The technician’s job is usually to ensure the lights are on, but we often need to shut a facility down to perform much needed outage-based maintenance. This switching activity is often straightforward, but when the electrical system is complex and several issues exist, unexpected events can occur.
Our team was recently fortunate to be awarded a major contract to provide preventive maintenance services for a large, critical facility that had deferred maintenance for three decades. When we initially walked down the facility, we recognized some of our original 1990 acceptance testing stickers. In addition to the likelihood of typical problems due to this lack of attention to maintenance, other red flags began to surface as we began our initial fact-finding.
Starting at the main 12kV outdoor switchgear, the breaker labeling did not match the single-line drawings, which only indicated two feeders. However, the switchgear labeling indicated two mains and four feeders. Although the logical layout of the gear seemed to indicate one main, the labeling implied there could be a utility main in series with a customer main.
The facility management firm had only been responsible for the system for a few years, and they had no idea how the medium-voltage system was configured. For that matter, they really did not know how many unit substations existed or where they were located. Additional drawings were located showing a third feeder, and it was determined that:
• Feeder 1 fed three unit substations via a loop of SF6 switches.
• Feeder 2 fed three separate unit substations, also via a loop of SF6 switches.
• The feeder 1 and feeder 2 loops could be connected via the SF6 switches.
• The newly discovered feeder 3 fed two separate unit substations via two SF6 switches.
• One eventually located, difficult-to-find feeder fed a separate, non-critical transformer, so it cautiously seemed the mystery was potentially solved.
On-line partial discharge testing was the first activity chosen to glean a picture of the overall insulation condition and to gain better understanding of the facility. Additionally, we hoped to detect any defects prior to the scheduled maintenance outages to be prepared for remedial actions.
The cable systems were determined to be in good condition, several SF6 switches were in need of gas, and the transformers were in good condition. And then there was the outdoor switchgear.
The outdoor gear looked like a scene from “The Adam’s Family” — cobwebs and spiders everywhere, and a quarter-inch of dirt on the floor and all horizontal surfaces including relay and meter covers. Touching the enclosure filters caused them to immediately fall apart to dust. Caution was required just to walk around, all the while keeping an eye out for Uncle Fester to appear.
Moderate ultrasonic signals from the potential transformers were detected and light ultrasonic signals were present from some breaker compartments. This information would be used later during the upcoming outages to focus visual inspections on these areas.
PLANNING THE OUTAGES
A series of four, late-night, four-hour maintenance outages were carefully planned. With such a short outage window, equipment and personnel would need to be staged and ready to go to work as soon as safely possible. The first night was planned to be a facility-wide outage to primarily service the main(s) and bus. Additionally, the two feeder-3 unit substations would be serviced, and all eight SF6 switches would be pressurized to normal gas levels. Technicians staged at the unit substations would be safe from the work at the main switchgear because they had their own dedicated SF6 switch that could easily provide local isolation for them.
In the final days before the outage, the utility became concerned with their ability to support the facility’s request for a temporary utility disconnect and to maintain their sections of the switchgear. During the call, it became apparent that the utility did not understand how the switchgear was fed and why two mains were present. Solving that mystery would need to be accomplished by opening the devices during the outage, seeing what loads are removed, and following the bus routing. We would also have to ensure that the second main was not a separate power input feed.
Meanwhile, without our input, the customer coordinated with a generator rental vendor to stage a 12kV, 2MW generator at the outdoor substation in case a breaker problem was encountered. We later observed that the vendor supplied 600V cable, so fortunately, the generator was not needed.
Prior to the outage, we conducted a safety meeting and laid out the teams:
At the main switchgear, we stationed three techs on the bus, two techs on breakers, and one relay tech. One tech was dedicated to the SF6 switches. Three technicians were stationed at each of the two unit substations. We provided an extra tech in case unexpected problems arose, and the team was supported by a project manager.
When the customer gave the word to commence, we began opening the feeders to see what areas would be affected. Feeder 1 and feeder 2 both dropped the main halves of the facility as expected. When feeder 3 was dropped, we phoned the techs to verify the outage to their areas, but they indicated the lights were still on. Feeder 3 obviously fed a different part of the facility. We proceeded to dump feeder 4, expecting favorable results, but a phone call to the technicians indicated their lights were still on, as well. For a moment, we thought it might not be possible to de-energize feeder 3, but we proceeded to drop the second main, which successfully turned the lights off. Turns out the second main was actually feeder 3. We continued to drop the real main and proceeded with our work.
Once things settled down after the initial surprises, we were able to successfully perform the intended services. Results of the maintenance activities revealed many problems including:
• Both potential transformers showed damage from partial discharge activity.
• Many of the medium-voltage insulators displayed partial discharge damage and signs that aggressive discharges were sparking to the breaker frames.
• Troubleshooting revealed that the strip heater fuses had been pulled, allowing condensation to occur. Coupled with the large accumulation of dust, this created ideal conditions for partial discharge inception.
• We function tested the heater circuit and found it in working order, but also determined that no thermostat was present in the circuit. With this location reaching temperatures in excess of 110°F, we felt it best to add a thermostat as soon as possible before completing the circuit.
Overall, the maintenance efforts were successful, and several lessons were re-emphasized.
• Accurate drawings are critical for successful outage planning and to ensure safety.
• Accurate equipment labeling is critical for efficiency, switching, troubleshooting, and safety.
• PD testing is a very good tool to perform prior to outages and regularly thereafter.
• Neglecting regular maintenance can place your equipment at risk of failure and reduce lifetime.
Don A. Genutis presently serves as President of Halco Testing Services, Inc., a NETA Accredited Company with offices in Los Angeles and Houston. He has held various principal positions during his 35-plus year career in the electrical testing field, primarily focused on advancing no-outage testing techniques for the last 20 years, with emphasis on cable and switchgear on-line partial discharge testing techniques. Early in his career, Don acquired and operated the former Westinghouse East Pittsburgh Insulation Research Laboratory, where he gained valuable experience in understanding insulation material performance. Don holds a BS in electrical engineering from Carnegie Mellon University and is a NETA Certified Technician. Don has authored 50 technical articles for NETA World and has been featured in EC&M and Uptime magazines. Don’s work is summarized in his book, Partial Discharge & Other No-Outage Testing Methods, published in 2019.