IEEE Guide: Transformer Evaluation & Reconditioning

IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers IEEE Power and Energy Society Sponsored by the Transformers Committee IEEE 3 Park Avenue New York, NY 10016-5997 USA IEEE Std C57.140™-2017 (Revision of IEEE Std C57.140-2006) Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140™-2017 (Revision of IEEE Std C57.140-2006) IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Sponsor Transformers Committee of the IEEE Power and Energy Society Approved 15 June 2017 IEEE-SA Standards Board Recognized as an American National Standard Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Abstract: Guidelines for the following are included in the standard: insulating liquid maintenance and diagnostics, liquid reclamation, testing methods for the determination of remaining insulation (paper) life, and upgrades of auxiliary equipment such as bushings, gauges, de-energized tap changers (DETCs), load tap changers (LTCs) (where applicable), and coil re-clamping. The goal of this guide is to assist the user in extending the useful life of a transformer. Keywords: condition evaluation, IEEE C57.140™, life extension, maintenance, power transformers, reconditioning, risk assessment The Institute of Electrical and Electronics Engineers, Inc. 3 Park Avenue, New York, NY 10016-5997, USA Copyright © 2017 by The Institute of Electrical and Electronics Engineers, Inc. All rights reserved. Published 31 October 2017. Printed in the United States of America. 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Participants At the time this IEEE guide was completed, the Evaluation and Reconditioning of Liquid Immersed Power Transformers Working Group had the following membership: Paul Boman, Chair Brian Sparling, Vice Chair Raj Ahuja Richard Amos Jeffrey Anderson Stephen Antosz Roberto Asano Derek Baranowski Michael Barnes Jeffrey Benach Enrique Betancourt William Boettger Juan Castellanos Luiz Cheim Donald Chu James Cross John Crouse Alan Darwin Eric Davis Marcos Ferreira Norman Field Joseph Foldi Michael Franchek Shawn Galbraith Eduardo Garcia James Gardner James Graham Mark Haas Suh Joon Han Gary Hoffman John Lackey Michael Lau Mario Locarno Susan McNelly Charles Patrick McShane Joseph Melanson Harold Moore Arturo Nunez Bipin Patel Mark Perkins Branimir Petosic Donald Platts Thomas Prevost Martin Rave Scott Reed Oleg Roizman Steven Schappell Ewald Schweiger Hemchandra Shertukde H. Jin Sim Thomas Spitzer Gregory Stem Craig Stiegemeier Raman Subramanian Charles Sweetser Mark Teetsel Malcolm Thaden Robert Thompson Rogerio Verdolin Jane Ann Verner David Wallach Joe Watson Roger Wicks Kipp Yule Waldemar Ziomek The following members of the individual balloting committee voted on this guide. Balloters may have voted for approval, disapproval, or abstention. Samuel Aguirre Saleman Alibhay Roy Ayers Peter Balma Thomas Barnes Barry Beaster W. J. (Bill) Bergman Wallace Binder Thomas Bishop Thomas Blackburn W. Boettger Paul Boman Jeremiah Bradshaw Gustavo Brunello Paul Cardinal Juan Castellanos C. Clair Claiborne Randy Clelland John Crouse Willaim Darovny Matthew Davis Dieter Dohnal Gary Donner Jorge Fernandez Daher Rabiz Foda Joseph Foldi Bruce Forsyth George Frimpong Nancy Frost Shawn Galbraith Ramsis Girgis Mietek Glinkowski Jalal Gohari Edwin Goodwin James Graham William Griesacker Randall Groves John Harley Roger Hayes Werner Hoelzl Gary Hoffman Jill Holmes Philip Hopkinson Richard Jackson John John Laszlo Kadar 6 Sheldon Kennedy Isidoro Kerszenbaum James Kinney Zan Kiparizoski Axel Kraemer Alexander Kraetge Jim Kulchisky Saumen Kundu John Lackey Chung-Yiu Lam Thomas La Rose Michael Lau Michael Lauxman Aleksandr Levin Albert Livshitz Mario Locarno Thomas Lundquist Richard Marek Lee Matthews Omar Mazzoni William McBride C. Michael Miller Daniel Mulkey Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Jerry Murphy Ryan Musgrove Ali Naderian Jahromi K. R. M. Nair Rhonda Netzel Arthur Neubauer Michael Newman Joe Nims Lorraine Padden Bansi Patel Dhiru Patel Paulette Payne Powell Brian Penny Donald Platts Alvaro Portillo Jean-Christophe Riboud Thomas Rozek Ryandi Ryandi Daniel Sabin Daniel Sauer Bartien Sayogo Ted Schoenberg Ewald Schweiger Adam Sewell Hamid Sharifnia Devki Sharma Hyeong Sim Jeremy Smith Jerry Smith Brian Sparling Ronald Stahara K. Stump Ed TeNyenhuis David Tepen Malcolm Thaden James Thompson Michael Thompson James Van De Ligt Alwyn Van Der Walt Gerald Vaughn Roger Verdolin John Vergis Sukhdev Walia David Wallach Daniel Ward Joe Watson Lee Welch Kenneth White Jennifer Yu Jian Yu Kipp Yule When the IEEE-SA Standards Board approved this guide on 14 June 2017, it had the following membership: Jean-Philippe Faure, Chair Gary Hoffman, Vice Chair John Kulick, Past Chair Konstantinos Karachalios, Secretary Chuck Adams Masayuki Ariyoshi Ted Burse Stephen Dukes Doug Edwards J. Travis Griffith Michael Janezic Thomas Koshy Joseph L. Koepfinger* Kevin Lu Daleep Mohla Damir Novosel Ronald C. Petersen Annette D. Reilly Robby Robson Dorothy Stanley Adrian Stephens Mehmet Ulema Phil Wennblom Howard Wolfman Yu Yuan *Member Emeritus 7 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Introduction This introduction is not part of IEEE Std C57.140-2017, IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers. At the turn of the century, approximately one-half of all transformers used in the electric utility industry reached their 30-year design life. Because of today’s economics, many of these transformers will be called upon to supply reliable service for an additional 20 to 30 years. Transformer owners intending to extend the equipment life should address the key areas of economics, inspection and diagnostics, expected cost of failure/ loss of production; and materials and design. A comprehensive economic study should be carried out before the investment of significant resources to recondition a transformer. This study involves load forecasts, reserve margins, new capacity plans, cost-benefit analyses, operating costs, capital costs, and continued reliability and availability. Once a financial decision to extend the transformer life is made, an inspection and diagnostic strategy should be determined. This evaluation should include the following: manufacturer, size, age, operating history, thermal load, electrical tests, maintenance history, and failure history. New materials, major component replacement, and other design changes may also affect the life extension decision of units manufactured in the last 50 years. The development of better core steel and better solid insulation has been ongoing for a number of years. The better operating efficiency of new materials may remove the economic advantage for life extension. Material added to this document includes information on corrosive sulfur in the insulation liquid and correlation curves of furanic content with degree of polymerization. There are also sections and updates with 5.4 solid insulation system analysis, power factor, and information on frequency response analysis. Acknowledgement Grateful acknowledgement is given to CIGRÉ for granting permission to reprint copyrighted material from “Technical Brochure N 445, Guide for Transformer Maintenance” and Technical Paper “New diagnostic for High Voltage Bushings.” Dedication This standard is dedicated to the memory of our friend and colleague, Roland James. 8 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Contents 1. Overview�� 10 1.1 Scope�� 10 1.2 Purpose�� 10 2. Normative references�� 10 3. Definitions, acronyms, and abbreviations�� 12 3.1 Definitions�� 12 3.2 Acronyms and abbreviations�� 12 4. Risk assessment�� 13 4.1 Impact on the system�� 14 4.2 Vintage�� 15 4.3 Vacuum withstand capability�� 15 4.4 Paper and pressboard�� 15 4.5 Accessibility and spare parts availability�� 16 4.6 Operational history�� 16 4.7 Type of construction�� 17 4.8 Maintenance and repair history�� 17 4.9 Operating environment�� 18 4.10 Failure mechanisms�� 18 5. Diagnostic tests�� 26 5.1 Dissolved gas analysis�� 26 5.2 Liquid quality assessment (physical tests)�� 28 5.3 Corrosive sulfur�� 28 5.4 Solid insulation system analysis�� 29 5.5 Capacitance, power factor, and dissipation factor�� 31 5.6 Frequency response analysis�� 34 5.7 Partial discharge detection�� 36 5.8 Infrared inspection�� 37 5.9 Degree of polymerization�� 39 5.10 Vibration and noise�� 42 6. Condition assessment and reconditioning�� 43 6.1 Core and coil assembly�� 44 6.2 Tap changers�� 57 6.3 Bushing and arrester�� 60 6.4 Tanks, gaskets, etc.�� 63 6.5 Gauges, indicators, and relays�� 67 6.6 Controls, alarms, and annunciators�� 71 6.7 Pumps�� 73 6.8 Radiators, coolers, and fans�� 75 7. Degassing and moisture removal�� 76 7.1 Off line de-energized processing methods�� 76 7.2 On-line energized liquid dry-out method�� 80 Annex A (informative) Alternative insulation liquid�� 81 Annex B (informative) Bibliography�� 82 9 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 1. Overview 1.1 Scope This document provides guidelines for the following: insulating oil maintenance and diagnostics, oil reclamation, testing methods for the determination of remaining insulation (paper) life, and upgrades of auxiliary equipment such as bushings, gauges, de-energized tap changers (DETCs), load tap changers (LTCs) (where applicable), and coil re-clamping. The goal of this guide is to assist the user in extending the useful life of a transformer. 1.2 Purpose The purpose of this guide is to provide guidelines for evaluation and reconditioning of transformers. This guide should prove helpful to users who do have evaluation and reconditioning programs in place, and who may not be aware of other activities and processes that are available. The guide is intended as a comprehensive document to aid users in selecting the proper approaches to upgrading, reconditioning, refurbishing, or other activities in extending the useful life of a transformer. 2. Normative references The following referenced documents are indispensable for the application of this document (i.e., they must be understood and used, so each referenced document is cited in text and its relationship to this document is explained). For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments or corrigenda) applies. ASTM D395, Standard Test Methods for Rubber Property—Compression Set. ASTM D1275, Standard Test Method for Corrosive Sulfur in Electrical Insulating Liquids. ASTM D1933, Standard Specification for Nitrogen Gas as an Electrical Insulating Material. ASTM D4243, Standard Test Method for Measurement of Average Viscometric Degree of Polymerization of New and Aged Electrical Papers and Boards. ASTM D5387, Standard Guide for Elements of a Complete Data Set for Non-Cohesive Sediments. 10 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers CIGRÉ TB445, Guide for Transformer Maintenance. DIN 51353, Testing of insulating oils; detection of corrosive sulfur; silber strip test. IEC 60450, Measurement of the Average Viscometric Degree of Polymerization of New and Aged Cellulosic Electrically Insulating Materials. IEC 61198, Mineral insulating oils—Methods for the Determination of 2-Furfural and Related Compounds. IEC 60422, Mineral insulating oils in electrical equipment—Supervision and maintenance guidance. IEC 62535, Test method for detection of potentially corrosive sulfur in used and unused insulating oil. IEEE Std C57.91™, IEEE Guide for Loading Mineral-Oil-Immersed Transformers and Step-Voltage Regulators. IEEE Std C57.93™, IEEE Guide for Installation and Maintenance of Liquid-Immersed Power Transformers. IEEE Std C57.104™, IEEE Guide for Interpretation of Gases Generated in Oil-Immersed Transformers. IEEE Std C57.106™, IEEE Guide for Acceptance and Maintenance of Insulating Mineral Oil in Electrical Equipment. IEEE C57.113™, IEEE Recommended Practice for Partial Discharge Measurement in Liquid-Filled Power Transformers and Shunt Reactors. IEEE C57.127™, IEEE Guide for the Detection and Location of Acoustic Emissions from Partial Discharges in Oil-Immersed Power Transformers and Reactors. IEEE Std C57.139™, IEEE Guide for Dissolved Gas Analysis in Transformer Load Tap Changers. IEEE Std C57.143™, IEEE Guide for Application for Monitoring Equipment to Liquid-Immersed Transformers and Components. IEEE Std C57.146™, IEEE Guide for the Interpretation of Gases Generated in Silicone-Immersed Transformers. IEEE Std C57.147™, IEEE Guide for Acceptance and Maintenance of Natural Ester Fluids in Transformers. IEEE Std C57.149™, IEEE Guide for the Application and Interpretation of Frequency Response Analysis for Oil-Immersed Transformers. IEEE Std C57.152™, IEEE Guide for Diagnostic Field Testing of Fluid-Filled Power Transformers, Regulators, and Reactors. IEEE Std C57.155™, IEEE Guide for Interpretation of Gases Generated in Natural Ester and Synthetic Ester-Immersed Transformers. IEEE Std C57.12.00™, IEEE Standard for General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers. IEEE Std C57.637™, IEEE Guide for the Reclamation of Mineral Insulating Oil and Criteria for Its Use. IEEE Std C62.1™, IEEE Standard for Gapped Silicon-Carbide Surge Arresters for AC Power Circuits. 11 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers IEEE Std C62.11™, IEEE Standard for Metal-Oxide Surge Arresters for AC Power Circuits (>1 kV). IEEE Std C62.22™, IEEE Guide for the Application of Metal-Oxide Surge Arresters for Alternating-Current Systems. 3. Definitions, acronyms, and abbreviations 3.1 Definitions For the purposes of this document, the following terms and definitions apply. The IEEE Standards Dictionary Online should be consulted for terms not defined in this clause.1 degree of polymerization (DP): A test used as a measurement for the degradation of the paper insulation used in transformers, cables, and capacitors, based on the average number of glucose molecules contained in the cellulose chains. furanic compound: A family of molecules created by the thermal degradation of cellulose. Furanic compounds are derived from a heterocyclic five-member hydrocarbon that includes oxygen and two double bonds. gas chromatography: A process in which the material sample is vaporized and injected into a stream of carrier gas like nitrogen or helium moving through a column containing a stationary phase composed of a liquid or particulate solid. The material is then separated into its component compounds according to their affinity for the stationary phase. static electrification (liquid-immersed transformers): A surface charge imbalance caused by solid insulation in contact with flowing oil. This imbalance results in a charge accumulation in oil that increases potential-producing electrical discharge. 3.2 Acronyms and abbreviations BIL basic lightning impulse insulation level DETC de-energized tap changer DP degree of polymerization DFR dielectric frequency response ETM electronic temperature monitor FRA frequency response analysis LTC load tap changer LTI liquid temperature indicator ODAF oil directed air forced OIP oil impregnated electrical bushing OLTC on load tap changer PCB polychlorinated biphenyl RBP resin bonded electrical bushing RIP resin impregnated electrical bushing 1 IEEE Standards Dictionary Online is available at: http://dictionary.ieee.org. 12 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers RPRR rapid pressure rise relay WTI winding temperature indicator 4. Risk assessment For the purpose of this guide, the term failure is defined as any unscheduled event of the transformer and integrated (non-ancillary) accessories that requires the transformer to be removed from service for corrective action. A failure of an ancillary component or accessory might cause a relay to trip the transformer for reasons not relating to the transformer itself, and such a trip does not constitute a transformer failure according to the intentions of this guide. Because the decision to remove a transformer from service will vary with different users, users should create their own specific models based on the general models in this clause. The term fault as used in this clause is not restricted to the traditional electric utility usage, i.e., an unintentional phase-to-ground or phase-to-phase dielectric failure. Instead, in this clause, the term fault may refer to a broader definition, such as a malfunction, defect, or indication of deterioration of a component or accessory. Evaluating and reconditioning of a liquid-filled transformer is not a trivial exercise. Dual objectives of meeting the growing demand of the electric power grid and maintaining system reliability may require significant changes in the way an owner operates and cares for its transformers. An emerging industry strategy is a life-cycle management program that sets loading priorities and provides owners with strategic direction for transformer assets. For the owner that has many transformers, it is usually not economically feasible to subject every aging transformer to a rigorous inspection and extensive testing. Thus, this asset management approach is typically a three-step process: a) Priority screening of transformer fleet b) Diagnostic testing c) Condition assessment of individual transformers Identifying and prioritizing an aging transformer population requires a screening process. The screening could be as simple as ranking the transformers by age. However, a more comprehensive screening can be accomplished with a risk assessment method. There are many different risk assessment methods and strategies available to the utility industry for a large family of power transformers. The method discussed here is a simple procedure called fault tree analysis, which can help identify the transformers that need additional condition assessment, additional testing, and/or other actions for the purpose of bringing the entire population up to an acceptable risk level. Each transformer in a group can have a risk index to rank and compare other transformers on the company’s balance sheet. The risk-based screening process uses statistical methods to identify and prioritize the transformers that represent the highest risk for the owner; however, this step does not identify the actual condition or the vulnerability of the individual transformers. Once the screening process has established a priority list, the next two steps in the process, diagnostic testing (see Clause 5), and condition assessment and reconditioning (see Clause 6), can help the owner establish a detailed asset management strategy. However, the list of variables and the individual utility circumstances that govern the technical and financial decision-making are such that it is impossible to establish an industry-wide set of rules or standards for managing the life cycle of aging transformers. Transformers can be evaluated through the use of online monitoring and each system can be monitored to determine if it is functioning properly. IEEE Std C57.143 is written to aid the engineer in determining the proper tools to use to monitor the transformer. This guide should also be referred to when considering instrumentation to a reconditioned liquid immersed power transformer. The potential cost of a failure in both economic and reliability terms should consider the possible repair or replacement factor of the transformer or failed component, environmental impact and clean-up costs, damage to 13 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers adjacent equipment, lost revenues from energy not served or production loss and litigation costs, as well as any other site-specific potential costs. There is also a large variability in the possible scope of the failure. A component or accessory failure may simply cause a momentary outage and require only a component replacement, or it could lead to a catastrophic failure with an insulating liquid spill and/or a large fire. The relative probability of each type of failure needs to be considered in the calculation of risk. The next ten subclauses (4.1 through 4.10) describe key issues that affect the risk of failure. In the most general sense, risk is defined as future’s uncertainty and has two basic components: the frequency or probability of undesirable events (i.e., how often undesirable events occur) and the severity or consequences of those events (i.e., how much the failure will cost). Obviously, many of these issues address the probability of failure, but some of them affect the severity of the failure. Risk-based methods generally use the product of both the frequency and severity of events together in the analysis process. Regardless of whether the frequency and severity data are subjective, qualitative, or quantitative, a risk-based decision process provides a logical framework to capture and portray several layers of complex data in one cohesive, easily interpreted format. 4.1 Impact on the system The risk assessment of system transformers requires evaluation of severity factors for individual system transformers. The evaluation should address the current and future value for individual transformers. The transformer application can also define the level of criticality for the equipment. A single-source power supply may have higher risk factors than a redundant source load. System operating requirements may have changed since each particular transformer was originally installed in the network. Consideration should be given to the functionality of each individual transformer with respect to the strategic impact of the system. System operating requirements or regulations (e.g., PCB, fire or environmental protection) may have changed since the installation of a particular transformer. Some questions that should be addressed include the following: — Will the transformer meet future load projections like running in parallel with other system transformers? — Is there any change in impedance needed to limit fault duty or improve regulation? — Does the transformer design and manufacturing quality, based on performance metrics, impact system reliability? — Can loads be redirected through other transformers in the power system if the transformer is removed from service, and what seasonal or long-term impact will that have on those transformers? — Will changes in the fire safety standards or environmental regulations require updates to the transformer installation? Although somewhat subjective, answers to such questions will help to define the consequences for a particular transformer failure. System reliability will influence the decision to invest in extending the expected useful life of a transformer. Transformer design rating may necessitate modification, if feasible, to meet anticipated transformer-loading requirements. A change in impedance may be required of a redesigned transformer to limit fault duty or improve reactive power performance and/or improve voltage regulation to acceptable levels. Economic considerations may include the cost of transformer losses, maintenance, and undelivered energy when the loss of the transformer results in a loss of ability to supply load on the system and costs associated with failure including customer incentives. 14 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 4.2 Vintage Manufacturer and vintage can be a factor of transformer quality, material, and component condition. Transformers manufactured in the United States before the 1960s were likely designed prior to advancement in present technology. Being conservatively rated, these transformers may have higher loading capability. However, they may lack adequate provision for leakage flux, have a higher probability of localized hot spots, and have high core losses (due to the quality of core steel available at the time of manufacture). The use of improved quality core steel has reduced the core losses significantly in many of the transformers built since the mid-1980s. Modern core cutting and stacking techniques have also resulted in reducing core losses. Thermally upgraded paper was first introduced in the 1950s, but not widely used by transformer manufacturers until the 1960s. Care must be taken to evaluate temperature-related characteristics of transformers that do not contain thermally upgraded cellulose insulation (based on a rated average winding temperature rise of 55 °C) as compared to those with the upgraded insulation (a rated average temperature rise of 65 °C). Such aspects of original product quality should be assessed. In evaluating the suitability for intended service, the original intended duty and specification should be compared to the anticipated loading and system condition (e.g., fault duty, regulation, stability) as these requirements could exceed the original intended capabilities of the transformer. Caution needs to be taken to help ensure that an existing unit auxiliary transformer or station transformer may not be used as a generator transformer unless there is ample verification of its withstand capability to the new load pattern. The evaluation must also include considerations for changes in pressboard density and loss of axial clamping pressure over time. 4.3 Vacuum withstand capability Transformers designed for vacuum liquid processing and filling should be filled in accordance with the manufacturers’ procedures. Users should be careful to ascertain the vacuum capability of all parts of the transformer including load tap changer compartments, conservator tanks, relays and monitoring equipment sensors. It may be necessary to install temporary equalizing pipes or place valves in other than normal positions to avoid damaging these components before the main transformer tank is placed under vacuum. Transformers that are not designed for vacuum liquid filling and processing can be filled from the bottom with degassed liquid, which may reduce the chance of problems once the transformer has been placed in service. However, this method of processing liquid and filling the tank may introduce tiny bubbles into the insulation. The presence of bubbles in the insulation significantly reduces the dielectric strength of the insulation. The practice of allowing a transformer to stand idle for a specified time, before energizing, will help compensate for the absence of a vacuum by allowing time for bubble dissipation. Allowable time for bubble dissipation will depend on the rate of flow of liquid during filling of the transformer, as well as basic lightning impulse insulation level (BIL) of the unit. A specific number for any timeframe is not recommended by this guide because this value will depend on site situations. If the transformer is equipped with forced-oil cooling, circulating liquid with the coolant pumps can also help flush bubbles or air pockets from the insulated areas, but the user should always be careful to avoid conditions that could cause static electrification conditions and should consult with the manufacturer or other experts if they have questions. 4.4 Paper and pressboard 4.4.1 Insulation Paper insulation is subject to degradation from oxidation, hydrolysis, and pyrolysis. Insulation defects may result from improper assembly, inherent material defects (such as a burr on the conductor), a rough edge on a brazed connection, or damage to the conductor insulation. Defects could be intensified by coil vibration 15 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers or impacts caused during shipment and normal operation. This situation can be monitored by conducting a frequency response analysis (FRA) test and leakage reactance test. FRA and leakage reactance tests may not show significant changes until defects progress to electrical shorts. Baseline test results must be kept as a record and used to compare with future results. Insulation contamination can be assessed by electrical tests like power factor and insulation resistance. See Clause 5 for additional information. 4.4.2 Thermally upgraded versus non-thermally upgraded paper Thermally upgraded paper has been chemically treated to reduce the tendency for hydrolysis and has reduced thermal degradation at normal operating temperatures compared to non-thermally upgraded paper. 4.4.3 Low-density versus high-density paper and pressboard In the mid-1960s, with the exact date depending on the manufacturer, there was a shift to the utilization of pre-compressed, high-density pressboard from low-density calendared pressboard for spacer material within the windings. High-density pressboard has superior compression characteristics in comparison with low-density pressboard. Transformers that have windings manufactured with high-density pressboard will tend to retain higher levels of the clamping pressure applied in the factory than earlier vintage transformers that utilized low-density spacer material. Transformers with higher clamping pressure (tighter windings) have an increased chance to withstand through faults without significant damage to the windings. 