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 400°C at 3 MPa to <30°C 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.

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.

Figure 5.16 (a) Vertical seismic sections through the CO2 plume in the Utsira Sand at the Sleipner gas field, North Sea, showing its development over time. Note the chimney of high CO2 saturation (c) above the injection point (black dot) and the bright layers corresponding to high acoustic response due to CO2 in a gas form being resident in sandstone beneath thin low-permeability horizons within the reservoir. (b) Horizontal seismic sections through the developing CO2 plume at Sleipner showing its growth over time. The CO2 plume-specific monitoring was completed in 2001; therefore data for 2002 was not available (courtesy of Andy Chadwick and the CO2STORE project).

Figure 5.16 (a) Vertical seismic sections through the CO2 plume in the Utsira Sand at the Sleipner gas field, North Sea, showing its development over time. Note the chimney of high CO2 saturation (c) above the injection point (black dot) and the bright layers corresponding to high acoustic response due to CO2 in a gas form being resident in sandstone beneath thin low-permeability horizons within the reservoir. (b) Horizontal seismic sections through the developing CO2 plume at Sleipner showing its growth over time. The CO2 plume-specific monitoring was completed in 2001; therefore data for 2002 was not available (courtesy of Andy Chadwick and the CO2STORE project).

Figure 5.17 Pure gas absolute adsorption in standard cubic feet per tonne (SCF per tonne) on Tiffany Coals at 55°C (after Gasem et al., 2002).

Original screening criteria proposed in selecting favourable areas for CO2 ECBM (IEA-GHG, 1998) include:

• Adequate permeability (minimum values have not yet been determined);

• Suitable coal geometry (a few, thick seams rather than multiple, thin seams);

• Simple structure (minimal faulting and folding);

• Homogeneous and confined coal seam(s) that are laterally continuous and vertically isolated;

• Adequate depth (down to 1500 m, greater depths have not yet been studied);

• Suitable gas saturation conditions (high gas saturation for ECBM);

• Ability to dewater the formation.

However, more recent studies have indicated that coal rank may play a more significant role than previously thought, owing to the dependence on coal rank of the relative adsorptive capacities

Chapter 5: Underground geological storage Box 5.7 The Allison Unit CO.-ECBM Pilot.

The Allison Unit CO2-ECBM Recovery Pilot Project, located in the northern New Mexico portion of the San Juan Basin, USA, is owned and operated by Burlington Resources. Production from the Allison field began in July 1989 and CO2 injection operations for ECBM recovery commenced in April 1995. Carbon dioxide injection was suspended in August 2001 to evaluate the results of the pilot. Since this pilot was undertaken purely for the purposes of ECBM production, no CO2 monitoring programme was implemented.

The CO2 was sourced from the McElmo Dome in Colorado and delivered to the site through a (then) Shell (now KinderMorgan) CO2 pipeline. The Allison Unit has a CBM resource of 242 million m3 km-2. A total of 181 million m3 (6.4 Bcf) of natural CO2 was injected into the reservoir over six years, of which 45 million m3 (1.6 Bcf) is forecast to be ultimately produced back, resulting in a net storage volume of 277,000 tCO2. The pilot consists of 16 methane production wells, 4 CO2 injection wells and 1 pressure observation well. The injection operations were undertaken at constant surface injection pressures on the order of 10.4 MPa.

The wells were completed in the Fruitland coal, which is capped by shale. The reservoir has a thickness of 13 m, is located at a depth of 950 m and had an original reservoir pressure of 11.5 MPa. In a study conducted under the Coal-Seq Project performed for the US Department of Energy (, a detailed reservoir characterization and modelling of the pilot was developed with the COMET2 reservoir simulator and future field performance was forecast under various operating conditions.

This study provides evidence of significant coal-permeability reduction with CO2 injection. This permeability reduction resulted in a two-fold reduction in injectivity. This effect compromised incremental methane recovery and project economics. Finding ways to overcome and/or prevent this effect is therefore an important topic for future research. The injection of CO2 at the Allison Unit has resulted in an increase in methane recovery from an estimated 77% of original gas in place to 95% of the original gas in place within the project area. The recovery of methane was in a proportion of approximately one volume of methane for every three volumes of CO2 injected (Reeves et al., 2004).

