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140 IPCC Special Report on Carbon dioxide Capture and Storage high CO2 content that simplifies the CO2 capture subsystem. The fuel is normally natural gas, though some concepts can also be incorporated into coal gasification systems. The systems concepts can be classified into two main groups (Goettlicher, 1999): • Systems with pre-fuel cell CO2 capture; • Systems with post-fuel cell CO2 capture. In pre-fuel cell CO capture systems (see Figure 3.18a) the 2 Figure 3.18a Fuel cell system with pre-fuel cell CO2 capture. The carbon-containing fuel is first completely converted into a mixture of hydrogen and CO2. Hydrogen and CO2 are then separated and the H2- rich fuel is oxidized in the fuel cell to produce electricity. The CO2 stream is dried and compressed for transport and storage. Figure 3.18b Fuel cell system with post-fuel cell CO2 capture. The carbon-containing fuel is first converted into a syngas. The syngas is oxidized in the fuel cell to produce electricity. At the outlet of the fuel cell CO2 is separated from the flue gas, dried and compressed for transport and storage. fuel is first converted into hydrogen using steam reforming or coal gasification, followed by the water gas shift conversion. This system approach has been first proposed both for low temperature and for high temperature fuel cells. The post-fuel cell capture system (see Figure 3.18b) is proposed for high temperature fuel cell systems (Dijkstra and Jansen, 2003). These systems make use of the internal reforming capabilities of the high temperature fuel cells resulting in an anode off-gas that has a high CO2-content, but also contains H2O and unconverted CO and H2. The water can easily be removed by conventional techniques (cooling, knock-out, additional drying). Oxidizing the H2 and CO from the (SOFC) anode with air will result in a too high dilution of the stream with nitrogen. Haines (1999) chooses to use an oxygen-transport membrane reactor placed after the SOFC. The anode off-gas is fed to one side of the membrane, the cathode off-gas is fed to the other side of the membrane. The membrane is selective to oxygen, which permeates from the cathode off-gas stream to the anode- off gas. In the membrane unit the H2 and CO are oxidized. The retenate of the membrane unit consist of CO2 and water. Finally a concept using a water gas shift membrane reactor has been proposed (Jansen and Dijkstra, 2003). steam to produce more H2 and CO2. The separation of these two gases can be achieved with well-known, commercial absorption- desorption methods, producing a CO2 stream suitable for storage. Also, intense R&D efforts worldwide are being directed towards the development of new systems that combine CO2 separation with some of the reaction steps, such as the steam reforming of natural gas or water gas shift reaction stages, but it is not yet clear if these emerging concepts (see Section 3.5.3) will deliver a lower CO2 capture cost. 3.5.5 Status and outlook This section reviewed a wide variety of processes and fuel conversion routes that share a common objective: to produce a cleaner fuel stream from the conversion of a raw carbonaceous fuel into one that contains little, or none, of the carbon contained in the original fuel. This approach necessarily involves the separation of CO2 at some point in the conversion process. The resulting H2-rich fuel can be fed to a hydrogen consuming process, oxidized in a fuel cell, or burned in the combustion chamber of a gas turbine to produce electricity. In systems that operate at high pressure, the energy conversion efficiencies tend to be higher when compared to equivalent systems operating at low pressures following the combustion route, but these efficiency improvements are often obtained at the expense of a higher complexity and capital investment in process plants (see Section 3.7). In power systems, pre-combustion CO2 capture in natural gas combined cycles has not been demonstrated. However, studies show that based on current state of the art gas turbine combined cycles, pre-combustion CO2 capture will reduce the efficiency from 56% LHV to 48% LHV (IEA, 2000b). In natural gas combined cycles, the most significant area for efficiency improvement is the gas turbine and it is expected that by 2020, the efficiency of a natural gas combined cycle could be as high as 65% LHV (IEA GHG, 2000d). For such systems the efficiency with CO2 capture would equal the current state-of- the-art efficiency for plants without CO2 capture, that is, 56% LHV. In principle, all pre-combustion systems are substantially similar in their conversion routes, allowing for differences that arise from the initial method employed for syngas production from gaseous, liquid or solid fuels and from the subsequent need to remove impurities that originate from the fuel feed to the plant. Once produced, the syngas is first cleaned and then reacted with Integrated Gasification Combined Cycles (IGCC) are large scale, near commercial examples of power systems that can be implemented with heavy oil residues and solid fuels like coal and petroleum coke. For the embryonic coal-fired IGCC technology with the largest unit rated at 331 MWe, future improvements are expected. A recent study describes improvements potentially realisable for bituminous coals by 2020 that could reduce both energy and cost-of-electricity penalties for CO2 capture to 13% compared to a same base plant without capture. For suchPDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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