IPCC Fourth Assessment Report: Climate Change 2007
Climate Change 2007: Working Group III: Mitigation of Climate Change

4.3.6 Carbon dioxide capture and storage (CCS)

The potential to separate CO2 from point sources, transport it and store it in isolation from the atmosphere was covered in an IPCC Special Report (IPCC, 2005). Uncertainties relate to proving the technologies, anticipating environmental impacts and how governments should incentivise uptake, possibly by regulation (OECD/IEA, 2005) or by carbon charges, setting a price on carbon emissions. Capture of CO2 can best be applied to large carbon point sources including coal-, gas- or biomass-fired electric power-generation or cogeneration (CHP) facilities, major energy-using industries, synthetic fuel plants, natural gas fields and chemical facilities for producing hydrogen, ammonia, cement and coke. Potential storage methods include injection into underground geological formations, in the deep ocean or industrial fixation as inorganic carbonates (Figure 4.22). Application of CCS for biomass sources (such as when co-fired with coal) could result in the net removal of CO2 from the atmosphere.


Figure 4.21: Carbon dioxide emissions and conversion efficiencies of selected coal and gas-fired power generation and CHP plants.

Note: CHP coal- fired and CHP gas-fired assume more of the available heat is utilized from coal than from gas to both give 80%.

Figure 4.22

Figure 4.22: CCS systems showing the carbon sources for which CCS might be relevant, and options for the transport and storage of CO2.

Source: IPCC, 2005.

Injection of CO2 in suitable geological reservoirs could lead to permanent storage of CO2. Geological storage is the most mature of the storage methods, with a number of commercial projects in operation. Ocean storage, however, is in the research phase and will not retain CO2 permanently as the CO2 will re-equilibrate with the atmosphere over the course of several centuries. Industrial fixation through the formation of mineral carbonates requires a large amount of energy and costs are high. Significant technological breakthroughs will be needed before deployment can be considered.

Estimates of the role CCS will play over the course of the century to reduce GHG emissions vary. It has been seen as a ‘transitional technology’, with deployment anticipated from 2015 onwards, peaking after 2050 as existing heat and power-plant stock is turned over, and declining thereafter as the decarbonization of energy sources progresses (IEA, 2006a). Other studies show a more rapid deployment starting around the same time, but with continuous expansion even towards the end of the century (IPCC, 2005). Yet other studies show no significant use of CCS until 2050, relying more on energy efficiency and renewable energy (IPCC, 2005). Long-term analyses by use of integrated assessment models, although using a simplified carbon cycle (Read and Lermit, 2005; Smith, 2006b), indicated that a combination of bioenergy technologies together with CCS could decrease costs and increase attainability of low stabilization levels (below 450 ppmv).

New power plants built today could be designed and located to be CCS-ready if rapid deployment is desired (Gibbins et al., 2006). All types of power plants can be made CCS-ready, although the costs and technical measures vary between different types of power plants. However, beyond space reservation for the capture, installation and siting of the plant to enable access to storage reservoirs, significant capital pre-investments at build time do not appear to be justified by the cost reductions that can be achieved (Bohm, 2006; Sekar, 2005). Although generic outline engineering studies for retro-fitting capture technologies to natural-gas GTCC plants have been undertaken, detailed reports on CCS-ready plant-design studies are not yet in the public domain.

Storage of CO2 can be achieved in deep saline formations, oil and gas reservoirs and deep unminable coal seams using injection and monitoring techniques similar to those utilized by the oil and gas industry. Of the different types of potential storage formations, storage in coal formations is the least developed. If injected into suitable saline formations or into oil and gas fields at depths below 800 m, various physical and geochemical trapping mechanisms prevent the CO2 from migrating to the surface. Projects in all kinds of reservoirs are planned.

Storage capacity in oil and gas fields, saline formations and coal beds is uncertain. The IPCC (IPCC, 2005) reported 675 to 900 GtCO2 for the relatively well-characterized gas and oil fields, more than 1000 GtCO2 (possibly up to an order of magnitude higher) for saline formations, and up to 200 GtCO2 for coal beds. Bradshaw et al. (2006) highlighted the incomparability of localized storage-capacity data that use different assumptions and methodologies. They also criticized any top-down estimate of storage capacity not based on a detailed site characterization and a clear methodology, and emphasized the value of conservative estimates. In the literature, however, specific estimates were based on top-down data and varied beyond the range cited in the IPCC (2005). For instance, a potential of >4000 GtCO2 was reported for saline formations in North America alone (Dooley et al., 2005) and between 560 and 1170 GtCO2 for injection in oil and gas fields (Plouchart et al., 2006). Agreement on a common methodology for storage capacity estimates on the country- and region-level is needed to give a more reliable estimate of storage capacities.

Biological removal of CO2 from an exhaust stream is possible by passing the stack emissions through an algae or bacterial solution in sunlight. Removal rates of 80% for CO2 and 86% for NOX have been reported, resulting in the production of 130,000 litres/ha/yr of biodiesel (Greenfuels 2004) with residues utilized as animal feed. Other unconventional biological approaches to CCS or fuel production have been reported (Greenshift, 2005; Patrinos, 2006). Another possibility is the capture of CO2 from air. Studies claim costs less than 75 US$/tCO2 and energy requirements of a minimum of 30% using a recovery cycle with Ca(OH)2 as a sorbent. However, no experimental data on the complete process are yet available to demonstrate the concept, its energy use and engineering costs.

Before the option of ocean injection can be deployed, significant research is needed into its potential biological impacts to clarify the nature and scope of environmental consequences, especially in the longer term (IPCC, 2005). Concerns surrounding geological storage include the risk of seismic activity causing a rapid release of CO2 and the impact of old and poorly sealed well bores on the storage integrity of depleted oil and gas fields. Risks in CO2 transportation include rupture or leaking of pipelines, possibly leading to the accumulation of a dangerous level of CO2 in the air. Dry CO2 is not corrosive to pipelines even if it contains contaminants, but it becomes corrosive when moisture is present. Any moisture therefore needs to be removed to prevent corrosion and avoid the high cost of constructing pipes made from corrosion-resistant material. Transport of CO2 by ship is feasible under specific conditions, but is currently carried out only on a small scale due to limited demand (IPCC, 2005).

Clarification of the nature and scope of long-term environmental consequences of ocean storage requires further research (IPCC, 2005). Concerns around geological storage include rapid release of CO2 as a consequence of seismic activity and the impact of old and poorly sealed well bores on the storage integrity of depleted oil and gas fields Risks are estimated to be comparable to those of similar operations (IPCC, 2005). For CO2 pipelines, accident numbers reported are very low, although there are risks of rupture or leaking leading to local accumulation of CO2 in the air to dangerous levels (IPCC, 2005).