Testing the oil in load tap changers (LTC's) provides valuable information on the operation of the unit. Monitoring conditions between preventive maintenance inspections is a critical step in preventing expensive maintenance problems and even unplanned outages. This first article in a series will address the aging of mineral insulating oil in an LTC.
You cannot just change the oil to lower the acid number to an acceptable level in place of a hot oil cleaning. Changing the oil will not permanently reduce the oxidation byproducts in the solid insulation. It is not an appropriate maintenance solution for lowering a high acid number.
Whenever there is excessive oxidation of the oil and aging of the paper insulation, the service recommended most often is hot oil cleaning. This valuable process involves the use of a mobile oil processing unit (a.k.a. vacuum oil processor or “VOP”) or oil reclamation “rig,” with the use of filtering clay such as Fuller’s Earth. The oil is reclaimed in the VOP through heating and vacuuming and sub-micronic filtration, and then returned to the equipment that is being cleaned.
Most mineral oil dielectric fluids contain an added oxidation inhibitor which is a chemical additive that acts as a preservative. The purpose of the inhibitor is to prevent oxygen from reacting with the oil, thus slowing the aging rate of the oil (and also of the solid insulation). The two most common oxidation inhibitors used in transformer oils are 2,6-ditertiarybutyl para-cresol (DBPC) and 2,6-ditertiary-butyl phenol (DBP).
Occasionally, we get questions from customers regarding whether two particular insulating liquids are compatible. For example, a customer may contemplate retrofilling with a different fluid, or adding fluid to a unit (“top-off”), but the original fluid is no longer being made. In any case, how do you determine a compatible substitute fluid?
As perchloroethylene fluid ages in service, it breaks down and forms hydrochloric acid. The AGE additive acts to neutralize this acid, so that the acid does not react with the metals in the transformers.
After the AGE test, the amount of acid remaining is measured, giving an indication of concentration of AGE in the sample. The result is compared to three calibration standards that are also run with the same procedure: a clank, a 1000 ppm AGE standard, and a 2000 ppm AGE standard. The response of the sample is compared with the response of the three standards to determine the concentration of AGE in the sample.
What causes bad D1816 dielectric breakdown voltage values? The first article in this series will discuss the three standard methods that SDMyers is equipped to perform, and why we perform them for our customers. There are two standard methods from ASTM International: D877, Standard Test Method for Dielectric Breakdown Voltage of Insulating Liquids Using Disk Electrodes, and D1816, Standard Test Method for Dielectric Breakdown Voltage of Insulating Oils of Petroleum Origin Using VDE Electrodes.
The Corrosive Sulfur test is a laboratory test performed on electrical insulating liquids of petroleum origin that detects the presence of corrosive sulfur in the sample. In Part 1 of this three-part series on the Corrosive Sulfur test, we will define corrosive sulfur, briefly review the history of the issue, and describe how corrosive sulfur can cause a transformer to fail.
When thinking about when the Corrosive Sulfur test should be performed, it helps to consider the operating conditions of the transformers that have actually failed due to corrosive sulfur. Therefore, as a general guideline, if a mineral oil-filled transformer was manufactured or retrofilled since about the year 2000, and if it spends at least six months of the year with its top oil at a minimum of 70°C, then we recommend that the oil be tested for corrosive sulfur.