ABB -Service Handbook for Transformers

Servic rv ice e Handbook ndb ook for Transform ransfo rme ers  DISCL DISC L AIMER OF WARRANTIES AND L LIMIT IMITATI ATION ON OF L LIAB IABIL ILITY ITY THE INFORMATION, RECOMMENDATIONS, DESCRIPTIONS AND SAFETY NOTIONS IN THIS DOCUMENT ARE BASED ON OUR EXPERIENCE, JUDGEMENT, AND DOCUMENTS IN THE PUBLIC DOMAIN WITH RESPECT TO TRANSFORMERS. THIS INFORMATION SHOULD NOT BE CONSIDERED TO BE ALL INCLUSIVE OR COVERING ALL CONTINGENCIES. IF FURTHER INFORMATION IS REQUIRED, THE TRANSFORMER DIVISION OF ABB INC. SHOULD BE CONSULTED. NO WARRANTIES, EXPRESSED OR IMPLIED, INCLUDING WARRANTIES OF FITNESS FOR A PARTICULAR PURPOSE OR MERCHANTABILITY, OR WARRANTIES ARISING FROM COURSE OF DEALING OR USAGE OF TRADE, ARE MADE REGARDING THE INFORMATION, RECOMMENDATIONS, DESCRIPTIONS, AND SAFETY NOTATIONS CONTAINED HEREIN. IN NO EVENT WILL ABB LTD. BE RESPONSIBLE TO THE USER IN CONTRACT, IN TORT (INCLUDING NEGLIGENCE), STRICT LIABILITY, OR OTHERWISE FOR ANY SPECIAL, INDIRECT, INCIDENTAL, OR CONSEQUENTIAL DAMAGE OR LOSS WHATSOEVER. THIS INCLUDES, BUT IS NOT LIMITED TO, DAMAGE TO OR LOSS OF USE OF EQUIPMENT, PLANT OR POWER SYSTEM, COST OF CAPITAL, LOSS OF PROFITS OR REVENUES, COST OF REPLACEMENT POWER, ADDITIONAL EXPENSES IN THE USE OF EXISTING POWER FACILITIES, OR CLAIMS AGAINST THE USER BY ITS CUSTOMERS RESULTING FROM THE USE OF THE INFORMATION, RECOMMENDATIONS, DESCRIPTIONS, AND SAFETY NOTATIONS CONTAINED HEREIN.  i ACKNOWL ACK NOWLEDGEMENTS EDGEMENTS This Transformer Service Handbook is meant to provide a general understanding of service as it relates to transformers. Service is a technical product that a transformer needs until the end of its lifetime. These pages provide an introduction to transformer service and maintenance, and are a guide to help increase the value of the product, by protecting and prolonging the asset life for customers and/or owners. The material was compiled and written by ABB experts from our Transformer Business Unit, based on their vast knowledge of transformers and many years of global experience in the field of transformer manufacturing and service. You are holding in your hands the end result of this challenging work – the Service Handboo Ha ndboo k for Transform ers. Leif Carlzon, Group Vice President and Product Group Manager for Transformer Service, Asim Fazlagic, Vice rPresident for Transformer Service Dr. George Frimpong, Transforme Transformer Service Servic e expert in USA, Pierre Boss, North SeniorAmerica, Transform Transformer er expert in Switzerland and Pierre Lorin, Technology Manager for Product Group Transformer Service have led the project by compiling, writing and editing the material in this handboo handbook. k. We also thank the ABB employees and industry partners who supplied valuable input and information, as well as a number of organizations which generously permitted us to use their materials and documentation in the creation of this handbook. Their support and contributions made this project possible. We are convinced that readers will find our Transformer Service Handbook a very useful and comprehensive source of answers to the many questions relating to transformers transform ers and a trouble-free product life. At ABB, we don’t just build high quality transformers - we take care of them so they stay that way. Tarak Mehta Group Senior Vice President Head of Business Unit Transformers Power Product Division Zurich, Switzerland ii  FOREWORD ABB possesses the technology rights of more than 30 brands including ABB, ACEC, ASEA, Ansaldo, Bonar Long, Breda, BBC, CGE, Challenger, Elektrisk Bureau, Elta, GE (> 40 MVA), GTE, Gould, IEL, ITC, ITE, Indelve, Industrial Design, Italtrafo, Lepper, MFO, Marelli, Moloney Electric, National Industri, Nitran, No-Tra-Mo, Ocren, OEL, OTE, Richard Pfeiffer, Sécheron, Strömberg, TIBB, Thrige, Westingho W estinghouse, use, Zinsco. At some utilities these transformers can account for up to 70-80 % of the utility’s total transformer asset base. With this in mind, we undertook the task of providing for the industry (users of ANSI/IEEE as well as IEC standards) a reference guide with detailed, yet easy to understand, information for the proper care and maintenance of transformers. This information should in no way supersede the maintenance guidelines provided by the transformer manufacturer. The engineering staffs at ABB keep abreast of new information and techniques available for analyzing problems problems in transformers. In many cases, we are the pioneers of such new ideas. In keeping up with new ideas, we have realized there is a wealth of information informa tion on transformers transformers available in the open literature. However, this information is at times found in little known journals, brochures, and books. What we have attempted to do with this handbook is to compile the most useful information into a single document. The goal is that this will serve as the preferred reference manual for all who are involved in the operation and maintenance of transformers. We have melded this information with our many years of experience in designing transformers and providing maintenance and diagnostic guidance to customers. This book can also be used as training material in many universities and schools, to help students gain specific knowledge about transformer service and maintenance. The material presented in this handbook is not meant to provide theoretical insights into the methods used for maintaining transformers. Instead, it is written to help the user gain a better understanding of why certain measurements are recommended, and in some cases, that howprovide to interpret the results of these are three short ABB publications theoretical coverage andmeasurements. discussions onThere transformers, circuit strengths as well as the testing of power transformers and shunt reactors (Transformer Handbook, Short circuit duty of Power Transformers and Testing of Power Transformers and Shunt Reactors available from the ABB website: www.abb.com/transformers). The layout of the handbook is as follows. We open with a general description of transformer design to help the user understand the nature of the various components that require maintenance in a transformer. Knowing the condition of a fleet of transformers transform ers iiss important for making informed decisions about any maintena maintenance, nce, repair or replacement activities. Therefore we address the topic of risk assessment/management of transformers. We present ABB’s methodology of risk assessment to of populations of transformers with them the view of identifying few that needastheapplied attention asset managers. This provides the ability to focusthe on  iii condition based rather than time based maintenance activities. This method has been successfully applied to transformer fleets of many utilities and industrial customers worldwide. The result has been to improve the availability of the fleet as a whole and at the same time optimize the maintenance spending where it has the best impact. This is followed by a general discussion of the various methodologies available for diagnosing potential problems in transformers. The subsequent sections, which constitute the bulk of the material in the handbook, provide detailed descriptions and discussions on the test methods and interpretation of results used to maintain and repair transformers, either in workshops or at site. Finally, we cover the environmental aspects related to transformers and the important topic of economics of transformer asset management. We would like to thank all the authors for their valuable contribution to making such a comprehensive book about using the transformer as a valuable asset for improving Power and Productivity for a Better World™. Leif Carlzon Asim Fazlagi Pierre Lorin Group Vice President Head of Product Group Service Zurich - Switzerland Vice President & General Manager ABB TRES North America Saint Louis, Missouri - USA Product Group Service Head of Technology Geneva - Switzerland iv  AUTHORS The first international version of this handbook was written in collaboration with ABB employees from several countries. We want to thank them all for this impressive team work. In Brazil Lars Eklund and Dr. Jose Carlos Mendes In China Henry-HongGuang Huang and Fred Samuelsson In Germany Sonia Berhane and Dr. Peter Werle In India Jivraj Sutaria In Ireland Mark Turner In Italy Paolo Capuano In Norway Knut Herdlevar and Arnt-Sigmar Todenes In Spain Miguel-Angel del-Rey, Rafael Santacruz and Nicolas Toribio In Sweden Dr. Dierk Bormann, Dr. Kjell Carrander, Dr. Mats Dahlund, Dr. Uno Gäfvert, Bjorn Holmgren, Lars Jonsson, Peter Labecker, Lena Melzer, Peter Olsson, Dr. Lars Pettersson and Bengt-Olof Stenestam In Switzerland Dr. Jose-Luis Bermudez, Pierre Boss, Cedric Buholzer, Thomas Horst, Paul Koestinger, Pierre Lorin, Jean-François Ravot, Ralf Schneider, Serge Therry, Olivier Uhlmann and Thomas Westman In Thailand Manoch Sangsuvan and Ekkehard Zeitz In Turkey Taner Danisment, Sener Ertuna and Burhan Gundem In United United Kingdom Liam Warren In United States of Americ a Wayne Ball, Gary Burden, Dr. Clair Claiborne, Eric Doak, Asim Fazlagi, Dr. George Frimpong, Ed Fry, Dr. Ramsis Girgis, Axel Kalt, Greg Leslie, Dr. T.V. Oommen, Mark Perkins, Eric Pisila, Rich Ronnau, Craig Stiegemeier and Brian Twibell.  v A special recognition goes to our colleagues who wrote the first ANSI/IEEE version of the handbook used as a base for the international version. Also we would also like to thank Doble Engineering, IEEE, CIGRE, GE Energy, FLIR Thermograpgy, Megger, Physical Acoustics, Electrical World Magazine, and the various other organizations that allowed the use of their materials in this handbook. Special thanks go to the three general reviewers Pierre Boss, Dr. George Frimpong and Mark Turner vi  CONTENTS DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITY........................................................I ACKNOWLEDGEMENTS ACKNOWL EDGEMENTS .................................................. ........................ ..................................................... ...................................................... .......................................... ............... II FOREWORD..........................................................................................................................................III AUTHORS ......................... ................................................... ..................................................... ...................................................... ..................................................... .....................................V ...........V 1 TRANSFORMER DESIGN DESIGN C CONSIDERATIONS ONSIDERATIONS ........................... ...................................................... ................................................ ..................... 17 1.1 1.2 1.3 1.4 1.5 CONFIGURATION ........................ ................................................... ..................................................... ..................................................... ........................................ ............. 17 MECHANICAL CONSIDERATION ....................... .................................................. ..................................................... ................................................ ...................... 17 THERMAL CONSIDERATIONS .......................... ..................................................... ..................................................... ................................................ ...................... 18 DIELECTRIC CONSIDERATIONS ....................... .................................................. ..................................................... ................................................ ...................... 19 CONSTRUCTION TYPES ........................ ................................................... ..................................................... ..................................................... ............................... .... 19 1.5.1 Shell Form....................... Form ................................................. ..................................................... ...................................................... ............................................ ................. 19 1.5.1.1 1.5.1.2 1.5.1.3 1.5.1.4 1.5.2 Core Form .................................................. ....................... ...................................................... ..................................................... ........................................... ................. 26 1.5.2.1 1.5.2.2 1.5.2.3 1.5.2.4 1.6 Design Design Fe Featu atures res ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................ ..... 19 Mechanical Strength ........................... Mechanical ............. ........................... .......................... .......................... .......................... .......................... ........................... ................. ... 20 Thermal Capability Capability............ ......................... .......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 22 Dielec Die lectric tric Characteristics............... Characteristics............................ .......................... .......................... ........................... ........................... .......................... ....................... .......... 24 Design Features ........... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................ ..... 26 Mechanical Strength ........................... Mechanical ............. ........................... .......................... .......................... .......................... .......................... ........................... ................. ... 27 Thermal Capability Capability............ ......................... ........................... ........................... .......................... .......................... .......................... .......................... ..................... ........ 29 Di Die ele lect ctric ric Characteristics................... Characteristics................................ .......................... ........................... ........................... .......................... .......................... .................... ....... 30 BUSHINGS ........................ .................................................. ..................................................... ..................................................... ................................................ ...................... 32 1.6.1 1.6.2 1.6.3 Design and Construction of Capacitances in Condenser Bushings Complying with the IEEE Standards .................... .............................................. ..................................................... .................................................... ......................... 32 Bushings Voltage Tap..................................... Tap........... ..................................................... ...................................................... ....................................... ............ 36 Connections ................................................... ......................... ..................................................... ..................................................... ....................................... ............. 38 1.6.3.1 1.6.3.2 1.6.3.3 1.6.4 1.6.5 1.7 In Inte tern rnal al Ele Elect ctririca call Co Conn nne ect ctio ions.... ns................. ........................... ........................... .......................... .......................... .......................... .......................... ................ ... 38 Dr Draw aw Lea Leadd Co Conn nne ecte ctedd Bu Bush shin ings................ gs............................. ........................... ........................... .......................... .......................... .......................... ............... 38 Bo Bott ttom om Co Conn nne ecte ctedd Bu Bush shin ings.... gs................. .......................... ........................... ........................... .......................... .......................... .......................... .................. ..... 38 Liquid Level Indication ........................... ...................................................... ..................................................... ................................................ ...................... 38 Painting ....................... ................................................. ..................................................... ...................................................... ................................................ ..................... 39 ON-LOAD TAP CHANGERS ........................ ................................................... ...................................................... .................................................... ......................... 40 1.7.1 Introductions....................................... Introductions............ ..................................................... ..................................................... .................................................... ......................... 40 1.7.2 Practices ..................................................... .......................... ..................................................... ........................................... ................. 1.7.2.1North-American General Description Descrip tion of LTCs .......................... ............. .......................... .......................... .......................... ........................... ........................... .................. ..... 41 41 1.7.2.2 Reactance Reactan ce Type LTCs.................................... LTCs...................... ........................... .......................... .......................... .......................... .......................... ................... ...... 41 1.7.2.3 Arcing Control Control Methods................................ Methods................... .......................... .......................... .......................... .......................... ........................... ..................... ....... 42 1.7.2.3.1 Arcin Arcingg Tap Switch Switch ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... .....................42 ..........42 1.7.2.3.2 Arcing Switch and Tap Selector Selector .......................... ............. .......................... .......................... ........................... ........................... ...................... ......... 42 1.7.2.3.3 Drive Mechan Mechanism ism for Reactance Reactance Type LTCs......................... LTCs............ .......................... ........................... ........................... .................. ..... 43 1.7.2.4 Vacuum Vacuu m Interrupter Interrupter Type LTCs.............................. LTCs................. .......................... .......................... .......................... .......................... ......................... ............ 43 1.7.2.5 Resistance Type LTCs................. LTCs.... ........................... ........................... .......................... .......................... .......................... .......................... ....................... .......... 44 1.7.2.6 Drive Mechanisms Mechanisms for Resistan Resistance ce Type LTCs............ LTCs ......................... .......................... ........................... ........................... .................... ....... 45 1.7.2.7 Failure Mechanisms Mechanisms for LTCs..................... LTCs........ .......................... .......................... .......................... .......................... ........................... ....................... ......... 45 1.7.2.7.1 Electrical Conne Connections ctions ........................... ............. ........................... .......................... .......................... .......................... .......................... ....................... .......... 45 1.7.2.7.2 Insulation System System ............ ......................... .......................... .......................... .......................... ........................... ........................... .......................... .................. ..... 46 1.7.2.7.3 Control System....... System.................... .......................... ........................... ........................... .......................... .......................... .......................... .......................... ............... 47 1.7.2.7.4 Mechan Mechanism ism ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................... ........47 47 1.7.3 European Practices ........................ .................................................. ..................................................... ..................................................... ............................. ... 47 1.7.3.1 Resistance Type OLTCs .......................... ............ ........................... .......................... .......................... .......................... .......................... ......................... ............ 47 1.7.3.2 1.7.3.3 Diverter Dive rterr Swi Switch tch OLTC ...................... ........... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................... ........48 48 Selecto Selector Switch OLTC... OLTC................ ........................... ........................... .......................... .......................... .......................... .......................... ......................... ............ 49  vii 1.7.3.4 Tie-In Resistors............ Resistors......................... .......................... ........................... ........................... .......................... .......................... .......................... .......................... ............. 51 1.7.3.5 Failure Mechanisms Mechanisms for OLTCs .......................... ............. .......................... .......................... .......................... .......................... ........................... ................ 52 1.7.3.5.1 Electrica Electricall Conne Connections ctions .......................... ............. .......................... .......................... .......................... ........................... ........................... ....................... .......... 52 1.7.3.5.2 Insula Insulation tion System System ............. .......................... ........................... ........................... .......................... .......................... .......................... .......................... ................. .... 53 1.7.3.5.3 Motor Drive Mechanism.. Mechanism............... .......................... ........................... ........................... .......................... .......................... .......................... ................... ...... 53 1.7.3.5.4 Mec Mechan hanism ism ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... .................... .........53 53 1.8 STREAMING ELECTRIFICATION ....................... .................................................. ..................................................... ................................................ ...................... 54 1.8.1 1.8.2 Charging Tendency Tendency and its Ef Effect fect of Streaming Streaming Electrification Electrification ......................... ........................................... .................. 55 Mitigation Strategies for Streaming Electrifica Electrification tion.......................... .................................................... ................................... ......... 56 2 A PRACTICAL APPROACH TO ASSESSING THE RISK OF FAILURE OF POWER TRANSFORMERS ..................................................... .......................... ..................................................... ..................................................... ................................................. ...................... 59 2.1 2.2 BACKGROUND........................ .................................................. ..................................................... ...................................................... ............................................ ................. 59 LIFE MANAGEMENT PROCESS ........................ ................................................... ...................................................... ................................................ ..................... 59 2.2.1 2.2.2 2.2.3 2.2.4 2.3 2.3.1 2.3.2 2.3.3 2.3.4 2.3.5 ........... ........67 ....67 ASSESSMENT OF THE TECHNICAL RISK OF FAILURE BY CATEGORY (MTMPTM PROGRAM) ....... Mechanical Aspects..... Aspects................................ ..................................................... ..................................................... ................................................ ..................... 67 Thermal Aspects............................ Aspects...................................................... ..................................................... ...................................................... .............................. ... 67 Electric Aspects Aspects - Risk of Dielectric Dielectric Failure....................... Failure.................................................. ................................................. ...................... 67 Aspects Related to Accessory Accessory Failure Failure........................... ...................................................... .................................................... ......................... 67 Total Technical Risk of Failure........................ Failure ................................................... ...................................................... ....................................... ............ 68 ISK MITIGATION ........................ R ................................................... ..................................................... ..................................................... ....................................... ............ 70 SUMMARY .................................................... ......................... ..................................................... ..................................................... ................................................ ..................... 70 2.4 2.5 3 Risk Assessment .......................... ..................................................... ...................................................... ..................................................... .............................. .... 60 Layout of the Ev Evaluation aluation Procedure ......................... ................................................... ..................................................... ............................... .... 63 Evaluation Procedure...................................... Procedure................................................................ ..................................................... ........................................ ............. 64 Probability of of Failure – Individual Failure Rate......... Rate.................................... ..................................................... ............................... ..... 66 DIAGNOSIS OF TRANSFORMERS........................................... TRANSFORMERS...................................................................... ................................................... ........................ 71 3.1 DIAGNOSTICS METHODS FOR POWER TRANSFORMERS AND ACCESSORIES ....................... .................................. ........... 71 3.1.1 Diagnostic Methods for Power Transformers..................................................... Transformers.......................... ........................................... ................ 71 3.1.1.1 3.1.1.2 3.1.1.3 3.1.2 Diagnostic Methods for Bushings......................... Bushings .................................................... ..................................................... .................................. ........ 74 3.1.2.1 3.1.2.2 3.1.2.3 3.1.3 Stressess Acting on Powe Stresse Powerr Transformers Transformers ......................... ............ .......................... .......................... .......................... .......................... ................ ... 72 Deterioration Factors Deterioration Factors and and Failure Failure Mechanis Mechanisms............... ms............................ ........................... ........................... .......................... ................ ... 73 Diagnostic Diagnos tic Methods.............. Methods........................... .......................... .......................... .......................... ........................... ........................... .......................... .................. ..... 73 Stressess Acting on Bushing Stresse Bushingss .......................... ............. .......................... ........................... ........................... .......................... .......................... .................. ..... 75 Deterioration Factors Deterioration Factors and and Failure Failure Mechanis Mechanisms............... ms............................ ........................... ........................... .......................... ................ ... 75 Diagnostic Diagnos tic Methods............ Methods......................... .......................... .......................... .......................... .......................... ........................... ........................... .................... ....... 76 Diagnostic Methods for for Surge Arresters...................................... Arresters........... ..................................................... ...................................... ............ 76 3.1.3.1 3.1.3.2 Stressess Acting on Surge Arresters Stresse Arresters ......................... ............ ........................... ........................... .......................... .......................... ...................... ......... 77 Deterioration Factors Deterioration Factors and and Failure Failure Mechanis Mechanisms............... ms............................. ........................... .......................... .......................... ................ ... 77 Diagnostic tic Methods.................. Metho ds............................... ........................... ........................... .......................... .......................... .......................... .......................... ............... 78 DIAGNOSIS TOOLS .....................................................................................................79 3.2 3.1.3.3 GENERALDiagnos 3.2.1 Oil Quality Assessment................................................. Assessment....................... ..................................................... .................................................... ......................... 