Grid monitoring and long-term planning should become standard practices to identify and implement the optimal solutions for the overall system operation and PV integration, according to the European Photovoltaic Industry Association.
PV is expected to play a central role in achieving Europe’s climate objectives. Today, PV produces enough electricity to supply over 15 million European households, covering about 2% of Europe’s electricity demand. The European Photovoltaic Industry Association (EPIA) projects that, depending on the political and economic framework conditions, PV could cover between 10% and 25% of EU electricity needs by 2030. This translates into between 11 % and 28% of the EU decarbonisation effort in the energy sector.
Sometimes it does not hurt to state the obvious. PV is scalable, from small rooftop-scale applications to hundreds of MW. Significant PV power potential exists anywhere in Europe, and the technology can be installed in a decentralised manner to cope best with network capabilities and power demand. But is it reaching its full potential as it is being run today?
“Costs have been coming down rapidly and the PV electricity is becoming increasingly attractive economically,” says Frauke Thies, Policy Director, EPIA.
According to Thies, for solar energy to reach its full competitive potential, PV needs adequate and predictable revenue streams, streamlined administrative and grid connection procedures, as well as adequate certification schemes for installers and easy access to capital.
As EPIA has demonstrated in its new study, Connecting the Sun, the capacity of the distribution network does not need to become a bottleneck if smart strategies are implemented today.
The further development of the distribution grid should be planned with a strategic perspective, taking into account the whole generation mix, as well as innovative options, such as active demand side management. Unfortunately, the relevance of the distribution grid for achieving the climate objectives is still largely underestimated on the European level, says Thies.
It is being highlighted that distribution grids in Europe can already take up significant amounts of PV electricity.
“In the past, PV systems have largely been treated as passive players in power system operation and inverters were designed only to maximise the PV electricity output. One example, is the so-called 50.2 Hertz issue: System operators used to require PV systems to switch off as soon as a certain frequency was exceeded in the system,” says Thies.
She explains that during a system disturbance in November 2006, this requirement led to decentralised generation – at that time mostly wind - being switched off, thereby even aggravating the situation. Today, many countries have adapted their network codes to better exploit the network support capabilities that PV can offer. PV is increasingly providing system services, such as active power reduction in case of over-frequency, fault-ride through capability and the provision of reactive power enabling voltage support.
Progress has also been made in the design of the power network itself. Not only network upgrades, but also technical adaptations, such as self-regulated distribution transformers, can be used to increase the hosting-capacity of the distribution network. Now the different solutions need to be implemented more widely to enable the large-scale integration of PV in a cost-effective manner, says Thies.
The PV industry also needs to identify the challenges ahead of large scale PV integration into the electricity grids. These include voltage rise and overloaded grid components. “These challenges exist and we have to take them seriously,” says Thies.
She adds: “The good news is that a number of solutions are available and can be used in combination. This includes the use and further development of active inverters, storage and demand side management, to name but a few. Curtailment should only be the last resort.
“Generally, we are currently seeing a transition from a passive distribution grid to a more active system management. This will not only facilitate the cost-effective integration of PV, but it will also support the deployment of other new appliances, such as electric vehicles, heat pumps, smart meters and efficiency measures,” explains Thies.
As for Europe, the challenges of integrating variable renewables will also be significantly reduced by a flexible electricity system, based on interconnection and cross-border trade, enlarged balancing areas, and a flexible power generation mix.
Also, for grid integration, as highlighted in the PV GRID Project in Europe, PV systems need to adhere to certain rules and meet certain technical criteria, usually defined by grid operators and electricity market regulators. There is also a need to work on grid capacity issues.
For its part, the EPIA is engaging in an active dialogue with transmission and distribution system operators to ensure that cost efficient PV development strategies are adequately taken into account in future network planning and network code requirements.
Alongside a well-coordinated and far-sighted network development, PV systems can also contribute actively to a smooth network integration through the delivery of specific system services, but also through the optimisation of dynamic self-consumption, and the aggregation of power in-feed.
“For example, households can play an active role in peak-shaving strategies through the combined use of PV self-consumption and heat pumps, or other load management options,” says Thies.
Arguably, a traditional approach leads to costly grid reinforcements. Distribution system operators generally do not have a real-time picture of the status of the grid and they often do not sufficiently reflect the projections for renewable energy uptake in their network planning. Also, current regulatory framework conditions leave little room for them to invest in smart and innovative solutions, other than traditional grid reinforcements.
Thies recommends that grid monitoring and long-term planning should become standard practices to identify and implement the optimal solutions for the overall system operation and PV integration. A first step to overcome existing bottlenecks would be the adaption of the regulatory framework on the long-term planning and financing conditions for network operators.
Coordination will cut costs and optimise PV
Talking of coordination between TSOs, DSOs and RES generators to achieve the EU decarbonisation goal, Thies says dialogue between the different players is crucial to achieve Europe’s climate and energy objectives. On one hand, system operators should be aware of the prospects of renewable energy uptake, but also of the capabilities of the different technologies and how these could be exploited.
On the other, the PV industry needs clarity on the requirements it should meet in view of ensuring optimal local power quality. Where this is not done yet, EPIA suggests establishing forums at national or regional level to exchange best practices and to reach consensus on network rules and investment decisions.
At the same time, TSOs and DSOs should also enhance their planning coordination.
“We think that a formal coordination framework would be appropriate to improve the flow of information between TSOs and DSOs,” says Thies.
Thanks to grid monitoring, further standardisation and long-term planning practices, DSOs will be able to adopt smart and cost-effective strategies to host increasing shares of distributed generation.
In this context, PV should no longer be considered as a passive actor in the grid: its capabilities should be exploited as much as possible.
However, to ensure proper operation of the distribution grids, DSOs’ remuneration structure should be re-discussed and a balance should be struck between services that PV can provide to the grid.
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