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Testing power transformers – safely
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Lead Applications Engineer
Everyone who works with electricity is aware of the importance of power transformers within the electrical infrastructure. Power is usually generated in remote locations and from there it has to be transmitted and distributed to consumers, satisfying well-defined standards for quality and efficiency. And, of course, the operation of the system must be safe and reliable. A major problem that electrical utilities often encounter is managing system losses arising from energy conversion processes, such as the use of power transformers, and from transmission and distribution. 
In order to ensure safe and reliable operation, testing and maintenance of electrical equipment in substations is carried out by professionals who are responsible and accountable for providing accurate assessment of the condition of these assets. Power transformers are critical and cannot always be made available for condition assessment. Availability of power transformers is decreasing due to load growth, and some users are able to put transformers on test only after extremely careful planning.
This article won’t get too specific about every test mentioned but it does contain relevant safety tips and literature references that will be useful when performing transformer tests in the field. Creating hazard awareness while performing a specific test and faithfully following safety program guidelines and relevant standards are key elements of power transformer testing practice.
Testing Intentions
Why is this transformer being tested? A power transformer is tested upon completion of all assembly activities in factory, as part of the commissioning process during installation, within the scope of a periodical and scheduled maintenance program, after system failure and any time its condition needs to be assessed. An important factor that needs to be considered is the applicable standards.
For factory tests, reference can be made to the 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 electrical tests, reference can be made to 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. These guides and standards are published by the Institute of Electrical and Electronics Engineers (IEEE).
Also, routine investigation of insulation properties is also important; reference for this practice can be found in Section 10 of the ASTM standards, which is published by the standards organization, ASTM International. Testing practices are also well described in the International Standard IEC 60076-Part 1 (General, specific clause 10); and Part 3 for testing of the dielectric system. This international standard is published by the International Electrotechnical Commission.
Responsibility for safety
Who will be in charge of testing the transformer? It is important to emphasize the hazards involved in high-voltage and high-current testing, and the potential consequences of not being properly trained in operating electrical test equipment. Recommendations that should be followed are contained in NFPA 70E (section 205.1, which outlines a ‘qualified person’ suitable for working on electrical equipment). NFPA 70E, ‘Standard for Electrical Safety in the Workplace’ is published by the U.S. trade association, the National Fire Protection Association (NFPA).
With a similar approach, section 3.2.1 of the NETA Standard for Acceptance Testing Specifications (NETA ATS-2009) requires electrical tests and inspections to be carried out by trained and experienced technicians who will be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. The NETA standards are published by the standards organisation NETA (International Electrical Testing Association).
Certification and calibration
Is calibrated and certified equipment available to run the tests? Even though this question sounds like common sense, asset owners don’t always request a calibration certificate for the equipment that will be used to carry out the tests. Test equipment calibration guidelines are given in NETA ATS 2009, section 5.3.
Summarizing these guidelines, the test company must calibrate the field instrumentation annually. Accuracy of the calibration shall be directly traceable to the National Institute of Standards and Technology (NIST).
Personal protective equipment
What about personal protective equipment (PPE)? Personal protective equipment must be worn. Imagine one of your colleagues falling from a height because of not having a harness, or injuring their hands or - even worse - no longer being able to work as the result of an electric shock. Perform inspection and testing of protective equipment and protective tools on a regular basis. The relevant standard is NFPA 70E, article 250.
Visual inspections
Why is a visual inspection needed on site? The tests will be performed on a unit that is offline, but it is usually only this unit that is offline; all other electrical apparatus in the substation is energised and is a source of electric and magnetic fields. While the offline unit is being tested, lockout/tagout procedures must be followed. The OSHA standard for The Control of Hazardous Energy (Lockout/Tagout), Title 29 Code of Federal Regulations (CFR) Part 1910.147, addresses the practices and procedures necessary to disable machinery or equipment, thereby preventing the release of hazardous energy while employees perform servicing and maintenance activities.
Occupational Safety and Health Administration (OSHA) is a U.S. federal agency that regulates workplace health and safety that publishes a variety of standards, including ones specific to the electrical industry.
The aforementioned OSHA standard outlines measures for controlling hazardous energies - electrical, mechanical, hydraulic, pneumatic, chemical, thermal, and other energy sources. When the environment has been made safe for testing the transformer, it’s time to look at the recommendations provided by the NETA ATS 2009 7.2.2.1 standard for visual and mechanical inspection of liquid-filled transformers. Remember that ATS is for acceptance testing and some steps might be skipped during routine testing. Things that must always be done are: check the nameplate information, carry out a grounding inspection, verify the presence of PCB content labeling, verify that all connection points to testing equipment are clean, verify liquid level in tanks and bushings, verify operation of tap changers, as well as the operation and accuracy of temperature gauges.
