In the early 20th century, there was a need for utilities to regulate voltage quickly. At that time, it could only be performed by deenergizing the transformer, changing the tap and then reenergizing the transformer. Not exactly a quick task. In response to this, Dr. Bernhard Jansen in Germany began to develop a system to change taps under load in 1926 and by 1929, the first load tap changer or on-load tap changer (LTC/OLTC) protype was developed by Dr. Jansen, Anton Schunda, and the Scheubeck brothers.

Ever since, LTCs have been critical in the operation of the electrical grid by enabling the transformer to maintain a stable output voltage despite fluctuations in input voltage or load changes. Today, there are many types and styles of LTCs including reactive, resistive, break-in-oil and vacuum types.

Since LTCs are mechanical devices and parts would wear or issues with contacts would develop over time, the operation count of the LTC was used as an indicator of when maintenance should be performed. The deterioration of LTCs overtime because of the mechanical issues makes them one of the weaker links in the utility network. Erosion of the contacts is expected due to the nature of their function. Coking of the contacts causes overheating, which can cause thermal runaway.

Today, transformers are expected to last way beyond their design life which is 20-25 years at rated voltage.

Transformer life in the United States is much beyond that with the average life span currently at 45 years. In a 2025 Doble conference, it was reported that several large utilities are now expecting their transformer assets to last 70 years or more. But there is a catch, what about all the moving parts in an LTC that will not last 70 years. An LTC failure can easily cause collateral damage to the transformer and decrease its lifespan. Thus, there is much emphasis placed on making sure the LTC operates correctly over time.

There are a number of strategies to maintain LTCs, including periodic, time-based maintenance, conditionbased maintenance, or some combination of both. Periodic maintenance can work if sufficient resources are utilized such that these activities occur at shorter time intervals than the gestation time of expected excessive wear and tear or development of problems into failures. To do this well, the time chosen must be conservative enough to catch most problems but increases cost of maintenance and often issues are not found. Conditionbased maintenance relies on tools which can detect most problems early enough that maintenance can be scheduled and performed. In most cases, condition-based testing is performed while the apparatus is in-service so that any down time is reduced or eliminated.

Oil testing has long been recognized as an important tool for detecting incipient-fault conditions in the main tanks of transformers and is being applied to load tap changers. Some of the advantages of oil tests are that they:

• can usually be performed while the equipment remains in service
• can detect a wide range of problems in the early stages
• can be used to ascertain a reasonable sense of the severity of the problem
• have been shown to be very cost effective

This testing is used to provide one of the most important early warning diagnostics for LTCs.

Although many of the common oil tests such as dielectric breakdown voltage, interfacial tension, acid content, particle count, metals analysis, etc. provide valuable information used in many LTC diagnostic programs offered by commercial and utility laboratories, this article will focus specially on DGA and water content.

Dissolved Gases in Oil: This is the most important oil test for LTC diagnostics. As insulating materials deteriorate byproduct gases are generated. Normal deterioration produces gassing patterns which are typical for a specific family which includes the model, type of breathing, and compartment. As problems manifest the gassing behavior changes which includes both the amount and most often the pattern or relative composition of gases in oil. Problems include localized overheating and/ or excessive arcing and other abnormalities. Localized overheating of conductors and surrounding insulation may lead to carbonization and byproduct polymeric films forming on conductors, which creates a runaway thermal condition.

Water Content: Excessive water reduces the dielectric breakdown strength of the oil and can accelerate the aging of the contacts. Excessive water in the solid insulation can result in tracking and ultimately an insulation failure. The water content will vary depending on if the compartment is sealed to the air, free breathing or has a desiccant breather. Compartments with arcing contacts in oil will often be vented to reduce the combustible gas concentration generated in the operation of the device. In such cases, the relative saturation of the water in oil will be driven by the ambient humidity and altered by the difference in the temperature of the ambient air and the oil. Increasing the temperature of the oil above that of the ambient air lowers the relative saturation of water in oil. Under equilibrium conditions, expected amounts of water in oil can be quantified and therefore makes it possible to estimate what concentrations are excessive.

