The Most Costly Piece of Equipment in a Substation is the Power Transformer. As part of the transformer assembly, high-voltage bushings allow current to pass through a barrier while providing insulation between the center conductor and ground.

In most modern bushings above 26 kV, paper provides the skeleton for the insulation system. The design typically consists of concentric layers of insulation and layers of conductor foils, which allow the voltage to be graded in a uniform manner. These layers of insulation and conductors form a concentric capacitor between the high-voltage center core and the bushing flange at ground potential. The paper is impregnated with mineral oil to provide more insulation, and the oil level inside the bushing must be maintained to prevent a breakdown in the insulation.

A common cause of failure in these bushings is oil leakage, which can lead to catastrophic destruction and a power outage. The tendency for this to happen is due to voltage gradients that are much higher in the bushings than in the transformer tanks. Therefore, it is important to have a predictive or preventive maintenance program that verifies the oil level and insulation integrity of the bushings.

Infrared (IR) thermography is the most efficient way of doing this. With this technology, a handheld IR camera can be used to determine the oil level in a bushing from a safe distance, even when oil leaks are not visible. An understanding of thermography basics will help users get the most out of their cameras and initiate appropriate maintenance activities when a bushing with a low oil level is found.

SMALL OIL LEAKAGE

If a small amount of oil has leaked out of a bushing, then air will enter to fill the space. As the temperature changes, the air will expand and contract, having the effect of breathing in and out. Since air contains moisture, this breathing action allows moisture to migrate into the bushing. Moisture attacks the oil and causes it to break down chemically.

The chemical action due to moisture is a weakening of the glucose molecule chains that make up the paper insulation skeleton. As the glucose chains break down, the paper loses its mechanical strength. In addition, as the insulation deteriorates, certain acids are generated, further attacking the oil and paper. Making matters worse, the byproducts are electrically conductive to some degree.

If this action continues, the foil layers will begin to short out one by one. Each layer that fails causes even more stress on the others. As time passes, the insulation breaks down to the point of a flashover between the center conductor and ground flange. Unless enough oil has leaked out of the bushing to drop its level significantly below the full line, this failure mode is hard to detect with IR thermography. Therefore, other test methods may work better, but the equipment must be taken off-line for testing.

Usually, modern bushings have a potential tap or a test tap. This tap allows the bushings to provide a proportional voltage at the tap and allows the bushing to be tested when de-energized. This off-line electrical testing is intended to find problems before a catastrophic failure occurs. So, electrical equipment is periodically taken out of service to be inspected and tested.

The power-factor test is the industry standard for checking bushings when the equipment is out of service. This test basically checks the electrical leakage current across the insulation system and checks the capacitance values. If there is a change in the leakage current by a few tenths of a percent, or if the capacitance increases by a few percent, the bushing integrity is called into question and raises a concern. Depending on the history of previous tests, the bushing may be tested more often or scheduled for replacement.

Off-line testing is costly because it takes equipment out of service. Moreover, disconnecting and preparing the equipment for testing requires a great deal of resources.

CONTINUOUS OIL LEAKAGE

Sometimes a slow, continuous leak can be seen with the naked eye but not always. The bushing can leak inside the tank where it is not visible. As oil continues to flow out of the bushing, moist air enters to replace it, as described previously. However, the effect is more severe and failure develops more quickly. The paper becomes void of oil, and the insulation system is unable to properly grade the voltage. Increased areas of electrical stress then cause electrical discharges to develop. These corona discharges eat like worms through the paper, thus causing foil layers to short out.

Of course, the deteriorating insulation is likely to be detected with off-line test methods. Unfortunately, today's off-line test intervals have been pushed out so far that a bushing can develop a leak and fail before the next scheduled test. To protect against such failures, an IR scan and visual inspection are absolutely necessary on an annual basis at a minimum. The higher the voltage, the more critical this becomes.

BUSHING THERMOGRAPHY

To detect the oil level of bushings with an IR camera, one must be aware of the thermographic principles that allow the oil level to be seen. Effective thermography requires a temperature differential on the target object or across multiple objects within the IR camera's field of view. In some cases, the camera is detecting the temperature difference between the target object and its background, such as the sky or the ground.

Under no-load conditions, the temperature rise in a power transformer is due to an energy loss arising from magnetizing current in the transformer core. This will cause a rise of a few degrees above ambient. As a transformer picks up load, copper losses will increase and produce a larger temperature difference. The heat in the iron and the coils of the wire will heat up the oil inside the transformer tank. Some of this heat energy is transferred to the bushings through thermal conduction. The thermal conductivity of the oil inside the bushing allows the bushing oil level to be detected by an IR camera. The bushings will appear warmer where there is oil and cooler where there is no oil.

When properly used, and with adequate sensitivity, modern IR cameras can detect small differences in the thermal patterns of electrical equipment. Most, if not all, of these cameras are calibrated to measure the actual temperature; a typical camera's absolute accuracy is ±2°C (3.6°F), with a resolution (the smallest detectable differential) of about ±0.08°C (0.14°F). Still, different cameras have different types of IR detector arrays with different levels of sensitivity. The more sensitive the camera, the better it is at detecting small temperature differences in the bushing, which results in a clearer image of the boundary line that indicates the oil level. Furthermore, different types of transformers and bushings may require a more sensitive camera or finer camera adjustments.

