Rock-fluid interfacial tension at subsurface conditions: Implications for H2, CO2 and natural gas geo-storage.

In H 2 , CO 2 and natural gas geo-storage, rock-fluid interfacial tension (γ r o c k − f l u i d ) is a key parameter which influences pore-scale fluid distribution and reservoir-scale gas storage capacity and containment security. However, γ r o c k − f l u i d data is seriously lacking because of the inability to measure this parameter experimentally. Therefore herein, a semi-empirical method is used to calculate γ r o c k − f l u i d at geo-storage conditions. Additionally, effects of organic acid and silica nanofluid on γ r o c k − f l u i d are studied. The following results are obtained. γ r o c k − g a s decreases with pressure, temperature, organic acid concentration and carbon number increase, while γ r o c k − H 2 O increases with organic acid concentration and carbon number increase; γ r o c k − g a s first increases and subsequently decreases with silica nanofluid concentration increase, while γ r o c k − H 2 O first decreases and then increases with silica nanofluid concentration increase; for same thermo-physical and rock surface chemistry conditions, γ r o c k − g a s follows the order H 2 > CH 4 > CO 2. These insights provide pivotal guidance on gas geo-storage and thus aids in the implementation of a more sustainable energy supply chain. [Display omitted] • γ rock−gas decreases with increasing pressure and organic acid concentration. • γ rock−gas first increases and then decreases with nanofluid concentration increase. • γ rock−gas follows the order H 2 > CH 4 > CO 2. [ABSTRACT FROM AUTHOR]