Among the best known technologies to assess the condition of power network assets are infrared and ultraviolet imaging. Both have been used now for decades and rely on specialized cameras that have evolved considerably over the years. The common direction of the latest generations of these cameras are towards more portability, improved data storage and sharing and greater ease for the user to assess the severity of any problem identified. The continuing existence of both imaging technologies has made some power engineers wonder whether they are complementary and must always be used together or whether they are rather alternatives that detect the same incipient problems. The answer might vary depending on which expert is being asked. But what is clear is that each inspection technology offers its own specific benefits when it comes to locating particular types of defect. In general, it can be said that infrared (IR) imaging records presence of internal heat due to elevated leakage current while ultraviolet imaging detects presence of corona due to high electric field near surfaces. The first phenomenon depends on an internally-generated heat source and the second on surface condition. Both situations represent a potential hazard to continued safe operation of a line component or piece of equipment in a substation and both are a reason for either closer future scrutiny or immediate remedial maintenance. In 2016, INMR accompanied IR imaging expert, Bill Hoth, on an infrared inspection of a 138 kV substation located near the Gulf Coast of Florida and discussed with him specifics of the IR inspection process.
Bill Hoth recalls the day when the infrared equipment he took with him for inspections was so cumbersome that it required him to also tote nitrogen coolant. These days, as head of Clearwaterbased Universal Thermography, he relies mainly on a camera with four times the pixels of the one it replaced yet that’s also light and portable.
Hoth says he has maintained his focus only on infrared imaging – in large part because he found corona inspection too arbitrary and, in his view, unable to clearly identify whether a component was in good working order or not. By contrast, in the case of IR, the definitive factor in condition assessment is not absolute temperature but rather how temperature of the item being inspected compares to the reference temperature of similar nearby items. Says Hoth, “today, most engineers do not care that much about the temperature of any particular item but rather whether or not it is significantly different from similar objects located next to it.”
Hoth points out that IR imaging requires the inspector to be aware of key meteorological parameters since it is affected by humidity as well as wind conditions. For example, higher relative humidity makes any ‘hot spot’ appear cooler than it actually is. In the case of high wind, there is no specific camera adjustment however a trained operator has to be aware of it and take it into account when preparing the inspection report. Hoth also notes that the key to all infrared imaging is emissivity since each item being inspected will emit at the same radiation as it absorbs. That means infrared imaging of each object has to be adjusted based on its known emissivity.
During thermal inspection of the 138 kV Immokalee Substation near Fort Myers – one of about 25 operated by local power utility Lee County Electric Co-operative – Hoth discovered a hot spot on the blade of a transmission switch. He says that this is something that could have been caused by corrosion between the fingers and blade and therefore it will probably require cleaning. “In a typical report,” he notes, “I will pinpoint the location of any hot spot such as this, indicating the device number and also the phase where it was detected.”
Hoth explains that findings of any inspection can have different consequences depending on the specific customer. “Every utility has its own thoughts on how to prioritize maintenance problems, whether urgent, serious or moderate,” he remarks. “Sometimes it’s a question of availability and what’s happening elsewhere in their grid. Still, if I ever see a temperature differential of 150°F (66°C) between phases of the same load and at the same location this is almost always regarded as ‘critical’. By contrast, localized temperature rises of up to 20°F can be due solely to increasing load or even just to changes in ambient conditions.” He also notes that it is not unusual for him to identify from 10 to 15 hot spots per inspection, with larger utilities often having 3 to 4 times this number. Typical locations of hot spots include distribution switches, where he estimates about half of these are registered during any inspection. “Switches tend to have the most hot spots,” he observes, “mainly because they are a moving part. Another common area for hot spots is bushings, generally due to loose or dirty connections.”