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Who should be responsible for reliability and resilience?

Energy storage and distributed renewables could produce another ‘paradigm shift’ for electricity networks

The major changes anticipated in operating, planning, and paying for electricity transmission and distribution networks with high levels of variable renewables are now clearly here, or on their way. For example, the arrival of large amounts of wind generation with very low marginal cost has led to customers being offered free or cheap electricity when it’s windy and demand is low (See A Texas Utility Offers a Nighttime Special: Free Electricity and Why Big Businesses Should Consider DSR). The same economics applies in principle to all low-marginal-cost sources including of course PV, but also nuclear.  The response to the economic impacts is clear: demand response, whether driven by variable pricing as in these examples or otherwise, and energy storage.

Energy storage for these purposes exists only at two very different scales: very large (for example, Scandinavian hydro reservoirs reacting to price signals caused by Danish wind production), and very small (for example, domestic battery + solar installations in Germany).  In the middle, at medium-voltage level, there are virtually no energy storage installations justified only by energy price variations: this is where demand response currently predominates instead.

Currently, neither storage nor demand-response contributes much to managing the electricity networks, though the emergence of aggregators will improve this (e.g., Flexitricity).  However, instead of regarding storage, demand response, and renewables on distribution networks as a minor adjunct to the business of operating a nation’s electricity system, is there value in looking at it completely differently?

This thinking arises from the view that electricity networks face increasing uncertainty and risks, due to the factors discussed above, and also cyber-security risks.  Traditionally, the approach to ensuring reliability and resilience in the face of uncertainty is to make the national (or even international) electricity system more robust: more transmission capacity, national restoration or ‘black-start’ plans, faster protection, periodic testing of generator dynamic capabilities, more communications and control.  In the current context, that also means strict attention to cyber security for the whole system.  The emphasis is on preventing disasters occurring at all. However, in situations where the distribution systems contain a large amount of generation, and in particular energy storage, it’s worth considering whether this is where the true robustness lies.  After all, that’s where the customers are.

What would such an approach look like?  It would:

  • Accept that blackouts can and indeed will happen, whether caused by predicted very rare events, unpredicted events, poor understanding of the state of a very complex system, or malicious attacks
  • In the event of a major disturbance, isolate all distribution networks from the transmission system
  • Use the embedded generation, demand response, and energy storage capabilities within each distribution network to establish stable frequency and voltage for the essential loads
  • Establish stable frequency and voltage on the transmission system, where suitable generators are available, such as reservoir hydro
  • Then (and only then) use the TSO to reconnect all energised networks.

How does this differ from current practice? In fact, not much—the main difference is that distribution networks try to get themselves working as island networks, in parallel to the recovery of the transmission system.  The benefits are earlier restoration of at least the essential supplies, and greater resilience—because distribution networks have different characteristics, unpredictable events and malicious attacks are unlikely to be able to affect them all to the same extent.  In fact, to guard against the latter, it would be beneficial to ensure a range of different cyber security practices, equipment, and systems across distribution networks.

What are the difficulties?  Well, the distribution network operators have a whole new set of tasks to perform.  However, this could be seen as just one more part of a general move to the DSO role.  Also, in most distribution networks, inertia is likely to be the biggest difficulty when trying to restore satisfactory frequency control.  Therefore, this strategy is most attractive where there is a significant proportion of embedded synchronous generation, such as standby generators, biomass, biogas, geothermal, or CHP or controllable inverters from windfarms, aggregated PV plant and storage systems.

What are the benefits?  Diversity provides more resilience against the ‘unknowns’: unpredicted events, unexpected behaviour of the system, and malicious attacks.  Planning how to get a distribution system running again in a list of possible situations may be easier than planning how to get a national or international electricity system running again against a much longer and less-understood list of possible situations.  Also, there may be a substantial cost saving, if the embedded generation and energy storage devices can remove the need for large thermal generators being kept in operating condition just for black-start purposes.

Can we move from here to there?  It would require very significant changes in current structures and thinking.  But whether we like it or not, very significant changes are coming anyway.

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