Uncertain, but possibly 104
a These numbers would increase by 25% if "undiscovered" oil and gas fields were included in this assessment.
a These numbers would increase by 25% if "undiscovered" oil and gas fields were included in this assessment.
the produced reserves (not the original oil or gas in place) could be replaced by CO2 (theoretical capacity) for all reservoirs in Western Canada, on the basis of in situ pressure, temperature and pore volume. Reduction coefficients were then applied to account for aquifer invasion and all other effects (effective capacity). This value was then reduced for depth (900-3500 m) and size (practical capacity) (Bachu and Shaw, 2005).
The storage potential of northwestern Europe is estimated at more than 40 GtCO2 for gas reservoirs and 7 GtCO2 for oil fields (Wildenborg et al., 2005b). The European estimates are based on all reserves (no significant fields occur above 800 m). Carbon dioxide density was calculated from the depth, pressure and temperature of fields in most cases; where these were not available, a density of 700 kg m-3 was used. No assumption was made about the amount of oil recovered from the fields before CO2 storage was initiated and tertiary recovery by EOR was not included. In Western Canada, the practical CO2 storage potential in the Alberta and Williston basins in reservoirs with capacity more than 1 MtCO2 each was estimated to be about 1 GtCO2 in oil reservoirs and about 4 GtCO2 in gas reservoirs. The capacity in all discovered oil and gas reservoirs is approximately 10 GtCO2 (Bachu et al, 2004; Bachu and Shaw, 2005). For Canada, the CO2 density was calculated for each reservoir from the pressure and temperature. The oil and gas recovery was that provided in the reserves databases or was based on actual production. For reservoirs suitable for EOR, an analytical method was developed to estimate how much would be produced and how much CO2 would be stored (Shaw and Bachu, 2002). In the United States, the total storage capacity in discovered oil and gas fields is estimated to be approximately 98 GtCO2 (Winter and Bergman, 1993; Bergman et al., 1997). Data on production to date and known reserves and resources indicate that Australia has up to 15 GtCO2 storage capacity in gas reservoirs and 0.7 GtCO2 in oil reservoirs. The Australian estimates used field data to recalculate the CO2 that could occupy the producible volume at field conditions. The total storage capacity in discovered fields for these regions with bottom-up assessments is 170 GtCO2.
Although not yet assessed, it is almost certain that significant storage potential exists in all other oil and gas provinces around the world, such as the Middle East, Russia, Asia, Africa and Latin America.
Global capacity for CO2-EOR opportunities is estimated to have a geological storage capacity of 61-123 GtCO2, although as practised today, CO2-EOR is not engineered to maximize CO2 storage. In fact, it is optimized to maximize revenues from oil production, which in many cases requires minimizing the amount of CO2 retained in the reservoir. In the future, if storing CO2 has an economic value, co-optimizing CO2 storage and EOR may increase capacity estimates. In European capacity studies, it was considered likely that EOR would be attempted at all oil fields where CO2 storage took place, because it would generate additional revenue. The calculation in Wildenborg et al. (2005b) allows for different recovery factors based on API (American Petroleum Institute) gravity of oil. For Canada, all 10,000 oil reservoirs in Western Canada were screened for suitability for EOR on the basis of a set of criteria developed from EOR literature. Those oil reservoirs that passed were considered further in storage calculations (Shaw and Bachu, 2002).
Global estimates of storage capacity in oil reservoirs vary from 126 to 400 GtCO2 (Freund, 2001). These assessments, made on a top-down basis, include potential in undiscovered reservoirs. Comparable global capacity for CO2 storage in gas reservoirs is estimated at 800 GtCO2 (Freund, 2001). The combined estimate of total ultimate storage capacity in discovered oil and gas fields is therefore very likely 675-900 GtCO2. If undiscovered oil and gas fields are included, this figure would increase to 900-1200 GtCO2, but the confidence level would decrease.1
In comparison, more detailed regional estimates made for northwestern Europe, United States, Australia and Canada indicate a total of about 170 GtCO2 storage capacity in their existing oil and gas fields, with the discovered oil and gas reserves of these countries accounting for 18.9% of the world total (USGS, 2001a). Global storage estimates that are based on proportionality suggest that discovered worldwide oil and gas reservoirs have a capacity of 900 GtCO2, which is comparable to the global estimates by Freund (2001) of 800 GtCO2 for gas (Stevens et al., 2000) and 123 GtCO2 for oil and is assessed as a reliable value, although water invasion was not always taken into account.
