From the November edition of pv magazine
Neil Horrocks recounts suburban folklore: The story of the short-armed linesperson, who connects every new or renovated house in the street to the wire that’s easiest to reach once they’re up the pole. In Australia we typically have four electricity wires, swaying with magpies and cockatoos, running down our streets. Three are used for connections, and because distribution network service providers (DNSPs) have primarily monitored power flows at the apex of their grid domain, rather than down in the weeds of local streets, they can get signals from individual lines at capacity that indicate the system is overloaded. This misinformation plays particularly badly for rooftop solar PV exports.
With 2.46 million Australian rooftop PV systems connected, and that number increasing at a rate of 200,000 a year, DNSPs in Queensland, Victoria and South Australia have tried to manage grid instability by limiting residential hopes of selling their excess solar generation back to the grid. Some have limited the size of the solar system householders and businesses can install. Others have imposed zero or near-zero caps on exports as part of grid-connection agreements. South Australia has just required that all rooftop solar systems must be enabled for mass turn-off should the grid be threatened by the giant duck curve, in which supply exceeds demand and the system quacks.
Enter Horrocks, the director of the Centre for Energy Data Innovation at the University of Queensland (UQ). And enter homegrown companies such as GreenSync, Redback Technologies and SwitchDin, who have been saying for several years that distributed energy resources (DER) are not the problem, but the answer to grid woes. All of them are working on tapping live data to orchestrate DER in a way that supports the grid, and supports the Australian people’s aspirations to reduce carbon emissions and minimise their electricity bills.
Take the issue of overload signals from areas with underloaded lines. Horrocks and his team at UQ are working with Redback Technologies and Energy Queensland (a group of state-owned DNSPs) on a project that deploys low-cost sensors at the pole tops along a number of Queensland streets, to observe at illuminated-house-number level what’s happening minute by minute in terms of electricity flow. Eleven million data sets a day are collected from this fraction of the Queensland network.
“Not only can we see when people lose power or when conditions are unsafe,” says Horrocks, adding that thanks to the new localised monitoring, technicians can be sent directly to remedy the affected part of the grid. “But we can see voltage signatures coming out of almost every connection point in a street, and which phase or line they’re connected to.”
As a result, UQ can provide the networks an accurate picture of the loading on each of the phases. “Hopefully, we’ll get to the point one day where the network can quickly run powerline analysis once every year, and move two or three houses from this phase to that phase, to unlock more capacity for solar on that line,” says Horrocks. “It’s an hour’s work for a technician in a truck versus weeks and millions of dollars to restring a line.”
In constrained areas of the Victorian and South Australian networks, the Australian Renewable Energy Agency (ARENA) is supporting a world-first trial that combines network data with software control of rooftop solar systems. The SA Power Networks Flexible Exports for Solar PV Trial aims to increase rooftop solar connections and avoid limiting grid-connection agreements for new solar-enabled homes – an inequitable situation that favours early adopters.
The 12-month trial will coordinate the solar energy exported from 600 homes with constrained network capacity, adjusting export limits every five minutes based on signals received from the distribution network. Control of rooftop systems will be enabled by inverters from Fronius, SMA and SolarEdge that are fitted with responsive technology, and on homes with other inverters by retrofitting SwitchDin Droplet technology, which performs the same function (it also allows property owners to control energy flows behind the meter, as well as virtually any solar-enabled system’s interactions as part of a virtual power plant).
“Export to the grid only needs to be turned down in those peak solar moments” that typically occur in the middle of sunny weekend days in spring and fall, when solar production is high, says Andrew Mears, founder and CEO of SwitchDin. Commercial/industrial demand is lower, and summer’s air-conditioners have not yet been unleashed. Using data to limit electricity exports from all connected systems at such times, but otherwise accepting excess solar PV generation into the system at volumes that the network can cope with, enables new solar PV connections on the way to net-zero emissions, rewards all exporters for contributing clean, cheap energy to the grid, keeps generation local – avoiding the losses of transporting energy over long distances – and protects the voltage reliability to properties that are not solar enabled.
“The great potential of the Internet of Things (IoT) is to make a system that’s interconnected, where everything talks to everything,” says Bruce Thompson, Head of Customer at GreenSync, which is constantly evolving its deX platform as a technology-agnostic marketplace or host for interoperability.
Thompson sees South Australia’s Smarter Homes Compliance requirement, enacted for all new solar/battery systems in the state connected or upgraded from Sept. 28 of this year, as an important step to wider digital interaction. The requirements relevant to exchange of information are that all inverter-connected generators and storage must be capable of remote communications, including enabling remote disconnection and reconnection by a nominated agent in the event of a network emergency; and that new smart meters are required to be capable of measuring and controlling generation and any controllable load (such as hot-water systems) separately to the general electricity supply. The digital visibility and control these regulations confer will enable coordinated responses (via virtual power-plants, for example) to dynamic data such as spot prices in the National Electricity Market and voltage fluctuations at a local network level.
Asked to envisage digital NEM utopia, Thompson calls for pragmatism: “Utopia is as you increasingly install solar panels, connect a battery or plug in an electric car over the next few years, you register that piece of equipment on a platform”. The resulting benefits include being able to safely participate in the network within “the right speed limits and without crashing,” he says, likening the network to a road. Digital capabilities inherent in dynamic connection agreements will then allow participants to “export or import a significant amount of energy to the benefit of that household or business.”
Granular automated digital control of residential appliances and commercial equipment by electricity retailers will ultimately allow homes to be cooled to the right temperature, ensure the car battery is appropriately charged and so on, in step with advantageous electricity prices.
At UQ, Horrocks is testing the ability of streaming data from local pole-top sensors to enable “wildly accurate” forecasting of demand and fine-tuning of efficiencies. He points out that it’s too expensive at the moment to supply every Australian home with a smart meter, but curbside data can reveal the electricity habits and needs of individual neighbourhoods and homes. This has prompted the Centre for Energy Data Innovation to work with German heating, cooling and ventilation company Stiebel Eltron, as well as a number of Queensland families. They will calibrate water heating so the supply in their tanks is never hotter than required, but just right – saving electricity and money.
Also on the horizon is the ability to get ahead of network problems. Says Horrocks, “we’re now getting information about the low-voltage network in such detail, that we can start to forecast not only what’s going to happen today, based on current connections, but the impact of new connections in different areas of the network and what the supply profile will look like street by street.”
All proponents emphasise that Australia is in the midst of transition to successful management of two-way energy flows, and although everyone is moving in the right direction, Thompson notes that one challenge to interoperability between all the millions of small controllable energy producing and consuming systems, the distribution and transmission networks and the overarching energy operator is that it infers “a shared piece of digital infrastructure that doesn’t exist yet.”
The Open Energy Networks Project conducted by Energy Networks Australia in collaboration with the Australian Energy Market Operator published its position paper in May, identifying four potential frameworks for that infrastructure, including a single integrated platform, an independent distribution system operator and a hybrid solution. The major sticking point it found in a cost-benefit analysis of the options was the upfront investment required to enable any such framework, and that “net benefits are only delivered shortly before 2039 and only at very high levels of DER.”
Distributed energy resources are multiplying in Australia, and will take a great leap forward as battery energy storage and electric vehicles reach attractive pricing levels, increasing the challenges for distribution networks. At the same time, innovation in the digital management of systems is helping to ensure ongoing connection of rooftop solar to charge behind the meter storage. And it’s transforming DER, along with consumer appliances from “problem” to a coordinated grid participant, that can compensate for variability of large-scale wind and solar generation, says Thompson. He adds that “it’s an elegant solution, and we think it’s quite readily achievable.”
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