4.5 Accessibility and spare parts availability Site-specific contingency plans should indicate the physical limitations regarding accessibility for transformer removal and installation and the availability of spares. Plans should include predetermined solutions for the impediments to a timely installation of the spare transformer. Evaluation of spare parts availability should focus on lead-time and options for replacement, restoration, or remanufacture of obsolete parts. A contingency plan should be developed in the event replacement parts significantly delay restoration of the transformer to service. For critical transformers, such as generator step-up applications, it may be justified to pre-design and/or pre-manufacture critical parts and assemblies for adapting a spare transformer. 4.6 Operational history Loading philosophy should be reviewed and compared to the original design philosophy while noting any limitations. The operational loading experience and/or loading philosophy of the transformer are important. Extended periods of overload (or full load with excessive ambient) or partial cooling may result in sustained high temperatures thereby degrading the windings. NOTE—See IEEE Std C57.91 for additional information on this subject. The fan and pump operational temperature settings are an important factor in how rapidly the transformer insulation ages. Cooler fan operational temperature settings will reduce the rate of aging and allow a higher overload with the same loss of life. Suggested fan operational temperature settings should result in fan operation for temperatures within 30 °C of maximum full load operating temperatures. For example, with a 65 °C rise rating and a 30 °C normal ambient temperature, the fans should run for top liquid temperatures exceeding 65 °C or winding hot spot temperatures exceeding 80 °C. The cooler temperatures, which result by turning the fans and pumps on sooner, will typically lower the winding losses, resulting in slightly higher total energy usage than at the higher temperatures without the fans and pumps running. For large power transformers with directed-oil, forced air flow (ODAF) cooling with voltage ratings of 345 kV and more, care must be taken to avoid operating too many pumps when the liquid is cold (e.g., at startup). Au- 16 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers tomatic control from winding/oil temperature should be used to reduce the risk of catastrophic failure due to static electrification. This recommendation applies to core-form and shell-form transformers. Anticipated loading conditions may subject the transformer to operating conditions beyond original design capability. Risk should be assessed to determine the impact of any design limitations on the remaining useful life. Voltage rating and winding insulation are also important factors to consider. Since the 1970s, some of the transmission line voltage levels have seen a shift in their nominal voltage levels. For example, 110 kV lines are now 115 kV lines. The transformers placed in service prior to this shift were coordinated with lower operating voltages and BILs. Several of these transformers are still in service and require evaluation to help ensure the continuation of reliable operation in today’s operating conditions. Short-circuit duty and the number of through faults experienced by the transformer should be reviewed, and provisions made to protect the transformer from forces in excess of design limitations. In the late 1970s, industry standards were revised to invoke more stringent short-circuit duty, which earlier designs might not meet. Lightning protection and lightning arrester operation history should be reviewed to determine whether a change in the protection is needed to help ensure proper protection coordination and integrity. Condition of coolers is an equally important consideration in assessing transformers. Replacement of coolers and/or pumps with modern cooling equipment could be a justifiable alternative in enhancing transformer performance. 4.7 Type of construction Medium and large power transformers are either core-form or shell-form construction. The primary difference between the two designs is the physical geometry of the cores and the coils. The core-form construction includes concentric high-voltage and low-voltage coils placed over one or more core legs. In most instances, core-form construction lends itself to internal inspections of the core and coil assembly including most of the leads, lead support structure, DETCs, liquid side of bushings, core, and clamping structure. If the outer coil is not wrapped, the outer coil may be visible. The shell-form construction is characterized by a set of “pancake” coils stacked and assembled into a “phase pack.” The phase packs are placed into a lower tank section and supported while the core is then stacked around the phase packs and through a core window in each phase pack. The shell-form construction generally provides a more compact design for transformers; hence, it lends itself more readily to larger power transformer applications. The shell-form construction is such that internal visual inspection beyond the liquid side of bushings, leads, upper bridge structure, DETCs, and top side of the phase packs is not practical. Evidence of problems below the top of each phase pack and top of the core stack (e.g., loose paper, metallic particles) may be available during internal inspection but requires careful analysis. Awareness of the type of construction will aid in risk analysis as some problems are constrained to a certain type of construction, such as T-beam heating found in shell-form designs. Other issues, such as susceptibility to static electrification, may be more common in one type of construction than another, but are not limited to a certain construction type. The transformer manufacturer may be able to provide valuable insights to the end user into past risks associated with a given type of construction and design approaches used during construction. 4.8 Maintenance and repair history A review of transformer maintenance history should be conducted to identify similar occurrences for the transformer being evaluated as well as failure and trouble trends of the transformer population. Industry data for 17 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers similar types or makes of transformers can supplement failure analysis, which is particularly necessary with small system transformer populations. Records of repair history and maintenance can indicate isolated or reoccurring incidents. Documentation of any field inspections and maintenance reports, and any OEM service advisories for the transformer should be reviewed as it may indicate the need for increased maintenance frequency for a suspect condition or known defect. 4.9 Operating environment Loading, service conditions, protection schemes, number of through faults, maintenance, and protection against overstressing and contamination all influence transformer useful life. The level of exposure to through faults may be an indication of thermal and/or mechanical degradation of the transformer. Overhead line exposure increases the likelihood of a fault occurrence. Mechanical overstressing, overloads, short circuits, and in-rush currents impose electromagnetic forces that could result in winding displacement or dielectric breakdown. Winding displacement can also be caused by vibration from transportation shocks or resonance phenomena. Electrical overstress, such as switching and impulse over-voltages and winding resonance, can also lead to dielectric breakdown. If the transformer was stored for a significant period of time between periods of service, the conditions of storage should be noted for possible implications relating to condition. A regular inspection program is recommended for such storage periods, and an inspection log should be kept. The condition of the liquid (assuming the transformer is liquid filled during storage) would be of interest. NOTE—For more information on storage, see IEEE Std C57.93. 4.10 Failure mechanisms Analysis of test data may indicate the need for increased frequency of testing and/or maintenance to monitor or manage a suspect condition or known defect. Failure mechanisms in transformers include excessive moisture and oxygen in the insulating liquid; and paper, creep, fatigue, corrosion, erosion, mechanical wear, and thermal and dielectric breakdown. a) Dielectric strength reduction due to moisture in the insulating liquid and paper. b) Oxygen and moisture in the liquid and paper increases the rate of degradation for both components. c) Creep is a loss of electrical insulation strength along a surface between components at different electrical potential. d) Structural metal fracture due to brittle material can be a result of fatigue. e) A chemical reaction to the surrounding environment can result in corrosion. f) Erosion forms surface deterioration and results in increased leakage current or partial discharge (PD). g) Mechanical wear results from severe or prolonged material stress. h) Dielectric breakdown is the failure of an insulating system to prevent destructive unintended current flow across the insulating space between live parts or between a live part and ground. Dielectric failure is a common failure occurrence and can have a profound effect on useful life. Contamination, thermal aging, repetitive excessive voltage stress, and mechanical deformation hasten dielectric breakdown. Contamination and thermal aging can be monitored through diagnostic testing. Voltage stress can be 18 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers controlled by design of transformer protection and operating philosophy. Severe or excessive voltage stress can lead to dielectric breakdown of the insulation. 4.10.1 Problems with determining component failure probability as function of condition assessment The statistically correct method of determining a system’s reliability is based on assessments of each system component. The assessment of the components then leads to a determination of the values for the components’ reliabilities, and these values are used in the model to calculate the system reliability. A model is constructed for the system that will accurately weigh the effect of each component’s reliability on the reliability of the entire system. The most accurate failure probability data include consideration for equipment of the same manufacturer, age, and design and are calculated from a large population over a sufficiently long period of time. Users may have data on their own equipment that improves accuracy of failure probability values. Methods of calculating these data are explained in Lewis [B35], Billington and Allan [B2]; and Pukite and Pukite [B54]. Risk assessments and failure probabilities are most accurate when applied to large populations of equipment where the positive and negative error range tends to average and cancel out. Applying statistical analysis to the evaluation of an individual transformer to determine the possibility of failure remains a difficult task. To date, there are no accurate assessment tools that will predict when a transformer will fail in service. 4.10.2 Modified event tree matrix and fault tree diagram There are several methods for estimating the reliability or condition of a transformer. The modified event tree matrix in Table 1 is one method that shows how a typical power transformer can be modeled to help identify the root causes of failures. This matrix can then produce a fault tree diagram for system average failure probabilities. The typical event tree breaks the equipment down into components and sub-components, and then lists the failure modes and causes. This modified event tree also contains the Symptoms and Tests or Tools to detect the individual sub-component failures. The fault tree diagram shown in Figure 1 shows a general transformer model. The user should evaluate the design of the transformer in question to determine the components utilized on its equipment before constructing the fault tree model and should add or subtract components or systems and subsystems as required. The fault tree model in this guide uses three levels for each system. The first levels list the possible systems that could cause a transformer failure. The second levels list subsystems that could fail, with that failure leading to a system failure. The third levels list the potential root causes of the subsystem failures. The user can add more layers to any of the branches if more detail is desired. The probability of occurrence for each root cause should be determined from a condition assessment or inspection of the transformer. When any component is found to be in a deteriorated condition, the component’s failure probability should be revised in the model, and a new system (transformer) failure probability calculated. The calculation of failure probabilities in the fault tree model, where any component can lead to a transformer failure, is shown in Equation (1). n Pf = 1 − ∏ Ri (1) i =1 where Pf is the probability of failure 19 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Ri is the reliability (1-failure rate) of each component or subcomponent For example, the fault tree lists two possible events that could lead to an insulating liquid failure in a bushing: loss of liquid and liquid contamination. Also, there are three subcomponents that can lead to a bushing failure: the condenser core, liquid, and shields. In this example, there are seven bushings on the transformer, and all but one bushing is found to be in normal condition. One bushing is found to have deteriorated gaskets, and the probability of a critical loss of insulating liquid is determined to be 33%. The risk of insulating liquid contamination is determined to be 0.1%. The probability of a failure of the bushing’s insulating liquid is calculated as follows: Pf = 1 − (1 − .33)(1 − .001) = .33067 (2) Furthermore, it is assumed that similar calculations have determined that the probability of a condenser failure is 0.3%, and the probability of a shield failure is 0.1%. Using the same procedures, the probability of a failure of this bushing is calculated as follows: Pf = 1 − (1 − 0.003)(1 − 0.001)(1 − 0.33067 ) = .3333 (3) Assuming that each of the other bushings has a failure probability of 0.1%, the probability of a failure of any bushing is calculated as follows: Pf = 1 − (1 − 0.3333)(1 − 0.001) = 0.3374 6 (4) The failure probability of each component/system (e.g., bushing, liquid preservation, LTC, DETC, core, tank and fittings, radiators and coolers, windings and conductors, and relay protection) is also combined using the same techniques to calculate the probability of a transformer failure. If the user creates a model with redundant systems, the failure probability of both systems would be calculated as in Equation (5). n Pf = ∏ Pf i (5) i =1 Where Pf is the probability of failure For example, the failure probability of all coolers on a lightly loaded ODAF transformer with two cooler banks, each with a 1% failure probability, where a failure of one cooler would not require an unscheduled outage would be calculated as follows: Pf = ( 0.01)( 0.01) = 0.0001 (6) 20 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Material/workmanship defects Liquid Loss of liquid Gasket/seal failure/vandalism Liquid contamination Gasket/seal failure/vandalism Corona shields Shields not in place Workmanship Increased power factor Increased capacitance Increased power factor Increased capacitance Loss of liquid Moisture intrusion Gassing PD X X X X X X Thermographic scan Fault recorder PD monitoring Visual X X X X Alarms Overvoltage/elevated operating temperatures DGA Insulation integrity Symptom Power factor/ capacitance Condenser Root causes FRA Bushing Failure Exciting current Subcomponent Winding resistance Component /system Insulation resistance Tests and condition assessment tools Turns ratio Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Table 1—Event table X X Table continues 21 Copyright © 2017 IEEE. All rights reserved. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Coil-ground fault Lead-lead fault Lead-ground fault Winding clamp system Winding distortion Insulation Insulation integrity Through fault/overvoltage/design flaw Through fault/overvoltage/design flaw Through fault/overvoltage/design flaw Exceeded winding design specification/loose winding clamp pressure Through fault/overvoltage/design Gassing flaw Short-circuit current PD Material/workmanship defects or Gassing deterioration with age, Short-circuit current PD Static electrification, application Intermittent dc discharges X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X Thermographic scan Fault recorder Through fault/overvoltage/design flaw X X X X PD monitoring Coil-coil fault Gassing PD Gassing Short-circuit current PD Gassing Short-circuit current PD Gassing Short-circuit current PD Gassing Short-circuit current PD Physical distortion of winding Visual Through fault/overvoltage/design flaw Alarms Turn-turn fault DGA Symptom Power factor/ capacitance Winding/ conductor Root causes FRA Windings/ conductors/ winding clamping Failure Exciting current Subcomponent Winding resistance Component /system Insulation resistance Tests and condition assessment tools Turns ratio Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Table 1—Event table (continued) X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X Table continues 22 Copyright © 2017 IEEE. All rights reserved. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Insulation Lamination insulation Material/workmanship defects integrity Core steel joint Design/workmanship defects opening Insulation integrity Flux heating/structural overstress Core grounding Oil and liquid preservation systems Oil Moisture intrusion Conservator Oxidation Bladder rupture Contamination/mechanical insulation damage/thermal insulation damage Contamination introduced gasket/seal failure Sludge Processing error Material or workmanship defects Piping Incorrect valve position(s) Oil containment failure Human error Improper painting/improper assembly/gasket failure Material/workmanship defects Gassing Reduced dielectric strength Elevated temperatures Reduced liquid dielectric strength Reduced liquid dielectric strength Oil level gauge error Oil inside bladder Pressure relief action Oil leaks Oil leaks Thermographic scan Fault recorder PD monitoring X Gassing Elevated temperatures Gassing Gassing PD Visual X Alarms X DGA Symptom Power factor/ capacitance Core steel Root causes FRA Core Failure Exciting current Subcomponent Winding resistance Component /system Insulation resistance Tests and condition assessment tools Turns ratio Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Table 1—Event table (continued) X X X X X X X X X X X X X X X X X X X X X X X X X X Table continues 23 Copyright © 2017 IEEE. All rights reserved. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Bearing failure Loss of power Fans Motor failure Bearing failure Loss of power Radiator plates Weld failure Rust/corrosion Coolers / tubesheets Cooler case Rust/corrosion Rust/corrosion De-energized Contacts tap changer (DETC) Drive shaft Contact burning/arcing Loss of control Circuit failure/unreliable power supply Elevated operating temperatures/wear out Wear out/design defect Circuit failure/unreliable power supply Improper welding/materials Defective or poorly maintained paint system Defective or poorly maintained paint system Defective or poorly maintained paint system Material/workmanship defects Material/workmanship defects Loss of liquid flow X Thermographic scan Fault recorder X X Loss of liquid flow X Noisy operation, liquid contamination Loss of supply voltage X X X Liquid leaks Rust/corrosion/liquid leaks X X Rust/corrosion/liquid leaks X Rust/corrosion Inability to change taps PD monitoring Visual X X Noisy operation, liquid contamination Loss of supply voltage Gassing Alarms Elevated operating temperatures/wear out Wear out/design defect DGA Motor failure Symptom Power factor/ capacitance Pump Root causes FRA Radiator/ cooler Failure Exciting current Subcomponent Winding resistance Component /system Insulation resistance Tests and condition assessment tools Turns ratio Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Table 1—Event table (continued) X X X X Table continues 24 Copyright © 2017 IEEE. All rights reserved. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Tank Relay components Circuitry/ plugs/ terminals Gaskets Gassing Material/workmanship defects Relay component failure Inability to change taps Inability to control Loss of liquid containment False trip/alarm Processing error Material or workmanship defects Material or workmanship defects, or aging Design/material/workmanship Gas in main tank liquid Gas in main tank liquid Liquid leaks Relay/alarm action X False trip/alarm Design/material/workmanship Relay/alarm action X Material or workmanship defects, or aging Material or workmanship defects Fluid leaks X Fluid leaks X Design/material/workmanship Design/material defect Tank/structure distortion Elevated tank temperatures Gassing Loss of fluid containment Piping Loss of fluid containment Structural steel Structural failure Flux heating 25 Copyright © 2017 IEEE. All rights reserved. X Thermographic scan Fault recorder PD monitoring Visual Alarms DGA Material/workmanship defects Drive shaft Loss of control Control Loss of control circuitry Isolation board Cracks/oil containment failure Gaskets Relay protection system Contact burning/arcing Symptom Power factor/ capacitance Contacts Root causes FRA Load tap changer (LTC) Failure Exciting current Subcomponent Winding resistance Component /system Insulation resistance Tests and condition assessment tools Turns ratio Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. Table 1—Event table (continued) X X X X X X X X X X IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Figure 1—Transformer fault tree 5. Diagnostic tests This clause describes modern diagnostic tests and inspection techniques that are conducted in the field on electrical equipment. Interpretive discussions are also included to provide guidance on acceptance criteria. These activities may help identify existing weaknesses or faults and also give some indication of expected service reliability and remaining life. No single electrical test can assure continued operation. Only the careful recording and plotting of the test results makes it possible to get the full information out of a test and to compare the values with those of previously conducted tests. It should be noted that several assessments might have to be interpreted together to diagnose a problem. The manufacturer’s acceptance criteria should also be consulted because it may take precedence over the criteria in this guide. Additional details can be found in IEEE Std C57.152 on the sections in this clause.2 CAUTION Bushing current transformers should always be shorted and grounded whenever electrical testing is performed on an out of service transformer. 5.1 Dissolved gas analysis Significant information regarding the condition of the insulation system of a transformer can be obtained from liquid testing and correct interpretation of the liquid analysis. It is beyond the scope of this guide to provide detailed technical information on all liquid analysis and testing; however, it is recommended reference the 2 Notes in text, tables, and figures are given for information only and do not contain requirements needed to implement the standard. 26 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers bibliography specifically, Chendong [B11], Dominelli [B17], Horning [B25], Pruente [B53], Vogel [B64], and Wilson [B65]. Dissolved gas analysis (DGA) has proven to be a valuable and reliable diagnostic technique for the detection of fault conditions within liquid-immersed transformers by detecting certain key gases. DGA has been widely used throughout the industry as the primary diagnostic tool for transformer maintenance, and it is of major importance for transformer loss prevention programs. Data has been acquired from the analysis of samples from electrical equipment at factory, laboratory, and field installations over the years. A large body of information relating certain fault conditions to the various gases that can be detected and easily quantified by gas chromatography has also been developed. The gases that are generally measured and their significance are shown in Table 2, based on IEEE Std C57.104. Methods for interpreting fault conditions associated with various gas concentration levels and combinations of these gases are also provided in IEEE Std C57.104, IEEE Std C57.155, IEEE Std C57.146, IEC 60599, and IEEE Std C57.139. Table 2—Gases typically found in transformer immersed mineral oil and ester insulating liquid Gas Chemical formula Predominant source in mineral oil immersed transformers Nitrogen N2 Inert gas blanket, atmosphere Oxygen O2 Atmosphere Hydrogena H2 PD, overheated oil adjacent to hot metal (core or windings) or ferrous metal oxidation in the presence of free water Carbon dioxide CO2 Overheated cellulose, air pollution; natural degradation product of cellulose aging which may be accelerated by heat; or by atmospheric contamination Carbon monoxidea CO Overheated cellulose, air pollution or Natural degradation product of cellulose aging which may be accelerated by heat Methanea CH4 Overheated oil adjacent to hot metal, or PD Ethane C2H6 Overheated oil adjacent to hot metal Ethylenea C2H4 Overheated oil adjacent to hot metal C2H2 Arcing in oil a Acetylene a a Denotes combustible gas. Overheating can be caused both by high temperatures and by unusual or abnormal electrical stress. Laboratory-based DGA programs are typically conducted on a periodic basis dictated by the application or transformer type. Some problems with rapidly increasing gas levels may go undetected between normal laboratory test intervals. Installation of continuous gas-in-oil monitors may detect the start of incipient failure conditions that might allow confirmation of the presence of a suspected fault through laboratory DGA testing. This early warning may allow the user to plan necessary steps required to identify the fault and implement corrective actions where possible. Present technology exists that can determine gas type, concentration, trending, and production rates of generated gases. The rate of change of gases dissolved in liquid is a valuable diagnostic tool in terms of determining the severity of the developing fault. A conventional unscheduled gas-in-oil analysis is typically performed after an alarm condition has been reported. The application of on-line dissolved gas monitoring may considerably reduce the risk of missing detection or of prolonged delay in detecting fault development due to a typical on-site interval of sample. Additional information on this subject is found in IEEE Std C57.143. The review of all of the DGA history for a unit is of high importance for determining the operating condition of the transformer and needs to be done when considering life extension options for the unit. 27 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 5.2 Liquid quality assessment (physical tests) Over years of operation, insulating liquid quality typically deteriorates significantly. An important part of the life extension of a transformer is the restoration of the transformer insulating liquid quality. The insulating liquid quality has implications on virtually all operational characteristics (e.g., dielectric performance, aging rate and thermal performance). Depending on the condition of the insulating liquid, it may be justified to reprocess, reclaim, or replace it. For the purpose of this guide, the diagnostic tests for insulating liquid quality described in IEEE Std C57.106, IEEE Std C57.111, IEEE Std C57.139, IEEE Std C57.147, and IEEE Std C57.152 are highly recommended as references. Particular attention should be paid to the moisture in the insulating liquid. The measurement of moisture in insulating liquid is considered a routine test (in addition to other physical characteristics of the insulating liquid) performed in the laboratory on a sample taken from the transformer. Another aspect related to the dissolved moisture content is the relative saturation of the moisture in the insulation liquid. The relative saturation is calculated from the dissolved moisture content and fluid temperature. The relative saturation indicates the conditions when the dissolved moisture content will form free moisture. Moisture in the transformer reduces the insulation strength by decreasing the dielectric strength of the transformer’s insulation system. Moisture, heat, and oxygen are the key factors that affect the rate of cellulose degradation so it is important to maintain dissolved moisture content as low as possible. Moisture level in the insulating liquid depends on the operating condition of the transformer (e.g., moisture content in the solid insulation and temperature) as well as the type and condition of the fluid. Fluid acidity and particle content can increase the capacity of the fluid to absorb moisture. Usually this situation can be corrected by fluid reclamation or, for more severe cases, by fluid replacement. Additional information on this subject is found in IEEE Std C57.637. Higher levels of moisture as given in their specific fluid maintenance guides may be more acceptable in fluids such as silicone or ester liquids than in mineral oil due to differences in moisture saturation characteristics of those fluids. Although the use of these types of fluids is relatively recent and not yet common, such differences should be considered in the interpretation of the implications of moisture content. Assessment of the level of moisture in the paper should be made, preferably by on-line monitoring of the insulating fluid moisture level, (see Vogel et al. [B64]) to complement the liquid assessment. Off-line tests using dielectric frequency response (DFR, refer to 5.5.1), also known as frequency domain spectroscopy (FDS) will estimate the gross amount of moisture in the solid insulation system. Reduction of moisture in insulating fluid will not necessarily reduce the solid insulation moisture content sufficiently if the moisture level is high because of the required time for moisture to migrate between the solid insulation and the fluid. (see Clause 7). 