Abstract:Simultaneous utilization of surfactant and preformed particle gel (henceforth; PPG) flooding on the oil recovery enhancement has been widely investigated as a preferable enhanced oil recovery technique after the polymer flooding. In this paper, a numerical model is developed to simulate the profound impact of hybrid chemical enhanced oil recovery methods (PPG/polymer/surfactant) in sandstone reservoirs. Moreover, the gel particle conformance control is considered in the developed model after polymer fl… Show more
“…Moreover, the variation of wettability have a huge impact on the capillary pressure, irreducible water saturation and residual oil saturation (Anderson 1985;A Davarpanah 2018;A Davarpanah and Mirshekari 2019a, 2019b, 2019cHan et al 2019;Xiao Hu et al 2020;Jadhunandan and Morrow 1995). It has been proved that the most of the carbonate reservoirs act as oil-wet due to the interaction of components crude oil and the kind of this rock (Afshin Davarpanah 2020; Afshin Davarpanah et al 2018;Geyssant 2019;Hirasaki and Zhang 2004;Xiaoyong Hu et al 2020;Jarrahian et al 2012;Kafashi et al 2020;Zhou and Davarpanah 2020). The composition of rock minerals plays a significant role in the adsorption of added surfactants, reservoirs and their influences on wettability (Hamid Giraldo et al 2013;Pan et al 2020;Somasundaran and Zhang 2006).…”
“…Moreover, the variation of wettability have a huge impact on the capillary pressure, irreducible water saturation and residual oil saturation (Anderson 1985;A Davarpanah 2018;A Davarpanah and Mirshekari 2019a, 2019b, 2019cHan et al 2019;Xiao Hu et al 2020;Jadhunandan and Morrow 1995). It has been proved that the most of the carbonate reservoirs act as oil-wet due to the interaction of components crude oil and the kind of this rock (Afshin Davarpanah 2020; Afshin Davarpanah et al 2018;Geyssant 2019;Hirasaki and Zhang 2004;Xiaoyong Hu et al 2020;Jarrahian et al 2012;Kafashi et al 2020;Zhou and Davarpanah 2020). The composition of rock minerals plays a significant role in the adsorption of added surfactants, reservoirs and their influences on wettability (Hamid Giraldo et al 2013;Pan et al 2020;Somasundaran and Zhang 2006).…”
“…Utilization of underground stored natural gas would be more environmentally friendly during enhanced recovery processes [17][18][19][20][21][22][23], as it does not need to transfer gas from petrochemical industries [24][25][26]. Moreover, it is more economical, as it has removed unprecedented expenses to capture carbon dioxide [27][28][29][30][31][32][33][34]. Recently, due to the high productions of hydrocarbon, most of the conventional reservoirs are almost depleted, or it is not economical to produce the remained hydrocarbon [35][36][37][38][39][40].…”
Supercritical carbon dioxide injection in tight reservoirs is an efficient and prominent enhanced gas recovery method, as it can be more mobilized in low-permeable reservoirs due to its molecular size. This paper aimed to perform a set of laboratory experiments to evaluate the impacts of permeability and water saturation on enhanced gas recovery, carbon dioxide storage capacity, and carbon dioxide content during supercritical carbon dioxide injection. It is observed that supercritical carbon dioxide provides a higher gas recovery increase after the gas depletion drive mechanism is carried out in low permeable core samples. This corresponds to the feasible mobilization of the supercritical carbon dioxide phase through smaller pores. The maximum gas recovery increase for core samples with 0.1 mD is about 22.5%, while gas recovery increase has lower values with the increase in permeability. It is about 19.8%, 15.3%, 12.1%, and 10.9% for core samples with 0.22, 0.36, 0.54, and 0.78 mD permeability, respectively. Moreover, higher water saturations would be a crucial factor in the gas recovery enhancement, especially in the final pore volume injection, as it can increase the supercritical carbon dioxide dissolving in water, leading to more displacement efficiency. The minimum carbon dioxide storage for 0.1 mD core samples is about 50%, while it is about 38% for tight core samples with the permeability of 0.78 mD. By decreasing water saturation from 0.65 to 0.15, less volume of supercritical carbon dioxide is involved in water, and therefore, carbon dioxide storage capacity increases. This is indicative of a proper gas displacement front in lower water saturation and higher gas recovery factor. The findings of this study can help for a better understanding of the gas production mechanism and crucial parameters that affect gas recovery from tight reservoirs.
“…The utilization of nanoparticles regarding their inorganic feature with the organic polymers would be of interest, as it can generate synergy between two materials and improve the oil recovery performances. The creation of hydrogen bonds between the polymers and nanoparticles to enhance the rheological properties of polymer-nanoparticle aqueous solution in the presence of high salinity and temperature is the reason for this phenomenon [61]. The addition of nanoparticles to chemical agents during enhanced oil recovery would be of importance, as it can significantly influence the wettability alteration and reduce the interfacial tension that is combined with the viscosifying property of polymer, which helps the oil phase to be more mobilized through porous media [62][63][64][65][66].…”
Nowadays, the addition of nanoparticles to polymer solutions would be of interest; however, the feasible property of nanoparticles and their impact on oil recovery has not been investigated in more detail. This study investigates the rheology and capillary forces (interfacial tension and contact angle) of nanoparticles in the polymer performances during oil recovery processes. Thereby, a sequential injection of water, polymer, and nanoparticles; Nanosilica (SiO2) and nano-aluminium oxide (Al2O3) was performed to measure the oil recovery factor. Retention decrease, capillary forces reduction, and polymer viscoelastic behavior increase have caused improved oil recovery due to the feasible mobility ratio of polymer–nanoparticle in fluid loss. The oil recovery factor for polymer flooding, polymer–Al2O3, and polymer–SiO2 is 58%, 63%, and 67%, respectively. Thereby, polymer–SiO2 flooding would provide better oil recovery than other scenarios that reduce the capillary force due to the structural disjoining pressure. According to the relative permeability curves, residual oil saturation (Sor) and water relative permeability (Krw) are 29% and 0.3%, respectively, for polymer solution; however, for the polymer–nanoparticle solution, Sor and Krw are 12% and 0.005%, respectively. Polymer treatment caused a dramatic decrease, rather than the water treatment effect on the contact angle. The minimum contact angle for water and polymer treatment are about 21 and 29, respectively. The contact angle decrease for polymer treatment in the presence of nanoparticles related to the surface hydrophilicity increase. Therefore, after 2000 mg L−1 of SiO2 concentration, there are no significant changes in contact angle.
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