On the Temporal Evolution of Non-Isothermal Injectivity Behaviour at an Active CO2 Injection Site Available to Purchase

Continuous monitoring of field conditions over 5 years of intermittent cold CO₂ injection at the Aquistore storage site, a Canadian CCS demonstration project, suggests a general increase in well injectivity performance with time. This paper presents injectivity-relevant field observations and operational data, collected from the two highly instrumented injection and observation wells at Aquistore which were specifically drilled for CO2 storage.

In this paper, we demonstrate that hydro-thermo-mechanical (THM) processes are involved in the noted variation of injectivity. Interpreting injection data in the context of injectivity index, the temporal evolution of CO₂ injectivity behaviour could most likely be explained through stress-dependent thermal mechanisms associated with semi-reversible effective permeability in the near-wellbore region. This region experiences sufficiently negative minimum effective stress that overcomes the tensile strength of the host rock leading to aseismic non-isothermal pore deformation, tensile micro-cracks, and/or opening of pre-existing critically stressed fractures. Events such as CO₂/brine chemical interaction (e.g. salt precipitation), rate-dependent pore flow (e.g. high-velocity laminar/turbulent) and CO2 phase behaviour (e.g. kinematic fluidity) are not anticipated to positively contribute to the injectivity performance.

Although semi-reversible stress-dependent changes in effective permeability are speculated to improve CO₂ injectivity performance, the non-isothermal induced stresses could also create new, localized, flow pathways through low-permeability non-reservoir formations, including caprock units. Understanding this thermal phenomenon is a critical consideration on long-term containment and conformance of the host aquifers and it needs to be further investigated.

As a viable short-to-medium term solution to isolate huge quantities of CO₂, effective geological carbon storage requires an improved understanding of injectivity behaviour in the subsurface formations (Law and Bachu 1996, Torsæter and Cerasi 2018). Over the past few decades, several CO2 storage and Enhanced Oil Recovery (EOR) projects have demonstrated the feasibility and technical difficulties arising from significantly increasing CO₂ injection rates (e.g. Sleipner of Norway, Illinois Basin Decatur of USA, Quest and Weyburn of Canada); such actions would potentially lead to multiple-fold upsurge in the storage capacity aiming to partially meet the global commitments of climate change through green house gas reduction policies (GCCSI 2016; Hitchon, B. 2012; Chadwick et al. 2008; Chalaturnyk 2007). However, moving beyond the existing limits of CO₂ containment entails considerable risks (IEA 2016). As high injectivity plays a vital role to reduce the cost of geological CO₂ sequestration, sufficient understanding of injectivity variation in the current settings of CO₂ storage projects is needed.