TY - GEN
T1 - Molecular Evaluation of the Temperature Role on the Wettability of Carbonate/Brine/Gas Systems
T2 - 2024 Abu Dhabi International Petroleum Exhibition and Conference, ADIPEC 2024
AU - Abdelrhman, Abdelateef Adam
AU - Bahamon, Daniel
AU - Al Kobaisi, Mohammed
AU - Vega, Lourdes F.
N1 - Publisher Copyright:
Copyright 2024, Society of Petroleum Engineers.
PY - 2024
Y1 - 2024
N2 - Rock wetting characteristics directly affect the storage size, security, and fluid flow behavior in Underground Hydrogen Storage (UHS). This study evaluates the impact of temperature variations on the wetting behavior of the UAE carbonate reservoirs in UHS environments and its implications for carbonates' structural and residual trapping capacities. A molecular-level discussion on the impact of temperature variation on UAE carbonates' wetting behavior during UHS implementation is presented for the first time. To obtain molecular insights into the storage process, molecular dynamics simulations were carried out on carbonate/brine/H2+ cushion gas systems. A calcite substrate was used as a representative of the carbonate surface, and CO2 was selected as a cushion gas. Then, the wettability of calcite/brine/H2+CO2 was evaluated at a fixed pressure of 50 MPa, a temperature range of 323 to 388 K, and a fixed salt concentration of 15 wt. %, mirroring the typical reservoir conditions found in the UAE. We report that, at low temperature (323 K), the presence of CO2 in the gas stream (i.e., H2+CO2 mixture) leads to a reduction in the hydrophilicity of calcite due to the higher intermolecular van der Waals attraction found between the calcite and CO2 molecules, leading to CO2 aggregation at the calcite surface. With increasing temperature, the calcite-CO2 interactions diminish, and the calcite surface becomes perfectly water-wet. It can be concluded that due to the higher interactions between calcite-CO2 compared to calcite-H2 interactions, the utilization of CO2 as a cushion gas enhances the carbonate's ability to trap H2 gas by filling the smaller pores with brine and dissolved CO2 molecules while leaving the larger pores available for injected hydrogen. Additionally, introducing CO2 before injecting H2 reduces the amount of hydrogen that can be residually trapped, resulting in an enhanced H2 recovery process.
AB - Rock wetting characteristics directly affect the storage size, security, and fluid flow behavior in Underground Hydrogen Storage (UHS). This study evaluates the impact of temperature variations on the wetting behavior of the UAE carbonate reservoirs in UHS environments and its implications for carbonates' structural and residual trapping capacities. A molecular-level discussion on the impact of temperature variation on UAE carbonates' wetting behavior during UHS implementation is presented for the first time. To obtain molecular insights into the storage process, molecular dynamics simulations were carried out on carbonate/brine/H2+ cushion gas systems. A calcite substrate was used as a representative of the carbonate surface, and CO2 was selected as a cushion gas. Then, the wettability of calcite/brine/H2+CO2 was evaluated at a fixed pressure of 50 MPa, a temperature range of 323 to 388 K, and a fixed salt concentration of 15 wt. %, mirroring the typical reservoir conditions found in the UAE. We report that, at low temperature (323 K), the presence of CO2 in the gas stream (i.e., H2+CO2 mixture) leads to a reduction in the hydrophilicity of calcite due to the higher intermolecular van der Waals attraction found between the calcite and CO2 molecules, leading to CO2 aggregation at the calcite surface. With increasing temperature, the calcite-CO2 interactions diminish, and the calcite surface becomes perfectly water-wet. It can be concluded that due to the higher interactions between calcite-CO2 compared to calcite-H2 interactions, the utilization of CO2 as a cushion gas enhances the carbonate's ability to trap H2 gas by filling the smaller pores with brine and dissolved CO2 molecules while leaving the larger pores available for injected hydrogen. Additionally, introducing CO2 before injecting H2 reduces the amount of hydrogen that can be residually trapped, resulting in an enhanced H2 recovery process.
UR - https://www.scopus.com/pages/publications/85215121544
U2 - 10.2118/222258-MS
DO - 10.2118/222258-MS
M3 - Conference contribution
AN - SCOPUS:85215121544
T3 - Society of Petroleum Engineers - ADIPEC 2024
BT - Society of Petroleum Engineers - ADIPEC 2024
Y2 - 4 November 2024 through 7 November 2024
ER -