79 3.2.1.1 Factors Affecting Affecting the Health and and Life of of Power Transformers Transformers .................. ............................... .......................... .................. ..... 79 3.2.1.2 Methods for Assessing Assessing the Quality of Transforme Transformerr Oils........................... Oils.............. .......................... .......................... ................... ...... 80 3.2.1.2.1 Dielectric Breakdown Breakdown Strength Strength (BDV)..................... (BDV)....... ........................... .......................... .......................... .......................... .................... ....... 80 3.2.1.2.2 Interfac Interfacial ial Tension Tension (IFT)....................... (IFT)......... ........................... .......................... .......................... .......................... .......................... ......................... ............ 80 3.2.1.2.3 Acid Neutra Neutralization lization Number Number ......................... ............ ........................... ........................... .......................... .......................... .......................... ................ ... 81 3.2.1.2.4 Powe Powerr Factor................... Factor................................ .......................... .......................... .......................... ........................... ........................... .......................... .................. ..... 82 3.2.1.2.5 Test for Oxygen Inhibitor............... Inhibitor............................ .......................... ........................... ........................... .......................... .......................... .................. ..... 82 3.2.1.2.6 Furan Analysis Analysis ...................... ................................. ...................... ...................... ....................... ....................... ...................... ...................... ...................... ............. .. 82 3.2.1.2.7 PCB Conte Content nt............. .......................... .......................... .......................... .......................... .......................... ........................... ........................... ........................ ........... 83 3.2.1.2.8 Corrosive Sulphur......... Sulphur...................... ........................... ........................... .......................... .......................... .......................... .......................... ..................... ........ 83 3.2.1.3 Moisture in Transfor Transformer mer Insulation Insulation Systems Systems ........................ ........... .......................... .......................... .......................... ........................ ........... 83 3.2.1.3.1 Trans Transforme formerr Oil ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... .............. ... 84 3.2.1.3.2 Relative Relative Humidi Humidity ty ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... .....................84 ..........84 3.2.1.3.3 Paper (Cellulose (Cellulose)........... )........................ .......................... .......................... .......................... .......................... ........................... ........................... .................... ....... 85 3.2.1.3.4 Where Does the Water Come From ......................... ............ .......................... .......................... ........................... ........................... ................. .... 86 3.2.1.3.5 Moisture Equilibrium Equilibrium between between Oil and Paper Paper in Transformers............... Transformers............................ .......................... ................. .... 86 viii  3.2.1.3.6 Caution Cautionss in Estimation of Moisture Moisture Using Moisture Equ Equilibrium ilibrium Curve Curvess .......................... ............. .................. ..... 88 3.2.1.4 Limits for for Measurement Measurement Oil Quality Quality Parameters Parameters ...................... .................................... ........................... .......................... .................... ....... 89 3.2.1.5 Moisture and Bubble Evolution in Transformers Transformers .......................... ............. .......................... ........................... ........................... ................ ... 92 3.2.2 Dissolved Gas in Oil Analysis (DGA) (DGA) ............................................................. ................................... ............................................. ................... 96 3.2.2.1 3.2.2.2 3.2.2.3 3.2.2.4 3.2.2.5 Introduction.............. Introduct ion........................... .......................... .......................... .......................... .......................... ........................... ........................... .......................... ................. .... 96 Procedure...................... .......................... Procedure................................... .......................... .......................... .......................... ........................... ........................... ........................ ........... 97 Sampling Samp ling ..................... ................................ ...................... ...................... ....................... ....................... ...................... ...................... ...................... ...................... ................ ..... 97 Extraction................... Extra ction.............................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... .................. ....... 97 Analysis.............................. Analysis................. .......................... .......................... ........................... ........................... .......................... .......................... .......................... ................... ...... 97 3.2.2.6 Interpre Inte rpretatio tation n ..................... .......... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ......................99 ...........99 3.2.2.7 Air ...................... ........... ...................... ...................... ...................... ...................... ...................... ....................... ....................... ...................... ...................... ...................... .............. ... 99 3.2.2.8 Gas Spectrum Spectrum – Types of Faults.................................... Faults...................... ........................... .......................... .......................... .......................... ................. .... 99 3.2.2.8.1 Hot Metal Metal Surface..................................... Surface........................ .......................... ........................... ........................... .......................... .......................... ................... ...... 99 3.2.2.8.2 Examples of Hot Metal Surfaces Surfaces ........................... ............. ........................... .......................... .......................... .......................... ..................... ........ 99 3.2.2.9 Overheatedd cellulose Overheate cellulose .......................... ............ ........................... .......................... .......................... .......................... .......................... ........................... ................ 100 3.2.2.9.1 Examples of Overheate Overheatedd Cellulose Cellulose ......................... ............ .......................... .......................... ........................... ........................... ................ ... 100 3.2.2.10 Electrica Ele ctricall Faults Faults ....................... .................................. ...................... ...................... ...................... ....................... ....................... ...................... ...................... ............. .. 100 3.2.2.10.1 Examples of Electrical Electrical Faults.................... Faults................................. .......................... ........................... ........................... .......................... ................ ... 100 3.2.2.11 Factors affecting affecting gas concentration concentration in transformers................ transformers............................. .......................... ........................... .................... ...... 101 3.2.2.11.1 Type and Brand Brand of Oil ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...........101 101 3.2.2.11.2 Oxygen...................... Oxygen................................... ........................... ........................... .......................... .......................... .......................... .......................... .................... ....... 101 3.2.2.11.3 Load.... Load............... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...........101 101 3.2.2.11.4 Oil Preservation Preservation Systems Systems ......................... ............ .......................... .......................... ........................... ........................... .......................... ................ ... 101 3.2.2.11.5 Gas Mixing Mixing ..................... ................................. ....................... ...................... ...................... ...................... ...................... ...................... ...................... ................ ..... 102 3.2.2.11.6 Temperature................. Temperature.............................. ........................... ........................... .......................... .......................... .......................... .......................... ................. .... 102 3.2.2.11.7 Gas Solubility Solubility in Oil................ Oil... .......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 103 3.2.2.11.8DGAOther Factors............ Factors .......................... .......................... .......................... ........................... ........................... .......................... ..................... ........ 104 3.2.2.12 Interpretation Interpre tation......................... Methods......................... Methods........... ........................... .......................... .......................... .......................... .......................... ................... ...... 106 3.2.2.12.1 Key Gas Method Method of of Interpreting Interpreting DGA........................... DGA.............. ........................... ........................... .......................... ....................... .......... 106 3.2.2.12.2 Individua Individuall and Total Total Dissolved Dissolved Key-Gas Concentration Concentration Metho Method d .......................... ............. ......................... ............ 107 3.2.2.12.3 Rogers Ratio Method............... Method.. ........................... ........................... .......................... .......................... .......................... .......................... ................... ...... 110 3.2.2.12.4 IEC Method Method ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ............... .... 112 3.2.2.12.4.1 Carbon Dioxide/Carbon Monoxide (CO2/CO) Ratio ................... ...................................... ......................................11 ...................112 2 3.2.2.12.4.2 IEC C2H2/H2 Ratio .................. ..................................... ...................................... ...................................... ...................................... ...................................11 ................113 3 ................................... ....................................... ................................113 ............113 3.2.2.12.4.3 IEC Recommended Method of Interpretation ................ 3.2.2.12.5 Duval Triangle Method for Diagnosing a Transformer Problem Using Dissolvedd Gas Analysis Dissolve Analysis ............ ......................... .......................... .......................... .......................... .......................... ........................... ................... ..... 114 3.2.2.12.6 ABB's Advanced Advanced Dissolved Dissolved Gas Gas Analysis Analysis Software Software (ADGA (ADGA)) .............. ........................... .......................... ................ ... 117 3.2.3 Analysis of Particles Particles in Transformer Oils ..................................................... .......................... .............................................. ................... 118 3.2.3.1 Oil Sampling Sampling for Particle Analysis Analysis .......................... ............. .......................... .......................... .......................... .......................... ....................... .......... 118 3.2.3.2 Particle Counting ......................... ............ .......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 118 3.2.3.2.1 Normal and and Abnormal Abnormal Particle Count Levels......... Levels...................... ........................... ........................... .......................... ................... ...... 119 3.2.3.3 Trace Metal Content of Particles...... Particles................... .......................... .......................... .......................... .......................... ........................... ................... ..... 120 3.2.3.3.1 Method of Measurement Measurement............. .......................... .......................... .......................... .......................... ........................... ........................... .................. ..... 120 3.2.3.3.2 Normal and Abnorma Abnormall Metallic Content Content of Particles Particles in Oil......................... Oil........... ........................... ........................ ........... 120 3.2.3.4 Diagnostic Diagnos tic Examples Examples of Particle Analysis.......................... Analysis............. .......................... .......................... .......................... ......................... ............ 121 3.2.3.5 Effect of particles particles on dielectric dielectric strength of insulating insulating oil oil .......................... ............. .......................... .......................... ................ ... 122 3.2.3.5.1 Current filtering practices practices on on new new transformers.... transformers................. .......................... .......................... ........................... ..................... ....... 122 3.2.3.5.2 Classificat Classification ion of contamination contamination level.................. level..... .......................... .......................... .......................... .......................... ....................... .......... 123 .................................... ...................................... ...................................... ...................................... ...................................... .......................123 ....123 3.2.3.5.2.1 Bare electrodes ................. ..................................... ...................................... ...................................... ...................................... ...................................12 ................123 3 3.2.3.5.2.2 Covered electrodes .................. 3.2.3.5.3 Contamina Contamination tion deposited deposited on insulating insulating surface.. surface............... .......................... ........................... ........................... ...................... ......... 124 3.2.3.5.4 Recommend Recommended ed corrective action................... action..... ........................... .......................... .......................... .......................... .......................... ............... 125 3.2.4 Winding Resistance Test ................................................... ........................ ...................................................... ............................................. .................. 126 3.2.4.1 3.2.5 3.2.6 Transformer Turns Ratio Test (TTR) .......................... .................................................... ..................................................... ........................... 128 Insulation resistance ................................................. ....................... ..................................................... ...................................................... ........................... 131 3.2.6.1 3.2.6.2 3.2.6.3 3.2.7  Measurement Measure ment Method for Winding Winding Resistan Resistance ce Measurement................... Measurement................................ .......................... ................ ... 126 Measurement........................... Measurement.............. .......................... .......................... ........................... ........................... .......................... .......................... ......................... ............ 131 Interpre Inte rpretatio tation n ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................... ........ 132 Polariza Pola rization tion Index Index ...................... ................................. ...................... ...................... ....................... ....................... ...................... ...................... ...................... ...........133 133 Insulation Power Factor Tests............................................ Tests.................. ..................................................... ............................................. .................. 134 ix 3.2.7.1 Two-Winding Two-Wind ing Transformer Transformer............ ......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 135 3.2.7.1.1 Testing of Two-Winding Two-Winding Transformers... Transformers................. ........................... .......................... .......................... .......................... ..................... ........ 136 3.2.7.2 Three-Winding ThreeWinding Transformer.............. Transformer........................... .......................... ........................... ........................... .......................... .......................... ................. .... 139 3.2.7.3 Typical Insulation Insulation Power Factor Values............. Values.......................... .......................... .......................... .......................... .......................... ............... .. 140 3.2.7.4 General Guideline Guideliness for Assessing Assessing Power Power Factor Values Values ......................... ............ .......................... ........................... ................. ... 141 3.2.7.5 Power Factor Tip-up Tests .......................... ............. .......................... .......................... ........................... ........................... .......................... ................... ...... 141 3.2.8 Core Insulation Resistance Measurement ......................... ................................................... .............................................. .................... 142 3.2.8.1 3.2.9 3.2.9.1 3.2.9.2 3.2.10 Measurement Measure ment and Diagnosis Diagnosis of of Inadvertent Inadvertent Core Grounds........ Grounds..................... .......................... .......................... ................. .... 142 Excitation Current Tests............................. Tests........................................................ ..................................................... .......................................... ................ 144 Measurement Measure ment Setup................................. Setup.................... ........................... ........................... .......................... .......................... .......................... ...................... ......... 145 Analysis of Excitation Excitation Current Results........... Results........................ .......................... .......................... .......................... ........................... ................... ..... 148 Infrared Thermography Thermography Anal Analysis ysis of Transformers and and Accessorie Accessories s ....................... ............................. ...... 149 3.2.10.1 The Thermography Thermography Process............ Process ......................... .......................... .......................... .......................... .......................... ........................... ................... ..... 149 3.2.10.2 Criteria for Evaluating Evaluating Infrared Measurements Measurements .......................... ............. .......................... ........................... ........................... ................ ... 150 3.2.10.3 Example Uses Uses of Infrared Thermography Thermography diagno diagnostics stics on Power Power Transformers ..................... .............. ....... 150 3.2.10.3.1 Loose connection connection at bushing bushing outlet outlet terminal................ terminal............................. .......................... .......................... ......................... ............ 150 3.2.10.3.2 Blocked oil flow in radiators radiators or or radiator radiator shut off .......................... ............ ........................... .......................... ....................... .......... 151 3.2.10.3.3 LTC overheating overheating .......................... ............. ........................... ........................... .......................... .......................... .......................... .......................... ............... .. 151 3.2.10.3.4 Low oil level in ttransfor ransformer mer or bushing bushing .......................... ............. .......................... .......................... .......................... ....................... .......... 152 3.2.10.3.5 Moisture contamination contamination of surge arrester............. arrester .......................... .......................... .......................... .......................... ................... ...... 152 3.2.11 Bushings .................................................... ......................... ...................................................... ..................................................... ..................................... ........... 153 3.2.11.1 ANSI & IEC – C Common ommon Diagnostic Diagnostic Tools..................... Tools........ .......................... .......................... .......................... ........................... ................. ... 153 3.2.11.1.1 Oil leakage inspection inspection............ ......................... .......................... .......................... ........................... ........................... .......................... ..................... ........ 153 3.2.11.1.2 Insulator inspection inspection and cleaning................................... cleaning...................... ........................... ........................... .......................... ..................... ........ 153 3.2.11.1.2.1 Porcelain insulators .................... ....................................... ...................................... ...................................... ...................................... ...............................153 ............153 3.2.11.1.2.2 Silicon rubber insulators ................... ...................................... ...................................... ...................................... ...................................... .........................153 ......153 3.2.11.1.3 Thermovis Thermovision... ion................ ........................... ........................... .......................... .......................... .......................... .......................... ........................... ................. ... 153 3.2.11.1.4 Oil sampling sampling from bushin bushing g .......................... ............. .......................... .......................... .......................... ........................... ........................... ............... 154 3.2.11.1.5 Dissolved Gas Analysis Analysis (DGA) ............ .......................... ........................... .......................... .......................... .......................... ..................... ........ 156 3.2.11.1.6 Moisture analysis analysis............ .......................... ........................... .......................... .......................... .......................... .......................... ........................... ................ 156 3.2.11.1.7 Dielectric Frequency Frequency Response Response Analysis Analysis (DFRA (DFRA)) ......................... ............ .......................... .......................... ..................... ........ 157 3.2.11.1.8 Partial Discharge Discharge measurements... measurements................ .......................... ........................... ........................... .......................... .......................... ............... 157 3.2.11.1.9 De-polyme De-polymerization rization analysis.......... analysis....................... ........................... ........................... .......................... .......................... .......................... ................ ... 157 3.2.11.2 Diagnostics Diagnos tics techniques techniques for bushings bushings complying with the ANSI/IEEE Standards..................... Standards.................. ... 158 3.2.11.2.1 Conde Condenser nser Bushing Power Factor Tests.................... Tests....... ........................... ........................... .......................... ......................... ............ 158 3.2.11.2.2 Factors Affecting Affecting C1 and C2 Capac Capacitance itance and Power Power Factor Measurements Measurements .................. ............. ..... 159 3.2.11.2.3 Bushing Hot Collar Test ........................... .............. .......................... .......................... .......................... .......................... ........................... ................. ... 162 3.2.11.2.4 What to do when when Bushing Power Power Factor Tests Tests are Doubtful................... Doubtful................................ ......................... ............ 164 3.2.11.2.5 Special Case – Type “U” Bushing Bushingss ............ ......................... ........................... ........................... .......................... .......................... ............... 164 3.2.11.2.5.1 History .................. ..................................... ...................................... ...................................... ...................................... ...................................... ...................................16 ................164 4 3.2.11.2.5.2 Recommendation ................... ...................................... ...................................... ...................................... ...................................... ...................................17 ................170 0 3.2.11.2.6 Type “T” Bushings.................. Bushings............................... .......................... ........................... ........................... .......................... .......................... ..................... ........ 173 3.2.11.3 Diagnostics Diagnos tics and Conditioning on ABB Bushings Complying Complying with the IEC Standa Standard.......... rd................ ...... 174 3.2.11.3.1 Capacitance and tan measurement............. measurement........................... ........................... .......................... .......................... ......................... ............ 175 3.2.11.3.2 Temperature correction............................ correction............... .......................... .......................... .......................... ........................... ........................... ................ ... 175 3.2.12 Measurements for Assessing the Condition Condition of OLTCs/LTCs ....................................... ......................... .............. 178 3.2.12.1 Number of Operations... Operations................ .......................... .......................... ........................... ........................... .......................... .......................... ....................... .......... 178 3.2.12.2 Resistance of the Electrical Electrical Conne Connections ctions .......................... ............. .......................... .......................... .......................... ......................... ............ 178 3.2.12.3 Temperature.. Tempera ture............... .......................... .......................... .......................... ........................... ........................... .......................... .......................... ......................... ............ 178 3.2.12.4 Motorr Current Moto Current ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................... ........ 178 3.2.12.5 Acoustic Signal Signal .......................... ............. .......................... .......................... ........................... ........................... .......................... .......................... ....................... .......... 178 3.2.12.6 Relay Timing.................................... Timing....................... ........................... ........................... .......................... .......................... .......................... ........................... ................. ... 179 3.2.12.7 Gas-in-Oi Gas-i n-Oill Analysis Analysis ....................... .................................. ...................... ...................... ...................... ...................... ...................... ...................... .................... ......... 179 3.2.12.7.1 Items Specific Specific to the European European Practice................................ Practice................... .......................... ........................... ........................... ............. 179 ...................................... ...................................... ...................................... ...................................... ...................................... ...................................17 ................179 9 3.2.12.7.1.1 Scope ................... ..................................... ...................................... ...................................... ...................................... ...................................... ...................................17 ................179 9 3.2.12.7.1.2 History .................. ...................................... ...................................... .............................179 ..........179 3.2.12.7.1.3 Faults in OLTCs possible to indicate by DGA................... ..................................... ...................................... ...................................... ...................................... ................................180 .............180 3.2.12.7.1.4 The Stenestam ratio .................. .................................... ................................180 .............180 3.2.12.7.1.5 Importan Importantt principals for inte i nterpretation rpretation of DGAs in OLTC ................. ..................................... ...................................... ...................................... ................................180 .............180 3.2.12.7.1.6 Stenestam ................. ratio .................. .................................... ...................................... ...................................... ...................................... ......................181 ...181 3.2.12.7.1.7 Interpreting Typical gas the concentrations x  3.2.12.7.2 Impo Importan rtantt to bear bear in mind ..................... ................................ ...................... ...................... ...................... ...................... ...................... .................. ....... 182 3.2.12.7.3 North-Ame North-American rican Practice............ Practice ......................... .......................... ........................... ........................... .......................... .......................... ................. .... 182 3.2.12.8 Moisture Moist ure ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................ ..... 183 3.3 ADVANCED DIAGNOSTIC TOOLS ......................... .................................................... ...................................................... .......................................... ............... 184 3.3.1 Assessment of Mechanical Mechanical Properties - Frequency Respons Response e Analysis (FRA) ................ 184 3.3.1.1 Introduction.............. Introduct ion........................... .......................... .......................... .......................... ........................... ........................... .......................... .......................... ............... .. 184 3.3.1.1.1 Purpose of FRA measurements measurements .......................... ............ ........................... .......................... .......................... .......................... ..................... ........ 184 3.3.1.1.2 When should should FRA measurements measurements be performed?...................... performed?................................... .......................... ......................... ............ 184 3.3.1.2 Standards. Standa rds.............. .......................... .......................... .......................... ........................... ........................... .......................... .......................... .......................... ................. .... 185 3.3.1.3 General description description of the FRA method ......................... ............ .......................... .......................... .......................... .......................... ............... .. 185 3.3.1.3.1 Principle of the measurement.................. measurement............................... ........................... ........................... .......................... .......................... ................... ...... 185 3.3.1.3.2 Pract Practical ical set-up set-up ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...........186 186 3.3.1.4 Commerciall equipment Commercia equipment ......................... ............ .......................... .......................... .......................... ........................... ........................... ......................... ............ 187 3.3.1.5 Detailed measurement measurement procedure..... procedure................... ........................... .......................... .......................... .......................... ........................... ................. ... 187 3.3.1.5.1 Test preparation preparation............. .......................... ........................... ........................... .......................... .......................... .......................... .......................... ................. .... 188 3.3.1.5.2 Tap changer changer position position .......................... ............. .......................... .......................... ........................... ........................... .......................... ....................... .......... 188 3.3.1.5.3 Treatment of un-tested un-tested terminals.................................. terminals..................... .......................... ........................... ........................... ........................ ........... 189 3.3.1.5.4 Test lea leads ds:: ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... .................. ....... 189 3.3.1.5.5 Test Set-up Set-up ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... .................. ....... 189 3.3.1.6 Reporting Repo rting of FRA measure measurements............... ments............................ ........................... ........................... .......................... .......................... ..................... ........ 192 3.3.1.6.1 General information: information: ......................... ............ .......................... .......................... ........................... ........................... .......................... ......................... ............ 192 3.3.1.6.2 Transforme Transformerr information:................... information:................................ .......................... ........................... ........................... .......................... ......................... ............ 192 3.3.1.6.3 Description of each measurement: measurement:............. .......................... .......................... .......................... ........................... ........................... ................ ... 192 3.3.1.6.4 Inst Instrume rumenta ntation: tion: ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...........193 193 3.3.1.6.5 Cab Cabling: ling: ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...........193 193 3.3.1.7 Basic interpretation interpretation and and on-site on-site quality check............................. check............... ........................... .......................... .......................... ................ ... 193 3.3.1.7.1 Some “normal” “normal” FRA spectra spectra ..................... ................................ ...................... ...................... ...................... ...................... ...................... ............... .... 194 3.3.1.7.2 Meaning of of different different frequency frequency ranges ranges in an FRA spectru spectrum m ........................... .............. .......................... .................. ..... 197 (A) When only the current FRA FRA measurement measurement data are available:........ available:..................... ........................... ........................... .................... ....... 197 3.3.1.7.3 Compariso Comparison n betwee between n open- and short-circuit short-circuit measurements measurements ......................... ............ .......................... .................. ..... 197 3.3.1.7.4 Compariso Comparison n betwee between n high- and and low-voltage low-voltage windings windings ......................... ............ .......................... .......................... ................ ... 197 3.3.1.7.5 Compariso Comparisonn between between phases. phases.............. ........................... ........................... .......................... .......................... .......................... ....................... .......... 197 (B) When further data are available....................... available.......... ........................... ........................... .......................... .......................... .......................... ....................... .......... 198 3.3.1.7.6 Compariso Comparisonn with historical data............. data.......................... .......................... ........................... ........................... .......................... ..................... ........ 198 3.3.1.7.7 Compariso Comparisonn with twin or sister units .......................... ............. ........................... ........................... .......................... .......................... ............... 198 3.3.1.7.8 Hist History ory of the unit unit ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... .................... ......... 198 3.3.1.7.9 Other diagnostic diagnostic data..................................... data........................ .......................... .......................... ........................... ........................... ......................... ............ 199 3.3.1.8 Exampless of Example of problems problems diagnosed diagnosed using using FRA FRA .......................... ............. ........................... ........................... .......................... .................. ..... 199 3.3.1.8.1 Axial Winding Collapse Collapse............. .......................... .......................... .......................... .......................... .......................... ........................... ..................... ....... 199 3.3.1.8.2 Hoop Buckling.... Buckling................. .......................... .......................... .......................... .......................... ........................... ........................... .......................... ................ ... 200 3.3.1.8.3 Short Shorted ed Turns Turns ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ............. .. 202 3.3.2 Assessment of Thermal Properties .................................................. ....................... ...................................................... ............................... .... 204 3.3.2.1 Degree of Polymerization Polymerization (DP) ........................... ............. ........................... .......................... .......................... .......................... ......................... ............ 204 3.3.2.1.1 DP versus Life Plots ............ ......................... ........................... ........................... .......................... .......................... .......................... ......................... ............ 204 3.3.2.1.2 Latest Research Research Findings on DP DP Analys Analysis is .......................... ............. .......................... ........................... ........................... .................. ..... 207 3.3.2.2 Furanic Compound Compound Analysis... Analysis................ .......................... .......................... ........................... ........................... .......................... .......................... ............... 207 3.3.2.2.1 Origin of Furanic Furanic Co Compounds mpounds ........................... .............. .......................... .......................... .......................... ........................... ....................... ......... 207 3.3.2.2.2 Dete Detection ction of Furanic Compounds.. Compounds............... .......................... .......................... ........................... ........................... .......................... ................ ... 208 3.3.2.2.3 Correlatio Correlation n Curves Curves of Furanic Furanic Conte Content nt with DP...................... DP......... .......................... .......................... .......................... ................ ... 208 3.3.2.2.4 Issues to Consider Consider in Using Using Furan Analysis Analysis............. ........................... ........................... .......................... .......................... ................ ... 209 3.3.3 Dielectric Dielectri c Frequency Response as a Tool for Troubleshooting Insulation Power Factor Problems ..................................................... .......................... ..................................................... ............................................. ................... 211 3.3.3.1 Introduction.............. Introduct ion............................ ........................... .......................... .......................... .......................... .......................... ........................... ........................... ............... 211 3.3.3.2 Dielectric Dielectr ic frequenc frequencyy response response and X-Y model model............ ......................... ........................... ........................... .......................... .................. ..... 211 3.3.3.3 Causess of High Cause High Power Power Factor in Transformer Transformer Insulation Insulation............. .......................... .......................... .......................... ................ ... 214 3.3.3.3.1 Compariso Comparison n of DFR to Power Factor Factor Measureme Measurement nt............. .......................... .......................... .......................... .................. ..... 214 3.3.3.3.2 Influence of Oil Conduct Conductivity ivity and Moisture Moisture on PF and and DFR .......................... ............. .......................... .................... ....... 215 3.3.3.4 Dielectric Dielectr ic Frequency Response Response Signature and Identification Identification Techniques Techniques ......................... ............ .................. ..... 216 3.3.3.4.1 Identifica Identification tion of high Core-Groun Core-Grounding ding Resistance Resistance Proble Problems ms ......................... ............ .......................... .................... ....... 217 3.3.3.4.2 Identif Identification ication of of Paper Paper Contamination Contamination Problems...... Problems................... .......................... .......................... .......................... .................. ..... 220 3.3.3.4.3 Low Temperature Temperature Effect on Insulation Insulation Power Power Factor Factor............ ......................... .......................... .......................... .................. ..... 220 3.3.3.5 Summary.......... Summary..................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ............... .... 222  xi 3.3.4 Assessment of Electrical Electrical Properties - Partial Discharge Discharge Measurements .......................... 223 3.3.4.1 Purpose of measurement measurement .......................... ............. .......................... .......................... ........................... ........................... .......................... ..................... ........ 223 3.3.4.2 Electrical PD Measurement Measurement on on Transformers Transformers .......................... ............ ........................... .......................... .......................... ................... ...... 224 3.3.4.2.1 Calibration Calibration............. .......................... .......................... .......................... ........................... ........................... .......................... .......................... .......................... ............. 225 3.3.4.2.2 PD measuring procedure procedure............. ........................... ........................... .......................... .......................... .......................... .......................... ................. .... 226 3.3.4.2.3 An Advan Advanced ced PD syste system m ........................... ............. ........................... .......................... .......................... .......................... .......................... ................. .... 226 3.3.4.3 Procedure for Investiga Investigation tion of PD PD Sources............ Sources......................... .......................... ........................... ........................... ....................... .......... 228 3.3.4.4 Acousticall Partial Discharge Acoustica Discharge Measure Measurement ment on Transforme Transformers rs ......................... ............ .......................... ....................... .......... 233 3.3.4.4.1 Acoustic PD Wave Characterization............. Characterization.......................... .......................... .......................... .......................... ........................... ................ 233 3.3.4.4.2 4 Acoustic Partial Discharge Discharge Localization Localization ......................... ............ ........................... ........................... .......................... ....................... .......... 235 FAULT ANALYSIS ANAL YSIS ..................................................... .......................... ...................................................... ..................................................... ..................................... ........... 237 4.1 GUIDANCE FOR PERFORMING FAILURE ANALYSIS ......................... .................................................... .............................................. ................... 237 4.1.1 4.1.2 4.1.3 4.1.4 4.1.5 Introduction...................................... ..................................................... Introduction................................................................ ..................................................... .......................... 237 Failure definition ........................... ...................................................... ..................................................... ..................................................... ............................. .. 239 Classification of failures ................................................... ........................ ..................................................... ............................................... ..................... 239 General information information on on malfunctions malfunctions and failures ........................... ...................................................... ................................. ...... 240 Systematic failure analysis............ analysis....................................... ..................................................... ..................................................... ............................. .. 241 4.1.5.1 4.1.5.2 4.1.5.3 4.1.5.4 4.1.5.5 4.1.6 Collecting information on the unit concerned concerned ......................... ............ .......................... .......................... .......................... ..................... ........ 242 Data and and information information at the time of of fault inception............... inception. ........................... .......................... .......................... ....................... .......... 243 Deciding on continued continued operation operation or additional additional investigations investigations ......................... ............ .......................... ....................... .......... 246 Assessment Assess ment of the extent extent of of damage damage on site site ......................... ............ .......................... .......................... .......................... ..................... ........ 247 Assessment Assess ment of external external damage damage on site........................... site.............. .......................... ........................... ........................... ......................... ............ 248 Diagnostic measurements and their interpretati interpretation on ........................ .................................................. ................................ ...... 249 4.1.6.1 Routine measurements measurements on site ......................... ............ .......................... ........................... ........................... .......................... .......................... ............... 250 4.1.6.1.1 Oil analysis analysis ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... .................. ....... 250 4.1.6.1.2 Insulation resistance and tan  ........... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...........250 250 4.1.6.1.3 Measure Measurement ment of transformer transformer ratio ......................... ............ .......................... .......................... .......................... ........................... ................... ..... 250 4.1.6.1.4 Measure Measurement ment of winding winding resistances............. resistances.......................... .......................... .......................... .......................... .......................... ............... 251 4.1.6.1.5 Measure Measurement ment of short-circuit short-circuit impedance impedance .......................... ............ ........................... .......................... .......................... ..................... ........ 251 4.1.6.1.6 Excitation at low voltage .......................... ............ ........................... .......................... .......................... .......................... ........................... ................... ..... 252 4.1.6.2 Special diagnostic diagnostic measurements measurements ......................... ............ .......................... .......................... .......................... .......................... ....................... .......... 252 4.1.6.2.1 Gas-in-oil analysis analysis .......................... ............. .......................... .......................... .......................... .......................... ........................... ........................... ............... 252 4.1.6.2.2 Measure Measurement ment of partial partial discharges.................. discharges............................... .......................... .......................... .......................... ......................... ............ 254 4.1.6.2.3 FRA method............... method............................ .......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 255 4.1.6.2.4 Measure Measurement ment of polarization polarization effects effects for for assessing the moisture moisture ......................... ............ .......................... ............... 256 4.1.6.3 Inspection Inspect ion of core-and-coil core-and-coil assembly assembly on site............ site ......................... .......................... .......................... ........................... ..................... ....... 256 4.1.6.3.1 General preconditions....................... preconditions.................................... .......................... .......................... ........................... ........................... ......................... ............ 256 4.1.6.3.2 Safety preca precautions................. utions............................... ........................... .......................... .......................... .......................... ............................. ....................... ....... 257 4.1.6.3.3 Checks to be conducted conducted .......................... ............ ........................... .......................... .......................... .......................... .......................... ................... ...... 257 4.1.6.4 Dismantling Dismantl ing the defective defective transformer transformer............. .......................... .......................... ........................... ........................... .......................... ................ ... 258 4.1.6.4.1 Prec Precond onditio itions ns ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... ............... .... 258 4.1.6.4.2 Inspe Inspection ction ...................... .................................. ....................... ...................... ...................... ...................... ...................... ...................... ...................... .................. ....... 259 4.1.6.4.3 Inspect Inspection ion of the core-and-coil core-and-coil assembly afte afterr lifting out of the tank............................. tank................ .................. ..... 259 4.1.6.4.4 Inspect Inspection ion of the windings............. windings.......................... .......................... .......................... .......................... ........................... ........................... ................ ... 260 4.1.6.5 Typical fault patterns of windings windings .......................... ............. ........................... ........................... .......................... .......................... ....................... .......... 260 4.1.6.5.1 Short-circui Short-circuitt faults................... faults................................ .......................... .......................... .......................... .......................... ............................. ....................... ....... 260 4.1.6.5.2 Electrical flashove flashoverr ......................... ............ .......................... .......................... ........................... ........................... .......................... .......................... ............... 261 4.1.6.5.3 The Thermal rmal fau faults lts ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ............. .. 263 4.1.6.6 Inspection Inspect ion of the core and the tank............. tank .......................... .......................... .......................... .......................... .......................... ..................... ........ 263 4.1.7 4.1.8 Final assessment of of the fail failure ure and the fault............................... fault.......................................................... ..................................... .......... 264 Case Studies ........................ ................................................... ...................................................... ..................................................... .................................... .......... 265 4.1.8.1 4.1.8.2 4.1.8.3 5 xii Case 1: Examination Examination of a transformer transformer affected affected by partial partial discharges............ discharges......................... ........................ ........... 265 Case 2: 2: Analysis Analysis of a failure failure caused caused by overvoltages overvoltages at no-load no-load switching switching operation operation ........... 275 Case 3: Fault analys analysis is on a generator generator step-up step-up Transformer Transformer following following an internal internal flashover flashover . 279 ONLINE DIAGNOSTIC MONITORS MONITORS FOR TRANSFORMERS AND KEY ACCESSOR ACCESSORIES IES .......... 284 5.1 POWER TRANSFORMER (TANK & CORE) ................................................... ......................... ..................................................... ............................... .... 284 5.2 5.3 HANGER ........................ LBOAD TAP&CCT ................................................... ...................................................... ..................................................... ............................... ..... 285 USHING .................................................. ........................ ..................................................... ...................................................... ........................................ ............. 285  5.4 6 EXAMPLE MONITORING SYSTEMS ........................... ..................................................... ..................................................... ...................................... ........... 286 PREVENTIVE PREVEN TIVE MAINTENANC MAINTENANCE E OF TRANSFORMERS............................................................... TRANSFORMERS................................................ ............... 294 6.1 BASIC AGEING PROCESSES ........................... ...................................................... ..................................................... .............................................. .................... 294 6.1.1 6.1.2 6.1.3 Introduction..................................... ...................................................... Introduction................................................................ ..................................................... .......................... 294 Paper Degradation.................................................................. Degradation........................................ ..................................................... ........................................ ............. 295 On-site Drying Methods ................................................... ........................ ...................................................... ............................................... .................... 298 6.1.3.1 Traditionall methods............. Traditiona methods.......................... .......................... .......................... ........................... ........................... .......................... .......................... ................. .... 298 6.1.3.2Oil reclaiming................................ On-site drying with low frequency frequency..................................................... heating heating (LFH) in combination combina tion with hot-o hot-oil il spray ................ ............. ... 299 6.1.4 reclaiming.......................................................... ...................................................... ............................. .. 300 6.1.4.1 6.1.4.2 6.1.4.3 6.2 Online oil reclaiming technology technology ................. .... .......................... ........................... ........................... .......................... .......................... ................... ...... 300 Comparison with oil change............ Comparison change......................... .......................... ........................... ........................... .......................... .......................... ................... ...... 300 Long- term stability................................ stability................... .......................... ........................... ........................... .......................... ............................ ......................... .......... 300 GENERAL MAINTENANCE OF TRANSFORMERS ........................ .................................................. .................................................. ........................ 302 6.2.1 Recommended schedule of Maintenance activities .................................................. ....................... .................................. ....... 302 6.2.1.1 6.2.1.2 6.2.1.3 6.2.2 Monthly Maintenance Maintenance Schedule.. Schedule............... .......................... .......................... ........................... ........................... .......................... ....................... .......... 302 Quarterly Maintenance Maintenance Schedule.... Schedule.................. ........................... .......................... .......................... .......................... .......................... ................... ...... 303 Annual Maintenanc Maintenance e Schedule Schedule with The Transformer Transformer De-energized De-energized ......................... ............ ......................... ............ 304 Maintenance of Components .......................... ..................................................... ..................................................... ..................................... ........... 