An economic analysis of the pilot indicated a net present value of negative US$ 627,000, assuming a discount rate of 12% and an initial capital expenditure of US$ 2.6 million, but not including the beneficial impact of any tax credits for production from non-conventional reservoirs. This was based on a gas price of 2.09 US$ GJ-1 (2.20 US$/MMbtu) (at the time) and a CO2 price of 5.19 US$ t-1 (0.30 US$/Mcf). The results of the financial analysis will change, depending on the cost of oil and gas (the analysis indicated that the pilot would have yielded a positive net present value of US$2.6 million at today's gas prices) and the cost of CO2. It was also estimated that if injectivity had been improved by a factor of four (but still using 2.09 US$ GJ-1 (2.20 US$/MMbtu)), the net present value would have increased to US$ 3.6 million. Increased injectivity and today's gas prices combined would have yielded a net present value for the pilot of US$ 15 million or a profit of 34 US$/tCO2 retained in the reservoir (Reeves et al., 2003).

of methane and CO2 (Reeves et al., 2004).

If the coal is never mined or depressurized, it is likely CO2 will be stored for geological time, but, as with any geological storage option, disturbance of the formation could void any storage. The likely future fate of a coal seam is, therefore, a key determinant of its suitability for storage and in storage site selection and conflicts between mining and CO2 storage are possible, particularly for shallow coals.

5.3.5 Other geological media

Other geological media and/or structures - including basalts, oil or gas shale, salt caverns and abandoned mines - may locally provide niche options for geological storage of CO2. Basalts

Flows and layered intrusions of basalt occur globally, with large volumes present around the world (McGrail et al., 2003). Basalt commonly has low porosity, low permeability and low pore space continuity and any permeability is generally associated with fractures through which CO2 will leak unless there is a suitable caprock. Nonetheless, basalt may have some potential for mineral trapping of CO2, because injected CO2 may react with silicates in the basalt to form carbonate minerals (McGrail et al., 2003). More research is needed, but in general, basalts appear unlikely to be suitable for CO2 storage. Oil or gas rich shale

Deposits of oil or gas shale or organic-rich shale, occur in many parts of the world. The trapping mechanism for oil shale is similar to that for coal beds, namely CO2 adsorption onto organic material. Carbon dioxide-enhanced shale-gas production (like ECBM) has the potential to reduce storage costs. The potential for storage of CO2 in oil or gas shale is currently unknown, but the large volumes of shale suggest that storage capacity may be significant. If site-selection criteria, such as minimum depth, are developed and applied to these shales, then volumes could be limited, but the very low permeability of these shales is likely to preclude injection of large volumes of CO2. Salt caverns

Storage of CO2 in salt caverns created by solution mining could use the technology developed for the storage of liquid natural gas and petroleum products in salt beds and domes in Western Canada and the Gulf of Mexico (Dusseault et al., 2004). A single salt cavern can reach more than 500,000 m3. Storage of CO2 in salt caverns differs from natural gas and compressed air storage because in the latter case, the caverns are cyclically pressurized and depressurized on a daily-to-annual time scale, whereas CO2 storage must be effective on a centuries-to-millennia time scale. Owing to the creep properties of salt, a cavern filled with supercritical CO2 will decrease in volume, until the pressure inside the cavern equalizes the external stress in the salt bed (Bachu and Dusseault, 2005). Although a single cavern 100 m in diameter may hold only about 0.5 Mt of high density CO2, arrays of caverns could be built for large-scale storage. Cavern sealing is important in preventing leakage and collapse of cavern roofs, which could release large quantities of gas (Katzung et al., 1996). Advantages of CO2 storage in salt caverns include high capacity per unit volume (kgCO2 m-3), efficiency and injection flow rate. Disadvantages are the potential for CO2 release in the case of system failure, the relatively small capacity of most individual caverns and the environmental problems of disposing of brine from a solution cavity. Salt caverns can also be used for temporary storage of CO2 in collector and distributor systems between sources and sinks of CO . Abandoned mines

