By Diego Robalino
Engineers value every component in an electrical system because they are all important: the generators, the switchgear, the transmission and distribution lines, and the power transformers. Together, those components make a whole that impacts all modern life because we are reliant on power to support our society.
The operation of an electrical system, therefore, must be continuous; it must be safe, secure and reliable. Reliability depends on preventing issues before they arise. This is often accomplished through proper maintenance and testing of substation components, and this adage is especially true with one particularly important component: power transformers.
Unfortunately, power transformers, being critical, are difficult to schedule for condition assessment and maintenance. As load growth increases, those transformers become more important, and, conversely, the window of time to maintain them shrinks.
|Megger's IDAX350 helps this user conduct an insulation diagnostic test for power transformers.|
Energy operators, therefore, must take advantage of the available testing window and get the most from the allotted time to ensure every minute of maintenance time is on track. Dc and ac electrical testing procedures allow identification of particular characteristics of each transformer's dielectric and electro-mechanical components: windings, core, insulation, bushings and tap changers.
|This test operator performs a winding resistance test using Megger's MCT1605.|
Here are nine insider tips to help substation engineers put their power transformer testing time to good use.
|Turns ratio testing is made easy with Megger's MTO and TTR product lines.|
Tip 1: Be Aware of Timing and Standards
As the substation engineer considers a maintenance and testing timetable, the number of times the power transformers have been-or should be-tested should be kept in mind.
All power transformers are first factory-tested. They are also tested during installation, as part of a maintenance program, after system failure and when other equipment-or an engineer's hunch-necessitates condition assessment. Each of those tests requires a different mindset and involves different standards. Where that substation engineer falls in the lifecycle of the power transformer dictates his reference standards, but following is a set of guidelines:
• Institute of Electrical and Electronics Engineers (IEEE) Standard General Requirements for Liquid-Immersed Distribution, Power and Regulating Transformers (C57. 12.00); and
• IEEE Standard Test Code for Liquid-Immersed Distribution, Power and Regulating Transformers and Guide for Short-Circuit Testing (C57.12.90).
Field Electrical Tests:
• IEEE 62-1995 (R2005): IEEE Guide for Diagnostic Field Testing of Electric Power Apparatus - Part 1: Oil-Filled Power Transformers, Regulators and Reactors;
• IEEE C57.93-2007: Guide for Installation and Maintenance of Liquid-Immersed Power Transformers; and
• IEEE PC57.152 D5.1: Draft Guide for Diagnostic Field Testing of Fluid Filled Transformers, Regulators and Reactors.
• IEEE 4. Standard for High-Voltage Testing (high-voltage tests);
• Section 10 of the American Society for Testing and Materials (ASTM) International standards (insulation tests);
• International Electrotechnical Commission 60076 - Part 1 (general tests, specific clause 10) and Part 3 (dielectric system test); and
• CIGRE 227. GUIDE for Life Management Techniques For Power Transformers, prepared by CIGRE WG A2.18, 2003.
Tip 2: Get Comfortable and Bring the Manual
Any technician testing power transformers must be comfortable with connecting and operating the test instrument. And, the technician should bring a user guide to consult.
Tip 3: Know the Hazards
Dealing with power, not surprisingly, is dangerous-especially power transformers' high voltage and current levels. Whoever tests these critical components must be properly trained, and one place to start is with reading. The National Fire Protection Association produces "Standards for Electrical Safety in the Workplace" with excellent recommendations. In addition, Section 3.2.1 of the International Electrical Testing Association's (NETA's) "Standard for Acceptance Testing Specifications (NETA ATS-2009)" can be helpful in determining an inspector's safety qualifications.
Tip 4: Look for the two Cs- Certification and Calibration
Even though it seems like common sense to ensure testing equipment is calibrated and certified to run the needed tests, many asset owners don't request a calibration certificate for testing equipment. Test equipment calibration guidelines are given in NETA ATS 2009, section 5.3. That guideline says: "The test company must calibrate the field instrumentation annually and the accuracy of that calibration is directly traceable to the National Institute of Standards and Technology (NIST)."
Tip 5: Remember the Safety Gear
During testing, personal protective equipment must be worn, and it could save lives. Harnesses protect testers from falls; gloves keep a random shock from burning hands. And, similar to inspecting substation equipment, inspect and test protective equipment and protective tools on a regular basis-the relevant standard is National Fire Protection Association (NFPA) 70E, Article 250.
Tip 6: Ground
For all tests, ensure tester equipment has a good grounding connection, and the transformer and testing equipment must be in the same grounding loop.
