Enhancing gas geo-storage capacity in carbonate saline formations using fluorinated surfactants: Experimental investigation and implications for sustainable energy solutions

Abstract

Large-scale gas geo-storage has the potential to be a key component in achieving a sustainable energy solution. Carbonate saline formations can be considered promising geological structures for this purpose. However, they are naturally water-wet, characterized by very low permeability and high brine salinity. To enhance the gas storage potential of carbonate saline formations, two key issues need to be addressed: modifying the rock surface wettability and reducing capillary entry pressure. For this purpose, a systematic experimental study utilizing a fluorinated surfactant was conducted. First, a comprehensive analysis of the rock surface morphology was conducted using SEM, EDAX, XRD, and AFM tests. This analysis aimed to elucidate the surface adsorption phenomena and investigate the morphological changes in the rock surface resulting from the wettability modification process. Second, brine/gas contact angle and surface tension were measured in different salinities and surfactant concentrations. Third, imbibition and flooding experiments were carried out to analyse the effect of the surfactant's modification of wettability and assess the enhanced storage performance. The findings revealed a significant decrease in the surface tension between brine and gas, as well as a change in the gas/brine contact angle, both of which are linked to the inclusion of the fluorinated surfactant in the aqueous phase. Specifically, the brine/gas surface tension dropped from 60.6 mN/m to 16.1 mN/m, while the contact angle decreased from 131° to 110°. Moreover, in the spontaneous imbibition experiments, the plug sample treated with the surfactant, exhibited reduced and slower water imbibition compared to the untreated plug, i.e., the volume of imbibed water was dropped from 28 cc to 10 cc. This indicates that a greater volume of gas remained within the core sample, thereby corresponding to an enhanced storage capacity. Moreover, during the experiments of core flooding conducted at a constant outlet pressure, the treated sample exhibited a lower injection pressure (higher pressure drop) compared to the untreated sample. For instance, the pressure drop in the treated sample was 40 psi, whereas it was 31 psi in the untreated sample. Overall, the reduction in surface tension and the modification of wettability resulted in a decreased capillary entry pressure and facilitating easier gas-brine displacement. The results demonstrated that the fluorinated surfactant reduced injection pressure, indicating better gas injectivity, while allowing a greater volume of gas to be stored within the core, thereby increasing gas storage capacity. All experimental findings align and together show that fluorinated surfactants have the potential to greatly enhance gas geo-storage capacity in carbonate saline formations. The results of this study hold wider significance and can be applied to multiple geo-storage applications, including Underground Hydrogen Storage (UHS), Carbon Capture and Storage (CCS), and Natural Gas Storage (NGS). As a result, these developments can play a positive role in tackling environmental issues and promoting long-term energy sustainability.