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This section examines three types of geological formations that have received extensive consideration for the geological storage of CO2: oil and gas reservoirs, deep saline formations and unminable coal beds (Figure TS.7). In each case, geological storage of CO2 is accomplished by injecting it in dense form into a rock formation below the earth’s surface. Porous rock formations that hold or (as in the case of depleted oil and gas reservoirs) have previously held fluids, such as natural gas, oil or brines, are potential candidates for CO2 storage. Suitable storage formations can occur in both onshore and offshore sedimentary basins (natural large-scale depressions in the earth’s crust that are filled with sediments). Coal beds also may be used for storage of CO2 (see Figure TS.7) where it is unlikely that the coal will later be mined and provided that permeability is sufficient. The option of storing CO2 in coal beds and enhancing methane production is still in the demonstration phase (see Table TS.1).
Existing CO2 storage projects
Geological storage of CO2 is ongoing in three industrial- scale projects (projects in the order of 1 MtCO2 yr-1 or more): the Sleipner project in the North Sea, the Weyburn project in Canada and the In Salah project in Algeria. About 3–4 MtCO2 that would otherwise be released to the atmosphere is captured and stored annually in geological formations. Additional projects are listed in Table TS.5.
Table TS.5. Sites where CO2 storage has been done, is currently in progress or is planned
In addition to the CCS projects currently in place, 30 MtCO2 is injected annually for EOR, mostly in Texas, USA, where EOR commenced in the early 1970s. Most of this CO2 is obtained from natural CO2 reservoirs found in western regions of the US, with some coming from anthropogenic sources such as natural gas processing. Much of the CO2 injected for EOR is produced with the oil, from which it is separated and then reinjected. At the end of the oil recovery, the CO2 can be retained for the purpose of climate change mitigation, rather than vented to the atmosphere. This is planned for the Weyburn project.
Storage technology and mechanisms
The injection of CO2 in deep geological formations involves many of the same technologies that have been developed in the oil and gas exploration and production industry. Well-drilling technology, injection technology, computer simulation of storage reservoir dynamics and monitoring methods from existing applications are being developed further for design and operation of geological storage. Other underground injection practices also provide relevant operational experience. In particular, natural gas storage, the deep injection of liquid wastes, and acid gas disposal (mixtures of CO2 and H2S) have been conducted in Canada and the U.S. since 1990, also at the megatonne scale.
CO2 storage in hydrocarbon reservoirs or deep saline formations is generally expected to take place at depths below 800 m, where the ambient pressures and temperatures will usually result in CO2 being in a liquid or supercritical state. Under these conditions, the density of CO2 will range from 50 to 80% of the density of water. This is close to the density of some crude oils, resulting in buoyant forces that tend to drive CO2 upwards. Consequently, a well-sealed cap rock over the selected storage reservoir is important to ensure that CO2 remains trapped underground. When injected underground, the CO2 compresses and fills the pore space by partially displacing the fluids that are already present (the ‘in situ fluids’). In oil and gas reservoirs, the displacement of in situ fluids by injected CO2 can result in most of the pore volume being available for CO2 storage. In saline formations, estimates of potential storage volume are lower, ranging from as low as a few percent to over 30% of the total rock volume.
Once injected into the storage formation, the fraction retained depends on a combination of physical and geochemical trapping mechanisms. Physical trapping to block upward migration of CO2 is provided by a layer of shale and clay rock above the storage formation. This impermeable layer is known as the “cap rock”. Additional physical trapping can be provided by capillary forces that retain CO2 in the pore spaces of the formation. In many cases, however, one or more sides of the formation remain open, allowing for lateral migration of CO2 beneath the cap rock. In these cases, additional mechanisms are important for the long-term entrapment of the injected CO2. The mechanism known as geochemical trapping occurs as the CO2 reacts with the in situ fluids and host rock. First, CO2 dissolves in the in situ water. Once this occurs (over time scales of hundreds of years to thousands of years), the CO2- laden water becomes more dense and therefore sinks down into the formation (rather than rising toward the surface). Next, chemical reactions between the dissolved CO2 and rock minerals form ionic species, so that a fraction of the injected CO2 will be converted to solid carbonate minerals over millions of years.
