The pace and scale of Australia’s green energy transition is likely to depend on the success and widespread adoption of a little known technology – grid forming inverters – and the early findings from a first-of-its-kind project in Australia look good.
Australia’s exit from coal has already been slowed down by concerns about the level of “grid security” – concepts such as inertia, fault current and system strength – which for decades has been provided as a free extra by synchronous generators such as coal, gas and hydro.
The prevailing view in Australian grid management circles is that these services must be at least partly delivered by giant spinning machines which don’t burn fuel, and are known as synchronous condensers – a technology that has been around for decades.
But the difficulty in obtaining and transporting these huge and now expensive pieces of kit have already caused another delay in the closure of Eraring, Australia’s largest coal generator.
The battery storage industry, and technology providers such as Tesla and Fluence, insist that their kit equipped with grid forming inverters can do the job of delivering “system strength” at a fraction of the cost of synchronous condensers, and can be sourced and installed a lot more quickly.
Grid management authorities, the market operator and the transmission companies responsible for system strength, say that may well be the case. But they need to see more evidence of it actually working to be convinced and to waive away the need for dozens and dozens of syncons planned across the grid.
The Australian Energy Market Operator is planning a world-first trial this year of isolating a part of the main grid with at least 100 MW of demand to test the theory, but other important trials have also been occurring and the reports are promising.
The small 25 megawatt, 50 megawatt Darlington Point battery in the Riverina was the first battery in Australia to be built from scratch with grid-forming inverters (most other early installations had them added after construction began), and as part of the federal funding deal agreed to provide updates to keep the industry informed.
In a report filed with Arena and published on its website last month, Edify Energy – which owns the Darlington Point battery – says the project has show it can provide system strength (frequency and voltage stabilisation, fast disturbance event response, etc.) with much faster response times than other storage or generation technologies.
“By providing these services, BESS (battery energy storage systems) projects with advanced grid forming inverters can remove the need for synchronous condensers or other measures to be installed with renewable energy projects,” it notes.
“Synchronous condensers are complex and expensive machines. Therefore, removing the need for such machines significantly reduces the cost and risk profile associated with connecting renewable energy projects in weak grids.”
What’s more, big batteries are highly flexible and can walk and talk at the same time, unlike most other grid technologies.
As Edify pointedly notes:
“BESS projects with grid forming inverters can also provide all the beneficial services that have been observed and well reported from other BESS projects (such as charging during periods of low demand / price, dispatching into high demand / volatile price periods and providing market ancillary services) making them a multi-use market and technical service technology, in contrast to single purpose technologies such as synchronous condensers.”
Of course, this is not the end of the story. As noted by a new white paper – Securing Power Systems in the Renewable Revolution – released this week by the UNSW Energy Institute, the University of Wollongong and the NSW Decarb Institute, there is a lot of work to be done.
“Sourcing these services from inverter-based resources, largely through GFM inverters, raises technical, economic and regulatory questions,” its experts write.
“These relate to first principles issues, protection mechanisms, dynamic behaviour and system stability, testing and validation, and markets and regulation.”
It recommends discussions on a series of technical, regulatory and management issues, including the definition of “protection quality fault current” which appears to be at the centre of the divide between the inverter makers and the regulatory and market bodies who must keep the lights on, and have no margin for error.
“The main risk isn’t normal day-to-day operation,” says Mark Twidell, one of the co-authors, the UNSW Energy Institute Industry Professor of Practice, and a director of AGL Energy.
“It’s how inverters respond during faults and disturbances, and whether existing protection systems can continue to operate reliably when those responses change. The White Paper calls for closer industry collaboration to harness existing data to understand inverter behaviour and plan ahead.”
Its recommended actions include finding answers to the following questions:
- – What is the need for synchronous machines now, during the transition and beyond?
- What mix of synchronous condensers (SynCons), grid-forming (GFM) and grid-following (GFL) inverters is necessary? What are the boundary conditions?
- – If required, can inverter-based resources (IBRs) provide all power system security services to the system?
- – How would a “Pilot” Future State of the Network be designed to provide confidence of “feasibility at scale” to regulatory authorities?
- – What is the appropriate mix of distribution and transmission-based assets to best operationalise security services?
- – How does this mix change with location, asset availability, demand, supply and penetration of generation, load features and network arrangement?
- Back at the Darlington Point battery, it is interesting to note that the authors say the output of the total 150MW facility (including the neighbouring Riverina battery) during different network disturbances has been compared to the output of a 150MVA synchronous condenser.
During a frequency disturbance, the BESS and the syncon provided a similar amount of inertia, with the BESS providing the additional benefit of a frequency droop response due to the stored energy.
Even when operating at 0 MW, a simulated network fault showed that the 150MW BESS was able to maintain stability of the network in a similar way to a 150MVA synchronous condenser.
On the other hand, that was not the case\ when the BESS was simulated operating at full export prior to the same fault, where it was shown that its efforts to stabilise the network indicated equivalence to a much smaller synchronous condenser.
“This highlights one of the key considerations which must be taken into account when networks consider relying on BESSs for the provision of system strength,” the report said. “This was also largely to be expected due to the relatively low current limits of inverter-based plants in this scenario.”
Another important achievement has been the ability of the battery, armed with grid forming inverters, to enter into a network support agreement with Transgrid that allows a local constraint equation to be eased, meaning lesser curtailment for wind and soalr.
“The key goal of the Project was to demonstrate that a grid forming BESS could provide system strength,” the report concludes.
“Ultimately the benefit of this will be that grid forming BESSs can deliver these critical services at a more
efficient cost than solutions such as synchronous condenser and network upgrades.”
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