Thermal Inspections Prove Effective for Substation Maintenance, Safety

By Tom Scanlon, FLIR Systems

Utility companies first began performing infrared (IR) camera inspections in substations in the mid to late 1980s. But, it was not until the early “Ëœ90s, when spatial resolution markedly improved-especially with the increased resolution provided by the focal plane array-that IR inspections were given more serious consideration. And, IR inspections continue to be used more widely today.

Approaches to inspections by utility companies vary. Systematic infrared inspections, as one approach, are a commitment by the utility to perform routine inspections at given intervals of time by a dedicated team of thermographers who have been trained to interpret and analyze the images and prepare all necessary reports. The systematic infrared inspection is defined by its consistency and its repetition.

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The Sumter Electric Cooperative in Sumterville, Fla., performs infrared scanning on each of its 42 substations once every two months and inspects all transmission lines and substation feeder distribution lines within 24 months. Sumter Electric employs five full-time thermographers, one performing inspections in the field and four who use thermal imaging in their work as energy auditors. The thermography inspection program is now in its ninth year.

“When we first began the infrared inspections full-time, I was finding 400 hot spots a year,” said Richard Strmiska, a certified thermographer, Level III, for Sumter Electric. “Now, I find maybe 250 in a year, and, of those, none are as bad or as dangerous as in the past. That shows you what a predictive maintenance program can do.”

Direct and Indirect Targets

Because substation connections and contacts differ widely in the use of thermal insulation, the specific object being inspected (called the target) is defined either as direct, where there is little or no thermal insulation between it and what the camera sees, or as indirect, where there is significant thermal insulation between it and what the camera sees. Examples of direct targets include bolted plate and external bushing connections and mechanical switches. Indirect targets include load tap changers, lightning arresters and oil-filled circuit breakers. In either case, any temperature rise observed relevant to ambient is termed as a hot spot, and needs to be investigated further (see Figure 1).

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    Fig.1 Internal problem on a bushing The transformer bushing is under a 15 percent load, at minimum test conditions. The hot spot has a 21-degree Fahrenheit rise, indicating a critical problem as this is an indirect reading. The heat is being generated about eight feet away in an oil-filled, main output transformer from a 900 MW coal fired power plant. The connection was loose enough for the bushing to be rotated by hand. The unit could not achieve its full power of 900 MW with such a problem. Based on a load correction for 100 percent capacity, the temperature rise would approximate 20 times the rise of normal operation. The main output transformer was a replacement for one that had exploded six weeks earlier, and an IR survey was taken on initial startup to verify that the new transformer was operating properly. On the right, with the loose connection repaired, the thermogram indicates normal operation.

“Indirect targets have an entirely different set of severity criteria from direct targets,” explained Bob Madding, director of the Infrared Training Center for FLIR Systems. “An indirect target can have a severe problem with low temperature rise on the surface because the internal temperature rise is quite high. But, with large amounts of thermal insulation, the IR camera picks up a much smaller surface temperature rise.”

Cameras built and designed for predictive maintenance and diagnostic work are set in the spectral range of 7.5 to 13 µm. For its substation inspections, the Sumter Electric thermographers use the FLIR ThermaCAM P60 infrared camera.

Strmiska first learned about infrared camera inspection and began using it 20 years ago. He received his certified thermography training from the FLIR Infrared Training Center (ITC), in North Billerica, Mass. “Level III training helped me understand more about the root cause of failures,” Strmiska said. “You can have a thermal reading that tells you a switch is failing. But, with more training and experience, you develop a knack for seeing that it’s the contact or connection, not the switch.

“You also develop a knack for inspecting targets at different angles,” he explained. Strmiska believes that one mistake many thermographers tend to make is not to use a telephoto lens. “At times, you’re scanning a one-inch target at 30 feet or more,” Strmiska said. “With targets that small, at those distances, you need the right optics for an accurate temperature measurement.”

Seeing the Unseen with Infrared

As a safety measure, an initial overview of the substation is taken, surveying for any major problems before an inspection begins. Madding recommends that if you have an “alarm high” mode on your camera, to set it above the ambient (normal) component temperatures and perform a safety survey. “For direct targets, 90 degrees Fahrenheit (50º C) above ambient is a good starting point. For indirect targets, you don’t want to see any temperature rise above normal operating conditions,” Madding explains. He further recommends that the first inspection be a baseline survey, imaging everything in the substation for future reference.