Starting the job
Where to start? This is a very common question. Is there a sequence recommended in any standard, which can simply be followed? The answer is no. The technician in charge of the electrical tests should 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. A through fault, line transients or any other switching operation will leave residual magnetism in the transformer core that may affect the results of the tests (as described in the IEEE 62 6.1.3.4 standard) especially when performing excitation current tests (low voltage or high voltage) and sweep frequency response analysis (SFRA) in open circuit configuration. IEEE 62, in section 6.1.3.5, describes the recommended methods for demagnetisation, and considers a more convenient method to neutralise the magnetic alignment of the core by applying a direct voltage of alternate polarities to the transformer for decreasing intervals. If the transformer has been in operation, leave the unit for at least couple of hours to cool down. Work with a winding or top-oil temperature close to ambient temperature, as the thermal dynamics are much slower and correction factors are more reliable.
Let's start testing
First of all, ensure that you feel comfortable with the operation and hook-up of the testing instrumentation and that you have a user guide to hand. Perform alternating current (ac) testing that will not affect the core’s magnetisation. You can follow the recommended tests presented in IEEE 62 (See Diagnostic Test Chart) and test each component of the transformer: windings, core, insulation, bushings and tap changers. For all tests, ensure that you have a good grounding connection and that you have the transformer and the testing equipment in the same grounding loop. If you are performing high-voltage testing, familiarise yourself with IEEE 4. Standard for High-Voltage Testing published by the Institute of Electrical and Electronics Engineers (IEEE).
Electrical tests
Turn ratio test Remember that you are applying a low- voltage signal. You are recommended to apply this signal 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. Remember the voltage will be multiplied by a factor equivalent to:
Winding resistance test
The test is normally performed on each winding separately. Start from the high-voltage side and then continue with the low-voltage side. Disconnection of the leads during current injection while performing the test may result in a high-energy discharge. Ensure that you discharge and de-magnetise the transformer after running a direct-current (dc) winding resistance test. For large YΔ configured transformers, perform the test with the simultaneous winding magnetisation technique. In this case, inject the test current through high-voltage and low-voltage windings simultaneously, to shorten the measurement time.
Dissipation factor (tan ∂) test
This kind of testing involves dealing with high-voltage equipment. Be sure your testing equipment is properly grounded and safely connected to the transformer. Because your transformer is not ideal and neither are the substation conditions, you will encounter electro-magnetic interference (EMI) at different levels and of different types (ac or dc) from various sources, creating electrical noise that needs to be suppressed by the testing equipment, which is one of the reasons why tan ∂ testing is performed at high voltages. You must consider the temperature of the insulation system, as a correction factor should be applied to normalise the results to a 20 ºC base, using either a table of correction factors or an individual temperature correction factor determined by using sweep frequency technology. Moreover, ensure that you verify the condition of the bushings; they should be clean and dry. This will avoid the flow of leakage currents on the surface of the porcelain. Also, ensure that your high-voltage lead and your measurement leads are not touching a grounding point because this would trip the unit or give negative power factor values.
Excitation current test
Normally, this test is only performed on the high-voltage side of the transformer. Remember that you have a choice of two instruments for performing excitation current tests; you can use a transformer turn ratio (TTR) instrument or you can use a dissipation factor test set. The big difference is the test voltage applied to excite the transformer. Never compare absolute numbers for a test performed at 100 volts with a test at 10 kilovolts. The results are very different. This may be a high-voltage test, so be sure to follow the operating instructions provided by the manufacturer for safe operation and good quality results.
Short circuit impedance test
Bear in mind that when you short circuit the secondary winding, a high current flow can be expected between the short-circuited terminals. Therefore, use jumper cables of at least #1 AWG (American wire gage) or 50 mm2 cross sectional area otherwise you may end up melting the jumper cables during the test.
Insulation resistance test
The life of a transformer is limited by the life of its insulation system. If you are confident about the condition of the insulation, then you can expect that the unit will provide many more years of service. You should discharge the transformer before and after the test so no residual charges will affect the personnel testing the unit or working on connection/disconnection. 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 on your results.
SFRA test
This new technique impresses many transformer manufacturers and transformer operators because of its ability to detect various faults in a single test. The test is straightforward, but following existing standards and procedures to ensure repeatability is essential. The test is sensitive to connections and set-up and you should be aware of the internal noise in your testing device. The transfer function of many transformers will reach a magnitude value close to -90 dB and sometimes down to -100 dB and, therefore, your instrumentation should have a wide dynamic range capable to record these transfer function magnitudes. Grounding practices are critical. The CIGRE 342 (2008): ‘Mechanical Condition Assessment of Transformer Windings Using Frequency Response Analysis’ document, published by members of the International Council on Large Electric Systems (CIGRE), describes in section 2.4.1.2 on how to use adjustable extension leads. It must be emphasised that residual magnetisation in the core will affect “open circuit” readings. Therefore, de-magnetise the transformer before performing SFRA tests. More detailed instructions are listed in CIGRE 342 section 2.4.8.
