SSEMC crews streamlined the installation of field reclosers with detailed planning and by doing much of the work on the ground, where equipment is more accessible and rubber gloves are not required. Animal guards, jumpers and mounting brackets are all readied for installation.

Snapping Shoals Makes a Smart Switch

Oct. 9, 2013
Distributed automation and SCADA deliver integrated smart switching schemes.

Utilities continually search for new ways to improve reliability and efficiency with technology. Installing a new high-tech system in an established utility environment can be difficult. Integrating multiple high-tech systems together and producing results in that same environment can be a formidable challenge.

There are many pitfalls to avoid. It is easy to end up with multiple high-tech islands, with pieces that are not being used to their fullest extent. And, it can be difficult to abandon a piece that is not meeting goals and start over after the initial investment is made. Lastly, getting employees to buy in and change old work practices to take maximum advantage of new high-tech systems can be challenging.

The Challenge

Snapping Shoals EMC (SSEMC) is a cooperative serving more than 90,000 members/owners. Like many utilities, SSEMC continually struggles with how best to use available technology. The coop has used a supervisory control and data acquisition (SCADA) system and remotely operated substation switches for years. The original SCADA system was based on DEC Alpha hardware running OpenVMS. The system was reliable but difficult to configure, ran proprietary protocols and was, in effect, a technology island. In 2000, SSEMC transitioned to Microsoft Windows for SCADA, and the engineering benefits were immediate. Load and event information was stored in a shared database and made available to engineering employees to support many daily engineering tasks.

The following year, a large customer choice load experienced a few outages and, as a result, some additional improvements were necessary. Utilities often receive blame for a power outage regardless of the cause; therefore, SSEMC’s decision to purchase an automatic source transfer (AST) scheme was relatively easy. The equipment purchased, IntelliTeam, was a joint venture between Cooper and S&C Electric. The
IntelliTeam senses an outage on its primary feeder and automatically switches the critical load to a backup feeder. It requires no human intervention and even returns service back to the primary feeder after power is restored.

Automatic switching technology was relatively new at the time SSEMC purchased the IntelliTeam, and the technology has served the coop well. During its 12 years in service, the IntelliTeam prevented 10 outages while serving up to 3 MW of load for approximately 60 customers. However, it was not able to communicate with the SCADA system, so it was an island in that regard. From an operational perspective though, SSEMC was able to exceed customer expectations with the IntelliTeam by providing reliable service, which was priceless.

Advancing and Building

The power and communications cables are attached to the Nova recloser while on the ground, allowing all the equipment to be lifted into position as a single unit.

In the years following its initial AST scheme installation, SSEMC deployed several more schemes serving dense commercial zones using Cooper’s NOVA reclosers and Form 6 recloser controls. The new schemes were designed using a decentralized philosophy with SCADA playing a supervisory role. In other words, they worked much like the original IntelliTeam, except they updated SCADA after events happened and allowed the SCADA to take manual control when necessary.

In 2010, the Cooperative Research Network (CRN) was awarded a US$33.9 million matching grant for a smart grid demonstration project, a portion of which was dedicated to the deployment of switching technology. SSEMC saw an opportunity to join forces with CRN and committed to a $4.1 million project to build on what it had already accomplished, to create a more comprehensive solution.

The project’s hardware consists of 97 Cooper NOVA reclosers, three S&C IntelliRupter PulseClosers, single-mode fiber and supporting communications equipment. Most of the switches work in pairs, protecting customers as an AST scheme, while the rest are independent and at normally open points. The independent devices at normally open points are not automated, but they serve two critical roles. Each one helps to facilitate outage restorations for two feeders and can be used with preplanned switching. The communications backbone is mostly single-mode fiber, but some of the more remote devices are served with Ethernet radios. By design, more than 30% of SSEMC customers are inside AST schemes, and all but a few substations can be switched out of service remotely.

Using automation and SCADA to assist with outage restorations has worked very well. Power can be restored safely, faster and with fewer employees than before. It is ironic in one regard. Linemen initially wondered how safe automation would be and had many questions up front. Now they understand how it works and see firsthand how quickly narrowing down the scope of an outage reduces the pressure on them. The temptation to rush is reduced once most of the lights are on, which ultimately enhances safety.

Maintenance, Too

Automation and SCADA are used regularly for system maintenance, which has also resulted in savings. In the spring of 2013, several substations underwent routine testing, which required each station to be completely unloaded. Regular testing helps avoid problems down the road, and that is a good thing; however, scheduling the work can be disruptive for crews. If everything goes as planned, testing is done during normal business hours with time to spare. If there is a problem, however, switching back to normal can be delayed until after hours or even into the following day.