305 6.2.2.1 Transformerr liquid and insulation Transforme insulation .......................... ............. ........................... ........................... .......................... .......................... ....................... .......... 305 6.2.2.2 Bushings and joints...................... joints......... .......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 306 6.2.2.3 Off-load tap changer changer (DETC)..................... (DETC)........ .......................... .......................... .......................... ........................... ........................... ..................... ........ 306 6.2.2.4 On-loadd tap change On-loa changerr ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... .................... ......... 307 6.2.2.5 Motor drive unit................... unit...... ........................... ........................... .......................... .......................... .......................... .......................... ........................... ................. ... 307 6.2.2.6 Oil filtering unit.................. unit..... .......................... ........................... ........................... .......................... .......................... .......................... .......................... ................... ...... 307 6.2.2.7 Coolers................................. Coolers.................... .......................... .......................... ........................... ........................... .......................... .......................... .......................... ............... .. 307 6.2.2.8 Liquid conservator conservator with with rubber rubber diaphrag diaphragm m (COPS) (COPS) ........................... ............. ........................... .......................... ....................... .......... 307 6.2.2.9 Gaskets................ Gaske ts........................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...........307 307 6.2.2.10 Surface protection................................. protection.................... .......................... .......................... .......................... ........................... ........................... ......................... ............ 308 6.2.2.10.1 Painted surfaces surfaces ........................... .............. .......................... .......................... .......................... .......................... ........................... ........................... ............... 308 6.2.2.10.2 Zinc coated coated surfaces surfaces ......................... ............ .......................... .......................... ........................... ........................... .......................... ....................... .......... 308 6.2.3 Investigation of Transformer Disturbances ................................................... ........................ .............................................. ................... 308 6.2.3.1 6.2.3.2 6.2.4 Internal Inspection .................................................... ......................... ..................................................... ..................................................... ............................. 312 6.2.4.1 6.2.4.2 6.2.4.3 6.2.5 6.2.6 6.2.7 Opening the Transformer Transformer ............. .......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 312 The Inspection............. Inspection........................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ............... .... 313 Electrica Ele ctricall Tests Tests ..................... ................................ ...................... ...................... ...................... ...................... ...................... ...................... ...................... ................. ...... 314 Maintenance of Bushings.................... Bushings.............................................. ..................................................... .................................................. ....................... 315 Maintenance and Service of OLTCs/LTCs ........................ ................................................... ............................................. .................. 317 General Quality Information for Various Types of LTCs.......... LTCs..................................... ......................................... .............. 318 6.2.7.1 6.2.7.2 7 Recording of disturbances............ disturbances......................... ........................... ........................... .......................... .......................... .......................... ..................... ........ 308 Fault localizations localizations advice for oil-immerse oil-immersed d transformers transformers............. .......................... .......................... .......................... ................ ... 309 North-American North-Amer icantice Practices............ Practice s......................... .......................... .......................... .......................... .......................... ............................. ....................... ....... 322 318 Europ European ean Practice Prac ...................... ........... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...................... ...........322 REPAIR, REFURBISHMENT REFURBISHMENT AND RETROFIT ......................... .................................................... .................................................. ....................... 324 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 PREPARATION PHASE ....................... .................................................. ..................................................... ..................................................... ................................ ..... 325 UNTANKING AND DISASSEMBLY OF ACTIVE PART .......................... ..................................................... ............................................. .................. 326 REPAIR OF THE TRANSFORMER ........................ .................................................. ..................................................... ............................................. .................. 327 ASSEMBLY AND TANKING OF THE ACTIVE PART ......................... .................................................... ................................................. ...................... 328 DRYING ......................... .................................................... ...................................................... ..................................................... ................................................. ....................... 328 FINAL ASSEMBLY .......................... ..................................................... ..................................................... ..................................................... .................................... ......... 329 HIGH VOLTAGE TESTING ........................ ................................................... ..................................................... ..................................................... ........................... 329 QUALITY PLAN ........................ .................................................. ..................................................... ...................................................... ........................................ ............. 330 FACILITIES FOR SITE REPAIR ........................... ...................................................... ..................................................... ............................................ .................. 330 7.9.1 Temporary Workshops................................................. Workshops...................... ..................................................... ................................................... ......................... 331 7.9.1.1 7.9.1.2 7.9.1.3 7.9.2  Steell Buildings.......................... Stee Buildings............ ........................... .......................... .......................... .......................... .......................... ........................... ......................... ........... 331 Large Tents Large Tents ...................... ................................. ...................... ...................... ...................... ...................... ...................... ...................... ...................... ..................... .......... 331 Foundation Foundat ion for a Temporary Temporary Workshop......................... Workshop............ .......................... ........................... ........................... .......................... ............... .. 332 Facilities for Heavy Lifting .................................................. ........................ ..................................................... ............................................. .................. 332 xiii 7.9.3 7.9.4 7.9.5 7.9.6 8 Moisture control .................................................. ........................ ..................................................... ...................................................... ................................. ...... 332 Oil processing...................... processing................................................ ..................................................... ..................................................... ...................................... ............ 333 Drying equipment ................................................... ........................ ...................................................... ..................................................... ............................. ... 333 High voltage test equipment................................ equipment.......................................................... ..................................................... .................................. ....... 333 ENVIRONMENTAL ENVIRONMEN TAL ASPECTS .......................... ..................................................... ...................................................... .............................................. ................... 334 8.1 CONTAMINATION OF OILS WITH PCB (POLYCHLORINATED BIPHENYLS) ................ ....................... ............... ................ ........334 334 8.1.1 General ........................... ..................................................... ..................................................... ...................................................... .......................................... ............... 334 8.1.2 8.1.3 8.1.4 Dehalogenation Processes Using Using Sodium and Lithium Lithium Derivatives.................................. 335 Dehalogenation Processes Processes Using Pol Polyethyleneglycol yethyleneglycol and Potassium Hydroxide Hydroxide ............. 335 Dehalogenation in in Continuous Mo Mode de by Closed Circuit Process...................................... Process..................... ................. 335 8.2 ELECTROMAGNETIC COMPATIBILITY (EMC (EMC)) ............... ...................... ............... ................ ................ ............... ............... ................ ................ ........335 335 8.2.1 8.2.2 8.3 Introduction...................................... ..................................................... Introduction................................................................ ..................................................... .......................... 335 Methods to Reduce EMF Levels in Existing Substations Substations ......................... ................................................. ........................ 336 AUDIBLE NOISE .......................... ..................................................... ...................................................... ..................................................... ..................................... ........... 336 8.3.1 8.3.2 Introduction...................................... ..................................................... Introduction................................................................. .................................................... .......................... 336 Background .......................... .................................................... ..................................................... ...................................................... ..................................... .......... 337 8.3.2.1 8.3.2.2 8.3.3 8.3.4 8.3.5 8.4 Criteria for Community Noise Levels ................................................... ........................ ..................................................... ............................ .. 337 Requirements ....................... ................................................. ..................................................... ...................................................... ..................................... .......... 338 Methods of Substation Noise Control ........................ .................................................. ..................................................... ............................. 338 RELEASE OF INSULATING OIL.......................... .................................................... ..................................................... .............................................. ................... 340 8.4.1 8.4.2 8.4.3 9 Characteristics Characte ristics of Transformer Transformer Noise......................... Noise............ .......................... .......................... .......................... ........................... ................... ..... 337 Propagation Propaga tion of Sound Sound ...................... ................................. ...................... ...................... ...................... ....................... ....................... ...................... ................ ..... 337 Introduction...................................... ...................................................... Introduction................................................................. .................................................... ......................... 340 Use of Synthetic Ester .................................................. ....................... ...................................................... .................................................. ....................... 340 Use of Natural Ester ....... .................................. ...................................................... ..................................................... ......................................... ............... 341 ECONOMICS OF TRANSFORMER ASSET MANAGEMEN MANAGEMENT T ......................... .................................................... ............................. 342 9.1 FAILURE STATISTICS FOR POWER TRANSFORMERS .......................... ..................................................... ......................................... .............. 342 9.1.1 9.1.2 9.2 CIGRE Survey Survey of Failu Failures res in Large Po Power wer Transformers Transformers ......................... ................................................ ....................... 342 Canadian Electricity Electricity Association Association Forced Outage Report ..................... ................................................ ............................. 344 ECONOMICS OF TRANSFORMER MANAGEMENT FOR FLEETS AND SPECIFIC UNITS ....... ............... ................ ............ .... 347 9.2.1 9.2.2 9.2.3 9.2.4 9.2.5 10 Introduction....................................... ..................................................... Introduction................................................................. .................................................... ......................... 347 General Concept for Economics Economics of Transformer Transformer Management......................................... 348 Description of the Simulation Model .......................... ..................................................... ..................................................... ............................ 349 Case Study by a Utility.................................................. Utility........................ ..................................................... .................................................. ....................... 350 Conclusions........................................ Conclusions............. ...................................................... ..................................................... ................................................. ....................... 352 HEALTH HEALT H AND SAFETY ASPECTS / RECOMMENDATIONS RECOMMENDATIONS ..................................................... ........................... .......................... 353 10.1 10.2 10.3 10.4 10.5 10.6 10.7 PREAMBLE ......................... ................................................... ..................................................... ...................................................... ............................................. .................. 353 INTRODUCTION ....................... .................................................. ...................................................... ..................................................... ........................................ .............. 353 SCOPE .......................... ..................................................... ...................................................... ..................................................... ................................................. ....................... 353 DEFINITIONS ....................... .................................................. ..................................................... ..................................................... ............................................. .................. 354 SAFETY MANAGEMENT .......................... .................................................... ..................................................... ...................................................... ........................... 355 DOCUMENTATION ......................... .................................................... ..................................................... ..................................................... .................................... ......... 355 ELECTRICAL SAFETY RULES ....................... .................................................. ...................................................... ................................................. ...................... 356 10.7.1 10.7.2 10.7.3 10.7.4 10.7.5 10.7.6 10.7.7 10.8 W ORK AT HEIGHT: ADDITIONAL SAFETY EQUIPMENT FOR POWER TRANSFORMERS . ........ ................ .............. ...... 362 10.8.1 10.8.2 xiv General Rules .................................................. ....................... ...................................................... ..................................................... ............................... ..... 356 Communication and Control Rules................... Rules.............................................. ...................................................... ................................ ..... 356 Rules for working on dead E Electrical lectrical Equi Equipment.............................. pment......................................................... ............................. 357 Rules for working on or or very near live Electrical Electrical Equipment................... Equipment......................................... ...................... 361 Switching........................................................ Switching............................. ...................................................... ..................................................... ................................. ....... 361 Work on or very near live conductors ......................... .................................................... ................................................. ...................... 361 Testing and Commissioning.................................. Commissioning............................................................. ..................................................... ............................ 362 “NO-RISK SYSTEM”................................. SYSTEM”............................................................ ..................................................... ....................................... ............. 362 “Fall Arrest Towers and Base Base Pla Plates”........ tes”................................... ...................................................... ....................................... ............ 365  10.9 APPENDICES ......................... .................................................... ...................................................... ..................................................... .......................................... ................ 365 10.9.1 10.9.2 proximity 10.9.3 10.9.4 10.9.5 10.9.6 Appendix 1 Appendix 2 368 Appendix 3 Appendix 4 Appendix 5 Appendix 6 - Minimum Mini mum working clearance............................. clearance.. ...................................................... ...................................... ........... 366 Minimum design clearance Minimum clearances s where power lines lines cross or are in close 10.9.7 10.9.8 10.9.9 Appendix 7 - Sampl Sample e Safety Check Sheet................ Sheet........................................... ................................................... ........................ 374 Appendix 8 - Sample Sample Safety Permit Permit to work. .......................... .................................................... ..................................... ........... 376 Appendix 9 - Sample Sample Energized Electrical Electrical Work Permit...................... Permit............................................... ......................... 378 Minimum Mini mum separation across point point of disconnection iin n air......................... 369 Principles of Risk Assessment.......................... Principles Assessment..................................................... ...................................... ........... 370 Example of of Sample Risk Assessment Assessment Sheet. ......................................... ......................... ................ 371 Electrical Job Haz Electrical Hazard ard Analysis Sheet. ........................... .................................................... ......................... 372 REFERENCES............................................................... REFERENCES..................................... ..................................................... ...................................................... .......................................... ............... 379 INDEX................................ INDEX..... ..................................................... ..................................................... ...................................................... ..................................................... ................................. ....... 390 ABB TRANSFORMERS SERV SERVICE ICE GENERAL B BROCHU ROCHURES RES ......................... .................................................... .................................. ....... 395 ABB TRANSFORMERS SERV SERVICE ICE PRODUC PRODUCT T LEAFL ETS....................................... ETS................................................................ ......................... 405 ABB TRES NORTH AMERICA SERVICE BROCHUR BROCHURES............ ES....................................... ..................................................... ............................. ... 423 CONTACT LIST FOR MAIN ABB SERVICE CENTER CENTERS........... S...................................... ..................................................... ................................ ...... 454  xv 1 TRANSFORMER TRANSFORME R DESIGN CONSIDERATIONS CONSIDERATIONS [ 1] 1.1 CONFIGURATION There arephysical two basic configurations for the power form and shell form. The principal difference between twotransformers: constructionscore is related to the geometry of the magnetic circuit and the position, alignment, and types of the windings employed for each design. Fundamentally, for the shell form designs, the magnetic circuit forms a shell around a major portion of the windings. Three phase shell form designs use 4 and 7 limb li mb cores with the usual horizontal orientation of the core limbs. Shell form 7 limb cores are used on newer shell form designs due to lower weight, manufacturing simplicity, and lower core loss. Single phase shell form transformers use 3 limb cores. In the shell form design, the windings are interleaved; that is, the high-voltage and low-voltage windings are subdivided into groups with the groups adjacent to each other in the axial (horizontal) direction. Each group is assembled a ssembled using interconnected rectangular rectangular pancake coils. In core form designs the magnetic circuit forms a core through the windings. Three phase core form transformers are usually constructed with a three limb core that has the center limbs vertically oriented with the top and bottom yokes for main flux return paths oriented horizontally. When shipping height becomes a limiting design factor, a five limb core may be used to keep the shipping height within the shipping limitation. This configuration enables the yoke depth to be reduced by providing a return flux path external to the wound limbs. The only other occasion in which a three-phase, five limb core might be necessary is when it is required to provide a value of zero sequence impedance of similar magnitude to the positive sequence impedance. The core form single phase geometry uses 2, 3, or 4 limb cores. Generally, the core form design uses several types of circular coils (layer, helical, disc) that are concentric with each e ach other and the vertical core limb. For power transformers, there will be design requirements where one form of construction will have an advantage over the other. The major parametric elements of the comparison are MVA size, voltage class, impedance requirements, and loss performance characteristics. ABB has the flexibility in design knowledge and manufacturing capability to produce either construction. 1.2 MECHANICAL MECHANICAL CONSI CONSIDERATION DERATION The mechanical design of a transformer involves the analysis and determination of the expected operational forces, the structural stress analysis of the insulation system and support elements, and the proper choice of materials. A transformer must be strong enough to withstand the mechanical stresses imposed by system-related events such as short circuits. generated The mechanical stressesshort developed normal areAlso, low, the but the stresses by a system circuit during event can be operation quite large.  17 magnitude of these stresses increase with the size siz e and complexity of the transformer. The majority of the mechanical stresses must be taken by the insulation system, which is primarily composed of cellulose-based materials. These materials are weakest in bending and tension. It is therefore best to apply these materials in compression. Also, to keep the total forces as low as possible, the design of the windings should be made using the best arrangement and overall geometry of the t he individual windings. 1.3 THERMAL CONSIDERATIONS Temperature is one of the most important factors affecting transformer life. As the temperature of the insulation increases, the insulation life decreases. The transformer must be designed to operate within the guaranteed temperature parameters and the prescribed standard allowances to ensure long transformer life. In an oil-filled transformer, the insulating oil is used to conduct the heat away from the windings and the magnetic core. To perform this function, the oil must circulate through the winding assembly and usually through externally applied cooling apparatus. For thermosiphon oil flow (natural oil flow), oil circulation is created when the weight of the column of oil in the cooling equipment is greater than the weight of the column of oil in the core and coil assembly. Also, the center of cooling must be above the center of heating. This distance has a direct affect on the top-to-bottom temperature difference – the larger the distance between the center of cooling and the center of heating, the larger the oil flow and the lower the top-to-bottom temperature difference. This configuration is defined in the standards as ONAN (oil natural, air natural) – the old nomenclature was OA). Additional transformer capacity can be created by adding auxiliary cooling equipment, such as fans. Fans increase the airflow over the external cooling equipment without changing the mode of internal oil flow. Fans can be added in one or two stages. Using the ONAN rating as the base or 100 % rating, a rating of 133 % can be attained by adding one stage of fans. Additional fans (2nd stage), usually equal in number to the first stage of fans, can be added to obtain a rating of 167 %. The energizing of the fan stages is normally controlled by temperature-actuated contacts provided in the winding temperature device. The current industry designations for fans-only auxiliary cooling with natural oil flow are defined in the standards as:  ONAN/ONAF ONAN/O NAF (oil natural, air natural/oil natural, air forced – 100 %/133 %) – the old designation was OA/FA  ONAN/ONAF/ONAF – (oil (oil natural, natural, air nat natural/oil ural/oil fo forced, rced, air forced/ ooilil forced, air forced – 100 %/133 %/167 %) – the old designation was OA/FA/FA For larger transformer ratings, some design configurations may require the addition of oil circulating pumps to meet the required temperature rise guarantees. With the addition of oil circulating pumps, the top-to-bottom oil temperature difference attained by the forced oil flow is usually in the order of single digits. The increased oil flow is usually accompanied by internal means to direct the oil flow through the windings; this is generally known as directed flow. When W hen two stages of auxiliary cooling are employed, the equipment is generally divided equally among the two stages. The T he designation for cooling 18  with auxiliary fans and pumps is defined in the standards as (past nomenclature shown in parentheses):  ONAN/ODAF (oil natura natural,l, air na natural/oil tural/oil directed, air forced – 100 %/133 %) – the old designation was OA/FOA.  ONAN/ODAF/ODAF ONAN/ODA F/ODAF (oil natural, air natural/oil directed, air forced/ oil directed, air forced – 100 %/133 %/167 %) – the old designat designation ion was OA/FOA/FOA. Other configurations for the use of auxiliary fans and pumps are sometimes applied, such as using fans only for the first rating increase and energizing all of the pumps for the second stage of cooling. Additionally, transformers can be designed with a single rating that uses auxiliary cooling equipment consisting of oil circulating pumps with an associated oil-to-air heat exchanger or forced oil with a water-cooled heat exchanger. exchanger. 