To ensure the safe and reliable operation of electrical equipment in substations, regular testing and maintenance carried out by professionals is essential. Power transformers are, however, critical assets that cannot always be made readily available for condition assessment, so it’s essential to make the most of opportunities for testing when these do present themselves.
This article doesn’t describe detailed test procedures, but it does provide safety suggestions and literature references that will be useful when performing transformer tests in the field. Creating hazard awareness while faithfully following safety guidelines and relevant standards are key elements of power transformer testing practice.
Question: Why is the transformer being tested?
Answer: Power transformers are typically tested in the factory, during commissioning, as part of a scheduled maintenance programme, after a system failure, and when their condition needs to be assessed. In each case, the applicable standards must be considered.
For factory tests, refer to IEC 60076-1 through to 8 (2000); IEEE Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers (C57.12.00); and to the IEEE Standard Test Code for Liquid-Immersed Distribution, Power and Regulating Transformers and Guide for Short-Circuit Testing (C57.12.90). For field tests, see IEC 60214-1; IEEE 62-1995 (R2005): IEEE Guide for Diagnostic Field Testing of Electric Power Apparatus - Part 1 - Oil Filled Power Transformers, Regulators, and Reactors; and IEEE C57.93-2007: Guide for Installation and Maintenance of Liquid-Immersed Power Transformers.
Routine investigation of insulation is also important; references can be found in IEC 60076 Parts 1 and 3 and Section 10 of the ASTM standards.
Responsibility for safety
Question: Who will be in charge of testing?
Answer: It is essential to understand the hazards involved in high-voltage and high-current testing and the need for tests to be performed by trained personnel. Recommendations are contained in each company’s Electrical Authorised Persons’ Rules and Procedures e.g. HSG85, JSP375 and Distribution Network Operators’ safe systems of work documents. There are other standards such as NFPA 70E, section 205.1, published by the US National Fire Protection Association (NFPA). Section 3.2.1 of NETA ATS-2009 also covers similar ground. One of the duties of the responsible person(s) is to ensure that appropriate personal protective equipment (PPE) is worn during testing.
Certification and calibration
Question: Is calibrated and certified equipment available for the tests?
Answer: Unfortunately, asset owners don’t always request a calibration certificate for equipment that will be used to carry out the tests. Nevertheless, the test company should calibrate field instrumentation annually, and the calibration should be directly traceable to recognized national standards.
Question: Why is a visual inspection needed?
Answer: Note that although the tests will be performed on a unit that is offline, nearby apparatus will be energised and will produce electric and magnetic fields. While the offline unit is being tested, lockout/tagout procedures must be followed.
When the environment has been made safe for testing, visual inspection can be started. This must always include checking the nameplate information, checking the earthing arrangements, verifying the presence of PCB content labelling, verifying that all connection points to testing equipment are clean, verifying liquid level in tanks and bushings, verifying operation of tap changers, and checking the operation and accuracy of temperature gauges.
Starting the job
Question: Where to start? Is there a standard test sequence?
Answer: The answer is no. The technician in charge should, however, avoid any possible remaining magnetisation of the core and residual charges in the insulation. It’s good practice to discharge and de-magnetise the unit before testing, as residual magnetism may affect test results. IEEE 62, in section 220.127.116.11, describes methods for demagnetisation. If the transformer has been in use, let it cool for at least two hours. Work with winding or top-oil temperature close to ambient, as the correction factors are more reliable.
Starting to test
First perform alternating current tests that will not affect the core’s magnetisation. Test each component of the transformer: windings, core, insulation, bushings and tap changers. For all tests, ensure that you have a good earth connection and that you have the transformer and the testing equipment in the same earth loop. For high-voltage tests, familiarise yourself with the applicable standards.
Turn ratio test
This uses a low-voltage signal. If possible, connect this to the high-voltage winding and use the measuring equipment to collect data from the low-voltage winding. If you must test the transformer from the low-voltage side, use the lowest available voltage.
Winding resistance test
The test is normally performed on each winding separately. Start from the high-voltage side and then move to the low-voltage side. Disconnecting the leads during current injection while performing the test may result in a high-energy discharge. Ensure you discharge and de-magnetise the transformer after running a direct current winding resistance tests. For large YΔ configured transformers, use the simultaneous winding magnetisation technique. This injects the test current through high-voltage and low-voltage windings simultaneously, shortening the measurement time.
Dissipation factor (tan δ) test
This is a high-voltage test. Be sure your testing equipment is properly earthed and safely connected to the transformer. You will almost certainly encounter electro-magnetic interference, which must be suppressed by the test equipment. Record the temperature of the insulation system and apply a correction factor to normalise the results to 20ºC, using either a table of factors or an individual temperature correction factor determined using sweep frequency technology. Verify bushings are clean and dry to avoid problems with leakage currents and also ensure that neither the high-voltage leads nor the measurement leads are in contact with any earthed point.
Excitation current test
This test is usually performed only on the high-voltage side of the transformer. Either a transformer turn ratio (TTR) tester or a dissipation factor test set can be used. The major difference is the test voltage. Never compare results for a test performed at 100 volts with a test at 10 kilovolts – they are very different, because of the widely differing excitation voltages applied.
Short circuit impedance test
When you short circuit the secondary winding for this test, a high current is likely to flow. Therefore, use jumper cables of at least 50 mm2 cross sectional area.
Insulation resistance test
You should discharge the transformer before and after performing insulation resistance tests so that personnel are not put at risk by residual charges. Be aware of possible leakage currents flowing on the surface of bushings and use the insulation resistance test set guard lead to minimise the effect of these currents.
This new test can detect many types of fault. It is straightforward, but it is essential to following standards and procedures to ensure repeatability. The test is sensitive to connections and set-up and you should be aware of the effect of noise on your testing device. The transfer function of many transformers reaches a value close to -90dB and sometimes down to -100 dB and, therefore, your instrumentation must have a wide dynamic range. Earthing practices are critical.
CIGRE 342 (2008): Mechanical Condition Assessment of Transformer Windings Using Frequency Response Analysis describes in section 18.104.22.168 how to use adjustable extension leads. Note that residual magnetisation in the core will affect ‘open circuit’ readings, so de-magnetize the transformer before performing SFRA tests. For more detailed instructions see CIGRE 342 section 2.4.8.
Diekectric frequency response (DFR) test
Insulation diagnostic testing using Dielectric Frequency Response (DFR), which is also called Frequency Domain Spectroscopy (FDS), is useful for determining the moisture concentration in solid insulation, the conductivity of liquid insulation and the temperature dependence of the dissipation factor. The procedure is similar to performing a tan δ test. The main differences are that with DFR, the capacitance and tan δ measurements are made over a range of frequencies and at a lower voltage, typically 140 Vrms. Recommendations regarding input signal location and measurement leads are the same as those for tan δ testing.
When performing this test, refer to CIGRE 254 - Dielectric Response Methods for Diagnostics of Power Transformers, and CIGRE 414 - Dielectric Response Diagnoses for Transformer Windings, section 4.1.3. - Suggested Checklist for Execution of Dielectric Response Measurements on Power Transformers.
We hope this brief set of recommendations will help you perform transformer testing in a safe manner, producing accurate results and valuable readings. Please remember to practice good management of the data obtained from field tests. Always keep an accurate record of the results, as data trending will help you to better determine the condition of the transformer.