Tesla’s ‘virtual power plant’ might be second-best to real people power



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Researchers talk to Bruny Islanders who have signed up to an experimental new method of managing energy.
Chris Crerar

Hedda Ransan-Cooper, Australian National University; Archie Chapman, University of Sydney; Paul Scott, Australian National University, and Veryan Anastasia Joan Hann, University of Tasmania

The South Australian government and Tesla recently announced a large-scale solar and storage scheme that will distribute solar panels and batteries free of charge to 50,000 households.

This would form what has been dubbed a “virtual power plant”, essentially delivering wholesale energy and service systems. This is just the latest in South Australia’s energetic push to embrace renewables, make energy cheaper and reduce blackout-causing instability.




Read more:
Explainer: what can Tesla’s giant South Australian battery achieve?


The catch is that more than a third of the costs of a power system are in the distribution networks, as are most of the faults. A virtual power plant on its own can’t necessarily solve the problems of costly network management.

The bundling of batteries together to power a network doesn’t consider the needs of either households or the network.

To address these problems, we’re trialling technology in Tasmania that intelligently controls fleets of batteries and other home devices with the aim of making networks more flexible, reliable, and cheaper to operate.

The Bruny Island Battery trial

Part of what we need to transition to a more reliable and cleaner grid is better control of power networks. This will improve operation during normal times, reduce stress during peak times, and remove the need for costly investment over the long term.

For instance, sometimes the network simply needs more energy in one particular location. Perhaps a household doesn’t want the grid to draw power from their battery on a particular day, because it’s cheaper for them to use it themselves. Most models of virtual power plants don’t take these different needs into account.

Bruny Island in Tasmania is the site of a three-year trial, bringing together researchers from the the Australian National University, the University of Sydney, the University of Tasmania, TasNetworks and tech start-up Reposit Power.




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Thirty-three households have been supplied with “smart battery” systems, charged from solar cells on their roofs, and a “controller” box that sits between the house and the power lines.

Participants are paid when their batteries supply energy to the Bruny Island network, which is sometimes overloaded during peak demand. Their bills will also go down because they’ll be drawing household power from their battery when it is most cost-effective for them.

In a world first, Network-Aware Coordination (NAC) software coordinates individual battery systems. The NAC automatically negotiates battery operations with the household (via the controller box), to decide whether the battery should discharge onto the grid or not.

In these negotiations, computer algorithms request battery assistance at a price that reflects the value to the network. If the price is too low for the household, for example because they are better off storing the energy for their own use later in the day, the controller will make a counter-offer to the network with a higher price.

The negotiation continues until they find a solution that works for the network, at the lowest overall cost.

The NAC-based negotiation is half of the economic equation. Battery owners will also be compensated for their work in supporting the grid. The trial team are working out a payment system that passes on some of the networks’ savings created by avoiding diesel generator use on Bruny Island.

Solving big problems

The problem of co-ordinating Australia’s 1.8 million rooftop solar installations in one of the longest electricity networks in the world is not trivial.

Distributed battery systems, such as in Tesla’s South Australian proposal, represent one possible future. The question that we’re exploring is how to coordinate large numbers of customer-owned batteries to work in the best interests of both the consumer and the network.

The primary feature of virtual power plants, to lump together resources, runs counter to what is required for targeted distribution network support. Nor do virtual power plants necessarily have to act in the best interest of householders.




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In contrast, we’re trialling technology that acts in the financial interests of householders, to earn value from their batteries by providing location-specific services to networks, at a time and price that suits the customer.

As currently conceived, the South Australian scheme may not be the most cost-effective solution to dealing with our evolving electricity system’s needs. The Bruny trial shows a different possible future grid – one which allows people to produce and store energy for themselves, and also share it, reducing pressure on the network and allowing higher penetrations of renewables.

The Conversation
The Bruny trial is funded by ARENA, and is a collaborative venture lead by The Australian National University, with project partners The University of Sydney, University of Tasmania, battery control software business Reposit Power, and TasNetworks.

Hedda Ransan-Cooper, Research fellow, Australian National University; Archie Chapman, Research Fellow in Smart Grids, University of Sydney; Paul Scott, Research fellow, Australian National University, and Veryan Anastasia Joan Hann, PhD Candidate – Energy Policy Innovation, University of Tasmania

This article was originally published on The Conversation. Read the original article.

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A month in, Tesla’s SA battery is surpassing expectations


Dylan McConnell, University of Melbourne

It’s just over one month since the Hornsdale power reserve was officially opened in South Australia. The excitement surrounding the project has generated acres of media interest, both locally and abroad.

