Tips & News - April 2014

In the old configuration, if we lost either feeder, 750-800 customers were without power until a trouble-crew drove out to open and close the switches to isolate the outage and restore power.

The newly automated switches have mesh radios and an RTU installed in the motor operators that communicate with the master radio at the substation. The substation then forwards the information to the dispatch center via the fiber. In addition to the radio system, we installed SCADA-enabled fault current indicators (FCI) on either side of the switches. They communicate wirelessly with the RTU and provide information such as load current, voltage, and fault detection (among others). With this data, the Dispatch Operator is able to make intelligent and fast-response decisions. Distance: Since Libbert Substation is remotely located from our central office, we expect this projectwill reduce restoration time due to the reduction in driving times. Of course a crew is still needed to make repairs, but the switches can quickly minimize the size and the duration of the outage. In short, we wanted to get our feet wet before we went swimming, and Libbert was the perfect place to try new DA technology. Bigger Plan Once we knew what we wanted to achieve and decided on a location, the next step was selecting the motor operators. We used Hubbell’s AR switches for ten years and view Hubbell products at different conferences. Additionally, the Hubbell representative brought the ‘roadshow’ trailer to show us the equipment. Given this familiarity, it was practical to use an operator that we knew would work with our switches. We purchased six operators in June of 2013, through Hubbell from Cleaveland Price in Trafford, PA. We installed them in November and commissioned them in mid-December in 2013. As currently configured, the switches provide outage/load information to the dispatch center, and a Dispatch Operator makes the decision to operate the switches or not. The system intelligence is expandable so that the system can be fully automated (ie self-healing) in the future, if desired.

This was an advantage not considered. If a fault happens on certain nearby circuits, we can dispatch a trouble-man to just one location instead of two. It cuts the outage time by about 15 minutes. Overall, we are quite pleased with our first DA project. The system is definitely affordable, and we hope to recoup our costs within three years. Further, we plan to do a similar project in 2014.

We wanted the project to add immediate value, as well as provide a barometer of how other DA projects would impact our system. The chosen pilot project included automating switches on two circuits out of the newly constructed Libbert Substation. Here is why. Load and System Configuration: Libbert is a new SCADA- equipped substation serving a primarily suburban area with residential and commercial customers. Two, three-phase feeders come out of Libbert (Camelot and High Point) and each circuit serves about 750-800 customers. Both are loop feeders since they tie with circuits from other substations through normally open switches. In the old configuration, if we lost either feeder, 750-800 customers would be without power until a trouble-crew drove out to open and close the switches to isolate the outage and restore power. Portions of both circuits are vulnerable, especially to trees, and much load growth occurs in that area, making circuit capacity a concern. In fact, the substation was built to help serve the growing load. SCADA and Communications: Although only about 50% of Vectren’s 93 distribution substations have SCADA today, Libbert Substation circuits were chosen for the DA pilot because two of the three area substations are also SCADA-equipped. Using equipment at these neighboring substations, we can monitor the Libbert feeders within the pilot area. This was a major factor in our decision for selecting a pilot location. The transmission lines into Libbert were constructedwith OPGW (Optical GroundWire) which serves as the static for the lines and enables high speed communication via the fiber optics inside the cable. With this fiber back-bone, available bandwidth exceeds immediate needs. Since this was a pilot project, the probability of wanting additional monitoring points in the future was high. From a data capacity standpoint, this is not a problem.

Although our transmission system is fully automated, the electrical distribution system at Vectren Energy Delivery (based in Evansville, IN) is not. Our first foray into Distribution Automation (DA)—adding remotely operated motors to sectionalizing switches—took place in the fall of 2013, and we are already reaping unexpected benefits. Location, Location, Location Vectren is an investor-owned gas and electric utility that serves ~142,000 electric customers in southwestern Indiana. Part of our responsibility is being prudent in our use of funds, so we chose the location for our DA pilot project carefully.

Remotely operated sectionalizing switches. The switches communicate with the substation via a mesh radio system.

The system is definitely affordable, and we hope to recoup our costs within three years.

To date, we operated them once.

In January 2014, during bitterly cold weather, a cross-arm on an adjacent circuit failed. We were able to transfer load onto one of the newly automated circuits. Since the outage was not on the automated circuit, a trouble-crew was sent to isolate those customers first. Dispatch was then able to remotely close one of the new switches to transfer the load to restore power.

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