Problems were discovered at two of the stations this spring and had to be repaired. It was after 10 p.m. before repairs were done on one of the stations, but dispatch was able to switch all six feeders back to normal from the office. Traditionally, this would have tied up a truck and one or two people at each open point on overtime, or the system would have been left abnormal until the following day.

The responsibilities of dispatch have changed and training is more important than ever. When feeder outages occur, dispatch is responsible for distribution switching by taking manual control of SCADA-enabled field equipment. Critical loads are typically served from the more reliable of two feeders and, for that reason, the backup feeder is more likely to experience a problem.

By design, the AST schemes do not automatically assist with feeder restorations. Dispatch must be ready to coordinate a restoration plan with field personnel. The goal is to isolate the damage from both sides and restore as many customers as possible before repair work begins. Occasionally, power can be restored from the office for some customers before dispatching a truck. The new equipment also has made preplanned substation switching easier. Before the new equipment was installed, dispatch had to come into work at 6 a.m. to have a substation manually switched out of service by 8 a.m. for testing. With SCADA-enabled devices in place, the same switching can be done in about 30 minutes from the office.

Positive Results

The lineman prepares to descend after the installation is complete. Planning and experience have reduced the installation time to an average of 4 hours to 5 hours, whereas before it took a full day.

For the year 2012, SSEMC had 16 events where AST schemes were used to address outages, preventing more than 11,000 consumer-hours of outage time. In five of those events, AST schemes automatically switched, preventing some customers from experiencing an outage. In that same year, more than 200 faults were automatically located. Most faults do not result in an outage, but the root cause is found about 75% of the time.

SSEMC regularly replaces damaged lightning arresters, insulators, switches and miscellaneous pole assemblies. There have been instances where lightning damaged down-line hydraulic reclosers, causing the protecting feeder to operate yet not resulting in a permanent outage. If SSEMC had not used the fault data to locate and repair the problem, it would have eventually escalated into a bigger problem. The key is to follow up quickly. If an animal was the culprit, the evidence may be gone if a utility waits until the next day to investigate.

Results have been so beneficial that hydraulic recloser operations are being investigated using automated meter reading blink data. It is difficult to quantify, but addressing faults during normal business hours makes inclement weather less troublesome than it would have been otherwise.

A cost-benefit analysis for automation can be challenging because it is subjective to some degree. However, many of the benefits can be substantiated. The data-collection phase for the CRN project is coming to a close; developing the analyses will officially bring it to conclusion. SSEMC is hopeful the results of the smart feeder switching project, along with the other CRN studies, will help to guide future endeavors and create a more intelligent grid.

Michael J. Milligan ([email protected]), manager of engineering at Snapping Shoals Electric Membership Corp., was the principal investigator for the smart feeder switching project and worked with Cappstone Energy Group to design that solution.

Companies mentioned:

Cooper |

Cooperative Research Network |

S&C Electric|

Snapping Shoals Electric Membership Corp. |

Sidebar: Automatic Transfer Example

Around 4 p.m. on Saturday, Feb. 18, 2012, it was misting rain and a pickup truck lost control, struck a double-circuit pole and took both feeders out of service that provide power to about 2,000 customers. One of the feeders normally serves an automatic source transfer (AST) scheme, so 660 customers only saw one short blink while being switched over to the backup feeder. The zone served by the AST scheme was restored before the primary feeder had time to lock out.

A downed distribution line such as this is an underlying reason that smart feeder switching and the enabling equipment are necessary to minimize the interruptions that customers experience.

After a few seconds, the substation breakers and the AST scheme updated the supervisory control and data acquisition (SCADA) system. Within 1 minute, the outage system collected fault data from the SCADA, calculated the location of the damaged primary lines and sent out emails stating what feeders were affected and the probable location of the fault. In a nutshell, everyone who needed to know was updated automatically within a few minutes of the actual event.

On that afternoon, a utility observer was at the scene right after the accident happened. The police were there, and the serviceman had already assessed the scene and left. A full crew with large bucket trucks was needed to make repairs, so the serviceman began to isolate the damage with gang switches. Using one small truck along with SCADA-controlled switches for isolation proved to be effective.

The serviceman opened a gang switch just past the damaged primary line, and then the SCADA operator took manual control of an AST device to backfeed the circuit. The serviceman was able to restore power to another 250 customers and a large county water-processing facility before the large bucket trucks arrived. The outage was further isolated to a very small area by the crew because of the extent of the damage. As a result, 660 customers only saw a blink. Of the remaining customers, most were restored within 30 minutes to 2 hours. Only 100 customers experienced the full 7-hour outage duration while repairs were being made.

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