On Sunday, 11 October 2020, South Australia made international headlines when it became the first interconnected power system of its size (1 to 3 GW) to have 100% of its demand met by 100% solar photovoltaics (PV). While this included centrally dispatched utility PV, the vast majority (76%) of the PV generation online was distributed (DPV), otherwise known as rooftop solar.
A few months later, on Sunday, 14 March 2021, South Australia made headlines again. An outage of a major transmission line coincided with record-low levels of demand, and to proactively manage risks to power system security, the Australian Energy Market Operator (AEMO) issued a direction that would result in the systematic, temporary reduction of DPV generation. Achieving active management of small rooftop PV en masse across the power system represents a major milestone towards achieving secure operation in a power system supplied primarily by distributed resources.
Australia’s National Electricity Market (NEM) has one of the highest levels of DPV in the world, with 15 GW of DPV capacity in a system with a peak demand of 35 GW. In fact, AEMO forecasts the NEM reaching periods of 100% instantaneous renewable generation by 2025, and high amounts of DPV generation will play a key role in meeting such a milestone. To enable a future with such high levels of DPV generation, AEMO is implementing measures to manage the twin challenges of minimum system load and DPV contingency.
Minimum System Load
Operational demand (also known as grid demand, or the demand serviced by centrally dispatched generation) is reaching record minimums, driven by the high uptake of DPV. In one 30-minute interval in 2021, DPV generation supplied 43% of underlying demand in the whole NEM mainland, and it is forecast to reach up to 77% by 2026, as shown in Figure 1.
Figure 1: Minimum Operational Demand in the NEM mainland (excluding Tasmania) (Source: AEMO, ESOO 2021)
In South Australia, where DPV uptake is even higher, DPV generation has supplied up to 92% of underlying demand (shown in Figure 2) and is forecast to supply over 100% in some periods for the first time this year. When this occurs, South Australia, which has a peak demand of over 3 GW, will see operational demand for the whole region pushed below zero (shown in Figure 3), with the entire region supplied not only by renewable resources, but by distributed renewable resources (small rooftop PV systems connected in the distribution network).
The NEM consists of five interconnected regions, and some regions (particularly Queensland, South Australia, and Tasmania) can occasionally separate from the rest of the NEM and need to operate as an island. For example, South Australia has separated from the rest of the NEM on average about once every 1 to 2 years, and during February 2020 South Australia needed to operate as an island for several weeks, following damage to the interconnector in a major weather event.
During these types of events, until the demonstration of new technologies such as grid-forming inverters, each region must have sufficient operational demand to allow enough synchronous generating units to operate to deliver all the essential security services, including inertia, system strength, voltage control, and frequency control. These units need to operate above their minimum loading levels, and with enough “headroom” and “footroom” to provide sufficient frequency services. The aggregate of these loading levels corresponds to the demand threshold for the secure operation of a region as an island, based on the present operational toolkit. In the future, with demonstration of new technologies such as grid-forming inverters, it may become increasingly possible to reduce these thresholds towards zero. But it will still remain necessary to have tools to export, store, spill, or otherwise actively manage excess DPV generation when the total generation in the region exceeds underlying demand (forecast to occur in South Australia in the next few months).
South Australia has already experienced demand levels below thresholds that can be managed with the present operational toolkit, while Queensland and the mainland NEM (the interconnected NEM excluding Tasmania) are forecast to approach these levels in 2022 and 2024, respectively. The estimated operational demand threshold for the NEM mainland, based on the present available operational toolkit, is shown above in Figure 1.
The crossing of this threshold represents a reduction in operational flexibility and system resilience. While interconnected, a region must store or export the difference to its neighbours. While operating as an island, if storage is not available, there is no other option but to reduce generation from distributed PV in order to maintain a secure power system. However, in the NEM, distributed PV is primarily small rooftop systems, and until recently, there was no physical way to remotely connect to these small rooftop systems and actively manage their output.
While DPV generation is driving demand down, it’s also driving generation contingency sizes up.
AEMO has observed a pattern of DPV inverters disconnecting during severe power system disturbances. Through field measurements and bench-testing, the inverters have been observed to disconnect for several minutes in response to a range of phenomena, including voltage sag, low frequency, phase angle jump, and high rates of change of frequency.
The sudden, unexpected loss of DPV generation has historically been offset by the disconnection of load. However, with DPV generation increasingly the largest generation source in some periods, these disturbances now represent a net loss of generation during daylight hours. This can coincide with the loss of the largest single generating unit, increasing the size of the largest credible generation contingency. With increasing DPV uptake, this behaviour, unabated, is forecast to present unmanageable generation contingency sizes.
