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Most people look for their electric meters on the side of the house or, in some communities, attached to the wall in the garage or basement. But increasingly, meters are cropping up in a variety of new venues, and they’re measuring much more than how many electrons zip over power lines to energize customer premises.

Now that utilities aren’t necessarily the only providers of energy on those lines, there’s more need to monitor electric system characteristics. Data collected from points across the grid supports system planning, maintenance, power factor optimization, reliability and more. Because meters increasingly are used to collect and monitor data related to all those operational tasks, there are many new places metrology is likely to crop up.

On the roof

“I think you’ll see a convergence of meters and smart inverters,” says Randy Edwards, director of product management for Landis+Gyr endpoint solutions. “Right now, the meters and chargers are two separate boxes. One feeds into the other,” he explains, adding that integrating the two functions into one device makes for a lower-cost installation.

Why would you need meters on smart inverters? Well, for one thing, those inverters are smart enough to see voltage and frequency issues on the grid. And, because they’re equipped with communications technology, they can be controlled by utilities for the greater good of the grid. Edwards calls devices with metrology, intelligence and control functions “combined operational meters,” and there are a variety of functions they can serve.

Right now, Landis+Gyr distribution automation devices are helping Arizona Public Service (APS) leverage smart inverters for volt/VAR support on the distribution system. APS has 1,670 households subscribed in its Solar Partner Program, which will give residential customers a $30 credit each month for the next 20 years in exchange for letting the utility control those rooftop PV systems.

The program is still partially a research project, which APS is conducting with help from the Electric Power Research Institute. Among other things, the two organizations are looking at how inverters can help utilities manage voltage and improve power factor to reduce system losses. “Over their mesh network, APS can download a voltage curve to the smart meter connected to the PV panels, and that smart inverter would be instructed to manage output or solar within a range on that voltage curve,” explains Kent Hedrick, director of Landis+Gyr grid management solutions.

He also foresees a day when controlling solar on the distribution grid will help utilities with outage restoration. “Backed by advanced analytics, there may come a time when utilities will be able to see how much distributed energy is in an outage area and do switching of circuits, such that operators could support a certain level of affected customers with local distributed energy resources (DERs) while repairing the circuit where the fault was.”

And, of course, putting meters on a solar array will also help keep things fair and accurate when utilities pay customers who feed energy back onto the grid. “If you want to compensate a customer for self-generation, you want to have direct measurement of that self-generation, i.e., the solar panel,” Hedrick says.

In the garage

Edwards says we can expect to see meters associated with electric vehicles (EVs), too. They’ll be integrated with chargers. Load control switches may be part of the package as well.

“If a utility has a new charging rate that gives customers lower costs per kilowatt-hour when consumers charge their EVs during certain hours, a load control device could schedule the time during which that charger would be enabled,” Hedrick says.

The control functions also could help utilities and their customers manage demand charges if such rates become commonplace. As Hedrick points out, some utilities seeing heavy proliferation of DERs are starting to ask regulators to impose demand charges on customers with solar arrays to offset the cost of distribution-system investments needed to back that solar power up.

“Suppose a customer with rooftop solar has a demand rate in addition to their energy rate,” he continues, adding that customers could choose a level over which they don’t want demand to spike to avoid higher billing rates. “The meter could watch demand for that consumer and even forecast out 30 minutes. Based on what it’s seeing, it could use peer-to-peer communications to control switches and shed load.” In other words, it could shut down the charger … or the air conditioner … or the pool pump … or any other device in an order specified by the consumer. “The meter will be able to do what’s necessary to maintain the demand threshold set by the customer,” Hedrick says.

At substations and transformers

Collecting money isn’t the only reason utilities are putting more meters out on their systems. Non-billing meters used as sensors are starting to proliferate.

For example, Alliant Energy and AEP are both using commercial meters with voltage and frequency-sensing capabilities at substations as stand-ins for system sensors. “Utilities really want to avoid overloading at a substation that could drive the need to expand substation capacity or transmission, as well as feeder upgrades,” says Hendrick. “When the utilities better understand loading, they can use proactive ways to manage peak conditions or imbalances and void costly capital expenditures.”

AEP is also using commercial meters on certain neighborhood transformers. The units identify localized voltage and loading problems so that the utility can take action by adding voltage-management devices, implementing load-shedding programs or taking other appropriate steps.

Another place where utilities are using non-billing meters is at capacitor banks, where meters can monitor device health and operations. “Typically, utilities inspect capacitor banks manually once a year. With meters, they can eliminate this inspection and still find issues, like a blown fuse,” Hedrick. explains. “With manual inspections only, the capacitor bank could have failed several months before an inspector finds the issue and calls in to get it repaired.”

On the line

Though not precisely a meter, an oscilloscope is a form of meter that directly measures waveforms and currents. The Landis+Gyr S610 line sensor contains an oscilloscope that takes 130 samples per waveform cycle, or 7,800 measurements per second. That means it can detect harmonics, which are distortions of the current waveform that can cause drastic overheating and voltage drop capable of damaging large substation transformers. Harmonics are a growing problem for utilities because customer-sited solar power can create them, Hedrick notes.

“This type of sensing can help a utility much more accurately find where a fault has occurred,” he adds. This is because faults create high current. Imagine a line downed by a falling tree limb. It creates a new pathway from the line to the ground with very little resistance and, consequently, very high current flow. When utility equipment senses that current flow, it trips off, creating an outage.

By feeding the oscilloscopic measurements into utility impedance models, system operators can determine how far from the sensor the fault is and send crews directly to the problem. “What improves is the time it takes for a utility to pinpoint where the fault occurred,” Hedrick says. “Without this, you may have a patrol person riding the line for 30 minutes to an hour looking for the fault.”

Even better than fixing an outage is preventing one, and Hedrick says oscilloscopic sensors help there, too. That’s because each type of fault has its own signature waveform, whether it’s a tree hitting a line, an animal scampering onto the system or wind causing phase-to-phase momentary outages as the A-phase line blows into the B- or C-phase line. By tracking such momentaries and their waveforms, utilities can proactively dispatch tree trimmers or take measures to keep the phases apart.

Not only will utilities save on restoration costs, they’ll also be able to raise reliability, maximizing the electrons flowing through the revenue meters on the wall at a customer’s premises.