In 2030, flexibility needs for daily power cycles will remain similar to current ones in France, says Arnaud Renaud, CEO, Artelys France who will be one of the strategic programme speakers at the European Utility Week.
Energy storage opportunities in France
Up to 20GW of installed photovoltaic solar generation coincides with periods of high demand, thus reducing the arbitrage possible between peak hours and off-peak hours. Above 30 GW, residual demand (after deduction of photovoltaic generation) drops significantly on sunny summer days, creating new electricity storage opportunities for the evening peak.
It must be noted that the 20 and 30 GW thresholds depend heavily on the energy policies of neighboring countries though: a massive roll-out in Europe of photovoltaic without associated electricity storage would lead to new electricity storage opportunities in France, given the high level of interconnection between European networks.
On the other hand, explains Renaud, flexibility needs for intra-weekly cycles will increase significantly by 2030: increases in tertiary uses lead to differences in demand between weekdays and weekends that are more marked than today.
National wind power generation, whose installed capacity objectives are high in all the scenarios studied (between 30 and 46 GW), statistically varies over cycles of several days as weather conditions averaged over the entire country generally remain stable for several days.
The combination of these two factors leads to an almost 50% increase in the need for flexibility over one week compared with the current situation and thus to opportunities for intra-weekly storage.
This being said, it is important to keep in mind that the French electricity mix already has high electricity storage capacities (4.3 GW of PHS and 13 GW of hydropower with reservoirs), which deteriorates the value of additional electricity storage capacities, explains Renaud.
Economically relevant energy storage technologies in France
Between now and 2030, in Metropolitan France, the only cost-effective mass electricity storage systems will be Pumped Storage Power Stations, assessed at 1 to 1.5 GW of installation potential, depending on the mix scenario.
While specific local contexts (impossibility of reinforcing the grid, societal acceptance difficulties, for instance) may generate sporadic opportunities, decentralized or diffuse electricity storage is most of the time less economically viable than grid reinforcement solutions or the curtailment of excess intermittent generation.
Most electricity flexibility needs can be satisfied through the dynamic management of electricity demand (such as end-use energy storage). For example, the dynamic management of the recharging of existing hot water heaters in homes could generate savings of 40 to 85 M€/year in France, for a limited cost in the context of the advantageous usage of future intelligent meters or the more dynamic use of tariff signals (on-peak hours / off-peak hours).
Similarly, by managing the recharging of electric vehicles (between 1 and 9 million vehicles in France, depending on the scenario) according to national electricity generation costs, one could eliminate an additional cost of 100 to 300 M€/year caused by direct charging (unscheduled charging of electric vehicles by the user).
Renaud points to thermal energy storage as a “very interesting solution” in the context of the creation or extension of a heating network. He says it introduces complementary flexibility to the supply-demand balance, making it possible to drastically reduce the investment costs in heating plants (biomass plants and peak capacities). The installation of heat storage on heating networks represents a potential in the order of 5 to 10 GWhth by 2030 in France.
Europe’s energy storage industry developments
The overseas territories represent an extremely interesting experimentation terrain for the development of stationary electricity storage, says Renaud.
While the French installation potential remains limited (200 to 400 MW), the projects studied in the PEPS report (surface CAES, Li-Ion batteries, etc.) are cost-effective for the community and the prospects for worldwide deployment are promising (by taking into consideration not only the islands but also the regions in which the electricity grid has a low level of interconnection), which thus leads to an interesting starting point for the creation of an export industry for stationary storage systems.
In terms of ancillary services, the study shows that a highly responsive electricity storage system dedicated to supplying the primary reserve in Metropolitan France would generate savings for the community of 250 to 450 k€/MW/year installed. For this, flywheels and batteries appear to be promising solutions: the forecasted investment cost at the horizon 2030 for ½ hour of storage is estimated at 180 k€/MW/year for flywheels (assuming 20 years of depreciation) and 80 k€/MW/year for a Li-Ion battery (assuming 10 years of depreciation).
Despite this, more detailed analysis and experimentations are necessary in order to quantify the operational costs and the technical feasibility of using the different technologies to this end, explains Renaud. Regulatory modifications would be required to allow the exclusive participation of an electricity storage system in the reserve.