By Betsy Loeff, AMRA News Writer
According to Kevin Cornish, director of utility solutions for Distribution Control Systems Inc., monthly usage data is almost irrelevant for designing a distribution system. “The monthly consumption figure a utility sees may have climbed steadily, or the usage might have occurred between 4 p.m. and 8 p.m. each day,” Cornish said. “With monthly data, you just don’t know.”
Cornish also noted that the historical practice of using monthly consumption data and demand profiles based on customer classes lacks the accuracy and flexibility desired in today’s climate of reduced capital expenditures.
Using monthly consumption data, the process of sizing transformers or placing capacitors-in fact any distribution system planning task-has an element of guesswork included with the analytic tools and engineering. But it doesn’t have to. Electric utilities with fixed network AMR systems can use frequent interval data to monitor distribution system assets, plan investments and more. Read on to see how some utilities gain by using detailed metering data-not assumptions-for engineering analysis.
Although load studies enable engineers to make assumptions about usage patterns, Cornish points out that many utilities are using studies that are 20 years old or older. Have consumption patterns remained constant over the past 20 years? Probably not.
For instance, most areas across the United States have seen a dramatic increase in the usage of residential air conditioners during the past 30 years. According to the Department of Energy, the percentage of U.S. housing with central air conditioning jumped from 23 percent in 1978 to 47 percent in 1997. In the Northeast, more than 41 percent of housing units had window air conditioners. That could certainly put a spike in a utility’s load profile. Worse, air conditioner motors affect system power factors.
“Old assumptions and models are becoming a real issue in places like New York,” said Chris King, chief strategy officer at eMeter, a company that creates meter data management software.
“Now that people can buy a window air conditioner for less than $100, more apartment dwellers are buying them,” King said. “These air conditioners are very “Ëœpeaky.’ They only get used a few weeks a year, and they’re only used for a few hours, and of course, they’re all used at the same time.”
King adds that air conditioner motors create reactive power, which further increases the amount of power utilities must generate.
“Substations, transformers, taps, fuses-for most utilities today, all the aspects of the electric system are sized based on assumed load,” Cornish said. “If you know what actual coincident load is, you can do a better job of sizing and locating equipment.”
King also noted that utilities with detailed metering data don’t need as large a reserve margin in distribution system planning. He is familiar with one Northwest utility that shaved 40 percent off its next year’s budget for distribution assets because accurate load data allowed the organization to defer purchases. On an ongoing basis, the utility estimated it could save up to 13 percent over investments made before it had advanced metering data.
Locating Assets and Load Balancing
John Bruns, manager of engineering and technology at White River Electric Cooperative in Branson, Mo., relies on data from his TWACS by DCSI metering system to see where loads actually occur on feeder lines. “Let’s say I have a feeder that goes 10 miles out of a substation,” he said. “I want to know exactly where its load is. Is it in the first couple of miles? At the end of the line? Once I know where the load occurs, I can put regulators and capacitors in the proper place. That cuts down on quality problems and line loss.”
Bruns also uses his AMR data for load balancing because the system delivers data on true phasing at each meter site. “We can go through and balance loads on A, B and C phases easily,” he said. “We know exactly which customers we need to move from one phase to another.” This, too, cuts the utility’s line loss.
Capacitor Bank Switching
As load climbs, voltage generally decreases, and utilities boost it via capacitors. “You want capacitors on mainly during peak hours,” King said. “Otherwise, they’re sucking energy out of the system unnecessarily.” Without communication to control capacitors, utilities must use thermostats or time clocks. “Time clocks get out of sync over the years, turning on and off at the wrong time. Plus, they over compensate,” King said. Thermostats can be problematic as well.
During the early to mid 1990s, Kansas City Power & Light replaced thermostat controls on 800 capacitors with intelligent electronic devices (IEDs) equipped with two-way radios that the utility can control via its CellNet AMR system. The result? Significant savings accrue from deferred investments, more effective equipment location, reduced line losses and eliminated maintenance tasks.
Although Puget Sound Energy (PSE) is just now gearing up to do load analysis with AMR data from the 1.6 million meters it reads with a Cellnet system, the utility is finding other operations perks. One is ad hoc research.
“We’ve done transformer load research for claims,” said PSE’s John McClaine, manager of metering network services. As an example, he cited a housing development where all the newly built homes were supposed to have gas heat, so the utility put in 50-kW transformers to serve the expected load of homes that didn’t rely on electricity for heating. During construction of the new development, an overburdened transformer blew.
“The developer brought in a bunch of electric heaters while drywall was being installed in houses,” McClaine said. “Then when we tried to charge the developer for the transformer, they said we’d undersized it. We hadn’t. It was sized for what the developer said the load would be.” Meter data showed the load exceeded expectations-and capacity.
McClaine also uses AMR data to find possible tree-trimming troubles. His system sends last gasp transmissions from each meter when the meter loses power. With radio signals stepping on each other, only about 7 percent of those transmissions get through in a widespread outage. But almost all the power-up transmissions the meters send when power is restored get through because the meters send that message up to 18 times over a 45-minute time period.
This leaves PSE with an “excessive restorations” report. Because both the last-gasp and power-up messages come from meters losing power for as little as a tenth of a second, the excessive restorations report spotlights blinks, or problems that could represent fault current caused by tree limbs brushing the lines.
“Excessive restorations identify potential problems,” McClaine said, but he adds that utilities must translate the information excessive outages relay. “Our emergency operations people don’t want to hear about momentary outages,” he said. “They want to know when people are really out of power.”
King sees another investigative use of advanced metering data: investigation of excessive line loss. Noting that U.S. utilities lose about 7 percent of generation or $14 in line loss annually, King maintains that even cutting losses by a small percentage could have big-dollar implications. “With detailed data, you can have simultaneous reads across your system at one point in time,” he said. “Then you can aggregate circuits, find the ones that have high loss and investigate. You might fine a phase that’s not being metered on a polyphase customer or faulty grounding that has you losing power to the ground.”
Although King noted that no utility has done such research in any detail, he feels the savings potential is significant. “Many utilities look at benefits like this and put a very small value on them,” he said. But he also maintains that it pays to examine all the possibilities advanced metering delivers.
“One Midwest utility saves more than $2 million every year just on load balancing and transformer load management alone,” King said.à¢®à¢®
Editor’s note: This article is adapted from an article that originally appeared in AMRA News, a publication of the non-profit Automatic Meter Reading Association (www.amra-intl.org). Betsey Loeff is a news writer for AMRA.