Public Power Magazine

Aging Infrastructure: A Smart Grid Progress Report

From the January-February 2013 issue (Vol. 71, No. 1) of Public Power

Originally published November 26, 2012

By Alice Clamp
November 26, 2012

Aging is inevitable, and the nation’s electricity grid is no exception. So how is that grid holding up?

Pretty well, according to Allan Long, manager of regulatory compliance at Memphis Light, Gas & Water. Long, who also serves as the project manager for MLG&W’s smart grid investment project, said the U.S. utility infrastructure is a “testament to those who designed it—and their dedication to the system’s reliability.”

But, he added, there comes a time when utilities must take advantage of new technologies—not just to maintain the grid, but to maximize its performance.

That’s where smart grid technology comes in. It’s a network of computer-controlled systems that can talk to each other, providing a tremendous amount of information about the grid’s operation.

“It’s all about data,” said Mike Hyland, senior vice president of engineering services at the American Public Power Association. 

That data is collected by various types of two-way communication devices—from smart meters to smart switches. And utilities are using the data to help maintain their infrastructure and enhance its performance.

Enhancing grid performance--As the grid ages, it’s imperative that utilities use smart grid technology to develop a better understanding of their assets, said Mark McGranaghan, vice president for power delivery and utilization at the Electric Power Research Institute. “One example is using smart meter data to indicate overloading on transformers, rather than waiting until they fail.”

Every utility knows how much power is leaving a substation, said MLG&W’s Long. “But without distribution automation, we don’t know what happens after that. We can make assumptions during annual load flow studies, but have little information on the distribution system’s real-time performance. Were we close to the limit? Did we have excess capacity? Or were there incipient problems? We have to wait for a problem to occur.”

But with its new smart grid project, the utility will know how every transformer in the system is performing, said Long. “We’ll have the information we need to do real-time distribution load-flow studies and do a better job of designing future improvements to the system.”

EPB, the city-owned utility in Chattanooga, Tenn., has installed 1,200 sensors on its distribution system that send data to the utility’s supervisory control land data acquisition system. “The data are pulled every four seconds, so our system operators have access to a real-time trending view of loading on the circuits at various points along the line,” said Jim Glass, EPB’s manager of smart grid development.

As part of its smart grid project, the Leesburg Electric Department in Florida is installing sensors on a main feeder line and two of its branches, said Paul Kalv, the department’s director and the city’s chief smart grid systems architect. “We know the total feeder load, but we don’t know what’s going down the two branches,” he said. “With the sensors, we’ll know.”

The Sacramento Municipal Utility District in California is working to use the data from customers’ smart meters to assess loads on its distribution lines, said Lora Anguay, senior project manager for the utility’s automation project. “With this data, our system maintenance group can determine if there are overloads on the system. We’re planning to create heat maps to identify issues.” Preventing overloading can extend asset life, she added.

Groton Electric Department in Massachusetts is using a couple of smart grid technology applications to improve system reliability, said Kevin Kelly, the department’s manager. Groton used the data on its transformers to identify those that were most heavily loaded. “We upsized those transformers, and during the hottest peak of the summer, we had only one callout because of an overloaded transformer. That’s because we didn’t have the correct data.”

Next, the department looked at its underloaded transformers. “We found a lot that never hit 10 percent of load,” said Kelly. “We had no idea they were so severely underloaded.” Many of those transformers served senior housing projects. “By downsizing these transformers, we can save a great deal of money over time.”

Isolating faults--EPB is installing automated switches with sensors that will detect a fault of a certain magnitude and activate an open/close sequence of feeder switches. “It’s a fascinating technology using what’s called communication-enhanced coordination,” said the utility’s Glass. EPB’s fiber optic system enables the switches to communicate with each other rapidly.

