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Power providers will probably never be free of quirky reasons the grid goes down. Who could anticipate that 2,000 people would lose an hour of electric service in Bridgeport, CT after confetti from a parade shorted out power lines? How can the industry protect itself from outages like the one in Spokane, WA, that left 11,000 residents in the dark after strong winds scooped up a trampoline and slammed it into a substation?
Those are two of the peculiar outages you’ll find noted in recent Eaton Blackout Trackers. You’ll also find this: The number of outages has gone up every year since 2008, when Eaton tracked 2,169 events. In six of the following eight years, Eaton counted more than 3,000 outages annually, and 2016 was highest year recorded with 3,879 events.
Aging infrastructure and increasingly severe weather are the destructive forces that most industry watchers are fingering for this rise in blackouts. They’re also a key driver for self-healing grid technology, which has, in recent years, moved from want-to-have to can-have status.
Here is an overview of how it can work for utilities from Kent Hedrick, Director of Distribution Grid Management at Landis+Gyr.
The value of retrospection
Planning may be a forward-looking activity, but it needs to be done with a thorough look back at past events and activity, Hedrick says. While many utilities are looking at historic causes of outage events and using that information for grid hardening, not as many analyze where restoration efforts stalled. That’s a key metric to know if you want smart-placement of the sensors that can lead to faster fault location.
“One of the first things a utility should do is increase the visibility of their distribution grid through sensing,” Hedrick says. “Planning will help a utility optimize the placement of sensors to maximize overall benefit.” He adds that circuit-level sensing is critical and something that likely can be done or augmented through smart metering.
Why is circuit-level sensing essential? “Utilities can use those sensors to locate, in a general vicinity or segment of line, where the fault occurred and shorten patrol time. Even better, they can bring in analytics and pinpoint exactly where the fault occurred. That’s the optimal solution,” Hedrick says.
Real-time analytics capabilities are now available with advanced distribution management systems (ADMS), a step up from traditional SCADA systems, he continues. ADMS systems provide support for software that supports fault location, isolation and service restoration (FLISR).
FLISR technology has not yet been widely adopted, in part, because real-time analytics capabilities to support it are just now being adopted. Likewise, most utilities lacked effective network communications across their distribution systems to bring data back in. In addition, smart grid sensors didn’t measure current in a granular enough fashion. Now, it’s measured in milliseconds, which is fast enough to capture fault current as it happens.
The dollar cost of manpower
According to Hedrick, the number one business-case justifier for FLISR is the operations and maintenance savings that comes from shortening the durations of outages. Specifically, he’s pointing to the savings utilities calculate by cutting their system average interruption duration index (SAIDI). He’s seen utilities value the savings by factoring labor and overtime charges for power restoration workers and patrollers who previously would have walked or driven the lines to locate outages, as well as reduced truck rolls and, in some cases, monetary penalties for poor SAIDI numbers. Labor savings and elimination of patrol times was enough for American Electric Power to calculate a billion dollars in savings over a 14-year period from FLISR investments.
Time to switch
Once utilities deploy their sensors and start using FLISR technology to shorten outages, they can also use the sensors to avoid many outages by analyzing momentary service interruptions.
First, utilities identify the feeders with higher-than-normal occurrences of momentaries, then they analyze the data to determine a cause. “Is it from vegetation hitting lines? In that case, utility managers can send in a crew to do vegetation management on that segment of line,” Hedrick says. “Maybe it’s animal contact or a line with too much sag, so there’s phase-to-phase contact when the wind blows.” Proper analysis allows the right crews to show up with the right equipment for repairs.
Along with preventing outages, utilities should use analytics to determine switching strategies and switching automation. That’s the “I” in FLISR – Isolation.
“Say a fault occurred about a third of the way down a feeder as it left the substation,” Hedrick says. “And imagine that halfway down that feeder, the utility has a tie line where one circuit is hooked up to another and fed out of a separate substation.”
He explains that with the intelligence utilities get from sensors, grid operators could know if a fault occurred upstream from that tie line. Then, they can coordinate switching to isolate the first half of the feeder but feed the second half from a separate substation. “Now, in probably less than a minute, the utility has restored service to at least half of the customers on the feeder who otherwise would have been out of service for the full duration of that outage event,” Hedrick notes.
Pepco is one utility that has implemented the ideas discussed above. By 2015, the utility had deployed an automatic sectionalizing restoration system on seven feeders serving approximately 9,500 customers in the District of Columbia. Pepco also has been working to install remotely operated switches on key feeders for faster restoration, plus it moved forward with fault detectors on overhead lines.
“Smart meters, advanced switches, and computer integration allow us to quickly pinpoint outages, reroute electricity through undamaged lines, and provide more accurate restoration estimates.”
These and other systematic upgrades give the utility credentials to make this claim on the company website: “Smart meters, advanced switches, and computer integration allow us to quickly pinpoint outages, reroute electricity through undamaged lines, and provide more accurate restoration estimates.”
Ahead, Hedrick sees utilities using distributed energy resources (DER) as another tool in creating a self-healing grid, but it’s going to necessitate changes in business models. Maybe utilities will own the DER at critical sites, like hospitals, maybe communities will own such resources, and maybe utilities will wind up with an incentive rate that lets the power providers control customer-owned DER in response to disasters. “This is a new opportunity for utilities to shorten outage duration,” he says. “They can leverage DER to help isolate faults and use those DER to keep customer sites energized.”
