopic photos is used to determine the particle size distribution of asphaltene flocs in the presence of inhibitors. Average particle size of asphaltene and fractal structure of aggregates are also investigated; results show that the compaction of asphaltenes flocs is correlated with concentration of inhibitor. However, no significant relationship was observed between surface roughness of flocs and inhibitor concentration. [ABSTRACT FROM PUBLISHER]

In this paper, synthesis and characterization of a novel CeO2/nanoclay nanocomposite (NC) and its effects on IFT reduction and wettability alteration is reported in the literature for the first time. The NC was characterized using scanning electron microscopy (SEM), X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), energy-dispersive X-ray spectroscopy (EDS), and EDS MAP. The surface morphology, crystalline phases, and functional groups of the novel NC were investigated. Nanofluids with different concentrations of 100, 250, 500, 1000, 1500, and 2000 ppm were prepared and used as dispersants in porous media. The stability, pH, conductivity, IFT, and wettability alternation characteristics of the prepared nanofluids were examined to find out the optimum concentration for the selected carbonate and sandstone reservoir rocks. Conductivity and zeta potential measurements showed that a nanofluid with concentration of 500 ppm can reduce the IFT from 35 mN/m to 17 mN/m (48.5% reduction) and alter the contact angle of the tested carbonate and sandstone reservoir rock samples from 139° to 53° (38% improvement in wettability alteration) and 123° to 90° (27% improvement in wettability alteration), respectively. A cubic fluorite structure was identified for CeO2 using the standard XRD data. FESEM revealed that the surface morphology of the NC has a layer sheet morphology of CeO2/SiO2 nanocomposite and the particle sizes are approximately 20 to 26 nm. TGA analysis results shows that the novel NC has a high stability at 90 °C which is a typical upper bound temperature in petroleum reservoirs. Zeta potential peaks at concentration of 500 ppm which is a sign of stabilty of the nanofluid. The results of this study can be used in design of optimum yet effective EOR schemes for both carbobate and sandstone petroleum reservoirs. [ABSTRACT FROM AUTHOR]