Mineralization

• Pore space (relative permeability) trapping;

• Adsorption of CO2 onto organic material.

The rate of fluid flow depends on the number and properties of the fluid phases present in the formation. When two or more fluids mix in any proportion, they are referred to as miscible fluids. If they do not mix, they are referred to as immiscible. The presence of several different phases may decrease the permeability and slow the rate of migration. If CO2 is injected into a gas reservoir, a single miscible fluid phase consisting of natural gas and CO2 is formed locally. When CO2 is injected into a deep saline formation in a liquid or liquid-like supercritical dense phase, it is immiscible in water. Carbon dioxide injected into an oil reservoir may be miscible or immiscible, depending on the oil composition and the pressure and temperature of the system (Section 5.3.2). When CO2 is injected into coal beds, in addition to some of the processes listed above, adsorption and desorption of gases (particularly methane) previously adsorbed on the coal take place, as well as swelling or shrinkage of the coal itself (Section 5.3.4).

Because supercritical CO2 is much less viscous than water and oil (by an order of magnitude or more), migration is controlled by the contrast in mobility of CO2 and the in situ formation fluids (Celia et al, 2005; Nordbotten et al., 2005a). Because of the comparatively high mobility of CO2, only some of the oil or water will be displaced, leading to an average saturation of CO2 in the range of 30-60%. Viscous fingering can cause CO2 to bypass much of the pore space, depending on the heterogeneity and anisotropy of rock permeability (van der Meer, 1995; Ennis-King and Paterson, 2001; Flett et al, 2005). In natural gas reservoirs, CO2 is more viscous than natural gas, so the 'front' will be stable and viscous fingering limited.

The magnitude of the buoyancy forces that drive vertical flow depends on the type of fluid in the formation. In saline formations, the comparatively large density difference (3050%) between CO2 and formation water creates strong buoyancy forces that drive CO2 upwards. In oil reservoirs, the density 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).

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).

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 of millimetres to centimetres per year (Bachu et al., 1994). Thus, migration rates of dissolved CO2 are substantially lower than for separate-phase CO2.

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 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).

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).

Figure 5.7 Radial simulations of CO2 injection into a homogeneous formation 100 m thick, at a depth of 1 km, where the pressure is 10 MPa and the temperature is 40°C. The injection rate is 1 MtCO2 yr-1 for 20 years, the horizontal permeability is 10 -13 m2 (approximately 100 mD) and the vertical permeability is one-tenth of that. The residual CO2 saturation is 20%. The first three parts of the figure at 2, 20 and 200 years, show the gas saturation in the porous medium; the second three parts of the figure at 200, 2000 and 4000 years, show the mass fraction of dissolved CO2 in the aqueous phase (after Ennis-King and Paterson, 2003).

Figure 5.7 Radial simulations of CO2 injection into a homogeneous formation 100 m thick, at a depth of 1 km, where the pressure is 10 MPa and the temperature is 40°C. The injection rate is 1 MtCO2 yr-1 for 20 years, the horizontal permeability is 10 -13 m2 (approximately 100 mD) and the vertical permeability is one-tenth of that. The residual CO2 saturation is 20%. The first three parts of the figure at 2, 20 and 200 years, show the gas saturation in the porous medium; the second three parts of the figure at 200, 2000 and 4000 years, show the mass fraction of dissolved CO2 in the aqueous phase (after Ennis-King and Paterson, 2003).

Figure 5.8 Simulation of 50 years of injection of CO2 into the base of a saline formation. Capillary forces trap CO2 in the pore spaces of sedimentary rocks. (a) After the 50-year injection period, most CO2 is still mobile, driven upwards by buoyancy forces. (b) After 1000 years, buoyancy-driven flow has expanded the volume affected by CO2 and much is trapped as residual CO2 saturation or dissolved in brine (not shown). Little CO2 is mobile and all CO2 is contained within the aquifer (after Kumar et al., 2005).

Figure 5.8 Simulation of 50 years of injection of CO2 into the base of a saline formation. Capillary forces trap CO2 in the pore spaces of sedimentary rocks. (a) After the 50-year injection period, most CO2 is still mobile, driven upwards by buoyancy forces. (b) After 1000 years, buoyancy-driven flow has expanded the volume affected by CO2 and much is trapped as residual CO2 saturation or dissolved in brine (not shown). Little CO2 is mobile and all CO2 is contained within the aquifer (after Kumar et al., 2005).

Paterson, 2003), although appropriate reservoir engineering can accelerate or modify solubility trapping (Keith et al., 2005).

5.2.2 CO2 storage mechanisms in geological formations

The effectiveness of geological storage depends on a combination of physical and geochemical trapping mechanisms (Figure 5.9). The most effective storage sites are those where CO2 is immobile because it is trapped permanently under a thick, low-permeability seal or is converted to solid minerals or is adsorbed on the surfaces of coal micropores or through a combination of physical and chemical trapping mechanisms.

5.2.2.1 Physical trapping: stratigraphic and structural Initially, physical trapping of CO2 below low-permeability seals (caprocks), such as very-low-permeability shale or salt beds, is the principal means to store CO2 in geological formations (Figure 5.3). In some high latitude areas, shallow gas hydrates may conceivably act as a seal. Sedimentary basins have such closed, physically bound traps or structures, which are occupied mainly by saline water, oil and gas. Structural traps include those formed by folded or fractured rocks. Faults can act as permeability barriers in some circumstances and as preferential pathways for fluid flow in other circumstances (Salvi et al., 2000). Stratigraphic traps are formed by changes in rock type caused by variation in the setting where the rocks were deposited. Both of these types of traps are suitable for CO2 storage, although, as discussed in Section 5.5, care must be taken not to exceed the allowable overpressure to avoid fracturing the caprock or re-activating faults (Streit et al., 2005).

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