As the oils from LTCs can contain considerable byproducts from the deterioration process, it is very important to take care in sampling to avoid cross contamination and obtain a representative sample. Experts recommend flushing enough oil to remove condensation in the valve and excessive carbon and debris that has formed as sediment on the bottom of the LTC. If enough oil is not removed, then a “false positive” can occur where the analysis indicates a problem with the LTC where one really may not actually exist.

It is critical to use new tubing each time as plastic materials have a “memory effect” where some of the gases dissolved in the oil will adsorb in the plastic only to desorb in the next sample that contains less of the gas. This can be particularly troublesome as the gases are not visible and different types of LTCs have very different normal gas concentrations. Cross contamination is of concern when taking samples from LTCs and thus the use of clean compatible sample containers is required.

Make sure the LTC is under positive pressure. This can be done by introducing a slug of oil into the tubing attached to the valve. Open the valve slowly and watch the movement of the oil slug. If it moves away from the valve, then there is positive pressure and flushing can continue. If the oil slug moves towards the valve, the valve should be immediately closed and the LTC should be brought back to positive pressure.

As with any sample from electric apparatus, it is necessary to have sufficient identification that the test data can be linked to the equipment and proper diagnostics can be provided as many of the test results are based on the construction of the electric apparatus. This would include information from the nameplate such as manufacturer and serial number. For diagnostic purposes the minimum information that should be supplied with LTC samples is:

• Manufacturer of LTC
• Year of manufacturer
• Model
• Type – Vacuum or break in oil (this is often evident from the model information but not always)
• Compartment – selector, diverter
• Tank type – sealed, free breathing, desiccant breathing

Other information such as if the unit has a filtering unit on it or when the LTC was last maintained or oil handled is useful information for those performing the interpretation of results.

The goal of diagnostics is to provide a ranking that prioritizes maintenance activities. This goes beyond the simple good/bad distinction, to provide some grading to permit different management options.

The primary test for LTC diagnostics and condition assessment is that for dissolved gas-in-oil as this detects most of the problems. There are three main types of LTCs, reactive with arcing contacts in oil, resistive with arcing contacts in oil and arcing contacts in a vacuum bottle. There should be differences in the gassing behavior between resistive and reactive types as the shorter time of arc extinction of the resistive type (5-6 ms after contact separation) should lower the concentrations of gases generated. However, it has been our experience that the gassing behavior of different models of LTCs are so different that generic rules for reactive and resistive LTCs are not adequate. The primary diagnostic gases used to develop condition codes are methane, ethylene and acetylene. In addition, three ratios are used:

• ethylene/acetylene distinguishes between thermal and electrical discharge activity in oil
• methane/acetylene distinguishes between thermal and electrical discharge activity in oil and can also detect partial discharge activity as a predominant gassing pattern
• (hydrogen + acetylene)/(TCG – carbon monoxide): Ratio of gases associated with discharges to those associated with overheating of oil. This is similar to a ratio proposed previously which included the carbon monoxide in the TCG.

A matrix has been developed for each model that includes concentration limits for each of the three diagnostic gases plus the three ratios. Points are assigned for each limit and then summed, with a total point range between 0 and 15. Condition codes are then determined from the points as shown in Table 1. A Condition Code of 1 indicates an LTC in the worst possible condition that should be the number one priority. A Condition Code of 5 would indicate an apparatus in good condition and the lowest possible on the list for sample frequency.

