Power transformers are the most expensive and critical pieces of equipment in a power distribution system. Ensuring they are running to optimum capacity and in good condition is thus crucial. Fault detection techniques serve as a warning to developing abnormalities in a transformer; and these techniques have many parameters of measurement and visual inspection.

Present-day transformers are operated at rated loads and, thanks to an ever-increasing demand for power, many a time at overload. It therefore becomes necessary that transformers are monitored regularly to assess faults and ensure that preventive or corrective actions are promptly taken. Condition monitoring also helps in the assessment of the remaining life of the transformer, ensuring that utilities are not caught unawares by sudden transformer breakdowns which almost always result in severe losses.

Factors that Contribute to Transformer Aging

There are numerous factors that are responsible for transformer aging. Controlling these variables can actually augment the lifespan of a transformer:

• Quality of oil
• Operating temperature
• Amount of oxygen present
• Water content in the insulation – which can cause molecular chains to decompose, speed up the cellulose aging process and adversely affect the tensile and dielectric properties of the insulation
• Contaminants

How oil by-products degrade the insulation system of transformers

Hydrocarbon or mineral-based oils and silicones are used as insulation fluids in transformers because of their high dielectric strength, heat transfer properties and chemical stability.

Under normal operating conditions very little decomposition of the dielectric fluid occurs. However, when a thermal or electrical fault develops, dielectric fluid and solid insulation will partially decompose. The low molecular weight decomposition gases include hydrogen, methane, ethane, ethane, acetylene, carbon monoxide and carbon dioxide. These fault gases are soluble in the dielectric fluid. Analysis of the quantity of each of the fault gases present in the fluid allows identification of fault processes such as corona, sparking, overheating and arcing.

Tests to check for Transformer Degradation

• Visual inspection
• Infrared thermography inspection
• Analysis of dissolved gases in oil
• Analysis of oil properties
• Humidity in paper
• Antioxydan
• Furanne
• Winding and bushing power factor
• Winding bushing and core insulation resistance
• Winding resistance

On-line monitoring devices are also available to measure temperature, gas in oil, humidity in paper, and vibration signature of load tap changers. The frequency at which testing is conducted varies with the test, importance of the equipment, whether an incipient-fault condition is known to be present or a problem exists, and when a family of transformers has been identified as having a history of problems.

The life of the transformer can be indicated by the condition and rate of deterioration of insulation. The main insulating materials in the transformer are transformer oil and the kraft paper. Due to thermal and electrical stresses both these materials degrade giving rise to reaction products that can be used for monitoring the extent of damage or incipient faults. The rate of deterioration further depends on the operational conditions.

Commonly used Diagnostic Testing to determine Transformer Degradation

The following are typical diagnostic tests used to determine transformer degradation:

• Oil Testing

  Oil Testing, both of new and old oil has its usefulness. New oil testing is done to check its suitability in a transformer. Testing of used oil is required for condition monitoring of a transformer and to determine its life. Testing of transformer oil using Furanic Compound Analysis is considered a reliable indicator of integrated and cumulative degradation of cellulosic material present in the transformer. The furan data on a transformer fluid measures the average decay integrated over the entire volume of the transformer insulation.

• Dissolved Gas-in-Oil Analysis

  Dissolved gas-in-oil analysis (DGA) is performed in accordance with ASTM D3612 or IEC 60567. It is, by far, the most frequently requested diagnostic test and the single most important test performed on transformer oil.

  As the insulating materials of a transformer break down from excessive thermal and electrical stress, gaseous byproducts form. The byproducts are characteristic of the type of incipient-fault condition, the materials involved and the severity of the condition.

  It is the ability to detect such a variety of problems that makes the dissolved gas-in-oil analysis such a powerful tool for detecting incipient-fault conditions and for root-cause investigations after failures have occurred. Dissolved gases are detectable in low concentrations (parts-per-million or ppm level), which usually permit early intervention before failure of the electrical apparatus occurs, and allow for planned maintenance.

  The DGA technique involves extracting or stripping the gases from the oil and injecting them into a gas chromatograph (GC). Detection of gas concentrations usually involves the use of a flame ionization detector (FID) and a thermal conductivity detector (TCD). Most systems also employ a methanizer, which converts any carbon monoxide and carbon dioxide present into methane so that it can be burned and detected on the FID, which is a sensor of, well, great sensitivity.

Frequency of Inspection

The frequency of inspections is determined by the usage and importance of the transformer. This may be a daily or weekly inspection, a semi-annual or annual inspection, a triennial or quinquennial inspection.

A daily or weekly inspection allows for the detection of any operational abnormalities, as well as any increase in the temperature of the oil or a number of operational abnormalities in the load tap changer.

How often tests are carried out is a decision made following the analysis of historical data and the importance of the equipment. If there is no historic data and there is new or newly repaired equipment, we have to adopt a tight sampling rate - say a couple of weeks to a couple of months between each sampling - and when we are convinced of the integrity of the unit we reduce the rate.

Conclusion

In a power grid that is already showing many signs of advanced age, transformer inspection and monitoring is an increasingly important task. With the coming of the Smart Grid and newer technologies, many of the existing systems will be forced to adapt – or fall behind. Utilities have a lot to plan and invest across the next few years, and keeping operations at optimal conditions till the big change comes is imperative.