Storage of CO 2 hydrate in shallow gas reservoirs: pre‐ and post‐injection periods

With the growing concern about climate change, interest in reducing CO 2 emissions has increased. Geological storage of CO 2 is perceived to be one of the most promising methods that could provide significant reductions in CO 2 emissions over the short and medium term. Since a major concern regarding geological storage is the possibility of leakage, trapping CO 2 in a solid form is quite attractive. Unlike mineral trapping, the kinetics of CO 2 ‐hydrate formation is quite fast, providing the opportunity for long‐term storage of CO 2 . Thermodynamic calculations suggest that CO 2 hydrate is stable at temperatures that occur in a number of formations in Northern Alberta, in an area where there are significant CO 2 emissions associated with the production of oil sands and bitumen. In this paper, we study storage of CO 2 in hydrate form at conditions similar to those at depleted gas pools in Northern Alberta. Our numerical simulation results show that the CO 2 storage capacity of such pools is many times greater than their original gas‐in‐place. This provides a local option for storage of a portion of the CO 2 emissions from the oil sands operations in northeastern Alberta. In an earlier paper, we studied hydrate formation during a period of continued CO 2 injection. In this paper, we extend the duration of the investigation to include the period after injection has stopped. In particular, we study the storage capacity of such depleted gas pools and the fate of the hydrate over long periods of time when the injection of CO 2 has slowed down or ceased. We examine the effect of properties of the reservoir and cap/base rocks, as well as operating conditions. In particular, we investigate a shut‐in case as the most realistic condition in CO 2 field sequestration. © 2011 Society of Chemical Industry and John Wiley & Sons, Ltd