5.3 Corrosive sulfur Sulfur is present in refined oils depending on the degree of refining and the type of crude oil stock. Some sulfur compounds act as natural antioxidants, and their presence in the oil is useful. At high temperature, sulfur decomposes on hot metal surfaces to produce metal sulfides that can affect the conductivity of metal contacts of the switching equipment. Although uncommon, sulfide formation may also occur at lower temperatures, especially on silver plated surfaces. The determination of corrosive sulfur in the oil in service is seldom necessary. Tests such as DIN 51353 (silver strip), ASTM D1275 (copper strip), and IEC 62535 may be used to determine the presence of corrosive tendencies. 28 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Recent international experience [CIGRÉ Technical Brochure 378] indicates that in special circumstances, such as high operating temperature, high load and low oxygen content (sealed/nitrogen blanket equipment), copper sulfide (Cu2S) has been formed on the solid insulation. The presence of this conducting compound in the insulation may lead to failures. It has been demonstrated that existing test methods (DIN51353 and ASTM D1275) for detecting corrosive sulfur tendencies are sometimes unable to detect the specific sulfur compounds that may cause this phenomenon so the IEC 62535 is available as a test method. 5.4 Solid insulation system analysis One of the latest insulating fluid test methods to help determine the condition of the insulation system is a test of furanic compounds. This method is designed to help determine the overall degradation of the cellulose within the apparatus. Methods or guides for interpretation of the results have not been universally adopted of this test. However, much research has been done, and some guidelines exist (see Bouchard and Lapointe [B7], Shroff and Stannett [B42], Chendong [B11], Burton [B8], Dominelli [B12], and Horning [B17]). A summation of the available research on furanic compound analysis as it relates to transformer cellulose material is available from the Electrical Insulation Magazine, vol. 28 issue 2 [B9]. Furanic compounds are a family of molecules based on a furan ring structure. The furanic compounds are generated in various amounts by the degradation of cellulose (paper) and are, therefore, a paper degradation marker. 5.4.1 Furanic compound analysis This method of transformer condition analysis involves the measurement of trace furanic compounds in transformers insulating liquid and relating the furanic content to the degree of polymerization of the paper insulation and to the remaining life of the insulation. The origin of furanic compounds are the five-member heterocyclic ring compounds that are produced as the cellulose breaks down due to thermal stress. Cellulose degradation produces other products also, such as carbon oxides and water, which are the ultimate degradation products. The furanic compounds are intermediate degradation products, which are liquids, and remain in the liquid in trace quantities. At least six furanic compounds have been detected in transformer liquid in units: furoic acid, 5-hydroxymethyl-2-furfural (HMF), furfuryl alcohol, furfural, 2-acetylfuran, and 5-methyl-2- furfural, according to Burton and others who published the original research on furanic analysis in 1984 (see Figure 2) [B8]. Figure 2—Typical furanic compounds The most common analytical technique is high performance liquid chromatography (HPLC), which involves extraction of the furanic compounds from liquid, followed by injection of a small quantity of the extract into a special column in the HPLC equipment. The column separates the components, and a chromatogram of peaks is produced that shows the individual compounds and its concentration. Details may be found in IEC 61198 and ASTM D5387. Other techniques such as GC-MS [B8] and colorimeter [B45] are described in the literature. 29 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 5.4.2 Correlation curves of furanic content with DP3 [B1] Furan levels in transformers are typically less than 0.1 ppm [some laboratories report furan content in parts per billion (ppb)—1,000 ppb is equivalent to 1 ppm] and can remain at this level throughout the life of the transformer. However, in many older units levels of up to 1 ppm, and in some cases 10 ppm, have been measured in mineral oil insulating liquid [B44]. In a study of over 5,000 European transformers [B12], a significant number were found to have furan content higher than 1 ppm. Several researchers have reported correlation curves between the furan content in liquid and the corresponding average DP of the cellulose insulation. Although none of these equations are exact, they allow one to estimate the DP of the insulation from the more easily obtained furan content. Four equations proposed by Chendong [B11], DePablo [B15], Pahlavanpour [B47], and Shkolnik [B60] are as follows: 1.51− Log10 ( F ) 0.0035 (7) 7100 8.88 + F (8) Chendong DP = DePablo DP = Pahavanpour DP = Shkolnik DP = 800 (9) (0.186 X F ) + 1 1.17 − Log10 ( F ) 0.00288 (10) DP is the estimated DP value and F is the 2-furfural (or furan) content in ppm. A graphical representation of these equations is given in Figure 3. Figure 3—Correlation of Furan Content with DP 3 Clause 5.4.2 provided by ABB Inc., Service Manual for Transformer. 30 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers The latest research on this topic as mentioned in this subclause suggests that the aging of thermally upgraded kraft paper does not produce as much furans as kraft paper. Other findings [B18] [B19] are that the most significant production of furans occurs below a DP value of 400. It is known that the Shkolnik curve was derived from data collected on transformers with predominantly thermally upgraded insulation and is in agreement with recent research findings. Since the Pahlavanpou and DePablo curves were derived from European transformers, it is highly likely to be for predominantly kraft insulated transformers and the recent research discussion bears this out. The Pahlavanpour curve is derived from the same data as the DePablo curve, but assumes a more realistic aging pattern for transformers: 20% of the winding paper and the inner paper layers degrade twice as fast as the rest of the paper insulation. The Chendong curve is suspected to be derived from transformers with mixtures of kraft and thermally upgraded insulation. [B43] Use the curve in Figure 3 that is closest to the insulation type for the transformer under consideration to estimate the DP value from furan concentration(s). Once an estimate of DP has been obtained using one of the given equations, the conditions outlined in section 5.4.2 can be used to estimate the amount of expended insulation life. 5.4.3 Issues to consider in using furan analysis Below is a list of some of the issues that should be considered in applying this analysis to transformers: a) Long-term stability of furanic compounds in liquid: If these compounds are not stable in liquid for long periods, we should at least know the rate of degradation. If we know the rate of generation from lab studies, we could perhaps adjust for the losses and estimate the absolute furanic content. b) Distribution of furanic compounds between paper and liquid: The furanic content of liquid is related to the furanic content of the paper insulation. The latter is dependent on the paper to liquid ratio and the temperature. The distribution between paper and liquid should be known over a wide range of ratios and temperatures (just as moisture distribution between paper and liquid). c) When the liquid in a transformer is changed (as in a reprocessing operation), most of the furanic compounds are lost. This is similar to dissolved gases being lost during liquid change. It may, therefore, be necessary to maintain accurate records of prior analysis. d) Correlation curves for different types of paper and pressboard materials would be needed to make meaningful correlation to DP from furanic estimations. e) Thermally upgraded paper and non-upgraded paper give significantly different results because of the chemicals used in thermally upgraded papers. Make sure you are using the proper correlation curves for your transformers. It is not advisable to de-energize a transformer based on furanic analysis alone. This test provides an indication of the health of the paper. Furanic analysis is recommended by many experts to give an indication of expended life. 5.5 Capacitance, power factor, and dissipation factor The dielectric loss is the power dissipated by the insulation when ac voltage is applied to any insulation system. All electrical insulation has a measurable quantity of dielectric loss, regardless of condition. Good insulation usually has a very low loss. Power factor testing consists of applying an ac voltage (not to exceed the rated voltage of the equipment being tested) and measuring the leakage current across and through the insulation system. Because an insulation system can be represented as a resistor and a capacitor in parallel, the power factor of the insulation can be defined as the result of leakage current (IR) divided by the total current (IT). The leakage current, and proportionally the power factor, will increase as the insulation system deteriorates. 31 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers The power factor test and the dissipation factor test are two similar methods of measuring the dielectric loss of an insulation system. The two terms power factor and dissipation factor are often used interchangeably even though they have slightly different mathematical characteristics. Power factor is a dimensionless ratio of the resistive current to total current flowing through the insulation. Dissipation factor (also known as tan delta test) is a dimensionless ratio of the resistive current to the reactive current flowing through the insulation. By convention, these factors are usually expressed as a percentage, which is one hundred times the value obtained from the basic calculation. Because most field-testing is done in energized stations, it is important that the test equipment be properly shielded to prevent electrostatic interference from influencing the test results. Most test equipment manufacturers are familiar with the problem and have a method of eliminating or cancelling the interference. If unusual readings are encountered, verify that the equipment is working properly before proceeding. If the tests show an increasing trend in the power factor, further investigation is warranted to determine the cause and possibly repairs before further degradation occurs. Determination of the cause of increased power factor is usually made by analyzing all of the available test data to find the problem. If the high power factor readings are caused by contamination in the liquid, there will be corresponding results in the liquid analysis. Increased liquid power factor may be the result of moisture or polar and ionic compounds in the liquid. This contamination may also reduce the dielectric strength of the liquid. A power factor test can also be run on the liquid itself. Moisture in the insulation system is another cause of increasing power factor. The moisture level of the liquid will help determine whether this situation could be the source of the problem. If the insulation is determined to be wet, a procedure for drying the unit can be implemented. Such procedures include filtering (on or off line), vacuum processing, or un-tanking and drying at a transformer repair facility. Internal inspections and repairs are possible in the field, but much of the insulation is inaccessible without de-tanking the transformer. If field repairs are made, care should be used to help ensure that the replacement materials are properly processed, compatible with the remainder of the system being repaired, and capable of withstanding the expected operating conditions. Bushings are often a source of high power factor readings. These parts can usually be tested in place and, as with the transformer, previous data are used to evaluate the results. If it is determined that a bushing or bushings are the cause of the problem, they can be replaced or repaired. The main capacitance, C1, of a bushing is the capacitance between the high-voltage conductor and the voltage tap (115 kV bushings and above) or the test tap (69 kV bushings and below). The capacitance C2 of a capacitance-graded bushing is the capacitance between the voltage tap (115 kV and above) or the test tap (69 kV and below) and the mounting flange (ground). — Capacitance C1 is measured during the power factor test of the bushings and must be very close to the value shown on the nameplate of the bushing (tolerance ± 5%). — Capacitance C2 is measured during the power factor test and is used as a benchmark, especially when measured during the initial installation of a brand new bushing never exposed to moisture or humidity. Deviation of the C2 measurement from the nameplate on future power factor tests could also be used to determine whether there has been moisture intrusion in the potential tap or near the flange. However, this result does not necessarily determine the internal condition of the bushing core. During the reconditioning process, consideration should be given to adding on-line bushing monitoring as online monitoring provides the ability to detect a bushing problem well in advance of periodic testing. Besides the fact that on-line bushing monitoring continuously tests the degradation of bushing power factor at an earlier stage it also tests the bushing at its operating voltage which is often substantially higher than voltages used 32 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers to conduct periodic tests. Testing at operating voltage has been shown to be more effective in allowing early discovery of degradation of power factor [B52]. In its application to high voltage bushings, the measurement of Dissipation/Power Factor at low frequencies (some Hz) enables the detection of moisture with high sensitivity. Figure 4 demonstrates the typical moisture sensitivity of the Dissipation/Power Factor Measurement on oil impregnated paper (OIP) bushings between 20 Hz and 400 Hz. Particularly on high-voltage bushings the measurement of the Dissipation/Power Factor at low frequencies (some Hz) enables the detection of moisture with high sensitivity. Dissipation/Power Factor Measurement on OIP bushings: Figure 4—Dissipation/power factor measurement on OIP bushings at different frequencies Typical limits for new and aged bushings are provided in Table 34 corrected to 20 °C. Table 3—Typical limits for new/service-aged bushings (% corrected to 20 °C)[B14] Resin Impregnated (RIP) Frequency New Service Aged Oil Impregnated (OIP) New Service Aged Resin Bonded (RBP) New Service Aged 15 Hz <0.6 <0.7 <0.5 <0.7 <0.7 <1.5 50/60 Hz <0.5 <0.5 <0.4 <0.5 <0.6 <1.0 400 Hz <0.6 <0.7 <0.5 <0.7 <0.7 <1.5 IEEE Std C57.152 provides additional guidance on in-service bushing capacitance testing and evaluation. The Guide states that a careful comparison of bushing nameplate and previous test results with changes in values of 5% from initial/nameplate values being investigated for continued serviceability. 5.5.1 Dielectric frequency response spectroscopy Dielectric frequency response is detailed in Table 45. 4 5 “New diagnostic for High Voltage Bushings” reprinted with permission from CIGRÉ, CIGRÉ International Conference Iguaçú ©2010. Frequency Domain Spectroscopy Figure 39, reprinted with permission from CIGRÉ, Technical Brochure 445, page 58, ©2011. 33 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Table 4—Dielectric frequency response spectroscopy (DFR) [B12] Detectable conditions The water content in solid cellulose insulation of oil and paper insulation and developing, insulation failures. DFR also detects contamination of insulation liquids from particles and acids. Indication DFR provides an indication of the moisture content of the solid insulation and condition of the insulating liquid. Test method The principle of this measurement is the same as Capacitance and Dielectric Power/Dissipation Factor described previously but the difference is that it is applied at different frequencies, typically from 0.001 Hz to 1000 Hz as shown in Figure 5. The DFR test is performed using low voltage. Selecting the test voltage level is a compromise: too high a voltage may introduce significant voltage dependent effects at low frequencies, however too low a voltage may make it impossible to suppress interference currents that may be several orders of magnitude greater when compared to insulation loss current at low frequencies. Test voltage levels typically used today are 140 V rms, but higher voltages may be used in high interference environments [B26]. The test voltage should be recorded for future reference. Reference Modeling and baseline signature comparisons are used to evaluate the transformer moisture content. Guidelines for the insulation system condition evaluation are given in in IEC 60422. IEEE PC57.161 [B26] draft also gives guidance on the DFR test method. Interpretation Moisture determination is based on a comparison of the transformers dielectric response to a modeled dielectric response. A curve fitting algorithm matches the measured data to model results stored in a database, and finds the best fit curve. From that it derives the moisture content and the oil conductivity. A reliable moisture analysis of on-site measurements is based on an exact data pool for the modeled dielectric response. The data pool consists of measurements on new pressboard at various temperatures, moisture contents and oils used for impregnation. New procedures consider also the dielectric properties of aged pressboard as well in order to compensate for the influence of aging. Once water content has been assessed, refer to the limits for dry, moderately wet and extremely wet insulation that are given in IEC 60422. Comments The combination of time domain polarization current measurements with frequency domain spectroscopy may reduce the test duration compared to existing techniques. Figure 5—Example dielectric frequency response [B1] 5.6 Frequency response analysis Frequency response analysis (FRA) is a diagnostic technique for detecting geometric change(s) related to the internal characteristics of a power transformer. The FRA measurement produces a transfer function from the resistive, capacitive, and inductive elements that represents the mechanical geometry of a power transformer. Detecting mechanical change or damage to transformer windings is one of the main interests of FRA test measurement. Such changes can result from various types of electrical or mechanical stresses (shipping damage, 34 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers seismic forces, loss of clamping pressure, short circuit forces, etc.).The measurement is performed over a wide range of frequencies and the results are compared with a reference “signature” or “fingerprint” to make a diagnosis. NOTE—See IEEE Std C57.149 for a detailed explanation of FRA. There are several distinct reasons to generate diagnostic FRA measurements: a) After factory short-circuit testing b) Relocation and commissioning validation c) Post incident: lightning, external through-fault, internal short circuit, seismic event, etc. d) Routine diagnostic purposes e) Condition assessment of older transformers f) Evaluation of used or spare transformers The FRA test has been driven by the desire to detect mechanical failures within a transformer. Failure modes are not exclusive to geometric variations within a transformer and can include variation in the core’s magnetic circuit and contact resistance. FRA test variations may indicate a single type of failure or a combination of two or more but may not show significant change until the defect progresses to a short-circuit. FRA is known to be useful in detecting the following failure modes: — Radial “hoop buckling” deformation of winding — Axial winding elongation “telescoping” — Overall-bulk and localized movement — Core defects — Contact resistance — Winding turn-to-turn short circuit — Open circuited winding — Residual magnetization 5.6.1.1 Analysis of results Transformer designs and applications vary greatly so the FRA results require interpretation. However, the FRA trace over specified frequency ranges, has a degree of predictability; low frequency core effects, main winding effects, and short circuit responses. These expectations can be used to identify basic problems that may exist within a transformer. Additional information can be found in IEEE Std C57.149. Trace comparison is the primary method for the analysis of FRA results. Comparisons can be made against: a) Baselines b) Similar units c) Across phases 35 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Traces can also be examined for expected patterns. 5.7 Partial discharge detection Partial discharge (PD) occurs in an insulation system when a localized breakdown of the insulation medium causes a redistribution of charge within the system. PD generates low-amplitude voltage and current pulses that are within radio range of frequency. Several techniques are available to detect and measure these signals in transformers. Two techniques consist of direct electrical measurements, and results are measured in microvolts of radio frequency energy or in pico-coulombs. The other method consists of acoustical measurements with an ultrasonic transducer. It is possible to locate an active discharge in the transformer by comparing the signals from acoustic and from electrical detection. NOTE—Additional information can be found in IEEE Std C57.127 and IEEE Std C57.113. 5.7.1 Electrical measurements Because PD is an electrical phenomenon, electrical measurements allow for the most direct and quantifiable data. PD measurements in the field can be accomplished using at least two different methods. The first method is the field-induced test, which is similar to factory testing, where a portable high-frequency generator system is used to excite the transformer. The second method involves exciting the transformer at the power frequency either from the utility grid or from an isolated generator. The field-induced test for older transformers is typically done at voltages somewhat less than the full-induced voltage test levels as specified in IEEE Std C57.12.00. Typical tests are done at 75% to 85% of the IEEE test levels for a duration of anywhere from 30 min to 60 min. The voltage level and test duration are based on assessment of the age and condition of the bulk insulation and bushings or other components and the capacity of the test generator. Utilizing power frequency for this test may saturate the core at excitation higher than the rated transformer voltage. PD activity may be measured using either the radio influence voltage (RIV) method or the apparent charge method. Each method has its own relative advantages and disadvantages. The RIV method is less affected by external noise from the power system, but may be affected by radio stations. It also is generally less sensitive to discharges deep within the transformer windings. (The RIV of equipment was historically measured to determine the influence of energized equipment on radio broadcasting; hence the name RIV.) Typically at 100% test voltage, if the PD magnitudes are less than either 100 µV or 500 pC, the transformer is considered acceptable. If the levels are above 500 µV or 1000 pC, then the transformer may be suspect. For values in between, the results are questionable, and further testing may be needed to more precisely characterize the risk. Advanced PD measurement methods are available that can effectively filter out external noise influences to selectively measure the PD activity in the windings. These methods involve narrow band measurements at certain resonant frequencies of the transformer to amplify the PDs and reduce the background noise. With this type of measurement, a transformer may be tested with excitation from the power grid. In other instances, the natural attenuation of PD between windings can be used to isolate the high-voltage winding while exciting a low-voltage or tertiary winding. Another advanced measuring method involves the measurement of a PD pattern based on a three-dimensional plot of the PD magnitude, phase angle of the pulses, and the number of pulses. Different types of insulation defects produce different but recognizable patterns, and the PD test result can be compared to a library of test results to make a judgment about the cause of the PD. In addition, the test can often establish a relative location of the PD within the transformer by PD pulse shape characteristic and time displacement between the bushings. One of the primary means of detecting PD is to measure the small voltage pulse, or current pulse, that accompanies every discharge. In a typical transformer, there may be thousands of PDs per second; thus, there may 36 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers be thousands of pulses detected every second. The voltage pulse can be detected by means of high-voltage capacitors, which are normally connected to each phase terminal. A bushing test tap or an existing surge capacitor can be used, or a small capacitor can be attached to the terminal. The capacitor has a high impedance to the power frequency, but appears as a low impedance to the high-frequency PD voltage pulses. Special circuits are used to convert the pulse signals from analog form to a digital form. Some of these special meters include spectrum analysers, quasi-peak pulse meters, and RIV meters. One of the most common approaches is to use pulse height analysis. The analyser measures the number of pulses and magnitude of each individual pulse and plots them. There are also pulse phase analysers, which digitally record where the PD pulses occur with respect to the power frequency. Interpretation of test results requires some experience with PD tests and with the type of device being tested. Pulse-height and pulse-phase analysis are most commonly combined in all modern instruments. Those systems record the number of pulses, the height of each pulse and plot these against the exciting phase frequency. This results in typical PD pattern which can be compared to a library of known PD patterns of failure modes. PDs caused by static electrification are typically intermittent dc discharges associated with the build-up of static charge resulting from forced-oil flow past cellulose surfaces. Such discharges are totally different from PD associated with ac voltage and must be detected differently. There have been many instances where such discharges were detected audibly as pinging or banging inside the transformer at intervals ranging from a few seconds to many minutes. 5.7.2 Acoustic The acoustic method of detecting PD offers good sensitivity to many types of PD sources and, in some situations, permits the site of the source to be located inside the transformer. The acoustic technique has the advantage that, when properly applied, it can be used on energized equipment and it is less susceptible to interference from outside sources. Acoustic signals are measured using ultrasonic transducers that are coupled to the outside wall of the transformer tank. In addition to the transducers, the other test equipment components are an amplifier and a display device. Self-contained, portable acoustic detectors are available for quick go/no-go field test programs. However, locating the PD source requires specialized measurements and custom-designed software and equipment. 5.8 Infrared inspection Thermography is a noncontact means of identifying thermal anomalies relating to electrical and mechanical components that are exhibiting an excessive heat loss. This situation may be indicative of poor connections, excessive stray flux, blocked cooling circuits, or other problems that have the potential for causing eventual failure of the transformer. An infrared thermal scanning camera is used to record thermal images for subsequent analysis and identification of corrective maintenance action. The self-emitted radiation in the infrared portion of the electromagnetic spectrum is measured at the target. 