The IEEE Transformer Committee is intensively working to make a Frequency Response Analysis Guide available. So far, the work is being compiled in the document IEEE PC57.149/D8 ‘Draft Trial-Use Guide for the Application and Interpretation of Frequency Response Analysis for Oil Immersed Transformers’.
DFR Test
Dielectric Frequency Response (DFR) Test Insulation diagnostic testing using Dielectric Frequency Response (DFR) or, as it is also called, Frequency Domain Spectroscopy (FDS) is a useful tool for determining the percentage 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 dissipation factor test. The main difference is that you are performing capacitance and tan delta measurements at different frequencies and to complete the test is somewhat longer - usually around 30 minutes. Another difference is that you are testing at lower voltages, typically 140 Vrms. Because the hook-up is the same as that used for tan ∂ testing, the same recommendations apply with regards to input signal location and measurement leads.
When performing this test, take some time to review the literature of the CIGRE 254 document - 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.
Summary
Performing electrical testing can be dangerous if personnel are not familiar with the test equipment and the object under test. An easy to follow procedure is described in NETA ATS 2009 section 7.2.2.2.
We hope that this brief set of recommendations will help you perform electrical 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 a good record of the results. Data trending will help you to better determine the condition of the transformer, leading to an easier process when making decisions about maintenance plans or immediate actions to be considered before bringing the transformer back in service. Finally, always ensure that you follow carefully the national and international standards mentioned in this feature, those standards or practices (IEC, VDE, GOST, etc) regulating the safe work and operation of electrical testing equipment in your territory and, of course, the manufacturer’s recommendations.
Megger's range of power transformer test equipment makes safe transformer testing easy, reliable and accurate.
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Pinpoint precision
email: Allen Joyce
HV and Cable Fault Location Product Manager
Cable fault locators that incorporate high- energy pulse generators and sophisticated time domain reflectometers (TDRs) are an invaluable tool for the power engineer working on underground cable systems. Used correctly, these test sets will allow the distance to the fault to be determined with a good level of accuracy, while preserving the cable from unnecessary additional damage.
That’s not quite the end of the story, however. It’s all very well knowing that the cable fault is shown at 53 metres on the TDR but, if as is often the case, the exact details of the cable route or installation is unknown. Therefore knowing the length of the buried cable (as shown on the TDR) is not sufficient on its own to allow precise or pinpoint location of the fault to determined.
Over the years, numerous methods have been employed to address this shortcoming, the most popular of which have involved listening for the characteristic audible noise (thump) produced by the flashover at the fault location when the cable is subjected to a surge from the high-energy fault locator. Devices as simple as a wooden stick, with one end in contact with the ground and the other pressed to the user’s ear, have been used as aids to detecting and locating the thump.
In more recent times, however, a more typical ‘pinpointer’ has embodied a specially designed ground microphone and an amplifier that delivers amplified signals from the microphone to headphones worn by the user. The idea is that the operator moves the microphone over the ground in what is believed to be the vicinity of the cable fault, and attempts to position it for the loudest thump in the headphones. In a perfect world, this would mean that the microphone was directly above the fault in the buried cable.
Unfortunately, things are never quite that straight forward and simple acoustic detectors of the type described, while still in widespread use, have numerous shortcomings.
Sometimes the acoustic noise produced by the fault is small, and in these cases it can take a lot of trial and error before the pinpointer is close enough to the fault to hear anything at all. In addition, the maximum level of acoustic noise may not necessarily correspond with the fault location, especially if the cable is conduit or trunking that can conduct the noise efficiently to a point remote to the fault.
To address these shortcomings, some manufacturers of pinpointers have devised instrument that, instead of an acoustic microphone, incorporate an electromagnetic detector that responds to the RF radiation emitted at the flashover created at the fault location by the HV surge. Such detectors typically have greater range than acoustic types, so it’s much easier to detect a signal, however without knowing the level of the electromagnetic signal, it is impossible to pinpoint the exact location of the fault. They can get you into the vicinity of the fault, this may be useful but it is not really the object of the exercise.
A shortcoming shared by simple acoustic and electromagnetic detectors is that they mislead the operator. When the signal strength increases, for example, does this mean that the operator is moving at angle toward the cable, or directly along the cable in the direction of the fault? These sort of uncertainties mean that considerable skill and experience - allied, possibly, with a bit of luck - are needed to get good results with simple pinpointers, however attractive they may at first appear.
As might be expected, this had led to the development of more sophisticated instruments, with some types offering both acoustic and electromagnetic detection and an indication of the received signal strengths. Such pinpointers are a step forward - except, in the case of those that use separate acoustic and electromagnetic pickups - especially as they can provide the relative distance to the fault by evaluating the time difference between the arrival of the electromagnetic and acoustic signals.