Condition codes 3-5 have a range for sample frequency. This is based upon the experience that the time from inception to complete failure, particularly for thermal runaway conditions, is shortened considerably if overloading significantly beyond nameplate on a regular basis. The matrix is structured to find a variety of problems which may be detected by excessive gassing rate, change in gas ratios or both. For example, localized overheating of contacts or the reversing switch will generally show increasing combustible gas generation with ratios of gassing going from an arcing pattern to characteristics of high temperature overheating of oil. Excessive arcing between contacts is most likely to develop high gas concentrations until the later stages when heating occurs (causing the combustible gas ratios to change). Examples of causes of overheating include:

• excessive contact resistance due to the formation of organic films and carbon deposits
• metal fatigue causing poor contact pressure
• loss of direct contact surface area from misalignment or loss of contact material

Excessive combustible gas buildup can result when the vent becomes plugged. This eventually leads to low oxygen contents as it is consumed in oxidation reactions and is not replenished. Typically, the ratios will remain normal unless another problem is present at the same time.

Various other thermal and electrical problems can also be detected depending upon the model of LTC.

The diagnostic matrix for selector compartments and vacuum type models that break under vacuum is different. The ratios do not apply in the same way for vacuum type LTCs and therefore, absolute concentration limits for the gases are relied upon to determine the condition codes. Condition codes are generated with the same type of ranking as for arcing contacts-in-oil compartments.

This diagnostic scheme has been very successful over the past years in determining which LTCs have problems that need remediation and many “saves” have been reported on an annual basis.

Oil testing is just the first step in the diagnosis of LTCs with potential problems. There are a number of nonoil tests that have been employed to confirm or identify LTC problems. These include the following:

Infrared thermography and temperature differential: A frequently used method to detect or confirm overheating of contacts or the reversing switch in externally mounted LTCs is to determine the temperature difference between the main tank and the LTC. Normally the main tank should be operating at a higher temperature than the LTC compartment except for the occasional transient such as when the pumps initially come on to cool the main insulation. As thermal problems develop in the LTC compartment the oil temperature will consistently be higher than the main tank. This difference in temperature can be detected using continuous temperature monitors mounted to the tank wall or by periodic inspections using infrared thermography.

Electrical tests: There are a number of electrical tests that can be used to confirm or help identify the source of LTC problems before entering for visual inspection.

• Exciting current tests on all LTC tap positions can be used to detect shorted turns and core problems in the preventive autotransformer, contact problems and connection problems in the preventive autotransformer or in taps.
• Turns ratio can detect shorted turns in the preventive autotransformer.
• Power factor tests are used to detect insulation deterioration such as from water and partial discharge activity, including tracking and carbonization of solid insulation structures.
• Contact resistance is used to detect excessive contact wear, poor contact pressure, coking and polymeric films on contact surfaces.
• Sweep Frequency Response Analysis (SFRA) and leakage reactance (short circuit impedance) are both used to detect winding movement or deformation and contact problems.

Acoustic and vibration analysis: Some investigators have developed a database of LTC signatures using acoustic analysis to complement diagnostic programs for LTCs.

To illustrate the LTC diagnostic program several case studies are presented. The details of the LTC for this case are listed in Table 2. The DGA results in Table 3 show the combustible gas values were high and the ratios indicative of an abnormal condition. The OLTC was assessed as being in an emergency condition and immediate remedial action was needed. The concentrations of the hydrocarbon gases associated with overheating were extremely elevated and the ethylene/ethane ratio was far more than what was considered normal.

These markers pointed to a severe thermal condition. Based on the DGA, an internal inspection was performed. Figure 1 shows the issue was on the stationary side of the reversing switch on one of the outside phases. Two of the good phases showing normal wear are given in Figure 2. The damaged part was replaced and the LTC returned to service.

DGA has gained wide acceptance in the industry for assessing the LTC condition and has become standard practice electrical networks all over the world. Doble has found that once oil diagnostic programs are started for LTCs, problems that were not being detected by other methods are revealed and, in many cases, sooner as the time intervals between sampling is shorter than most other maintenance or testing activities. After using oil diagnostics for all the LTCs in a system, the number of problems found the second time around is reduced showing the effectiveness of the program.

This article was originally published in the June 2025 issue of the Transformer Technology magazine, which you can access here.

To download the PDF version of this article, click here.