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Chapter 5: Underground geological storage 217 Table 5.1) and some authors have suggested that CO2 injection might result in lower gas recovery factors, particularly for very heterogeneous fields (Clemens and Wit, 2002). 5.3.3 Saline formations 5.3.4 Coal seams Coal contains fractures (cleats) that impart some permeability to the system. Between cleats, solid coal has a very large number of micropores into which gas molecules from the cleats can diffuse and be tightly adsorbed. Coal can physically adsorb many gases and may contain up to 25 normal m3 (m3 at 1 atm and 0°C) methane per tonne of coal at coal seam pressures. It has a higher affinity to adsorb gaseous CO2 than methane (Figure 5.17). The volumetric ratio of adsorbable CO2:CH4 ranges from as low as one for mature coals such as anthracite, to ten or more for younger, immature coals such as lignite. Gaseous CO2 injected through wells will flow through the cleat system of the coal, diffuse into the coal matrix and be adsorbed onto the coal micropore surfaces, freeing up gases with lower affinity to coal (i.e., methane). The process of CO2 trapping in coals for temperatures and pressures above the critical point is not well understood (Larsen, 2003). It seems that adsorption is gradually replaced by absorption and the CO2 diffuses or ‘dissolves’ in coal. Carbon dioxide is a ‘plasticizer’ for coal, lowering the temperature required to cause the transition from a glassy, brittle structure to a rubbery, plastic structure (coal softening). In one case, the transition temperature was interpreted to drop from about 400oC at 3 MPa to <30oC at 5.5 MPa CO2 pressure (Larsen, 2003). The transition temperature is dependent on the maturity of the coal, the maceral content, the ash content and the confining stress and is not easily extrapolated to the field. Coal plasticization or softening, may adversely affect the permeability that would allow CO2 injection. Furthermore, coal swells as CO2 is adsorbed and/or absorbed, which reduces permeability and injectivity by orders of magnitude or more (Shi and Durucan, 2005) and which may be counteracted by increasing the injection pressures (Clarkson and Bustin, 1997; Palmer and Mansoori, 1998; Krooss et al., 2002; Larsen, 2003). Some studies suggest that the injected CO2 may react with coal (Zhang et al., 1993), further highlighting the difficulty in injecting CO2 into low- permeability coal. Saline formations are deep sedimentary rocks saturated with formation waters or brines containing high concentrations of dissolved salts. These formations are widespread and contain enormous quantities of water, but are unsuitable for agriculture or human consumption. Saline brines are used locally by the chemical industry and formation waters of varying salinity are used in health spas and for producing low-enthalpy geothermal energy. Because the use of geothermal energy is likely to increase, potential geothermal areas may not be suitable for CO2 storage. It has been suggested that combined geological storage and geothermal energy may be feasible, but regions with good geothermal energy potential are generally less favourable for CO2 geological storage because of the high degree of faulting and fracturing and the sharp increase of temperature with depth. In very arid regions, deep saline formations may be considered for future water desalinization. The Sleipner Project in the North Sea is the best available example of a CO2 storage project in a saline formation (Box 5.1). It was the first commercial-scale project dedicated to geological CO2 storage. Approximately 1 MtCO2 is removed annually from the produced natural gas and injected underground at Sleipner. The operation started in October 1996 and over the lifetime of the project a total of 20 MtCO2 is expected to be stored. A simplified diagram of the Sleipner scheme is given in Figure 5.4. The CO2 is injected into poorly cemented sands about 800– 1000 m below the sea floor. The sandstone contains secondary thin shale or clay layers, which influence the internal movement of injected CO2. The overlying primary seal is an extensive thick shale or clay layer. The saline formation into which CO2 is injected has a very large storage capacity. The fate and transport of the Sleipner CO2 plume has been successfully monitored (Figure 5.16) by seismic time-lapse surveys (Section 5.6). These surveys have helped improve the conceptual model for the fate and transport of stored CO2. The vertical cross-section of the plume shown in Figure 5.16 indicates both the upward migration of CO2 (due to buoyancy forces) and the role of lower permeability strata within the formation, diverting some of the CO2 laterally, thus spreading out the plume over a larger area. The survey also shows that the caprock prevents migration out of the storage formation. The seismic data shown in Figure 5.16 illustrate the gradual growth of the plume. Today, the footprint of the plume at Sleipner extends over approximately 5 km2. Reservoir studies and simulations (Section 5.4.2) have shown that the CO2-saturated brine will eventually become denser and sink, eliminating the potential for long-term leakage (Lindeberg and Bergmo, 2003). If CO2 is injected into coal seams, it can displace methane, thereby enhancing CBM recovery. Carbon dioxide has been injected successfully at the Allison Project (Box 5.7) and in the Alberta Basin, Canada (Gunter et al., 2005), at depths greater than that corresponding to the CO2 critical point. Carbon dioxide- ECBM has the potential to increase the amount of produced methane to nearly 90% of the gas, compared to conventional recovery of only 50% by reservoir-pressure depletion alone (Stevens et al., 1996). Coal permeability is one of several determining factors in selection of a storage site. Coal permeability varies widely and generally decreases with increasing depth as a result of cleat closure with increasing effective stress. Most CBM-producing wells in the world are less than 1000 m deep.PDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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