They’re not a complete answer as they still don’t provide any form of indication of whether the user is walking along the cable route or at an angle to it. Recently, this issue has also been addressed by the introduction of new cable-fault pinpointer that has an acoustic pickup plus two electromagnetic detectors built into one ground microphone.
The electromagnetic detectors are directional and are arranged so that their directions of maximum sensitivity are at right angles to each other. This means that by comparing the way the signal strength seen by each detector varies as the pinpointer is moved, the user can easily work out the direction they are moving in relation to the cable route. It then becomes a simple matter to find the cable and align to its route.
Naturally, this new pinpointer incorporates facilities for evaluating the time difference between the acoustic and electromagnetic signals it receives, and this allows the fault location to be found with a high degree of accuracy, even in ‘difficult’ installations. The key is that the fault is located not by looking for the maximum level of the signals which can be misleading, but by looking for the minimum time between the arrival of the acoustic and electromagnetic signals, which is in an infallible indicator of the fault location.
This new pinpointer – the Megger MPP2000 – also incorporates many additional refinements, including a user-configurable filter for the acoustic signal to make it easier to hear when in the presence of background noise, and an LED indicator to show instantly when the instrument is within range of the electromagnetic signal from the fault.
As would be expected from a Megger product, the MPP2000 is robust yet lightweight and easily portable, and it is supplied with a rugged, but lightweight, ground microphone that incorporates the acoustic pickup and the two electromagnetic detectors. Being competitively priced and, given the costs that are associated with prolonged cable outages, particularly in utility applications, it makes it an investment that’s very easy to justify. And don’t forget these features help to remove prolonged operator stress!
Finding faults with voice and data communications
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Product Manager
For locating faults rapidly on voice and data communications installations, a time domain reflectometer (TDR) is potentially an invaluable tool. Yet all too often, TDRs fail to live up to their potential, largely as a result of the limitations inherent in older instruments.
The latest generation of TDRs has effectively removed these limitations, making the new instruments more useful – and easier to use – than ever.
Auto set up is a real time saver for occasional and experienced users alike.
Let’s take a look at some of the shortcomings that have often been associated with TDRs in the past, and how these have been addressed. The first and possibly most significant issue is the location of near-end faults. Put simply, for faults close to the instrument, the signal reflected from the fault often arrived at the instrument before the launch pulse had finished and, therefore, could not be detected.
This is particularly problematic as the majority of faults on communications networks near-end faults. In principle, the remedy is straightforward – make the launch pulse shorter, so that it no longer masks the return signal from a nearby fault. It has taken recent advances in technology to make this possible, however, and the best of the new generation of TDRs can work with launch pulses as short as 2 nS.
In practical terms, this means that the new instruments can locate faults as close as 0.1 m (around 4 inches) from the point of connection. Given that TDRs are almost always used with test leads that are a metre or more long, the near-end fault location problem has been comprehensively solved! The next problem commonly encountered with older TDRs is complicated set up. What is the cable impedance? What is the best pulse width to use for a particular operating range? How should the gain be set? Experienced users will have the answers, but for others, and particularly for those who use TDRs only infrequently, the multiplicity of options can be daunting.
The solution is auto set-up, where the TDR itself determines the cable impedance, and sets the optimum gain and pulse width for each range. Not only is this ideal for ensuring that novice users get the best from the instrument, it’s also a big time saver for experienced users. Naturally, the best instruments also provide a manual operating mode for tackling unusual or complex situations where fine-tuning the operation of the TDR can help to wring the last ounce of performance from it.
Interpreting the trace produced by the TDR is another issue that sometimes poses challenges. One very effective solution is to compare the trace from a known good pair and the faulted pair but in the past, instruments offering dual-channel operation with a trace comparison facility have typically been bulky and expensive.
A slightly different but equally effective approach is to provide a single-channel instrument with the facility for storing a trace on screen. This means that the instrument can first be used on the good pair and the resulting trace stored. It can then be used on the faulted pair, and the new trace compared with the first one, which is still on the screen. This arrangement allows all the benefits of visual trace comparison to be provided in a compact and cost-effective single-channel instrument. Another issue that can be a problem is the quality of the display used in the TDR. Getting good results involves interpreting the fine detail of the traces and setting the cursor accurately. This can only be done if the display has good resolution, particularly in a handheld instrument where the overall display dimensions are necessarily limited. Fortunately, very high resolution displays are now available at reasonable prices and the best TDRs use these.
 The conclusion is clear: the best of the new generation TDRs, of which Megger’s TDR1000/3 range are excellent examples, offer greatly enhanced usability and performance, allowing these remarkably useful instruments to live up to their full potential, even in the hands of inexperienced users. Auto set up is a real time saver for occasional and experienced users alike
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