Geomechanics workflows are being increasingly utilized within the industry to assess the risks associated with oil and gas recovery during depletion, including well integrity issues due to reservoir compaction and possible fault reactivation as reservoir pressures decline over the lifecycle of the field. However, little work has been conducted on the feasibility of utilizing existing production wells for the safe injection of CO2 as part of a carbon capture and storage (CCS) project.
Field-wide 3D analyses conducted to date have taken a macroscopic view in terms of reservoir performance, but little work has been conducted at the wellbore centric scale. For the cases where a depleted field is being considered for long-term CO2 containment, it is vital that the effects of temperature are included in the reservoir flow model. Injected CO2 can be many hundreds of degrees cooler than the in-situ reservoir rock formations and exposure to these cooler temperatures will induce sudden deformations in the vicinity of the injector well. As the temperature front progresses into the reservoir, cap-rock integrity may be breached due to reductions in effective stress, in addition to the possible creation of tensile fractures. The resulting stress changes due to thermal diffusion may also have a significant effect on the wellbore architecture itself, as the cooling formation will exert tensile strains on the wellbore casing and surrounding cement.
This study examines the effects of injecting cool CO2 into a relatively deep, thermally active reservoir, on the wellbore architecture and whether the induced strains in the reservoir formation arising from both increases in pressure and reductions in temperature can be safely withstood.
