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- 저자 : ( Kyuro Sasaki ) (검색결과 2 건)
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( Tola Sreu ),( Kyuro Sasaki ),( Yuichi Sugai ),( Ronald Nguele ) 대한지질공학회 2019 대한지질공학회 학술발표회논문집 Vol.2019 No.2
The present study investigated, therefore, the potential of stabilized Nanofluid (NF) to increase the production of a stranded light crude oil. Silica nanoparticle (SiO2-NP) was selected as a primary one. The Polyvinyl Alcohol (PVA) was blended in the base fluid to increase the NF stability. The SiO2-NF was prepared in the CO2-rich condition. It was found that SiO2-NF becomes stable for up to 1 week without any visible precipitation at 55°C considered as a reservoir temperature. The stable SiO2-NF has not formed with the absence of CO2-rich environment, and the NF precipitation was observed after a while. The Interfacial tension (IFT) between oils and NF, which was measured by the pendant drop method at room temperature, revealed a negligible of IFT reduction. Furthermore, contact angle measurements using the sessile drop method at room temperature showed the wettability of rock was altered to be more water-wet when NF was used. Subsequently, core-flooding (CF) experiments were carried out using two different types of oils (Light Japanese Oil, LJO and Light Mineral Oil, LMO) in the Berea sandstone. The injecting SiO2-NF into the core after the water flooding increased the oil recovery factor (RF) of 7.6% larger than injecting PVA solution alone (RF=1%). The main mechanism of the increment of oil using NF was expected to be a plugging function of SiO2-NPs in the micropores in the cores because the NPs block the higher permeability fluids passes and push the oil out from low permeability zone with higher oil saturation.
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( Qiang Sun ),( Kyuro Sasaki ) 대한지질공학회 2019 대한지질공학회 학술발표회논문집 Vol.2019 No.2
In CCS program, solubility trapping is an important trapping mechanism. The injected CO<sub>2</sub> and formation fluid (usually brine) can be considered as the solute and the solvent respectively. After injection CO<sub>2</sub> gradually dissolves into the formation fluid at the contact surface. Because the formation fluid with dissolved CO<sub>2</sub> is slightly denser than the surrounding fluid, it tends to sink to the bottom of the formation over time. At the same time, because of the difference in density between fluids, the buoyant force is another key factor that influence the CO<sub>2</sub> plume front. In this study, considering dissolved trapping CO<sub>2</sub> plume front propagations were studied for geological CO<sub>2</sub> storage in a deep saline aquifer at a depth of 1000 m from the ground propagation. We will consider the influence of solubility trapping and buoyant forces for CO<sub>2</sub> plume front propagations. Gas solubility in water can be defined by K-values, which can be obtained from thermodynamic models. The cylindrical grid models with homogeneous permeability distributions were constructed to study CO<sub>2</sub> plume front against elapsed time. In the numerical simulations using CMG STARS, aquifer boundary at 1 km from the injector was set as an open boundary with keeping initial constant pressure. Some sensitivity study on effects of applying gas solubility was investigated. The result shows that solubility trapping is have an important impact on the propagation of CO<sub>2</sub> plume front.
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