Sammendrag
Integrated Gasification Combined Cycle (IGCC) power plants with CO2 capture are expected to form an important part of a future carbon constrained energy scenario. As with all capture routes, research efforts related to IGCC have been concentrated on minimizing the energy penalty of the capture process. However, in respect to the overall improvement of energy efficiency, the realization of an IGCC with CO2 capture would benefit considerably by the realization of gas turbines burners that are capable of burning hydrogen with low NOx emissions and without the energy penalty presently incurred when diluting the hydrogen fuel with steam or nitrogen. This is a tall order and a number of technical difficulties have prevented the realization of such burners to date, one of the most important issues is the achievement of an injection scheme for the hydrogen fuel into the oxidant stream that is both intrinsically flashback-safe and that provides efficient mixing (Grout et al., 2011). Previous work has concluded that two of the main flashback-related challenges concerning the injection of hydrogen in an oxidant stream are: 1) the presence of a concentrated fuel point-source represented by the fuel nozzle itself and 2) the formation of a low-velocity region immediately downstream of the nozzle in the wake of the transverse fuel jet (Grout et al., 2012; Kolla et al., 2012).
A novel concept, for the IGCC as well as for the H2 gas turbine, is to employ hydrogen-permeable Pd membranes to achieve an optimally distributed fuel injection into the oxidant stream, directly upstream of a gas turbine combustor. A membrane-injector scheme would not only avoid the presence of concentrated fuel sources in the pre-mixer section of the burner but also prevent the formation of unwanted low-velocity regions in the flow field. A preliminary study (Weydahl et al., 2012) indicated that the membrane-injector concept is feasible and that the main challenges that need to be addressed before its deployment are: 1) the (presently) somewhat limited maximum hydrogen mass flow achievable through the membrane and 2) the design of an opportune oxidant flow that efficiently removes the hydrogen fuel from the permeate side of the membrane thereby ensuring optimal membrane operation (maximum theoretical mass flow).
In the present work the ASU, gasifier, syngas cleanup, water-gas shift and sulphur removal were modeled according to the European Benchmarking Task Force (EBTF), by Franco et al. (2011), whereas the gas turbine is modeled as a large industrial unit with reheat, and the steam bottoming cycle is adapted to match with the requirements of the process. The novelty of the IGCC process presented in this work is that H2 membrane units are integrated directly in the fuel mixing zone of the high-pressure gas turbine combustor, for enhanced mixing of the fuel and combustion air. This concept will require a novel type of hydrogen membrane/ combustor feed flow integrated design, and a preliminary sketch of such a design is shown in Figure 1. Not all of the available hydrogen in the shifted syngas can be separated through the membrane, which matches well with the process envisaged for the low-temperature separation of hydrogen and CO2 in the shifted syngas downstream of the hydrogen membrane (Figure 2). In the low-pressure gas turbine combustor, the hydrogen fuel recovered from the low-temperature separation process is premixed with some of the nitrogen available from the ASU and assumed to be injected in a lean-premix combustor of more conventional type.
A novel concept, for the IGCC as well as for the H2 gas turbine, is to employ hydrogen-permeable Pd membranes to achieve an optimally distributed fuel injection into the oxidant stream, directly upstream of a gas turbine combustor. A membrane-injector scheme would not only avoid the presence of concentrated fuel sources in the pre-mixer section of the burner but also prevent the formation of unwanted low-velocity regions in the flow field. A preliminary study (Weydahl et al., 2012) indicated that the membrane-injector concept is feasible and that the main challenges that need to be addressed before its deployment are: 1) the (presently) somewhat limited maximum hydrogen mass flow achievable through the membrane and 2) the design of an opportune oxidant flow that efficiently removes the hydrogen fuel from the permeate side of the membrane thereby ensuring optimal membrane operation (maximum theoretical mass flow).
In the present work the ASU, gasifier, syngas cleanup, water-gas shift and sulphur removal were modeled according to the European Benchmarking Task Force (EBTF), by Franco et al. (2011), whereas the gas turbine is modeled as a large industrial unit with reheat, and the steam bottoming cycle is adapted to match with the requirements of the process. The novelty of the IGCC process presented in this work is that H2 membrane units are integrated directly in the fuel mixing zone of the high-pressure gas turbine combustor, for enhanced mixing of the fuel and combustion air. This concept will require a novel type of hydrogen membrane/ combustor feed flow integrated design, and a preliminary sketch of such a design is shown in Figure 1. Not all of the available hydrogen in the shifted syngas can be separated through the membrane, which matches well with the process envisaged for the low-temperature separation of hydrogen and CO2 in the shifted syngas downstream of the hydrogen membrane (Figure 2). In the low-pressure gas turbine combustor, the hydrogen fuel recovered from the low-temperature separation process is premixed with some of the nitrogen available from the ASU and assumed to be injected in a lean-premix combustor of more conventional type.