5.8.1 Noncontact thermal measurement The component to be measured should be at normal operating temperature. Because heating varies directly with the square of the current, component loading will directly affect the thermographic image. The current level should at least be 40% of rated full load. If measurement is recorded when the equipment is not at full load, the maximum temperature rise can be estimated by Equation (11) and Equation (12). For cooling by natural convection and radiation: I  Trisemax = Trise meas  rated   I meas  1.67 (11) 37 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers For cooling by forced convection and radiation:  Irated  Trisemax = Trisemeas   I meas  2 (12) where Trise max Trisemeas I rated I meas is maximum temperature rise is measured temperature rise is rated current is measured current How a surface appears in the visible spectrum is the same way the surfaces will appear in infrared. Temperature readings should be taken from target surfaces that are dull in the visible spectrum. When focusing on the target, get close enough so the target occupies a sizable section of the viewer screen. Look at the target face on, and move around to eliminate reflections. Most thermal scans of equipment in metal enclosures will not give good readings unless the heat is of a high enough intensity to heat the enclosure. Therefore, panel doors and cabinets should be opened or panels removed, as necessary, to obtain good thermal scans. 5.8.2 Maintenance scanning Thermographic scans are usually performed on a semi-annual or annual frequency. The ambient temperature, transformer winding and top liquid temperature (instantaneous and maximum), and load information should be recorded for future reference. Establish a baseline for the component under normal load and operating conditions to facilitate identification of abnormalities. A comparison of phases in a three-phase system will indicate a uniform temperature pattern for balanced load and a non-uniform pattern for an unbalanced load. An unbalanced load can be distinguished from an anomaly, as the temperature is relatively constant along the component when component size and mass are the same. The manufacturer’s literature should be checked to verify upper limits for actual temperature. 5.8.2.1 Transformer main tank Determine normal operating temperature of the transformer tank, examine all sides of the enclosure, and record any temperature rise greater than or equal to 10 °C. In addition, similar measurements and criteria should be used for generator step-up transformers in the area where they are connected to the generator bus duct. Improper bus connections or deterioration of connections over the service life can result in excessive heating in the vicinity of the interconnection and the transformer tank. 5.8.2.2 Bushings Determine the normal operating temperature, and document any temperature rise greater than or equal to 10 °C. 5.8.2.3 Load tap changer (LTC) Record the tap position and tap changer counter, examine the tap changer, and record the temperature differential relative to the main tank. Reactor LTC types should never be hotter than the main tank. Resistor LTC types may temporarily show higher liquid temperatures than the main tank. 38 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 5.8.2.4 Control cabinet Examine all connections and components. An understanding of control component functions is necessary, as high temperatures on some components may be normal operating temperatures. Record any temperature greater than or equal to 10 °C above normal. 5.8.2.5 Overhead For connections and other ancillary equipment, determine the normal operating temperature, and document any temperature rise greater than or equal to 10 °C. 5.8.3 Temperature rise An acceptable maximum surface temperature rise is dependent upon the environment of the equipment, severity of duty, significance of the equipment to the operating system, and equipment type. Knowledge of possible sources of measurement error (such as surface emissivity and solar reflections) is required for accurate readings and interpretation. Maintenance and operating personnel who are most familiar with the equipment should have the responsibility for judging the seriousness of an abnormal condition. Table 5 presents guidelines to use in the analysis. Table 5—Suggested temperature rise recommendations Temperature rise above local ambienta (°C) Action 0–10 Take no action 10–25 Record and plan to reinvestigate within 3 months to 6 months 25–70 Schedule an investigation and/or possible repair Above 70 Investigate immediately a Local ambient refers to immediate surrounding area. For example, the overall transformer tank temperature will be at least as hot as the top liquid (40 °C to 60 °C above air temperature) without there being a problem. However, a spot on the tank that is 25 °C hotter than the surrounding tank area deserves further investigation. 5.9 Degree of polymerization Degree of polymerization (DP) testing is used as a precise measure of the degradation of the paper insulation used in transformers, cables, and capacitors. Cellulose, (i.e., the main constituent of paper and wood) is a large linear polymeric molecule constituted of several hundreds of glucose units. DP is the average number of glucose molecules making the cellulose chains. The DP value decreases with time as the cellulose molecules break and fragment. The rate of deterioration is very much temperature dependent. The following is a summary of the latest findings on DP analysis for power transformer diagnostics: — Many researchers and transformer insulation experts suggest DP at the end of life in the range 100−200, with most favoring a value of 200 [B56]. — Pahlavanpour [B45] presents results that show that the DP of kraft paper starts decreasing at 120 °C. The rate of decrease of DP increases rapidly with increasing temperature and reaches end of life at a DP of 180 °C. — Hill [B24] found a nonlinear relationship between tensile strength and DP. They found the tensile strength of kraft paper decreases slowly with decreasing DP until the DP reaches a critical value of 500 °C. At this point, the decrease in tensile strength is more rapid with decreasing DP. — Lundgaard [B33] found that the aging of thermally upgraded kraft paper is slower by a factor of about three and is less sensitive to moisture; the activation energy for the aging of Thermally upgraded kraft 39 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers paper is the same as that of kraft paper; the aging of Thermally upgraded kraft does not produce as much furfural (furans) as kraft paper; the effect of water on aging of transformers is more dramatic than oxygen; aging of liquid also increases the acidity of the liquid; Thermally upgraded kraft paper produces more acids than kraft paper. — Moser [B39] reports that an increase of 0.5% water content in an aging transformer will reduce the value of DP by one-half. The difficulty, however, is that in order to get a sample of paper the transformer must be opened. Moreover, the areas of greatest deterioration of cellulose material in a transformer (the hottest spot), is usually not easily accessible for obtaining paper samples. Once a transformer is manufactured, the paper with the highest probability of becoming weakened is usually in locations that cannot be easily accessed without risk of damaging the transformer. As a result, collecting the paper samples from a transformer may jeopardize the reliability of the transformer. For in-service equipment, taking paper samples must be limited to areas that, after repair, will result in a negligible increase in the probability of failure as a result of the paper sampling. Locations are selected based on judgment, but should usually be in the upper part of the transformer where top liquid temperatures are the highest. A coil lead, bushing draw lead or a crossover connection could be such a location. For this reason, furanic analysis discussed in 5.4.1 can be used to calculate an estimate of the average DP for transformer insulation. It has been shown that the DP method provides a direct correlation between tensile strength and the DP result. The DP values range from an average value for new paper of about 1200 (i.e., on average, each cellulose chain contains 1200 glucose units) down to values for aged paper as low as 100. At a DP value of 200, a direct correlation has been shown to agree with paper that has lost approximately 70% of the original tensile strength. At this point, the paper becomes brittle, and the transformer can be deemed to be at the end of its useful life due to its loss of tensile strength (e.g., Shroff and Stannett [B63]). The test method that should be specified for determining the DP is ASTM D4243 with the IEC 60450 equivalent test method. The paper used in electrical equipment is assumed to age at a more rapid rate where the temperature of the paper and exposure to moisture and oxygen are the highest. In order to collect samples for DP tests, the paper should be collected from locations that have the most rapidly aging paper. Collection of samples that are directly in contact with the conductor is important. If the transformer liquid has been exposed to air, the outer layer of the paper should also be tested. To obtain a sample of paper in contact with the conductor often requires the removal of a considerable amount of insulating material. It is important that the insulation be carefully removed and the location and layer from which the paper was removed be documented. The repair of the insulation system requires great care. For example, paper tapes must be properly applied to replicate the previous insulation. Often paper tapes should be pre-impregnated with clean dry liquid. The concept that “more paper is better” is a poor idea as excessive paper can cause hot spots by restricting the cooling of the conductor. It is recommended that properly trained personnel repair disturbed sections of the insulation system. If a transformer has failed and duplicate transformers exist, a good opportunity is presented for collecting samples from the failed unit that may be representative of identical units, particularly when the loading conditions have been the same. Such conditions exist for many generator step-up transformers. In these cases, the best locations for samples will be in areas of the windings presumed to be the hottest. For core-form transformers, this location will be near the top of the coils. For shell-form transformers, this location will be directly over the top of the core were the liquid flow is the least. 40 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Unfortunately for most transformers that are in service, the results of DP tests will result only in values that may not be representative of insulation that is in a higher state of deterioration. If these samples are below a DP of 300, the transformer may be at the end of its life. Collecting the paper samples is an important process, and the following guidelines and Table 6 are presented to help ensure that the samples are collected and identified properly for laboratory analysis using ASTM D4243 or IEC 60450. For routine testing, a) The minimum weight of liquid-impregnated paper with excess liquid removed is 300 mg. b) The minimum weight of non-oil-impregnated paper is 175 mg. Table 6—Dimensions of required DP paper sample Thickness [mm (in)] Area [cm2 (in2 )] 0.08 (0.003) 39 (6) 0.13 (0.005) 23 (3.5) 0.25 (0.010) 13 (2) For samples from failed transformers, a quick means for acquiring samples is to cut about 15.24 cm (6 in) of the conductor out of the coil and wrapped insulation. Wrap the sample in plastic or place in a plastic bag, and identify the source and location. The aging of the solid insulation is not uniform; therefore, the more paper samples tested, the better in order to understand the spatial distribution of relative aging of the solid insulation. Darker areas of insulation are an indication of advanced aging and should be candidates for testing. It is best to collect as many samples as possible and then test as many as needed to obtain the desired information. Figure 6 is an example of the information that should be provided with the samples. Samples collected from different locations should be separated and clearly identified so that analysis of the results will be logical. Samples should be protected from the environment. The use of sealed plastic bags is a method of separating samples. The testing facility should be consulted to discuss the different types of testing available, the accuracy of the different test methods, and associated sample requirements. NOTE—Insulation cannot be varnished or impregnated with any material that will not be readily removed by rinsing with solvent. If the insulation is impregnated with anything other than the insulating liquid used in the transformer, it is unlikely that the DP measurement can be made. 41 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Figure 6—Typical DP sample information form 5.10 Vibration and noise Noises may be caused by insignificant conditions, but they may also be early indications of conditions that could cause a failure and should always be monitored and investigated using methods that will reduce the risk of failure and injury. The human ear is a valuable tool in assessing equipment condition. However, the use of noise is subjective. Site checks are, therefore, best carried out with regular visits by the same qualified personnel. They can become accustomed to the usual sounds heard so that any new or unusual sounds or noises may be obvious to them. New sounds can usually be located as coming from the tank, pumps, fans, or other components attached to the tank. Certain audible sounds are readily identified, but in some instances, the levels of sound, their tone, and direction may often be more apparent than real and are then difficult to locate and identify. However, any new or changed sound level is worth investigating. 42 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 5.10.1 Internal noise Increased levels of sound emanating from the tank could result because windings have become loose due to shrinkage or short-circuit movement. The sound due to such changes would generally have a tonal frequency of twice the operating system frequency. This change in sound could also be the result of loose leakage-flux rejecters or collectors. Abnormal overloads could also increase the level of sound or the tonal content emitted, both from normal winding vibration and leakage-flux collector saturation effects. Damaged or loose cores could contribute to modified sound characteristics, as could any changes to the mechanical clamping or anchorage of the “active part” structure. Overvoltage and/or under-frequency will cause excessive flux and hence possible saturation of the core. This situation would result in higher sound levels and changing tonal composition. Superposition of dc on the exciting current can cause much higher sound levels as well as extra tonal harmonics. Broken or loose leads supports, or tank wall shields and supports can be responsible for a change in sound levels and tones, especially if the natural frequency of these structures is close to a harmonic of the system power frequency. 5.10.2 External noise Broken or loose external components can cause modified sound characteristics. Valve wheels and handles can become loose and vibrate when their retaining nuts become unlocked. Cabinet or other component anti-vibration mounts can fail and allow the component to rattle in sympathy with the normal transformer tank vibration. Fans and pumps should be manually energized to help ensure proper operation. Any significant noises (e.g., grinding, rubbing, scraping, vibration, or loose fan guards) should be noted and investigated further. LTC motors may start to make different sounds if their bearings wear or if their windings become damaged. Additionally, if contacts become worn, different sounds may be noticed during the tap change operation. 6. Condition assessment and reconditioning In order for a transformer to continue in reliable service for an extended period, every effort should be made (economically and operationally) either to regain the relevant original performance characteristics or to modify the loading and/or its application duty as appropriate. It is technically feasible to regain many of the factors that directly affect the long-term reliability. After completion of the risk assessment and thorough diagnostic testing, the owner may have been able to reduce to a more manageable number the transformers that are candidates for condition assessment. Condition assessment includes both nonintrusive and intrusive evaluations. Obviously, the intrusive or internal evaluation is the most costly, most time consuming, and highest risk procedure. An internal evaluation may also be risky, depending on the age and condition of a transformer. The decision to perform this assessment must not be taken lightly. These inspections require great care and knowledge of transformer construction. Although the condition assessment is considered an inspection, some components may be considered for upgrading or replacement at this time. Refurbishment or replacement of these components might arguably be considered as a comprehensive maintenance exercise, which may not contribute directly to the life extension of a transformer. Nevertheless, new or refurbished components could increase versatility and reliability, and they should be considered at this time because there is an opportunity to do so while the transformer is out of service. The intrusive inspections and the transformer components are addressed in 6.1 through 6.8. 43 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers NOTE—See Clause 6 and Clause 7 of IEEE Std C57.152 for additional information on the inspection of electrical safety and inspection techniques. 6.1 Core and coil assembly 6.1.1 Core and coil inspection Proper coil clamping pressure is required for the winding to withstand axial short-circuit forces. As a result of thermal and mechanical cycling over time, vertical clamping forces (axial) on the coils can be reduced below the level required to hold the coils stable during through-fault events. Inadequate coil clamping pressure has been known as a primary cause of transformer winding failures due to through faults. Coil clamping pressure generally reduces gradually over time at a different rate for different windings or for different layers of the same winding. The primary reason is that total accumulation of cellulose insulation between the fixed top and bottom clamps can take a permanent set over time under static loading and dynamic loading. Mechanical creep characteristics of compressible, non-elastic material are much more pronounced on low-density material such as found in older transformers. For this reason, loss of clamping pressure on coils is more prevalent in older units. Another contributor to the loss of coil clamping pressure is shrinkage of the cellulose, which is caused by thermal cycling due to load variations in service. The original equipment manufacturer or designers that are familiar with the design of the transformer should be consulted before re-blocking to reduce the possibility of damaging transformer components. Manufacturers have gone out of business or sold the rights to the design information. There may be knowledgeable repair concerns or consultants that have experience in re-blocking vintage of transformers. At the time this guide was published, the only recognized method for evaluating coil-clamping adequacy was an internal inspection. Re-clamping the winding is one of the most constructive measures to extend transformer life. For life extension, an internal inspection should be done to observe loose blocks, key spacers, and wedge blocks. If loose blocks or key spacers are discovered, re-clamping should be considered in order to regain the strength needed to withstand forces generated during through faults. Prior to making the decision to re-block and re-clamp, it would be prudent to investigate whether the transformer is a suitable candidate for life extension. Factors such as DGA, FRA, DP, and furan analysis can be invaluable in determining the suitability of re-blocking and re-clamping the transformer. If diagnostic test results indicate that serious problems exist in the transformer, it would not be advisable to re-block and re-clamp at this time. It is not advisable because increased clamping pressure may exacerbate the condition that is causing the generation of a particular gas, and could possibly cause the transformer to fail soon after energization. If the testing identifies serious problems and if the source of problems can been found and eliminated, the transformer should be returned to service and monitored. If symptoms of problems do not persist, the transformer may then be reconsidered for the re-blocking and re-clamping. Hydraulic jacks, pumps, and hoses are normally utilized for re-clamping and re-blocking. A good practice is to employ new hydraulic equipment for this task and to substitute the hydraulic fluid with transformer liquid. In the event of pump, jack, or hose leaks, the transformer will not be contaminated by hydraulic oil. Even with new hydraulic equipment, it should be thoroughly flushed with transformer liquid in order to remove any hydraulic fluids. If a liquid leak from the hydraulic jack is detected while applying the pressure, even if you changed the hydraulic oil to transformer liquid, itis advisable to retain the liquid that has been leaked by containment means. This liquid coming from the leak could have metallic compounds that can affect the performance of the transformer. Normal practice is to mount the pump and manifold outside the transformer on the cover, only hoses go inside with the hydraulic jack. 44 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 6.1.2 Oil distribution box inspection and reconditioning Directed oil, forced air flow cooled transformers (e.g., ODAF) may include an oil collection box near the bottom of the transformer tank. The purpose of the box is to direct liquid from the pumps into the bottom of the coils. During the internal inspection of the core and coils discussed above, the oil box should be inspected for structural damage such as tears or blowout of bolted joints. Implication of a breach of this box are that cooledoil flow in coils is reduced and that winding temperatures will be higher than with a box that is sealed as intended. The rupture typically occurs in the window area of the core at an overlapping pressboard seam. If a ruptured box is found, properly sized pressboard should be ordered for the repair. On-site repairs to restore the integrity of the box are usually feasible by replacement of damaged pieces or by installing new material over the damaged areas. It is important to use only appropriate dried and liquid-saturated material for this repair. One common repair method is to cut and install a piece of pressboard through the window area from one side of the oil box to the other. The patch in the window area should be wide enough to be partially wedged under the two adjacent winding assemblies in the ruptured area. See [B48] for additional information. Because possible causes of damage to the oil box include the repeated starting and stopping of all pumps at once, a recurrence may be avoided by reviewing the operational procedures and cooler control characteristics and modifying them as necessary. 6.1.3 Re-blocking and re-clamping of transformer coils—core type transformers An important characteristic of core and coil assemblies is their design for maintaining adequate clamping of the windings to sustain them during through-fault events. Coil assemblies (including end blocking and collars) are clamped between the upper and lower core frames. The vertical distance between the top yoke frame and the bottom yoke frame is maintained by tie-plates or rods assembled adjacent to each core leg or maintained by rods installed outside the coils. Final assembly coil compression is accomplished by various means of expanding the gap between the upper collar (or clamping ring) and the top yoke clamping assembly. The most common method is to insert scissors jacks or bottle jacks between the yoke assembly and the clamping collar. Once a predetermined coil-height dimension is achieved, filler blocks are installed or screw-jacks are adjusted to hold the dimension after jacks are removed. Once the coils are clamped, the entire clamping system is rigid, and there is typically no provision to compensate for shrinkage in the solid insulation system. The pressure is therefore expected to reduce gradually over the years. Some large power transformer designs include dashpots (i.e., oil-filled spring-loaded pistons and cylinders) for coil clamping. This system helps ensure positive clamping pressure even with moderate changes in coil height. Clamping pressures are transmitted through the columns of radial key spacers. The clamping pressures are normally specified as the pressure exerted onto the radial key spacers. There is, however, no industry standard, and clamping pressures vary widely. The total force in clamping the coil is calculated by multiplying the area of key spacers covering the conductors by the clamping pressure, which should be greater than the pressure expected from axial forces produced by the winding during a fault condition. For example: Key spacer area High-voltage winding (high voltage spacer area dimension) × (number of spacers) = High voltage area (13) 45 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Low-voltage winding (low-voltage spacer area dimension) × (number of spacers) = Low voltage area (14) Total key spacers area (high voltage area + low voltage area) = Total area (15) The required clamping pressure and total area equals a total clamping force. Normally, the coils may be re-clamped to the original values specified by the manufacturer. However, if there are possibilities of insulation damage or conductor tilting due to previous faults, the insulation damage must be evaluated and clamping pressure may be reduced accordingly to a lower value, e.g., 60% of original clamping pressure. The purpose of re-blocking is to restore the transformer’s through-fault withstand capability. Restoration of a portion of the original compression will improve this capability. The original equipment manufacturer or designers that are familiar with the design of the transformer should be consulted before performing re-blocking to help ensure that components should not be damaged. 