Tip 7: Look Around
Visual on-site equipment and area inspections are vital. While the tests may be performed on an offline unit, other units usually are not. The other electrical apparatus in the substation will be energized and, therefore, a source of electric and magnetic fields. While the offline unit is being tested, lock-out/tag-out procedures must be followed. The Occupational Safety and Health Administration's (OSHA's) "Standard for the Control of Hazardous Energy (Lockout/Tagout), Title 29 Code of Federal Regulations (CFR), Part 1910.147" addresses these issues. It lists necessary practices and procedures to disable machinery or equipment to prevent accidents during testing.
When the environment has been made safe for testing, look at the recommendations provided by the NETA ATS 2009 18.104.22.168 standard for visual and mechanical inspection of liquid-filled transformers. Remember that ATS is for acceptance testing, and some steps may be skipped during routine testing. Testers must, however, check the nameplate information; carry out a grounding inspection; and verify the presence of polychlorinated biphenyls (PCB) content labeling-that all connection points to testing equipment are clean, the liquid level in tanks and bushings, the operation of tap changers, and the operation and accuracy of temperature gauges.
Tip 8: Discharge and Demagnetize Before Testing
The technician needs to avoid remaining core magnetization and residual charges in the insulation. So, it's good practice to discharge and demagnetize the unit before testing. A through fault, line transients or any other switching operation will leave residual magnetism in the transformer core that could impact or alter test results-especially when with excitation current tests and sweep frequency response analysis in open circuit configuration. According to IEEE standards, testers can neutralize the core's magnetic alignment by applying direct voltage of alternate polarities to the transformer for decreasing intervals. If the transformer has been in operation, the technician should leave the unit for at least two hours to cool down. Work with a winding or top-oil temperature close to room temperature because the thermal dynamics are slower and correction factors are more reliable.
Tip 9: Know the Test
There are many tests technicians can perform on transformers: insulation resistance, turns ratio, winding resistance, dissipation factor, excitation current, short-circuit impedance, sweep frequency and dielectric frequency. Whichever a tester chooses, the basic principles must be understood (see sidebar).
When a technician finishes the power transformer testing, the data should be kept safe, penning (or inputting) a record of the results. This will allow for data trending from past tests when performing future tests-with more accurate information on transformer conditions. More accurate information will make the next tight testing window more efficient and honed to the needs and scope of the system-and make the substation manager's life easier.
Please note: These are only highlights and should not be considered the final word on testing. Government, manufacturer and workplace guidelines should be precisely followed for individual safety and equipment protection.
About the Author: Diego Robalino received his Ph.D. degree in electrical engineering from Tennessee Technological University. Robalino spent a decade working for the oil and gas industry managing design, construction and commissioning of electrical and electro-mechanical projects, as well as research and university lecturing. He is an active member of IEEE and ASTM. Currently, Dr. Robalino is a lead applications engineer for Megger.
Circle 163 on reader service card
The Test Lead
• Insulation Resistance Test: The life of a transformer is limited by the life of its insulation system. Technicians should be aware of possible leakage currents flowing on the bushings' surface and use the insulation resistance test set guard lead to minimize the effect of these currents on the results.
•Turn Ratio Test: The tester is applying a low-voltage signal, ideally, to the high-voltage winding. Data is pulled from the low-voltage winding. If testing the transformer from the low-voltage side, the tester should use the lowest available voltage.
•Winding Resistance Test: This test is normally performed on each winding, separately. Technicians start from the high-voltage side and then continue to the low-voltage side for most transformers. Large YΔ-configured transformer tests inject current simultaneously.
• Dissipation Factor (tan δ) Test: This test involves high-voltage equipment. Testers should be sure the testing equipment is properly grounded and safely connected to the transformer. Because a transformer is not ideal and neither are the substation conditions, testers will encounter electro-magnetic interference (EMI) at different levels and of different types (ac or dc) from various sources. This creates electrical noise that needs to be suppressed by the testing equipment-which is one of the reasons why tan δ testing is performed at high voltages.
• Excitation Current Test: Normally, this test is only performed on the high-voltage side of the transformer. Technicians have a choice of two instruments for performing excitation current tests: a transformer turn ratio (TTR) instrument or a dissipation factor test set. The main difference is the test voltage applied to excite the transformer.
• Short Circuit Impedance Test: When a tester short circuits the secondary winding, a high current flow can be expected between the short-circuited terminals. The tester should, therefore, use jumper cables of at least #1 AWG (American wire gage) or 50 mm2 cross-sectional; otherwise, the jumper cables could melt during the test.
• Sweep Frequency Response Analysis (SFRA) Test: This new technique can detect various faults in a single test. The test is sensitive to connections, set-up and internal noise. Instrumentation should have a wide dynamic range capable of recording transfer function magnitudes.
• Dielectric Frequency Response (DFR) Test: Insulation diagnostic testing using Dielectric Frequency Response (DFR) or Frequency Domain Spectroscopy (FDS) is a useful tool for determining the percentage of 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 the technician performs capacitance and tan delta measurements at different frequencies.