By Dave Elliott
Several academic studies have indicated that balancing variable renewables need not be expensive. An authoritative review of over 200 studies by UK Energy Research Centre in 2006 concluded: ‘Intermittency costs in Britain are of the order of £5 to £8/MWh, made up of £2 to £3/MWh from short-run balancing costs and £3 to £5/MWh from the cost of maintaining a higher system margin’.
By Dave Elliott
High shares of wind and solar power transform the entire power system and can lead to additional system integration and back-up costs aside from building the power plants themselves. A new background paper from Agora Energiewende examines these dynamics and concludes that, not only are the direct integration/balancing costs low, but so are the controversial indirect costs associated with the variable utilization, in balancing mode, of conventional plant – as long as the power system becomes considerably more flexible.
By Dave Elliott
Imperial College London and the NERA consultancy have produced studies of energy system integration costs and grid balancing options for the government’s advisory Committee on Climate Change. They focus on flexible generation and backup systems and conclude that ‘flexibility can significantly reduce the integration cost of intermittent renewables, to the point where their whole-system cost makes them a more attractive expansion option than CCS and/or nuclear’.
By Dave Elliott
The vehicle to grid (V2G) debate continues, offering a way to balance variable renewables and also demand peaks, by using the batteries of electric vehicles, linked to the grid when parked at home, to store excess power during low demand periods, ready to export when demand is high and renewables low. It sounds a clever idea but in addition to economic issues (e.g. the extra costs of the home-based power uploading system) it opens up some interesting logistical issues. (more…)
The Energy Futures Lab at Imperial College London has produced a ‘Strategic Assessment of the Role and Value of Energy Storage Systems in the UK Low Carbon Energy Future’ for the Carbon Trust, using a holistic system-wide modeling approach. It concludes that storage would allow significant savings to be made in generation capacity, interconnection, transmission and distribution networks and operating costs. In all it says that storage could provide up to £10 billion of added value in a 2050 high renewables scenario.
However, the relative level and share of the savings changes over time and between different assumptions. In the high renewables ‘Grassroots pathway’ used by the research team, the value of storage increases markedly towards 2030 and further towards 2050, so that carbon constraints for 2030 and 2050 can be met at reduced costs when storage is available. For bulk storage cost of £50/kW per year, the optimal volume deployed grows from 2 GW in 2020 to 15 and 25 GW in 2030 and 2050 respectively. The equivalent system savings increase from modest £0.12bn per year in 2020 to £2bn in 2030, and can reach over £10bn per year in 2050.
The value of storage is the highest in pathways with a large share of renewables, where storage can deliver significant operational savings through reducing renewable generation curtailment i.e. when there is excess wind output available. In addition, storage could lessen the even larger wind curtailment requirement that would result if there was also significant amount of inflexible nuclear capacity on the grid. However CCS scenarios yield the lowest value for storage: ‘adding storage increases the ability of the system to absorb intermittent sources and hence costly CCS plant can be displaced, which leads to very significant savings.’
Although it can be very useful in some situations, storage is not a magic solution for all our grid balancing problems: it is best used for specific purposes and durations. Crucially, Imperial say that ‘A few hours of storage are sufficient to reduce peak demand and thereby capture significant value. The marginal value for storage durations beyond 6 hours reduces sharply to less than £10/kWh year.’
So it seems we are talking about short storage cycles, ready for the next demand peak- not long term grid balancing to deal with long lulls in wind availability. That makes sense: storage is expensive, so you want to use the hardware regularly to capture excess energy (when it’s cheap) and sell it soon after to meet peaks, when energy prices are high.
This may be fine for short cycles. But how then do you deal with longer lulls? Especially in areas where there is a lot of wind capacity? Imperial say ‘Bulk storage should predominantly be located in Scotland to integrate wind and reduce transmission costs, while distributed storage is best placed in England and Wales to reduce peak loads and support distribution network management.’
The report also offers some other valuable insight into the interactive nature of the overall system options and operation. For example, one option for balancing grids in the short term is the use of flexible demand – e.g. reducing peaks by time-shifting demand. Imperial say that ‘Flexible demand is the most direct competitor to storage and it could reduce the market for storage by 50%.’ So with that, you would not need so much storage.
Another option, which might also help with longer-term grid balancing, is the use of interconnectors. While pumped hydro is the cheapest large scale bulk electricity storage option, the UK does not have much potential for large amounts, and some have argued that it would be cheaper to get access to the large pumped hydro storage capacity on the continent, in Norway for example, using ‘supergrid’ interconnector links. That could also allow the UK to import power when there was a long lull in wind availability.
Interconnectors are expensive, but Imperial say that cross-channel links (maybe 12GW or more) could be ‘beneficial for the system because it significantly reduces the amount of curtailed renewable electricity generation in the UK from 29.4 TWh to 15.1 TWh annually’. They add ‘this also suggests there will be less scope for storage to be used to reduce the system operating cost through reductions in renewable curtailment. The operating cost savings component is indeed lower in cases with increased interconnection capacity, by about 50% compared to the baseline (Grassroots) case.’ So we would not need so much storage.
Nevertheless, Imperial do see a need for perhaps 15GW of storage, given that ‘in the Grassroots Pathway, storage has a consistently high value across a wide range of scenarios that include interconnection and flexible generation.’
While there is a good overview of some storage technologies, beyond the points as above about the relative merits of bulk and distributed storage, the report doesn’t specify what sort of storage is best. Moreover, it is primarily about electricity storage. But how about rival modes of storage/ transmission e.g. heat or gas (including green gas). That would open up even more interactivity and may also improve the overall efficiency of the system and perhaps even reduce costs. After all, it is much easier to store heat or gas than electricity. Imperial admit that there are technical limits to conventional storage: the round-trip efficiency of storage can be low, and trying to increase it might not actually be worthwhile: ‘higher storage efficiencies only add moderate value of storage’ although ‘with higher levels of deployment efficiency becomes more relevant’. They also warn that ‘operation patterns and duty cycles imposed on the energy storage technology are found to vary considerably, and it is likely that a portfolio of different energy storage technologies will be required, suited to a range of applications.’
Fair enough: clearly more research is needed! Imperial do make a good job of promoting the benefits of storage and defending it against some critics. They say that ‘by providing reserve capacity and the resulting improved scheduling of plant, storage enables more wind energy to be delivered at the time of generation. In such instances the round trip efficiency of storage does not directly affect the amount of avoided curtailed that displaces other plant.’
However they add that ‘there remain a number of important unknowns with respect to the technologies involved in grid-scale energy storage, in particular relating to the cost and lifetime of storage technologies when applied to real duty cycles within the electricity network.’ While it is useful to get some idea of the possible interactions and their impacts, these technological and operational uncertainties do make you wonder how useful high-level modeling is: we are some way from being able to optimize the design of the emergent new grid systems, especially given the advent of novel storage technologies. So perhaps its not surprising that, on policy, Imperial ends up saying, ‘it is not clear whether government policies should incentivise the development and deployment of novel storage technologies, and if so, what sort of mechanisms should be considered, e.g. ranging from subsidies to direct procurement.’