Managing risk in modern power systems

By AEMC Director, Christiaan Zuur

with thanks to Graham Mills, Julian Eggleston, Alan Rai, Oliver Tridgell, Sam Martin, Andrew Dauwalder

2020 is taking shape to be another year of significant change to make the national electricity market (NEM) more resilient to new and emerging risks. This is important work – underpinning the delivery of a reliable and secure supply of energy for customers, at the lowest possible cost.

The power system faces a number of new mitigation and adaptation risks. More extreme weather will unavoidably impact a weather dependent generation fleet (adaptation risk). And indirectly, a key climate change mitigation measure, the replacement of emission intensive thermal generation with zero emission renewables, also brings new risks (mitigation risk).

The NEM market bodies; the Australian Energy Market Commission, Australian Energy Market Operator, and the Australian Energy Regulator, together with the Energy Security Board, are working to support the transition of the system by managing all these risks.

The power system’s new generation mix means we have to manage the system differently. Modern power systems face very different risk scenarios. This is driven by the transition of the generation mix away from large thermal synchronous units, to smaller, variable renewable energy (VRE), asynchronous generators. On the demand side, the rapid uptake of behind the meter technologies is also driving change. This is in addition to well-understood historic risks such as the loss of individual large generators or single transmission lines which must still be actively managed.

Many of the stabilising services that were provided for free by synchronous generators are not necessarily provided by the asynchronous variable renewable energy generators, although several new asynchronous generators and batteries are starting to offer these services. Any shortfall in these services can make it harder to control the voltage and frequency of the power system, both during normal operation and following sudden system breakdowns.

The output of variable renewable generators depends on environmental conditions, including wind speed and levels of sunlight. This makes them particularly vulnerable to some of the effects of climate change, which in Australia may include more severe weather and increasing bushfires. These generators are typically widely distributed, with many small units scattered across wide areas. In combination with their dependence on weather conditions, this means that a generation fleet dominated by variable, renewable generators can exhibit large swings in power, in relatively short time frames. These swings can destabilise voltage and frequency, and potentially threaten the stability of the transmission connection between regions.

And critically – there’s another revolution happening at the small end of the grid on the demand side.

Distributed energy resources like rooftop PV and batteries, bring with them a new set of opportunities and challenges. This locally produced generation can reduce peak demand and take pressure off the system. If carefully coordinated, it can also mitigate the impacts of system-wide risks, by supporting the grid during disturbances. However, high penetrations of rooftop solar supply and increasing take-up of batteries can also result in rapid changes in demand, which requires an increasingly flexible and rapid start-up generation fleet. Distributed energy resources need to be strongly coordinated or there’s a stronger risk of cascading blackouts if uncontrolled loss of local generation happens after an unexpected power system equipment failure.

All this adds up to a new kind of “indistinct” risk that must be managed in modern power systems. Indistinct risks are condition dependent. This means they are driven by external conditions, particularly environmental effects like severe weather. They are also likely to occur across a wide area, affecting many generation and transmission elements at once, in an unpredictable manner. Finally, they may occur over a period of time, as opposed to the almost instantaneous N-1 contingencies.

Regulators need to expand approaches to manage this new power system risk profile in addition to the tools used to manage the risks associated with a power system dominated by synchronous generators. There are several ways to do this.

It is necessary to actively rebuild the system stabilising services that used to be provided automatically by synchronous generators’ equipment. These services stabilise system frequency and voltage. System frequency is stabilised through the control of active power, which is dependent on the presence of system inertia. System voltage is stabilised through the control of reactive power, which is stabilised through the presence of system strength.

Several major reforms have already been completed by the AEMC, or are underway, with the aim of restoring these services. We are currently progressing a rule change to provide a primary frequency response from the generation fleet. This reform can help control frequency, during normal operation and following disturbances of all kinds.

We have also made significant changes to technical performance standards for generators seeking to connect to the national electricity grid. Under the new rules, a connecting generator’s technical requirements are matched to local power system needs rather than a one-size-fits-all approach. This is key to keeping costs down for consumers

This included changes to the way that generators provide reactive power to stabilise voltage, both during normal operation and following disturbances.

We have also introduced new arrangements to help bolster levels of system inertia and system strength, both of which are of critical importance to stabilising the system.

The Energy Security Board currently is considering the design of the national electricity market’s power system. This post-2025 market design work program will consider what new services are needed and what they should look like, as well as the best way to source them. This work program will also be considering issues related to managing the variability of a variable renewable-dominant generation fleet. The AEMC is working hard with the other market bodies to assist the ESB with this work program.

Investment in new network assets can also strengthen the system by making it more interconnected.

Increasing the degree of interconnection in the system means that there are fewer single points of failure. It also means there is greater scope to share stabilising services between different parts of the power system. A more coordinated approach to planning and building the network also means that security risks can be identified and addressed sooner. Under the auspices of the ESB, AEMO’s Integrated System Plan and the AEMC’s Coordination of Generation and Transmission Investment processes are looking at how network interconnection can be facilitated.

Finally, there are several ways we can make the system smarter, and more flexible, to account for these new risks. This can be achieved through building schemes that protect against specific events, like the loss of a major transmission line. However, operational measures are some of the lowest cost, and most effective, ways of making the system smarter.

The AEMC has recently proposed two new operational measures, which will make the system smarter and better able to manage risk. These are:

• A new “protected operation” framework, which will allow AEMO to change the operational profile of the power system in the presence of heightened indistinct risks. For example, AEMO will be able to take actions, like procure additional services or limit interconnector flows, when it considers the system faces increased indistinct risk from a major storm system.
• A new general risk review process, which will involve NSPs, AEMO and interested market participants working together to identify new and pressing risks and propose new measures to address them.

The AEMC considers that these new measures will help reduce the risk of major blackouts, improving outcomes for consumers, for a relatively low cost.

More work remains to be done. Work on identifying new services will continue under the ESB in 2020. The AEMC has also identified several areas for reform which could enhance the ability of the system to manage new risks. These include:

• Reassessing the effectiveness of under frequency load shedding control schemes
• Reforming the protected events framework, to better identify and address critical non-credible contingencies in each jurisdiction
• Considering the existing power system standards, and whether new standards could be developed to enhance the resilience of the power system.