Abstract
Reliable CO2 injection into geological formations is essential for large-scale carbon storage, yet hydrate formation during injection can significantly impair injectivity and flow stability. This study investigated the multiphase flow behavior of liquid CO2 injected into water-saturated sediments using a combination of laboratory experiments and computational fluid dynamics (CFD) simulations. Liquid CO2 injection experiments were conducted in a horizontal one-dimensional reactor designed to simulate water-saturated sediment. Under hydrate-stable conditions at 274.15 K and 4.0 MPa, CO2 hydrate formation caused severe flow restriction and eventual plugging within the reactor, whereas stable CO2 transport was maintained at 286.15 K without persistent plugging. The addition of monoethylene glycol as a thermodynamic hydrate inhibitor mitigated hydrate formation; however, its apparent inhibition performance deviated from closed-system expectations. CO2 discharge resumed after approximately 4 h at 4.6 mol% MEG, whereas the pressure increased to approximately 10 MPa after about 8 h at 8.8 mol% MEG, owing to dynamic water/inhibitor redistribution during liquid CO2 injection. CFD simulations complemented the experiments by resolving internal phase distributions and multiphase transport processes that cannot be directly observed experimentally. The simulations revealed the formation of an inlet-side dry-out region, hydrate accumulation in the mid-section, and preferential flow pathways that control CO2 migration and injectivity. These results provide mechanistic insight into hydrate-induced flow restriction during liquid CO2 injection and highlight important considerations for hydrate mitigation in geological CO2 storage systems.