The aspect that has generated the most interest is the battery’s rapid response time in smoothing out several major energy outages that have occurred since it was installed.

Following the early success of the SA model, Victoria has also secured an agreement to get its own Tesla battery built near the town of Stawell. Victoria’s government will be tracking the Hornsdale battery’s early performance with interest.

Generation and Consumption

Over the full month of December, the Hornsdale power reserve generated 2.42 gigawatt-hours of energy, and consumed 3.06GWh.

Since there are losses associated with energy storage, it is a net consumer of energy. This is often described in terms of “round trip efficiency”, a measure of the energy out to the energy in. In this case, the round trip efficiency appears to be roughly 80%.


Further reading: Yes, SA’s battery is a massive battery, but it can do much more besides


The figure below shows the input and output from the battery over the month. As can be seen, on several occasions the battery has generated as much as 100MW of power, and consumed 70MW of power. The regular operation of battery moves between generating 30MW and consuming 30MW of power.

Generation and consumption of the Hornsdale Power Reserve over the month of December 2018.
Author provided [data from AEMO]

As can be seen, the the generation and consumption pattern is rather “noisy”, and doesn’t really appear to have a pattern at all. This is true even on a daily basis, as can be seen below. This is related to services provided by the battery.

Generation and consumption of the Hornsdale Power Reserve on the 6th of Jan 2018.
Author provided [data from AEMO]

Frequency Control Ancillary Services

There are eight different Frequency Control Ancillary Services (FCAS) markets in the National Electricity Market (NEM). These can be put into two broad categories: contingency services and regulation services.

Contingency services

Contingency services essentially stabilise the system when something unexpected occurs. This are called credible contingencies. The tripping (isolation from the grid) of large generator is one example.

When such unexpected events occur, supply and demand are no longer balanced, and the frequency of the power system moves away from the normal operating range. This happens on a very short timescale. The contingency services ensure that the system is brought back into balance and that the frequency is returned to normal within 5 minutes.


Read more: Baffled by baseload? Dumbfounded by dispatchables? Here’s a glossary of the energy debate


In the NEM there are three separate timescales over which these contingency services should be delivered: 6 seconds, 60 seconds, and 5 minutes. As the service may have to increase or decrease the frequency, there is thus a total of six contingency markets (three that raise frequency in the timescales above, and three that reduce it).

This is usually done by rapidly increasing or decreasing output from a generator (or battery in this case), or rapidly reducing or increasing load. This response is triggered at the power station by the change in frequency.

To do this, generators (or loads) have some of their capacity “enabled” in the FCAS market. This essentially means that a proportion of its capacity is set aside, and available to respond if the frequency changes. Providers get paid for for the amount of megawatts they have enabled in the FCAS market.

This is one of the services that the Hornsdale Power Reserve has been providing. The figure below shows how the Hornsdale Power Reserve responded to one incident on power outage, when one of the units at Loy Yang A tripped on December 14, 2017.

The Hornsdale Power Reserve responding to a drop in system frequency.
Author provide [data from AEMO’

Regulation services

The regulation services are a bit different. Similar to the contingency services, they help maintain the frequency in the normal operating range. And like contingency, regulation may have to raise or lower the frequency, and as such there are two regulation markets.

However, unlike contingency services, which essentially wait for an unexpected change in frequency, the response is governed by a control signal, sent from the Australian Energy Market Operator (AEMO).

In essence, AEMO controls the throttle, monitors the system frequency, and sends a control signal out at a 4-second interval. This control signal alters the output of the generator such that the supply and demand balanced is maintained.

This is one of the main services that the battery has been providing. As can be seen, the output of the battery closely follows the amount of capacity it has enabled in the regulation market.

Output of Horndale Power Reserve compared with enablement in the regulation raise FCAS market.
Author provided [data from AEMO]

More batteries to come

Not to be outdone by it’s neighbouring state, the Victorian government has also recently secured an agreement for its own Tesla battery. This agreement, in conjunction with a wind farm near the town of Stawell, should see a battery providing similar services in Victoria.

This battery may also provide additional benefits to the grid. The project is located in a part of the transmission network that AEMO has indicated may need augmentation in the future. This project might illustrate the benefits the batteries can provide in strengthening the transmission network.

It still early days for the Hornsdale Power Reserve, but it’s clear that it has been busy performing essential services and doing so at impressive speeds. Importantly, it has provided regular frequency control ancillary services – not simply shifting electricity around.

