Selecting and Performance Evaluating of Surfactant in Carbon Dioxide Foam Flooding in Caoshe Oil Field
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This chapter contains sections titled: Introduction Geological Characteristics in Taizhou Formation of Caoshe Oil Field Techniques to Improve the Effect of CO2 Flooding Selecting and Evaluating of Surfactant ConclusionsKeywords:
Water flooding
Water flooding
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Analyze the relation of the water flooding system and the water flooding station; present a design of simplifying the water flooding system control to water flooding equipment control. Apply ANN(Artificial Neural Network) in optimizing control system based on the optimized water flooding equipment; test the control system using the industrial data. Prove that the control system has good effect, and is of highly practical value.
Water flooding
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Chemical stimulation such as surfactant flooding in petroleum reservoirs makes efforts to produce remained oil and improve sweep efficiency by means of different phenomena such as lowering interfacial tension and wettability alteration of reservoir rock. Implementing concentration of surfactant through surfactant flooding is one of the big challenges while interfacial tension between surfactant solution and oil after certain concentration involves little changes such as critical micelle concentration (CMC). This article highlights the effect of nanosilica on CMC of Zyziphus Spina Christi, as sugar-based surfactant, in aqueous solutions for enhanced oil recovery and reservoir stimulation purposes. A conductivity approach was selected to assess the CMC of the introduced surfactant in aqueous solution at 25°C. The influence of nanosilica concentrations on CMC variation of introduced surfactant is considered. It is found that CMC of introduced surfactant decreased while the concentration of the nanosilica increased. Results from this study can aim in optimum condition selection of surfactant flooding as an enhanced oil recovery ends.
Thermodynamics of micellization
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This paper is aimed at the geological characteristics of Jiangsu oil field and the present condition of water flooding development, and modern physics simulation method is used to probe into periodic water flooding and its affecting factors. The experimental results show, compared with conventional water flooding, the enhanced oil recovery by periodic water flooding is 6.8% on average. The flooding efficiency of periodic injection will be affected by many factors such as the injection time and distribution patterns of well nets and so on. The oil recovery of periodic water flooding is better than that of conventional water flooding when it is carried out in the integrated water cut of 40%, 70% and 90%.
Water flooding
Water cut
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Low Salinity Water (LSW) incorporates in surfactant Enhanced Oil Recovery (EOR) as a pre-flush is a common practice aiming to reduce the formation salinity, which affects surfactant adsorption. However, in a field implementation, the adsorption of surfactant is unavoidable, so creating a scheme that detaches the trapped surfactant is equally essential. In this study, LSW was a candidate to enhance the desorption of surfactant. LSW solely formulated from NaCl (1 wt.%), Sodium Dodecylbenzene Sulfonate (SDBS) was chosen as the primary surfactant at its critical micelle concentration (CMC, 0.1 wt.%). It found that injecting LSW as post-flush achieved up to 71.7% of SDBS desorption that lower interfacial tension against oil (31.06° API) to 1.3 mN/m hence bring the total Recovery Factor (RF) to 56.1%. It was 4.9% higher than when LSW injecting as pre-flush and 5.2% greater than conventional surfactant flooding (without LSW). Chemical analysis unveiled salinity reduction induces Na + ion adsorption substitution onto pore surface resulting in an increment in surfactant desorption. The study was further conducted in a numerical simulation upon history matched with core-flood data reported previously. By introducing LSW in post-flush after SDBS injection, up to 5.6% RF increased in comparison to other schemes. The proposed scheme resolved the problems of adsorbed surfactant after EOR, and further improve the economic viability of surfactant EOR.
Dodecylbenzene
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The residual oil remained in the reservoir after the primary recovery and water flooding can either be produced by increasing the mobility of the oil or by altering the reservoir rock wetting behavior and diminishing the oil water interfacial tension. The surfactant flooding is one of the chemical enhanced oil recovery methods. At the optimal concentration, the surfactant flooding can provide the low interfacial tension favoring to the enhanced oil recovery. In contrast, the loss of the surfactant at the solid-liquid interface due to an adsorption lessens the amount of the surfactant required for oil displacement during the flooding. Therefore, the silica nanoparticles are used to enhance the surfactant EOR process in minimizing the surfactant adsorption which also results in the wettability alteration. In this study, the behavior of the interfacial tension between oil and different interfaces at the reservoir conditions are observed. From the results, IFT is greatly affected by the surfactant concentration, the presence of the nanoparticles in the surfactant solution, temperature and salinity. At the end, the desired low interfacial tension is achieved when 750 ppm by weight of nanoparticles are used with 2000 ppm�concentration of the surfactant in the low salinity of 750 ppm�brine solution.
