Cooper Power Systems’ NOVA-STS vacuum recloser installation with a 220-MHz radio antenna connected to a GE MDS SD2 radio. By the end of 2013, Southside Electric Cooperative will deploy 74 distribution automation locations.
Cooper Power Systems’ NOVA-STS vacuum recloser installation with a 220-MHz radio antenna connected to a GE MDS SD2 radio. By the end of 2013, Southside Electric Cooperative will deploy 74 distribution automation locations.
Cooper Power Systems’ NOVA-STS vacuum recloser installation with a 220-MHz radio antenna connected to a GE MDS SD2 radio. By the end of 2013, Southside Electric Cooperative will deploy 74 distribution automation locations.
Cooper Power Systems’ NOVA-STS vacuum recloser installation with a 220-MHz radio antenna connected to a GE MDS SD2 radio. By the end of 2013, Southside Electric Cooperative will deploy 74 distribution automation locations.
Cooper Power Systems’ NOVA-STS vacuum recloser installation with a 220-MHz radio antenna connected to a GE MDS SD2 radio. By the end of 2013, Southside Electric Cooperative will deploy 74 distribution automation locations.

Distribution Automation Boosts System Reliability

July 25, 2013
Southside Electric Cooperative implements a fault detection isolation and restoration system.

As part of an organizational assessment performed in 2008, the reliability of Southside Electric Cooperative (SEC) was benchmarked against other cooperatives of like size and composition. SEC was consistently identified as being in the fourth quartile, or lowest 25% of performance. Prior to this assessment, there never had been any objective reviews of the coop’s reliability performance nor comparisons made to other utilities. The system reliability shortcomings made evident through the benchmarking process resulted in SEC’s board of directors and management team identifying reliability improvement as the No. 1 strategic objective for the cooperative.

In 2010, SEC completed a reliability improvement plan that established finite reliability improvement goals through 2015 for its system average interruption duration index (SAIDI), system average interruption frequency index (SAIFI) and customer average interruption duration index (CAIDI), as defined by Rural Utilities Service bulletin 1730A-119, Interruption Reporting and Service Continuity Objectives for Electric Distribution Systems, and IEEE standard 1366, IEEE Guide for Electric Power Distribution Reliability Indices.

This comprehensive plan created a framework for justifying future capital improvement projects, defined operational and maintenance practices focused on reliability improvements, and identified investments in technology that would directly impact system reliability performance. Through this reliability planning process, the coop identified the deployment of distribution automation (DA) as the single-greatest opportunity to improve performance at the quartile level.

Map of the SEC service territory and communications infrastructure as it existed in 2012, showing the microwave backbone. SEC needed a deployment plan to extend communications to the distribution automation locations shown in orange and red.

Historically, during outage events, SEC had manually isolated faulted line sections and energized unfaulted line sections from adjoining circuits. The time required to manually transfer load was lengthy because of the size of the coop’s service territory. SEC operates 60 miles (97 km) of transmission, 34 substations, 120 distribution circuits and 8,149 miles (13,115 km) of line, serving 54,669 service locations. Reliability improvement planning revealed that 67% of the coop’s SAIDI minutes were generated by only 20 of its 120 total circuits. Of these 20 poorest-performing circuits, 19 had ties with neighboring circuits.

Distribution Automation

The reliability improvement plan called for the deployment of DA, specifically a fault detection isolation and restoration (FDIR) system, on the 20 poorest-performing circuits. During outage events, the FDIR system would restore service by switching unfaulted line sections automatically in minutes versus manually in hours.

For the FDIR deployment to be successful, SEC concluded the following critical components were necessary:

  • Ties between distribution circuits
  • Adequate system capacity, including voltage drop considerations
  • Resources necessary to operate and maintain DA systems
  • Intelligent electronic device (IED)-controlled reclosers at circuit midpoints
  • IED-controlled switches at circuit tie points
  • A robust supervisory control and data acquisition/distribution automation/distribution management software (SCADA/DA/DMS)
  • A robust communications system to communicate with the IEDs.

