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CO2 Capture and Storage

3. How do CO2 capture technologies work?

  • 3.1 What capture technologies are currently available?
  • 3.2 What are the costs of CO2 capture?

3.1 What capture technologies are currently available?

The source document for this Digest states:

This section examines CCS capture technology. As shown in Section 2, power plants and other large-scale industrial processes are the primary candidates for capture and the main focus of this section

Capture technology options and applications

The purpose of CO2 capture is to produce a concentrated stream of CO2 at high pressure that can readily be transported to a storage site. Although, in principle, the entire gas stream containing low concentrations of CO2 could be transported and injected underground, energy costs and other associated costs generally make this approach impractical. It is therefore necessary to produce a nearly pure CO2 stream for transport and storage. Applications separating CO2 in large industrial plants, including natural gas treatment plants and ammonia production facilities, are already in operation today. Currently, CO2 is typically removed to purify other industrial gas streams. Removal has been used for storage purposes in only a few cases; in most cases, the CO2 is emitted to the atmosphere. Capture processes also have been used to obtain commercially useful amounts of CO2 from flue gas streams generated by the combustion of coal or natural gas. To date, however, there have been no applications of CO2 capture at large (e.g., 500 MW) power plants.

Depending on the process or power plant application in question, there are three main approaches to capturing the CO2 generated from a primary fossil fuel (coal, natural gas or oil), biomass, or mixtures of these fuels:

Post-combustion systems separate CO2 from the flue gases produced by the combustion of the primary fuel in air. These systems normally use a liquid solvent to capture the small fraction of CO2 (typically 3–15% by volume) present in a flue gas stream in which the main constituent is nitrogen (from air). For a modern pulverized coal (PC) power plant or a natural gas combined cycle (NGCC) power plant, current post-combustion capture systems would typically employ an organic solvent such as monoethanolamine (MEA).

Pre-combustion systems process the primary fuel in a reactor with steam and air or oxygen to produce a mixture consisting mainly of carbon monoxide and hydrogen (“synthesis gas”). Additional hydrogen, together with CO2, is produced by reacting the carbon monoxide with steam in a second reactor (a “shift reactor”). The resulting mixture of hydrogen and CO2 can then be separated into a CO2 gas stream, and a stream of hydrogen. If the CO2 is stored, the hydrogen is a carbon-free energy carrier that can be combusted to generate power and/or heat. Although the initial fuel conversion steps are more elaborate and costly than in post-combustion systems, the high concentrations of CO2 produced by the shift reactor (typically 15 to 60% by volume on a dry basis) and the high pressures often encountered in these applications are more favourable for CO2 separation. Pre-combustion would be used at power plants that employ integrated gasification combined cycle (IGCC) technology.

Oxyfuel combustion systems use oxygen instead of air for combustion of the primary fuel to produce a flue gas that is mainly water vapour and CO2. This results in a flue gas with high CO2 concentrations (greater than 80% by volume). The water vapour is then removed by cooling and compressing the gas stream. Oxyfuel combustion requires the upstream separation of oxygen from air, with a purity of 95–99% oxygen assumed in most current designs. Further treatment of the flue gas may be needed to remove air pollutants and non- condensed gases (such as nitrogen) from the flue gas before the CO2 is sent to storage. As a method of CO2 capture in boilers, oxyfuel combustion systems are in the demonstration phase (see Table TS.1). Oxyfuel systems are also being studied in gas turbine systems, but conceptual designs for such applications are still in the research phase.

Figure TS.3 shows a schematic diagram of the main capture processes and systems. All require a step involving the separation of CO2, H2 or O2 from a bulk gas stream (such as flue gas, synthesis gas, air or raw natural gas). These separation steps can be accomplished by means of physical or chemical solvents, membranes, solid sorbents, or by cryogenic separation. The choice of a specific capture technology is determined largely by the process conditions under which it must operate.

