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The Future of Hydrogen Chapter 5: Opportunities for hydrogen in transport, buildings and power Flexible power generation Hydrogen can be used as a fuel in gas turbines and CCGTs. Most existing gas turbine designs can already handle a hydrogen share of 3–5% and some can handle shares of 30% or higher. The industry is confident that it will be able to provide standard turbines that are able to run entirely on hydrogen by 2030 (EUTurbines, 2019). Ammonia is another potential fuel for gas turbines. The direct use of ammonia has been successfully demonstrated in micro gas turbines with a power capacity of up to 300 kW (Shiozawa, 2019). In larger gas turbines above 2 MW, the slow reaction kinetics of ammonia with air, the flame stability and the NOx emissions are issues still being investigated by researchers (Valera-Medina et al., 2018). Instead of directly burning ammonia, an alternative approach is to reconvert the ammonia first into hydrogen and nitrogen, to burn hydrogen in the combustor of the gas turbine. The heat required for decomposing (or cracking) the ammonia at temperature levels of 600–1 000°C (the temperature depends on the catalyst) can be supplied by the gas turbine, though this slightly reduces the electricity generation efficiency of the overall process. Fuel cells can also be used as a flexible power generation technology. With electric efficiencies of 50–60% (lower range today, upper future potential) being in a similar range to those of CCGTs, the choice between fuel cells and CCGTs in economic terms largely depends on their capital costs. It is, however, worth noting that fuel cell stacks today still suffer from a shorter technical lifetime than gas turbines (10 000 to 40 000 hours of operation), and that stationary fuel cells today typically have a smaller power output (up to 50 MW for the largest fuel cell power plants), which makes them most suitable for distributed generation. For comparison, CCGT units can reach capacities of 400 MW. The heat produced by the fuel cell while generating power can be used to provide an additional revenue stream. Future cost reductions for fuel cells will depend on future deployment levels and the learning effects and economies of scale that follow from this. On optimistic assumptions, CAPEX for hydrogen fuel cells may fall to USD 425/kW by 2030 compared to USD 1 600/kW for a 1 MW PEMFC unit today or USD 1 000/kW for a CCGT today (Bruce et al., 2018). Hydrogen and ammonia could offer low-carbon flexibility for electricity systems with increasing shares of VRE. Alternative low-carbon flexible generation options are natural gas- fired power plants equipped with CCUS and biogas power plants. Both alternatives are characterised by higher capital costs per unit of power than needed for a hydrogen-fired CCGT power plant, due to the additional capture equipment needed for CCUS and the typically smaller scale of biogas power plants. The capital cost advantage of the hydrogen option is more pronounced when the load factor is low (Figure 62), and it often is low in systems with high shares of VRE. At a capacity factor of 15%, low-carbon hydrogen would become competitive with electricity generation from natural gas with CCS at hydrogen prices of USD 2.5/kgH2, if the gas price is USD 7/MBtu.54 54 For comparison, USD 1/kgH2 corresponds to USD 8.8/MBtu. PAGE | 156 IEA. All rights reserved.PDF Image | The Future of Hydrogen 2019
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