6.1.3.1 On-site re-blocking and re-clamping process Investigation for loose blocking is relatively simple, as described in this subclause. However, correcting for the loose blocking is complex along with the specific winding and blocking geometry that should be carefully considered in order to avoid inflicting damage to the windings and incurring a subsequent increase in failure risk. The re-blocking plan should be developed by personnel with knowledge of the specific winding and blocking design. With knowledge of original pressure, a new pressure objective can be established; however, keep in mind that reestablishment of original pressure may be unrealistic. In a core form, it is not necessary to adjust the lower coil blocking because clamping pressure is applied to the entire lengths of each concentric coil during this process. — Checking for loose blocking. Loose blocking can be checked by rapping the blocking with a mallet and observing any movement and listening to the sound the mallet makes. Loose blocks will make a dull sound, and the mallet will not bounce back. Sometimes, however, it is difficult to identify a loose (under inadequate pressure) block that is glued securely. — Re-blocking and re-clamping. The total force exerted on the coil is controlled by the pressure in the hydraulic line, which is calculated based on the bore diameter of the jacks. A set of four (or more) bottle jacks, hydraulic hoses, a common manifold, an accurate pressure gauge, and a pump will be required for re-blocking and re-clamping coils. The bottle jacks are to be positioned evenly on the end ring. There are usually provisions to accommodate the bottle jacks. — The existing clamping pressure may be checked by slowly applying pressure to the end ring and noting the force at which the coil blocking becomes loose and can be removed. — Repacking loose blocking may be a tedious process. With the coil still under pressure, the loose blocks are identified and marked. Next, the clamping pressure is released. Loose blocks may then be glued and repacked with various thickness of high-density pressboard paper. The whole process may have to be repeated a few times to help ensure all blocks are tight. Besides rapping the block with a mallet and listening for the sound, the tightness of blocking can be roughly determined by the amount of residual liquid squeezed out of the wooden blocks. — Hydraulic jacks versus torque wrenches. Hydraulic jacks can be used to provide a fairly accurate clamping force. On transformers that are equipped with jacking screws and have no provision for the bottle jacks, jacking screws may be tightened with a torque wrench to provide the proper clamping force according to the empirical formula in Equation (16). T= kDN 12 (16) 46 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers where T is torque Nͯ m (ft ͯ lb) k is torque factor D is diameter of bolt cm (in) N is tensile load on bolt kN (lbf) — The problem with using this equation is the selection of a value for the torque factor k. Unfortunately, this torque factor can vary anywhere from 0.1 to 0.3, depending on the bolt size and friction coefficient. The wide variation is a result of surfaces that can be rough, smooth, oxidized, chemically treated, or lubricated (see Haviland [B23]). Oily steel has a range of 0.11 to 0.17. Because the values of the torque factor vary widely, this equation should be used with caution. — One important aspect of the coil re-clamping job is to help ensure that all windings share the clamping load. Disk and helical windings have a large percentage of cellulose in their axial build; therefore, they are soft. Layer windings have much less cellulose; therefore, they are hard or stiff. If soft and hard windings are clamped together and if they have the same unclamped height, the hard winding would take the majority of the load. It is a bit of an art to assure appropriate sharing of the clamping load. In some cases, it would be necessary to install additional radial blockings with steps of different thickness to redistribute the clamping load onto the different windings. — Another concern to be considered is the possibility of unexpected shifting of winding conductors as a result of the application of pressures. A layer (barrel) winding, for example, includes an axial alignment of conductors so that axial pressure could result in overlapping of conductors (lateral alignment versus series alignment) and subsequent compromise of dielectric integrity. Pressure must be increased slowly with careful monitoring of pressure changes. If a comparison of movement to pressure change is indicative of a “soft” winding, the procedure should be halted to mitigate possible damage. — The owner should consider performing a FRA after re-blocking to establish a baseline response pattern for assessment (by comparison) of coil movement, deformation, and/or looseness later. If FRA was previously performed for the re-blocked transformer, it will be voided by the coil shifting during the re-blocking procedure, and a new baseline would be necessary. 6.1.4 Re-blocking and re-clamping of transformer coil—shell-form transformers In shell-form transformers, the windings consist of conductors wound into flat “pancakes” and assembled with insulation barriers, washers, and formed parts to become phase packages. Each phase package is suspended above the bottom tank section so that the core can be stacked through and around the phase legs. Therefore, a substantial portion of the phase packages are effectively clamped within the mass of the core material, surrounding all but the upper and lower portions of the package. Because the shell-form transformers have a form-fit tank construction, the side walls of the tank fit the core assembly snugly and, by supporting it, provide additional support to the phase packages. The top and bottom ends of the phases are blocked during manufacturing using wood wedges, wedge guides, and packing board for a tight assembly. The clamping design of shell-form transformers can differ depending on the manufacturer and vintage. In all cases, the procedures mentioned in this guide should be applied with caution. The original manufacturer or someone knowledgeable with the design and manufacturing practices of the specific transformer involved should be consulted. Furthermore, the on-site person(s) doing the actual re-blocking should be skilled in this endeavor. Depending on the manufacturer, there are three types of phase-wedging design for three-phase shell-form transformers: a) An upper wood inter-phase blocking wedge system b) An upper steel inter-phase frame with wood wedges system 47 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers c) A “circular shell” or “round shell” system, which does not have wood wedges Circular shell transformers have aluminum interphase and end pressure plates. The end plates are tightened from the outside with a set of steel bolts and wall-welded nuts located above and below of the core stack. During the manufacturing of these units and after the final drying process, those steel bolts are tightened and welded to nuts to avoid possible liquid leaks through the thread. An attempt to re-clamp these phase packages in the field will be intrusive because the steel bolts have to be cut to remove them. Also, the nut threads must be clean and their threads redone. A set of new bolts must be installed. The aluminum pressure plates are combined with phenolic barriers against the phases. There is no maple lumber involved in this clamping arrangement; therefore, the shrinkage should be minimal. Because of these described distinctions of the circular shell design, re-blocking is considered impractical, and the remainder of this subclause will focus on the other design types. Single-phase transformers are similar in construction among the manufacturers in that there is no interphase blocking to be considered. In the special case of three-phase transformers known as a “seven-leg core,” there is also no inter-phase blocking, and the treatment will be the same as the single-phase type. If, during an internal inspection of a three-phase “D-core” design transformer (i.e., the most commonly used core design with a non-step lap), it is noticed that the inter-phase upper blocking has become loose, the transformer should be evaluated for re-clamping in the field. It will be necessary to consider all the internal dimensional limitations as well as accessibility of the upper wedges. 6.1.4.1 Adding packing to the block wedges in the field An internal inspection will be necessary to gather information needed to prepare the packing material and the tooling. For example, it will be necessary to measure the length of the wedges for use in preparing the packing board (the length of the wedges will be the width of the packing board). Because the only access to the transformer will be through the manholes, the dimension of the manhole opening must be taken into account when preparing the packing board materials. Typically, the board material is dried out and liquid impregnated to avoid shrinking during field processing. A judgment call has to be made during the internal inspection to determine how much packing will be needed. This decision will depend on how loose the wedges are. It may be prudent to prepare additional packing. If any of the wedges are found to be cracked or damaged, they should be replaced as needed using appropriately sized maple lumber, previously dried and liquid impregnated to avoid shrinkage. 6.1.4.2 Three-phase transformers with maple wood blocking wedges For three-phase transformers with wood blocking wedges, it is typical to have a two-piece wedge set between phases, as shown in Figure 7. Tightness can be assessed by tapping on, and/or attempting to lift, the wedge whose larger end is up. It should not be possible to lift or shift this wedge. When it is determined that the transformer is to be re-blocked, an internal inspection must be performed for scoping the task. When all the needed packing boards are ready, the inter-phase wedges must be removed. It is customary to begin with the area between phase A and phase B. Depending on how loose the wedges are, it may be necessary to use hydraulic jacks to relieve pressure from some of the inter-phase wedges for their removal. All the hydraulic equipment used inside the transformer must be in optimal condition to avoid an internal spillage; extreme caution must be used when doing this work. Additional maple lumber may be needed as tooling to spread the wedge guides or wedge retainers. Figure 8 shows a typical arrangement of hydraulic jacks. 48 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Figure 7—Three-phase wood interphase blocking 49 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Figure 8—Three-phase wood interphase blocking Apply only enough pressure to loosen the wedges, up to 10 342 kPa (1500 psi). If adjacent wedges have not become loose at this pressure level, the pressure should be increased slowly until the wedges start to loosen. The wedges can then be removed, starting from the center and moving to the outside. Once all of the wedges are out, the hydraulic jacks can be carefully removed. With the wedge guides loose, packing material is placed between the wedge guides and the phases. The packing material can be placed on just one side, but it is preferable to place the packing on the back of both wedge guides. Do not add the packing board between the wedges and the wedge guides. Always place the packing board behind the wedge guides. Once the packing is in place, the jacks are placed between the wedge guides and pressure applied. The wedges are put back in place, starting from the inside and working to the outside, in the same way they were removed. Pressure is applied as needed to open the wedge guides [usually 17 237 kPa (2500 psi) is adequate], and the wedges are placed between them. It is important that an excessive amount of pressure is not applied so to avoid 50 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers causing any permanent damage. Consult a manufacturing representative for confirmation of the pressures used. The use of more than two jacks could be necessary for better and more uniform pressure along the wedge guides. Check the tightness of all wedges. When the re-clamping between phases A and B is complete, then the re-clamping between phases B and C can be started. The previous steps are then repeated to pack this blocking. Wedges located between the phases and the tank (on phases A and C sides) will be addressed in 6.1.4.3 because they are placed using a method similar to single-phase wedging. 6.1.4.3 Phase-to-tank wedging—three-phase transformers with upper steel inter-phase, seven-leg core transformers, and single-phase transformers Re-clamping for these three different cases will all be done in a similar fashion. In all of these cases, the phase pack will be between the wedge guide, with the wedges and the shunt packs or bundle shields. For these types of transformers, if the wedging becomes loose, it is more difficult to get additional packing in place because of the size of the wedges and the space available. In this case, it may be necessary to use a hydraulic jack with jaws that can fit into the appropriate clearance and can open to 9.525 cm (3.75 in). Figure 9 shows the case for a three-phase transformer with steel framing and wooden wedges. Once the packing material and the tooling are ready, the hydraulic jack is placed as shown in Figure 8 to start spreading apart the wedge guide and the board. Pressure is then applied to it; and when the wedge is totally loose, it is then pulled out of the assembly. The hydraulic jacks are then moved to the next notches, and the procedure repeated until all of them are removed. Additional packing is placed between the phase packs and the wedge guides. Then, using the hydraulic jacks, the maple wedges are put back in place again, in the same sequence as they were removed. Once the wedges are tight on this side of the phase pack, the other side of the phase pack is done. When one phase is complete, move to the next phase and repeat the process. It will be necessary to repeat the same process six times (two sides per phase). Figure 11 is a single-phase transformer that utilizes the same procedure for the side to tank wedges as was utilized for the end phases on a three-phase unit because both cases have the same configuration and it is necessary to follow the same steps. For three-phase, seven-leg core transformers, the addition of board packing uses the same method as a single-phase, but it is repeated three times, one per phase. In this variant of shell-form transformers, the phases are rotated 90° with respect to a horizontal line along the tank length similar to having three single-phase units sharing the same core. Instead of having a common opening for all phases, there are three different openings, one per phase. The addition of packing board in this case starts with the removal of the fiber studs and nuts that keep the wedge retainer in place, a maple piece, the wedge retainer shim, and a pressboard piece bolted to the inside frame with the fiber studs. The removal of the studs and nuts is necessary to gain access to the maple wedges. In most of the cases, this step was already done in order to size the wedges and the packing material. The wedges are removed using the hydraulic jacks shown in Figure 10 to spread the wedge guide and the pressboard packing. Following the same procedure described in the previous subclause, the wedges are all removed, and the additional board packing is placed between the phase and the wedge guide. The wedges are inserted back in place using the hydraulic jacks to spread the wedge guide and the pressboard piece. The same steps are repeated until the last wedge is placed. If needed, the tightness of the wedges should be verified and more packing material added (it is always a good idea to add at least one extra piece of thin packing to the original estimate to assure the wedging will be tight). Once this step has been completed, the 51 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers wedge retainer and wedge retainer shim are inserted into place, using the fiber studs and nuts to help ensure they are tight. Figure 9—Three-phase steel frame interphase and wood blocking 52 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Figure 10—Three-phase steel frame interphase and wood blocking 53 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Figure 11—Single-phase, seven-leg, or end-phase wood blocking 6.1.4.4 Core clamping jacks Many older versions of shell-form transformers with steel inter-phase frames have a system of jack bolts that press down on the top core blocking and/or onto the core itself. However, newer units of this type have a set of compressed springs on the core joint areas in conjunction with the jack bolts. As part of the re-blocking assessment for this type of transformer, the tightness of the jack bolts should be checked. The most common size 54 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers size jack bolt is 3.175 cm (1.25 in) –7 NC diameter steel bolts, and these should be tightened to 610 N × m (450 ft × lb) of torque. 6.1.4.5 Assessment of potential re-blocking effectiveness The effective natural clamping provided by surrounding core material was discussed in the opening sentences of 6.1.4. Various methods for restoring clamping pressures for top coil sections have been addressed. No methods have been discussed for restoring pressure for bottom sections because this area is inaccessible in shell-form transformers. Typically, there is no space for movement because the one-piece bottom wedges are enclosed and compressed between the inter-phase shielding and the inter-phase core section. For the transformers having a steel inter-phase bottom frame, the shrinkage is minimal because the wood content is less. There are concerns that re-blocking the top section would not improve reliability or effective life of the transformer because material shrinkage will weaken the bottom coil section and this area cannot be re-blocked. However, the top section is the area with the leads and the lead support structure attached to the phases, which is more susceptible to shrink than the bottom section. The reason for expecting improvement of through-fault survivability by re-blocking the top section is to maintain all the leads and copper bars so they are properly supported and clamped as they were originally designed. When the top section of the phase becomes loose, that looseness will make the leads and copper bars lose support, and this area will create a problem when the clearances are reduced because of the lack of proper support. When the top section re-blocking is done, the lead support structure must be retightened to assure it is back to its original strength. 6.1.5 Shielding Historically, winding shields have been of two types: line shields and ground shields. Line shields usually enclose irregular shaped components of the line end of a winding, are electrically attached to the winding lead, and help contour and control the voltage gradient in these high-stress areas by their effect on capacitance coupling of turns. Ground shields are used in some transformers to control the capacitance between windings and ground planes such as the core and tank. Typically, these shields are placed in the main gap between the high-voltage and low-voltage windings. Usually, a paper-taped lead is brought out of the winding assembly and attached to a core-clamping member, which is grounded. Because line shields for both core-form and shell-form transformers are usually an integral part of the winding, it is difficult or impossible to inspect these shields as part of an internal inspection. However, one can look for areas of burning or “spitting” in the line end of a winding as a possible indication of PD activity. Ground shields are quite different from line shields in that an insulated lead is normally used to ground the shield outside the winding assembly. On core-form transformers, these leads are normally brought out at the top of the winding and can be inspected for mechanical tightness of the hardware, which is usually a bolted connection to the core clamp. The electrical integrity of the lead can be examined visually, and a capacitance measurement of the ungrounded shield lead can be made to the adjacent windings. The measured capacitance should be significant if the lead is continuous to the shield. Occasionally, ground shields can become disconnected from the lead through age and service. In this case, the measured capacitance will be quite low and can serve as an indication that a problem exists. An additional benefit can be realized by disconnecting the ground shields and letting them “float” electrically, while making conventional power factor and capacitance measurements between the high-voltage and low-voltage windings. Usually the ground shield acts as a barrier to this particular test measurement, and no practical value is obtained. On shell-form transformers, the close proximity of the tank to the core and coil assembly usually restricts an inspection. Improper connection of a shield can be detected through monitoring of dissolved gas concentration. However, at the time this guide was published, the only recognized method for evaluating shield integrity was an internal inspection. For life extension, an inspection should be done to observe for the conditions mentioned. 55 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 6.1.6 Bus and leads Over years of service, bus and lead supports can develop weaknesses, such as cracking of structural members or loosening of the bolted structure interconnections. Physical stresses from through-fault currents can damage the support structure for a bus and/or lead. Bus and/or lead insulation components can become dielectrically weakened by abrasion and/or tearing as a result of normal vibration or through-fault-induced movement. Reasonable efforts to correct such damage should be made. If damage is found in areas not correctable in the field, consideration should be made to send the transformer to a repair facility. Leads should require little maintenance, but they do need to be inspected whenever possible. During transformer inspections, the leads should be checked to see that the insulation (normally crepe or linen tape) is intact and firm. If the paper close to the conductor is damaged, the insulation will have soft spots. The leads should also be checked to see that they are attached to the cleat assemblies properly to prevent movement. Check for signs of broken supports or loose hardware that would allow the leads to move, and then repair any damage. If the leads have been moved to change bushings or make repairs, ensure that there is adequate clearance after the work is completed. If insulation is damaged or missing and if repairs are to be made, care should be taken to replace with insulation similar to the original design criteria. The manufacturer may have to be contacted to obtain this information. Too little insulation can reduce the voltage withstand, and too much can cause overheating in some conditions. If the leads themselves are damaged, there is little that can be done to repair them. Usually the lead can be replaced. Manufacturers and repair shops normally keep lead materials on hand. When splicing leads, take care to ensure that the new lead is the correct size and length. When completed, the splice should be properly insulated and the lead secured. Leads should also be inspected at terminals to check for signs of overheating. Leads should be sized for the expected loads. Overheating is a sign of loose connections or other problems that should be investigated before returning a transformer to service. Lead supports should be constructed to hold the leads securely during both normal operation and during fault conditions. Ideally, the leads are held in place by a clamping arrangement, but are sometimes tied to supports with tie wraps or cloth tape. While inspecting the leads and lead supports, consider the forces during fault conditions. Particular attention should be paid to points of physical stress such as secured points and points of pressure against edges and corners of structure. If the leads come loose, they can move and possibly create short circuits in the tank. Consider both phase-to-ground and phase-to-phase clearances in these inspections. 6.1.7 Flux control For large power shell-form and core-form transformers, designs typically include control of stray flux to avoid excessive heating of the tank and/or other magnetic components. A particular transformer may include either or both of the methods discussed in 6.1.7.1 and 6.1.7.2. 6.1.7.1 Flux shielding Flux shielding prevents magnetic component heating by repelling (blocking) flux impingement through strategically placed nonmagnetic plates or sheets between the protected area or component and the flux of concern. Common materials for flux shielding are aluminum and copper. For shielding the tank walls, sheets or plates of such material are mounted on the inside wall closest to the coils. By repelling the flux at its surface, shielding forces the flux lines to paths parallel to the shield surface until the flux bends back toward its source to continue its loop. Because of its capacitive coupling to the adjacent coil(s), the shielding has the potential to establish significant voltages if not properly grounded. Defects in the design and/or manufacture of its grounding may cause PD and resultant gassing or may cause tank wall or other component heating due to equalizing currents between separate shield components. 56 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Inspection of flux shielding components should be a part of a transformer’s internal inspection. Areas of spot heating, loose mounting, ground lead burning, etc. are indications of problems with the shields that can result in eventual transformer failure. 6.1.7.2 Flux shunts Another method of avoiding tank wall and other stray flux heating is to include magnetic shunts in the transformer. Typically, these shunts are designed and manufactured into shunt packs, consisting of wound or stacked packages of thin strips of grain-oriented magnetic steel. As compared to the repulsion of flux shields, the shunts provide a low-reluctance path for the flux to efficiently (low losses and low heating) flow along the area protected on its path to complete its loop back to the source. As with flux shielding, the shunt packs can acquire significant voltage by their capacitive coupling to the adjacent windings and should be inspected for loose mounting, burn spots, etc., for signs of abnormal heating. As in the case of flux shielding, defects in shunt pack design and/or grounding can result in PD and component heating. Shunt packs are typically used in shell-form transformers to protect the many areas of the tank sides and bottoms from stray flux heating. For the shell design, most of these areas are not observable without un-tanking the transformer. The best way to assure the proper functioning of shunt packs on a shell-form transformer is to review infrared results. 6.2 Tap changers 6.2.1 De-energized tap changer (DETC) 6.2.1.1 DETC external inspections When performing an external inspection on a DETC, caution should be used when operating the DETC through tap positions. Internal hardware may break, or contacts may become misaligned so that an extended outage is required to internally repair the DETC. The external DETC shaft should show no signs of liquid leakage. If leakage is noted, it may require seal replacement or bearing attention. The control handle or actuator should have a provision for padlocking added if it is not already present. During the inspection, the DETC should be operated through all tap positions to verify its operability. If attempted operation reveals that the mechanism is seized, the gearbox should be inspected for corrosion or misalignment. If it is confirmed that the mechanism is seized inside the tank, an internal inspection should be made to observe any binding parts in the internal assembly. Also, the contact alignment and condition should be confirmed for each tap position. A transformer turns ratio test will help determine whether the actual ratio and the handle indicator are correct for each phase. CAUTION Under no circumstances shall the DETC be operated when the transformers has voltage applied. Such operation may result in failure of the transformer and possible injury to the operator. 6.2.1.2 DETC internal inspection The purpose of DETCs as part of the transformer design is to allow selection of appropriate or optimum turns ratio for the transformer’s performance in its operating position. Because this device is typically the only current-carrying component in the transformer that is not bolted, crimped, or brazed to assure its continuity, proper contact alignment and conductivity between moving and stationary contacts are critical for reliable transformer performance. Unless properly designed, manufactured, and maintained, this component can become a weak point for transformer reliability. A typical failure mode for a DETC is coking, metal flow, and/or welding of contact surfaces due to increases of contact resistances over time. 57 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Although there are DGA interpretations that can provide warning of tap contact progressive failure (see Pruente [B53]), typical templates for interpretation of gas combinations do not include warnings for this particular anomaly. Left unchecked, contact failure can generate an explosive accumulation of combustible gasses. Typically (if not uniformly), manufacturers of transformers and tap changers recommend periodic exercising of the DETC by operating the tap changer through its range of settings and back to the operating position. This movement creates a wiping action on electrical contact surfaces and tends to clean them from accumulated carbon and/or corrosion and contamination materials. Unfortunately, what manufacturers commonly recommend is not commonly practiced by users, and the DETCs of many transformers remain in the same position for the life of the transformer. During the internal inspection, the DETC should be operated through all tap positions while the contact assembly is observed directly by the inspector inside. Particular attention should be paid to the condition of the mating surfaces in the position in which the DETC has been in service. Any sign of coking or surface heat damage should be investigated for corrective action. Spring pressure between the moving contact and stationary contacts should be checked to ensure a proper connection. Stationary contacts can be bolted or crimped to corresponding tap leads, which should be inspected for tightness from development of high resistance in the connection. External handle rotation is translated into contact movement by a series of steel shafts and gears. Each of these components should be inspected carefully for condition and alignment. Typically included in the shaft assembly are one or more couplings to allow relative movement of mounting points (e.g., tank-wall and lead assembly). These couplings should be inspected for their potential for decoupling, which would allow movable tap assemblies to drift from their connected positions and the possible creation of open circuits in the current paths in the transformer. Recent findings relating to relative performance of various contact designs suggest that tap assemblies that include silver plating on stationary and moving contacts are less susceptible to increases in contact resistance and eventual heating problems. Therefore, it is recommended that any rebuild or rework of taps include silver plating on fixed and moving contacts. Prior to energizing the transformer after any DETC tap change or tap movement, the following tests should be performed to ensure that all taps are properly connected and aligned: a continuity test, transformer turns ratio test, and contact resistance test. 6.2.1.3 DETC maintenance As part of a transformer upgrade and service life extension, the contact assemblies should be inspected for evidence of poor performance, such as discoloration and/or material flow (melting) of contacts and also film or carbon buildup (coking) in conducting contact area. If degradation is observed, the contacts should be reconditioned which may include new or resurfaced contacts. If contact design or spring design problems are suspected, redesign should be included in the upgrade. DGA history should be reviewed for evidence of hot spots that could be related to tap contact performance (e.g., hydrogen, ethylene, ethane, and finally acetylene.) The internal tap assemblies and their operating shafts/gears should be inspected carefully for alignment and physical condition. The tap changer mounting structure can be damaged by shipping and/or through-fault stresses or by maintenance activities inside the transformer. Any damage with potential for negative consequences should be repaired in place if practical. If not field repairable, consideration should be given to removing the transformer to a repair facility. 