Modeling and monitoring injectivity evolution during cold CO ₂ injection with field evidence from aquistore carbon capture and storage operations

Abstract

This study examines the evolution of carbon dioxide (CO ₂ ) injectivity during intermittent cold injection at the Aquistore site, a Canadian CO ₂ capture and storage demonstration project. Continuous monitoring over 5 years of CO ₂ injection, supported by two highly instrumented injection and observation wells, reveals a general improvement in injectivity performance with time. Bottomhole temperature records indicate persistent cooling near the injector, with injectivity performance inversely correlated to downhole temperature. A non‐isothermal modeling and monitoring framework is applied to interpret these trends through thermo‐hydro‐mechanical (THM) processes. Analysis of injection data using the injectivity index suggests that stress‐dependent non‐isothermal mechanisms and semi‐reversible changes in near‐wellbore permeability govern the observed behavior. During cold injection episodes, minimum effective stresses may exceed the tensile strength of the host rock, leading to aseismic pore deformation, tensile micro‐cracking, and reactivation of critically stressed fractures. Processes such as CO ₂ /brine chemical interaction, rate‐dependent pore flow, and CO ₂ phase behavior are not expected to enhance injectivity. While stress‐induced permeability changes may improve injectivity performance, non‐isothermal stress redistribution could also create flow pathways through low‐permeability formations, including caprock units. These findings highlight the importance of THM processes in injectivity modeling and underscore non‐isothermal effects as a critical consideration for long‐term CO ₂ containment and conformance in deep saline aquifers.