SEC’s distribution system was an ideal candidate for the deployment of FDIR because 90% of the distribution circuits have ties to neighboring circuits. Also, the coop has followed Rural Utilities Service bulletin 1724D-101B, System Planning Guide, Construction Work Plans, which states that in the normal system configuration, primary conductors should not be loaded to more than 50% of the thermal rating for major tie lines during peak loading conditions.

Additionally, 78% of the distribution system is operated at 24.94 kV; the remainder, operated at 12.47 kV, is currently being converted to 24.94 kV. As a result, voltage drop during DA switching will not be a major issue. SEC was in a great position because circuit ties and system capacity are, by far, the most expensive components of a successful FDIR system, and these capital investments had been made already.

SEC had some valuable existing assets that could be leveraged for the new DA communications. It operates a 450-MHzvehicle radio system, a 900-MHz SCADA system and a 6-GHz microwave system, linking its four district offices and headquarters facility. To operate these radio-based communications systems, the coop owns 35 towers that have excess capacity and skilled telecommunication technicians on staff to provide maintenance support.

Moving Forward

SEC identified three areas that it had to address before it could move forward with a DA FDIR system:

  • Select a DA-ready recloser to deploy at distribution system protection points and circuit tie points
  • Select a SCADA/DA/DMS application software suite
  • Select a DA backhaul communications solution.

SEC selected Cooper Power Systems’ NOVA-STS single-tank triple-single reclosers to be used for the DA reclosers as well as the circuit tie switches. At the time of selection, SEC had deployed 34 NOVA-TS triple-single reclosers in the field that were performing well. Plus, SEC uses Cooper’s VWVE electronically controlled, oil-insulated three-phase reclosers as distribution feeder breakers, so the coop’s engineering and operations staff were already trained on operating the Cooper Form 6 control.

The Efacec ACS SCADA screen was developed as part of SEC’s pilot distribution automation deployment at the Amelia substation.

After careful consideration of how it planned to operate its system in the future, SEC decided to deploy a centralized SCADA/DA/DMS logic architecture. SEC determined that the best solution was a software suite that combined traditional SCADA, DA, distribution management including FDIR and voltage optimization, and outage management.

Through a request-for-proposal process, SEC selected Efacec ACS to provide the software application solution. At the time, SEC system operators had to use a variety of islanded applications on as many as five different monitors. Because the Efacec ACS software combines these applications into what appears to the operator as a single application on a single screen, SEC considered this a single-screen solution.

Communications Challenge

DA communications was the most challenging area SEC had to address. With centralized logic architecture, DA functions are only carried out when the communications systems are on-line, and functions like FDIR are typically required when communications systems are under the most stress, for instance during thunderstorms. SEC knew it needed a robust DA communications solution, but it also had a lot of unanswered questions:

  • Of the available communications media, what would be the best fit for this application?
  • How much bandwidth would the DA backhaul communications require?
  • What about scalability for communications to more devices in the future?
  • With rapidly evolving technology, what would be the best solution for the future?

SEC contacted Power System Engineering Inc. (PSE) to assist in selecting and procuring the best-fit communications backhaul technology and frequency spectrum if a licensed wireless solution was chosen for deployment.

The design challenge was to determine how to best interconnect up to 180 DA and commercial and industrial (C&I) metering sites to the SEC headquarters in Crewe, Virginia, U.S., over the large geographical, rural wooded terrain throughout the service territory while leveraging the SEC-owned tower and backbone communications assets.

PSE was asked to avoid leasing commercial tower space and building tall tower structures in the substations if at all possible. Commercial cellular services were not considered for the DA backhaul solution because of poor coverage in rural areas and a perceived risk of switching operations failing during storm events because of cellular outages.

Analysis of Communication Alternatives

PSE issued an information request to obtain all of the geo-located SEC assets that could be exported from the coop’s geographic information system. This allowed PSE to input the SEC-owned tower locations, DA locations, service centers, substations and C&I metering points into the EDX SignalPro software propagation prediction tool used for this design analysis. Using this software tool, several different point-to-multipoint (PMP) frequencies were reviewed for received signal strength to all DA and C&I locations from all current tower locations throughout the service territory. Mesh technologies were analyzed, as well, for feasibility.

