Flexible nuclear plants with thermal energy storage and secondary power cycles: Virtual power plant integration in a UK energy system case study

Electricity markets are fast changing because of the increasing penetration of intermittent renewable generation, leading to a growing need for the flexible operation of power plants to provide regulation services to the grid. Previous studies have suggested that conventional power plants (e.g., nuclear) may benefit from the integration of thermal energy storage (TES), as this enables greater flexibility. In conventional Rankine-cycle power plants, steam can be extracted during off-peak periods to charge TES tanks filled with phase-change materials (PCMs); at a later time, when this is required and/or economically favourable, these tanks can feed secondary thermal power plants to generate power, for example, by acting as evaporators of organic Rankine cycle (ORC) plants. This solution offers greater flexibility than TES-only solutions that store thermal energy and then release this back to the base power plant, as it allows both derating and over-generation. The solution is applied here to a specific case study of a 670 MW el nuclear power plant in the UK, which is a typical baseload power plant not intended for flexible operation. It is found a maximum combined power of 822 MW el can be delivered during peak demand, which is 23% higher than the base plant’s (nominal) rated power, and a maximum derating of 40%, i.e., down to 406 MW el during off-peak demand. An operational energy management strategy (EMS) is then proposed for optimising the charging of the TES tanks during off-peak demand periods and for controlling the discharging of the tanks for electricity generation during peak-demand periods. An economic analysis is performed to evaluate the potential benefits of this EMS. Profitability in the case study considered here can result when the average peak and off-peak electricity price variations are at least double those that occurred in the UK market in 2019 (with recent data now close to this), and when TES charge/discharge cycles are performed more than once per day with a discharge duration to the ORC plants longer than 2 h. When considering the most recent UK electricity prices in 2021 (to-date), the EMS investment cost for one 1-h charge and 1-h discharge cycle per day is 199 m£ with a total generation of 50 GWh per year and a levelised cost of electricity (LCOE) of 463 £/MWh. The investment cost drops significantly to 48 m£ when discharging for a longer duration of 8 h as the size of the ORC plants decrease. The projected LCOE also decreases to 159 £/MWh when doubling the total generated electricity (100 GWh/year) by employing two 8-h TES charge/discharge cycles per day. Importantly, it is found that the economics of the EMS are determined by a trade-off between longer discharge durations to the ORC plants that minimises their size and cost, and shorter charge/discharge durations that yield the highest spread between off-peak and peak electricity prices