Storage of CO2 hydrate in shallow gas reservoirs: pre‐ and post‐injection periods

Abstract

AbstractWith the growing concern about climate change, interest in reducing CO2 emissions has increased. Geological storage of CO2 is perceived to be one of the most promising methods that could provide significant reductions in CO2 emissions over the short and medium term. Since a major concern regarding geological storage is the possibility of leakage, trapping CO2 in a solid form is quite attractive. Unlike mineral trapping, the kinetics of CO2‐hydrate formation is quite fast, providing the opportunity for long‐term storage of CO2.Thermodynamic calculations suggest that CO2 hydrate is stable at temperatures that occur in a number of formations in Northern Alberta, in an area where there are significant CO2 emissions associated with the production of oil sands and bitumen. In this paper, we study storage of CO2 in hydrate form at conditions similar to those at depleted gas pools in Northern Alberta. Our numerical simulation results show that the CO2 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 CO2 emissions from the oil sands operations in northeastern Alberta.In an earlier paper, we studied hydrate formation during a period of continued CO2 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 CO2 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 CO2 field sequestration. © 2011 Society of Chemical Industry and John Wiley & Sons, Ltd