1.4 DIELECTRIC CONSIDERATIONS The transformer insulation system must be designed to withstand the normal operating voltages as well assurges. over-voltages during consideration lightning events, system short circuits, and system switching In addition, must be given to produce transformers that withstand these voltages with all elements operating below the corona onset voltage. A transformer is a simple inductance when considering low frequency operating voltages and overvoltages. However, to an impulse voltage, the transformer presents a complex combination of inductances and capacitances. Initially, when an impulse voltage impinges upon a transformer winding, the initial ini tial distribution is determined by the winding coil-to-coil and coil-to-ground capacitances. The final voltage distribution is ultimately distributed in line with the winding coil inductances. For many transformers, the initial distribution of an impulse voltage is less than perfect. This results in increased stress at the line end of the winding. There are several solutions for these increased stresses. For the lower voltage ratings, the usual method is to accept the higher stress and insulate accordingly. For higher voltage ratings, there are a number of winding arrangements, conductor interleaving schemes, and electrostatic shielding methodologies that are employed to reduce the voltage stresses produced at the line end of the windin winding. g. 1.5 CONSTRUCTION TYPES 1.5.1 1.5.1.1 SHELL FORM DESIGN FEATURES The ABB Shell Form-Form Fit design features a rectangular shaped coil system made up of a series of inter-connected pancake coils. The coil and insulation assembly is mounted vertically tank bottom The coreshell is positioned around the outside ofinthethe winding and actssection. as a protective around thehorizontally coil. The upper section  19 of the tank fits snugly over the core and coils to form a unit assembly with the mechanical support completely outside the winding (see Figure 1-1). The heat generated by the core and coils is dissipated by the circulation of the oil. The oil flow from the bottom to the top of the tank is supported by the temperature differential or thermal head during self-cooled operation. The addition of pumps and fans for forced cooling will increase the flow of oil through the core and coils and the flow of air the heat With either mode cooling, oil passes through a heatthrough exchanger whereexchanger. it cools prior to reentering theoftank at the the bottom. The shell form insulation system consists of high dielectric strength pressboard sheets and precisely located oil spaces designed to control voltage stress concentration. Figur e 1-1: 1-1: Parti Parti al Cutaway of a Shell Form Transform er 1.5.1.2 MECHANICAL STRENGTH The coils in a shell form design are large surface area pancake coils, and they are assembled into winding groups with their faces adjacent to flat pressboard washers which contain a planned pattern of spacer blocks cemented to the surface. The spacer blocks provide a uniform support system to the turns and strands of the individual coils. The complete phase is installed vertically in the tank bottom, and the core is stacked around it. The upper section of the tank is fitted snugly over the core and shimmed with vertical wooden slits spaced around the periphery of the core. The total force between transformer winding groups varies as the square of the ampere turns per group. If the current during fault conditions is ten times the normal load current, the short circuit force will be one hundred times the normal load winding forces. As transformers get larger, the ampere turns per winding group are reduced in a shell form design by increasing the number of winding groups, or high-low spaces; thus controlling the magnitude of the total force. Increasing the number of high-low spaces 20  does not increase the length of the average mean turn in a shell form winding; therefore, it can be done economically. The forces within successive winding groups in a shell form transformer are in opposite directions. As they traverse the winding, the forces tend to cancel each other out. As a result, the net total restraining force that must be applied externa externall to the windings is only the force corresponding to a single pair of winding groups (see Figure 1-2). Figure 1-2: 1-2: Section Through a She Shell ll Form Winding Group with a High-Low Coil Configuration (arrows (arrows illustrate mechanical forces) In addition to the control of total force magnitude available in a shell form design, the unit stresses on the winding insulation structures are kept at a low level. The major winding force is perpendi perpendicular cular to the face of the pan pancake cake coils, and each coil is supported by spacer blocks on its adjacent pressboard washers. Between spacers, the windings act as uniformly loaded beams, and the total winding force is transmitted through the group by compression of the spacer blocks. The shell form design uses large pancake coils; thus a large number of spacer blocks are available to absorb the total force, and the unit stresses in the pressboard are relatively relatively low. The totalhigh-low force magnitude in a shellEven formwith design be reduced considerably witha multiple coil arrangements. this can advantage it is essential to have rugged mechanical structure to withstand the ultimate forces encountered during thrufault conditions. In the ABB Shell Form-Form Fit design the major components of force are taken by well-braced structures completely outside the winding. The close-fitting Form Fit tank and the core assembly combine to restrain the total forces acting on the winding. For the portions of the winding that are above and below the core, heavy steel structural members welded to the tank provide the restraint for the forces. The bracing structures are completely outside the winding and can be reinforced without any compromises in winding design. The ABB Shell Form-Form Fit design offers a combination of controlled maximum stress, inherent stability, and high mechanical strength to withstand the forces produced by system thru-faults. The use of the Form Fit tank as the major structural support makes  21 up to a 20 % reduction in total weight and as much as 40 % reduction in oil volume in ABB shell form large power transformers possible (see Figure 1-3). Figure 1-3: Partial Cutaway of a Shell Form Transformer Showing Support Structure for Core and Coils 1.5.1.3 T HERMAL CAPA BIL ITY A transformer is a very efficient piece of apparatus; however, energy is generated by losses in the core and coils during normal operation. This energy is in the form of heat, which increases approximately as the square of the load current and must be dissipated to prevent deterioration of the insulation system. The oil in the transformer serves as a medium for transmitting this energy from the core and coils to a heat exchanger, where it is dispersed to the atmosphere. The HV and LV coils in an ABB Shell Form Transformer are arranged vertically in the tank and pressboard insulation washers containing spacer blocks in a pre-designed pattern are located on either side of each coil. The spacer block pattern provides ducts on both sides of the conductor through wh which ich the oil travels from fr om the bottom to the top of the tank. The core in a shell form transformer is a stack of narrow-width steel punchings. Oil flowing on both sides of th thee core adequa adequately tely cools this area; th therefore, erefore, oil ducts duct s withi withinn the magnetic circuit are not necessary. The oil flow in the transformer tank during self-cooled operation is supported by the temperature differential between the oil at the top and bottom of the tank. This temperature differential, or thermal head, is approximately 12 °C for a shell form transformer transform er (see Figure 1-4). 22  Figure 1-4: Partial Cutaway of a Shell Form Transformer Illustrating OA (Self-Cooled) Cooling Act io n As the load on a transformer increases, the energy generated by the losses in the coil system will increase in proportion proportion to the square of the increase in load. Forced cooling is applied to dissipate this additional energy and allow the transformer to operate at the increased load and within temperature guarantees. ABB applies both pumps and fans for forced cooled ratings on shell form transformers. The pumps augment the circulation of oil that exists due to the thermal head, and since the coils are positioned vertically, no barriers are necessary to direct the oil flow. The additional oil flow provided by the pumps virtually eliminates the oil temperature differential in the transformer and reduces the winding hottest spot temperature as much as 10°C. The fans direct the airflow over the heat exchanger at a high velocity, thus improving energy transfer to the atmosphere. The addition of fans alone to a typical radiator bank will significantly increase its energy dissipation; fans used in conjunction with pumps to provide forced air and forced oil cooling will further increase the cooling capability of the same radiator bank. The forced cooling can be operated continuously for heavily loaded transformers, or it can be actuated in stages as the load increases. Forced oil-forced air cooling is the most efficient method of increasing the capacity of a transformer. This method of cooling coupled with the inherent thermal characteristics of the ABB Shell Form Transformer design offer the highest thermal capability in large power transformers.  23 Figure 1-5: Partial Cutaway of a Shell Form Transformer Illustrating FOA (Forced-Cooled) Cooling Act io n 1.5.1.4 DIELECTRIC CHARACTERISTICS The effect of overvoltage and system surge conditions on the windings of a transformer is determined by the characteristics of the particular coil and insulation system. As this voltage surge enters the transformer winding, the initial voltage distribution will be directly determined by the capacitance networks of the coil and winding system (see Figure 1-6). Oscillations may develop as the surge progresses through the coil system, which for certain designs may be amplified by the natural oscillation in these systems to a value greater than the initial crest. This overvoltage condition may concentrate at some point in the winding, such as the first several turns at the line end of the winding or around a tap section, and stress the turn-to-turn insulation in these areas. Figure 1-6: Equivalent Inductance-Capacitance Network of a Shell Form Winding Section The coil assembly of an ABB Shell Form Transformer consists of a relatively few “pancake” coils with a broad cross-sectional area and a narrow coil edge (see Figure 1-6). Since the capacitances between coilsarea andoffrom coiland to the ground proportional, respective to the cross-sectional the coil area are of itsdirectly edge, 24  the shell form coil system has a high coil-to-coil and a low coil-to-ground capacitance. When the ratio of coil-to-coil capacitance to the coil-to-ground capacitance is high, as it is in a shell form transformer design, the voltage distribution with rapidly rising voltage surges is more nearly uniform. Figure 1-7: Shell Form Transformer - Cross-Section of Line End Coils within the Core Iron The turn-to-turn voltage stresses due to the initial application of the surges are thereby reduced in the shell form design insulation system, and the succeeding oscillations developed in the winding are also reduced. The large inherent capacitance of the shell form design causes the natural period of the winding oscillation to be relatively long, thus allowing the voltage surges to decay to a low value before the winding oscillations can develop to a significant magnitude. The insulation structures between coils, between coils and core, and between winding groups are made of high dielectric strength oil-impregnated sheets. Oil spaces are provided with a precise relationship to the coil and pressboard structures to control voltage stress concentrations. Specially formed insulation pieces are used over the coil edge where the voltage stress is highest. This insulation is stressed in puncture rather than creep for additional strength.  25 The pancake coils in a shell form transformer are arranged to termin terminate ate at the top of the transformer where line end and tap connections can be made with a short lead. The magnitude of circulating currents induced by high fields is minimized in an ABB Shell Form Transformer because of the short lead length and unique subdivided lead construction. The inherent design characteristics of ABB Shell Form Transformers assure their reliable operation. The performance of ABB Shell Form Transformers is verified by exclusive modeling techniques prior to manufacture. 1.5.2 1.5.2.1 CORE FORM DESIGN F EATURES Core Form construction (see Figure 1-8) utilizes a series of cylindrical windings stacked on a steel core. The core is at ground potential; therefore, the lowest voltage winding is located adjacent to it, and the higher voltage windings are separated from the core in order o rder of voltage. vo ltage. The highest voltage voltage winding is on the outside of the asse assembly. mbly. The windings are supported laterally by laminated winding tubes and properly selected conductor tension. Vertical support for the coils is provided by a plate type pressure ring and lock plate assembly restrained by channel end frames. 26  Figure 1-8: Parti Parti al Cutaway of a Core Form Transfo rmer Cooling of the core and coilducts assembly circulation through ducts between the coils and also within is theaccomplished core. The oil by flowoilfrom the bottom to the top of the tank is supported by the thermal head or temperature differential from the bottom to the top of the transformer. The oil passes through a heat exchanger, where it cools before reentering the transformer at the bottom. The individual turns in the coil are insulated with high-density cellulose tape. Oil spaces are provided between the disc sections of the coil with laminated spacer blocks. The oil spaces between coils are maintained by vertical spacer rods. 1.5.2.2 MECHANICAL STRENGTH The coil system of a core form transformer consists of cylindrical type windings placed on a vertical steel core. The forces created by thru-fault currents tend to separate these windings. The forces on the outer (or HV) winding push the winding out and place the  27 conductors in tension. The force on the inner (or LV) winding acts to compress the winding, windin g, and the stress is transmitted to the winding tube (see Figure 1-9). Figure 1-9: 1-9: Section Through a Core Form Form Winding Group with an Expanded View of One Coil and Spacers Space rs (arrows illustrate mechanical forc es) If the electrical centers of the coils are displaced by taps or an unequal winding arrangement, a vertical force is introduced, which tends to telescope the windings. The vertical forces can exceed 800,000 pounds per phase during the thru-fault conditions. The forces in a core form transformer increase with transformer size; therefore, the mechanical properties of winding tubes, vertical spacers, and radial spacers are critical to the mechanical strength of the design. The The tensile strength strength of the HV winding conductor is is also a very important consideration. The vertical forces that act to telescope the windings are transmitted through radial spacers to the pressure rings and then to the core end frames at the end of the winding. These forces are transmitted through the winding across the narrow face of the conductor, resulting in a high per-unit stress on the conductor and spacers. The vertical forces tend to compress the spacer material, and over a period of time will cause looseness between the disc sections of the coils. Preventing this will require some means provided to maintain compression on the winding. On ABB Core Form designs, the horizontal and vertical forces occurring during thrufault conditions are calculated during the design of a transformer, and the support structure is designed accordingly. The coils are pre-stressed at the time of assembly to maintain the vertical dimensional tolerances and the tightness of the coils. 28  Figur e 1-10 1-10:: Partial Cutaway Cutaway of a Core Form Transformer Show ing th e S Supp upp ort Stru ctu re for Core and Coils 1.5.2.3 T HERMAL CAPA BIL ITY The energy generated by the losses in the core and coil system of a core form transformer is transmitted to the heat exchanger by the circulation of oil through ducts between the coils and ducts within the core. The oil flow is supported by the thermal head in the tank. The HV winding in a core form transformer is made up of a series of disc sections positioned horizontally on the winding tube. The oil must travel through both horizontal and vertical ducts to properly cool the conductors. Typically, the LV coil construction helical insulated or transpose and is cooledisbya oil flow winding through that ductsuses on either siderectangular of the coil. The core has conductors a relatively large cross-sectional area and is located inside the coil assembly where heat is concentrated; therefore, ducts must be provided within the core to allow oil circulation for cooling. The plate type pressure rings, which are located at each end of the coil assembly, tend to block the flow of oil through the coil assembly; therefore, ducts and barriers must be provided to direct the oil flow to the inner windings. Forced cooling is applied to core form design by adding high velocity fans to the heat exchanges to increase energy dissipation. The oil circulation is supported by the thermal head in the transformer tank (see Figure 1-11). If pumps are added for forced oil circulation, baffles must be provided to direct the oil flow, otherwise the greater part of the oil volume will move upward in the area between the HV winding and the tank wall. The barriers used to direct forced oil flow will impede  29 the flow during self-cooled operation. Transformer designs with continuous forced cooling, such as generator step-up units, can advantageously utilize the baffled arrangement. (a) (b) Figure 1-11: P Partial artial Cutaway o f a Core Form Transfo rmer Illu stratin g (a) O ONAN NAN ((Se Self-Cool lf-Cool ed) Cooling Action; and (b) OFAF OFAF ((Forced-C Forced-Cooled) ooled) Cooling Action ABB uses a patented bypass valve on the core form design, which allows the proper thermosiphon action to function during self-cooled operation. It will also properly direct forced oil flow so that pumps can be used to an advantage during forced-cooled operation. 1.5.2.4 DIELECTRIC CHARACTERISTICS Overvoltage and system surge conditions can cause severe stresses on the insulation system of core form transformers if the coil system is not arranged to distribute the voltage surge uniformly across the winding. The initial distribution of a voltage surge is determined by the ratio of the capacitance networks of the winding. Transformers designed for service with system ratings of 69 kV or below generally utilize a continuously wound HV coil made up of a column of disc sections separated by horizontal oil ducts. The ratio of coil-to-coil capacitance to coil-to-ground capacitance will be relatively low for this type of coil; however, additional insulation can be added in critical areas to withstand any voltage surges. Core form transformers used where system voltages are above 69 kV employ a variety of winding configurations to increase the coil-to-coil capacitance, thus improving the voltage surge distribution. HV coils for ABB Core Form Transformers in these voltage ratings are mechanically similar to the continuous wound coils, except the turns are interleaved to obtain a high series capacitance and a uniform voltage surge distribution. 30  Transformers rated above 100 MVA would require several conductors in parallel in order to carry the current in the HV coils, and the winding procedure would also be very complex. The taps in a core form winding are brought out near the center of the coil in order to not displace the electrical center of the coil. The tap leads are generally brought to a switching mechanism at the top of the core and coil assembly (see Figure 1-12). When underload taps are required, a small regulating winding is often employed. If tap sections are placed in the HV coil, thyrister devices are used between the coil sections to reduce the turn-to-turn voltage stresses. Figure 1-12: 1-12: Partial Cutaway of a Core Form Transform er Showing Coils, Insulatio n, and Tap Tap Leads  31 1.6 BUSHINGS BUSHINGS [2] Bushings may be classified cl assified by design as follow follows: s:  Condenser type: a) Oil-impregnated paper insulation, with interspersed conducting (or condenser) layers of oil-im oil-impregnated pregnated paper insulation continuous continuously ly wound with interleaved lined paper layers b) paperpaper insulation, with interspersed conducting (condenser c) Resin-bonded Resin-impregnated insulation. Bushing in which the major insulationlayers) is impregnated with a curable epoxy resin  Non-condenser Non-condenser type: a) Solid core or alternat alternatee layers of solid and liquid insulation b) Solid mass of homogeneous homogeneous insulating material (e.g. solid porcelain) c) Gas-filled Bushings may be further classified as either having a test tap, potential tap (also referred to as capacitance, voltage tap) or not. Condenser bushings facilitate electric stress control through the insertion of floating equalizer screens made of aluminium or semi-conducting materials. The condenser core in which the screens are located decreases the field gradient and distributes the field along the length of the insulator. The screens are located coaxially resulting in the optimal balance between external flashover and internal puncture strength. Bushings, as with other electrical equipment, are bound by industry standards, which vary between international, regional and national standards for the electrical and mechanical performance of bushings. The international IEC standard has a broad global acceptance but it cannot address specific regional issues. For this reason regional standards deal with application issues such as atmospheric and seismic conditions or in some cases the interchangeab interchangeability ility of products among among different manufactur manufacturers. ers. The rest of this section covers general information for bushing designed under ANSI/IEEE standards and will focus mainly on condenser type bushings. Similar design criteria are used under IEC standards. Parts of the section related to bushings are excerpts from the ABB Instruction Manual [3] 1.6.1 DESIGN AND CONSTRUCTION OF CAPACITANCES IN CONDENSER B USHINGS COMPLYING WITH THE IEEE STANDARDS [4] ABB condenser bushings (e.g. Type “O Plus C”, Type AB) are designed for transforme transformerr and oil-filled circuit breaker applications. These bushings meet all applicable dimensional requirements of the IEEE Standard C57.19.01 and meet or exceed all applicable electrical and mechanical requirements of the IEEE Standard C57.19.00. They are also manufactured to meet the E.E.M.A.C. Standard. 32  A condenser bushing is essentially a series of concentric capacitors between between the center conductor and the ground sleeve or mounting flange. As per the IEEE Standards C57.19.00 and C57.19.01, condenser bushings rated 115 kV and above are provided with wit h C1 (main) and C2 (tap) capacitances. The C1 capacitance is formed by the main oil/paper insulation insulation between the central ccondu onductor ctor and the C1 layer/foil, which is inserted during the condenser winding process. The C2 capacitance is formed by the tap insulation between the C1 and the C2 layers. The C1 layer/foil is internally connected to the voltage tap stud whereas the C2 llayer/fo ayer/foilil is perma permanently nently connected to the grounded mounting flange. Under normal operating conditions, the C1 layer/foil is automatically grounded to the mounting flange with the help of the screw-in voltage tap cover that makes a connec connection tion between the tap stud and the mounting flange. The C2 insulation under normal operating condition is therefore shorted and not subjected to any voltage stress. When such a bushing is used in conjunction with a potential device, the voltage tap is connected to this device. Under this condition, the C1 and C2 capacitances are in series and perform like a voltage or potential potential divider. The voltage developed across the C2 capacitance is modified by the potent potential ial device and is used for operat operation ion of relays, and other instruments. Also, the voltage tap can be used for measuring the power factor and capacitance C1 anddischarge C2 insulation of the bushing. addition, this tap can be used for monitoring theofpartial during factory testsInand insulation leakage current (including partial discharge) during field service operation. For condenser bushings with potential taps, the C2 capacitance is much greater than the C1 capacitance and may be 10 times as much. Figure 1-13 shows the construction details of a typical condenser bushing with voltage rating 115kV and above.  33 C E N T E R C O N D U C T O R Figur e 1-13 1-13:: Design Details of a Typical Condens er Bushi ng, 115 115kV kV and Above Condenser bushings rated 69 kV and below are provided with C1 capacitance as per the IEEE Standards. This cap capacitance, acitance, which is conside considered red the main capacitance, is formed by the oil/paper insulation between the central conductor and the C1 layer/foil, which is inserted during the condenser winding process. The C1 layer/foil is internally internally connected to the the test ttap. ap. These bushin bushings gs have an inherent C2 capacitance, which is formed by the insulation between the C1 layer and the mounting flange. This insulation consists of a few layers of paper with adhesive, an oil gap betweenoperating the condenser corethe and mounting flange, andgrounded the tap insulator. Under normal conditions, C1the layer/foil is automatically to the mounting flange with the help of the screw-in test tap cover that makes a connection between the test tap spring and the flange. The C 2 insulation under normal operating conditions is therefore shorted and not subjected to any voltage stress. The test tap is used for measuring the power factor and capacitance of C1 and C2 insulation of the bushing. In addition, this tap is sometimes used for monitoring partial discharges during factory tests and insulation leakage current (including partial discharge) during field service operation. For condenser bushings with power factor taps, the C2 capacitance is typically of the same order as the C1 capacitance. See Figure 1-14 for condenser design and test tap details. 34  Voltage Equalizers Oil Impregnated Paper C1 Layer Foil C E N T E R C O N D U C T O R Test Tap Mounting Flange (Grounded) C1 C2 Figure 1-14: 1-14: Design Details Details o f a Typic Typic al Condenser Bush ing s, 69 kV And Below For both constructions the condenser is housed in a sealed cavity formed by the upper and lower porcelain insulators, the high-strength, one-piece flange, and the metal or glass expansion domes. This cavity along with the condenser is evacuated and then filled with highly processed transformer oil for a very low moisture content and low bushing power factor. This low moisture content and low power factor is maintained throughout the life of the bushing by permanently sealing the bushing cavity. Springloaded center clamping hardware is used to apply sufficient clamping pressure to seal the bushing cavity during manufacturing. The upper and lower insulators, mounting flange, extension, spring assembly, sightand bowl, lower support, clamping nut form anflange oil-tight shell to contain the condenser insulating oil. Theand sealing between components is accomplished with oil-resistant “O-rings” in grooves and/or oil-resistant flat fiber reinforced gaskets. This seal is never broken. A dehydrated nitrogen gas cushion above the oil allows thermal expansion of the oil in the sealed cavity. The oil level in the bushing can be monitored by visual inspection of the sight bowl. The mounting flange and flange extension are high-strength, corrosion-resistant aluminum. The lower support is designed to accept a variety of optional terminating devices, such as standard threaded studs, NEMA blades, or draw rod system. The upper insulator is one-piece, high-quality porcelain with sheds designed for maximum performance. ABB condenser bushings are designed to meet or exceed “Heavy Creep” requirements as described in IEEE Std C57.19.01-2000. Figure 1-15 shows a cutaway view of a 138kV type ABB condenser bushing.  35 Figur e 1-15 1-15:: Cutaway View of ABB Type AB Bushi ng 138 kV of Bus hing Ca Capacitan pacitan ces 1.6.2 B USHINGS VOLTAGE TAP ABB bushings ratedtap 115outlet kV and higher the (e.g. Type Oflange. Plus C) have a small housing containing a voltage just above mounting The terminal in the tap is grounded by means of a spring clip in the tap cover. This tap is connected to one of the inner foil electrodes of the condenser. In the factory, the voltage tap is tested at 20 kV, 50/60 HZ for 1 minute. Under normal operation, this tap is grounded. If the voltage tap is used in conjunct conjunction ion with a potential/m potential/monitoring onitoring device, the voltage between the tap and ground should be limited to 6 kV. While the purpose of the tap is to provide connection to a bushing potential device, it also provides a convenient means for making connections for measuring power factor and capacitance by the UST (Ungrounded Specimen Test) method. Many bushing users make it a practice to measure the UST power factor and capacitance at the time of installation. We endorse this practice, and it is discussed in more detail tap, under the heading of “Maintenance.” When a connection is measurement, to be made to the voltage either for use with a potential device or for power factor 36  open the housing by removing the tap cover (item 19 in Figure 1-16). Assemble the potential device connection or proceed with the power factor measurement. After the power factor measurement is completed and if there is no connection to a potential device, remove the test connection and close the housing by replacing the tap cover. Be certain the cover is on tight. If the voltage tap is used for a connection to a potential device, after the connection is assembled, remove the filler plug (Item 17, Figure 1-16) and fill the chamber with clean, dry transformer oil. Leave an expansion space of approximately one quarter of an inch at the top of the chamber when you fill it. Coat the threads on the filler plug with a suitable sealer and replace the plug in the filling hole. Be certain the plug is tight. Figure 1-16: Sectional View of Bushing  37 WARNING: DO NOT APPLY APPLY VOLTAGE VOLTAGE TO THE BUSHING BUSHING WITH THE VOLTAGE VOLTAGE TAP COVER COVER REMOVED, EXCEPT WHEN USING THE BUSHING WITH A POTENTIAL DEVICE OR WHEN MEASURING POWER FACTOR. IF THE TAP IS NOT GROUNDED, THE VOLTAGE MAY EXCEED THE INSULATION INSULAT ION DIELECTRIC STRENGTH, STRENGTH, RESULTING IN A FLASHOVER. THE VOLTAGE ON THE TAP MUST NOT EXCEED 5 kV WHEN MEASURING POWER FACTOR. FAILURE TO FOLLOW THESE GUIDELINES COULD RESULT IN SEVERE PERSONAL INJURY, DEATH, OR PROPERTY DAMAGE. 