In addition, the physical properties such as densities of each combination of chemicals and viscosities of oil samples acquired from northern Thailand oilfield are measured with and without the surfactant solutions and the silica nanoparticles assisted the surfactant solutions at the different concentration. From the experiments, the anionic surfactants, sodium dodecyl sulfate (SDS)and sodium dodecylbenzene sulfonate (SDBS) are used according to the lower adsorption in the sandstones compared to the cationic surfactants. From the results, the static adsorption behavior of the surfactant at the interface with the reservoir rock from the northern Thailand oilfield is studied and the nano silica can indeed reduce the adsorption of the surfactant by being adsorbed at the rock surface itself and the wettability is also changed consecutively. However, the sacrificial adsorption of the nanoparticles become effective when the surfactant concentration beyond the critical micelle concentration is used. In comparison of two anionic surfactant, SDBS shows the higher adsorption on the rock sample rather than that of SDS.
In conclusion, from the study of the physical property measurement, adding the nano silica to the surfactant solutions enhances the important parameters of EOR. The IFT can be reduced. Also, the surfactant adsorption can be lowered if concentration above CMC is used. Also, the nano silica can provide the effective contact angle reduction and support the oil recovery for the surfactant flooding.
Residual oil
Brine
Microemulsion
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Abstract Injecting carbon dioxide (CO2) into oil reservoirs has the potential to enhance oil recovery (EOR) and mitigate climate change by storing CO2 underground. Despite successes in using CO2 to enhance oil recovery, mobility control remains a major challenge facing CO2 injection projects. The objective of this work is to investigate the potential of using surfactant and a mixture of surfactant and nanoparticles (NPs) to generate foam to reduce gas mobility and enhanced oil recovery. A newly developed anionic surfactant and a mixture of the surfactant and surface modified silica NPs were used to assess the ability of generating a stable foam at harsh reservoir conditions: sc-CO2 and high temperature. Dynamic foam tests and coreflood experiments were conducted to evaluate foam stability and strength. To measure the mobility of injected fluids in sandstone rocks, the foam was generated by co-injection of sc-CO2 and surfactant, as well as a mixture of surfactant and NPs at 90% quality. The coreflood experiments were conducted using non-fractured and fractured sandstone cores at 1550 psi and 50°C. Surfactant alone and mixtures of surfactant and NPs were able to generate foam in porous media and reduce CO2 mobility. The mobility reduction factor (MRF) for both cases was about 3.5 times higher than that of injecting CO2 and brine at the same conditions. The coreflood experiments in non-fractured sandstone rocks showed that both surfactant and a mixture of surfactant and NPs were able to enhance oil recovery. The baseline experiment in the absence of surfactant resulted in a total recovery of 71.50% of the original oil in place (OOIP). Using surfactant brought the oil recovery to 76% of the OOIP. The addition of NPs to surfactant resulted in a higher oil recovery still, 80% of the OOIP. In fractured rocks, oil recoveries during secondary production mechanisms for the mixture, the surfactant alone, and sc-CO2 alone were 12.62, 8.41 and 7.21% of the OOIP, respectively.
Brine
Foaming agent
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On the base of surfactant enhanced oil recovery,the HD interface characteristics and core flooding experiments were studied.The results showed that HD can make ultra-low interfacial tension of water and oil under concentrations from 0.025% to 0.30% in the salinity of 6 823 mg/L.The lowest interfacial tension of the time(the original 40 min,first for 15 min) is the 63.5% of original,and the results were superior to a single by additive HDSY.It showed that the water flooding after water up to 95% can continue to improve oil recovery 24.25% by composite flooding system.
Water flooding
Oil in place
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Water-flooding curve is a method to calculate the recoverable reserve that's commonly used for water-drive oil-field.In this paper,it's used on the Jianyucha oil-field according to the characteristics of scroll production,water injection development and stable production.The result and the development status match better.It could be a reference for other similar oil-fields.
Water flooding
Water cut
Oil Production
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