58 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 6.2.2 Load tap changer (LTC, also known as OLTC) 6.2.2.1 LTC inspection The load tap changer (LTC) external condition needs to be monitored and maintained periodically. External conditions, such as liquid leaks, rust, peeling paint, dirt, or various types of debris buildup on the LTC, may in time compromise the internal integrity of the LTC. Leaks may lead to a low-liquid condition in the LTC and compromise its ability to provide dielectric strength and arc-suppressing functions internally. Liquid leaks may also be an ingress point for moisture to enter the LTC and promote oxidation. Should sufficient oxidation by-products and moisture be allowed to build up in an LTC, insulation materials will prematurely deteriorate, and the dielectric function of the liquid and insulation will suffer. This situation can lead to failure. The abrasives in the oxidation by-products may lead to accelerated wear of the contacts. Rusted metal and peeling paint conditions should be corrected so the structural condition of the tank is not compromised. If repainting is performed, a compatible primer and paint recommended by the transformer manufacturer should be used. Care should be taken to not use coatings that may cause heat retention in the LTC. Dirt or various types of debris building up on the LTC may result in heat buildup that will lead to other problems previously mentioned, such as oxidation. Dirt and debris can also lead to rust and paint problems with the case. Dirt or debris can block the breathing device, and a dangerous amount of combustible gasses may be allowed to build up in the LTC. This buildup may result in an internal fault that may lead to a major fault of the transformer. Periodic inspections of the free breathing device are a necessity. If the free breathing device is equipped with a desiccant filter, check the filter regularly, and change as necessary to prevent moisture from entering the LTC. Additional equipment associated with the LTC, such as the control cabinet, voltage control, liquid filtration system and control-blocking relays, should also be included in the maintenance plan. Control cabinets should be properly sealed as moisture and other contaminants can lead to damage of the control circuits. Periodic inspection and calibration of the relays to ensure reliability are also recommended. Functional checks of alarms, such as off tap, loss of potential, loss of control voltage, and liquid level, are also recommended. Functional checks should also be performed on the motor control circuits and position indicators. If the LTC is equipped with vacuum interrupter protection systems and rapid pressure rise relay (RPRR) systems, functional checks of these systems should be performed. LTC filtration systems should be checked including the filter, inlet and outlet piping. Periodic testing of the LTC fluid can help in the decision-making process of when to maintain and recondition the LTC. Some of the same tests performed on the main tank transformer liquid may also be performed on the LTC. These tests include DGA to help detect overheated contacts and components, the Karl Fischer test to detect moisture ingress, and liquid screen tests to help maintain acceptable dielectric strength and monitor oxidation. Additional testing may also include liquid power factor (an increase may indicate the presence of moisture, oxidation by-products, or other contamination), metals testing to indicate unusual wear, and inhibitor content. Advanced testing methods to consider are particle counting and analytical ferrography. With more than 100 different models of LTCs in use today, it is impossible to establish typical general acceptable criteria. IEEE Std C57.139 gives a classification scheme as well as a statistical method to make model-specific recommendations. 6.2.2.2 LTC maintenance and upgrade LTCs should be carefully inspected to assess the condition of the mechanical and electrical assemblies and parts for extended service. LTC inspection should only be carried out by trained personnel. Looseness (slack) in operating linkages due to wear can cause contact misalignment and potential failure. Contact alignment 59 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers should be checked and corrected as needed. Bolts, nuts, wire terminals, and cam tightness should be checked. If additional problems are found, the tap changer should be refurbished (repaired) or replaced, depending upon the nature of the problem. 6.2.2.3 LTC temperature monitoring When reconditioning transformers with a LTC, consideration should be given to monitoring the temperature difference between transformer top liquid and LTC tank temperatures. Temperature monitoring is typically successful for an LTC with low liquid volume in reactance type LTC. The LTC tank temperature is equal or lower than the top liquid temperature, depending on the design of the LTC (separate compartment type versus in-tank type). A constantly higher LTC liquid temperature may indicate unusual LTC operation. A resistor type LTC temperature can be temporarily higher than the transformer top liquid temperature due to resistor heating. However, in the course of use, LTC contacts can erode or develop coking or a polymeric film. Also, connections and/or contacts can loosen, or abnormal arcing may develop over time. Any of these problems will generate heat that in turn causes the temperature within the LTC tank to be higher than the top liquid temperature. The temperature difference can then be used to trigger a more thorough investigation, including thermal imaging and liquid sampling to determine whether and when an outage should be scheduled. Some electronic indicators provide for an additional temperature probe for monitoring the LTC tank temperature and provide an alarm indication when the differential temperature exceeds a preset threshold value. Preset thresholds will vary from installation to installation as temperature probe placement, LTC liquid volume, LTC model and transformer loading will influence this setting. When adding LTC differential temperature monitoring, consideration should be given to measuring LTC tank surface temperature or measuring the internal LTC tank liquid temperature by installing a thermometer well into the LTC tank wall. Normally, the internal LTC tank liquid temperature will be more accurate than measuring temperature using a surface temperature probe. Consideration of temperature probe placement is also important. If surface-mount temperature probes are used, it may be necessary to shield the temperature probes from solar radiation. However, whether a surface-mount or internal LTC tank liquid temperature probe is used, it should be installed near the top of the LTC tank liquid level. 6.3 Bushing and arrester 6.3.1 Bushing—external inspection Bushings are a critical part of all transformers and their suitability for service is an important aspect of a transformer’s evaluation. The methods for assessing a liquid-filled bushing’s condition are well understood, with the most common methods being power factor (dielectric loss) and capacitance measurements made while the transformer is off line, and infrared inspections while energized. On-line power factor and capacitance techniques are relatively new and are gradually gaining acceptance. The most common technique for assessing a liquid-filled, bushing’s condition is power factor and capacitance measurement. Measurements of the main insulation (C1) are made by applying a test voltage to the center conductor and measuring to the test or potential tap, using an ungrounded specimen test technique. The tap insulation (C2) is measured by the grounded specimen test method with the high-voltage terminal of the bushing connected to the guard circuit. The test/voltage tap is measured to the ground flange using a guard test connection. Test results are then compared to nameplate values or previous tests. Increases or decreases from reference values are usually an indication of contamination and/or deterioration of the insulation system. Limits for the maximum permissible change tend to be manufacturer and type specific; however, a doubling of the initial power factor value warrants either more frequent monitoring or replacement. A 10% change in capacitance also warrants replacement. It is important to note that changes in C2 test values for bushings with test taps may 60 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers indicate a change in the bushings environment not necessarily the condition of the bushings itself. The following checklist should be followed if suspect test values are received: a) Make sure the test set-up is correct b) Make sure the test set works properly c) Make sure all groundings are properly done d) All bushing flanges must be directly grounded through the “Guard” or ground lead e) Make sure there are no sharp wire strands sticking up in the energized test circuit that could cause corona f) Clean and dry the bushing external insulator surface g) Clean and dry the bushing voltage/test tap area h) All voltage/test tap covers should be closed except for the bushing under test i) Make sure the transformer liquid is clean j) Do not test a bushing in the crate The condition of bushings, which do not have test taps, can be assessed using a hot collar measurement. The hot collar method involves energizing a conducting band that is wrapped around the bushing usually below the top skirt of the bushing weather shed. This step measures the capacitance and dielectric loss of the insulation between the collar and the grounded center conductor. The test is used to detect moisture ingress between the conductor and weather shed. It is also effective for detection of liquid contamination and deterioration on liquid-filled horizontally mounted bushings. The evaluation is based on a comparison of tests on similar bushings on the transformer. On-line infrared inspections are effective for locating either loose or high resistance connections in the bushing’s top terminal. The evaluation is based on a comparison of the three transformer bushings. Terminal temperature differentials in excess of 5 °C should be investigated. Comparison of the three transformer bushings liquid levels should be made by observation of the sight glass or level gauge. Abnormally high or low bushing liquid level should also be investigated and may justify further testing to find cause or resulting damage. The detection of liquid bubbling or internal corona should also be addressed according to the manufacturer’s recommendations. 6.3.2 Bushing—internal inspection The primary function of a bushing is to provide insulation for the energized conductor that passes through the grounded transformer tank wall or cover. The bushing also provides support to the lead that is connected at the bottom end on the liquid side or to the lead that passes through the bushing in the draw-lead applications. Inspect each bushing for loose connections, burning, or indication of overheating. If a bushing has a drawlead, inspect the exposed portions of the lead for burning or indications of overheating. The draw lead insulation damage at the bushing can generate electrical discharge activity that causes burn marks or hot spots on the tape. The liquid side of the bushing should be inspected for cracks, chips, mechanical damage surface imperfections, or signs of tracking. Inspect the top of the core and coil assembly for pieces may have come from the bushing including strands/shavings of copper conductor. Check the draw lead insulation where it exits the bushing internal tube. Circulating currents can develop if insulation gets damaged during draw lead insulation. Check for burn marks or hot spots on tape. Some insight into the physical condition of a bushing below the flange may be indicated by the most recent voltage tap (or test tap) power factor test, commonly referred to as the “C2 [bushing] power factor.” An in- 61 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers crease in C2 power factor to a value above the factory nameplate value or a notable change since the last field test may indicate surface contamination of the porcelain below flange and should be investigated during the internal inspection. If stains or films are present on the surface of the bushing, further investigation is recommended. Bushing with test taps may or may not have C2 values on the factory nameplate. The C2 test results for these types of bushings can be greatly affected by external factors such as the transformer tank. Comparison of the C2 test results should be made while the bushing is in the same environment for both tests. If there are springs present to maintain pressure on gasket surfaces of a bushing, check that each spring is in place and maintaining positive pressure by visual inspection, and if applicable, check manually for movement of a spring that would indicate that the spring is no longer compressed. If there is a corona shield present, inspect the shield for signs of arcing or pitting. Some vintage bushings may contain polychlorinated biphenyls (PCB) as a main ingredient. This factor should be considered as the PCBs may leak from the bushing while in service, particularly if heated during an event associated with the transformer. 6.3.3 Bushing replacement Each bushing should be inspected and tested to determine whether a specific problem justifies its individual replacement. Final determination of any electrical test results should be made with the bushing removed from the transformer to eliminate any influence of the transformer in the bushing test values. If any of the bushings are of a design that is known to be of unusually high risk, consideration should be given to replace them all, while the transformer is out of service, in order to avoid an unplanned forced outage in the future. As an alternative, bushings can be refurbished if permitted by the conditions and economics. 6.3.4 Bushing current transformer The primary function of bushing current transformers is to provide a current input to protection devices. The function of bushing current transformers may be tested externally by examining the current transformer saturation, turns ratio, and accuracy and by performing high voltage testing of the insulation. The physical condition of bushing current transformers is confirmed by an internal inspection of the transformer. If accessible, check current transformer polarity markers against the nameplate drawing. Bushing current transformers should be centered on the bushing and bushing leads with no signs of shifting or deformation. They should not touch the bushing or bushing leads. The mounting hardware should hold the bushing current transformers firmly in place and be in good condition with no loose parts or connections. The bushing current transformer leads should also be held firmly in place and routed along the tank wall. The insulation should be examined for signs of burning, overheating, or abrasions. Current transformer circuit terminal contacts in the control cabinet should be examined for any looseness or burning. 6.3.5 Surge arrester The normal operating and maintenance procedures of surge arresters by most utilities involve either field or shop testing. The cost evaluation of field or shop testing should take into account that the arrester testing is carried out either as scheduled maintenance or as an emergency repair. In general, shop testing is more accurate and effective in diagnosing faulty arresters, but it is more expensive because arresters have to be removed and shipped to the shop. In contrast, field testing can be fast and inexpensive, except for the initial capital cost of the test equipment, while being less effective because of the limitations of mobile equipment. If arresters are not already installed for transformer protection, they should be added. If the transformer installation has the gap-type arresters, improved surge protection can be achieved by replacing the gap-type arrester with properly rated metal oxide varistor arresters. IEEE Std C62.82.1 and IEEE Std C62.22 provide recommendations for the selection and application of surge arresters. 62 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 6.3.5.1 Gap-type surge arrester testing A gap-type silicon-carbide surge arrester is a protective device for limiting surge voltages on equipment by discharging or bypassing surge current; it prevents continued flow of follow current to ground and is capable of repeating these functions as specified. Field studies indicate that moisture ingress is the cause of about 90% of all arrester failures. In general, acceptable limits of allowable leakage current in gap-type arresters have been developed on the basis of past experience with arrester units of the same type and rating. Test procedures and evaluation are described in IEEE Std C62.1 and include the following: a) Impulse spark-over tests on gap-type arresters (shop testing) b) Power-frequency spark-over test (shop testing) c) Leakage current measurement (shop testing or field testing) 6.3.5.2 Metal oxide surge arrester testing A metal oxide surge arrester is a protective device for limiting surge voltages on equipment by diverting surge current and returning the device to its original status. It is capable of repeating these functions as specified. In normal service, the zinc oxide surge arrester may be exposed to different stresses that alone or together may cause increased resistive current. These stresses are normal operating voltage, temporary overvoltage, switching overvoltage, lightning overvoltage, and external pollution. The increase in resistive leakage current (aging) may bring the arrester to thermal instability and complete arrester breakdown. Different systems are used to monitor surge arrester operation or possible deterioration. The following tests are described in detail in IEEE Std C62.11: a) Measuring of the V-I characteristics (shop testing or field testing) b) Power loss measurement (shop testing or field testing) c) Third-order harmonic leakage current (shop testing or field testing) d) Measurement of the temperature of the surge arrester (field testing) e) Thermal imaging monitoring (field testing) 6.4 Tanks, gaskets, etc. 6.4.1 Tank condition The tank contains the transformer active element (core and coil assembly) and its insulating fluid. The LTC compartment should be included in the assessment of tank condition. The integrity of the tank is dictated primarily by its mechanical characteristics. The tank must hold pressure and should not leak. The integrity of the tank depends primarily on the condition of gasket containing surfaces, hand hole, manhole, and tap changer door gaskets and on the integrity of tank welds. Deficiencies are detected by observing liquid leakage. Liquid leakage may be due to deteriorated gaskets, warped gasket surfaces, and faulty welds. A leak in a weld may be difficult to locate, as a breach in a weld may involve weld damage at different locations within and outside the tank. Extension of tank life may involve replacement of gaskets, possibly with higher temperature rated gasket material, if deterioration due to high ambient temperature is suspected, and replacement of covers that may have become warped or uneven after years of removal and reinstallation. The inability to adequately seal a tank may render a tank environmentally unacceptable for its current installation. External sealant repair systems, involving specialty sealants and unique hardware containing gasket provisions, may also prove effective in stopping leaks. 63 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers The tank should also be inspected for indications of deformation. Tank deformation may result from extreme pressure or electrical arc experienced during a fault, improper foundation support, and, for spare transformers, frequent installation and removal. Welding performed on a liquid filled tank has no risk of paint carbonization, whilst welding repairs completed on a drained tank or in the region of the gas space above the transformer fluid will risk carbonization of the paint. Although the wall thickness of the tank being welded will dictate the technique and type of welding process, several procedures can be used to control the heat during the weld process. Ideally, keeping the temperature of the plate adjacent to the weld below 100 °C should avoid carbonizing and bubble formation on the inside surface of the tank; in order to achieve this objective the following procedures should be adopted, such as using small weld electrodes, making a series of short welds on alternate sides of the weld perimeter rather than making a continuous weld, improving the cooling process by using water soaked rags to cool the exterior plate surface and allow plate to cool by delaying the next weld segment. Retrofit of safety measures, such as fall protection, may be necessary in a complete tank assessment. 6.4.2 Pressure-regulated gas-blanketed system Gas-blanketed transformers are used as a method to stop oxygen and moisture from entering the transformer. These systems offer some advantages and disadvantages as shown in Table 7. Table 7—Advantages and disadvantages of gas blanketed systems Advantages Disadvantages Positive nitrogen pressure (along with a good gasket) keeps oxygen and moisture out. If the nitrogen bottle is empty, moisture and oxygen may enter the transformer. Purging of nitrogen during thermal cycles removes moisture and oxygen. High levels of nitrogen in the liquid could lead to nitrogen bubble entrapment in the insulation or pumps under certain conditions of cool down. Lower values for moisture and oxygen in the transformer decreases the rate of insulation deterioration. Purging of nitrogen will remove other gas from the transformer making DGA of limited value for long term trending, particularly for gas that are released from the liquid easily, such as hydrogen. Maintenance resource requirements will be higher. 6.4.2.1 Typical system components Gas-blanketed systems have typical main components installed on a transformer and usually include most of the following items: a) Nitrogen cylinder with connections defined by the Compressed Gas Association. Typical cylinders have a capacity of 5.663 m3 (200 ft3) and are full at a pressure of 15 168 kPa (2200 psi) at 210 °C. Nitrogen should be dry and clean and may be specified as Type I in accordance with ASTM D1933. WARNING Nitrogen gas displaces oxygen. Any space that has been purged by nitrogen shall be degassed, and breathable air used to fill the space prior to any entry into the space. Follow all necessary safety precautions to help prevent death or injury. b) High-pressure regulator. Most are two-stage regulators. The first stage reduces the pressure to approximately 690 kPa (100 psi). The second stage reduces the pressure to the level acceptable by the low-pressure regulator. A typical value for output of the second stage is 34 kPa (5.0 psi). The “T” han- 64 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers dle on the regulator should be adjusted so that the output pressure from the second stage is as specified by the transformer manufacturer or as indicated on the nameplate of the system. c) Low-pressure regulator. This device, which feeds the nitrogen into the transformer space is set by the transformer manufacturer and should not be changed in the field. d) High-pressure gauge. This gauge, typically 0 to 20 685 kPa (0 to 3000 psi) indicates the pressure in the nitrogen cylinder. e) Sump. This device is used to collect any moisture or liquid condensate. The sump has a drain cock. f) Pressure gauge. This gauge indicates the pressure in the gas space of the transformer. g) Pressure relief device. This device releases nitrogen when the pressure in the transformer exceeds the set point. h) High-pressure alarm switch. This switch operates when the set point is exceeded and resets when the pressure drops below the set point. i) Low-pressure alarm switch. This switch operates when the pressure falls below a set point that indicates the nitrogen blanket is being lost and corrective action is required. 6.4.2.2 Maintenance The following maintenance of a gas-blanketed system should be done on an annual basis: — Drain the sump — Verify the low-pressure alarm activation — Verify the pressure relief device operation — Verify the pressure gauge is operating properly — Conduct a leak check of the system Follow the manufacturer’s instructions to verify other accessories that may be included with the system. 6.4.3 Conservator systems The transformer liquid conservator system typically consists of one or more externally mounted reservoirs (or expansion tanks). They are installed at the height required to provide a liquid level in the transformer that is above the cover of the main tank of the transformer, or in many cases, above the highest oil-filled bushing boss. Many conservator systems generally include a bladder inside the tank that provides a liquid-to-air barrier to prevent moisture and dissolved air from entering the transformer liquid. The system also has an air equalization line that allows air to enter the bladder when the transformer temperature is decreasing and air to discharge from the bladder when the temperature is increasing. There is also normally a desiccant container in line with this equalization line to dry the incoming air. Some conservator systems have a separate pressure equalization tank and do not have the internal bladder. These systems do not maintain degassed liquid in a transformer, but allow the liquid to become saturated with air or nitrogen (depending on whether air or nitrogen is used in the gas space of the system). Conservator systems usually have a liquid level gauge attached to the tank with an alarm connection to alert operators when the liquid level is to the minimum or maximum acceptable liquid level in the tank. A Buchholz valve or other non-return valve that closes in the event of a main tank rupture can be installed between the main tank and the conservator also known as an expansion tank. Some of these valves also contain a gas collector that traps gas generated in the main tank and provides an alarm when a certain amount is collected. 65 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Transformers with conservator systems may also have gas detector relay systems that are mounted separately on the tank. The condition of the bladder conservator system is dependent on the integrity of the bladder and the other components. A deteriorated bladder can allow moisture or oxygen to enter the transformer. Generally, a bladder should be considered for replacement about every 10 years. The integrity of a bladder may be checked in service by inserting a swab stick with a cotton cloth on the end through the bladder access port in the top of the conservator tank and gently swabbing the inside of the bladder. If the cotton swab becomes saturated with liquid, there is a leak in the bladder, and the bladder must be replaced. The liquid level in the conservator system should be checked regularly to make sure that it is at the proper level and to verify there is no undetected liquid leak in the transformer. There is normally a 25 °C elevation mark on the liquid level gauge to use in adjusting the proper liquid level. If the liquid level gauge gives erratic readings, the float inside the conservator tank should be checked for proper operation or damage. Generally, conservator tanks are not designed to withstand full vacuum. Whenever vacuum is applied to the main tank, the valve between the main tank and the conservator tank must be closed. The desiccant for the bladder conservator system should be checked regularly and replaced when it reaches the end of its moisture removal capability. Operating such a system with a nonfunctioning desiccant, (especially in a humid environment) can allow moisture to enter the tank, or cause the bladder to age prematurely. 