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In this research, it was attempted to describe in vitro the efficiency of a natural polymer synthesized from sugarcane waste by bacteria for application in enhanced crude oil recovery. Necessary experiments were carried out with the main targets of extraction and description of the polymer and its effectiveness in enhanced oil recovery. It is shown that in the polymer concentrations of 1, 2, 5, and 8 wt%, the viscosity is equal to 26.08, 76.51, 100.94, and 168.36 mPa s. A shear‐thinning flow behavior is observed at initial shear rates. The sandstone wettability alteration is observed through the contact angles at concentrations of 1, 2, 5, and 8 wt% that are 85.93°, 72.19°, 76.51°, and 71.09°, respectively. Based on salinity compatibility, the polymer work up to a salinity of 90 000 ppm and based on viscosity tests, up to a salinity of 120 000 ppm. Regarding the performance of the polymer solution against temperature, it shows an acceptable performance in increasing the viscosity at the highest temperature of 75 °C. The water cut reaches its minimum of 8%, and then increases. By injecting 3.3 Pore volum (PV), the oil recovery reaches 81.4%. In a polymeric slug injection program, the oil recovery factor reaches 74.8%.Similarly, the water cut starts to decrease after the injection of polymer, and finally, after the injection of 0.9 PV including 0.5 PV of the polymer solution and 0.4 PV of water, reaches its minimum during the experiment, i.e., 22%.
In this research, it was attempted to describe in vitro the efficiency of a natural polymer synthesized from sugarcane waste by bacteria for application in enhanced crude oil recovery. Necessary experiments were carried out with the main targets of extraction and description of the polymer and its effectiveness in enhanced oil recovery. It is shown that in the polymer concentrations of 1, 2, 5, and 8 wt%, the viscosity is equal to 26.08, 76.51, 100.94, and 168.36 mPa s. A shear‐thinning flow behavior is observed at initial shear rates. The sandstone wettability alteration is observed through the contact angles at concentrations of 1, 2, 5, and 8 wt% that are 85.93°, 72.19°, 76.51°, and 71.09°, respectively. Based on salinity compatibility, the polymer work up to a salinity of 90 000 ppm and based on viscosity tests, up to a salinity of 120 000 ppm. Regarding the performance of the polymer solution against temperature, it shows an acceptable performance in increasing the viscosity at the highest temperature of 75 °C. The water cut reaches its minimum of 8%, and then increases. By injecting 3.3 Pore volum (PV), the oil recovery reaches 81.4%. In a polymeric slug injection program, the oil recovery factor reaches 74.8%.Similarly, the water cut starts to decrease after the injection of polymer, and finally, after the injection of 0.9 PV including 0.5 PV of the polymer solution and 0.4 PV of water, reaches its minimum during the experiment, i.e., 22%.
Summary Polymer flooding in deep reservoir profile control presents challenges in balancing injectivity and effective mobility control. To address this, we propose a solution by utilizing a microencapsulated polymer that can be easily injected and thickens over time. However, limited research has been conducted on the flow characteristics and the impact on oil mobilization by such profile control agents. In this study, we approximately simulated the time-varying flow process of microencapsulated polymer through in-situ triggered experiments at high temperature and pressure. The flow characteristics and oil displacement mechanism of the microencapsulated polymer under different trigger times were analyzed, and the displacement efficiency during the triggered viscosity enhancement process in porous media was quantitatively evaluated. The experimental results reveal that microencapsulated polymer exhibits a dual mechanism of near-wellbore reservoir particle temporary plugging and deep formation consistency control mechanisms. The transient aggregation of capsule particles alters the flow path, intensifying after expansion. The interaction between the microcapsule particles and the partially released polymer further enhances the resistance-enhancing property of the solution. The viscosity-enhanced microencapsulated polymer fluid improves the displacement efficiency. Microscopic oil displacement and coreflooding experiments resulted in a decrease in oil saturation of 39.5 and 18.33%, respectively. This study provides valuable microscopic insights into the flow behavior and oil displacement performance of microencapsulated polymer, offering essential guidance for optimizing oil reservoir extraction strategies.
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