Geological and geomechanical factors impacting loss of near-well permeability during CO₂ injection

To maximize safety and cost-efficiency of CO₂ storage, it is necessary to understand how a high permeability in the near-well region can be maintained. All the injected CO₂ needs to pass through this zone before entering the reservoir, and pore clogging/closing here can cause fracturing and channelling of the formation – and will require costly mitigation measures. Recent storage pilots have reported incidents of permeability loss during injection, and these have been ascribed to salt precipitation, bacterial activity, and pressure/temperature variations caused by starts and stops in the injection pattern. As we move to larger scale CO₂ storage projects (gigatonnes/year), a higher number of wells and larger quantities of CO₂ will be dealt with. This means that injectivity issues will become more frequent – and thus have a greater impact on Carbon Capture and Storage (CCS) project economics. Until now, salt precipitation has completely dominated the field of injectivity – and is by far the most studied loss mechanism. In the present publication, we show that there are other important injectivity loss mechanisms that should not be overlooked. These are fines migration, geomechanical factors (e.g. borehole deformation), geochemical factors (e.g. clay content) and rock heterogeneity. We summarize laboratory and field studies of these topics, and discuss their relevance for CO₂ injectivity – particularly in unconsolidated sands. The paper reviews when such injectivity problems occur in the context of CO₂ injection, and how they can be prevented and mitigated.