Current post-combustion and pre-combustion systems for power plants could capture 85–95% of the CO2 that is produced. Higher capture efficiencies are possible, although separation devices become considerably larger, more energy intensive and more costly. Capture and compression need roughly 10–40% more energy than the equivalent plant without capture, depending on the type of system. Due to the associated CO2 emissions, the net amount of CO2 captured is approximately 80–90%. Oxyfuel combustion systems are, in principle, able to capture nearly all of the CO2 produced. However, the need for additional gas treatment systems to remove pollutants such as sulphur and nitrogen oxides lowers the level of CO2 captured to slightly more than 90%.

As noted in Section 1, CO2 capture is already used in several industrial applications (see Figure TS.4). The same technologies as would be used for pre-combustion capture are employed for the large-scale production of hydrogen (which is used mainly for ammonia and fertilizer manufacture, and for petroleum refinery operations). The separation of CO2 from raw natural gas (which typically contains significant amounts of CO2) is also practised on a large scale, using technologies similar to those used for post-combustion capture. Although commercial systems are also available for large-scale oxygen separation, oxyfuel combustion for CO2 capture is currently in the demonstration phase. In addition, research is being conducted to achieve higher levels of system integration, increased efficiency and reduced cost for all types of capture systems.

Source & ©: IPCC  Carbon Dioxide Capture and Storage: Technical Summary (2005)
3. Capture of CO2, p. 25

3.2 What are the costs of CO2 capture?

The source document for this Digest states:

The monitoring, risk and legal implications of CO2 capture systems do not appear to present fundamentally new challenges, as they are all elements of regular health, safety and environmental control practices in industry. However, CO2 capture systems require significant amounts of energy for their operation. This reduces net plant efficiency, so power plants require more fuel to generate each kilowatt-hour of electricity produced. Based on a review of the literature, the increase in fuel consumption per kWh for plants capturing 90% CO2 using best current technology ranges from 24–40% for new supercritical PC plants, 11–22% for NGCC plants, and 14–25% for coal-based IGCC systems compared to similar plants without CCS. The increased fuel requirement results in an increase in most other environmental emissions per kWh generated relative to new state-of-the-art plants without CO2 capture and, in the case of coal, proportionally larger amounts of solid wastes. In addition, there is an increase in the consumption of chemicals such as ammonia and limestone used by PC plants for nitrogen oxide and sulphur dioxide emissions control. Advanced plant designs that further reduce CCS energy requirements will also reduce overall environmental impacts as well as cost. Compared to many older existing plants, more efficient new or rebuilt plants with CCS may actually yield net reductions in plant- level environmental emissions.

The estimated costs of CO2 capture at large power plants are based on engineering design studies of technologies in commercial use today (though often in different applications and/or at smaller scales than those assumed in the literature), as well as on design studies for concepts currently in the research and development (R&D) stage. Table TS.3 summarizes the results for new supercritical PC, NGCC and IGCC plants based on current technology with and without CO2 capture. Capture systems for all three designs reduce CO2 emissions per kWh by approximately 80–90%, taking into account the energy requirements for capture. All data for PC and IGCC plants in Table TS.3 are for bituminous coals only. The capture costs include the cost of compressing CO2 (typically to about 11–14 MPa) but do not include the additional costs of CO2 transport and storage (see Sections 4–7).

Table TS.3. Summary of CO2 capture costs for new power plants

The cost ranges for each of the three systems reflect differences in the technical, economic and operating assumptions employed in different studies. While some differences in reported costs can be attributed to differences in the design of CO2 capture systems, the major sources of variability are differences in the assumed design, operation and financing of the reference plant to which the capture technology is applied (factors such as plant size, location, efficiency, fuel type, fuel cost, capacity factor and cost of capital). No single set of assumptions applies to all situations or all parts of the world, so a range of costs is given.

