Power system operators are facing new challenges with increasing levels of variable renewable energies (VRE) while at the same time needing to ensure their power systems remain stable and resilient.
Different approaches are being used to integrate VRE in different jurisdictions and a number of these are the subject of a new study for the IEA’s Implementing Agreement on Renewable Energy Technology Deployment (IEA-RETD). The overall objective of the research was to understand how the context of different jurisdictions influence the measures implemented to integrate VRE and the effectiveness of these measures. The ten jurisdictions investigated were Alberta and Ontario in Canada, the California ISO and ERCOT in the US, Great Britain, Ireland, Denmark, Germany and Spain in Europe, and Hokkaido in Japan. This later is notable as being a vertically integrated system and the only one of the sample not relating to a deregulated market.
Challenges for renewable integration
The study by Mott MacDonald identifies four main challenges for policy makers in addressing VRE integration:
1. Ensuring VRE is deployed in a way that makes the most of VRE generation while reducing its negative system impacts.
2. Introducing market arrangements and operational practices which make the most of the current installed flexibility.
3. Creating an incentive environment that encourages investment in the required amount of flexibility, where flexibility comes from generation, storage and demand side response.
4. Making the most of scarce grid resources (in terms of capability to transport electricity from producers to load centres).
Not all the challenges are felt equally across all jurisdictions, due to the context (characteristics) of the jurisdiction. In particular, the size and nature of the VRE portfolio and its geographical distribution, the type and level of interconnection and the access to flexibility will determine the nature of the integration challenges a jurisdiction will face. Additionally, the regulatory arrangements of a jurisdiction (e.g. the use of markets, separation of utility functions and operations) will influence the types of measures that can be implemented.
Lessons for renewable integration
The study finds that the continued increase of levels of penetration of VRE technologies requires new policies in order to secure their successful integration into markets and power systems. There is no ‘one size fits all’ approach, and policy makers will need to tailor their policy interventions to suit their country specific factors. Countries with weak interconnection and electrical system flexibility will face the greatest challenge, and so they will need to implement appropriate VRE integration measures at lower levels of VRE penetration.
Specifically the lessons drawn are as follows:
1. The deployment patterns/mix of technologies should be considered at an early stage of VRE deployment in order to mitigate congestion/reduce swings in net load. Measures found to have successfully impacted on deployment patterns and the mix of technologies include differentiated financial support, planning and using connection rules/charges for different technologies.
2. Build-in grid code measures sooner rather than later. The prudent approach is to ensure that VRE is built-in with as much grid support functionality as is viable, without incurring excessive cost.
3. Move to near real time re-dispatch supported by sophisticated forecasts of VRE output and load. This allows more efficient scheduling of capacity and reduces the need to carry operating reserve.
4. Learn from others but do one’s own studies to assess impacts.
5. Co-operate with other jurisdictions. Exploiting the opportunities to trade energy, reserve and balancing services to the fullest extent is likely to be one of the best ways of integrating VRE where a jurisdiction has interconnector access to other jurisdictions.
Lessons by jurisdiction characteristics
1. Well-connected countries should focus on interconnector rules and market harmonization. The first priority should be making sure the fullest interconnector capacity is made available and applying “use it or lose it” rules for capacity allocation. This should be followed by coupling of day ahead and intraday markets and SO-to-SO co-operation on balancing.
2. Jurisdictions experiencing chronic grid bottlenecks should consider both operational measures such as dynamic line rating (and potentially special derogations in security standards) and market arrangements which explicitly incorporate the spatial dimension in pricing.
3. Systems with weak interconnections and especially those with asynchronous links need to be aware that their challenge will be greater and consider special system services for inertia and fast frequency response, dynamic reactive power and emergency response to frequency drops (through demand side response and storage) to ensure adequate flexibility and system resilience.
4. Systems with low internal flexibility and weak interconnections need to be aware they will face caps on VRE deployment (before curtailment is required) unless they address these constraints.
5. Systems lacking significant flexibility (due to high shares of nuclear or inflexible coal/gas/hydro plant) may be forced to choose between curtailing VRE or their “inflexible” dispatchable plant even at fairly low VRE shares. Exploiting existing demand side response and squeezing the most out of existing interconnectors should be first priorities. Beyond this, these systems will need to expand storage, demand side response and interconnector capacity.