Earlier this decade, Hancock-Wood Electric Cooperative was experiencing increasing difficulties in providing reliable electrical service to its members because of lengthy outages. In fact, Hancock-Wood’s average outage time of 414 minutes per member far exceeded the National Rural Electric Cooperative Association (NRECA) average.
With 23 substations and 1,600 miles (2575 km) of power lines, this not-for-profit electric cooperative serves nearly 13,000 accounts in 10 counties in rural northwest Ohio, U.S., including Kelleys Island on Lake Erie. A significant percentage of its outages were the result of interruptions in power supplied by three different transmission providers across 21 delivery points. Lengthy outages were particularly costly for Hancock-Wood’s commercial and industrial customers, which represent 60% of the utility’s sales.
Knowing the transmission providers could not be forced to improve service, Hancock-Wood managers realized they needed to control how quickly the cooperative could backfeed its substations. Substations offered the greatest impact on outage time improvement as each substation serves a large number of members who may be affected by an outage. Improving reliability would require the utility to implement distribution automation consisting of supervisory control and data acquisition (SCADA) communications, remotely controllable smart switches and control software.
The Automation Solution
By being able to control switches remotely, managers could restore power to an outage area quickly by rerouting power from a different substation. For a switch to be used in an automated system, it must be able to sense a loss of voltage and communicate it to the central office as well as other switches. The switches must be equipped with motorized operators that allow them to open and close in response to a control signal. The control signal may be sent from a central office by software, or it may be received from another switch if the system is designed to operate automatically.
If an electrical fault causes an outage to a section of the grid, a recloser will sense the loss of voltage and try three times to reestablish power or reclose. If unsuccessful, the recloser will send a signal to a normally open tie recloser telling it to close, thereby restoring power from a different source. This approach is called a loop scheme because the grid is sectionalized into loops that can be powered from different sources. Of course, the automation requires the capability for switches to communicate through a SCADA network as well as the integration of control software.
After identifying this distribution automation/SCADA solution, Hancock-Wood managers took steps to educate their board members and assure them where and how needed funds would be well spent. They began by explaining the problems with older technology then in use, such as air-brake switches that cannot be reset with the press of a button as newer automated technology allows. With the older technology, a lineman had to drive to both the pole and the substation to reset the switch.
Engineering and operations personnel used Google Maps to calculate the cost of drive times and show the board the distances involved. When the board members saw the maps, they understood the value automation offered in terms of speed of restoring service to members.
For the co-op board, the motivation behind the initiative was to reduce power supply outages. Members of the board and the co-op CEO live in the community, and when an outage occurs, they get calls from family and neighbors. Co-op members do not care if the problem is actually the transmission providers’ fault, because they pay their bill to Hancock-Wood. Educating the board members about this helped to equip them with a good response to complaints: “The utility is investing in reliability in three ways: adding SCADA so it can remotely control switches, upgrading its infrastructure and adding distribution automation.”
Rather than ask for funding of distribution automation and SCADA outright, managers requested funding for rebuilding substations and a line rebuild program. SCADA and distribution automation were a small part of the total cost, and the board understood the need to maintain infrastructure to keep up with changing technology. For example, it made sense to pay a small premium to install a recloser rather than a manually operated air-brake switch as part of a larger substation maintenance project.
Well versed on the proposed initiative, the co-op board decided to implement SCADA and distribution automation in 2010. In January 2011, to take advantage of available low interest rates, the board amended an existing 2009 construction work plan for Rural Utilities Service to upgrade substation infrastructure.
The project began in early 2012 with the hiring of a SCADA technician and a review of potential equipment vendors. Wireless backhaul and communications improvements were required to implement both SCADA and distribution automation. Because communications was the biggest initial challenge, the Hancock-Wood team first looked into point-to-point wireless, unlicensed band radios. However, interference from trees and Wi-Fi hot spots (truck stops, amateur ham radio operators and warehouses with internal radio systems.) was an issue.
In January 2014, the utility moved forward with a Sensus distribution automation and advanced metering infrastructure (AMI) pilot project, which uses licensed radio frequencies to communicate with the tie point reclosers. Fortunately, it already had in place the towers and backhaul used to implement Sensus AMI for smart meter reading.
Distribution automation began with the selection of a vendor to replace the manual air-break switches with reclosers at the open points between different circuits — all located on the distribution system, mounted on poles.
Several equipment suppliers were considered, including G&W Electric. When Hancock-Wood management toured the G&W plant, they were impressed by the facility and product quality. Managers appreciated the 100% testing and were impressed by the amount of time G&W people spent with them.
They also liked the fact G&W’s Viper reclosers were flexible to use, with no preconfiguration needed, and could be applied to any open point. With other brands of reclosers, it is crucial to be specific and accurate when specifying them. Because Viper reclosers have integrated sensors on both the line side and load side, co-op workers would not need to add external current transformers and voltage sensors. Additional equipment needed included controls for the motor at the switch and substation. Hancock-Wood’s SCADA technician chose Schweitzer Engineering Laboratories controls for their intuitive operation.
Making a Difference
Even though the distribution automation project is only 50% installed, it is already making a big difference, delivering value particularly after hours. Previously, a dispatcher had to call and wake up linemen, who would drive to the office to get a truck, roll the truck to the substation to set up the backfeed, and then drive to the pole for repairs. This usually meant a three-hour outage for members in the area. Today, the manager logs into the system from home and sets up a backfeed, so outages are now just 15 minutes long.
Hancock-Wood engineering and operations can communicate with DA points and the substation to reconfigure the network as needed. About once a month, when a transmission provider needs to do maintenance on its own transmission line, it requests Hancock-Wood to take a substation off-line so it can do maintenance. Although the improvements are not made to the co-op’s network, they do improve the reliability of the power supply.
The Hancock-Wood line crew has embraced the new automation. Frequently, linemen request the office to implement hot-line tags remotely, using the computer, because this saves them time and is more convenient. The hot-line tag sets an instantaneous curve to limit the arc flash hazard to workers and eliminate automatic reclosing of the circuit. The system provides feedback by confirming the hot-line tag is set.
One of the substations is located inside the fence of a steel galvanizing plant. It can take 20 to 30 minutes to get a visitor’s badge, and then the line crew must return later to push the button and restore the settings.
To date, the utility has implemented SCADA at 11 substations. This implementation will continue in conjunction with ongoing substation improvements and maintenance. Through Survalent software, an operator uses SCADA two to three times a day to control switches remotely. Most major open points (tie reclosers) are connected and Hancock-Wood can fully backfeed two substations now through remote control.
There is no question DA has saved Hancock-Wood significant time. Engineering and operations personnel can now go to the pole directly in case of a fault, instead of first driving to the substation to set up a backfeed manually. Remotely, when 0 V is seen, SCADA is used to operate the switch at the substation and close a tie point to a different feed, restoring power. So far, the initiative to use a combination of SCADA and loop-scheme DA technology has reduced the co-op’s average resolution time per outage by an impressive 34 minutes per member. The improvements will continue as the project continues.
William Barnhart ([email protected]) is vice president of operations and engineering at Hancock-Wood Electric Cooperative. During his 17 years with the Hancock-Wood, he has managed numerous innovative projects, including the utility’s investment in innovative technology such as SCADA and distribution automation systems. Barnhart holds a BSEE degree and is completing his MBA degree.