Do you know who made that Big Mac you just sunk your teeth into? Can you call them by name, or are you among the millions and millions of Americans served who’ve never even contemplated the McDonald’s process?
It’s almost magical: you talk into the plastic screen, you drive forward and the specific “no onions/extra sauce” burger you requested simply appears–wrapped and ready for consumption. At Edison Electric Institute’s “Electricity: the New Millenium” conference in late June, Fred Wiersema, co-author of The Discipline of Market Leaders and author of Customer Intimacy, revealed that our love of McDonald’s is, at least partially, rooted in its ability to fade into the background–to be familiar but not obvious. (He also linked flourishing electricity companies to this ability to be neither seen nor heard.)
The same could be said for distribution automation (DA): it works best when we notice it least. When the customer turns on the light and nothing surprising happens–it simply brightens the room–DA has done its job: smoothing the conduction of electricity from production to end-user. In other words, all the potholes have been found and filled–even before the car begins the drive.
DA encompasses a handful of different monitoring and controlling software and equipment that allows a company to oversee the grid from a Zeus-on-the-mountaintop perspective. Capacitor and recloser/switch automation, along with line voltage and current monitoring are the basics of DA, but DA also includes outage notification and equipment monitoring–allowing Zeus even more free time to devote to other industry areas.
“Distribution automation can enable utilities to automatically optimize the real time operation of the electricity delivery system and flag equipment or conditions which threaten the economy or reliability of that system,” stated Mike Cannon, manager of Cannon Technologies’ substation automation division.
He listed the number of DA capabilities offered by Cannon and others, which includes real time load monitoring (with integrated load management and distributed generation control), power capacitor control and monitoring, substation equipment condition and performance monitoring, and distribution feeder sectionalizing and performance monitoring. Cannon stated that those expanded capabilities came from advancements in software, hardware, communications and the Internet.
“Such capabilities will be needed by utilities operating in a competitive environment, managing loads with less available generation reserve,” he said.
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Innovations in DA continue to refine the process: detecting those potholes quicker, filling them faster. Utilities strive to deliver that perfect package of electricity, so DA software/hardware seems to upgrade by the millisecond in response.
Gary Moore of GE Harris Energy Control Systems Canada sees intelligent fault location as the cutting edge in DA. “This enables the system operator to quickly dispatch appropriate crews to the exact fault location to repair the faulted feeder, minimizing customer interruption minutes,” he commented. With growing concern about blackouts and brownouts, cutting off such a system drain at the proverbial pass may give DA a white hat to wear in the utility arena.
“This type of system does not require the expense of a multitude of feeder monitoring devices or outage detection devices in a customer’s home,” Moore added. “Instead it utilizes data mining methodologies to determine the ‘signature’ of a distribution network and build rules to determine fault location based upon geographical topology of the network and the real time load information–somewhat like real-time asset management.
Of course, reclosers, sectionalizing switches and feeder RTUs will help in reducing the number of customers affected by a feeder fault or interruption, but it is only intelligent fault location that pinpoints the exact location of faults in a complex interconnected distribution network,” he commented.
Amir Khalessi, vice president and general manager of the distribution information systems division of ABB’s automation group agreed with Moore that the cutting edge of DA lies in intelligent electronic devices (IEDs). He cited an increase in concern for the customer as one of the main reasons for this push–along with efficiency in the workplace. Khalessi listed areas that are traditional problems for DA, including costs (of RTUs, field electronics and communications) and “limited computing power,” but stated that new technology has erased these restrictions.
“With the new generation of IEDs, an abundance of wireless communications infrastructure, and the availability of faster and larger computers, the traditional barriers for distribution automation have been eliminated and we are now able to witness a fairly rapid breakthrough in the area,” Khalessi commented.
Ed Cannon, president of Cannon Technologies, expanded further by stating that “many utilities are utilizing 900 MHz FLEX paging for load control, genset and capacitor bank control. The signal propagation is better than other radio technologies, the cost is low and coverage is widespread. The utility can deploy one unit or several thousand and not have to build any infrastructure.” He added that Cannon offers control from their secured website, making the purchase and maintenance of a master station unnecessary.
Vice president Joel Cannon wrapped up the issue by focusing on “maximizing the physical plant without compromising it,” which will involve load shedding.
“Since distribution automation and load shedding involves a widely scattered set of components, we believe that low cost communication is the key to a successful program–products that use industry-standard, alpha-numeric paging for basic switching of utility owned and commercial or residential customer premise equipment,” he said.
Jack McCall, director of protective relays at Cooper Power, on the other hand, views UCA 2.0/MMS communication protocol with generic object oriented substation equipment (GOOSE) messaging as the future of DA, which “allows for hundreds of virtual contact interconnections between devices on the network.” Merely defined by the UCA specification, GOOSE messaging can exist separately from this protocol. (UCA and GOOSE are open architecture and not proprietary.)
“A user could be running a traditional protocol, such as DNP 3.0, from one IED communication port and GOOSE out of another,” he said, adding that this would let utilities implement GOOSE without discarding its predecessor.
“Only a few products are currently available that implement GOOSE messaging, but many more are in development. This should be widely available in the next two to three years,” McCall finished.