1.6.3 1.6.3.1 CONNECTIONS INTERNAL ELECTRICAL CONNECTIONS The method used in making connections between a bushing and the apparatus on which it is mounted will depend upon the type of connection used in the apparatus. 1.6.3.2 DRAW LEAD CONNECTED BUSHINGS Bushings with current ratings of 800 amperes are generally designed with a hollow conductor through which a flexible cable can be pulled. The cable is considered a component of the apparatus on which the bushing is mounted and is not supplied with the bushing. 1.6.3.3 BOTTOM CONNECTED B USHINGS Bushings rated 1,200 amperes and higher are designed to carry the current through the center conductor. A circuit breaker interrupter or transformer terminal may be connected to the lower support s upport of the bushing. 1.6.4 L IQUID L EVEL INDICATION The oil level in the bushing is adjusted in the factory to the normal level at approximately 25 °C. Unless there is subsequent mechanical damage to the bushing, which results in loss of oil, in theoilfiller should be occur satisfactory for the temperatures, life of the s, bushing. Since fluctuations levellevel will necessarily with changing temperature the column of oil in the bushing is topped with a compressible cushion of nitrogen gas to fill the gas space above the oil. The actual oil level can be seen on a bushing equip equipped ped with a sight glass or a prismatic oil level gage. As long as the oil level can be seen, the level is at a satisfactory height. When a low oil level is indicated, examine the bushing for possible loss of oil, which could result in eventual electrical failure. A low level exists when the pointer on a float type indicator is on “Low” or when the level has disappear disappeared ed below the sight glass or prismatic gage. WARNING: DO NOT OPERATE OR TEST A BUSHING WITH A LOW INTERNAL OIL LEVEL. THIS COULD RESULT IN SERIOUS DAMAGE TO THE BUSHING, APPARATUS ON WHICH THE BUSHING IS MOUNTED, AND/OR THE TESTING EQUIPMENT BEING 38  USED. OPERATION COULD RESULT IN SEVERE USED. SEVERE PERSONAL INJURY, INJ URY, DEATH, OR PROPERTY DAMAGE. 1.6.5 PAINTING The metal parts at the top end are painted for protection against the weather. Care should be used to prevent scratching these painted surfaces. If the metal becomes exposed, the area should be then wiped a commercial solvent and then wiped dry. The cleaned area should bewith coated with suitablesafety outdoor gray enamel paint.  39 1.7 ON-LOAD TAP CHANGERS [5] 1.7.1 INTRODUCTIONS There are some differences between tap-changers used under IEEE standards and tapchangers used under IEC standards. The main differences are listed in Table 1-1 . Table 1-1: IEC and IEEE Tap Changer Differences Standard IEC IEEE Designation OLTC LTC Diverter switches Arcing switch Selector switch Arcing tap switches Mainly resistor type Resistor Resistor and reactor type Tap Selection and Acing Control Methods Current Limiting Method The tap (regulation) winding in a load tap changing transformer is used to adjust the number of transformer winding turns, usually to keep a constant voltage on the secondary side of the transformer. If many electrical steps are required a plus/minus connection or a coarse/fine connection is used. A plus/minus connection enables the tapped winding to either add or subtract its voltage from the main winding. A coarse/fine connection enables a coarse winding to be added to the regulating winding. The switch that makes this connection is named change-over change-over selector. Figure 1-17: Different tap-changer connections. On-load tap-changers must also be able to switch between the different positions without interrupting the current flow. Different designed practices are used under IEC 40  and IEEE guidelines to achieve this smooth transition. The methods are outlined in the sections below. 1.7.2 1.7.2.1 NORTH-AMERICAN PRACTICES 1 GENERAL DESCRIPTION OF LTC LT CS The tap or regulation winding in a load tap changing transformer is used to adjust the number of transformer winding turns, usually in the secondary or low-voltage winding and hence the transformer ratio. A regulating winding is commonly a layer type. A reversing switch, located inside the LTC mechanism, enables the regulation winding to either add or subtract its voltage from the low-voltage winding. Most LTCs have 16 mechanical tap positions, generally described as 32 electrical steps (16 above neutral and 16 below). The usual range of regulation is ±10 % of the rated line voltage. Although LTCs are built with other numbers of steps and ranges of regulation, the 32step, ±10 %, tap changing under load equipment has become a standard for many types of transform transformers. ers. Voltage change must be provided smoothly and efficiently without interrupting the secondary current flow, up to and including full load at the maximum nameplate rating, plus any additional When changing tap positions, the LTC mechanism must “make before break”overload. to avoid opening the secondary circuit. This causes the taps to be connected together each time the LTC makes a voltage step. Electrically, this is a short circuit in which a circulating current flows. The method used to limit this circulating current defines the basic differences between the two types of LTC: reactance and resistance types. Both types use stationary and moving contacts. In some designs, the moving contacts are located on an arm or shaft in the center of the fixed contacts and move over the fixed contacts in a circular fashion. As the moving contacts make connection with each fixed contact, a tap change is made. 1.7.2.2 REACTANCE TYPE LTC LT CS Reactance a preventive auto with transformer, housedwinding in the main transformer type tankLTCs and use connected in series the mainusually low-voltage and regulation windings. The preventive auto transformer is always connected in the circuit and experiences circulating current each time a voltage step is made. The capacity of the preventive auto transformer must be equal to the top nameplate rating of the transformer multiplied by the step percentage of the LTC, plus sufficient capacity to account for the circulating current during operation operation in the bridged position. Location and construction of the preventive auto transformer can vary significantly between different manufacturers and in different applications. In most cases, it is located in the main transformer transform er tank, sometimes on top of the main coil and core assembly. However, if the 1 Portions of this section are reprinted with permission from Electrical World Magazine, June 1995, copyright by The McGraw-Hill Companies, Inc. with all rights r ights reserved. reserved. This reprin reprintt implies no endorsement, either tacit or expressed, of any company, product, service, or investment opportu opportunity. nity.  41 preventive auto transformer fails, the entire transformer must be taken out of service, and the main core and coil assembly may be contaminated with carbon and copper particles. A costly transformer repair may be the result. To reduce this possibility, the preventive auto transformer transformer can be located in a separate tank or compartment. Reactance type LTCs are designed to operate continuously in the bridged position, thus the need for the preventive autooftothe carry the full type load LTC current plusthe theinherent circulating current. However, a major shortcoming reactance is that inductance of the preventive auto transformer increases the arcing time as the fixed and moving contacts separate. Three different methods methods minimize the effect of this arcing and extend contact life for as long as possible between overhauls. 1.7.2.3 ARCING CONTROL METHODS 1.7.2.3 1.7. 2.3.1 .1 Arc ing Tap Switch The arcing tap switch has tandem moving contacts, known as wipe contacts, responsible for both breaking the arc and carrying the main current. Arcing takes place on both edges of the wipe contacts, while the center of the same contacts carries the load current during normal operation. operation. The wiping action of these contacts is designed to remove carbon buildup on the main contact and improve current carrying surface (see Figure 1-18). Because the tap change operation is performed under oil, and no other device is present to reduce contact c ontact wear and coking, the contamination of oil in this type of LTC mechanism is much more severe than any other arcing-in-oil mechanism. mechanism. Figure 1-18: Arcing Tap Switch Reactance LTC 1.7.2.3 1.7. 2.3.2 .2 Arc ing Switc h and Tap Selector The arcing switch-and-tap selector type has separate arcing and main current carrying contacts. Arcing occurs on transfer switches located on a separate shaft from the main current carrying contacts (see Figure 1-19). The two shafts are sequenced by a series of gears, which are precisely aligned so that all arcing occurs on the transfer switches and none on the main contacts. 42  Figur e 1-19: 1-19: Arcin g Switch -and-Ta -and-Tap p Selector Rea Reactance ctance LTC 1.7.2.3 1.7. 2.3.3 .3 Drive Mechanism for Reactance Type LTCs Reactance type LTC systems use direct-drive mechanisms. Direct-drive mechanisms on reactance type LTC mechanisms use highly specialized gearing-and-scroll or dualslope cams to control the operating speed of the contacts and switches. When driven by a motor, speed and positioning are controlled by gears and limit switches. Motor failure, loss of power or control problems can cause the operation to stop before the tap change is complete. The result is improper contact positioning, requiring immediate and corrective action to avoid failure. If the LTC is operated manually, movement must be fast and complete to limit contact arcing. In a vacuum diverter LTC, the tap-selector contacts, diverter switches, and vacuum bottles are connected by an extensive motor-driven gear train. Limit switches stop the motor when a proper continuous operating position has been reached. In the case of drive failure, it is possible for the mechanism to stop in an off-tap position so that only one-half of the preventive auto transformer is in the circuit to carry the circulatingtocurrent. Most manufacturers that, ifas thispossible occurs, or thethe mechanism must be returned a normal operating positionstate as soon transformer load must be reduced to one-half of the nameplate rating. This off-tap position can also occur in the arcing switch-and-ta s witch-and-tapp selector type of reactance LTC. Several users require that the preventive auto transformer be sized twice as large as the normal center-tapped auto transformer and an alarm be included to avoid damage from this condition. Manual operation of the vacuum diverter LTC, while energized, is not recommended. If a vacuum bottle failed during a manual tap change, there would be no way to stop the tap change from being completed, possibly damaging the transformer and injuring the operator. 1.7.2.4 VACUUM INTERRUPTER TYPE LT CS The vacuum interrupter-and-tap typearcing is a significant reactance LTC mechanisms. In selector effect, the current is improvement diverted fromover the other main  43 contacts into a vacuum bottle via two diverter switches. Because the arcing contacts are housed in the vacuum bottle, there is no arcing to contaminate the oil (see Figure 1-20). Minor arcing can occur in the switches that divert the current to the vacuum bottle. Concentric drive shafts house the main current carrying contacts, diverter switches, and vacuum bottles. These drive shafts operate in a precisely timed sequence so that changes in the tap selector contacts only occur when no current is flowing. The tap selector contacts last forcontact the lifewear. of the transform transformer, er, since they are not burdened with arcing and theusually associated Vacuum bottle switching eliminates multiple re-strikes and sustained arcing that occurs in other types of reactance LTCs. The vacuum interrupter-and-tap selector is generally good for 500,000 operations. This compares with 50,000 to 150,000 operations for the other two reactance type LTC mechanisms. However, the complicated mechanical interlocking and precise timing required is critical to proper operation. Figur e 1-20: 1-20: Vacuum Vacuum Interrup ter Rea Reactanc ctanc e Type LTC 1.7.2.5 RESISTANCE T YPE LTC S Resistance type LTCs place resistors in the circuit to limit the circulating current during the time thatand thereactance tap change is taking place. T The principal differencetype between betwnever een resistance type LTCs type mechanisms ishethat the resistance operates continuously in the bridged position. The high-speed resistor transition type LTC (used principally in the US) moves directly from one full-cycle position to the next, using the impedance of the resistor to limit circulating currents for less than 60 milliseconds. The rotating arm of the LTC mechanism carries both moving and arcing contacts, which are electrically separate. The moving contact carries the main current, while the arcing contacts carry the arcing current that occurs during a tap change (see Figure 1-21). Because of the absence of inductance in the circuit, the arc is extinguished on the first current/voltage current/volta ge zero. The high speed of the mechanism also ccontributes ontributes to the absence of both re-strike and extended arcing. Arcing is limited to five or six milliseconds, which is the average time to reach a current zero after contact separation. However, because the bridged position is not used for continuous operation, the high-speed resistor 44  transition LTC needs 17 fixed contacts and 16 regulator winding conductors to provide the electrical tap positions. There is a second type of resistance LTC known as the resistive diverter. This type is primarily used in Europe, where it is applied to the high-voltage transformer winding. The main contacts of this mechanism are usually housed in the main transformer tank, while the arcing contacts are housed in their own compartment. Regulating Winding Transition Resistors Moving Main Current Carrying Contact Figur e 1-21: 1-21: Resistanc e Type LTC 1.7.2.6 DRIVE MECHANISMS FOR RESISTANCE TYPE LT CS Resistance type LTC systems use stored-energy drive mechanisms. The high-speed resistive transition LTC mechanism uses the motor to charge a spring. The spring cannot release its energy until it is fully charged, at which point the tap change is made. Motor failure, loss of power, or control problems cannot leave the LTC mechanism in an undesirable contact position. positi on. 1.7.2.7 FAILUR E MECHANISMS FOR LTC LT CS From an analysis of failure statistics it is known that LTC failures can be grouped under the following systems:     Electrical connections Insulation system Control system Mechanical system The typical failure mechanisms under each group gr oup are discussed below. 1.7.2.7 1.7. 2.7.1 .1 Electri cal Connecti ons In an LTC, there are electrical connections that will not be opened during the lifetime of the unit. In addition, there are switching contacts that will be opened and closed on  45 a frequent basis. The contact surfaces of the switching contacts are typically covered with silver or an alloy of tungsten and copper. Because of the friction during the switching, small particles will rub off the contact and move around in the oil. If many particles come together, they are able to build a chain, which can create a short circuit across contacts. Furthermore, these particles change the electrical fields within the LTC and can cause partial discharges. As the contact material becom becomes es depleted, the underlying copper surface of the contact c ontact becomes exposed. The copper and silver can react with oxygen in the oil or bond with organic components that are present in some LTCs to form copper or silver oxides. These materials form stable films on the surface of the copper and silver contacts, resulting in an increase in resistance and in contact temperature. The increase in temperature tempera ture increases the deposition rate of the oxides and can lead to coking failures. Coke, a black carbon material, is a by-product of oil degradat degradation ion and is generated generated when hydrocarbon-based insulating oils are subjected to extreme heat and arcing. The presence of water contributes to the formation of the film as well as metal oxides on all surfaces. The coking process tends to compound in nature. A point source of heat begins the process. The resulting coke forms a carbon film resistor on the contact 2 surface, increasing matingthe resistance and heat by holds virtue the of the higher I R power loss. The added heat anneals spring material that mating surfaces together, releasing contact pressures and further adding to the problem. Eventually, the coke formation prevents the contacts from moving, and a major failure can occur when the LTC is required to make a change [6]. 1.7.2.7 1.7. 2.7.2 .2 Insul ation System Usually the insulation system of a LTC consists of oil and solid insulation materials, which depending on the construction, could be made of cardboard, fiberglass, or epoxy resin. For the most part, only th thee insulation capability of the oil is of concern. concern. It is well known that oil degradation is highly dependent on temperature. Depending on the brand of oil, the degradation of oil can start even under normal operating conditions with a temperature over 60 °C. The rate of degradation significantly increases at temperatures above 80 °C. As the oil degrades, CO, CO 2, H2, and hydrocarbon compounds like CH4, C 2H6, C2H4, and C3H6 are generated. In addition, the insulation capability of the oil decreases. But the main destructive agent for the oil is hotspots, which are caused by joints or contacts that have developed high-resistance surfaces and interfaces. The temperature can go well over 150 °C on the connection surface. A by-product of the hotspot degradation is the generation of soot particles in the oil. In addition, the generation of some of the hydrocarbon compounds (C2H6, C2H4, and CH4) is greatly enhanced by the presence of hotspots in the LTC. The oil will also be destroyed by the high temperature of arcs, which occur during normal switching operations. Partial discharges can be created by moving particles in the oil as well as rough surfaces. As mentioned in the preceding section, at high 46  temperatures, oxygen and sulfur in the oil will react with copper and silver to form metal temperatures, oxides and sulfides on joints and contacts. Excessive amounts of moisture in the oil will decrease the electric strength of the oil and enhance the possibility of discharge activity. 1.7.2.7 1.7. 2.7.3 .3 Contr ol System The sw The swit itch chin ing g of the the LTC is co cont ntro rolllled ed an and d mon onit itoore red d by a syst system em of re rela lays ys an andd RTU RT Us. A fail failuure of any of these hese com ompo ponnents nts will ill le leaad to a failu ilure of th thee LTC to operate. 1.7.2.7.4 Mechanism The force to switch the LTC is generated by a motor and transmitted by gears to the contacts. The motor and the gears will age with time or develop their own set of functional problems. For example, binding in the gears or the shafts that hold the switches and contacts can slow down the switching sequence or prevent the mechanism from moving. These problems as well as material or assembling failures can cause a failure of the LTC. 1.7.3 1.7.3.1 EUROPEAN PRACTICES RESISTANCE T YPE OLTCS Resistance type OLTC’s exist in two main types: diverter switch type and selector switch type. In both cases, transitions resistors are used to:  To carry the current during the switching ooperation peration when the main main contact is moving from one position to anothe anotherr  Reduce the circulation cu current rrent tha thatt will start with the switching ope operation ration w when hen one loop in the regulation windin winding g is short circuited The arcs during the switching operation are normally extinguished at the first current/voltage current/voltag e zero. The high-speed resistive transition OLTC mechanism uses the motor to charge a spring. The spring cannot release its energy until it is fully charged, at which point the tap change is made. Motor failure, loss of power, or control problems cannot stop the OLTC mechanism in an undesirable contact position because this critical part is controlled exclusively by the springs. The high speed of the mechanism also contributes to the absence of both re-strike and extended arcing. The average arcing time is five to six milliseconds, which is the average time to reach a current zero after contact separation. The time for a highspeed resistor type OLTC to switch from one position to another position is approximately 40-70 milliseconds. Loading of the springs and preparation for a new switching operation takes between 2.5-6 seconds.  47  1.7.3.2 DIVERTER SWITCH OLTC The diverter switch OLTC consists of a diverter switch and a tap selector. The diverter switch, which breaks the arcs, is placed in a glass fiber (previously bakelite) cylinder. This cylinder is tightly sealed to prevent the arcing products from entering the transformer transform er tank. The tap selector, which makes the conn connection ection to the tap (regulating) (regulating) winding, is placed under the diverter switch. Figure 11-22 22 sho shows ws the lay layout out of a typ typica icall diverter switch between taps. tap changer and Figure 1-23 shows a complete switching sequence Figure 1-22: An ABB diverter switch tap changer of type UC. 48  Selector arm V lies on tap 6 and selector arm H on tap 7. The main contact x carries the load current. Selector contact H has moved in the no-current state from tap 7 to tap 5. The main contact x has opened and the arc has extinguished. The load current passes through the resistor Ry and the resistor contact y The resistor contact u has closed. The load current is shared between Ry and Ru. The circulating current is limited by the resistor Ry plus Ru. The resistor contact y has operated and the arc has extinguished. The load current passes through Ru and contact u. The main contact v has closed, resistor Ru is bypassed and the load current passes through the main contact v. The on-load tapchanger is now in position 5. Figure 1-23: Example of a switching sequence for a diverter switch type OLTC 1.7.3.3 SELECTOR SWITCH OLTC Selector switch OLTC’s have only one compartment where both the breaking of arcs and the connection to the different taps are made. This compartment is tightly ti ghtly sealed to prevent arcing products from entering the transformer main tank and Figure 1-25 show a layout and a switching sequence for a typical selector switch tap changer. 49  Figur e 1-24 1-24 : Selector Selector swit ch tap-chan gers of UZ a and nd UBB typ e 50  UZ design with fixed contacts in a circle and the main contact surrounded by the transition contacts at the top. The transition contact M1 has made on the fixed contact 2. The load current is divided between the transition contacts M1 and M2. The circulating current is limited by the resistors. The main contact H is carrying the load current. The transition contacts M1 and M2 are open, resting in the space between the fixed contacts. The transition contact M2 has made on the fixed contact 1, and the main contact H has been broken. After After that the arc has extinguished. The transition resistor contact, M2, carries the load current. The transition resistor contact M2 has broken at the fixed contact 1, and the arc has extinguished. The transition resistor and the transitio transition n contact M1 carry the load current. The main contact H has made on contact 2. The main contact H is carrying the load current. Figure 1-25 1-25 : Exa Example mple of a switching sequence for selector switch tap-cha tap-changers ngers 1.7.3.4 T IE-IN RESISTORS The change-over selector is only operated when it is not carrying current. However, due to capacitive coupling to the surrounding windings, tank or core, the free floating tap winding might develop a voltage that could create a dangerous arc on the change-over selector contacts. This arcing will normally not affect the DGA in the transform transformer er tank. If the voltage over over the selector is too hhigh, igh, a tie-in resistor is needed to reduce it. Figure 1-26 shows a tap changer layout that used a tie-in resistor to control arcing. 51  The change-over selector is moving and the tap winding is free floating. High voltages can appear over the change-over selector. With a tie-in resistor the voltage over the change-over selector can be reduced. There will, however, be extra losses due to the current in the tie-in ti e-in resistor. With a switch that is only closed at the time of the change-over selector movement, the tie-in losses can be avoided. Figure 1-26: Tie-in connections 1.7.3.5 FAILUR E MECHANISMS FOR OLTCS From an analysis of failure statistics it is known that OLTC failures can be grouped under the following systems:     Electrical connections Insulation system Control system Mechanical system The typical failure mechanisms under each group are discussed below. 1.7.3.5 1.7. 3.5.1 .1 Electri cal Connecti ons The contacts where the breaking takes place are typically of copper/tun copper/tungsten gsten material. At each operation, the arcing will carbonize some oil and a small amount of the contact material will also end up in the oil. The maintenance criteria of the OLTC are set to avoid these products since they tend to lower the dielectric di electric withstand voltage. If proper maintenance is not performed or if too much moisture enters the OLTC, the dielectric strength of the oil in the OLTC can reach a dangerous level. If a contact remains in one position for a long time (several months or years), the normal wiping action which cleans the contact surfaces during normal operation of the tap selector contacts does not occur. Consequently, the temperature in the contact might increase and led to growth of carbon particles oonn the surface of the contact. This will cause the temperature of the contact to increase and progressively worsens the situation. The final result is the formation of coke on the contacts. This can lead to the generation of free gas, and potentially to a flashover, which may catastrophically damage the transformer. 52  In extreme cases, the carbon growth (sometimes referred to as pyrolytic carbon growth) between and around the contacts can bind the contacts together. This condition can cause mechanical damage if an attempt is made to operate the tapchanger. Depending on the design, this may be a potential problem especially for the change-over selector in on-load tap-chang tap-changers. ers. 1.7.3.5 1.7. 3.5.2 .2 Insul ation System The insulation system of an OLTC consists mainly of oil and solid insulation materials. Depending on the construction, the solid insulation material could be made of fiberglass, epoxy resin or bakelite. In the diverter and selector switches, the oil will be degraded by the arcs even during normal switching operations. The condition of the oil and electrically stressed surfaces in the solid material will be influenced by the arcing products. Tap selectors are normally placed in the transformer tanks and therefore share oil with the main winding insulation. Since no arcs are typically generated during tap selection, there is no concern for the generation of arc-decomposition products that may degrade the oil. However, excessive amounts of moisture in the oil will decrease its electric strength and enhance the possibility of discharge activity. 1.7.3.5 1.7. 3.5.3 .3 Motor Drive Mechanism The switching of the OLTC is performed from the OLTC motor device. This cabinet contains relays and switches. A failure of any of these components can lead to a malfunction of the control system for the OLTC. A fault in the motor drive mechanism will not lead to a tap-changer failure. 1.7.3.5.4 Mechanism A motor is used to drive the shaft s haft system and gears that will load the spring battery and also operate the tap selector. It is essential that the shaft system is correctly coordinated with the tap-changer, else severe failures can result. If the gear box is jammed, it can result in the motor protection stopping the motor from operating. If the wear in the gear box is abnormal, abnor mal, it can prevent the tap-changer from operating. 53  1.8 STREAMING ELECTRIFICATION EL ECTRIFICATION Inside a power transformer, the insulation between high-voltage parts (high and lowvoltage coils) and grounded parts (tank walls and iron core) is provided mainly by paper, pressboard, and low conductivity oil. In transformers transformers with forced-oil cooling (OFAF), the oil is circulated by pumps in a closed circuit and acts additionally as a coolant for the power apparatus. Severalin factors have been to influence the likelihood of streaming electrification transformers. Theseshown include the electrostatic charging tendency of the oil, the oil flow velocity, the conductivity of the oil, the insulation temperature, tempera ture, and the moisture content of the insulation. At any liquid-solid interface, and also at the contact surface between pressboard insulation and transformer oil, an uneven charge distribution can be observed. The uneven charge distribution is caused by the difference in adsorption rate of the solid surface for positive and negative ions in the liquid. In a transformer, the solid surface adsorbs typically more negative ions, forming a charge layer trapped within the pressboard. The corresponding positive charges form a mobile, diffuse layer extending into the liquid. The positive ions in the liquid are subjected to two counteracting forces: the electrostatic force keeping the ions close to their negative counterparts in the solid and the agitation of the fluid diffusing the ions to regions of lower ion concentration. Apart from the diffusion process, there is also the macroscopic flow of the liquid entraining the ions [7]. When the low-conductivity oil shears over the pressboard surface, it entrains the diffused positive part of the electric double layer, while the solid retains the corresponding negative charges on its surface. This process is called streaming electrification, where the entrained ions form a streaming current. The entrained charges may recombine with other countercharges in the liquid, be deposited on a remote solid surface, flow along with the liquid, or undergo a combination of all these processes. The accumulation of uni-polar charges on an insulated part of the structure, a process referred to as sstatic tatic electrification, generat generates es a potent potentially ially dangerous voltage buildup. When the corresponding electric field surpasses a certain threshold, electrical discharges may occur, damaging the system. The damage can range from deterioration of the transformer oil to flashover between high- and low-voltage coils or between an AC coil and ground, the latter most likely leading to costly repair or replacement [8]. Figure 1-27 shows a graphical depiction of the process of stream streaming ing electrification as described above. 