Calcite–Fluid Interfacial Tension: H₂ and CO₂ Geological Storage in Carbonates

Abstract

Underground hydrogen storage (UHS) and CO 2 geological storage (CGS) are two outstanding techniques for meeting the universal energy demand and reducing anthropogenic greenhouse gases (GHGs). In this context, the calcite–fluid interfacial tension (γ calcite–fluid ) is a critical parameter for gas s torage in carbonate formations as it affects the spreading and flow of fluids in porous media, gas injection/withdrawal rate, gas storage capacity, and containment safety. However, there is a scarcity of γ calcite–fluid data (e.g., γ calcite–gas and γ calcite–water for carbonate/gas/water systems) at geological conditions in the literature. In addition, there is no independent experimental method to measure γ rock–fluid; thus, advancing and receding contact angles are often used to calculate it by a combination of Neumann’s equation of state and Young’s equation. We, therefore, theoretically calculated γ calcite–fluid as a function of the main geological parameters, including temperature, pressure, organic acid concentration, and salinity for calcite/H 2 /water and calcite/CO 2 /water systems. We recognized that γ calcite–gas decreased with pressure, salinity, and organic acid concentration but increased with temperature. Also, a slight increase in γ calcite–water with organic acid concentration and salinity was noticed at 15 MPa, 323.15 K, and 10 MPa, 323.15 K, respectively. However, γ calcite–water slightly decreased with temperature, assuming that it remained constant with pressure. Furthermore, the values of γ calcite–fluid for a H 2 /brine system were more than those for a CO 2 /brine system. This work thus provides a deep understanding of the wetting characteristics at calcite/H 2 /water and calcite/CO 2 /water interfaces and leads to a better investigation of H 2 /CO 2 storage in carbonate formations.

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