Yet another type of trapping occurs when CO2 is preferentially adsorbed onto coal or organic-rich shales replacing gases such as methane. In these cases, CO2 will remain trapped as long as pressures and temperatures remain stable. These processes would normally take place at shallower depths than CO2 storage in hydrocarbon reservoirs and saline formations.
Source & ©:
IPCC
5. Geological storage, p. 31
The source document for this Digest states:
As shown earlier in Section 2 (Figure TS.2b), regions with sedimentary basins that are potentially suitable for CO2 storage exist around the globe, both onshore and offshore. This report focuses on oil and gas reservoirs, deep saline formations and unminable coal beds. Other possible geological formations or structures (such as basalts, oil or gas shales, salt caverns and abandoned mines) represent niche opportunities, or have been insufficiently studied at this time to assess their potential.
The estimates of the technical potential6 for different geological storage options are summarized in Table TS.6. The estimates and levels of confidence are based on an assessment of the literature, both of regional bottom-up, and global top-down estimates. No probabilistic approach to assessing capacity estimates exists in the literature, and this would be required to quantify levels of uncertainty reliably. Overall estimates, particularly of the upper limit of the potential, vary widely and involve a high degree of uncertainty, reflecting conflicting methodologies in the literature and the fact that our knowledge of saline formations is quite limited in most parts of the world. For oil and gas reservoirs, better estimates are available which are based on the replacement of hydrocarbon volumes with CO2 volumes. It should be noted that, with the exception of EOR, these reservoirs will not be available for CO2 storage until the hydrocarbons are depleted, and that pressure changes and geomechanical effects due to hydrocarbon production in the reservoir may reduce actual capacity.
Table TS.6. Storage capacity for several geological storage options
Another way of looking at storage potential, however, is to ask whether it is likely to be adequate for the amounts of CO2 that would need to be avoided using CCS under different greenhouse gas stabilization scenarios and assumptions about the deployment of other mitigation options. As discussed later in Section 8, the estimated range of economic potential for CCS over the next century is roughly 200 to 2,000 GtCO2. The lower limits in Table TS.6 suggest that, worldwide, it is virtually certain that there is 200 GtCO2 of geological storage capacity, and likely that there is at least about 2,000 GtCO2.
Site characterization, selection and performance prediction are crucial for successful geological storage. Before selecting a site, the geological setting must be characterized to determine if the overlying cap rock will provide an effective seal, if there is a sufficiently voluminous and permeable storage formation, and whether any abandoned or active wells will compromise the integrity of the seal.
Techniques developed for the exploration of oil and gas reservoirs, natural gas storage sites and liquid waste disposal sites are suitable for characterizing geological storage sites for CO2. Examples include seismic imaging, pumping tests for evaluating storage formations and seals, and cement integrity logs. Computer programmes that model underground CO2 movement are used to support site characterization and selection activities. These programmes were initially developed for applications such as oil and gas reservoir engineering and groundwater resources investigations. Although they include many of the physical, chemical and geomechanical processes needed to predict both short-term and long-term performance of CO2 storage, more experience is needed to establish confidence in their effectiveness in predicting long-term performance when adapted for CO2 storage. Moreover, the availability of good site characterization data is critical for the reliability of models.
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IPCC
5. Geological storage, p. 32
The source document for this Digest states:
Risk assessment and environmental impact
The risks due to leakage from storage of CO2 in geological reservoirs fall into two broad categories: global risks and local risks. Global risks involve the release of CO2 that may contribute significantly to climate change if some fraction leaks from the storage formation to the atmosphere. In addition, if CO2 leaks out of a storage formation, local hazards may exist for humans, ecosystems and groundwater. These are the local risks.
With regard to global risks, based on observations and analysis of current CO2 storage sites, natural systems, engineering systems and models, the fraction retained in appropriately selected and managed reservoirs is very likely to exceed 99% over 100 years, and is likely to exceed 99% over 1000 years. Similar fractions retained are likely for even longer periods of time, as the risk of leakage is expected to decrease over time as other mechanisms provide additional trapping. The question of whether these fractions retained would be sufficient to make impermanent storage valuable for climate change mitigation is discussed in Section 8.
