CO2-Soluble Ionic Surfactants and CO2 Foams for High-Temperature and High-Salinity Sandstone Reservoirs

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• 作者：Zheng Xue ; Krishna Panthi ; Yunping Fei ; Keith P. Johnston ; Kishore K. Mohanty
• 刊名：Energy & Fuels
• 出版年：2015
• 出版时间：September 17, 2015
• 年：2015
• 卷：29
• 期：9
• 页码：5750-5760
• 全文大小：544K
• ISSN：1520-5029

文摘

The sweep efficiency of CO₂ enhanced oil recovery can be improved by forming viscous CO₂-in-water (C/W) foams that increase the viscosity of CO₂. The goal of this study is to identify CO₂-soluble ionic surfactants that stabilize C/W foams at elevated temperatures up to 120 掳C in the presence of a high salinity brine using aqueous phase stability, static and dynamic adsorption, CO₂ solubility, interfacial tension, foam bubble size, and foam viscosity measurements. An anionic sulfonate surfactant and an amphoteric acetate surfactant were selected to achieve good thermal and chemical stability, and to minimize adsorption to sandstone reservoirs in the harsh high-salinity high-temperature brine. The strong solvation of the surfactant head by the brine phase and surfactant tail by CO₂ allows efficient reduction of the C/W interfacial tension, and the formation of viscous C/W foams at high salinity and high temperature. Furthermore, the effect of temperature and methane dilution of CO₂ on foam viscosity was evaluated systematically in both bulk and porous media. High temperature reduces the stability of foam lamella, which leads to lower lamella density and, therefore, lower foam viscosity. Methane dilution of CO₂ reduces the solvation of surfactant tails and makes the surfactant less CO₂-philic at the interface. The consequent increase of the interfacial tension decreases the stability of foam lamella, as seen by the increase in foam bubble size, thereby reducing foam viscosity.