For the studies listed in Table TS.3, CO2 capture increases the cost of electricity production5 by 35–70% (0.01 to 0.02 US$/kWh) for an NGCC plant, 40–85% (0.02 to 0.03 US$/ kWh) for a supercritical PC plant, and 20–55% (0.01 to 0.02 US$/kWh) for an IGCC plant. Overall, the electricity production costs for fossil fuel plants with capture (excluding CO2 transport and storage costs) ranges from 0.04–0.09 US$/ kWh, as compared to 0.03–0.06 US$/kWh for similar plants without capture. In most studies to date, NGCC systems have typically been found to have lower electricity production costs than new PC and IGCC plants (with or without capture) in the case of large base-load plants with high capacity factors (75% or more) and natural gas prices between 2.6 and 4.4 US$ GJ-1 over the life of the plant. However, in the case of higher gas prices and/or lower capacity factors, NGCC plants often have higher electricity production costs than coal-based plants, with or without capture. Recent studies also found that IGCC plants were on average slightly more costly without capture and slightly less costly with capture than similarly- sized PC plants. However, the difference in cost between PC and IGCC plants with or without CO2 capture can vary significantly according to coal type and other local factors, such as the cost of capital for each plant type. Since full-scale NGCC, PC and IGCC systems have not yet been built with CCS, the absolute or relative costs of these systems cannot be stated with a high degree of confidence at this time.

The costs of retrofitting existing power plants with CO2 capture have not been extensively studied. A limited number of reports indicate that retrofitting an amine scrubber to an existing plant results in greater efficiency loss and higher costs than those shown in Table TS.3. Limited studies also indicate that a more cost-effective option is to combine a capture system retrofit with rebuilding the boiler and turbine to increase plant efficiency and output. For some existing plants, studies indicate that similar benefits could be achieved by repowering with an IGCC system that includes CO2 capture technology. The feasibility and cost of all these options is highly dependent on site-specific factors, including the size, age and efficiency of the plant, and the availability of additional space. Table TS.4 illustrates the cost of CO2 capture in the production of hydrogen. Here, the cost of CO2 capture is mainly due to the cost of CO2 drying and compression, since CO2 separation is already carried out as part of the hydrogen production process. The cost of CO2 capture adds approximately 5% to 30% to the cost of the hydrogen produced.

Table TS.4. Summary of CO2 capture costs for new hydrogen plants

CCS also can be applied to systems that use biomass fuels or feedstock, either alone or in combination with fossil fuels. A limited number of studies have looked at the costs of such systems combining capture, transport and storage. The capturing of 0.19 MtCO2 yr-1 in a 24 MWe biomass IGCC plant is estimated to be about 80 US$/tCO2 net captured (300 US$/tC), which corresponds to an increase in electricity production costs of about 0.08 US$/kWh. There are relatively few studies of CO2 capture for other industrial processes using fossil fuels and they are typically limited to capture costs reported only as a cost per tonne of CO2 captured or avoided. In general, the CO2 produced in different processes varies widely in pressure and concentration (see Section 2). As a result, the cost of capture in different processes (cement and steel plants, refineries), ranges widely from about 25–115 US$/tCO2 net captured. The unit cost of capture is generally lower for processes where a relatively pure CO2 stream is produced (e.g. natural gas processing, hydrogen production and ammonia production), as seen for the hydrogen plants in Table TS.4, where costs vary from 2–56 US$/tCO2 net captured.

New or improved methods of CO2 capture, combined with advanced power systems and industrial process designs, could reduce CO2 capture costs and energy requirements. While costs for first-of-a-kind commercial plants often exceed initial cost estimates, the cost of subsequent plants typically declines as a result of learning-by-doing and other factors. Although there is considerable uncertainty about the magnitude and timing of future cost reductions, the literature suggests that, provided R&D efforts are sustained, improvements to commercial technologies can reduce current CO2 capture costs by at least 20–30% over approximately the next ten years, while new technologies under development could achieve more substantial cost reductions. Future cost reductions will depend on the deployment and adoption of commercial technologies in the marketplace as well as sustained R&D.

Source & ©: IPCC (WGI)  Intergovernmental Panel on Climate Change IPCC
Carbon Dioxide Capture and Storage: Technical Summary (2005)

3. Capture of CO2, p. 27

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