A systematic inspection begins either on the line or the load side and includes scanning every bolted, crimped and sliding connection; all lightning arresters; transformers; oil-filled circuit breakers; capacitor banks; potential transformers; current transformers; voltage regulators; control cabinets; and the battery room.

“A substation has thousands of connections and contacts,” Madding emphasized, “which is why thermal inspections are so effective. The scanning is noninvasive. You can get a reading for critical equipment, operating at peak load when necessary, while minimizing your safety risks.”

Strmiska’s long experience has convinced him that the effort put into the inspection work more than pays for itself. In addition to preventing outages, Strmiska has used thermal images several times to prove to manufacturers that equipment was defective, and not damaged in the field.

“I don’t think that many utilities are using thermal inspections to their full effectiveness,” he said. “They’re not aware that infrared inspection can save money. I’ve read studies that conclude for every dollar spent on infrared inspections, there’s a $4 return on the investment. I think the return is higher than that.”

Inspections as Needed

The Electric Power Board (EPB) in Chattanooga, Tenn., manages thermal inspections with a different approach. Operating and maintaining 135 substations in a 600-square mile area, thermal inspections began periodically about 10 years ago, and have continued at semi-regular intervals.

“We try to inspect the substations with infrared at least every three months,” Alex Bowen, an engineer in the preventive maintenance department explained. “But manpower and resources don’t permit a scheduled maintenance routine using the camera.”

Thermographers at the Electric Power Board have found infrared inspections for predictive maintenance to be effective in routine scanning and also for investigative work on specific problem areas. Recently, several polymer lightning arresters that attach to the substation transformers failed for no apparent reason.

Cheaper and lighter than the older ceramic design, the polymer lightning arresters had been gaining in popularity throughout the country. “We had no idea why the arresters were failing,” said Bowen. “So, we decided to systematically scan all the polymer arresters to take any more offline that may have been close to failure.”

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    Fig.2 Visual and thermal images taken in an underground vault. The lightning arrester is to the right of the three elbow breakers. The visual image indicates no problem, but the thermal image shows a temperature rise on the arrester, indicating leakage current. To operate safely, there should be no external temperature rise on an arrester caused by internal heating. Note that the colors are used to differentiate temperatures and that two targets, SP01 and 02, are used to highlight the difference. The temperature chart on the right of the thermogram is standard.

Using its FLIR ThermaCAM 695 infrared camera, over 700 arresters were scanned in a period of one month. “We found two or three more arresters with a temperature rise of 20 degrees Fahrenheit,” said Bowen. Because lightning arresters are indirect targets in a thermal scan, the temperature rise was significant. “We took those offline as quickly as we could. Without the infrared camera, there would be no way to tell that the failures were imminent” (see Figure 2).

The cause of the polymer arrester failures ultimately proved to be moisture intrusion. The problem stemmed from a poor seal. Other utilities have reported similar problems with polymer arresters. Companies that manufacture the arresters report that the problem has been addressed.

The Electric Power Board has been gradually increasing its infrared inspections, purchasing a FLIR ThermaCAM E4 infrared camera for scanning transmission lines. “The E4 camera doesn’t have the resolution of the 695 camera, but it’s smaller and a little lighter and gives the inspector more mobility when moving up and down a line that’s parallel to a roadway,” explained Bowen.

Long range plans at the EPB are to continue expanding the use of thermal scanning. Innovations for the use of infrared cameras, particularly detector technology, infrared software development, built-in alarming and visual imaging have made thermal analysis solutions for utilities more cost effective than ever before.

“The payback is quick once you prevent a couple of shutdowns or failures,” commented Bowen. “I think the limitation for some utility companies is that they look for quick returns without putting more resources and more planning into the process of preventive maintenance and how the inspection system could identify more potential problems and further savings.”à¯£à¯£

Tom Scanlon is vice president, Americas thermography, at FLIR Systems. He has been a leader in the infrared camera and utility industries for over 20 years.


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