With regard to local risks, there are two types of scenarios in which leakage may occur. In the first case, injection well failures or leakage up abandoned wells could create a sudden and rapid release of CO2. This type of release is likely to be detected quickly and stopped using techniques that are available today for containing well blow-outs. Hazards associated with this type of release primarily affect workers in the vicinity of the release at the time it occurs, or those called in to control the blow-out. A concentration of CO2 greater than 7–10% in air would cause immediate dangers to human life and health. Containing these kinds of releases may take hours to days and the overall amount of CO2 released is likely to be very small compared to the total amount injected. These types of hazards are managed effectively on a regular basis in the oil and gas industry using engineering and administrative controls.
In the second scenario, leakage could occur through undetected faults, fractures or through leaking wells where the release to the surface is more gradual and diffuse. In this case, hazards primarily affect drinking-water aquifers and ecosystems where CO2 accumulates in the zone between the surface and the top of the water table. Groundwater can be affected both by CO2 leaking directly into an aquifer and by brines that enter the aquifer as a result of being displaced by CO2 during the injection process. There may also be acidification of soils and displacement of oxygen in soils in this scenario. Additionally, if leakage to the atmosphere were to occur in low-lying areas with little wind, or in sumps and basements overlying these diffuse leaks, humans and animals would be harmed if a leak were to go undetected. Humans would be less affected by leakage from offshore storage locations than from onshore storage locations. Leakage routes can be identified by several techniques and by characterization of the reservoir. Figure TS.8 shows some of the potential leakage paths for a saline formation. When the potential leakage routes are known, the monitoring and remediation strategy can be adapted to address the potential leakage.
Careful storage system design and siting, together with methods for early detection of leakage (preferably long before CO2 reaches the land surface), are effective ways of reducing hazards associated with diffuse leakage. The available monitoring methods are promising, but more experience is needed to establish detection levels and resolution. Once leakages are detected, some remediation techniques are available to stop or control them. Depending on the type of leakage, these techniques could involve standard well repair techniques, or the extraction of CO2 by intercepting its leak into a shallow groundwater aquifer (see Figure TS.8). Techniques to remove CO2 from soils and groundwater are also available, but they are likely to be costly. Experience will be needed to demonstrate the effectiveness, and ascertain the costs, of these techniques for use in CO2 storage.
Source & ©:
IPCC
5. Geological storage, p. 29
Monitoring and verification
Monitoring is a very important part of the overall risk management strategy for geological storage projects. Standard procedures or protocols have not been developed yet but they are expected to evolve as technology improves, depending on local risks and regulations. However, it is expected that some parameters such as injection rate and injection well pressure will be measured routinely. Repeated seismic surveys have been shown to be useful for tracking the underground migration of CO2. Newer techniques such as gravity and electrical measurements may also be useful. The sampling of groundwater and the soil between the surface and water table may be useful for directly detecting CO2 leakage. CO2 sensors with alarms can be located at the injection wells for ensuring worker safety and to detect leakage. Surface-based techniques may also be used for detecting and quantifying surface releases. High-quality baseline data improve the reliability and resolution of all measurements and will be essential for detecting small rates of leakage.
Since all of these monitoring techniques have been adapted from other applications, they need to be tested and assessed with regard to reliability, resolution and sensitivity in the context of geological storage. All of the existing industrial-scale projects and pilot projects have programmes to develop and test these and other monitoring techniques. Methods also may be necessary or desirable to monitor the amount of CO2 stored underground in the context of emission reporting and monitoring requirements in the UNFCCC (see Section 9). Given the long-term nature of CO2 storage, site monitoring may be required for very long periods.
Legal issues
At present, few countries have specifically developed legal and regulatory frameworks for onshore CO2 storage. Relevant legislation include petroleum-related legislation, drinking-water legislation and mining regulations. In many cases, there are laws applying to some, if not most, of the issues related to CO2 storage. Specifically, long-term liability issues, such as global issues associated with the leakage of CO2 to the atmosphere, as well as local concerns about environmental impact, have not yet been addressed. Monitoring and verification regimes and risks of leakage may play an important role in determining liability, and vice- versa. There are also considerations such as the longevity of institutions, ongoing monitoring and transferability of institutional knowledge. The long-term perspective is essential to a legal framework for CCS as storage times extend over many generations as does the climate change problem. In some countries, notably the US, the property rights of all those affected must be considered in legal terms as pore space is owned by surface property owners.
