[H-SC05] CCUS (Carbon Dioxide Capture, Utilization, and Storage) for Climate Mitigation

[HSC05-14] Numerical estimation of leakage suppression using CO₂ hydrate on the oceanic field scale

Takuya Wako¹, Yosuke Sawano¹, *Toru Sato¹ (1.University of Tokyo)

Keywords:Sub-seabed CO2 storage, Geological formation, CO2 hydrate formation, Numerical simulation, Reservoir scale

CO₂ capture and storage is a promising strategy against global warming. Although there is concern about the risk of CO₂ leakage from deep saline aquifers, it is expected that leaking CO₂ forms gas hydrate and this hydrate formation suppresses the CO₂ leakage. When the water depth of a storage site is large: say, about 400 m or more, leaked CO₂ changes its form to gas hydrate, which may block CO₂ rise in the sandy seabed sediment. Therefore, hydrate formation in the sub-seabed sand sediments is one of key factors in lowering the risk of CO₂ leakage and it is important to know conditions under which CO₂ leakage is suppressed by hydrate formation.

On the other hand, using this leakage trap mechanism, it is also possible to store CO₂ in the form of gas hydrate without a cap rock in the sub-seabed geological formation. To estimate the sealing effect of CO₂ hydrate against CO₂ leakage beneath the seafloor, it is necessary to evaluate the permeability of the stratum after CO₂ hydrate forms.

In this study, numerical simulations of hydrate formation in sand sediment are conducted for CO₂ injected in the sub-seabed geological formation. When modelling CO₂ hydrate formation, it is assumed that the hydrate forms on the CO₂-water interface and on the surface of the sand particles after CO₂ plume front passes by during its rise. Permeability reduction during hydrate formation was modelled using the results of microscale hydrate simulations with the phase field model and lattice Boltzmann method in the literature.

First, the processes of CO₂-water two-phase flow and CO₂ hydrate formation in the sand sediment under the experimental conditions are analysed by the present numerical model. Simulation results are compared with the experimental data, so that unknown parameters in the models are determined by parameter-fitting.

Simulation results suggest that the total hydrate formation rate is higher near the boundary of the reaction vessel, and CO₂ hydrate is mainly distributed near the boundary of the reaction vessel due to the cooling effect of the temperature-controlled boundary. Furthermore, it is also indicated that CO₂ hydrate formation on the hydrate film behind the gas front makes the most important contribution to the high CO₂ hydrate saturation near the boundary; on the contrary, CO₂ hydrate formation on the gas front and on the surface of the sand particles behind the gas front only have has a very small effect on CO₂ hydrate saturation in the sand sediment. Therefore, on the basis of the analysis above, we can draw the conclusion that the sharp permeability reduction of the sand sediment during CO₂ injection is mainly caused by the part of CO₂ hydrate formation on the hydrate film behind the CO₂ plume front, which is likely to exist between the sand particles and occupy the pore space of the sand sediment, resulting in blockage of the gas flow.

Then, this numerical method was applied to 3D realistic geological formation to simulate whether hydrate seal is formed to block the leakage of CO₂ and to store CO₂ safely in the form of gas hydrate in the reservoir scale. The results from numerical simulations showed that the formation of a CO₂ hydrate layer could block the upwards migrating CO₂ under most conditions of injection depth, seafloor depth, seafloor temperature, and injection rate, while in some cases, CO₂ leaks before hydrate forms to occupy the pore space enough to block the leakage. Therefore, it is important to choose storage sea sites: particularly, absolute permeability.

Acknowledgement
This work has been conducted under “Sustainable CCS project” by the Ministry of the Environment, Government of Japan.