Microseismic Monitoring and Geomechanical Modelling of CO2 - bris

1.2. CCS OVERVIEW
Figure 1.2: CCS sites by annual storage volume (as of 2009). Data provided by the IEA Greenhouse
Gas Program. Many smaller CO 2 injection sites are not included on this plot.
industrial complexes and pumped via pipelines to the storage area. Storage can be achieved in saline
aquifers, depleted oil reservoirs and unmineable coal seams.
1.2.1 Storage mechanisms
CO 2 is injected at pressures over 8MPa, where it exists as a supercritical fluid with a density of
∼ 700kg/m 3 , which is less dense than most formation brines and oils. Buoyancy forces will therefore
drive the injected CO 2 upwards until it meets an impermeable layer capable of preventing further
fluid migration. Once trapped, the CO 2 will exist as a free phase ‘bubble’ below the caprock. This is
known as stratigraphic trapping, and it is estimated that, during the early stages of injection most of
the injected CO 2 will be trapped in this manner (Johnson et al., 2001).
Free phase CO 2 will slowly dissolve into any residual fluids present in the reservoir. Dissolution of
CO 2 increases the density of brine, so buoyancy forces will force such fluids down, reducing the risk
of leakage. This is known as hydrodynamic trapping, and Johnson et al. (2001) estimates that up to
15% of injected CO 2 may be stored in this manner.
Free phase CO 2 and CO 2 enriched brines will be in chemical disequilibrium with the rocks of the
reservoir, and so chemical reactions will occur between them. This may result in both dissolution
and/or precipitation reactions. If minerals containing carbonate are precipitated, this will represent
the optimum storage scenario, as the precipitated minerals will be immobile, so there is no risk of
leakage. However, the reaction rates for such processes are very slow, so on decadal timescales only a
very small amount (