document preview

Summary

With the increasing concern about climate change, the public, industry, and government are showing increased interest toward reducing carbon dioxide (CO₂) emissions. Geological storage of CO₂ is perceived to be one of the most promising methods to provide significant reduction in CO₂ emissions over the short and medium term. However, one major concern regarding geological storage of CO₂ is the possibility of leakage. CO₂ under the pressure and temperature conditions encountered in most geological settings remains more buoyant than water. Processes that could lead to permanent trapping of CO₂ include geochemical reactions, with the formation of solid minerals. This trapping mechanism is attractive because it converts the CO₂ into a solid compound. However, the time scale of such reactions is perceived to be centuries to millennia. In contrast, the kinetics of CO₂-hydrate formation--leading to trapping of CO₂ in the solid form--is quite fast, providing the opportunity for long-term storage of CO₂. In this paper, geological settings suitable for formation of CO₂ hydrate are investigated. We study storage of CO2 in depleted gas pools of northern Alberta.

Thermodynamic calculations suggest that CO₂ hydrate is stable at temperatures that occur in a number of formations in northern Alberta, in an area where significant CO₂ emissions are associated with production of oil sands and bitumen. Simulation results presented in this paper suggest that, upon CO₂ injection into such depleted gas reservoirs, pressure would initially rise until conditions are appropriate for hydrate formation, enabling storage of large volumes of CO₂ in solid form. Numerical-simulation results suggest that, because of tight packing of CO₂ molecules in the solid (hydrate), the CO₂ storage capacity of these pools is many times greater than their original-gas-in-place capacity. This provides a local option for storage of a portion of the CO2 emissions there.

In this paper, we study the storage capacity of such depleted gas pools and examine the effect of various reservoir properties and operating conditions thereon. In particular, we study the effect of the in-situ gas in formation of mixed-gas hydrates; the effect of rise in temperature as a result of the exothermic reaction of hydrate formation; the effect of initial reservoir pressure, temperature, and porosity; and conditions for avoiding the deleterious formation of hydrate around the wellbore.