SMUD, too, is installing sensor-activated automated switches on its distribution lines. “A switch can isolate a fault down to a small number of customers,” said Anguay, the senior project manager for the utility’s distribution automation project. “The switches will work in conjunction with breakers. One switch or breaker will detect the fault and the one closest to the fault will open, isolating it.”

Load information collected from the field devices minutes prior to the fault will be used to determine if sections of the line can be restored through additional switching.  Restoration of these sections will be automated and occur in less than one minute.

Without such automation, SMUD would send a troubleshooter into the field to figure out the location of the fault and manually isolate it and perform manual switching to restore sections of the line, said Anguay. “Now, fault isolation will take just a few minutes.”

MLG&W has a different issue on its distribution lines: water. “Our system is almost totally underground, so we need sensors to monitor the intrusion of water into equipment and into vaults,” said Long. “We can now sense environmental factors that we never could sense before, and dispatch crews to address them.”

The Leesburg Electric Department plans to install pad-mounted reclosers at strategic locations along four feeder lines from one of its  substations, said Kalv. “We are configuring the system so that reclosers will automatically operate to isolate an anomaly on any one of the lines—and reconfigure and restore service even if the whole line is out.”

Controlling voltage--A typical approach to upgrading a geographic area is to reconductor, said Leesburg’s Kalv. But that may not be the most cost-effective approach. “With smart meters, we can get voltage readings from every home and business,” he said. “We were amazed at the voltage variability.” This information may point to less expensive, more effective methods of providing for growth, he said.

If the data indicate that the conductor size is okay but there are wide swings in the voltage, the answer may be capacitor banks, said Kalv. “They will improve the power factor and gain additional real current as opposed to reactive current.”

EPB is installing voltage regulators and additional capacitor banks to improve voltage on its system, said Glass. Voltage is higher at the substation, dropping as the line goes farther from the station. “The regulators and capacitors will allow us to flatten the voltage profile, delivering more consistent voltage to all customer delivery points.”

SMUD is using smart grid technology to implement conservation voltage reduction (CVR) and volt/var optimization (VVO), said Anguay. “These control strategies work together. VVO controls the substation and line capacitor banks, improving efficiency, monitoring reactive demand and reducing losses on the system.”

CVR allows the utility to reduce the substation voltage output from its operations center, said Anguay. “Typically, we want the voltage to be at the high end at the substation so it’s still within the bandwidth at the end of the line.” Although CVR can reduce utility revenues, it also reduces stress on the system. “It’s important for us as a municipal utility to be as efficient and cost-effective as possible,” she said

SMUD implemented the CVR and VVO programs at two substations and associated circuits last summer. “We tested a 2 percent voltage reduction using CVR.”  SMUD’s CVR/VVO program is being implemented at 40 distribution substations and associated feeders by April 2013, which is roughly 18% of their distribution system.  The VVO program is expected to reduce peak losses by 6.1 MW or 1,150 MWh annually. While CVR is expected to yield 10.4MW energy savings at peak and 36,520MWh per year.

Not without a plan--Every utility should have a strategic plan for implementing smart grid technology on its system, said MLG&W’s Long. “That plan can be implemented incrementally.”

Long suggests designing the system and then installing components as the budget permits. “Good planning doesn’t cost any more than bad planning.”

It’s important to look at what you want to do down the road, said EPRI’s McGranaghan. “Infrastructure investments now can be used for smart grid applications in the future.”

Some utilities will sit back, said APPA’s Hyland. “And sometimes, that’s prudent.” He cites the example of AMR—automated meter reading—systems. “A lot of utilities jumped on the AMR bandwagon.” Now, the move is to AMI systems—smart meters. Meanwhile, smart grid technology continues to evolve. And, he said, price points are coming down.

EPRI’s McGranaghan agreed that it makes sense for smaller utilities to wait, letting other utilities lay the groundwork and taking advantage of cost reductions.

For many utilities, the first step is installing smart meters, said Leesburg’s Kalv. “The demand charge on our wholesale power supply bill was escalating, and we wanted to engage our customers in reducing demand during our coincident peak period.”

