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

Abstract

Underground hydrogen storage (UHS) and CO2 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 (γcalcite–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 γcalcite–fluid data (e.g., γcalcite–gas and γcalcite–water for carbonate/gas/water systems) at geological conditions in the literature. In addition, there is no independent experimental method to measure γrock–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 γcalcite–fluid as a function of the main geological parameters, including temperature, pressure, organic acid concentration, and salinity for calcite/H2/water and calcite/CO2/water systems. We recognized that γcalcite–gas decreased with pressure, salinity, and organic acid concentration but increased with temperature. Also, a slight increase in γcalcite–water with organic acid concentration and salinity was noticed at 15 MPa, 323.15 K, and 10 MPa, 323.15 K, respectively. However, γcalcite–water slightly decreased with temperature, assuming that it remained constant with pressure. Furthermore, the values of γcalcite–fluid for a H2/brine system were more than those for a CO2/brine system. This work thus provides a deep understanding of the wetting characteristics at calcite/H2/water and calcite/CO2/water interfaces and leads to a better investigation of H2/CO2 storage in carbonate formations.