The suitability of mines for CO2 storage depends on the nature and sealing capacity of the rock in which mining occurs. Heavily fractured rock, typical of igneous and metamorphic terrains, would be difficult to seal. Mines in sedimentary rocks may offer some CO2-storage opportunities (e.g., potash and salt mines or stratabound lead and zinc deposits). Abandoned coal mines offer the opportunity to store CO2, with the added benefit of adsorption of CO2 onto coal remaining in the mined-out area (Piessens and Dusar, 2004). However, the rocks above coal mines are strongly fractured, which increases the risk of gas leakage. In addition, long-term, safe, high-pressure, CO2-resistant shaft seals have not been developed and any shaft failure could result in release of large quantities of CO2. Nevertheless, in Colorado, USA, there is a natural gas storage facility in an abandoned coal mine.

5.3.6 Effects of impurities on storage capacity

The presence of impurities in the CO2 gas stream affects the engineering processes of capture, transport and injection (Chapters 3 and 4), as well as the trapping mechanisms and capacity for CO2 storage in geological media. Some contaminants in the CO2 stream (e.g., SOx, NOx, H2S) may require classification as hazardous, imposing different requirements for injection and disposal than if the stream were pure (Bergman et al., 1997). Gas impurities in the CO2 stream affect the compressibility of the injected CO2 (and hence the volume needed for storing a given amount) and reduce the capacity for storage in free phase, because of the storage space taken by these gases. Additionally, depending on the type of geological storage, the presence of impurities may have some other specific effects.

In EOR operations, impurities affect the oil recovery because they change the solubility of CO2 in oil and the ability of CO2 to vaporize oil components (Metcalfe, 1982). Methane and nitrogen decrease oil recovery, whereas hydrogen sulphide, propane and heavier hydrocarbons have the opposite effect (Alston et al., 1985; Sebastian et al., 1985). The presence of SOx may improve oil recovery, whereas the presence of NOx can retard miscibility and thus reduce oil recovery (Bryant and Lake, 2005) and O2 can react exothermally with oil in the reservoir.

In the case of CO2 storage in deep saline formations, the presence of gas impurities affects the rate and amount of CO2 storage through dissolution and precipitation. Additionally, leaching of heavy metals from the minerals in the rock matrix by SO2 or O2 contaminants is possible. Experience to date with acid gas injection (Section suggests that the effect of impurities is not significant, although Knauss et al. (2005) suggest that SOx injection with CO2 produces substantially different chemical, mobilization and mineral reactions. Clarity is needed about the range of gas compositions that industry might wish to store, other than pure CO2 (Anheden et al., 2005), because although there might be environmental issues to address, there might be cost savings in co-storage of CO2 and contaminants.

In the case of CO2 storage in coal seams, impurities may also have a positive or negative effect, similar to EOR operations. If a stream of gas containing H2S or SO2 is injected into coal beds, these will likely be preferentially adsorbed because they have a higher affinity to coal than CO2, thus reducing the storage capacity for CO2 (Chikatamarla and Bustin, 2003). If oxygen is present, it will react irreversibly with the coal, reducing the sorption surface and, hence, the adsorption capacity. On the other hand, some impure CO2 waste streams, such as coal-fired flue gas (i.e., primarily N2 + CO2), may be used for ECBM because the CO2 is stripped out (retained) by the coal reservoir, because it has higher sorption selectivity than N2 and CH4.

5.3.7 Geographical distribution and storage capacity estimates

Identifying potential sites for CO2 geological storage and estimating their capacity on a regional or local scale should conceptually be a simple task. The differences between the various mechanisms and means of trapping (Sections 5.2.2) suggest in principle the following methods:

• For volumetric trapping, capacity is the product of available volume (pore space or cavity) and CO2 density at in situ pressure and temperature;

• For solubility trapping, capacity is the amount of CO2 that can be dissolved in the formation fluid (oil in oil reservoirs, brackish water or brine in saline formations);

• For adsorption trapping, capacity is the product of coal volume and its capacity for adsorbing CO2;

For mineral trapping, capacity is calculated on the basis of available minerals for carbonate precipitation and the amount of CO, that will be used in these reactions.