For example, smaller transformers that do not carry load but feed instruments typically have much smaller temperature differentials compared to power transformers. These instrument transformers look like a large bushing sitting atop a small container, and their source of heat is rather small compared to high-voltage bushings. To collect meaningful data on the instrument transformer bushings, it is best to compare similar units under similar conditions. Just two or three degrees of difference between similar units can be an indicator of trouble.

In making such comparisons, IR cameras typically offer different options for selecting the target area of the object being measured. For example, the target area could be defined as a single spot, a geometric area or a line profile. The latter measures the temperature profile along a straight line, which is defined by the camera operator using camera configuration tools. A line profile is particularly useful in measuring small temperature differences from top to bottom of an instrument transformer bushing to reveal a low oil level.

INTERPRETING RESULTS

A low oil level in bushings is more frequent than one might think and should not be taken lightly. It is a ticking time bomb just waiting to go off. However, thermograms can be misinterpreted by inexperienced users or observers. Furthermore, some bushing problems can go undetected with both visual and IR inspections. Even when a low oil level is found, a more drastic action than simply refilling and testing may be needed.

On a transformer failure in 2006 at Tennessee Valley Authority (TVA; Knoxville, Tennessee, U.S.), the results of a root-cause investigation reported the refilling of a bushing when it was found to be extremely low on oil. In 1999, the bushing had been shipped off-site to be refilled and tested. It was subsequently shipped back to the site and placed in the transformer. The bushing was run through another full battery of tests and passed all of them. Still, all did not end well for the bushing or the transformer. The bushing failed in just a little over six years after being refilled.

This incident and other investigations point out that refilling a bushing low on oil is not the answer for reliable, long-term service. Doing so will tend to mask a problem more than fix it. TVA has changed its policy to not refill bushings after they are found to be low on oil. Instead, they are replaced with new or rebuilt bushings to prevent the type of failure that occurs because of slow, continuous leaks and moisture ingression.

Visual inspections work for external oil leaks. They are also good for observing level gauges and sight glasses. However, gauges can malfunction and sight glasses may become stained and hard to see through. Therefore, visual inspections need to be combined with IR scans that are performed and interpreted by a qualified thermographer. This two-pronged approach will save time and money while keeping the equipment in service. Nonetheless, when equipment comes out of service for any reason, a full battery of tests is always a good idea.

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Mark B. Goff (mbgoff@tva.gov) is a staff system engineer for Tennessee Valley Authority. He received a BSEE degree from the University of Kentucky in 1983 and went to work for TVA as a field test engineer at its Paradise Fossil Plant. He joined TVA's transmission staff in 1990 as a lead engineer for substation large-power equipment. Since being on the staff, he has developed the predictive maintenance program for TVA's substations. In 2006, he received EPRI's Power Delivery & Markets Product Champion Award for his work at the Paradise substation. He is a registered professional engineer in Kentucky.

BULL-RUN TRANSFORMER BANK FAILURE

A Bull-Run transformer bank failure occurred on Sept. 11, 2007, even though the transformer had been taken out of service just three months earlier for a full set of electrical tests, including a power-factor test; no problems had been found. After the failure, the spare transformer was put back into service and a root-cause analysis was performed on the failed transformer.

A thermogram of the failed transformer bushing had been taken during a routine inspection 15 months prior to the failure. The entire bushing had a higher temperature than the ambient background, which was initially misinterpreted as a low oil level. Such a misinterpretation can occur with inexperienced observers, because high temperatures are often an indication of electrical equipment problems. However, a bushing's temperature is higher where there is oil and lower where there is no oil.

In fact, the bushing cap in that thermogram appears the warmest (bright yellow in the thermogram), because heat conducts better through the metal can at the top of the bushing, as compared to the thicker porcelain insulator below. An underlying problem of the thermogram was the temperature span set by the camera operator. The span was too wide for the temperature range across the bushing. A narrower temperature span would have shown the oil level to be near the top of the metal can.

The root cause of the failure in this bushing was moisture ingress through a chipped oil-level sight glass. This is similar to a failure where a finite amount of oil has leaked out, only to be replaced by moist air. However, in this case, the chip in the sight glass was above the normal oil level, so the oil could not leak out. Nevertheless, the chip created an opening where moisture could get into the bushing. The moisture found its way to the bottom of the bushing as free water and compromised the insulation, causing a flashover and bushing failure. It was concluded this type of failure could not be detected by normal visual or infrared (IR) inspections. Furthermore, a power-factor test and hot-collar test were performed just three months prior to the failure and no problems were found.

Many oil-leakage problems, however, can be detected when IR scans are performed by qualified thermographers. Upon returning the transformer bank to service, an IR scan indicated one of the bushings on the spare transformer looked strange. Instead of the oil being just a little low, the observer noticed the 161-kV bushing's oil level was extremely low. The oil level was just above the ground flange. This was verified with two different IR cameras. The transformer was taken out of service and the bushing replaced.

In this incident, there was a lack of understanding of the initial IR image, which delayed repair of the transformer. Verification was required with another IR camera before the transformer was removed from service.