Analysis results determined that unlicensed wireless PMP and mesh technologies were not feasible because of the non-line-of-sight conditions caused by the wooded terrain, remote antenna heights of 20 ft (3 m) and low density of the remote locations. The 450-MHz licensed narrowband communication technologies were feasible but not optimal in communicating to a high enough percentage of the remote locations.

However, the analysis also revealed that 220-MHz narrowband PMP licensed technologies would cover 94% of the remote sites without the need for adding new tower locations. Bandwidth requirements analysis determined that up to 20 remote devices could be connected to the same master using a 12.5-kHz simplex radio frequency channel. The GE MDS SD2 radio solution was selected through a competitive bidding process to provide the backhaul solution for the DA deployment.

A diagram showing the 220-MHz point-to-multipoint masters and remote sites in the Amelia and Powhatan areas. The radio system and channel plan were designed to overlap master locations where at all possible.

While the radio technology was in the bidding process, PSE assisted SEC in procuring 220-MHz high-spectrum licenses in the 220-MHz and 221-MHz bands. Because of the location of the coop’s territory, the spectrum needed to be purchased in two basic economic areas from three different spectrum license holders. A master channel plan was developed for SEC based on the spectrum purchased that provided a robust frequency reuse plan for all of the master sites while taking into account frequency coordination of other co-channel users at the borders of its geographical Federal Communications Commission licenses.

The First Deployment

SEC’s first deployment and use of DA was at its Amelia substation. Amelia is a 34.5/24.94-kV substation supplied by a historically unreliable 34.5-kV distribution feeder. SEC installed three DA switches that, when used in conjunction with the SCADA-controlled reclosers within the substation, allow restoration to the Amelia circuits from the neighboring Powhatan substation.

The DA scheme is as follows:

1. Amelia circuit 1 is tied to Powhatan circuit 5 (both are 24.94 feeders).

2. The Amelia 34.5/24.94-kV power transformer is isolated from the 24.94 bus.

3. Amelia’s 24.94-kV bus is energized.

4. Amelia circuits 2, 3 and 4 are energized, transferring all Amelia load to Powhatan.

Historically, it took SEC nearly 2 hours to transfer the load served by the Amelia substation to adjoining circuits during source outages. With the new DA scheme, the switching required to restore power to all 2,419 service locations served by the Amelia substation can now be accomplished in less than 5 minutes.

This map illustrates the basic economic areas’ geographical spectrum boundaries (dark red), as defined by the FCC, where the 220-MHz licenses were partitioned from other spectrum owners and licensed by SEC. Geographical areas where spectrum was purchased are highlighted in yellow with the SEC territory highlighted in gray. Special border coordination arrangements are highlighted in green.

Reliability in Progress

Reliability improvement on the quartile level is a challenging goal for any utility. Through the development of a defined reliability improvement plan, SEC determined that deployment of DA on its 20 poorest-performing circuits was an investment necessary to meet the strategic goals it had set as a company. The SEC FDIR solution is still in the deployment phase, but SEC is pleased about the success it has already had using this technology and looks forward to providing its members the reliable service they expect and deserve.

Mike Bender ([email protected]) joined Southside Electric Cooperative in 2002 as an apprentice line technician. Today, he is SEC’s director of engineering services, responsible for system planning, system design, SCADA/DA, GIS, OMS, and relaying and metering, and he also plays a key role on SEC’s technology planning team. He is a registered professional engineer in the Commonwealth of Virginia.

Charles Plummer ([email protected]) manages the communications practice area for Power System Engineering Inc. He helps PSE utility clients facilitate the evaluation, procurement and implementation of communications infrastructure. He has worked in the electrical utility industry for 20 years, focused on communications and application technologies, and has a BSEE degree from the University of Wisconsin at Madison.

Editor’s note: This article is based on a presentation from the 2013 TechAdvantage conference.

Companies mentioned:

Cooper Power Systems|




Power System Engineering|

Southside Electric Cooperative|

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