By Betsy Loeff, AMRA
Compared to maintaining non-communicating meters, automatic meter reading (AMR) is quite different for most utilities to manage, especially fixed network systems (advanced metering infrastructures). The technology adds some complexity and skill requirements, but, experts agree, it also adds value in the long run.
“What we’ve done is take a meter design that has been stable for 100 years, and we added a whole new series of failure modes to it,” says John Skog, president of Maintenance & Test Engineering Company. “It’s like the personal computer,” he explains. “Maintenance on a pen and paper was simpler, but you can do so much more when you have a PC.”
And like the PC, AMR requires different skills from its operators and maintenance crew. Following are a few of the issues that crop up when an AMR system goes in.
Wayne Fairchild, special project manager of AMR for PPL Electric Utilities, reports that once his utility began deploying its TWACS system from DCSI Inc. in 2002, the biggest maintenance surprise wasn’t with the AMR units but with other distribution system maintenance problems discovered through the installation process.
“We’ve found wiring and connection problems, some of which affected meter registration and some that did not. But they definitely affected AMR communication,” he said.
Example: “We found things like single-phase services on premises that used to have three-phase service. When the three-phase customer moved out and the single-phase customer moved in, someone just cut two phases instead of rewiring the service properly. The AMR module wouldn’t power up, and we had to put in an adapter base to correctly power up the module and read the meter,” Fairchild said.
“Although we’ve uncovered a lot of situations ignored for years, in some cases, it’s helped us recover revenue,” he added. “We expected to pick up revenue through theft detection, but we’ve found even more lost revenue by correcting installation, metering and billing errors.”
Actually, recovering revenue through AMR’s ability to detect problems and failures isn’t rare. “With AMR, the system tells you when it’s not working, so the impact of failure isn’t as great revenue-wise as it used to be for the utility,” Skog says. “In the past, you found failure two ways: through complaints when the meter data didn’t work in the customer’s favor or by having one of your people stumble across the problem. With AMR, you’ll see failures more quickly and wind up disputing usage mistakes that lasted no more than a few days, not those that happened over months or even years.”
“AMR also gives more information for the people who have to go out in the field and fix the meters,” said John Wambaugh, vice president of operations at eMeter, an AMR back-office software and consulting services provider.
“Without AMR, a meter reader finds a meter not working, then someone goes out in the field without knowing what the problem is. With AMR, the system will tell you if it’s the signal or the meter that’s down. AMR systems have diagnostic or status checking capabilities, so you go out in the field with a better idea of where to start troubleshooting. It lowers the cost of a trouble truck roll.”
And, of course, AMR can replace truck rolls in some instances. “Without AMR, when a customer calls in an outage, you have to dispatch a truck to see what’s wrong,” Wambaugh says. “With two-way AMR, you can try to communicate with the meter, and if the communication goes through, you know there’s power. Then you can walk the customer through checking circuits.”
Wambaugh, who was chief technology officer for Cellnet, recalls that Kansas City Power and Light eliminated 70,000 truck rolls a year with its Cellnet AMR system. That’s one place where utilities can cut labor with AMR. But like computers or other technology, AMR requires the addition of skill sets and people to support it.
Dealing with Data
“The biggest maintenance issue with AMR is database maintenance,” Skog says. He has been involved in maintenance issues with several projects, including the 1.5 million-endpoint AMR system deployed at Puget Sound Energy. “Most of the time, you’re not just dealing with one system at the utility. You’ve got billing, CIS, work order systems and more all tied together with data fields, and if you get them out of sync, the data stops flowing,” Skog says.
To elaborate on this, Wambaugh says that utilities have always had data maintenance and synchronization issues. With AMR, it becomes more of an issue because of the amount of data, the frequency of data collection and the many other systems that are relying on the data. For example, in non-AMR, the meter reads are used just for billing. With AMR, data is used for billing, but information from the AMR system also is used for troubleshooting/meter maintenance, outage, distribution planning, etc.
To ensure data reliability, Puget Sound Energy installed a system that automatically validates data every day though a variety of integrity tests.
“Out of 1.5 million reads that come in, there might be as many as 50 a day that get flagged for investigation. Many of these exceptions can be resolved automatically, but sometimes, the integrity tests are signaling the first signs of equipment failure,” Skog says.
Ready for Anything
Equipment failure happens with and without AMR. But as Wambaugh notes, “With AMR, you have more equipment, so you have more failure.” As an example, he points to a typical pole-top data concentrator that eventually will transmit data back to a utility in a fixed-network system. “A typical concentrator has four main components,” he explains. “There’s a LAN transceiver, a WAN modem, a CPU and a battery or power supply. You can expect around 5 percent of devices to have some kind of failure.”
Although a much smaller percentage of AMR transmission modules fail—less than a percent, says Wambaugh—it still happens. To deal with the added equipment, PPL introduced tracking procedures on the AMR modules as well as the meters.
“Polyphase meters are expensive, so we don’t want to throw them out,” Fairchild says. “We made the decision up front that if we divorced a meter from its AMR module, we’d need to track both devices separately.” The utility does that through bar codes associated with every piece of equipment that comes in its meter shop.
Other items susceptible to failure are antennas. “If you have a radio frequency system, you will probably have an antenna, and those need to be checked every five years or so,” Wambaugh says. “They deteriorate over time.”
Then there are the poles themselves. “Every electrical utility has pole churn,” Wambaugh says. “Every year some of the distribution poles are replaced, and if they have concentrators on them, the devices will need to be moved.”
Which brings up another maintenance issue: Whose job is it, anyway?
“Before AMR, utilities have clear lines between the responsibilities of the meter shop and line crew. With AMR, suddenly there is metering equipment atop poles, so you wonder which department owns it?” Wambaugh says. “It may have telecommunications equipment in it, so is it part of the telecommunications group? There’s a computer involved, so should it be managed by the IT department? Or because everything relates to metering, is it still owned by the meter shop?”
And that brings us to another maintenance issue of AMR: It requires an all-new set of skills among meter shop crew and other utility employees.
Time for Training
“When you put in AMR, you no longer have people managing routes and readers,” Wambaugh says. “They’re managing data. They have to watch it every day, investigate problems and make sure the data gets to the applications that need it.”
Wambaugh points out that AMR turns data collection into a 24/7 operation in some instances. “The only group accustomed to that in a utility is the SCADA group. For the AMR team, learning round-the-clock maintenance is a new skill set to develop.”
Many utilities also increase their communications expertise with new people or new training. “Before AMR, all the test shop gets in is meters,” Wambaugh explains. “They calibrate them, rebuild them. Now there is a communication module too, so the team needs communications technologies. And when the shop re-zeros the meter, they have to re-zero the transmission module, as well. And they need to add testing facilities for that transmission module. Often, utilities don’t think of this in their business cases.”
Plus, AMR requires know-how in networking, data management and interface applications such as billing and CIS. That means AMR requires system specialists who can see the big picture as well as troubleshoot metering glitches. “Someone has to fully understand the AMR technology the utility is starting to use,” Wambaugh says. “This isn’t a set of responsibilities you just throw on someone’s plate.”
Editor’s note: This article originally appeared in AMRA News, a publication of AMRA. For more information about the nonprofit association, which provides information critical to the understanding and application of utility automation technologies, visit www.amra-intl.org. Betsy Loeff is a news writer for the Automatic Meter Reading Association.