A salvage company called MIDWEST and complained because they had an old transformer filled with silicone oil and they couldn’t get rid of it. It seemed to them that no one really wanted an old silicone oil transformer. At least no one would pay as much as they wanted for it. They wanted to know why, because they knew oil filled transformers were used everywhere. Since MIDWEST Switchgear Division deals in used and new electrical power transformers, they came to us for some quick help. The simple answer is that silicone is not oil. Transformer oil is mineral oil, much like you put into your car, but it is refined differently. To use the term silicone oil doesn’t make sense. You could say silicone dielectric fluid, but not oil. Silicone filled transformers provide fire protection for indoor use. And since silicone is very expensive, it is not needed or used in outdoor fluid filled power transformers. Regular oil filled transformers must be installed in a secure vault if installed indoors. But they are used every where outdoors. Silicone is really never used outdoors. Therefore, for many installations, silicone has lost favor as a transformer fluid. It especially does not lend itself to informative routine dielectric testing or combustible gas-in-oil testing, which is commonly used to monitor the condition of old and new electrical power transformers used in industry. It is a simple case of supply and demand. And there is not a great demand for old or refurbished or retrofilled, so called silicone oil filled transformers. We referred them to Dow Corning 561 Silicone Transformer Liquid if they wanted to know more about silicone. In addition, there are now substitutes for silicone dielectric fluid on the market.
One common concern with pad mount transformers is in the area of oil sampling. Companies with large pad mount transformers may sample and test the oil in the transformers annually to determine the reliability of the transformer. The condition of the oil reflects the current state of the transformer. Now here’s where it gets tricky. Large pad mount transformers are designed with two cabinet doors. One door exposes the high voltage cables and bushings and the other door exposes the secondary, low voltage, side. The sample valve can be located in either compartment but most of the time the valve is located in the secondary cable side. Years ago it was not uncommon for an intrepid technician with nerves of steel to pull an oil sample from an energized pad mount transformer, the valve being located at the bottom of the transformer while hot cable lugs were located only a couple feet above the oil valve. With safety becoming a paramount concern in industry today, it is no longer prudent nor standard practice to pull an oil sample on an energized pad mount transformer. The hot lugs being within short reach of the technician create a shock hazard. And the secondary side of a transformer is one of the most dangerous arc flash hazards there is. Oil sampling is now performed only during scheduled shutdown of the transformer.
However, there still remains somewhat of a challenge when it comes to pulling an oil sample from a pad mount transformer. The secondary compartment of pad mount transformers can be a pretty fully house. There may be as many as six cables attached to each secondary bushing, making it very difficult to access the sampling valve through that jungle of vines. One way around this, literally, and we’re finding it used more and more in industry, is extending the sample value system to a small secure box on the exterior of the transformer enclosure. The valve would then be enclosed in a newly created box with a locked access door mounted on the exterior wall of the cabinet. In this way the transformer can be sampled at any time, while energized, without exposing the technician to shock or arc blast hazards.
During a highly technical conversation about the life expectance of old and new electrical transformers, MIDWEST was asked by the Consulting Team what the most common failure mode for outdoor oil filled power transformers was. The discussion involved 1000 kva to 10 Mva power distribution transformers typically found in the outdoor substations of manufacturing plants. We were discussing Failure Mode and Effects Analysis (FMEA) and its value for reliability optimization. The consultant was using military data for failure mode and frequency of occurrence. There was poor connectivity between that data and our world of big old oil transformers used by industry. It was even less appropriate to use historical military data on the new oil transformers used today to replace those old tubs. The whole thing was rather ridiculous as every one struggled to find legitimacy in the analysis. The solution came with a twist from a reliable and too often forgotten source.
MIDWEST’s senior field service technicians and service engineers were asked what the most common failure mode was, based on their experience, experience that exceeded 100 years. Their one word answer was, “Raccoons.” After the technical minds recovered and realized the answer was more than just a little jab and a lot hilarious, they realized it was true. So now they asked what should be done to lower the probability of this critical failure mode. The answer, “No raccoons.” Problem solved.
MIDWEST performed an Infrared Scan of the electrical system for a new customer. They had two old outdoor oil filled transformers with load tap changers that had not been used in some time. So when we scanned these old transformers, we made certain we scanned the load tap changer compartments. Each tap changer was dangerously over heating. The electrician with us wondered why, since they hadn’t operated the tap changers in 20 years. But tap changer contacts can cause coking, especially if they are not operated. Later, during a scheduled maintenance outage, MIDWEST found both load tap changer compartments completely coked, full of black sludge. The sludge had to be removed by hand, like scooping out sticky black mud. Since they would never use the transformer tap changers again, MIDWEST removed the entire interior operating mechanisms and bussed the terminals. The old transformers were very lucky the tap changers didn’t fault. If they had, it would not have been cost effective to repair them. It was just a matter of time before a catastrophic fault in a tap changer would have cost them a transformer. We have seen this problem before in old transformers. In this case, certain failure was avoided, and they reused the transformer after the repair. Infrared Scanning is very important, even on old, obsolete transformers and switchgear.