Utility taps the power of smart metering

Constrained energy capacity, an aging infrastructure and security concerns are driving electric utilities to build a smarter grid -- one with processing power and communications technologies that will enable the utilities to monitor, manage and distribute energy more efficiently.

A key element of the smart grid is the smart meter, which collects detailed information on energy use at individual buildings and has two-way communications with the utility. With smart meters, utilities can monitor how much power a particular house or office is using and, under terms to which customers agree, can throttle power down to certain buildings or even certain systems within buildings at particular times in order to better manage electricity during peak use periods.

Allegheny Power, the distribution unit of Allegheny Energy that delivers electrical service to approximately 1.5 million customers in Maryland, Pennsylvania, Virginia and West Virginia, is launching a smart grid pilot project in May whereby controls for a six-building office park in Morgantown, West Virginia, will be integrated directly into the utility's infrastructure.

In addition to the smart meters, Allegheny is installing new sensors on power lines and integrating old sensors into one network, all of which will feed into Allegheny's overall enterprise network, explains Harley Mayfield, planning engineer at Allegheny Energy.

Unlike traditional meters, which merely count the number of kilowatt hours, these smart meters will track kilowatt hours over time, which will tell the utility when a given building or neighborhood is using a peak amount of electricity or even which systems in a building are using the most power at a particular time.

Combining that information with data on power-line loads and the demands on various other parts of the network accomplishes two goals, Mayfield notes. First, it helps the company manage power distribution in the short-term -- by ratcheting down power to certain nonessential areas at peak times to avoid a brownout, for example. Second, it allows Allegheny to build a database to help it make more intelligent decisions about its distribution system in the long term, he says.

But the utility currently has a mishmash of sensors in the field -- including old analogue sensors that predate the digital age and rudimentary digital sensors that are now years old -- all from different manufacturers and using different protocols. "One of the problems that has plagued us," says Mayfield, "is how to integrate these different sensors to get this information into the system" -- that is, into Allegheny's distribution network.

To solve the problem, Allegheny is using sensor hardware and middleware from Augusta Systems, a maker of enterprise sensor networks. The products work like universal translators for various sensor standards and protocols -- they can convert proprietary protocols to an IP protocol, which in turn enables that information to be fed into an IP-based enterprise network, explains Patrick Esposito, Augusta president and chief operating officer. "For many enterprises, that is a huge problem -- wrestling with all that data and getting the non-IP data onto the IP network," he notes.

Allegheny will use the Augusta Systems products as regional processors in the distribution network around the office complex. These ports will receive data via Wi-Fi from the smart meters and various sensor devices, translate that data into an IP protocol, cull the relevant information and forward it to the mainframe, says Mayfield.

Long term, the system could help Allegheny decide when or whether to increase its distribution capacity, says Mayfield. Today, the utility has only isolated pieces of information -- the condition of a given power line or the fact that a given neighborhood uses a certain amount of power over a six-month period, for example.

The new system will provide more specific information and combine it with other data that gives Allegheny a more accurate and complete picture. "We'll be able to identify the peak load on the substation and whether we need to increase capacity," says Mayfield. "That's data that we don't have right now."