AS/NZS 4777.1 is the primary standard relating to the safety and installation of grid-connected PV systems with or without storage – and it’s changing. Australian Solar Council vice president Glen Morris spoke to Jacob Harris to explain how.

AS/NZS 4777.1 was last updated in August 2013. It went to public comment at the time but was held back from publication until the current AS/NZS 4777.2, which addresses inverter requirements, was published. As Glen Morris puts it, ‘it was a chicken and egg type scenario.’

Glen, who is a member of a number of key industry advisory and regulatory committees including EL-42 (the committee responsible for maintaining the Australian Standards for PV design and installation) explains that part two is the more controversial of the Standards because it deals with inverter requirements. Because the requirements directly affect utility networks, all utilities needed to agree on the update before it could be published.

“We very nearly had the project cancelled on us because it came up to within five years of when it was started and that’s the limit Standards Australia has set for projects – so we had to really put our heads down and only got it finished with a few weeks to go,” says Glen.

Part two has now been published and will come into effect on 10 October this year. This will have some fairly pronounced ramifications, most notably that many existing inverters will no longer be compliant.

“The inverter requirements for compliance to the International Electrotechnical Commission (IEC) standards, and other mandatory features that are specified in 4777.2, will change when the new standard comes into force. So you wouldn’t want to stock up on inverters on 9 October, you’d probably find that half of them fall off the Clean Energy Council (CEC) list. Most of the specified features are things that make inverters more network friendly. This means more solar can be installed with be less objections based on the size of systems,” says Glen.

Now that part two is out, part one is expected to be published later this year. The process is taking longer than usual because it’s a joint standard – not just an Australian standard – and as such must undergo a formal process at the New Zealand end that can take a few months.

When the new standard comes into force, it’ll bring with it some significant changes that contractors will have to adopt into their business models. These will include new signage requirements and also a lot of changes relating to hybrid or multi-mode inverters.

“Essential circuits supplied independently in standalone mode will have to be connected to a dedicated switchboard – not a sub-set of a grid switchboard. So that will make things a bit more complicated in small installations where the customer has got a switchboard in their hallway, for example, and they want a hybrid system installed. In this situation the contractor is going to have to explain that the customer needs to put another switchboard in as well,” says Glen.

Phase balancing requirements is another area that has been updated, stipulating that generation over 5kVA must be across three phases – meaning the end of 10kVA systems on single phase supplies.

“We are updating the anti-islanding set point to be more gradual. At the moment the passive anti-islanding features are very crude tools. To counter this, we’ve allowed for a rate of change over time for voltage and for frequency to smooth out and randomise the effects of passive anti-islanding,” says Glen.

In an effort to facilitate smart grid functionality, the update also makes new provisions for demand response modes. Smart grid is about the grid acting as an autonomous system without the need for lots of individual controls and demand response modes are a step towards that goal.

To comply with the new Standard, all inverters must have demand response modes available and installers will be required to mark on the side of the inverter which modes have been enabled.

Demand response modes are already widely available in a lot of appliances but can also be used for generation systems. For instance, a utility could send out a signal either because of power quality, cost or an agreement with the customer to reduce their generation by a nominated percentage or disconnect from the grid for a period of time.

The signals may be communicated via an old fashioned ripple control but, according to Glen, are more likely to be sent via a dedicated link such as 3G to the installation or some form of aggregation by the utilities over pole top communication systems. They will be used when there’s excess generation on the network but also to export energy from customers back onto the grid.

“At the moment we’re all about stopping excess generation but there may be times when grid support modes are needed. At these times utilities can request energy from customers who have the facility and have agreed to allow their energy to be exported on demand – this will tie in with some sort of financial benefit to the customer.”

Voltage rise and voltage drop calculations for grid connected systems as part of the application process have also been addressed in the updated standard. NSW utilities adopted the AS/NZS 4777.1 draft recommendations in back in August 2013 and the utilities in other states and territories will no doubt adopt them as soon as it’s published.

“You’ll have to keep voltage rise below 1% per network segment – so 1% from the inverter output to the switchboard and then 1% from the switchboard to the point of common coupling which is usually the service mains arm of the building. This is hard to do on rural properties that often have 16mm mains coming in and long AC supplies from the switchboard to where the house is and where the solar is likely to be installed – in this kind of scenario it’ll be well over 1% over 20m-30m. That calculation not only needs to be done but needs to be complied with as a 2% overall rule will come into force with the publication of AS/NZS 4777.1.”