Energy Source & Distribution looks at the standards and technologies affecting substation design.
The emergence of IEC61850 represents a new phase of consistency in substation design. Leading a call to action is ActewAGL systems control manager, Lucas Milmore. Speaking at Smart Substations 2011, Mr Milmore will discuss the standardisation that the introduction of IEC61850 will bring to the industry, as well as major developments taking place in the US.
“There are a lot of papers primarily coming out of the (US) – they are the ones spearheading smart grid at the present moment – about how they are actually utilising this technology, interfacing with existing practices or with an existing system to increase their reliability across their above networks. So it will be taking a few of those papers and explaining how we can apply it to the Australian market,” he said.
Mr Milmore believes the Australian network holds itself well in the global industry.
“When you look at it across the board, Australia is up in the top three in smart grid implementation. Something we were pioneering 20 years ago that are now en vogue which were normal proactive for us, so in a lot of respects Australia is actually in very advanced in a lot of things, maybe not everything, but it a lot of things we are every advanced comparatively to the rest of the world,” Mr Milmore said.
ActewAGL SCADA engineering manager, Stephen Major agrees with Mr Milmore regarding the need for standardisation.
“We have a standard and that standard will be able to be replicated across our substation network, which will then have multiple advantages going forward,” Mr Major said.
“For us IEC61850 is the way going forward because that standard basically defines a whole new paradigm in the way you engineer your substation going from the actual specification all the way through to the equipment supply and the configuration. So for us, moving forward 61850 is one of the main drivers with high-speed communications and open standards.”
When questioned about the potential capabilities of IEC61850, Mr Major and Mr Milmore respond by asking, “How far do you want to go?”.
“From our old legacy equipment where per data item, we might be talking 10 points, we could be going up to 100, to 1000… they’re completely configurable. So you can determine how much data you want to send back based on your communication infrastructure and that sort of stuff,” Mr Major said.
“Future development and integration of IP technologies and high-speed WANs and high-speed communication networks that allow us to basically fault find, diagnose equipment from the field and office and do more proactive type of work, where at the moment we are pretty reactive in what we do. The amount of data we can ascertain from this sort of equipment will help us to more intelligently model our network and plan and go forward.”
Mr Major said that transmission and distribution utilities worked on substation designs at different rates.
“Transmission (companies) have actually got together quite heavily and actually discussed implementation of 61850 and substations, while a lot of the distributors are still very islanded by ourselves. We do have the ENA who do a lot of work with all the utilities, but we don’t have a large working group like the transmission people do, so it will be very interesting to see how we all stack up against each other,” Mr Major said.
Cost and size have been major factors influencing the difference in uptake between transmitters and distributors.
“A lot of our distribution subs, we don’t even have telemetry in,” Mr Major explains.
“From a cost-benefit analysis it doesn’t really stack up (with) 61850 at this stage, because the equipment is still new and hasn’t been completely standardised and rolled out. When it becomes more of an IP-common product for volume and that kind of stuff it makes it a lot cheaper. At this stage because of the huge engineering changes and the cost of the equipment, it’s like a factor of five more expensive than the equipment we use now. It’s not been a cost-wise way to go.
“But you have also got to look at distribution companies, they normally have a zone transformer area servicing around 10-20,00 customers, while transmission people (have) 100,000, 200,000 maybe 700,000 customers per zone. When you take the cost per customer it’s actually exorbitantly higher for the distribution companies then it is the transmission companies.”
While IEC61850 is a standard originating from Europe, Australia has largely made use of the US-based DMP3 system.
“61850 started out predominantly in Europe – they are a fair way ahead of us – while DMP3 is a US-centric protocol which we have widely adopted here. We’re probably more on the US-base of being predominately DMP3 at the moment,” Mr Major said.
“It also depends on what aspect of 61850 you’re talking about. 61850 has a lot of different components, like high-speed intertrip fuse messaging. Projects in Australia used that 10 years ago but that’s only one per cent of protocols, if you’re talking about a whole 61850 substation then,” he said.
Mr Milmore said it was necessary to look at utilities at different points of time and the different economic and physical drivers underpinning their decisions.
“So we’ll all be sitting at different stages of development with IEC61850 but yes it is… similar to DMP3. They are all international standards that we pick and choose to use when we feel fit,” he said.
ActewAGL is currently rolling out a prototype 61850 distribution substation that encapsulates much of its engineering benefits.
“The core benefit is the paradigm change and the engineering process and utilising automated configuration tools which is what we’re trying to base our whole design on,” Mr Major said.