According to the general principles of customary international law, States can exercise their sovereignty in their territories and could therefore engage in activities such as the storage of CO2 (both geological and ocean) in those areas under their jurisdiction. However, if storage has a transboundary impact, States have the responsibility to ensure that activities within their jurisdiction or control do not cause damage to the environment of other States or of areas beyond the limits of national jurisdiction.
Currently, there are several treaties (notably the UN Convention on the Law of the Sea, and the London11 and OSPAR12 Conventions) that could apply to the offshore injection of CO2 into marine environments (both into the ocean and the geological sub-seabed). All these treaties have been drafted without specific consideration of CO2 storage. An assessment undertaken by the Jurists and Linguists Group to the OSPAR Convention (relating to the northeast Atlantic region), for example, found that, depending on the method and purpose of injection, CO2 injection into the geological sub- seabed and the ocean could be compatible with the treaty in some cases, such as when the CO2 is transported via a pipeline from land. A similar assessment is now being conducted by Parties to the London Convention. Furthermore, papers by legal commentators have concluded that CO2 captured from an oil or natural gas extraction operation and stored offshore in a geological formation (like the Sleipner operation) would not be considered ‘dumping’ under, and would not therefore be prohibited by, the London Convention.
Public perception
Assessing public perception of CCS is challenging because of the relatively technical and “remote” nature of this issue at the present time. Results of the very few studies conducted to date about the public perception of CCS indicate that the public is generally not well informed about CCS. If information is given alongside information about other climate change mitigation options, the handful of studies carried out so far indicate that CCS is generally regarded as less favourable than other options, such as improvements in energy efficiency and the use of non-fossil energy sources. Acceptance of CCS, where it occurs, is characterized as “reluctant” rather than “enthusiastic”. In some cases, this reflects the perception that CCS might be required because of a failure to reduce CO2 emissions in other ways. There are indications that geological storage could be viewed favourably if it is adopted in conjunction with more desirable measures. Although public perception is likely to change in the future, the limited research to date indicates that at least two conditions may have to be met before CO2 capture and storage is considered by the public as a credible technology, alongside other better known options: (1) anthropogenic global climate change has to be regarded as a relatively serious problem; (2) there must be acceptance of the need for large reductions in CO2 emissions to reduce the threat of global climate change.”
Source & ©:
IPCC
5. Geological storage, p. 34
The source document for this Digest states:
The technologies and equipment used for geological storage are widely used in the oil and gas industries so cost estimates for this option have a relatively high degree of confidence for storage capacity in the lower range of technical potential. However, there is a significant range and variability of costs due to site-specific factors such as onshore versus offshore, reservoir depth and geological characteristics of the storage formation (e.g., permeability and formation thickness).
Representative estimates of the cost for storage in saline formations and depleted oil and gas fields are typically between 0.5–8 US$/tCO2 injected. Monitoring costs of 0.1–0.3 US$/tCO2 are additional. The lowest storage costs are for onshore, shallow, high permeability reservoirs, and/or storage sites where wells and infrastructure from existing oil and gas fields may be re-used.
When storage is combined with EOR, ECBM or (potentially) Enhanced Gas Recovery (EGR), the economic value of CO2 can reduce the total cost of CCS. Based on data and oil prices prior to 2003, enhanced oil production for onshore EOR with CO2 storage could yield net benefits of 10–16 US$/tCO2 (37–59 US$/tC) (including the costs of geological storage). For EGR and ECBM, which are still under development, there is no reliable cost information based on actual experience. In all cases, however, the economic benefit of enhanced production depends strongly on oil and gas prices. In this regard, the literature basis for this report does not take into account the rise in world oil and gas prices since 2003 and assumes oil prices of 15–20 US$ per barrel. Should higher prices be sustained over the life of a CCS project, the economic value of CO2 could be higher than that reported here.
Source & ©:
IPCC
(WGI)
Carbon Dioxide
Capture and Storage: Technical Summary (2005)
5.
Geological storage, p. 36
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