54  Figure 1-27: Streaming Electrification Model in Power Transformers [ 9] 1.8.1 CHARGING TENDENCY AND ITS EFFECT OF STREAMING ELECTRIFICATION One of the key determinants of the risk of streaming electrification failure is the electrostatic charging tendency tendency (ECT) of the oil. This is defined as the amount of charge generated per unit volume of oil as it flows though a specific filter and is measured in microcoulombs microcoulom bs (C/m3). In a transformer, it provides an indication of the capability of oil to generate charges as it flows past the surface of the cellulose in the cooling duct. It has been found that the use of oils with high ECT in a transformer result in a higher level of charge density in the transformer. This increases the risk of streaming electrification failure. The ECT is measured by forcing a specified volume of oil through a specified filter. As the oil flows through the filter, charge separation occurs. The charge collected on the filter is measured by an electrometer and is used to calculate the ECT. The changing tendency of new oils typically the range of 0-150 C/m3. of The charging tendencies of oils in “normal” fieldisunits haveinbeen measured in therange 5-200 C/m3. 55  Table 1-2 provides recommended limits of ECT for oils used in transformers in service. The values provided in the table are to be used only as guidelines in determining the risk of failure from streaming electrification. While most of the recorded streaming electrification failures were in transformers with ECT values greater than 500, there have been a few reported cases of failures failures in which the ECT was below 200. This points to the varied number of conditions and mechanisms that can lead to a streaming electrification failure. Forand example, if low-charging tendency transformer that has high flow velocities, the transform transformer er insulation is cold oil (asisinina astartup), sufficient charge separation and accumulation can occur and increase the potential for streaming electrification failure. On the other hand, in a transformer with normal flow velocities, high-charging tendency oil at warm insulation temperatures would have reduced potential for charge separation and accumulation. The risk of streaming electrification failure would therefore be lower than the previous example. Perhaps the most important factor that determines the level of charge separation in a transformer is the flow velocity in the insulation ducts. The flow velocities in a large power transformer vary depending on the design of the insulation ducts, the number of pumps, and the volume flow rate of the cooling pumps. It is desirable to maintain as low a flow rate as possible without affecting the cooling efficiency of the transformer. For large power transformers that are have a part the installed base ABB transformers, transform ers, ABB design engineers theof capability to determine determ ine of theinherited flow velocities in the cooling ducts to maintain the required cooling efficiencies. If a given transformer is found to be susceptible to streaming electrification failure, ABB can make recommendations for achieving the proper cooling efficiencies while minimizing the risk of streaming electrification. Table Table 1-2 1-2:: Li mits for Cha Charging rging Tendency Tendency in Service Tra Transfo nsfo rmers 3 ECT (C/m ) <250 250-400 >400 1.8.2 Potentia Potentiall for Streaming Streaming Ele Electrification ctrification Normal Moderate to High High MITIGATION STRATEGIES FOR STREAMING ELECTRIFICATION It is assumed that streaming electrificati electrification on does exist to some extent in all transformers with forced-oil cooling and especially those with directed flows. The goal is to determine how these transformers can be safely operated in a way that will keep the effects of streaming electrification under check. Several observations in a project [10] by ABB for EPRI have been made as to the causes of the electrification process and modifications to minimize these causes:  The charge generat generation ion process tha thatt aggrav aggravates ates the electrification electrification process is increased with flow rate and temperature. Charge relaxation, which counterbalances the generation processes, is, on the other hand, enhanced primarily by temperature. The result is that the potential for charge buildup is increased at low temperatures, when the generation processes are dominant. As 56  the temperature increases, the relaxation processes are faster and eventually overtake the generation processes. Beyond this point, the transformer can be assumed to be out of danger with regard to charge buildup and eventual failure of the insulation system.  The streaming streaming electrification pprocess rocess is highly depen dependent dent on the charging tendency of the insulating oil. High-charging tendency oils are likely to increase the electrification characteristics by several times. The more high-charg high-charging ing an oil, the more charges are generated under flow conditions. So, at low temperatures there is more likelihood of extreme charge buildup, which can lead to damaging discharges in the transformer. However, once the relaxation processes are accelerated by temperature, these dangers subside as more charges relax than are generated.  It was observed that the primary source of charge genera generation tion was inside the winding ducts. The lower plenum, which has washers extending into the oil space and also the entrance regions to the ducts, were presumed to generate some charges are well. This was evidenced by high levels of charge density and streaming currents that were measured in the upper plenum oil space than what was measured in the lower plenum oil space.  It was also observed that the more open an andd leakage ducts ther theree were in the high-low voltage insulation of the transformer, the more charges were separated in the ducts. This indicates that it may be possible to alter the design of the ducts of a transformer so that there are fewer ducts open without sacrificing cooling capability.  The height of the lower plenum plenum oil space was found to pplay lay a very important important role in the level of charge generat generation ion that occurs in the ducts and more iimportan mportantly tly at the tips of the washers and the entrance region regionss to the ducts. It appears the local eddy effects generated in the lower plenum becom becomee diffused as the height of the oil space is increased. There is therefore less charge sheared from the insulation structures extending into the oil space. This may be a possible change to a problem transformer that may help alleviate the dangers of streaming electrification.  It appears impurities tha thatt cause the charging tendency of the oil to increa increase se can be absorbed or loosely bonded to the cellulose fibers. Retrofitting with lowcharging oil after draining the high-charging oil may not be sufficient to reduce electrification in the transformer. Perhaps, before oil retrofitting can be effective, the cellulose insulation must be “washed” with oil that has a high degree of solubility for impurities. This will hopefu hopefully lly dislodge most of the impurities from the cellulose. Retrofitting with low-charging oil may then be effective.  Perhaps the most important observatio observationn was that the electrificat electrification ion process can be controlled via modifications of the operational processes of the transformer. Charge density measurements revealed a tremendous decrease in charge accumulation in transformer the upper plenum beyondbe50operated °C, even under full pumping capabilities. The can therefore under reduced oil flow 57  rates until the temperature is above this critical temperature. At this point, full oil flow can be added without significant increases in charge densities and also any dangers due to streaming electrification. The same procedure will be needed for the reverse cycle.  ABB further recomm recommends ends that utilities shou should ld ensure ensure that all winding winding tem temperature perature gauges are operational and properly calibrated; that the cooling controls operate properly and are set in the AUTOMATIC position for operation. Also, the utility should have in place operating procedures that prevent the running of all the pumps when the oil temperature is below 50 °C. The charging tendency of the oil should also be tested along with the other oil quality tests.  Several oil oil manu manufacturers facturers recom recommend mend a chem chemical ical approach to so solving lving th this is issue. They focus on reduct reduction ion of the ECT by using additives (inhibitors). This technique could lead to a reduction in the risk of static electrification, especially for old transformer transform er designs. 58  2 A PRACTICAL APPROACH APPROA CH TO TO ASSESSING THE RISK OF FAILURE OF POWER TRANSFORMERS TRANSFORMERS 2.1 BACKGROUND Transformer risk assessment is one of the main branches of transformer diagnostics. It is related to strategic planning of technical and economical activities, i.e. how to manage the the transformer asset with available resou resources. rces. The impo importance rtance and need of strategic planning is elaborated elsewhere in this handbook. However, in short it is related to the inherent conflict between a desire of operating the transformer fleet at lower cost and the requirement to retain the requested availability and reliability. A consequence of this desire is a trend of operating the transformers harder (higher, increasing loads) and for a longer period of time and at reduced costs (including reduced costs for maintenance and expertise). The transformer fleet will become older and many units will suffer an increasing risk of not being able to fulfill their function – either by a technical malfunction or by being obsolete in another way. In most western countries the average age of the transformer fleet is around 30-40 years, which is in the range where the technical failure rate is expected to increase. With the continuing ageing of transformers, it has become important to understand the factors that contribute to elevated levels of risk of failure. The goal is that if these factors are understood, then a risk of failure profile can be developed for each unit in an organization’s fleet of transformers. This information allows the organization to target appropriate strategies for mitigation, repair, upgrading, replacement, etc. for the correct set of transformers transformers as identified by the risk of failure profiles. This section presents the general approach in a transformer risk assessment that considers several factors, including condition indicators, known design capabilit c apabilities, ies, and operationall characterist operationa c haracteristics ics of a transformer. From these factors, a probable likelihood of failure is calculated for each transformer. Together with the relative importance of each unit to the power system, a prioritized strategy can be developed for transformers in a fleet. 2.2 L IFE MANA MANAGEMENT GEMENT PROCE PROCESS SS Transformer risk assessment is a part of an overall unit oriented transformer life management managem ent process. This process has the following major ingredients: 1. A screening pr process ocess to ident identify ify units for fu further rther scrut scrutiny. iny. 2. Condition analysis and m more ore or less detailed design evaluation of individual units. 3. Life assessment decisions and th their eir implementation implementation (life exten extension sion via upgrading upgrading,, relocation, replacement etc.). 59  The risk assessment is used in the fleet screening process and its primary purpose is to rank the transformers with respect to the risk. This allows us to prioritize the transformers for follow-up corrective actions such as detailed design or condition assessment, diagnostic diagnostic evaluation, inspection, inspection, repair, or rep replacement. lacement. Another benefit of a risk assessment is that the results (or scores) of the evaluation can provide the basis for an intelligent estimation of the statistical technical risk of failure of the various units. 2.2.1 RISK ASSESSMENT In its true sense a risk consists of two different aspects – a probability of an occurrence (e.g. a failure) during a time interval and the consequence of the occurrence. The probability of a failure is the individually adjusted hazard function or failure rate. This function depends on various technical factors – from design, service and diagnostics. The consequence represents the severity of a failure and is determined essentially from various costs of undelivered energy or power, costs of repair etc. It can also be dependentt on other factors such as strategic and environm dependen environmental ental aspects etc. In order to estimate a “true” adjusted individual failure rate, common statistical distributions are used – but modified using models that depend on the score of the technical risk. The ABB approach to fleet risk screening involves both risk aspects mentionedd above. However, th mentione thee functiona functionall forms of the these se aspects are very com complex plex and it is difficult to determine them in an exact manner. Hence, in a first step, relative parameters are used to map the original parameters. The technical risk (of a failure) gives a value or score that depends on (or is a good estimator of) the individual failure rate. The (relative or econom economic) ic) iimportan mportance ce is a measure of the negative consequences consequences of the failure. The result of the combined evaluation of the technical risk and importance in a risk manageme management nt investigation is normally normally presented in either of two ways:  As a Risk Index Index def defined ined as a norm normalized alized prod product uct of the technical risk and relative importance as shown in Figure 2-1.  In a two-dimensional two-dimensional diagram exemplified in Figure 2-2 and F Figure igure 22-3 3 with the the technical risk and the relative importance on the two axes (Preferably the true probability of failure and the true costs should be used but according to above these parameters are difficult to determine). 60  Technical Te chnical Risk*Relative Risk*Relative Import ance x e d In k is R Transformer Units Figur e 2-1: 2-1: R Risk isk Ind ex for a Numb Numb er of Transfor mers Figure 2-2: Risk Management Approach to Identify Transformers at Risk 61  Technical Risk B C Very Urgent A Urgent Priority Normal 100 Relative Importance Figure 2-3: An Alternative Diagram for Risk Identification The Risk Index represents the statistically expected cost due to a failure for the unit under scrutiny. In this sense the product is related to the insurance premium to be paid by the utility for keeping the unit in operation. In Figure 2-1 the Risk Index compares the expected economical consequences of a failure for the different transformers belonging to a utility. Discrimination between groups of units is clearly seen. However, using a two-dimensional diagram is probably a better way to present the results of a risk assessment. The two diagrams, Figure 2-2 and Figure 2-3, display the outcome of analyses for two example fleets of transformers that have diverse risk of failure characteristics charact as diverse relative importance. diagra diagrams, ms, each transformer in eristics the fleetasis well assigned a technical riskim ofportance. failure andIna the relative importance and is then displayed on the risk management plot. Those that fall in the (various degrees of the) Red Zone are transformers with a combination of high risk of failure and/or higher importance for the system. These are classified as Urgent (or very Urgent), or those requiring immediate action. The next transformers are those in the Yellow (Priority) Zone. Action would normally be taken on these transformers as soon as the Urgent transformers have been taken care of. The transformers in the Normal category would typically not require anything other than normal basic maintenance unless circumstances move either the risk of failure or importa importance nce to a higher value into the Yellow or Red Zone. The intent of risk management is to move the identified transformers to areas of lower risk. For example, a transformer can be moved from the Urgent zone to the normal zone by reducing the expected technical risk of failure. (The arrows arrows A in the figures exem exemplify plify 62  this case). The process of reducing the expected risk may begin with a detailed life assessment study to identify ways of reducing the risk of failure. In the process, some of the original assumptions regarding the risk of failure may also be modified to obtain a more accurate view of the risk of failure. Actual methods for reducing the risk of failure may include refurbishment of the transformer or accessories, moving the transformer to an area with lower incidents of faults on the feeder lines, or it could involve system changes like modifying practices or trimming treesthe in arelative right ofimportance way. Another strategy of riskreclosing management involves reducing of a transformer. This is illustrated in the figures by case B . This strategy might involve moving a higher-risk transformer transformer to a less critical location. It might also include adding a parallel spare transformer transformer to reduce the impact of a failure. Ideally, the actual strategies would include both types of solutions to reduce the risk of failure and reduce the criticality of the application; exemplified exemplified by the case C. 2.2.2 L AYOUT OF THE THE EVALUATION PROCEDURE Our risk assessment procedure focuses on the transformer functionality or suitability-for-use [[11]. 11]. We addr address ess va various rious aspects that might jeopard jeopardize ize or negatively influence this suitabili suitability-for-use. ty-for-use. Influential aspects on the suitability for use of the transformer Technical ssu uitability Accessories Mechanical suitability Main tank Electric suitability Non-technical su suitability Economical incentives Strategic reasons Environmental reasons Thermal suitability Figure 2-4: 2-4: Va Various rious directions of a transformer evaluation Technical aspects include not only the traditional paper ageing aspects, but also other aspects related to short-circuit strength, electric integrity, thermal degradation and accessory failures. The focus on transformer functionality is fundamental. The aspects that are addressed are linked to situations that are potentially dangerous to the transformer operation. As can be seen in Figure 2-4, there are essentially four aspects that are considered in determining the technical risk of failure of a given transformer: 63   Mechanical Mechanical aspects: This involves the risk of short circuit failure, which is based on assessment of the short circuit strength of the windings and clamping structure and the incidence and magnitude of short circuit through fault events.  Thermal aspects: This involves the winding thermal condition and is based on the condition of the paper insulation. Aged, brittle insulation is more likely to fail under the mechanical conditions. Also, metal parts at high temperature could pose a risk to thestress transformer. transform er.  Electric aspects: This involves the risk of dielectric failure and is based on the assessment of the dielectric withstand capability of the transformer insulation system (oil, paper, etc.) and the electrical stress imposed by the power system and naturally occurring events.  Ac Acces cesso so ry fai lures lu res : Failures of a transformer accessory such as a bushing, pump, or tap changer may cause a failure or loss of service of the transformer. Each of these factors will be explained in more detail later. As for the consequences or importance of a failure, the various cost factors mentioned above (undelivered power, environmental costs etc) should be evaluated. This is an exercise for the utility or the utility and ABB working together. Most often the utility ranks its transformer fleet with respect to the relative importance of the various units and assigns an evaluation value between 0 and 10 or 0 and 100. 2.2.3 EVALUATION PROCEDURE Estimating the technical risk of failure of a transformer is a complex issue involving analysis of historical failure data, knowledge of design issues, and interpretation of diagnostic test results. The evaluation procedure also involves the selection of suitable data to be used, rules and overal overalll structure. ABB has methods of different comp complexity lexity for the evaluation. The ABB approach, [12,13,14,15,16] relies heavily on deep knowledge in design, transformer manufacturing, service and transformer diagnostics. The data used for reasoning when evaluating a large number of transformers in a fleet screening must be based on easily information order for the evaluation to on be economically reasonable. The dataavailable for reasoning is theninpre-processed data based various influential factors such as DGA, dissipation factor, oil condition, time-inoperation, size, etc. As illustrated in Figure 2-5, there are essentially two procedures used in algorithms for combining the data for reasoning. 64  I. Overall unstructure unstructured d method Data for reasoning Rules w1 w2 Total Score (Technical Risk) wN Data for reasoning Rules Subgroup evaluation Mechanical Score Electric Score Rules II. Method structured along possible risks wM wE Total Score (Technical Risk) wT Thermal Score w.. Etc. Figure 2-5: 2-5: Proce Procedures dures for obtaining th e technical technical ris k value for a transfor mer Method I is an unstructured method while method II is structured according to different external stress modes – mechanical stresses, thermal stresses, electric stresses, auxiliary stresses etc. In method I the total score is obtained through a formula applied directly to the data for reasoning. Examples of such a formula are a weighing formula or a knockout criterion. In the latter case the Total Score is determined only by the parameter having the worst (maximum) influence. In method II the influential factors and data for reasoning are combined in such a way that first an evaluation of the various subgroups are made and then the risk scores of these subgroups are combined to a total evaluation. The structure of method II can be extended beyond the “influential factor” procedure to include a more detailed analysis involving design data and calculations and more condition assessment measurements. This is a more precise risk of failure estimate than performed with influential factors. It focuses on specific knowledge of the transformer transform er desi design gn and condition, in addition to the statistical and historical parameters. 65  The reasoning rules are based on known transformer relationships. This is the method used in the Mature Transformer Maintenance Program (MTMPTM) offered by ABB. In this evaluation a more pertinent statement of the condition and risk in connection with various transformer stresses can be obtained, for example, regarding short-circuit strength, dielectric strength, insulation ageing, tap changer status and loadability. The more detailed design and condition is for practical reasons applied only to a reduced number of transformers transformer s si since nceranking it requires more input data. For an evaluation performed according to the structured method II, not only can a total ranking be performed but also separate rankings according to the different types of stress. The subgroup ranking can be made either when the data for reasoning is obtained from influential factors or when it comes from more detailed calculations/analyses. A final step in a ranking procedure is to scrutinize the evaluation for parameters having a large or significant single impact on the result – even if the total risk for the particular transformer is calculated to be low. Knowledge of such parameters is used to direct the engineering mitigation work. 2.2.4 PROBABILITY OF FAILURE – INDIVIDUAL FAILURE RATE The evaluation described above yields an estimation of the technical risk in a relative scale. Sometim Sometimes es an absolute assessment assessment of the individua individuall failure rate of a un unitit is desired. A first approx approximation imation to this is achie achieved ved by combining th thee technical risk with statistical failure rate models as shown in Figure 2-6. This can be done on component (influential factor), on subgroup level and on total risk level. STATISTICAL FAILURE RATE MODEL (RELATIVE) TECHNICAL RISK MODIFICATION MODEL MOD EL = f (Tec (Technical hnical Risk ) INDIVIDUAL FAILURE RATE Figure 2-6: 2-6: Combination of a statistical failure rate function with a technical parameter parameter value to obtain an estimation of the individu al failure rate of the a addressed ddressed transformer 66  2.3 ASSESSMEN ASSESSMENT T OF THE TECHN TECHNICAL ICAL RISK OF FAILURE FAIL URE B Y TM CATEGORY (MTMP PROGRAM) The algorithms for technical risk of failure, as discussed above, are based on influential factors related to the individua individuall ssubcatego ubcategories ries [17,18,19]. The total technical risk is then determined either directly from these influential factors or from a combination of the assessed risks for the subcategories. To aid in the understanding of the risks for the fleet of transformers, the relative risks for each of these categories will be briefly presented. 2.3.1 MECHANICAL ASPECTS One of the more common types of failures in power transformers is a winding failure caused by the forces associated with a through-fault. As part of the risk of failure analysis, each of the transformers in the fleet is evaluated for the potential risk of short circuit failure. The influential risk factors that may be considered as part of the short circuit risk include the transformer design, the dielectric and thermal condition of the windings, the reclosing practices, and the average number of through-faults experienced by the transformer transformer in a given year. For example, it is typically the case that transformers transform ers having a higher incidence of through-faults have the highest relative risk of short circuitlines. failure. These transformers are generally located in substations feeding distribution 2.3.2 THERMAL ASPECTS An important factor in the risk of a short circuit failure is the condition of the paper insulation. An aged transformer with brittle insulation and/or loose windings is more likely to experience a failure under the same through-fault conditions than another transformer of the same design that does not have brittle insulation or loose windings. This principle is incorporated into the risk of failure analysis by the thermal winding risk factor. Typical influential factors are the temperature, the age of the transformer insulation, the relative compositions of produced carbon oxides, the load profile and the MVA size. Another thermal risk factor is hot spots in metallic materials such as core or current carrying contacts. This risk is determined from DGA. 2.3.3 ELECTRIC ASPECTS - RISK OF DIELECTRIC FAILURE The risk of dielectric failure involves both design and condition issues. Both design knowledge and the historical information are used in this evaluation as well as the diagnostic test data. Conditions such as the dissipation factor (tan , power factor) of the insulation, oil quality results, the amount and distribution of dissolved gases in oil, and design of the over voltage protection may be used in the evaluation of the dielectric risk. 2.3.4 ASPECTS RELATED TO ACCESSORY FAILURE Accessory failure refers to the loss lo ss of service ooff the transformer due to either the failure or operational breakdown of an accessory. The accessories considered in this analysis include oil coolant pumps, tap changers and bushings. The risk of accessory failure is 67  based on the type of accessory and the diagnostic evidence from DGA, power factor (tan  results, or other analyses. In addition, a “Random failure risk” is included in the assessment. This risk is related to external causes not associated with the design or condition of the transformer itself. It takes into account other types of failure risks not accounted for in the other factors. The parameters paramete rs affecting random can from be: the type to of transformer, theloading location, cases where a transformer must befailure removed service de-gas the oil, practice etc. This type of risk also includes transformers at risk for streaming electrification due to the design type, potential high oil velocity, and/or cooling operation philosophy. 2.3.5 TOTAL TECHNICAL RISK OF FAILURE The total technical risk (or individua individuall failure rate) is obtained either direct directly ly from metho methodd I in Figure 2-5 or (better) according to method II from a combination of each of the risk categories discussed above. The risk of failure is determined for each of the transformers transform ers in the fleet. Figure 2-7 shows a histogram of failure rates for over 200 power transformers. An indication of the relative importance of each of the transforme transformers rs is also calculated based on the replacement cost for the transforme transformerr or the criticality of the transform transformer er to sys system tem reliability. In order to develop a priority for addressing mitigation strategies for the transformers, transform ers, a pl plot ot of the risk of failure vs. the importance is shown in Figure 2-8. 40 35 s ti 30 n U 25 f o r 20 e b 15 m u 10 N 5 0 5 2 1 . 0 5 2 6 . 0 5 2 1 . 1 5 2 6 . 1 5 2 1 . 2 5 2 6 . 2 5 2 1 . 3 5 2 6 . 3 5 2 1 . 4 5 2 6 . 4 5 2 1 . 5 Total Failure Risk Figure 2-7: Total Total Risk of Failure of Transfo rmers 5 2 6 . 5 5 2 1 . 6 68  100 80 e c n a tr 60 o p Im e 40 v ti a l e R A 20 B 0 0.0 1. 0 2.0 3.0 4. 