Pressurization and brine displacement issues for deep saline formation CO2 storage

Abstract Deep saline formations are expected to store gigatonnes of CO 2 over the coming decades, making a significant contribution to greenhouse gas mitigation. At present, our experience of deep saline formation storage is limited to a small number of demonstration projects that have successfully injected megatonnes of captured CO 2 . However, concerns have been raised over pressurization, and related brine displacement, in deep saline formations, given the anticipated scale of future storage operations. Whilst industrial-scale demonstration projects such as Sleipner and In Salah have not experienced problems, generic flow models have indicated that, in some cases, pressure may be an issue. The problem of modeling deep saline formation pressurization has been approached in a number of different ways by researchers, with published analytical and numerical solutions showing a wide range of outcomes. The divergence of results (either supporting or negating the pressurization issue) principally reflects the a priori choice of boundary conditions. These approaches can be summed up as either ‘open’ or ‘closed’: (a) open system models allow the formation pressure to dissipate laterally, resulting in reasonable storage scenarios; (b) closed system models predict pressurization, resulting in a loss of injectivity and/or storage formation leakage. The latter scenario predicts that storage sites will commonly fail to accommodate the injected CO 2 at a rate sufficient to handle routine projects. Our models aim to demonstrate that pressurization and brine displacement need to be addressed at a regional scale with geologically accurate boundary conditions. Given that storage formations are unlikely to have zero-flow boundaries (closed system assumption), the boundary contribution to pressure relief from low permeability shales may be significant. At a field scale, these shales are effectively perfect seals with respect to multiphase flow, but are open with respect to single phase flow and pressure dissipation via brine displacement at a regional scale. This is sometimes characterized as a ‘semi-closed’ system. It follows that the rate at which pressure can be dissipated (and CO 2 injected) is highly sensitive to the shale permeability. A common range from sub-millidarcy (10 −17  m 2 ) to sub-nanodarcy (10 −22  m 2 ) is considered, and the empirical relationships of permeability with respect to porosity and threshold pressure are reviewed in light of the regional scale of CO 2 storage in deep saline formations. Our model indicates that a boundary permeability of about a microdarcy (10 −18  m 2 ) is likely to provide sufficient pressure dissipation via brine displacement to allow for routine geological storage. The models also suggest that nanodarcy shales (10 −21  m 2 ) will result in significant pressurization. There is regional evidence, from the North Sea, that typical shale permeabilities at depths associated with CO 2 storage (1–3 km) are likely to favor storage, relegating pressurization to a manageable issue.