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Pickwick Electric Cooperative Uses DFA to Avoid PQ Problems and Catastrophic Switch Failure

Pickwick Electric Cooperative (PEC) used Distribution Fault Anticipation (DFA) technology to perform conditionbased maintenance on a capacitor bank with a failing vacuum switch, thereby avoiding power quality problems and potentially catastrophic switch failure. No conventional technology, including a remote communications system PEC uses to manage their capacitor banks, alerted PEC to the problem.

Like many utility companies, PEC applies switched and fixed capacitor banks on its distribution circuits. PEC’s remote capacitor communications capabilities enable them to detect problems such as blown phase fuses. Such systems cannot, however, detect latent or incipient problems such as switch bounce or symptoms of partial loss of vacuum in a switch.

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Mid-South Synergy Uses DFA Technology to Avoid Outage and Reduce Wildfire Risk

Mid-South Synergy Electric Cooperative (MSEC) avoided a significant outage and reduced other risks, including potential wildfire ignition, by using Distribution Fault Anticipation (DFA) technology to discover a detached conductor lying directly on a wooden crossarm. Conventional technologies did not alert MSEC to the problem.

MSEC is one of seven utility companies participating in the Texas Power Line-Caused Wildfire Mitigation project, a field demonstration supported by the Texas legislature. As part of that effort, MSEC has instrumented ten circuits, primarily long, rural circuits, with DFA technology. Each is fitted with a single, substation-installed DFA device, which detects faults, failures, and other events along the circuit’s length and automatically reports them to a central master station server computer for access by personnel.

Latent power line conditions can cause recurring faults. Some such conditions are influenced by weather conditions, such as wind and moisture, and cause faults only intermittently. Such conditions are difficult to discover with conventional technologies and can exist for days or weeks without notice.

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Bluebonnet Electric Uses DFA Technology to Detect Arrester Failure and Accelerate Response

Thomas Ellis, P.E., Carl L. Benner, P.E., Dr. B. Don Russell, P.E.

Bluebonnet Electric Cooperative (BEC) recently used Distribution Fault Anticipation (DFA) technology to detect and locate a failed lightning arrester and initiate response by a line crew before receiving conventional notification of the failure. DFA enabled BEC to respond to this event sooner and with better diagnostic information.

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Sam Houston EC Uses DFA Technology to Detect and Locate Failed Arrester

Sam Houston Electric Cooperative recently used Distribution Fault Anticipation (DFA) technology to detect and efficiently locate a failed lightning arrester, enabling its replacement. Failed arresters can reduce a line’s surge suppression capability, affect service reliability, cause future short circuits, and create a risk of wildfire ignition.
The Cooperative learned of the failure only from DFA, not from any conventional technology.

Sam Houston EC is one of six utility companies participating in the Texas Power Line-Caused Wildfire Mitigation project, a field demonstration effort supported by the Texas legislature. As part of that effort, Sam Houston is instrumenting ten distribution circuits, primarily long, rural circuits, with DFA technology. DFA instrumentation of a circuit consists of a single, substation-installed DFA device, which detects and warns of faults, failures, and other events along the length of the circuit.

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Pedernales Uses DFA Technology to Reduce Vegetation Wildfire Risk and Increase Reliability

Pedernales Electric Cooperative (PEC) improved reliability and reduced wildfire risk by detecting, locating, and clearing vegetation contacting a rural, overhead distribution line near Blanco, Texas. Distribution Fault Anticipation (DFA) technology enabled this by detecting early warning signs of the vegetation intrusion. Conventional technologies did not notify PEC of this condition. Rather PEC’s only notification came from DFA.

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Severe Power Quality Event… Burned Fuse Cut-out Determined & Located

Event from week commencing April 4th 2016 – USA. This event involved a long circuit with many miles of overhead exposure. A school and other customers at various locations on the circuit began complaining of flickering lights. The utility patrolled but was unsuccessful. They were considering running an infrared scan of the circuit, but this would be difficult because some portions of the circuit were not truck accessible. The flicker condition was severe and continued for six days. Early in the process DFA detected a failing switch on the circuit and estimated that the switch had 83 kVA of load past it, +/- 50%. The utility company became desperate enough that they were willing to switch off sections of the circuit, one at a time, to see when the flicker went away. Unfortunately they did not have any system, other than DFA, that would tell them when the problem went away. Power Solutions Inc, the makers of and prime technical support team for the DFA, worked with them for four hours at that time during which time they opened and closed multiple switches. At each switching operation, DFA real-time measurements made it obvious whether the problem was downstream of the just-operated switch. This is possible because DFA and PSI is aware which parameter to monitor as an indication of switch failure. Neither SCADA nor anything else available to the customer utility would provide this parameter or enable this real-time feedback to guide their search. In addition, dispatchers asked PSI "could it be tree contact?" and "could it be a failing arrester?" and many such questions. The clear answer, based on DFA, was that it was not any of these things but rather a failing switch or clamp, with greatest likelihood of switch. This enabled the utility to know what to look for. When they finally identified the problem, it was indeed a burned top of a fused cut-out serving a single heavily-loaded 50 kVA service transformer. The DFA-assisted search took four hours. A search without DFA would likely have taken days, during which time the utility would have expended many more man-hours and would have continued to provide degraded service to their customers.

Catastrophic Surge Arrestor Failure Detected and Located

Event from week commencing March 28th 2016: USA. A substation circuit breaker tripped once and reclosed successfully, during a storm. SCADA told the utility this, but told them nothing more. This was a routine fault that ordinarily would not be investigated. From DFA, however, it was clear that the fault resulted from the catastrophic failure of an MOV-type arrester. When these fail, the body of the arrester may blow apart physically. In such scenarios it might be that part of the arrester body remains connected to an energized phase conductor and dangles in the air, another common scenario being that the arrestor blows apart and can eject hot porcelain and internal material posing a fire and safety risk in either case. Based upon knowing from DFA that this was an arrester failure, the utility investigated and indeed found the failed arrester which had suffered that latter failure mode on this occasion. In addition, DFA supplied a fault current level, which the utility put the DFA-generated fault current into their single line model to narrow the search to a small area. (A relay might have given them a fault current level, too, but this point is moot if they do not have a compelling reason to investigate the event.) Therefore the crew was dispatched knowing (1) where to look and (2) what to look for. If the utility had not investigated, it is impossible to have known either how long the fractured arrester body may have remained in the broken, dangling condition and a continued possible safety, bushfire, and customer service delivery/reliability risk, or, in the second and actual scenario in this case, whether there had been a fire start or injury to a passing person as a result. The prompt location was valuable in either scenario.

BC Hydro Uses DFA Technology to Prevent Conductor-Slap and Outages

BC Hydro and other utilities have used DFA technology detect and locate conductor-slap events on overhead lines, enabling proactive repairs, to prevent future outages and stresses to the system. A conductor-slap event occurs when an initial fault induces magnetic forces that cause a second fault, closer to the substation, often leading to breakers tripping entire feeders.

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