Colorado Springs is one of the fastest-growing cities in the United States. For Colorado Springs Utility (SU; Colorado, Springs, Colorado), this has meant phenomenal expansion of its delivery system. In the past 20 years, the number of SU substations has more than doubled. Surprisingly, the number of technicians that support and maintain the substations has stayed relatively constant. This is because SU uses remote monitoring, and a supervisory control and data acquisition (SCADA) system links all of SU's substations.

The Human Factor

Despite technology, there is an undiminished human factor requirement needed to maintain SU's 60-plus substations. Even though the system catches a lot, it still requires on-site visits to substations as a fundamental part of system reliability. A SU technician visits each substation at least once a month to inspect line-termination structures, switchgear, transformers, surge protectors, controls and metering.

During a scheduled sub-check, the technician visually inspects the premises and equipment. The technician takes voltage measurements, reads transformer currents and temperatures, inspects bushings and checks fan functionality. From an environmental perspective, technicians look at all the berms and drains surrounding the site to make sure they are intact. It is hard to put a price on the importance of this monthly visit, but having on-site technicians has saved millions of dollars.

An example of this occurred recently. As the technicians were pulling up to a substation, they saw smoke coming out of a bushing. They called dispatch immediately and dumped the load. The transformer bushing had failed and most of the oil had leaked out. Smoke was flowing out of the bushing, and the transformer was probably close to blowing up. Luckily, the technicians were there. Even with all the efficiencies gained from technology and automation, it's still important to have the technicians visit the sites on a periodic basis.

SU also could have lost a transformer. Instead, the bushing was replaced for $10,000. Replacing the transformer have cost from $750,000 to $1 million.

A Connector Meltdown

In another instance, a technician was pulling maintenance at a substation and saw a cable termination smoking on the other side of the yard. Molten aluminum was dripping off a bad connection; it was literally melting down. The technicians just happen to be in the site on a monthly sub-check and saw the impending failure.

A monitoring device is never going to find a jumper meltdown. SU would have eventually found out there was a problem, but the damage would have be done already.

Working Inside the Fence

Prior to the system automation, substations were primarily maintained manually on an as-needed basis. Technicians waited for a customer's call or performed on-site maintenance, and responded with repairs accordingly. As its system has grown, SU has installed monitoring and control devices that are monitored at the operations center. Early warning alarms, connected to equipment at the substations, alert the operator when something isn't pumping or when a fan has failed and a transformer is getting too hot.

This remote monitoring system is beneficial to the technicians responding to a trouble call. When technicians take a call, they go prepared with specific equipment information provided by central operations. The fully integrated system has not only increased the efficiency of the support workforce, but it has changed the day-to-day responsibilities of SU technicians.

Twenty years ago, the duties of a technician could best be described as mechanical. Today, the substation technician's primary assignment is diagnostic in nature: testing and measuring, reading captured-data records and, where applicable, recalibrating devices. More technical equipment at substations allows the technician to do many things without manually taking things apart. Primary tools such as wrenches have been replaces with test equipment — infrared cameras, power-factor testing and voltmeters.

Battery Maintenance

Battery maintenance is a good example of the evolution of a technician's job. In the old days when a technician went out to do maintenance on a set of station batteries, battery maintenance was scheduled on the calendar. Regardless of the battery's performance, the technician would take everything apart, clean the components and put it back together. Equipment failure was often the way you found out there was a problem. And by the time a problem was identified, it was usually a big problem and a costly one. Today's maintenance is more predictable and, more often than not, scheduled in advance.

Today, as part of routine maintenance, technicians will hook up a test set to the batteries, read impedances, conduct cell-voltage checks and inspect for high-resistance connections. These diagnostic procedures help pinpoint repairs that may be needed in the future. Unless there is an anomaly, technicians do not turn a wrench.

SF₆ Circuit Breaker's Reduce Time

Another high-maintenance issue is oil-based circuit breakers. Like most utilities, SU's older circuit breakers use oil as the insulating medium. Spills and leaks are notorious and can only be prevented by constant attention from the support team. Oil-based insulators are heavier, more at risk for fire and have more frequent bushing failures.

For these reasons, SU has been replacing all oil-insulated circuit breakers with SF₆-insulated circuit breakers. SF₆, a gas-medium insulator, has proven to have excellent insulating properties and remarkable arc-quenching abilities.

For the technician, that means there is no oil to check, or leaks and spills to clean up. SF₆-insulated electrical gear has proven to be more reliable and requires very little maintenance. Some of the first breakers SU converted to SF₆ have been problem-free for 10 years. Maintenance intervals have since been pushed out even further. SF₆-insulated breakers are less bulky, which adds space to an already crowded substation environment. And because the units are completely enclosed, they can be installed horizontally or vertically.

Success

SU has grown to be one of the nation's largest municipally owned utilities. But being the largest isn't the primary measurement of success. A better indicator of success is that SU's System Average Interruption Duration Index (SAIDI) number has decreased steadily. In 2006, SU's SAIDI number was 36.6, far below the 90 to 120 national averages among U.S. utilities. This standard reliability index brings together the advantages of automation implemented at SU, as well as the results of those monthly sub-checks and the maintenance performed by those technicians.

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Brian Anderson is energy operations superintendent at Colorado Springs Utilities (SU). Most of his 20-year career at SU has been in substation work. banderson@csu.org

Switchgear Racking Dangers

Finding more efficient ways to manage and support system growth is only part of the focus at Colorado Springs Utility (SU). There is also a total dedication to safety inside the substations. A good example of this has been the innovative racking procedure developed with manufacturing partner Powell Industries (Houston, Texas).

A few years ago, the racking of 15-kV circuit breakers for clearances was identified as one of the most dangerous tasks at the substations. In the past, workers would stand directly in front of the switchgear to perform this hazardous task. If the circuit breaker was closed at all, it might blow up. Currently, there are no industry safety standards for the racking of circuit breakers. Different safety methods are available, including the wearing of personal protective equipment, but workers would still be in harm's way.

Newer switchgear has been engineered by SU to be safer — with arc resistance and other safety features — but it is not always economical to immediately replace all switchgear at a company, especially if it still has useful life. So SU and Powell Industries teamed up to develop a remote racking solution for all of SU's existing 15-kV switchgear.

The system includes a motor at the end of an umbilical cord, so employees stand 30 ft away when they are racking the breaker. If something does happen, the technician will not be in harm's way.

Since the remote racking system was implemented, SU did have a case where workers were using the remote racking solution and the circuit breaker did blow up. The workers were not harmed because they were out of the line of fire. SU's 15-kV switchgear is racked using the remote procedure and equipment. The implementation of this unique accomplishment is an example of SU's commitment to employee safety.