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Power system transformation and flexibility |
areas, at specific times of the day. These programmes are becoming more and more common as platforms emerge to match customer usage data with the specific needs of the local distribution system.
Engaging distributed battery storage
Similar to distributed generation, distributed storage systems are connected at the distribution level or sited locally to serve specific needs, for example through collocation with small-scale or remote wind generation.
A growing field in the deployment of battery storage relates to the provision of various grid services. Due to their speed and precision of response, batteries can be deployed for a number of applications, such as frequency regulation. Additionally, depending on the jurisdiction, battery storage may be used for a number of applications such as arbitrage in wholesale markets or for balancing markets. Depending on the frameworks available, it may be possible to deploy existing back-up batteries or even make use of EV fleets.
In all of these cases, the regulatory framework and interconnection requirements play a key role for profitability. In Germany, for example, transmission system operators (TSOs) who are in charge of procuring primary frequency reserves for very short-term flexibility have developed a set of minimum requirements, specifying the secure operating range for primary regulation provision based on the state of charge at the time of dispatch (Regelleistung, 2015).
In the United Kingdom, by contrast, the attractiveness of battery storage participation in the capacity mechanism has reduced substantially due to the introduction of a new de-rating methodology, thus motivating battery operators to seek additional sources of revenue, such as the balancing mechanism. Further to these applications, typically in markets operated by the TSO or independent system operator (ISO), batteries can be deployed at the consumer end to reduce energy bills and potentially to balance the transmission or distribution networks directly. In these cases, the structures of ownership and operation depend heavily on unbundling regulations and the ability to stack revenues from different sources.
Box 15. Battery storage for real-time balancing
Battery storage projects in the United Kingdom have mainly relied on income from participation in frequency regulation services and in the country’s capacity market. Revenues from these sources have decreased due to saturation of the frequency regulation market and de-rating provisions in the capacity market.
National Grid operates the balancing mechanism as part of the wholesale market for participants to settle any imbalances close to real time. This market has previously been restricted to generators under 50 MW, as they are exempt from the wholesale market participation licence requirement. Limejump, an independent aggregator, has applied for a special dispensation to enter the wholesale market, aggregating 10 MW of standalone battery storage and a co-located facility of 10 MW PV and 6 MW battery storage.
The project allows sufficient revenue for battery storage, as balancing mechanism prices have been observed to reach up to GBP 2 500 (British pounds) /MWh and are above GBP 100/MWh for a third of the time. An additional aspect to the profitability of such aggregation is the ability to stack revenues from arbitrage in the wholesale market and participation in the balancing mechanism.
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One particular area yet to be discussed, which is seeing increasing relevance, is the deployment of battery storage for location-specific flexibility services. For example, ENDESA, one of Spain’s largest distribution system operators, is testing the deployment of back-up battery storage from telecommunication base stations for local balancing purposes. Aggregation of flexibility resources for balancing at the local distribution level can limit the extent of bidirectional flows back into the transmission system (Box 16).
Box 16. Battery storage for balancing the distribution network
By using the flexibility available at 20 telecommunication battery sites across the Barcelona distribution network, ENDESA Distribución has tested the feasibility of operating a local market to solve congestion in the distribution network, while maintaining a committed consumption schedule at the border with the transmission network. In practice, such a business model should be expected to facilitate balancing the overall system, although it depends on a number of regulatory and institutional questions. At the institutional level, balancing is currently the responsibility of the transmission system operator, such that ENDESA would actually require a particular agreement with Red Eléctrica de España to recognise and monetise its contribution to keeping the system in balance.
On the regulatory side, as distribution network operators under the European framework, ENDESA is not allowed to own or operate battery storage units, which count as generators. For this reason, ENDESA has established a number of partnerships. For example, the batteries were originally installed to provide back-up supply at Vodafone stations. While ENDESA has visibility over the station’s smart meters, it dispatches the batteries via a local flexibility market based on the bids of an aggregator (Our New Energy [ONE]) upon detecting upcoming deviations from the agreed consumption profile.
As with other inverter-based DER, this project supports the deployment of battery storage for real-time balancing due to the speed of response and precision. Nonetheless, any commercialscale application will depend on the creation of the appropriate co-ordination interface between REE and ENDESA. Moreover, applicability would depend on identifying revenue streams that are sufficient both to incentivise ENDESA, the respective aggregator (ONE) and Vodafone, as the asset’s owner, and to prove cost-effective when compared with typical balancing resources.
Source: Madina et. al (2018), “Exploiting flexibility of radio base stations in local DSO markets for congestion management with shared balancing responsibility between TSO and DSO”, https://zenodo.org/record/1445342#.W7XntBMzZTY.
Distributed generation for system services
Distributed generation includes renewable energy generators and co-generation units connected to the distribution network, or small units connected at the transmission level that are physically close to loads. Due to their technological diversity, distributed generation assets will be able to contribute to flexibility needs differently. This will also depend on the operational and prequalification requirements in place.