The ConversationWith the costs and need for frequency control service increasing in recent years, the boost to supply through the Hornsdale power reserve is good news for consumers, and a timely addition to Australia’s energy market.

Dylan McConnell, Researcher at the Australian German Climate and Energy College, University of Melbourne

This article was originally published on The Conversation. Read the original article.

Explainer: what can Tesla’s giant South Australian battery achieve?


Ariel Liebman, Monash University and Kaveh Rajab Khalilpour, Monash University

Last Friday, world-famous entrepreneur Elon Musk jetted into Adelaide to kick off Australia’s long-delayed battery revolution.

The Tesla founder joined South Australian Premier Jay Weatherill and the international chief executive of French windfarm developer Neoen, Romain Desrousseaux, to announce what will be the world’s largest battery installation.

The battery tender won by Tesla was a key measure enacted by the South Australian government in response to the statewide blackout in September 2016, together with the construction of a 250 megawatt gas-fired power station.

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The project will incorporate a 100MW peak output battery with 129 megawatt hours of storage alongside Neoen’s Hornsdale windfarm, near Jamestown. When fully charged, we estimate that this will be enough to power 8,000 homes for one full day, or more than 20,000 houses for a few hours at grid failure, but this is not the complete picture.

The battery will support grid stability, rather than simply power homes on its own. It’s the first step towards a future in which renewable energy and storage work together.

How Tesla’s Powerpacks work

Tesla’s Powerpacks are lithium-ion batteries, similar to a laptop or a mobile phone battery.

In a Tesla Powerpack, the base unit is the size of a large thick tray. Around sixteen of these are inserted into a fridge-sized cabinet to make a single Tesla “Powerpack”.

With 210 kilowatt-hour per Tesla Powerpack, the full South Australian installation is estimated to be made up of several hundred units.

To connect the battery to South Australia’s grid, its DC power needs to be converted to AC. This is done using similar inverter technology to that used in rooftop solar panels to connect them to the grid.

A control system will also be needed to dictate the battery’s charging and discharging. This is both for the longevity of battery as well to maximise its economic benefit.

For example, the deeper the regular discharge, the shorter the lifetime of the battery, which has a warranty period of 15 years. To maximise economic benefits, the battery should be charged during low wholesale market price periods and discharged when the price is high, but these times are not easy to predict.

More research is needed into better battery scheduling algorithms that can predict the best charging and discharging times. This work, which we are undertaking at Monash Energy Materials and Systems Institute (MEMSI), is one way to deal with unreliable price forecasts, grid demand and renewable generation uncertainty.

The battery and the windfarm

Tesla’s battery will be built next to the Hornsdale wind farm and will most likely be connected directly to South Australia’s AC transmission grid in parallel to the wind farm.

Its charging and discharging operation will be based on grid stabilisation requirements.

This can happen in several ways. During times with high wind output but low demand, the surplus energy can be stored in the battery instead of overloading the grid or going to waste.

Conversely, at peak demand times with low wind output or a generator failure, stored energy could be dispatched into the grid to meet demand and prevent problems with voltage or frequency. Likewise, when the wind doesn’t blow, the battery could be charged from the grid.

The battery and the grid – will it save us?

In combination with South Australia’s proposed gas station, the battery can help provide stability during extreme events such as a large generator failure or during more common occurrences, such as days with low wind output.

At this scale, it is unlikely to have a large impact on the average consumer power price in South Australia. But it can help reduce the incidence of very high prices during tight supply-demand periods, if managed optimally.

For instance, if a very hot day is forecast during summer, the battery can be fully charged in advance, and then discharged to the grid during that hot afternoon when air conditioning use is high, helping to meet demand and keep wholesale prices stable.

More importantly, Tesla’s battery is likely to be the first of many such storage installations. As more renewables enter the grid, more storage will be needed – otherwise the surplus energy will have to be curtailed to avoid network overloading.

Another storage technology to watch is off-river pumped hydro energy storage (PHES), which we are modelling at the Australia-Indonesia Energy Cluster.

The ConversationThe South Australian Tesla-Neoen announcement is just the beginning. It is the first step of a significant journey towards meeting the Australian Climate Change Authority’s recommendation of zero emissions by at least 2050.

Ariel Liebman, Deputy Director, Monash Energy Materials and Systems Instutute, and Senior Lecturer, Faculty of Information Technology, Monash University and Kaveh Rajab Khalilpour, Senior Research Fellow, Caulfield School of Information Technology, Monash University

This article was originally published on The Conversation. Read the original article.