Technoeconomic modelling of renewable hydrogen supply chains on islands with constrained grids
In the global effort to reduce carbon emissions, renewables are helping to decarbonise our energy systems. However, their intermittent nature means they must be supported by complementary technology. One such option is water electrolysis, which uses electricity and water to produce hydrogen and oxygen. The hydrogen can then be used for sector coupling, relatively high energy density drive trains, intercontinental energy transport and seasonal storage. In order to assess the viability of hydrogen production from a given site, it is necessary to undertake technoeconomic analysis to calculate production rates and unit costs. In turn, this requires validated models of electrolysers. This work ties detailed electrolyser models into technoeconomic analyses methods, which are then applied to a number of different scenarios. I focus on islands, wind and tidal power, and constrained grids. The main outcome of the modelling aspect is that there is negligible difference (up to 1.6%) between: using a constant value for electrolyser performance (kWh/kg); modelling electrolyser performance as a function of power consumption and temperature. This justifies the use of the simple approach in large scope, low detail studies. The main outcome of the technoeconomic analysis is the production/delivery rates and unit costs in three main studies. The first was a supply driven, wind and/or tidal powered electrolyser. This study included production, storage and transport via ferries. Delivery rates ranged from 53 kg/day at £15.53/kg using curtailed power only to 185 kg/day at £7.93/kg, where non-curtailed renewable power was also used. Using curtailed power exclusively gave a low capacity factor which, because of the relatively great capital cost, resulted in expensive hydrogen. In contrast, harnessing non-curtailed renewable power increased the capacity factor and reduced the unit costs. The second study was a 2,500 kg/day demand driven system, where the resulting hydrogen is used in an essential ferry service. This considered production and storage. Here, the best levelized cost was £4.60/kg using predominantly wind power. Tidal and grid power were used as a back up, and the grid was not constrained. The optimal plant capacities obtained were a 7.85 MW electrolyser, a 4,500 kg store, a 50 MW wind farm and a 50 MW tidal farm. The third study was a supply driven system, were only production costs were considered. This used record low prices for solar power and electrolysis capex to estimate hydrogen production rates and levelised cost when an electrolyser has priority dispatch from a 2 GW solar plant. The maximum production rate was 224,000 kg/day. Levelised cost varied between £0.86 - 1.91/kg, depending on electrolyser capacity and capex. This thesis confirms that using only curtailed power results in expensive hydrogen. However, it also found competitive scenarios, e.g. priority dispatch to an electrolyser from a relatively large renewable power installation. In these cases, renewable hydrogen is set to imminently match or even undercut the cheapest hydrogen produced from fossil fuels with carbon capture and storage. The modelling work and approach to technoeconomic analysis showcased in this thesis can be taken forward in other scenarios. These studies will reveal the locations and business models through which renewable hydrogen can be produced competitively, thus becoming a viable energy vector for decarbonising energy and industry where electrification is not suitable.