6.4.4 Sealed tank transformers A sealed tank system simply utilizes a transformer’s sealed tank to keep the liquid isolated from external atmospheric conditions. The use of a sealed tank system requires that the tank be large enough to accommodate the minimum volume of liquid required by the transformer when the liquid is cold, and the maximum volume of liquid generated when the transformer is operated at its maximum load rating under its maximum designed ambient temperature. The tank must, therefore, be able to accommodate the liquid’s full volumetric excursions from a de-energized “dead cold” condition to a fully loaded “maximum heat” condition. This type of preservation system is typically used for transformers whose minimum and maximum liquid level requirements can be accurately predicted. Many sealed tank transformers are filled with dry nitrogen and have pressure gauges and fill valves to manually add nitrogen if the pressure drops. One of the advantages of sealed tank systems is that they are less expensive than the pressure-regulated gas-blanketed system. One of the disadvantages is that a leak can allow oxygen and moisture to enter the tank. Some sealed tank transformers can suffer a slight loss of gas pressure at peak loads, which will result in negative pressures (or vacuum) during periods of light loading. Consideration should be given to convert these transformers to a pressure-regulated gas-blanketed system. 6.4.5 Free-breathing transformers Operating around the world are numerous transformers of all sizes that have free-breathing liquid insulation systems. Most of these have a provision for maintaining the dryness of the liquid. Such provisions include a desiccant breather or a refrigerating breather. However, some free-breathing transformer designs do not include provisions for maintaining the liquid in a dry condition, and the predictable result is an increase of moisture in the liquid. In such cases, consideration should be given to make some provisions to ensure the dryness of the liquid. After liquid replacement, reconditioning, reprocessing, etc, the preferred modification is to include a bladder in the expansion tank (if so equipped). If cost of conversion to a bladder sealed design is not justified, an alternative improvement would be to vent the expansion tank through a desiccant (drying) system. The reason that bladder addition is preferred is that its design includes sealing the liquid from oxygen entry as well as moisture entry. 66 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 6.4.6 Gaskets Gasket material must be compatible with the transformer insulating fluids. Otherwise, failure of the gasket occurs and leaks develop. The nitrile or fluorocarbon are preferred materials for gasket applications. Gaskets must be applied and maintained in proper condition to help ensure the reliability of the insulation system, safety of personnel, and health of the environment. Gaskets in good condition will be smooth, firm, and pliable. Gasket surfaces should be checked for damage, such as nicks, indentations, and deformation. Improper manufacturing, handling, or sizing may have caused these defects. Gasket surfaces should be lubricated prior to gasket installation with materials compatible with the gasket material and with the transformer insulating fluids. The gasket material should be checked for chemical and thermal degradation. These types of degradation result in softening or hardening of the material, and it may show cracks. These defects may be caused by improper material selection or manufacturing. Gaskets that are confined in grooves should confirm to proper design criteria for gasket compression and groove volume fill. 6.5 Gauges, indicators, and relays 6.5.1 Liquid and winding temperature gauges Liquid temperature indicator (LTI) and winding temperature indicator (WTI) devices typically control the cooling operation, indicate the actual operating temperature conditions of the transformer, and provide alarms or trip functions should preset temperature parameters be exceeded. The lenses of the devices should be clear and free of scratches. Maximum indicating mechanisms should operate freely and allow the indicating hands to reset and not vibrate or move on their own. Dials should be legible and free of paint flaking or chips. Labels should be visible. Look for any signs of moisture or condensation under the lens and replace if present. The devices should be functionally tested using a calibrated temperature bath with an accuracy of no worse than 2 °C at the actual sensing probe of the gauge. The readings at any point on the gauge should be no worse than ± 2% of full scale. Also, note any hesitation in the pointer mechanism during an increase to high temperature and decrease to low temperature as a sign of corrosion or binding of the internal drive mechanism. Hesitation of more than 2% of full scale is considered cause to replace the gauge. The operation of the switch should be a clear change of state from normally open to normally close. Non-contact commonly referred to as dead spots, or simultaneously normally open and normally closed contacts cannot be allowed in the system. Also verify that the connector cable from the device to the control or annunciator panel shows no signs of significant aging. Replace the cable if it shows signs of aging or cracking. As a general rule, the cable should be replaced if the gauge is replaced. Electronic indicators should be considered as a replacement for the older mechanical top-liquid and simulated winding temperature gauges. Although this type of replacement may not contribute directly to the life extension of a transformer, it should increase reliability and/or versatility of temperature monitoring. Typically, transformers with forced-air or forced-oil cooling are operated in fail-safe mode (in other words, the cooling system will automatically be activated, e.g., fans will be energized, if the electronic temperature indicator becomes de-energized or fails). The user should design their protective relaying system to switch 67 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers off the fans and/or pumps if the transformer should trip off line. If the transformer has tripped, cooling is not needed. If a catastrophic failure has occurred, fail-safe energization of the fans and/or pumps could exacerbate the situation. Instrument selection should include winding temperature input directly from a current-transformer (rather than by use of a heater) in order to avoid the concern for the heater circuit and components. If the winding temperature device will continue to utilize a well heater, the functionality and/or accuracy of the heater and heater circuit should be confirmed to avoid erroneous winding temperature indication and inappropriate cooler initiation. Some electronic indicators offer the ability to measure both the liquid and winding temperatures simultaneously and provide control and alarm functions for any combination of measured sources. This option provides an opportunity for replacing two gauges with one instrument or for using one of the mechanical gauges as a redundant alarm source while operating experience is gained with the new equipment. If the latter case is chosen, the liquid temperature gauge should be retained, and the electronic indicator should be configured for cooling control and alarm functions based on hottest spot temperature. Consideration should be given to the functionality of the indicator with respect to the overall mission of the other equipment in the substation to which the transformer will be applied. Some example questions that need answers are the following: a) Will the indicator be required to transmit measured quantities to control centers? b) If communication is required, will digital or analog methods be used? c) What is the protocol used by the indicator to transmit data in a digital format, and is it compatible with the application’s equipment? d) Will the indicator interface with a translation device or directly to a remote terminal unit? e) Will the indicator collect data from other devices on the transformer? f) Is additional cabling required to service the transmission of additional information in analog form? g) Should the indicator be powered from ac station mains or from dc station battery? Mechanical gauges are immune to electromagnetic interference, electrostatic discharge, and transients that are common in substation environments. Some examples are switching transients, lightning strike, faults, and usage of wireless communications devices nearby. Electronic instruments, however, contain semiconductor components and other circuit elements, which are generally susceptible to these kinds of influences. Designs typically incorporate clamping, shielding, and filtering devices that protect the semiconductors from damage and prevent mis-operation of the instrument’s functions to defined levels of energy. Consideration should be given to the level of susceptibility that the instrument manufacturer specifies for the instrument and to the way that factor relates to the actual application. Where electronic indicators are currently being used on the transformer, the instruments should be returned to the manufacturer for refurbishment and recalibration prior to the re-commission of a transformer. Typically, the manufacturer will replace mechanical control relays, switches that show signs of wear, faded or worn labels and markings, and viewing windows. All functions should be tested, and recalibration should be performed. 6.5.2 Liquid level indicator The liquid level gauge lens should be clear and free of scratches. The dial should be legible and free of paint flaking and chips. There should be no signs of moisture condensation on the lens. All labels should be clearly legible and visible. 68 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers The pointer should travel freely when checked with a magnetic drive source. If any sticking is detected, replace the gauge. The switch should operate at the appropriate set point as shown on the dial or drawing when the pointer is moved by the magnetic drive. The operation of the switch should be a clear change of state from normally open to normally close. There should be no non-contacts, commonly referred to as dead spots, or simultaneously normally open and normally closed contacts. The float mechanism should be examined to ensure proper staking and/or assembly and no wear in the drive mechanism. Any floats exhibiting binding should be replaced. Note that this last activity is actually an internal assessment because it is necessary to lower the liquid level in the transformer in order to access the float mechanism. Defective gauges should be repaired or replaced. Liquid level indicators in the main tank of a conservator transformer have a demonstrated propensity to seize up due to lack of movement. Because the main tank on such a transformer normally remains full of liquid, the level indicators remain stationary for months or years. Whenever the liquid is lowered for maintenance activities, these gages should be carefully examined for proper functionality and replaced if needed. 6.5.3 Rapid pressure rise relay (RPRR) The RPRR typically is used to trip the transformer off line to protect the transformer from damage caused by an internal fault. This relay is also known as fault gas relay, fault pressure relay, and sudden pressure relay. The operating characteristics and sensitivity of the device is such that it should not operate in the event that the pressure rise generated during a through fault or other such phenomenon is below the calibrated threshold. There are two basic types of RPRRs, gas space relay and liquid space relay. The gas space relay is set to respond slightly faster than the liquid space relay to compensate for the compressibility of the gas versus the non-compressible liquid to which the liquid space unit is exposed. There are no general rules regarding which type of relay functions better under various conditions. In recent years, it is becoming more common to place dual relays on the tank in perpendicular planes with the relay switches wired in a series configuration. This arrangement reduces the occurrence of a nuisance trip due to surges below the calibrated limits of the unit should one of the relays be more sensitive or experience fault conditions to which the other relay was not subjected. The manufacturers of these types of instruments publish testing methods to ensure that the units function within calibrated parameters. It is important that these units be tested on a periodic basis to ensure conformance to the manufacturer’s standards. Several factors affect the performance and long-term life of the units including, but not limited to, excessive vibration, moisture, and corrosive environments. Due to the design of the relay, it is not easy to detect signs of wear other than to conduct the performance tests recommended by the manufacturers. The operation of the switch should be a clear change of state from normally open to normally close. There should be no non-contacts, commonly referred to as dead spots, or simultaneously normally open and normally closed contacts. Some users have found that the conflicting issues of false (nuisance) trips and reliable protection are somewhat balanced by the use of three different RPRRs, mounted apart from each other on the transformer tank. When an internal fault occurs, the nearest relay should pick up first. By using a two-out-of-three relaying scheme, a trip signal will be only sent when the second relay picks up. Any one of the three relays can fail to sense the fault without failing the protection scheme. As a general rule, any relay that does not perform to the published test parameters should be replaced. As this device is used for tripping a transformer, any nonconformance to standards could result in nuisance trips or failure to operate in the event of actual fault. It is also recommended to consult the manufacturer to determine if the relay in question has undergone any design changes that would enhance performance or reliability to ensure that only the most recent technology products are placed back in service. In addition to a performance check, it is also important to perform a visual inspection of the relay. Look for signs of corrosion in and around the connector location and around the top cover. Check that the flange-mount- 69 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers ed units have smooth and even flanges and clean gasket sealing surfaces. The thread-mounting devices should have smooth threads, and old sealant materials should be cleaned before reinstalling. The condition of the isolation valve should be checked to determine that it is functioning properly, in case the relay would need to be removed from service. Verify that the connector cable from the RPRR to the seal-in function or control panel shows no signs of significant aging. Replace the cable if it shows signs of aging or cracking. As a general rule, the cable should be replaced if the relay is replaced. It is also important to verify that the associated seal-in relay function, typically installed in series with the RPRR function, is operating correctly and of the latest design. It is best to consult with the manufacturer of these relays to ensure they are functioning to the latest standards. If the transformer does not include RPRR protection, consideration should be made to add such protection. For expansion tank designs, a RPRR can be installed in the side or on the top of the main tank by modifying a manhole and/or hand hole. For sealed tank designs, a RPRR can be installed in a manhole and/or hand hole on the side of the tank. An existing fill or drain valve can be used for installing the RPRR, but the location and orientation of such valves are usually not optimum for responsiveness of the relay to faults. For expansion tank designs, a Buchholz relay can be installed in the piping between the main tank and the expansion tank. Electronic fault pressure monitoring devices are now also available with sensor mounting to small pipe fittings versus the large flange or thread mount designs. These sensors adapt well to fill plugs or other such fittings with minimal impact on operation or performance. These devices may also contain adjustability features to vary the response time based on the actual operating environment of the transformer. 6.5.4 Gas detector relay The tubing from the source to the gas detector relay should be checked for crimping and plugs. Replace the tubing if any damage is detected. The relay gauge lens should be clear and free of scratches. The dial should be legible and free of paint flaking and chips. There should be no signs of moisture condensation on the lens. All labels should be clearly legible and visible. If provisions on a transformer conservator tank do not include detection of free gas, such provisions may be added. Options include the installation of a gas detector relay on the top of the main tank and tapping into the highest point of the tank top. As an alternative, a Buchholz relay can be installed in the piping between the main tank and the expansion tank for gas detection. 6.5.5 Pressure relief devices The pressure relief device is designed to relieve internal pressure in order to protect the transformer tank when internal pressure exceeds the calibrated limit of the pressure relief device. The actual operating pressure for the device is determined by the transformer manufacturer and should not be changed without consultation with the transformer manufacturer. The device operates as follows: the sealing valve opens when the internal tank pressure is sufficient to overcome the force of the hold-down springs. CAUTION The hold-down springs contain a tremendous amount of stored energy when assembled and should never be disassembled without taking the proper safety precautions. The relief device sealing valve gaskets are typically coated with a special lubricant to reduce sticking and long-term vulcanization to the sealing valve due to pressure, vibration, and temperature. This lubricant may break down after long-term exposure to transformer liquid and should be checked. The lubricant can also be 70 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers wiped clean during multiple operations; therefore, any device that has seen more than a few operations in the field should be carefully inspected to ensure the gasket does not stick due to the lack of lubricant. Visual inspection of the cover for signs of corrosion, primarily at the sharp bend radii, is important. If any sign of cracking or pitting is noted, the device should be replaced. Also, verify that the springs have not corroded beyond light surface rust. Note the condition of the attached operation indicating alarm switch, if so equipped. Any signs of corrosion or contamination, especially around the connector area, require the switch to be replaced. Most switches are designed with a manual test lever to allow users to verify proper operation. If the switch does not function and reset properly, it should be replaced. The operation of the switch should be a clear change of state from normally open to normally closed. There should be no non-contacts, commonly referred to as dead spots, or simultaneously normally open and normally closed contacts. Also verify that the connector cable from the alarm switch to the control or annunciator panel shows no signs of significant aging. Replace the cable if it shows signs of aging, such as cracking. As a general rule, the cable should be replaced if the alarm switch is replaced. Consideration should be given to installing pressure relief devices with a greater flow rate than on the original factory installation. These devices provide greater transformer tank protection under fault conditions than traditional devices. Consult individual device manufacturers for latest pressure protection recommendations. Consideration should also be given to installing discharge directional control devices that direct the flow should the pressure relief device operate. Any transformer installation that could have personnel working near the tank places these workers in peril should the relief device operate. Discharge directional control devices will direct the flow during operation of the relief device away from control panels and cooling equipment, which could spray discharge further. 6.6 Controls, alarms, and annunciators 6.6.1 Cooling equipment controls Cooling equipment controls are devices that are interposed electrically or mechanically between the control device (e.g., LTI, WTI), the cooling impetus (e.g., fans, pumps), and media containment (e.g., radiators, tanks). Typical controls include bypass, bank selector, and mode switches; interposing contactors; and shut-off valves. 6.6.2 Bypass, bank selector, and mode switches Bypass switches turn cooling apparatus on and off independent of the LTI or WTI. Bank selector switches select the order in which cooling stages are operated so that operating times may be equalized. Mode switches have manual and automatic positions that determine the source of control. These switches may be rotary or toggle switches. They may or may not have a locking feature. Should bank selector switches be found in need of repair or replacement, consideration should be given to implementing this functionality with an Electronic Temperature Monitor (ETM) for LTI and WTI. This functionality will not require future operator intervention and provide even wear on fan and pump motor bearings. Switches should operate freely without binding or sticking. Making and breaking of the circuit(s) under control should be instantaneous, discounting the action of any delay devices that may modify the action of the switch. Locking mechanisms should have the unlocking means available and functional. There should be no signs of corrosion, overheating, or discoloration on the switch case, actuators, connections, or associated wiring. 71 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 6.6.3 Control contactors Interposing contactors should be examined for evidence of deterioration, which could shorten their extended life. On open-frame types, pivot points should be examined for excessive wear, and contacts should exhibit no excessive pitting. Coils should show no signs of overheating or insulation deterioration. If doubt of continued reliable operation exists, the contactor should be replaced. The switching capacity of the contactor should be reviewed if there is the possibility of the addition of higher capacity cooling equipment in the future. 6.6.4 Time delay controls Mechanical delay devices should be operated over the full range of delay settings to ensure adjustability and delay period accuracy. At the expiration of the set delay period, interruption or making of the circuit should be instantaneous. Contact resistance should be checked when visual inspection of contact condition is not possible. Should the existing time delay controls need repair or replacement, consideration should be given to replacing the timer functionality contained in an electronic temperature monitor used for LTI and WTI. 6.6.5 Over-temperature station trip controls The over-temperature station trip control is normally actuated by the WTI through an interposing contactor, which operates load-shedding breakers. The actuating circuit is frequently supervised by a second contactor that interrupts the trip in the event of a false alarm due to sensor or WTI failure. This supervisory circuit may or may not be part of the WTI feature set. The contactors in the circuit should be evaluated as indicated in 6.6.3. When testing the station trip circuit the contactor should actuate; the alarm annunciator should light, and the alarm signal should be verified at the load-shedding breaker. In addition, a simulated sensor and WTI failure should be performed to verify that the trip lockout functions properly. 6.6.6 Liquid level alarm The liquid level alarm is an interposing contactor that is responsive to the liquid level sensor, an alarm annunciator, and wiring that connects the alarm to an external retransmission device. The contactor should be evaluated as indicated in 6.6.3. When testing the level sensor, the contactor should actuate; the annunciator should light; and the contact closure should be verified at the remote wiring connection point. 6.6.7 Rapid pressure rise alarm The rapid pressure rise alarm circuit operation is similar to the liquid level alarm, but is responsive to rapid pressure increases inside the tank. The alarm circuit’s function is examined in the same manner as in 6.6.6. 6.6.8 Lighted annunciators Lighted annunciators should provide an illumination level that is clearly visible in direct sunlight. Lenses should be free from cracks and be of the correct color. If the lens is exposed to weather, the sealing gasket or O-ring should be replaced. It is recommended that incandescent lamps be replaced with high-intensity, clustered light-emitting diode types wherever possible. 6.6.9 Mechanical target annunciators Drop-down or pop-up flags, or mechanical target annunciators, should be operated several times to verify operation without sticking or hesitation of any kind. Viewing windows should be free of haze or scratches that 72 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers obscure clear viewing of the flag. For increased reliability, mechanical annunciators should be replaced with illuminated annunciators (of the high-intensity clustered light-emitting diode type) wherever possible. 6.7 Pumps 6.7.1 External inspection Visual inspection of the transformer liquid-cooling loop components should be performed as experience dictates which should not exceed a 12-month frequency. Pumps should be manually energized to ensure proper operation and correct rotational direction. Any significant noises (e.g., grinding, rubbing, scraping) should be noted, investigated further, and corrected. Flow gauges should indicate full flow without fluctuation. The motor current draw should be checked and compared to the pump nameplate full load amperage value. All areas including piping, valves, and surrounding ground area must not show evidence of any liquid leakage. Pump nameplate data should be reviewed to determine age, style, or model. Pumps equipped with a bearing condition monitor should have readings taken annually to ensure bearing integrity. 6.7.2 Internal inspection Original equipment pumps have no reliable means of condition assessment without being physically removed from the cooling loop and disassembled. Disassembly of the pump should only be performed by the pump OEM or skilled maintenance concern. Extensive experience is required to ensure that bearing and rotor clearances and other critical criteria are maintained. An internal inspection should include the following: a) Visually inspect thrust collar and bearing for wear and for any scoring on the shaft. b) Measure endplay and analyze for proper clearance. c) Analyze thrust collar and thrust bearing finishes for finish. d) Measure bearing inside diameter and on-shaft journals and compare, analyze, and check for proper clearance. e) Take readings of insulation resistance and winding resistance to assess electrical motor condition. f) Perform high potential test for grounds or breakdown of insulation. 6.7.3 Remanufacturing or new replacement of pumps Transformer liquid pumps are vital to the reliability and performance of power transformers. Remanufacturing of a pump should not be attempted by anyone other than the original equipment manufacturer or a fully qualified pump remanufacturing facility. Failure to maintain clearances, bearing and thrust collar materials, surface finish requirements, and alignment of pump rotating components can result in premature failure of the pump and potential introduction of metallic components into the transformer. Pumps with ball bearings are particularly vulnerable to in-service failure. Therefore, any pumps with ball bearings older than the equivalent of 5 years of continuous duty should be considered for replacement by pumps with sleeve bearings. All original sleeve bearing pumps that have been in service for an equivalent of 10 years or more of continuous duty should be inspected and checked to determine viability for continued operation and possibly be remanufactured or replaced. For very large and/or critical installations, an internal bearing condition monitor system could be considered to monitor the life of pump bearings. The criteria identified in 6.7.3.1 through 6.7.3.6 should be followed for each of the systems in a remanufactured or new replacement pump. 73 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers 6.7.3.1 Thermal system Ensure positive liquid circulation within the pump motor for motor winding cooling to maintain a maximum motor end temperature rise to 5 °C above the pumped liquid temperature. 