18.104.22.168 Storage in deep saline formations Saline formations occur in sedimentary basins throughout the world, both onshore and on the continental shelves (Chapter 2 and Section 5.3.3) and are not limited to hydrocarbon provinces or coal basins. However, estimating the CO2 storage capacity of deep saline formations is presently a challenge for the following reasons:
• There are multiple mechanisms for storage, including physical trapping beneath low permeability caprock, dissolution and mineralization;
• These mechanisms operate both simultaneously and on different time scales, such that the time frame of CO2 storage affects the capacity estimate; volumetric storage is important initially, but later CO2 dissolves and reacts with minerals;
• Relations and interactions between these various mechanisms are very complex, evolve with time and are highly dependent on local conditions;
• There is no single, consistent, broadly available methodology for estimating CO2 storage capacity (various studies have used different methods that do not allow comparison).
• Only limited seismic and well data are normally available (unlike data on oil and gas reservoirs).
To understand the difficulties in assessing CO2 storage capacity in deep saline formations, we need to understand the interplay
1 Estimates of the undiscovered oil and gas are based on the USGS assessment that 30% more oil and gas will be discovered, compared to the resources known today.
Injection Trap filling Physical trapping Dissolution Residual C02 trapping Mineralization Adsorption
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.
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.
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.
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 storage capacity of Europe has been estimated as 30577 GtCO2 (Holloway, 1996; B0e et al., 2002; Wildenborg et al., 2005b). The main uncertainties for Europe are estimates of 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 GtCO2, which is a theoretical maximum assuming that all the pore water in the 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).
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.
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.
22.214.171.124 Storage in coal
No commercial CO2-ECBM operations exist and a comprehensive realistic assessment of the potential for CO2
storage in coal formations has not yet been made. Normally, commercial CBM reservoirs are shallower than 1500 m, whereas coal mining in Europe and elsewhere has reached depths of 1000 m. Because CO2 should not be stored in coals that could be potentially mined, there is a relatively narrow depth window for CO2 storage.
Assuming that bituminous coals can adsorb twice as much CO2 as methane, a preliminary analysis of the theoretical CO2 storage potential for ECBM recovery projects suggests that approximately 60-200 GtCO2 could be stored worldwide in bituminous coal seams (IEA-GHG, 1998). More recent estimates for North America range from 60 to 90 GtCO2 (Reeves, 2003b; Dooley et al., 2005), by including sub-bituminous coals and lignites. Technical and economic considerations suggest a practical storage potential of approximately 7 GtCO2 for bituminous coals (Gale and Freund, 2001; Gale, 2004). Assuming that CO2 would not be stored in coal seams without recovering the CBM, a storage capacity of 3-15 GtCO2 is calculated, for a US annual production of CBM in 2003 of approximately 0.04 trillion m3 and projected global production levels of 0.20 trillion m3 in the future. This calculation assumes that 0.1 GtCO2 can be stored for every Tcf of produced CBM (3.53 GtCO2 for every trillion m3) and compares well to Gale (2004).
5.3.8 Matching of CO2 s ources and geological storage sites
Matching of CO2 sources with geological storage sites requires detailed assessment of source quality and quantity, transport and economic and environmental factors. If the storage site is far from CO2 sources or is associated with a high level of technical uncertainty, then its storage potential may never be realized.
Matching sources of CO2 to potential storage sites, taking into account projections for future socio-economic development, will be particularly important for some of the rapidly developing economies. Assessment of sources and storage sites, together with numerical simulations, emissions mapping and identification of transport routes, has been undertaken for a number of regions in Europe (Holloway, 1996; Larsen et al., 2005). In Japan, studies have modelled and optimized the linkages between 20 onshore emission regions and 20 offshore storage regions, including both ocean storage and geological storage (Akimoto et al., 2003). Preliminary studies have also begun in India (Garg et al., 2005) and Argentina (Amadeo et al., 2005). For the United States, a study that used a Geographic Information System (GIS) and a broad-based economic analysis (Dooley et al., 2005) shows that about two-thirds of power stations are adjacent to potential geological storage locations, but a number would require transportation of hundreds of kilometres.
