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The reservoir’s properties are required for proper reservoir simulation, which also involves uncertainties. Experimental methods to estimate the relative permeability and capillary pressure data are expensive and time-consuming. This study aims to determine the relative permeability and capillary pressure functions of a sandstone core in the presence and absence of clay during low-salinity water floods. The data were provided by automatic history matching the results from previously lab-reported studies through coupling a simulator with the particle swarm optimization algorithm. Correlations were proposed using multiple-linear regression for relative permeability and capillary pressure parameters at low-salinity conditions. They were validated against experimental results of no clay and clayey formation with regression of 95% and 97%. To assign one curve of relative permeability and capillary pressure to the grid cells of the simulator, averaging techniques were implemented. The effect of salinity and clay content on the obtained curves was investigated. Changing salinity from 42000 to 4000 ppm, the reduction in water relative permeability appeared to be higher than the oil relative permeability increment. Moreover, a noticeable shift in the relative permeability curves toward the highest saturations related to the clay content was observed. The proposed hybrid method could be a suitable tool to estimate the relative permeability and capillary pressure functions of the water-based EOR methods.
The reservoir’s properties are required for proper reservoir simulation, which also involves uncertainties. Experimental methods to estimate the relative permeability and capillary pressure data are expensive and time-consuming. This study aims to determine the relative permeability and capillary pressure functions of a sandstone core in the presence and absence of clay during low-salinity water floods. The data were provided by automatic history matching the results from previously lab-reported studies through coupling a simulator with the particle swarm optimization algorithm. Correlations were proposed using multiple-linear regression for relative permeability and capillary pressure parameters at low-salinity conditions. They were validated against experimental results of no clay and clayey formation with regression of 95% and 97%. To assign one curve of relative permeability and capillary pressure to the grid cells of the simulator, averaging techniques were implemented. The effect of salinity and clay content on the obtained curves was investigated. Changing salinity from 42000 to 4000 ppm, the reduction in water relative permeability appeared to be higher than the oil relative permeability increment. Moreover, a noticeable shift in the relative permeability curves toward the highest saturations related to the clay content was observed. The proposed hybrid method could be a suitable tool to estimate the relative permeability and capillary pressure functions of the water-based EOR methods.
The injection of Sulphonated-smart water (SW) could be an attractive application as it results in the formation of a mechanically rigid oil-water interface, and hence possible higher oil recovery in combination with the polymer. Therefore, detailed experimental investigation and fluid flow analysis through porous media are required to understand the possible recovery mechanisms. This paper evaluates the potential influence of Sulphonated/Polymer water injection in oil recovery by coupling microfluidics and core flooding experiments. The possible mechanisms are evaluated utilizing a combination of experiments and fluids. Initially, synthetic seawater (SSW) and Sulphonated-Smart water (SW) were optimized to be used in combination with a viscoelastic HPAM polymer. Fluid characterization was achieved by detailed rheological characterization focusing on steady shear and in-situ viscosity. Moreover, single and two-phase core floods and micromodels experiments helped to define the behavior of different fluids. The data obtained was cross-analyzed to draw conclusions on the process effect and performance. First, Sulphonated/polymer water solutions showed a slight decrease in the polymer shear viscosity as compared to the SSW-polymer. Similar behavior was also confirmed in the single-phase core flood-through the differential pressure, looking at the in-situ viscosity. Second, on the one hand, smart water produced only ~3% additional oil recovery as compare to the SSW through micromodel due to improved interfacial viscoelasticity, where no local wettability alteration was observed in the porous media. On the other hand, core flood experiments using SW led to ~12% additional oil as compare to SSW. This excessive extra recovery in core flood compare to micromodel could be due to the combined effect of interfacial viscoelasticity and wettability alteration. Micromodel is coat with a hydrophobic chemical; hence, wettability becomes hard to be altered through SW while in the core flood it is dominated with ionic exchange (local wettability alteration). Finally, a combination of SW with polymer flood can lead to ~6% extra oil as compare to the combination of polymer flood with SSW. Overall, coupling microfluidics with core flooding experiments confirmed that IFV and wettability alteration both are the key recovery mechanisms for SW. The evaluation confirmed that the main recovery mechanisms of smart-water injection are interfacial viscoelasticity and wettability alteration. Furthermore, it confirmed that the combination of SW with polymer flood could sweep the reservoir efficiently resulting in higher oil recovery. This topic has been addressed in the literature with mixed results encountered.
This work describes the flow behavior of the oil recovery obtained by the injection of sulfate-modified/low-salinity water in micromodels with different wettabilities. It provides a detailed microscopic visualization of the displacement taking place during modified water flooding at a pore-scale level, while evaluating the effect of wettability on oil recovery. A comprehensive workflow for the evaluation is proposed that includes fluid–fluid and rock–fluid interactions. The methods studied comprise flooding experiments with micromodels. Artificial and real structure water-wet micromodels are used to understand flow behavior and oil recovery. Subsequently, water-wet, complex-wet, and oil-wet micromodels help understand wettability and rock–fluid interaction. The effect of the sulfate content present in the brine is a key variable in this work. The results of micromodel experiments conducted in this work indicate that sulfate-modified water flooding performs better in mixed-wet/oil-wet (artificial structure) than in water-wet systems. This slightly differs from observations of core flood experiments, where oil-wet conditions provided better process efficiency. As an overall result, sulfate-modified water flooding recovered more oil than SSW injection in oil-wet and complex-wet systems compared to water-wet systems.
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