6.7.3.2 Mechanical system A bronze sleeve bearing system with a high strength steel shaft, hardened steel thrust collars and a high quality bearing bronze journal/thrust bearings should be used in a remanufactured or replacement pump. The bearings must be designed to assure proper lubrication of the thrust bearing and journal bearing surfaces that use liquid feeder grooves. The shaft/rotor/impeller assembly should be dynamically balanced. Use of pumps built with ball bearings is not recommended for transformer service because of the poor lubricating characteristics of the transformer insulating fluid. 6.7.3.3 Sealing system All gaskets should be a confined gasket groove design and should be constructed of using fluorocarbon or nitrile elastomeric material with a hardness of 60 to 70 durometer. All gasket seals should be replaced. All O-ring seals should be fluorocarbon or nitrile with a hardness of 60 durometer. Compression set specifications should be in accordance with ASTM D395. Gasket sizing should be recommended to fill approximately 80% to 90% of the retaining groove at 25% to 35% compression. Replace all pump gaskets during the remanufacturing process. 6.7.3.4 Fluid system Any remanufactured or new replacement pump should duplicate the original pump’s hydraulic performance criteria, including capacity flow, total dynamic head, rotational speed, and electrical power requirements. 6.7.3.5 Electrical system Pump motors should be rated with Class F or higher insulation. Motor windings should be double-dipped and baked with an epoxy varnish. The electrical connector, power cord and conduit system should be designed to assure that no migration of moisture is possible into the electrical connection point. Power cords or conduit that show any signs of cracking or deterioration from weather or aging should be replaced. 6.7.3.6 Inspection/testing requirements The user should consider performance testing of new or remanufactured pumps. Any performance test should use only transformer liquid as the pumped fluid, and the results should be recorded. The performance test should include flow conditions throughout the performance curve. The following are minimum tests required on transformer liquid pumps: a) Measure motor resistances (ohms) on all phases (A to B, A to C, and B to C). b) Measure insulation resistance of motor (minimum insulation resistance–200 MΩ). c) Perform dc high potential test. d) Measure “no load” motor amps. e) Perform leak test on the pump with liquid during performance test. Document pump performance data for a minimum of three flow conditions ranging from shutoff to end-ofcurve using the actual performance tests for each pump. The following data should be included for each flow condition: 74 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers — Suction pressure — Discharge pressure — Total dynamic head — Flow rate in liters per minute (gallons per min) — Voltage (actual) — Current of each phase under load conditions — Ensure motor/pump rotation is correct 6.7.4 Pumping of natural ester-based insulating fluids Careful consideration should be given when applying a forced liquid cooling system (circulating pumps) to a transformer filled with any natural ester-based insulating fluid. Particularly in cold start-up conditions, the fluid becomes excessively viscous (as compared to typical mineral-based fluids) and may overload the pump motor or trip out electrical controls. 6.8 Radiators, coolers, and fans 6.8.1 Radiators and fans Visual inspection of the transformer liquid-cooling loop components should be performed as experience dictates, which should not exceed a 12-month frequency. Fans should be manually energized to ensure proper operation. Any significant noises (e.g., grinding, rubbing, scraping) should be noted, investigated further, and corrected. Fan blade guards must meet government safety standards. Obvious airflow obstruction through coolers via debris should be noted and cleaned. Periodic infrared imaging of the coolers/radiators should be taken to ensure proper liquid flow and cooler/radiator heat transfer. All areas including piping, valves, and surrounding ground area must not show evidence of liquid leakage. Typical leakage points will include all pipe flange connections, valve stems, pump electrical connections, radiator/cooler headers, etc. Any missing, failed, or defective fans should be repaired or replaced. If the transformer’s future expected service includes normal loading beyond nameplate kilo-volt-amperes, considerations should be given to increasing the number of fans as part of the reconditioning of the transformer. However, any cooling revisions should be developed by someone with specific knowledge of the transformer’s cooling design. 6.8.2 Forced liquid coolers Forced liquid and air coolers can be found on almost all generator step-up transformers and mobile transformers and on some substation transformers. These coolers depend upon both the full airflow from their fans and full liquid flow from their associated pumps in order to provide the amount of cooling required to dissipate the transformer heat losses. Without both the fans and pumps operating, these coolers are essentially nonfunctional. Depending on the environmental conditions where the transformer is in service, after about 20 years in service, the coolers deteriorate to the extent that they approach their end of life. One or more of the conditions described in 6.8.2.1 through 6.8.2.4 may hasten the end of life for these coolers. 6.8.2.1 Thermal degradation of the cooler tube bundle Thermal degradation of the cooler tube bundle occurs when the finned surface is fouled or clogged with debris from airborne particles. This condition might be remedied with the use of high-pressure spray cleaning. Care needs to be taken to avoid deformation of cooling fins by high-pressure spraying because this action may constrict the airflow paths intended by the supplier. Other forms of thermal degradation occur when there is mechanical damage or deformation of the fins or when there is a general deterioration of the fins due to corrosion (which then helps to hold debris inside the tube bundle). The end result is that any of these conditions reduces 75 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers the air flow and heat transfer capability of the coolers and causes the transformer to operate at higher temperatures. Overheating of the transformer windings resulting from fouled coolers causes excessive thermal aging of the insulation, which reduces the overall life of the transformer. 6.8.2.2 Water spraying Some users spray their transformers with water during emergency overload conditions. The transformer design engineers of the original equipment manufacturer may utilize the transformer tank surface and the cooling system (radiators or coolers) to help radiate the heat losses that are generated. Unfortunately, when the sprayed water evaporates, the tank wall and cooler surfaces are coated with layer after layer of mineral deposits, and possibly dirt, depending upon the quality of the water. This condition reduces the overall heat transfer capability of the cooling system. Once the minerals are baked on the surface, they are virtually impossible to remove, and the overall life of the transformer is reduced. 6.8.2.3 Galvanic corrosion Corrosion due to galvanic action of dissimilar metals is a function of the metals used in the construction of the cooler and the ambient conditions in which the coolers are operated. The corrosion usually occurs between dissimilar metals in the lower portion of the cooler at the juncture of the tubes and the tube sheet and is readily seen when liquid leaks are observed. Some field repairs have prolonged the life of forced-oil and forced-air coolers; however, this correction is considered to be short term. Left unattended, the liquid leaks could eventually cause an environmental concern. 6.8.2.4 Thermal expansion Occasionally, liquid leaks may occur where the tubes meet the tube sheet and can be attributed to thermal expansion and contraction that deform the relatively soft tubes and allow liquid to leak from this joint. Cooler designers must take thermal expansion and contraction into account to prevent such leaks. Cooler manufacturer’s installation instructions must be followed to avoid eliminating features that accommodate the thermal stresses. In summary, in order to extend their efficiency, forced-oil and forced-air coolers should be maintained over their life span. However, when indications show that they are at the end of their life, plans should be made to replace them in order to extend the reliability and the life of the power transformer. 7. Degassing and moisture removal NOTE—See IEEE Std C57.93 for a detailed explanation of these methods. 7.1 Off line de-energized processing methods For non-vacuum rated transformers: There are two established methods used on non-vacuum rated transformers: hot air circulation and hot liquid circulation. a) Hot air method consists of removing all of the liquid from the transformer, sealing the tank except for the air in and out connections, and circulating hot air within the transformer tank. As the hot air picks up moisture from the active parts, it becomes saturated and will not absorb any more moisture. At this point the saturated air must be purged with a supply of dry air. This is typically done by bleeding in a constant stream of dry air and allowing the saturated air to escape. This method is very slow and care must be taken not to overheat the active parts as they are exposed to air. An alternative method is to use dry nitrogen in place of the dry air. Higher temperatures can be used because of the absence of air. 76 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers b) Hot liquid method consists of heating the entire volume of liquid in the transformer and passing it through a vacuum degasified/dehydrator to remove the moisture from the liquid and reheating the liquid as it is returned to the transformer. The hot dry liquid will pick up moisture from the surface of the active parts of the transformer and that moisture is removed from the liquid using the vacuum dehydrator/degassifier. This is also a slow process because moisture deep within the active parts must migrate to the surface areas to be removed by the hot liquid. Care must be taken to help ensure that the transformer is vented so that the degassed liquid does not result in a vacuum being exerted on the tank. For vacuum rated transformers: There are three established methods used on a vacuum rated transformer. They are hot liquid circulation followed by draining the liquid and applying vacuum, hot liquid spray and vacuum, hot liquid spray with low frequency heating and vacuum. 1) Hot liquid circulation with liquid drain and high vacuum process consists of heating the entire volume of liquid in the transformer and continuously passing it through a vacuum degasified/dehydrator to remove the moisture from the liquid and reheating the liquid as it is returned to the transformer. The hot dry liquid will pick up moisture from the surface of the active parts of the transformer and that moisture is removed from the liquid using the vacuum dehydrator/degassifier. This recirculation process is continued until the inlet and outlet liquid temperatures are within an acceptable delta T. At this point a circulation countdown timer is started and the circulation process continues. At the end of the timed interval, the liquid is drained from the transformer and vacuum is applied to remove the moisture from the active parts of the transformer. If the transformer is extremely wet, this process may need to be repeated. 2) Hot liquid spray and vacuum process consists of spraying hot degasified and dehydrated liquid over the active parts of the transformer by placing a spray system in the tank, usually by using a manhole or inspection plate cover that has been modified to accept the spray system. The hot liquid is sprayed in the top and drawn out at the liquid drain connection. This typically requires a liquid booster pump at the base of the transformer to assist in pumping the liquid back to the processor. The liquid is degasified, dehydrated, and reheated and returned to the spray system. Vacuum is also applied to the transformer and moisture is removed from the insulation as the hot liquid heats it to a point of vaporization. 3) Hot liquid spray with low frequency heating and vacuum process consists of the addition of a low frequency heating system used in conjunction with the hot liquid spray process. This provides an additional source of heat within the active parts and promotes the vaporization of moisture without having to wait for the hot liquid to reach the interior of the insulation. Important factors: The most important factors in recirculation are temperature, vacuum, and set time (often referred to as absorption). These factors are required to remove moisture from the transformer liquid, remove moisture from the cellulose insulation, and/or to re-impregnate the cellulose insulation. The intent is to heat, filter, and degasify the liquid while circulating the liquid through the transformer tank under vacuum. Completion of the drying process and final liquid filling may occur after using one or more of the following methods to determine dryness: — A designated period of vacuum time — Monitoring of liquid quality, vacuum, and moisture extraction — Measuring the amount of extracted water — Monitoring the internal tank relative humidity/dew point 77 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers An insulation power factor measurement is recommended after the required transformer set time (re-impregnation of the cellulose insulation) in liquid. See Table 8 for recommended set times. The insulation power factor measurement should be the final verification on the integrity of the insulation system. Table 8—Recommended minimum set time (i.e., absorption) after final liquid fill Voltage class (kV) Minimum set time (hours) 69 48 138 48 230 48 345 60 500 72 765 96 NOTE—Extended set times may be required if the core and/or coil assembly was out of the liquid for a prolonged period. 7.1.1 Field instructions The following are generic field instructions for recirculation and transformer set time before energization. In addition to the CAUTION notes provided with the items below, the manufacturer’s instruction literature should be consulted for other electrical, mechanical, or thermal design limitations that may prohibit the use of this or other recirculation field processes. Mechanical and thermal recommendations for the recirculation process are as follows: — General equipment recommendations are as follows (specifications may vary based on the size of the transformer and ambient temperatures). — Degasification trailer capable of circulating 114 LPM (30 GPM) to 151 LPM (40 GPM) at 63 °C (145 °F) to –74 °C (165 °F), 190 to 265 kW heating capacity. Trailer intake filter 0.5 μm, trailer discharge filter 0.5 μm. — Vacuum pump with 4.25 m3/min to 8.5 m3/min (150 CFM to 300 CFM) capacity or greater with attainable blank off pressure of 0.02 Torr or less. An additional option is a booster pump with a capacity of 34 m3/min to 41 m3/min (1200 CFM to 1449 CFM). — Positive displacement rotary tri screw or other low net positive suction head (NPSH) pump sized to match the processor flow rate for liquid discharge from the main transformer tank. — Optional monitoring and test equipment: on-line total dissolved gas monitor, on-line hygrometer or standard dew point equipment, test equipment for monitoring winding resistance, cold trap for cryogenic-vacuum processing, moisture content and dielectric strength liquid test equipment, liquid power factor tester, and insulation power factor tester. — Oil entrance into the transformer tank should be through the top main cover or at the top main tank walls as close to the cover as possible. CAUTION If ambient temperatures are 5 °C or less, the liquid should be heated gradually and directed so that it does not splash on bushing porcelain. Failure to comply with this requirement may result in breakage of bushing porcelains due to thermal shock. — Vacuum connections should be at the top of the transformer tank as far away as possible from the liquid entrance. 78 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers CAUTION Review the transformer instruction literature to be sure that the main transformer tank, auxiliary tanks, terminal boards between walls and all ancillary items can withstand designated full vacuum 103 kPA (15 psi) at elevated temperatures. Epoxy or nonmetallic terminal boards may not be able to withstand full vacuum at elevated temperatures. Ancillary devices such as fault pressure relays or monitoring devices may require removal or “valved out” of system if not able to withstand full vacuum. CAUTION Conservator tanks with rubber bladders may be designated as being capable of withstanding full vacuum. Vacuum applied to the conservator tank may damage or weaken the rubber bladder. CAUTION If external bushing connections are made, be certain there is sufficient slack in the external line connections to allow for bushing movement caused by the flexing of the transformer cover and/or walls. Failure to relieve this stress at the bushing connection may result in bushing seal damage and a loss of liquid. — Oil discharge from the main transformer tank should be from the bottom of the tank. A positive displacement liquid pump should be used at the tank discharge valve within 1.5 m (5 ft) of the tank wall. Vacuum should be maintained at the best possible level with the lowest possible liquid level in the transformer tank to maintain liquid discharge without pump cavitation. A minimum liquid head of approximately 0.9 m (36 in) is required to maintain liquid flow 151 lpm (40 GPM) under full vacuum with a positive displacement pump. Table 9 provides recommended vacuum levels for recirculation and final liquid fill. The vacuum level will initially be affected by the liquid quality and moisture level in the liquid. Ideally, the liquid level in the main tank should be below all major insulation. — Additional recommendations for the liquid circulation and vacuum dry process include the following. — Prior to vacuum and liquid circulation, close all valves to cooling equipment. Close all valves to ancillary items that will not withstand full vacuum. — Oil circulation through the tank should continue until the moisture and gas levels of the liquid are acceptable and the cellulose insulation is heated sufficiently to facilitate moisture extraction under vacuum. — When ambient temperatures are below 0 °C, an liquid level greater than 0.9 m (36 in) may be necessary to act as a heat sink to obtain the desired temperatures. Thermal blankets on the exposed tank walls may also be necessary. — Circulate 85 °C liquid through the tank until the liquid discharge temperature stabilizes at 50 °C or higher. — When liquid discharge temperature stabilizes at 50 °C or greater, drain the liquid to a level below the coil assemblies or drain complete. Apply vacuum as indicated in Table 9 based on one of the following options: — Designated period of vacuum time 79 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers — Monitoring of liquid quality, vacuum, and moisture extraction — Measuring the amount of extracted water — Monitoring the internal tank relative humidity/dew point Final verification of the dielectric strength of the insulation system should be an insulation power factor test. An acceptable insulation power factor value for a new transformer is < 0.5% or as specified by the manufacturer. See 6.1.6.2 and 6.1.6.8 in IEEE Std C57.152 for additional information. Table 9—Recommended vacuum levels for recirculation and final liquid filling (exposed insulation) Voltage class (kV) Vacuum final liquid filling [μm of Hg (mm Hg)] 69 2000 (2) 138 2000 (2) 230 2000 (2) 345 1000 (1) 500 1000 (1) 765 1000 (1) 7.2 On-line energized liquid dry-out method On-line transformer moisture removal systems have become increasingly popular to extend the operating period of a transformer that has had an increase in moisture levels or may be gassing and needs to remain in service until a scheduled outage can occur. There are several systems readily available and use either an absorptive system or vacuum dehydration. Absorptive systems use a media that will remove the moisture from the liquid as it passes through the media. These absorptive systems must either regenerate the absorptive material or have the absorptive elements replaced when they become saturated. The affinity liquid has for moisture increases with temperature so the material used to absorb the moisture from the transformer liquid must be suited for the operational conditions. Vacuum dehydrator/degasifier systems use vacuum to remove the moisture and the dissolved gasses. The system must be designed so that the vacuum used in the processor is never exerted on the energized transformer. 80 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Annex A (informative) Alternative insulation liquid A.1 Retro-filling transformers Investigations into the operating characteristics of alternative insulation liquids like natural and synthetic esters continue to receive public attention. There are published technical papers on the transformer aging [B29], thermal dynamic performance [B48], and chemical interactions at operating conditions for available alternative insulation liquids. Retro-filling an existing transformer should include design considerations (viscosity, electrical characteristics, pour point, etc.). The operating conditions, such as expected ambient conditions as well as the fluid performance and handling are also key factors for consideration. NOTE—See IEEE Std C57.147 for additional guidance on this subject. Other considerations should include a cost benefit analysis. It is highly recommended to include an engineering design review with the original manufacturer of the transformer, as any possible re-rating or de-rating of the unit should it be retro-filled with an alternative fluid. 81 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers Annex B (informative) Bibliography Bibliographical references are resources that provide additional or helpful material but do not need to be understood or used to implement this standard. Reference to these resources is made for informational use only. [B1] ABB, Inc., Service Handbook for Transformers, 2nd Ed. Zurich, Switzerland: ABB Management Services Ltd, 2007, pp. 197–203. [B2] Allan, D. M., “Practical life assessment technique for aged transformer insulation,” IEE Proceedings A, vol. 140, no. 5, pp. 404–408, Sept. 1993, http://dx.doi.org/10.1049/ip-a-3.1993.0063. [B3] Allan, D. M., “Studies of the condition of insulation in aged power transformers. Part 1: Insulation condition and remnant life assessments for in-service units,” Proceedings of the 3rd International Conference on Properties and Applications of Dielectric Materials, July 8-12, 1991. [B4] Aschwanden, T. H. et al., “Development and application of new condition assessment methods for power transformers,” International Conference on Large High Voltage Electric Systems (CIGRE), Paper 12-207, 1998. [B5] Balma, P. M., R. C. Degeneff, H. R. Moore, and L. B. Wagenaar, “The effects of long term operation and system conditions on the dielectric capability and insulation coordination of large power transformers,” IEEE Transactions on Power Delivery, vol. 14, no. 3, p. •••, July 1999, http://dx.doi.org/10.1109/61.772341. [B6] Billington, R. and R. N. Allan, Reliability Evaluation of Engineering Systems: Concepts and Techniques. Plenum Press, 1983, http://dx.doi.org/10.1007/978-1-4615-7728-7. [B7] Bouchard, M. and D. Lapointe, “Premature aging in rectifier transformers,” Proceedings of 63rd Annual International Conference of Doble Clients, 1996. [B8] Burton, P. J., “Recent developments by CEGB to improve the prediction and monitoring of transformer performance,” CIGRE, Paper 12-09, 1984. [B9] Cheim, L., D. Platts, T. Prevost, and Xu Shuzhen, “Furan analysis for liquid power transformers,” Electrical Insulation Magazine, IEEE, Vol 28, Issue 2, pp. 8-21. [B10] Chendong, X., “Monitoring paper insulation aging by measuring furfural contents in oil,” 7th International Symposium on High Voltage Engineering, p. 139, 1991. [B11] Chendong, X., “To Estimate the Aging Status of Transformers by Furfural Concentration in the Oil,” CIGRE Committee 33 Colloquium, Leningrad, Moscow, 1991. [B12] CIGRÉ Technical Brochure N 445, “Guide for Transformer Maintenance” and Technical Paper “New diagnostic for High Voltage Bushings,” CIGRÉ International Conference Iguaçú 2010. [B13] CIGRE Working Group 12.09, “Lifetime evaluation of transformers,” Electra, no. 150, pp. 39–51, Oct. 1993. [B14] DePablo, A., “Furanic Compound Analysis: A Toll for Predictive Maintenance of Oil-Filled Electrical Equipment,” CIGRE Task Force Report 15.01.03. 82 Copyright © 2017 IEEE. All rights reserved. Authorized licensed use limited to: Zhejiang University. Downloaded on January 09,2025 at 02:38:25 UTC from IEEE Xplore. Restrictions apply. IEEE Std C57.140-2017 IEEE Guide for Evaluation and Reconditioning of Liquid Immersed Power Transformers [B15] DePablo, A., Furfural and Aging: How They Are Related. UK: IEE Power Division Colloquium Insulating Liquids, National Grid Leatherhead, 1999. [B16] Dick, E. P. and C. C. Erven, “Transformer diagnostic testing by frequency response analysis,” IEEE Transactions on Power Apparatus and Systems, vol. 97, pp. 2144–2153, 1978, http://dx.doi.org/10.1109/ TPAS.1978.354718. [B17] Dominelli, N., “The analysis of furanic and non-furanic compounds as a transformer diagnostic technique,” EPRI Substation Equipment Diagnostics Conference III, Nov. 1–3 1994. [B18] Emsley, A. M., ““Degradation of Cellulosic Insulation in Power Transformers. Part 3: Effects of Oxygen and Water on Aging in Oil,” IEE Proc. Sci,” Measurement Techniques, vol. 147, pp. 115–119, 2000, http://dx.doi.org/10.1049/ip-smt:20000021. [B19] Emsley, A. M., ““Degradation of Cellulosic Insulation in Power Transformers. Part 2: Formation of Furan Products in Insulating Oil,” IEE Proc. Sci,” Measurement Techniques, vol. 147, pp. 115–119, 2000, http://dx.doi.org/10.1049/ip-smt:20000021. [B20] EPRI TR-111593, Power Transformer Leak Mitigation—Technology Assessment, 1998. [B21] Gillies, D. A., L. E. Humbard, and E. J. Rogers, “Bonneville Power Administration transformer short circuit test results—Comparison of winding inspection with diagnostic methods,” IEEE Transactions on Power Apparatus and Systems, vol. 92, pp. 934–942, 1978. [B22] Heinrich, C. and V. Hinrichsen, “Diagnostics and monitoring of metal-oxide surge arresters in high-voltage networks—Comparison of existing and newly developed procedures,” IEEE Transactions on Power Delivery, vol. 16, no. 1, p. •••, January 2001, http://dx.doi.org/10.1109/61.905619. [B23] Haviland, G. S., “Design with threaded fastener,” Mechanical Engineering (New York, N.Y.), Oct, pp. 17–29, 1983. [B24] Hill, D. J. T., “A Study If Degradation Of Cellulosic Insulation In Power Transformers—Part 2: Tensile Strength Of Paper”, IEE Proceedings On Scientific Measurement Techniques, Vol. 147, pp. 285-290, 2000. [B25] Horning, M., J. Kelly, S. Myers, and R. Stebbins, Transformer Maintenance Guide. Tallmadge, OH: Transformer Maintenance Institute, Division of S. D. Myers, Inc., 2004. [B26] IEEE PC57.161™/D2.0 1, IEEE Draft Trial-Use Guide for Dielectric 2 Frequency Response Test. [B27] Jarman, P. N. et al., “Life assessment of 275 kV and 400 kV transmission transformers,” International Conference on Large High Voltage Electric Systems (CIGRE), Paper 12-210, 1998. [B28] Kamierski, M. et al., “Selected elements of life management of large power transformers—A Polish experience,” International Conference on Large High Voltage Electric Systems (CIGRE), Paper 12-203, 1998. [B29] Kachler, A. J. et al., “Pros and contras of on-site tests on power transformers and reactors,” International Conference on Large High Voltage Electric Systems (CIGRE), Paper 12-201, 1998. [B30] Liao, R., J. Hao, L. Yang, S. Liang, and J. Yin, “Improvement on the Anti-aging Properties of Power Transformers by Using Mixed Insulating Oil,” IEEE/DEIS and CSEE 2010 International Conference on High Voltage Engineering and Application, Oct. 11-14, 2010. [B31] Lat, M. V., and J. Carr, “Application guide for surge arresters on distribution systems,” CEA report 077-D-184A, Sept. 1988. 83 Copyright © 2017 IEEE. 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IEEE Guide: Transformer Evaluation & Reconditioning

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