The Tesla big battery may have taken just 10 months from tweet to commissioning, or just 6 weeks from connection agreement to full production, but the going has not been so easy for the state’s second big battery, located to the south on the Yorke Peninsula
The ESCRI project – it stands for Energy Storage for Commercial Renewable Integration – is now more commonly known as the Dalrymple North battery, after the local substation. But it is still incomplete more than a year after financial close, and some five years after it was first mooted.
It appears that the owners and developers recognise that the battery may be trying to bite off more than it can chew, and there are now doubts about whether it will be able to perform all the functions expected of it.
The $30 million Dalrymple battery is a completely different size to the Tesla facility at Hornsdale – 30MW/8MWh compared to 100MW/129MWh.
It is primarily designed for fast-frequency control services to help ease constraints on networks, frequency control, and an ability to “island” the local area and provide power to households and business in case of blackouts elsewhere.
It’s this last component – which is designed to allow the battery to use the neighbouring wind farm, the 91MW Wattle Point facility, and local rooftop solar to keep the lights on if they go out elsewhere – that is causing headaches.
As RenewEconomy reported back in September, the battery took the peninsula off the grid in a trial, but it has not yet been able to do this with the wind farm switched on.
There are now doubts – rated at 50-90 per cent possibility, see table below – that it will not be able to properly integrate the Wattle Point wind farm and provide a seamless transition/operation under islanded conditions.
And a new report rates it “almost certain” that all its project resources may not be available when needed, with impacts for all major project drivers (technical, quality, costs/variations, time/delays, and GPS registration).
Officials, including local transmission operator ElectraNet, have been reluctant to comment on the issues, but the new report – courtesy of the “knowledge sharing” that comes as part of the $12 million of ARENA funding – sheds light on the problems, and gives a “warts-and-all” account of the issues faced, from language problems, to definitions, and technology problems.
Many of the problems – particularly those relating to generating performance standards, network modelling and working with the local network operator and the market operator – will be familiar to those in the solar and wind industries who have struggled with delays and connection problems over the past year.
It states, for instance, difficulties with generator modelling, the generator performance standards and registration delays, which accounted for at least four months of delays and added to costs.
The reasons cited by the report included the new-ness of the technology.
- “Battery technology and the subsequent demonstration of BESS Generator Performance Standards is still new to the industry, including AEMO (Australian Energy Market Operator),” it said.
- “The project contains added complexity over a normal grid-connected asset, as the battery must also show compliance with islanding functionality which is a first within the NEM for battery systems. Requirements for off-grid operation drives some of the requirements for on-grid operation, so the battery must always be ready for off-grid behaviour.”
The FCAS and arbitrage elements appear to have passed muster without issue since its energisation in April and its connection agreement in June.
And as we reported in September, it took the peninsula off the grid in a trial, but it has yet to do so while the neighbouring 91MW Wattle Point wind farm was switched on. According to this report, it is waiting for wind farm owner AGL to install some additional protections to that wind farm.
It is this inability to “integrate the Wattle Point WF so as to provide seamless transition / operation under islanded conditions” that emerges as the main concern, and raises questions about the “ability to provide all services committed to by ElectraNet.”
- The report points to higher than anticipated costs, the risk of lower than expected revenues, and gaps between the EPC contract and the performance guarantees delivered by the supplier. All may arise from this islanding issue.
The report also highlights issues through initial “hold point” testing that failed to meet the generator performance standards imposed by ElectraNet and AEMO. Thus necessitated a further round of parameter changes and associated simulations and review and approval.
Specifically, the issue related around the Samsung battery’s inability to regulate the voltage at the connection point to within 0.5% of its set point, and at dispatch output greater than +24 MW, its inability to regulate the power factor at the connection point to within 0.5% of its set point.
The report further cited different network modelling assumptions by various consultancies, communications issues, problems with some equipment (such as the failure solar circuit breakers to handle battery systems, since addressed) and some plant difficulties.
“The majority of delay in the project has been from difficulties with acceptance of the generator models. Specific lessons learnt include that the contractor should demonstrate model compliance prior to contract awards and the Original Equipment Manufacturer should have a working understanding of the regulatory requirements.”
Many of these will be familiar to the developers and contractors on solar farms that have led to significant delays, and which have had major consequences, including a role in the collapse of RCR Tomlinson, and damages in other projects.
- Other issues include the assumption by AGL that it would be able to benefit from the overload capacity of the BESS, as the requirements for FFR are assessed across the portfolio of a market participant. But it turns out that the Samsung battery cells have no overload capacity, at least not in”real” power.
- It also seems that ElectraNet was caught short by the confusion over the definition of “cycling”, and its impact on availability and degradation, and the need for “resting time”, which meant that the battery might not be available for use as much as assumed by ElectraNet and AGL.
Another problem that emerged was that, once fully charged, the battery could only generate at full output for approximately 15-20 minutes, and AEMO systems were not able to fully integrate the dispatching of such plant at this stage, as 30 minute bids are submitted.
These point to many of the issues that developers of battery storage installations are finding.
The rules often do not allow for the batteries to get paid for their assets, because they are faster, more accurate and more versatile than anything the grid has seen before – the rules either favour slow incumbent technologies (30 minute settlement rule vs the 5 minute rule), or simply don’t allow for the proper pairing with wind and solar farms.
In this case, the report says that AGL is currently developing new bidding software to provide automatic rebidding, which was not available during initial commissioning. A manual work-around was used during commissioning until the final bidding system was complete.
There are a whole bunch of other issues, including the need for up to 1.5MW of load to deal with the air conditioning of the battery sheds, to keep them at the right temperature during maximum charge and discharge.
Still, it says, many of the lessons learned will be of benefit to future battery installations. RenewEconomy sought comment from ElectraNet about the anticipated completion date for the project, but did not get a response.