Active DER Feed-in Management
The dispatch of DPV through virtual power plants and future “two-sided markets,” in which distributed energy resources respond to real-time prices, will deliver a level of control that will help address these challenges in the future and reward customers for their participation.
In Australia, the proportion of new DPV installations participating in aggregation remains relatively low, and the uptake of DPV so high, that capabilities to reduce DPV generation to maintain system security are needed in the shorter term.
In September 2020, South Australia became the first Australian jurisdiction to require all new DPV installations to have the capability to be remotely disconnected in emergency conditions.
The Smarter Homes regulations require a relevant agent (appointed by the DPV customer) to manage the curtailment capability. This can be delivered by several technologies, including through application programming interface (API) control of internet-connected inverters, modbus control of an inverter via 4G signal, and switching of an internal circuit dedicated to the DPV installation in an advanced metering infrastructure meter. Legacy systems that export more than 200 kW to the network can also be curtailed via SCADA disconnect control (this capability has been required by the network provider since 2018
In addition, SA Power Networks deployed its Enhanced Voltage Management scheme across its distribution network in 2020, which has the capability to curtail DPV systems installed prior to the regulations. The technology is primarily used to address high-voltage issues by reducing voltage levels on feeders during high DPV generation periods. In addition, in emergency conditions when DPV curtailment is required, the scheme can be used to increase voltage levels to a point that causes a proportion of legacy DPV systems to disconnect due to their overvoltage protection settings.
In February 2022, Western Australia introduced a requirement for remote curtailment capability for all new and upgraded DPV installations 5 kW and below, while other Australian jurisdictions are considering similar requirements.
Following observations of DPV disconnection during power system disturbances, AEMO initiated a review into the Australian Standard AS/NZS 4777.2, which sets out connection requirements for inverter-based distributed energy resources. The revised standard, published in December 2020 and taking effect in December 2021, requires greater capabilities from DPV inverters to remain connected and generating power during system disturbances, stemming the growth in the DPV contingency risk.
Compliance with the new standard is essential for its effectiveness. However, data samples provided by manufacturers suggest that only 35% of installations since January 2022 have been installed in accordance with the new AS/NZS4777.2:2020. AEMO is collaborating with stakeholders on various measures to improve compliance.
The disconnection of DPV is a last-resort mechanism used to maintain system security in emergency conditions, and social licence is a critical requirement for its ongoing success.
To improve transparency, AEMO has introduced a market notice framework to alert the market and community if there is a risk of a DPV curtailment event. The market notices may also elicit a market-based response (such as an increase in demand), which may avoid the need for DPV curtailment.
The framework consists of three levels of market notices, with a level 1 notice indicating a forecast risk of DPV curtailment, a level 2 notice indicating that AEMO has intervened in the market (either through the direction to curtail DPV, or other steps to address the risk), and a level 3 notice indicating that DPV curtailment is occurring.
Network Investment and New Technologies
Lastly, when demonstrated at scale, grid-forming inverters offer the possibility of a future in which all essential system security services might be provided without the need to maintain synchronous units online, even in islanded operation. This could reduce minimum system load thresholds to zero — though DPV generation exceeding underlying demand will still need to be exported or curtailed. AEMO is actively investigating the application of grid-forming inverters in the NEM.
Distributed PV generation presents an enormous opportunity, for DPV owners and more broadly for enhanced power system security. As with any new technology, there is a transition process where various changes to the power system need to be investigated and actively managed, such as minimum system load and DPV contingency risks.
The measures outlined above provide an important and enduring foundation for managing power system security, upon which longer-term management measures such as network investment, grid-forming inverters, and two-sided markets can be layered, to implement a power system that can operate affordably, reliably, securely, and efficiently on 100% distributed renewable resources.
As DPV uptake continues to increase in other NEM regions and around the world, other jurisdictions may need to implement similar solutions.
Mark Thompson and Dr. Jenny Riesz
Australian Energy Market Operator (AEMO)
phil kreveld says
Reading the blog reinforces the idea that with the very high uptake of DPV we are arriving at a point where many distribution networks could be isolated from the HV grid provided there were BESS voltage forming inverters connected at zone substations. More home storage, more community batteries, the use of smart transformers (to basically desynchronise the edge of network and some smarts to resynchronise for the smart transformers fed from 22 kV feeders for reconnection to the main HV grid (switching between minigrid/main grid operation) would reshape the NEM. We could reexamine the need for SA Connect, VNI west-or at the very least the proposed ratings for these lines.