“From the research we’ve done it would probably be the first in a distribution station context that 61850 has been used. Normally its been ‘dome’ substations and transmission substations. So we’re talking down to a localised area using 61850,” Mr Milmore added.
One of the major challenges in integrating IEC61850 will be the ‘human factor’, according to Mr Milmore.
“Remember, as Steven rightly pointed out, it is a paradigm shift. It’s sort of like going from DOS to Windows. It’s a very massive shift for a lot of people. They’ve got to not only deal with the technology but deal with the fact that their atypical traditional role has now become this different role that they (are not used to), and it’s actually managing a lot of those functions, because it is our people that make us the best companies around,” Mr Milmore said.
“61850 and high-speed communications actually allow us to do a lot of work from the office… but you’ve got to look as we increase our intelligence on our network we can actually monitor a lot more finitely our assets. So we can now, instead of replacing it on a time based, we can actually replace on its actual true life. So there’s multitudes of benefits across all facets of a substation,” he said.
Monitoring substation asset age
ENERGEX network substation standards manager, Jonathan Khor spoke to Energy IQ about his views on smart substations strategies and information.
It pays to be at the forefront of substation technology when you’re a utility, but not too far ahead, according to ENERGEX’s Jonathan Khor.
“Being a utility we seem to want to wait and see what the industry is actually providing. So we certainly would like to be at the leading edge, but certainly not at what we call the ‘bleeding edge’, where we discover faults and problems,” Mr Khor told the organisers of Smart Substations 2011 in February.
As a result, ENERGEX keeps its eye on industry developments where product has been tested in smaller projects, such as mining companies.
“We are looking at them to start off with to see how the product is actually performing in the general industry. Then we look at the general experiences of other utilities who are brave enough to start the process, wait and see whether to ascertain whether it will benefit our organisation in order to reproduce these into our system,” Mr Khor said.
“The issue we’ve got is, certainly, once we introduce something into the system we replicate a lot of the faults as well as the benefits, so we have to be very careful in choosing which technologies we introduce,” he said.
ENERGEX is currently looking to see if its substation switchgear and plant design is the most efficient and cost-effective available. Mr Khor has been involved with substations for six years and heads up the company’s substation design team.
According to Mr Khor, the crux of the matter is condition monitoring and the age of the circuit breakers and plants.
“As you are well aware there’s a myriad of technologies with regard to condition monitoring. So here at ENERGEX we are using the trans enclosure voltage (TEV), partial discharge online monitoring and, certainly, trending. We try to share information with our colleagues from other utilities where we discuss technical and problems that we have with switchgear or plant, learning from each other’s experience. It would certainly be of interest and benefit to the organisations out there to be able to pull information together and really have a bit of a trend line to find out what’s happening with switchgear etc. Age is a problem and certainly that is something we will look at,” he said.
ENERGEX is looking at their fault detection technologies, both inside and outside the substation.
“For outside the substation, we are really looking at distributed supervisory systems, DSS as we call it. To ensure that we have the right number of enclosures in a network, cable fault and line fault indicators, to ensure that we know where they are, and these things need to come back to a central database where we are able to detect which fault power is gone,” he said.
ENERGEX is currently trialing a faster reclosing method. They are attempting to send blocking signals from their downstream reclosers up to the upstream reclosers. They hope to get their upstream reclosers to eventually block their signals from tripping, reduce the fault level or fault clearing time for the reclosers, so they don’t have any grading issues.
“Within the substation itself the main fault that we have is the substation bus faults within the switchgear. The issue that we are grappling at the moment is whether we have one system detection, which is either at the bus only or we have a unitised detection which is covering the bus, the CV area as well the cables,” he said.
Mr Khor said that network planning is a crucial part of the design process, they are looking at the inclusion of fibre optic as a double check for what has traditionally been bus zone protected.
“Being able to load forecast what is coming up, I certainly (think is) key to all this. On the other hand, we are seeing a lot of emerging technologies, such as distributed generation. Even though these could diversify a lot of the loading, we still have the main issue, problem rather, if and when these distributed generators do not produce electricity, the service providers will still have to meet the demand of load,” Mr Khor said.
“So as a result of that we still have to design the network to meet all the demand. Certainly the issues we have at the moment is trying to curtail some of the load, using peak locking and maybe even looking at battery or storage capabilities, using a battery or a statcom for voltage and support. That’s what we try to do,” he said.
ENERGEX is also looking at how they will go about signaling of demand management, whether they use a smart grid system to manage load and the potential use of audio frequency load-shedding devices.