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Chapter 5: Underground geological storage 223 Figure 5.18 Schematic showing the time evolution of various CO2 storage mechanisms operating in deep saline formations, during and after injection. Assessing storage capacity is complicated by the different time and spatial scales over which these processes occur. the amount trapped (estimated to be 3%) and storage efficiency, estimated as 2–6% (2% for closed aquifer with permeability barriers; 6% for open aquifer with almost infinite extent), 4% if open/closed status is not known. The volume in traps is assumed to be proportional to the total pore volume, which may not necessarily be correct. Early estimates of the total US storage capacity in deep saline formations suggested a total of up to 500 GtCO2 (Bergman and Winter, 1995). A more recent estimate of the capacity of a single deep formation in the United States, the Mount Simon Sandstone, is 160–800 GtCO2 (Gupta et al., 1999), suggesting that the total US storage capacity may be higher than earlier estimates. Assuming that CO2 will dissolve to saturation in all deep formations, Bachu and Adams (2003) estimated the storage capacity of the Alberta basin in Western Canada to be approximately 4000 GtCO , which is a of the various trapping mechanisms during the evolution of a CO2 plume (Section 5.2 and Figure 5.18). In addition, the storage capacity of deep saline formations can be determined only on a case-by-case basis. Alberta Basin could become saturated with CO2, which is not likely. An Australian storage capacity estimate of 740 GtCO2 was determined by a cumulative risked-capacity approach for 65 potentially viable sites from 48 basins (Bradshaw et al., 2003). The total capacity in Japan has been estimated as 1.5–80 GtCO2, mostly in offshore formations (Tanaka et al., 1995). To date, most of the estimates of CO2 storage capacity in deep saline formations focus on physical trapping and/or dissolution. These estimates make the simplifying assumption that no geochemical reactions take place concurrent with CO2 injection, flow and dissolution. Some recent work suggests that it can take several thousand years for geochemical reactions to have a significant impact (Xu et al., 2003). The CO2 storage capacity from mineral trapping can be comparable to the capacity in solution per unit volume of sedimentary rock when formation porosity is taken into account (Bachu and Adams, 2003; Perkins et al., 2005), although the rates and time frames of these two processes are different. Within these wide ranges, the lower figure is generally the estimated storage capacity of volumetric traps within the deep saline formations, where free-phase CO2 would accumulate. The larger figure is based on additional storage mechanisms, mainly dissolution but also mineral trapping. The various methods and data used in these capacity estimates demonstrate a high degree of uncertainty in estimating regional or global storage capacity in deep saline formations. In the examples from Europe and Japan, the maximum estimate is 15 to 50 times larger than the low estimate. Similarly, global estimates of storage capacity show a wide range, 100–200,000 GtCO2, reflecting different methodologies, levels of uncertainties and considerations of effective trapping mechanisms. More than 14 global assessments of capacity have been made by using these types of approaches (IEA-GHG, 2004). The range of estimates from these studies is large (200–56,000 GtCO2), reflecting both the different assumptions used to make these estimates and the uncertainty in the parameters. Most of the estimates are in the range of several hundred Gtonnes of CO2. Volumetric capacity estimates that are based on local, reservoir-scale numerical simulations of CO2 injection suggest occupancy of the pore space by CO2 on the order of a few percent as a result of gravity segregation and viscous fingering (van der Meer, 1992, 1995; Krom et al., 1993; Ispen and Jacobsen, 1996). Koide et al. (1992) used the areal method of projecting natural resources reserves and assumed that 1% of the total area of the world’s sedimentary basins can be used for CO2 storage. Other studies considered that 2–6% of formation area can be used for CO2 storage. However, Bradshaw and Dance (2005) have shown there is no correlation between geographic area of a sedimentary basin and its capacity for either hydrocarbons (oil and gas reserves) or CO2 storage. The assessment of this report is that it is very likely that global storage capacity in deep saline formations is at least 1000 GtCO2. Confidence in this assessment comes from the fact that oil and gas fields ‘discovered’ have a global storage capacity of approximately 675–900 GtCO2 and that they occupy only a small fraction of the pore volume in sedimentary basins, the rest being occupied by brackish water and brine. Moreover, oil and gas reservoirs occur only in about half of the world’s sedimentary basins. Additionally, regional estimates suggest that significant storage capacity is available. Significantly more storage capacity is likely to be available in deep saline formations. The literature is not adequate to support a robust estimate of the maximum geological storage capacity. Some studies suggest that it might be little more than 1000 GtCO2, while others indicate that the upper figure could be an order of magnitude higher. More detailed regional and local capacity assessments are required to resolve this issue. The storage capacity of Europe has been estimated as 30– 577 GtCO2 (Holloway, 1996; Bøe et al., 2002; Wildenborg et al., 2005b). The main uncertainties for Europe are estimates of 5.3.7.3 Storage in coal 2 theoretical maximum assuming that all the pore water in the No commercial CO2-ECBM operations exist and a comprehensive realistic assessment of the potential for CO2PDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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