CO 2 capture from fossil-fired power plants

For the separation of CO2 from power plant flue gases, separation technologies can be classified based on the positioning of CO2 capture in the overall power plant process. These technologies include post-combustion capture, oxyfuel combustion and pre-combustion capture (Figure 2). In each of these processes, the composition of the CO2 containing stream varies and consequently, different CO2 separation methods are applicable.

Figure 2. The technologies for capture of CO2 from power generation processes.

2.1.2.1 Post-combustion capture

In post-combustion capture, CO2 is captured from the flue gas after conventional combustion of the fuel in the presence of air [45]. The advantage of post-combustion capture is that no changes are required to the power plant process, allowing the retrofitting of existing plants with the CO2 separation unit. However, separation is complicated by the low concentration of CO2

(12-15 vol-%) and the vast volumes of flue gas to be processed [32]. The low pressure of the flue gas further limits the available separation technologies.

Chemical absorption by amine solvents is currently considered the best available option for post-combustion CO2 capture [45, 32]. While high degree of separation and purity of CO2 is achieved by the absorption processes, the high energy requirement and solvent degradation are an issue. The efficiency losses in power generation caused by the implementation of CO2

capture by amine absorption are estimated to be 10-14 %-points (compared to base efficiency), including the compression of CO2 [32].

While chemical absorption processes have been implemented in chemical industry and at pilot scale in power generation, the full scale implementation at power plants is a challenge [32]. In the current pilot scale operations, CO2 is captured at maximum quantities of approximately 500 t per day, corresponding to electric power generation of less than 1 MW. In contrast, conventional power plants operate at capacities of 500 to 1000 MW of electricity generated.

The potential developments in post-combustion capture include the development of more energy efficient solvents and alternative technologies such as carbonate looping.

2.1.2.2 Oxyfuel combustion

In the oxyfuel combustion process, fuel is combusted in the presence of pure oxygen instead of air. As a result, the flue gas consists of mostly CO2 and steam, with the concentration of CO2

approximately 89% by volume [32]. After condensation of water, a highly pure CO2 stream is obtained, with only residual drying and purification required. In addition, the volume of flue gas is greatly reduced as dilution by nitrogen is avoided. The oxygen is separated from air in cryogenic air separation units, by condensation below -182^oC. In pure oxygen combustion, temperatures are higher than in air combustion. To reduce the combustion temperature, a significant fraction (approximately 2/3 by volume) of the flue gas is recycled to the combustion chamber.

While the energy-intensive CO2 separation can be largely avoided by oxyfuel combustion, the separation of oxygen from air still requires a sizable energy input. With cryogenic separation, efficiency losses are approximately 10 %-points, including compression of CO2, while optimized separation processes could reach an estimated efficiency loss of 8 %-points [32]. Oxygen separation by membranes has been discussed as a potential method of improving the overall efficiency of oxyfuel combustion, but further improvements in membrane materials are required before full implementation [46, 47]. Difficulties in oxyfuel CO2 capture may arise from residual oxygen present in the flue gas, which complicates the purification of CO2 [32];excess oxygen is commonly fed to combustion processes to ensure complete combustion. Finally, oxyfuel combustion requires significant alterations to various power plant components and is only applicable at new installations. Oxyfuel combustion has been demonstrated in the pilot scale at power ratings up to 30 MW [48].

2.1.2.3 Pre-combustion capture

In the pre-combustion process, the fuel is first converted into hydrogen-rich syngas, followed by capture of CO2 and combustion of the hydrogen. Coal or heavy oil fuels are gasified by partial oxidation into carbon monoxide and hydrogen. Next, the water gas shift reaction is carried out in presence of steam to convert CO into CO2 (Section 2.1.1). The result is a stream consisting of hydrogen and CO2 at a high pressure, allowing the separation of CO2 by physical solvents [32].

Use of physical solvents such as methanol (the Rectisol process) is less energy-intensive compared to chemical absorption processes, leading to lower efficiency losses. The solvent simultaneously removes sulfur compounds such as H2S, leading to cleaner combustion of the fuel gas (hydrogen). Alternatively, pressure swing adsorption can be used for the separation of CO2 and hydrogen. While the capture of CO2 can be performed with high energy efficiency in the post-combustion process, energy input is required for air separation to provide oxygen for gasification. The estimated efficiency losses are in the range of 10-12%-points for coal fired IGCC power plants [49, 50].

Fuel gasification followed by combustion is operated at integrated gasification combined cycle (IGCC) power plants, which mainly utilize coal as feedstock [32]. Plants without CO2 capture have been in operation since the 1980’s, but the establishment of IGCC technology has been limited by reliability issues and high investment costs. Integration of CO2 capture is currently only at the planning and demonstration stage. Demonstration plants with capacities of up to 900 MW of electricity are in consideration [51]. Combustion of hydrogen rich fuel (as opposed to CO containing syngas at conventional IGCC plants) in large gas turbines is also under development. Integration of CO2 capture is limited to new IGCC plants due to the required changes to the combustion processes.