Studies of Canadian sedimentary basins that include descriptions of the type of data and flow diagrams of the assessment process have been carried out by Bachu (2003).
Results for the Western Canada Sedimentary Basin show that, while the total capacity of oil and gas reservoirs in the basin is several Gtonnes of CO2, the capacity of underlying deep saline formations is two to three orders of magnitude higher. Most major CO2 emitters have potential storage sites relatively close by, with the notable exception of the oil sands plants in northeastern Alberta (current CO2 emissions of about 20 MtCO2 yr-1).
In Australia, a portfolio approach was undertaken for the continent to identify a range of geological storage sites (Rigg et al., 2001; Bradshaw et al., 2002). The initial assessment screened 300 sedimentary basins down to 48 basins and 65 areas. Methodology was developed for ranking storage sites (technical and economic risks) and proximity of large CO2 emission sites. Region-wide solutions were sought, incorporating an economic model to assess full project economics over 20 to 30 years, including costs of transport, storage, monitoring and Monte Carlo analysis. The study produced three storage estimates:
• Total capacity of 740 GtCO2, equivalent to 1600 years of current emissions, but with no economic barriers considered;
• 'Realistic' capacity of 100-115 MtCO2 yr-1 or 50% of annual stationary emissions, determined by matching sources with the closest viable storage sites and assuming economic incentives for storage;
• 'Cost curve' capacity of 20-180 MtCO2 yr-1, with increasing storage capacity depending on future CO2 values.
126.96.36.199 Methodology and assessment criteria Although some commonality exists in the various approaches for capacity assessment, each study is influenced by the available data and resources, the aims of the respective study and whether local or whole-region solutions are being sought. The next level of analysis covers regional aspects and detail at the prospect or project level, including screening and selection of potential CO2 storage sites on the basis of technical, environmental, safety and economic criteria. Finally, integration and analysis of various scenarios can lead to identification of potential storage sites that should then become targets of detailed engineering and economic studies.
The following factors should be considered when selecting CO2 storage sites and matching them with CO2 sources (Winter and Bergman, 1993; Bergman et al, 1997; Kovscek, 2002): volume, purity and rate of the CO2 stream; suitability of the storage sites, including the seal; proximity of the source and storage sites; infrastructure for the capture and delivery of CO2; existence of a large number of storage sites to allow diversification; known or undiscovered energy, mineral or groundwater resources that might be compromised; existing wells and infrastructure; viability and safety of the storage site; injection strategies and, in the case of EOR and ECBM, production strategies, which together affect the number of wells and their spacing; terrain and right of way; location of population centres; local expertise; and overall costs and economics.
Although technical suitability criteria are initial indicators for identifying potential CO2 storage sites, once the best candidates have been selected, further considerations will be controlled by economic, safety and environmental aspects. These criteria must be assessed for the anticipated lifetime of the operation, to ascertain whether storage capacity can match supply volume and whether injection rates can match the supply rate. Other issues might include whether CO2 sources and storage sites are matched on a one-to-one basis or whether a collection and distribution system is implemented, to form an integrated industrial system. Such deliberations affect cost outcomes, as will the supply rates, through economies of scale. Early opportunities for source-storage matching could involve sites where an economic benefit might accrue through the enhanced production of oil or gas (Holtz et al., 2001; van Bergen et al, 2003b).
Assigning technical risks is important for matching of CO2 sources and storage sites, for five risk factors: storage capacity, injectivity, containment, site and natural resources (Bradshaw et al., 2002, 2003). These screening criteria introduce reality checks to large storage-capacity estimates and indicate which regions to concentrate upon in future detailed studies. The use of 'cost curve' capacity introduces another level of sophistication that helps in identifying how sensitive any storage capacity estimate is to the cost of CO2. Combining the technical criteria into an economic assessment reveals that costs are quite project-specific.
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