One common case of distributed generation for system flexibility entails the use of back-up generation on site to ensure continuous energy supply for critical energy uses, such as hospitals, banks and data centres. Back-up generators, typically diesel units, are characterised by their rapid start-up times, between 10 and 30 minutes, and short minimum up-times. In recent years back-up generation, primarily from diesel generators, has been used in some American and European markets to serve long-term flexibility needs, and to meet peaks in demand and short-
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Power system transformation and flexibility |
term balancing through restoration reserves. From the perspective of critical energy users, the deployment of back-up generation for flexibility may be seen both as an additional source of revenue and an additional source of security of supply as the back-up generators are used more regularly. From a policy maker’s perspective, deploying otherwise idle back-up generation may be an alternative to kick-starting markets for demand response. However, the long-term viability of this should be balanced against additional concerns, such as increased urban emissions.
Additional distributed generation technologies include dispatchable rooftop PV and cogeneration from biomass plants. As explained earlier, distributed PV’s ability to contribute to the system depends on the inverter technology available, while for co-generation it may depend on the associated heating demand. While these plants are usually too small to be able to participate in the provision of flexibility at the levels typically required by system operators, it is possible to aggregate and co-ordinate their output through virtual power plants. In Germany and Switzerland a number of pilots and commercial schemes have been established to do this.
Using smart inverter technology, solar PV can provide voltage management capabilities and power system support services, as well as improved communications and interactivity. Adding battery storage improves the provision of these services, and has the important benefit of shifting some or all of the generated power for consumption to times of higher system demand (Figure 16). These services can have value for local grids; at high shares of decentralised solar PV, they can also become relevant to ensuring security of supply.
Figure 16. Technical impacts of rising deployment of distributed solar PV generation
Source: IEA PVPS (2014), Transition from Uni-Directional to Bi-Directional Distribution Grids.
As decentralised solar PV increases, a new set of technical challenges must be overcome.
Aggregation for load shaping
The rise of digitalisation allows for the co-ordinated deployment of many smaller types of system resources at a large scale. So-called aggregators make use of digital platforms to
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actively manage distributed energy resources in a way that is beneficial for both the power system and the consumer.
Smaller industrial and large commercial consumers are increasingly engaging in demand response programmes; these are typically operated through aggregators and allow flexibility providers to either obtain an additional source of income or reduce their energy bills. Participation of such end consumers has usually been enabled by the presence of smart metering infrastructure and time-of-use electricity tariffs (dynamic load shifting and curtailment). By engaging a greater number of stakeholders, aggregators can contribute to reduce the cost of balancing the system, but targeted policy or regulatory changes may need to be implemented to allow for their participation in wholesale or ancillary services markets.
Box 17. Pooling industry and battery storage in virtual power plants
In 2018 Belgium faced a tight winter, with extended outages of its nuclear fleet impacting the country’s security of supply. The government secured extra capacity from gas-fired power stations, and the TSO introduced a new product to allow additional flexibility to participate in the balancing market. In addition, the Belgian government entered into agreements for cross-border electricity exchanges with its neighbours, France, Germany and the Netherlands. In the previous two years electricity imports and exports across Belgium’s borders were severely constrained by network restrictions in the Central Western Europe region, due to grid congestion and unscheduled loop flows.
Belgium is reasonably well positioned among European countries in respect of opening the provision of flexibility services to DER, such as industrial demand response and battery storage. Procuring frequency reserves from a broader range of flexibility resources is seen as a way of reducing the cost of reserve provision and Elia, the country’s system operator, has taken an active role in developing products that enable their participation. As of 2018 access for different technologies and market participants was satisfactory. Although in practice some requirements still exclude DER from the market, the cost of procuring reserves has fallen in recent years by opening the balancing markets to additional flexibility from DER.
REstore, part of Centrica, integrates localised distributed energy solutions for businesses around the world, leveraging onsite generation (co-generation, PV and wind), storage and flexible loads (industrial, commercial and residential). As one of Europe’s largest aggregators with a portfolio of 2 300 MW, REstore has developed a number of solutions to serve the Belgian balancing markets.
In April 2018 REstore launched the 32 MW Terhills Virtual Power Plant (VPP), located in a former coal mine on the edge of Belgium’s National Park. The project took 6 months from inception to operation, including 5 weeks to install the 18.2 MW Tesla Powerpack storage system, composed of 140 batteries. What makes this battery project unique is its inclusion in a larger flexibility portfolio, together with micro-generation, industrial loads and household applications, such as domestic boilers. The VPP provides primary reserve and frequency regulation to the Belgian system operator, instantly charging when frequency is too high and discharging when frequency is too low. The battery can respond incredibly accurately and fast, up to 100 times faster than a fossil fuel power plant.
The European Commission described the Terhills project as a key enabler for the decarbonisation
of the European energy system. The VPP supports the grid while reducing the need to ramp up
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