Exploring Feasibility and Optimization of CO2 Sequestration in Depleted Methane Hydrate Reservoirs

Abstract With the climate crisis intensifying, reducing carbon dioxide (CO2) emissions is critical. Current CO2 sequestration methods face limitations due to geological integrity risks and slow reaction rates, hindering long-term reliability. This underscores the urgent need for innovative, sustainable solutions. Increasing interest is growing in underground solid-state CO2 storage, particularly in depleted CH4 hydrate reservoirs, which are less prone to leakage and offer a more reliable option for long-term storage. This study developed a Thermal-Hydrological-Chemical (THC) model to simulate the reactions involved in the formation and dissociation of CO2 and CH4 hydrates. Initially, the model was used to simulate methane hydrate production through depressurization. After 15 years of methane hydrate production and depletion, CO2 injection was initiated and continued for 30 years. The simulation results indicated that the depressurization method effectively induced the dissociation of methane hydrates, leading to significant changes in reservoir properties such as porosity, hydrate concentration, permeability, and temperature. These changes facilitated methane gas production from methane hydrate, which in turn enhanced CO2 storage capacity. To further understand these dynamics, the developed model was used to conduct a sensitivity analysis, investigating the impact of porosity, permeability, reaction frequency factor, and bottom hole flowing pressure on methane hydrate production and CO2 storage. The analysis revealed that low porosity, a high reaction frequency factor, and high permeability result in higher methane production from methane hydrate reservoirs. Improved methane recovery was also correlated with increased 0ϋ2 storage capacity. However, in this particular study, some factors seemed not to affect the storage capacity significantly because the amount of CO2 injected was much lower than the amount of methane recovered from methane hydrates. The study found that CO2 injection for 30 years was feasible in almost all cases explored, especially when the injection rate was below 5,000 m3 and the bottom hole pressure was less than 55.5% of the initial pressure in the methane hydrate formation. It is possible that at higher injection rates, the injectivity of CO2 storage might be compromised. Overall, the results of this work indicate that injecting CO2 into depleted methane hydrate reservoirs is a feasible and effective method for long-term CO2 storage. This approach is particularly suitable when the production well operates with minimal bottom hole pressure, leading to the recovery and dissociation of a significant amount of methane hydrates.