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206 IPCC Special Report on Carbon dioxide Capture and Storage difference and buoyancy forces are not as large, particularly if the oil and CO2 are miscible (Kovscek, 2002). In gas reservoirs, the opposite effect will occur, with CO2 migrating downwards under buoyancy forces, because CO2 is denser than natural gas (Oldenburg et al., 2001). of millimetres to centimetres per year (Bachu et al., 1994). Thus, migration rates of dissolved CO2 are substantially lower than for separate-phase CO2. In saline formations and oil reservoirs, the buoyant plume of injected CO2 migrates upwards, but not evenly. This is because a lower permeability layer acts as a barrier and causes the CO2 to migrate laterally, filling any stratigraphic or structural trap it encounters. The shape of the CO2 plume rising through the rock matrix (Figure 5.6) is strongly affected by formation heterogeneity, such as low-permeability shale lenses (Flett et al., 2005). Low-permeability layers within the storage formation therefore have the effect of slowing the upward migration of CO2, which would otherwise cause CO2 to bypass deeper parts of the storage formation (Doughty et al., 2001). Water saturated with CO2 is slightly denser (approximately 1%) than the original formation water, depending on salinity (Enick and Klara, 1990; Bachu and Adams, 2003). With high vertical permeability, this may lead to free convection, replacing the CO2-saturated water from the plume vicinity with unsaturated water, producing faster rates of CO2 dissolution (Lindeberg and Wessel-Berg, 1997; Ennis-King and Paterson, 2003). Figure 5.7 illustrates the formation of convection cells and dissolution of CO2 over several thousand years. The solubility of CO2 in brine decreases with increasing pressure, decreasing temperature and increasing salinity (Annex 1). Calculations indicate that, depending on the salinity and depth, 20–60 kgCO2 can dissolve in 1 m3 of formation fluid (Holt et al., 1995; Koide et al., 1995). With the use of a homogeneous model rather than a heterogeneous one, the time required for complete CO2 dissolution may be underestimated. As CO2 migrates through the formation, some of it will dissolve into the formation water. In systems with slowly flowing water, reservoir-scale numerical simulations show that, over tens of years, a significant amount, up to 30% of the injected CO2, will dissolve in formation water (Doughty et al., 2001). Basin-scale simulations suggest that over centuries, the entire CO2 plume dissolves in formation water (McPherson and Cole, 2000; Ennis-King et al., 2003). If the injected CO2 is contained in a closed structure (no flow of formation water), it will take much longer for CO2 to completely dissolve because of reduced contact with unsaturated formation water. Once CO2 is dissolved in the formation fluid, it migrates along with the regional groundwater flow. For deep sedimentary basins characterized by low permeability and high salinity, groundwater flow velocities are very low, typically on the order As CO2 migrates through a formation, some of it is retained in the pore space by capillary forces (Figure 5.6), commonly referred to as ‘residual CO2 trapping’, which may immobilize significant amounts of CO2 (Obdam et al., 2003; Kumar et al., 2005). Figure 5.8 illustrates that when the degree of trapping is high and CO2 is injected at the bottom of a thick formation, all of the CO2 may be trapped by this mechanism, even before it reaches the caprock at the top of the formation. While this effect is formation-specific, Holtz (2002) has demonstrated that residual CO2 saturations may be as high as 15–25% for many typical storage formations. Over time, much of the trapped CO2 dissolves in the formation water (Ennis-King and Figure 5.6 Simulated distribution of CO2 injected into a heterogeneous formation with low-permeability layers that block upward migration of CO2. (a) Illustration of a heterogeneous formation facies grid model. The location of the injection well is indicated by the vertical line in the lower portion of the grid. (b) The CO2 distribution after two years of injection. Note that the simulated distribution of CO2 is strongly influenced by the low-permeability layers that block and delay upward movement of CO2 (after Doughty and Pruess, 2004).PDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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