The major impediments to applying these simple methods for estimating the capacity for CO2 storage in geological media are the lack of data, their uncertainty, the resources needed to process data when available and the fact that frequently more than one trapping mechanism is active. This leads to two situations:

• Global capacity estimates have been calculated by simplifying assumptions and using very simplistic methods and hence are not reliable;

• Country- and region- or basin-specific estimates are more detailed and precise, but are still affected by the limitations imposed by availability of data and the methodology used. Country- or basin-specific capacity estimates are available only for North America, Western Europe, Australia and Japan.

The geographical distribution and capacity estimates are presented below and summarized in Table 5.2. Storage in oil and gas reservoirs This CO2 storage option is restricted to hydrocarbon-producing basins, which represent numerically less than half of the sedimentary provinces in the world. It is generally assumed that oil and gas reservoirs can be used for CO2 storage after their oil or gas reserves are depleted, although storage combined with enhanced oil or gas production can occur sooner. Short of a detailed, reservoir-by-reservoir analysis, the CO2 storage capacity can and should be calculated from databases of reserves and production (e.g., Winter and Bergman, 1993; Stevens et al., 2001b; Bachu and Shaw, 2003, 2005; Beecy and Kuuskra, 2005).

In hydrocarbon reservoirs with little water encroachment, the injected CO2 will generally occupy the pore volume previously occupied by oil and/or natural gas. However, not all the previously (hydrocarbon-saturated) pore space will be available for CO2 because some residual water may be trapped in the pore space due to capillarity, viscous fingering and gravity effects (Stevens et al., 2001c). In open hydrocarbon reservoirs (where pressure is maintained by water influx), in addition to the capacity reduction caused by capillarity and other local effects, a significant fraction of the pore space will be invaded by water, decreasing the pore space available for CO2 storage, if repressuring the reservoir is limited to preserve reservoir integrity. In Western Canada, this loss was estimated to be in the order of 30% for gas reservoirs and 50% for oil reservoirs if reservoir repressuring with CO2 is limited to the initial reservoir pressure (Bachu et al., 2004). The capacity estimates presented here for oil and gas reservoirs have not included any 'discounting' that may be appropriate for water-drive reservoirs because detailed site-specific reservoir analysis is needed to assess the effects of water-drive on capacity on a case-by-case basis.

Many storage-capacity estimates for oil and gas fields do not distinguish capacity relating to oil and gas that has already been produced from capacity relating to remaining reserves yet to be produced and that will become available in future years. In some global assessments, estimates also attribute capacity to undiscovered oil and gas fields that might be discovered in future years. There is uncertainty about when oil and gas fields will be depleted and become available for CO2 storage. The depletion of oil and gas fields is mostly affected by economic rather than technical considerations, particularly oil and gas prices. It is possible that production from near-depleted fields will be extended if future economic considerations allow more hydrocarbons to be recovered, thus delaying access to such fields for CO2 storage. Currently few of the world's large oil and gas fields are depleted.

A variety of regional and global estimates of storage capacity in oil and gas fields have been made. Regional and national assessments use a 'bottom-up' approach that is based on field reserves data from each area's existing and discovered oil and gas fields. Although the methodologies used may differ, there is a higher level of confidence in these than the global estimates, for the reasons outlined previously. Currently, this type of assessment is available only for northwestern Europe, United States, Canada and Australia. In Europe, there have been three bottom-up attempts to estimate the CO2 storage capacity of oil and gas reservoirs covering parts of Europe, but comprising most of Europe's storage capacity since they include the North Sea (Holloway, 1996; Wildenborg et al., 2005b). The methodology used in all three studies was based on the assumption that the total reservoir volume of hydrocarbons could be replaced by CO2. The operators' estimate of 'ultimately recoverable reserves' (URR) was used for each field where available or was estimated. The underground volume occupied by the URR and the amount of CO2 that could be stored in that space under reservoir conditions was then calculated. Undiscovered reserves were excluded. For Canada, the assumption was that

Table 5.2 Storage capacity for several geological storage options. The storage capacity includes storage options that are not economical.

Reservoir type

Lower estimate of storage capacity

Upper estimate of storage capacity

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