But, he noted, a utility can start with a device other than the smart meter. “Each utility needs to determine what’s most important to it. If the biggest problem is wholesale power supply cost, then smart meters are the first solution.”

A number of public power utilities received smart grid grants from the U.S. Department of Energy. But what about those utilities that didn’t? Their smart grid plan probably won’t change, but the timeline will.

“Had we not received a DOE grant, we would have implemented our plan more slowly and over a longer period of time,” said Jay Anderson, general manager of Marblehead Municipal Light in Massachusetts.

“But sometimes, ramping things up—as required by the grant—can come with a whole new set of logistical problems,” he added. “We wondered if our equipment order was so small that it would fall behind other, larger orders.”

Leesburg’s Kalv acknowledged that it can be more difficult for municipal utilities to concentrate on system improvements, especially when those improvements involve large and expensive pieces of equipment.

That’s why utilities should do a cost/benefit analysis to identify savings. “There are ways to justify these expenses,” said SMUD’s Anguay.

A cost/benefit analysis works best when a utility considers applications—which can involve a wide range of components—rather than looking at one set of devices, such as smart meters, said EPRI’s McGranaghan. “Automated fault location, for instance, involves an AMI system, sensors, a communications infrastructure, a geographic information system and electrical models. You need to tie those together to make the application work.”

Some investments provide reliability benefits early on, said McGranaghan. An example is conservation voltage reduction—CVR—which involves small additional investments for capacitors and voltage regulators.

For those utilities that need help in funding their smart grid plan, there are some financing vehicles available, said Marblehead’s Anderson. A regional joint purchasing program, perhaps through a joint action agency, is one option. Another is a bond issue.

The Leesburg Electric Department was awarded a DOE grant, but it also applied to the state of Florida for a block grant, which it received. “It was a window of opportunity that will never occur again,” said Kalv.

Smaller utilities should look first at integrating all their databases, said Groton’s Kelly. “You need one unique field that is common to all databases. If you don’t have a common field, you can’t connect GIS—geographic information system—data to smart meter data.”

Groton did everything—smart meters, GIS, outage management—for less than $120 per customer, said Kelly. The utility has approximately 4,000 customers. “You don’t have to spend a lot of money,” he said. “You don’t have to be totally cutting edge. It’s cheaper if you’re one year behind the curve.”

MLG&W’s Long would like to see an ongoing support group that includes utilities at the forefront in deploying smart grid technology and those at the tail end. Networking among APPA members is essential, he said. “There’s no book, no school, no set of standards to refer to. We need to talk with other utilities, find out what they’re doing, keep the dialog going.”

Benefits--“Smart grid technology gives us the ability to delve more deeply into what’s going on in our system in real time,” said Marblehead’s Anderson.

And that understanding offers concrete benefits. EPB’s Glass said the utility has already seen a 30 percent improvement in reliability because of automation. “And when all the smart grid equipment is installed, we conservatively expect to see more than a 40 percent improvement.”

But there’s another benefit, too, said Glass. “From the public power standpoint, our motivation isn’t a financial return on investment,” he said. “It’s about the direct impact on the community. We’re improving service for our customers.”

One of the big issues that utilities will face is what to do with all the data, said EPRI’s McGranaghan. “When it comes to the future data analytics potential, neither utilities nor customers have scratched the surface of that data’s value in managing an aging infrastructure.”

“Reliability is clearly one of the key objectives of smart grid technology,” he said. But it’s the communications infrastructure that has the potential to take reliability a step further.

Many of the innovative applications that we will see haven’t even been thought of yet, said McGranaghan. One possibility: customers will send videos or texts to social media on the condition of the power system. Those feeds could be integrated with smart meters and the outage management system, he said.

The challenge for utilities will be pulling all of this information together. “Integration requirements are at the top of the list of smart grid functions.”


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