In the same way a blood test can provide a doctor with a wealth of information about their patient, taking an oil sample enables service engineers to learn a great deal about the condition of a transformer. This can play a key role in the effective management of a vital network asset for extended life and enhanced reliability. Liam Warren, ABB's general manager power service explains
The oil in a transformer acts as both a coolant and insulation for the internal components. In doing this it bathes almost every internal part. As a result, the oil contains around 70% of the available diagnostic information for the transformer. The challenge is to access this information and analyse it effectively to provide an early indication of a developing condition such as tap-changer arcing.
Obtaining a representative sample
The data generated from an oil sample is only as good as the sample itself. A poorly drawn or contaminated sample can invalidate the test results or even lead to a misdiagnosis. At ABB we have recently upgraded our sampling procedure to use the TFSS (Turbulent Flush Sampling System). This compact, self-contained system provides several benefits including:
- promoting turbulent flush
- standardizing flush volumes
- producing a representative sample
- preventing sample contamination
TFSS ensures the sample is representative of the oil inside the transformer, rather than any contaminates that might have settled into the valve.
Transformer condition assessment (TCA)
Traditional oil-testing programmes utilise only a few diagnostic parameters, leaving a vast amount of potential oil-based information unexplored. Yet surveys of failed transformers reveal many failures can be attributed to problems that could have been properly managed with an early diagnosis through a more detailed analysis of the insulating fluid.
ABB bridges this gap by working with a leading test laboratory to provide TCA (transformer condition assessment). TCA offers a comprehensive assessment of the dielectric and mechanical state of the transformer including:
- Dissolved gas analysis (DGA)
- Insulating fluid quality analysis
- Particle analysis
- Furan analysis
DGA - a view of operational condition
Hydrocarbon (mineral base) oils are frequently used as insulating fluids in high voltage power equipment such as transformers because of their favourable dielectric strength and chemical stability. Normal degradation of the oil usually occurs due to oxidation. This is generally a slow process. However, under the influence of an electrical or thermal fault, the oil can degrade to form a variety of low molecular weight gases that dissolve in the oil (such as methane, ethane, ethylene, acetylene, hydrogen, carbon monoxide and carbon dioxide).
The composition of the breakdown gases depends on the type of fault, while the quantity depends on its duration. Hence by dissolved gas analysis (DGA) it is possible to distinguish such transformer fault processes as partial discharge (corona), overheating (pyrolysis) and arcing.
DGA involves two steps - extraction and chromatographic analysis. In the first step, the gases are extracted by subjecting the oil sample to high vacuum. The volume of the extracted gases is measured and a portion of the gas is transferred to a gas chromatograph.
The great sensitivity of the chromatographic process enables low detection limits for each gas - at the parts per million level. The remarkable sensitivity and precision of this method ensures a high measure of reliability for the diagnostic interpretation of DGA data.
Based on the dissolved gases in the transformer oil it is possible to indentify faults such as corona, sparking, overheating and arcing.
Corona - is a low energy electrical fault that results from the ionization of the fluid surrounding the fault. Typically, this is characterised by an increased level of hydrogen without a concurrent increase in hydrocarbon gases.
Sparking - is an intermittent high voltage discharge that occurs without high current. It is characterised by increasing levels of hydrogen, methane and ethane without a concurrent increase in acetylene.
Overheating - can arise from a variety of causes, such as overloading, circulating currents, improper grounding and poor connections. It is characterised by the presence of hydrogen together with methane, ethane and ethylene.
Arcing - the most severe fault process, involves high current and high temperatures and may occur prior to short circuit failures. It is characterised by the presence of acetylene.
Faults involving cellulose insulating materials, such as impregnated paper, wood and pressboard, result in the formation of carbon dioxide and possibly carbon monoxide. In load tap-changers, thermal problems are characterised by elevated levels of ethylene.
Interpretation of DGA data can be a complex process because of the large number of equipment parameters and operating conditions that affect gas formation. It is important to take into consideration the operating philosophy and past history of the transformer. Establishing baseline values for a transformer against which future DGA tests can be compared is a very effective diagnostic testing procedure. Monitoring the rate of gas generation makes it possible to assess the progress of the fault process.
Insulating fluid quality analysis - a view of how the transformer is being managed
There are a number of routine tests on the insulating fluid that provide a useful indication of how well the transformer is being managed in service. They cover a number of key parameters including PCBs, moisture, acidity and dielectric strength.
Although not related directly to the transformer performance, it is still important to identify the presence of the chemicals known as Polychlorinated Biphenyls (PCBs) in the insulating fluid. PCBs were very popular in the late 1950s/early 1960s as an alternative to mineral oil thanks to their excellent insulating properties. They are however highly toxic and have been outlawed for many years. Unfortunately, PCBs were in service for long enough to cause some cross-contamination with mineral oil stocks and it is relatively common to find some background traces in older transformers. No immediate action is required at levels below 50 ppm. At levels between 50 to 500 ppm the transformer needs to be taken out of service when possible so that it can be flushed and re-filled with fresh oil. At anything greater than 500 ppm immediate action is required.
An increase in the oil's moisture content can degrade its insulating properties and result in dielectric breakdown. This is especially important when a transformer is subjected to fluctuating temperatures, possibly when in intermittent operation, as the cooling down process causes dissolved water to come out of solution, reducing the insulating properties. In addition, cellulose-based paper is in common use as insulation for the transformer windings and the presence of excess moisture can damage this paper.
Increased acidity not only cause the oil to attack the many copper components in the transformer as well as corroding the steel tanking, it also degrades the paper insulation. Acids can also cause the formation of a sludge that blocks ducts and cooling galleys, resulting in less efficient cooling - resulting in further degradation of the oil. As a general rule, the oil must be replaced when the acidity exceeds 0.5 mg/g KOH.
The dielectric strength of the transformer oil is a measure of how effective an insulator it is. Factors that can cause a significant reduction in dielectric strength include the presence of contaminants that result in an increased content of free-ions and ion-forming particles, such as water, oil degradation products and cellulose insulation breakdown products.
One of the major advances in extracting a higher level of diagnostic information from transformers has come from the identification of suspended and sedimented particles found in the oil. When the DGA analysis indicates the presence of a possible fault, particle analysis will provide corroboration and pinpoint its location. For example, in one analysis the DGA results suggested that heating gases and carbon oxide gases were present, indicating a hot spot. The microscopic analysis confirmed the hot spot condition with the presence of charred paper in the oil.
Furan analysis - a view of remaining life
In general, the life of a well maintained transformer with no serious operating defects will be determined by the condition of its insulating paper. As the paper degrades it produces organic compounds known as Furans. There is a direct relationship between the amount of Furans produced and the strength of the paper insulation. Furan analysis can therefore provide a useful estimate of the transformer's remaining service life.
Oil sampling becomes most useful when carried out on a regular basis so trends may be identified. So it is useful to take a benchmark sample when a transformer has been energised or an oil treatment performed and to then take further samples at regular intervals so that any variation in quality can be measured in order to monitor developing faults.
The battery of sophisticated analysis techniques available to monitor the quality of the oil form a valuable diagnostic tool that provides an indication of the general condition of a transformer, how well it is being managed and how long it can be expected to function before requiring a major service or replacement. Perhaps most importantly, it can be used to anticipate severe faults, enabling preventive action to be taken before they occur.