0 5.0 6.0 Probability of Failure Failure Figure 2-8: Categorization of Risk (Technical Risk or probability of failure and relative importance) Profiles for Power Transform Transform ers In this chart, the transformers are grouped into three categories: Urgent (red), Priority (yellow), and Normal (green). For each transformer in the Urgent or Priority regions (these are considered the abnormal regions), a more detailed analysis is made to identify which risk factors were prominent in placing it in that category. For those factors that are flagged, the sub-factors are analyzed to determine which underlying parameters triggered the abnormal status. All such sub-factors are summarized as the reasons for the transformer being classified in a particular abnormal category. This detailed analysis is then used as the basis of recommendation recommendationss for mitigatio mitigationn actions. As an example, consider the transformer labeled A in Figure 2-8. Ninety-six percent of the total risk was contributed by the relative risk of accessory failure. The underlying factor the high accessory risk factor wasother traced to atheconditional factor with a for leaking high-voltage bushing. On the hand, unit labeled B is associated at risk due to several factors. It has increased potential for through-fault failure due to its design and the high incidence of through-faults at the substation. In addition, its LTC is at risk for failure due to the type of LTC and the presence of certain combustible gases in the selector switch compartment. The same unit is also at risk of dielectric failure since the kV breakdown of the oil is low and the high-low insulation power factor is higher than 1%. The histogram in Figure 2-7 is also suitable when comparing the evaluation of a single transformer with the evaluation of previously evaluated units. For instance, a new transformer with the risk evaluation value 3 belongs to the upper 10 % most risky units of all units evaluated so far.  69 2.4 RISK MITIGA MITIGATION TION For all of the transformers identified in the Urgent or Priority category, recommended risk mitigation actions are suggested based on the underlying factors that support the high-risk evaluation. In some cases, immediate action such as replacement of an offending bushing or inspection of a tap changer can be taken to correct the situation. For other cases, additional diagnostic testing is needed to better evaluate the risk to determine the most appropriate maintenance maintenance and risk mitigation actions. In such s uch cases, the evaluation is taken further to include also condition assessment and design assessment if possible One important risk management area is to identify spare transformers for the Urgent and Priority transformers in the system. The risk of failure ranking is used to identify which transformers to begin with. In many cases, especially those where design issues such as short circuit strength are involved, it may be more appropriat appropriate e to replace a highrisk transformer with a new unit and keep the older transformer as a spare in order to reduce the risk and improve the system reliability. For a great number of the transformers that have been analyzed, the greatest risks of failure are (1) risk of accessory (bushing, tap changer, pum pump, p, etc.) failure, (2) failure due to through-fault currents caused by close-in faults on the transmission system, and (3) risk of dielectric failure due to various causes. 2.5 SUMMARY In this section we have discussed the principle and methods for the risk assessment of power transformers that takes into consideration various risk factors that together present a comprehensive risk profile for a given transformer. Each of these risk factors is assessed based on certain condition indicators and/or the design and/or the application of the transformer. This results in a quantitative and repeatable assessment of the risk of failure. The risk of failure is used in conjunction with the relative importance of each transformer to classify the overall risk of each transformer. By understanding the underlying reasons for the risk classification of each transformer, the appropriate mitigation actions can be prescribed. Because of the quantitative nature of the analysis, mitigation options can be evaluated to determine the most cost effective means of reducing risk of failure of a given transformer. So far, this method of risk assessment has been performed on a large number of transformers, including industrial transformers, generator step-ups, and power transformers of various voltage classes and MVA sizes. 70  3 DIAGNOSIS OF TRANSFORMERS TRANSFORMERS Power transformers transformers are of prime importance for electrical power systems. The condition of a power transformer is crucial for its successful operatio operation n and, as a consequence, for the reliability of the power system as whole. During transportation or installation or under service operation, a power transformer is exposed to transient and steady-state stresses that can affect its condition as well as its useful life. In addition, transformers are subjected to a natural ageing process under service conditions. The detection of incipient faults which may be caused by insulation weakness, malfunction, defects or deterioration is of fundamental importance. So is the estimation of the ageing condition of the power transformer insulation and its main accessories. This may allow the operators to plan adequate corrective actions at an early stage. Diagnostic techniques are usually used as a means to detect fault and ageing conditio conditionn in power transformers in the field. Conventional and advanced off-line diagnostic methods may be applied periodically or whenever necessary to help detect incipient faults. In some cases, modern on-line monitoring systems may be applied to continuously monitor the condition of the transformer and/or its accessories. 3.1 DIAGNOSTICS METHODS FOR POWER TRANSFORMERS AND ACCESSORIES [20] [ 20] A set of modern diagnostics methods is available and applied for oil filled power transformers and accessories. In this book, both general and advanced diagnostic methods are presented in a summ summarized arized format. General diagnostic methods include the analysis of oil quality (physical, chemical and electrical properties, as well as dissolved gases), core and core insulation analysis, winding and insulation analysis and analysis of the condition of the accessories. In addition, there are advanced diagnostic methods that address the thermal, electrical and mechanical condition of a transformer. Thermal assessment techniques are well established and are typically used to analyze the condition and remaining life of the transformer insulation. Electrical assessment includes partial discharge (PD) analysis, which is a powerful tool used to detect incipient faults in the transformer insulation. Mechanical assessment includes frequency response analysis (FRA), which is applied to detect changes in transformer winding dimensions due to deformations, displacements, shorted turns, etc. Other methods are presented in the proceeding sections. 3.1.1 DIAGNOSTIC METHODS FOR POWER TRANSFORMERS Power transformers are considered to include generator step-up transformers, transmission step-down transformers, system inter-tie transmission transformers, and 71  DC converter transformers, together with such associated equipment as shunt, series, and saturated reactors. Power transformers may be equipped with on-load and/or deenergized tap changers c hangers.. Power transformers are used to reduce the costs of power transmission by transforming the voltage at which current is transmitted. Shunt and series reactor components are similar to transformers but need to absorb reactive power and limit fault currents respectively. The insulation system of a power transformer is a combination of cellulose based material impregnated with mineral insulating oil. The following cellulose materials are normally used:  Kraft paper used as a turn-turn insulation;  Kraft-based Kraft-ba sed hhigh igh density transformer board used for winding spacers and mechanical supports; and  Kraft-based Kraft-ba sed medium to high density transformer board used as major major insulation between windings and from windings to ground. Kraft paper can also be converted into flexible creped paper and used for insulating conductors and leads. Mineral insulating oil is used as an impregnating fluid for dielectric and cooling purposes. Since the mid 1960s, thermally-upgraded Kraft paper has been used as turn-to-turn insulation in transformers. In more recent years, natural esters (vegetable oils) are being used as insulating fluids in power tr transform ansformers. ers. 3.1.1.1 STRESSES ACTING ON POWER T RANSFORMERS The major stresses acting on a power transformer, either individually or in conjunction, are: MECHANICAL THERMAL DIELECTRIC stresses between conductors, leads, and windings due to shorts horttime load overcurrents, fault currents mainly caused by system short circuit and inrush currents while under energ energization ization conditions stresses, due heating or local overheating, associated to short-time overload currents and leakage flux when loading above nameplate rating, or due to malfunction of the cooling systems stresses, due to system overvoltages, transie transient nt impulse i mpulse conditions, or internal resonances within the windings A definitive analysis of the subject of diagnostic tests on power transformers must take into account that the majority of diagnostic indicators are sensitive to all three fundamental stresses acting on the transformer. Therefore, the general interpretations of the outputs of the diagnostic indicators, including the localization of faults, can be problematic a reliable evaluation of the are riskcrucial of failure. The experience and interpretation interpretat ionfor capabilities of transform transformer er experts for a successfully diagnosis. 72  The situation is also complicated because dielectric failure is often the final stage consequent to the mechanical and/or thermal stresses, especially if moisture and/or oil deterioration have already placed the transformer in a hazardous condition. This fact underscores the importance of assessing the service stresses (overvoltages, overcurrents, temperature, etc.) jointly with a detailed knowledge of the design technology and materials. The interpretation of the values and trends of the diagnostics tools must therefore be tailored to different units in order to avoid unjustified alarms. 3.1.1.2 DETERIORATION F ACTORS A ND F AIL URE MECHANISMS Deterioration of the paper-oil insulation is caused by thermal stresses and is accelerated by the presence of moisture, oxygen, or high acidity compounds in the oil. The insulation is unlikely to exhibit a lower l ower dielectric strength after deterioration, deterioration, but it is more subject to rupture under mechanical stress, leading to dielectric failure as a consequence. Few transformers fail due to old age; they usually fail as a consequenc consequence e of:  Short circuit faults  Local overheating overheating due to circulating cur currents, rents, current uunbalance nbalance or the effects of leakage flux  Insulation failure failure und under er electr electric ic stress (die (dielectric lectric failure), failure), perhap perhapss as the final final stage of a scenario involving previous short-circuit faults and/or local overheating, and  Accessory failures failures (bushings, tap changers, coolers, surge-arre surge-arresters, sters, etc.). Faults can be classified as developing in one of three time scales:  An immediate fault where electrical electric al breakdow breakdownn occurs withi withinn seconds of a short circuit, system overvoltage, lightning impulse surge or any other transient phenomena in the system interacting with the transformer;  A local fault developing over days, w weeks, eeks, or or months;  A deterioration deterioration ooff HV insulation over a period of m months onths or years. Diagnostic techniques have been introduced mainly to detect the presence of small local faults and to monitor their development development over time on a period of weeks or months. They provide evidence to plan for further investigation and remedial work to take place on a planned basis, rather than as an emergency. 3.1.1.3 DIAGNOSTIC METHODS Table 3-1 presents the diagnostic techniques used most widely for power transformers, together with their field of application, present status, effectiveness, and specific references. Diagnostic techniques may give information on detection of incipient faults as well as about the specific source or location in a transformer structure structure.. 73  Table 3-1: Most Important Diagnostic Techniques Used for Power Transformers PROBLEMS DIAGNOSTIC TECHNIQUES TECHNIQUES SERVICE CONDITIONS OF THE EQUIPMENT MECHANICAL 1. Excitation Current 2. Low-voltage impulse 3. Frequency response analysis 4. Leakage inductance measurement 5. Capacitance GAS-IN-OIL ANALYSIS 6. Gas chromatography 7. Equivalent Hydrogen method OIL-PAPER DETERIORATION 8. Liquid chromatography-DP method 9. Furan Analysis THERMAL HOTSPOT DETECTION 10. Invasive sensors 11. Infrared thermography OIL ANALYSIS 12. Moisture, electric strength, resistivity, etc. 13. Turns ratio DIELECTRIC PD MEASUREMENT 14. Ultrasonic method 15. Electrical method 16. Power Factor and Capacitance 17. Dielectric Frequency Response 3.1.2 2 OFF-S OFF-S OFF-S OFF-S OFF-S STATUS OF THE DIAGNOSTIC TECHNIQUE 3 PROVEN EFFECTIVENESS OF THE DIAGNOSTIC TECHNIQUE REFERENCE 4 A A A A A M L H M/H H 21 22 23 A A H M 24, 25 26 ON B M/H ON B M/H ON B L ON A H ON A M OFF-S A L ON ON B B M/H M/H 30, 31 32 OFF-S OFF-S A A H H 33 ON ON 27 28 29 DIAGNOSTIC METHODS FOR B USHINGS Bushings insulated terminals current and into HVDC and out apparatus, provide such as transformers, reactors,carrying circuit breakers valvefrom halls.power They additionally serve as mechanical supports for external bus and lines, as well as for internal supports, such as circuit breaker contacts. 2 3 OFF-S = equipment out of service at site, OFF-L = equipment out of service in laboratory, ON = equipment in service 4 A = generally applied, B = development stage H = high, M = medium, L = low 74  Bushings are constructed to numerous design considerations, but commonly commonly consi consist st of:  Center conductor  Mounting flange  Insulation (solid, fluid, plastic, or in combination) between conductor and flange The core may consist of only two terminals:  the bushing center conductor; and  the mounting flange/ground flange/ground sleeve system In a bushing having a non-condenser body design the electric voltage will be distributed logarithmically between the conductor and the flange. In a bushing having a condenser body design, it may include strategically placed conducting wrappings or layers to uniformly distribute the voltage stresses in the core. Most high-voltage bushing designs use the condense condenserr principle. The insulation system may be:  Dry: bulk porcelain, gas, or air  Wound paper and wound paper with conducting layers The wound paper core may be:  Oil-immersed, Oil-im mersed, in porcelain  Oil-impregnated, Oil-impregna ted, oil-immersed  Resin-bonded, either oil or gas-immersed  Resin-impregnated, Resin-i mpregnated, oil-immersed 3.1.2.1 STRESSES A CTING ON B USHINGS Apparatus bushings are subject to the effects of internal apparatus voltage, current, temperature, and contamination but are also subject to external atmospheric and environmental environme ntal conditions as well as mechanical stresses. 3.1.2.2 DETERIORATION F ACTORS A ND F AIL URE MECHANISMS Bushing insulationfrom integrity degrades in flashover normal service from internal moisture,and internal PD and tracking external corona, and tracking from ageing, from physical damage. Despite the intention that outdoors bushings be hermetically sealed devices, inadvertent ingress of moisture resulting from defective gasket seals and physical strain or damage is a major cause of insulation deterioration. deterioration. Internal PD and tracking can be a symptom and result of internal moisture contamination, physical shrinkage of plastic or compound fillers, system overvoltage or marginal designs where there is inadequate stress distribution. External surface contamination effects can be minimized by proper housekeeping and/or by use of coatings. Bushing insulation systems do not usually deteriorate due to time alone, except where they have been subjected to unusual service conditions, such as excessive temperature or operation at voltages above the nameplate rating over long periods of time. 75  3.1.2.3 DIAGNOSTIC METHODS Bushings are ideally suited for field-testing by dielectric diagnostics to detect and analyze defects or deterioration resulting from the conditions previously described. Bushings are commonly field tested when new to confirm factory test data and to monitor for shipping damage, and then periodically tested following system disturbances or apparatus failures and routine outages. Table 3-2 reports the diagnostic techniques used most widely on bushings alone or installed together with their field of application. The present status and effectiveness of the techniques and specific references for further description of the method are also provided. Table Table 3-2 3-2:: Most Important Diagnostic Techniques Used fo r Bush ings PROBLEMS Moisture Corona Ageing Short-circuited condensers Internal surface leakage Poor connections 3.1.3 DIAGNOSTIC TECHNIQUES SERVICE CONDITIONS OF THE EQUIPMENT 5 STATUS OF THE DIAGNOSTIC TECHNIQUE 6 PROVEN EFFECTIVENESS OF THE DIAGNOSTIC TECHNIQUE REFERENCE 7 Capacitance/Power Factor Tap voltage OFF-S ON A A H M 34, 35, 36, 37 34, 35, 36, 37 DCHot-collar resistance Partial discharge (PD) Radio-influence voltage Capacitance/Power Factor DC resistance Capacitance/Power Factor Tap voltage PD/RIV Capacitance Power Factor AC dielectric loss Infrared scanning OFF-S OFF-S OFF-S ON OFF-S OFF-S OFF-S ON/OFF-S A A B B A A A A A A A A L H M/L M H L H M M/L M H H 34,3737 37 37 34, 35, 36, 37 34, 37 34, 35, 36, 37 34, 37 34, 37 34, 37 37 37 OFF-S OFF-S OFF-S ON DIAGNOSTIC METHODS FOR SURGE ARRESTERS Surge arresters areelectrical used asnetwork. protective devices to of limit of possible overvoltages in the However, most thethe timeamplitude they are expected to function as insulators. According to service experience, most of the trouble caused by surge arresters comes from the deterioration of this "insulator function." The majority of arresters in service are still of the so called conventional type, i.e. mad madee of the series combination of active gaps and non-linear silicon carbide (SiC) resistors, encapsulated in a porcelain housing. For this type, the withstand voltage relies mainly on the gaps, spacers, and the external grading rings used in higher voltage applications. 5 6 OFF-S = equipment out of service at site, OFF-L = equipment out of service in laboratory, ON = equipment in service 7 A = generally applied, B = development stage H = high, M = medium, L = low 76  A very important feature is that the voltage distribut distribution ion across the several gaps in series is controlled by "grading" non-linear resistances and also sometimes by internal capacitors. Nowadays, Metal Oxide Varistors (MOV) are able to perform the voltage clamping function as well as the insulator function: several tens of non-linear zinc oxide (ZnO) varistors are connected in series, and gaps are no longer needed in MOV arresters. arresters. 3.1.3.1 STRESSES A CTING ON SURGE ARRESTERS In addition to the obvious electric stress, arresters are also exposed to substantial thermal stress. Sizeable temperature increase is caused by normal duty operation or by external potential redistribution due to pollution or salt in combination with rain or fog. In the latter case, internal discharges may also occur, generating reactive species that can cause internal surface deterioratio deteriorationn in the arrester. Mechanical stresses are normally taken entirely by the porcelain insulator, whereas the active arrester parts are well protected protected.. 3.1.3.2 DETERIORATION FACTORS AND F AIL URE MECHANISMS The insulator function of arresters can be deteriorated in several ways: Moisture ingress: Condensation and corrosion inside the arrester can affect the dielectric withstand of insulating pieces and surfaces, and the spark-over characteristics characteristics of the gaps can also be affected. Tightn Tightness ess is a must for good performan performance ce of arresters. Heavy external pollution: The surface currents on heavily contaminated housings, especially for multi-unit arresters, affect the voltage distribution and may create important temperature rises, jeopardizing the grading system of conventional arresters or the blocks in MOV arresters. Discharges inside the arresters: Decomposition products resulting from gas discharges in the arrester can impair the chemical stability and the dielectric surface properties of the internal parts, especially of the varistors. Varistor deteriorations: ZnO blocks in MOV arresters, as well as grading resistors in SiC gapped type arresters, may suffer from changes of their characteristics during service. This results in higher leakage currents and losses. For conventional arresters, the final stage of deterioration is sparking at service voltage; for MOV arresters, the final fi nal stage is thermal runaway. Grading Gra ding c apacit apacit or deterioration: Less frequent than grading resistor deterioration, deterioration, but essentially the same effect. Gap Ga p deterioration by arrester duty: Spark-over characteristics will be affected. The failure rate of arresters depends on the keraunic level (number of thunderstorm days/year), the system voltage, and the margin used in the selection of the rated voltage. For1/1,000 healthyper and well-designed arresters, the failure rate should not be higher than about year. 77  Once a particular category of arresters (make, environment, age) suffers from one of the above-mentioned problems, the failure rate becomes much higher. Diagnostic techniques are then necessary to make decisions on the replacement replacement policy. Otherwise diagnostic techniques techniques are not likely to be more intensively used than just being included in the maintenance programs. 3.1.3.3 IAGNOSTIC D ETHODS M Table 3-3 summarizes the diagnostic techniques used most widely for surge arresters, together with their field of application, present status, effectiveness, and specific references. Table 3-3: Most Important Diagnostic Techniques Used for Surge Arresters PROBLEMS DIAGNOSTIC TECHNIQUES TECHNIQUES SERVICE CONDITIONS OF THE EQUIPMENT 8 STATUS OF THE DIAGNOSTIC TECHNIQUE 9 PROVEN EFFECTIVENESS OF THE DIAGNOSTIC TECHNIQUE REFERENCE 10 CONVENTIONAL SURGE ARRESTERS - Visual inspection External pollution -current Measurement of external leakage ON ON A ? L L Heating of grading resistors -Thermovision ON A M Deterioration of grading system - Leakage current under controlled voltage - Watt loss under controlled voltage - 60 Hz spark-over voltage OFF-S OFF-S OFF-S A A A H H H ON ON A ? L L ON ON ON ON OFF-L A A A B A L M H H H 38 38 38 METAL-OXIDE SURGE ARRESTERS External pollution Deterioration of varistor blocks - Visual inspection - Measurement of external leakage current - Leakage current - Harmonic decomposition of leakage current - Peak of resistive current - 3rd harmonic of resistive current - Reference voltage 8 9 OFF-S = equipment out of service at site, OFF-L = equipment out of service in laboratory, ON = equipment in service A = generally applied, B = development stage 10 H = high, M = medium, L = low 39 38 40 78  3.2 GENERAL DIAGNOSIS TOOLS 3.2.1 3.2.1.1 OIL QUALITY ASSESSMENT FACTORS A FFECTING THE HEALTH AND L IFE OF POWER T RANSFORMERS 11 The three main componen components ts subject to deteriorat deterioration ion and contamination in a transformer transformer are the paper, which is used for conductor insulation; the pressboard, which is used for the major insulation and winding support; and the insulating oil. Water, air or gas bubbles, particles of different origin, oxygen, and oil ageing products are agents of degradation. degradat ion. The presence of these elements in the transform transformer er can directly reduce the dielectric strength of the insulation system or result in acceleration of the rate of ageing of the insulation system. The level of possible contamination of a transformer over years depends on its design, especially on the effectiveness of the oil preservation system, and sources of contamination. Detection of possible sources of contamination in the particular transformer is a critical step of its condition assessment. The CIGRE working group 12.18 has suggested some possible sources of typical contamination that are listed in Table 3-4. The objects of primary concern should be transformers that have poor sealing, worn-out oil pump bearings, sources of overheating, aged oil and free-breathing transformers operating with variable load. Table 3-4: Sources of Typical Contamination of Power Transformers Contaminant Source Storage Mode Water Entering as a Vapor  Direct exposure exposure of the in insulation sulation to air dduring uring in installation stallation and inspection. of wet air through  Ingress by viscous movement of unsealed oil expansion systems (conservator tanks) and through loose or cracked gaskets (at flange connections).  As a byproduct of the age ageing ing ooff the insulation system Liquid Water  Damaged water heat exchangers.  When the transformer is unde underr less tha thann atmospheric pressure because of bad gaskets and loose connections (the top seal of draw-lead bushings, the seals in explosion vents, leaks through poor sealing of nitrogen blanketed transformer).  Condensation in the coolest regions.  From manufacturing process  Dress and test dirt  Oil ageing  Wear of aged cellulose  Overheating of metals (carbon)  Carbon from OLTC  Wear of the pump bearings  Most ooff the water is stored in the thin structure that operates at oil bulk temperature (20-30% of the total insulation mass). zones” s” (typically bottom  Presence of “wet zone part of insulation of outer winding).  Concentration in the vi vicinity cinity ooff hotspots  Bound water-in–oil.  Typically on the bo bottom ttom parts of of the tank and coolers.  Diffusion into the oil.  Temperature migration.  Movement of ice by ooilil flow. Particles 11  Migration in oil.  Sediment under eeffect ffect of gravity, oil flow and particularly effect of electrical and electromagnetic field that attracts the conductive particles and stimulates depositing them on the winding surfaces, pressboard barriers, and bushing porcelain. This section is extracted by permission from CIGRE WG12.18 – Brochure N° 227, 2003 ‘Life Management of Transformers’, CIGRE, Paris 79  Processes of insulation deterioration involve slow diffusion of water, gases, and ageing products, and therefore affect basically only a part of the insulation structure, the so called “thin structure” (conductor insulation, pressboard sheets, etc.), which comprises typically 40-60 % of the total mass. The moisture distribution is a function of the system moisture content, thermal distribution, and the dimensions the cellulosic structures. Parts higher of the insulation that arealso in contact with less l essof heated layers ofinsulation bulk oil may have notably moisture content. Hydrolysis is a dominant mechanism of insulation ageing decomposition at normal operating temperature. Accordingly, adsorbed moisture and oil ageing products (acids particularly) have to be considered in order to estimate the degree of ageing. The heated mass of conductor insulation (hotspots) that is subjected to accelerating decomposition due to elevated temperature and contributes to formation of by-products, comprises typically 2-10 % of the total mass of transformer insulation. Those heated zones are usually inaccessible for visual inspection or sampling. However, water and acids affect the outer layers of insulation, which are quite accessible for inspection. Information about thermal distribution across the winding is vital to assess the ageing state of insulation. Based on these observations, a review of the methods used to assess the level of contamination in the insulation of transformers is presented below. 3.2.1.2 3.2.1.2 3.2. 1.2.1 .1 METHODS FOR A SSESSING THE QUALITY OF T RANSFORMER OILS Dielectri c Breakdow n Strength (BDV) This test measures the voltage at which the oil electrically breaks down. The test gives a good indication of the amount of contaminants (water, dirt, oxidation particles, or particulate matter) in the oil. The property is measured by applying a voltage between two electrodes under prescribed conditions under the liquid. There are two ASTM procedures: D-877, which specifies a test cup equipped with one-inch diameter vertical electrodes that are 0.100 inch apart; and ASTM D-1816, which specifies a test cup equipped with spherical electrodes spaced either 1 mm or 2 mm apart. This cup includes a stirrer and is therefore sensitive to small amounts of particulates. In the latest IEEE guide for acceptance and maintenance of insulating oils in equipment, it is stated that the preferred method for assessing the dielectr dielectric ic breakdown of transformer oil is the ASTM D-1816 (Note: this is at least 2000 or newer) method. This is because the electrode configuration of the D-1816 method more closely approximates transformer application. Moreover, the method provides a higher sensitivity to the presence of particles and moisture that are detrimental to the operation of transformers. 3.2.1.2 3.2. 1.2.2 .2 Interfaci al Tension (IF (IFT) T) This test (ASTM D-971-99a) is used to determ determine ine the interfac interfacial ial tension between the oil sample and distilled water. The oil sample is put into a beaker of distilled water at a temperature tempera ture of 25 °C. The oil should float because its specific gravity is less than that of water. There should be a distinct line between the two liquids. The IFT number is the 80  amount of force (dynes) required to pull a small wire ring upward a distance of 1 cm through the water/oil interface. A dyne is a very small unit of force equal to 0.000002247 pound. Good clean oil will make a very distinct line on top of the water and give an IFT number of 40 to 50 dynes per centimeter of travel of the wire ring. As the oil ages, it is contaminated by tiny particles (oxidation products of the oil and paper insulation). These extend water/oil weaken the tension between theparticles two liquids. Theacross more the particles areinterface present,line the and weaker the interfacial tension and the lower the IFT number. The IFT and acid numbers together are an excellent indication of when the oil needs to be reclaimed. Low IFT numbers are an indication of highly contaminated oil, which can lead to sludging. If such oil is not reclaimed,, sludge will settle on windings, insulation, etc., and cause loading and cooling reclaimed problems. There is definitely a relationship between the acid number, the IFT, and the number of years in service. The accompanying curve (see Figure 3-1) shows the relationship and is found in many publications (this chart was originally published in the AIEE transactions in 1955). Notice that the curve shows the normal service limits both for the IFT and the acid number. 3.2.1.2 3.2. 1.2.3 .3 Aci d Neutr Neutr alizatio n Number The acid number (acidity) is the amount of potassium hydroxide (KOH) in milligrams (mg) that it takes to neutralize the acid in 1 gram (g) of transformer oil. The higher the acid number, the more acid that is in the oil. New transformer oils contain practically no acid. Oxidation of the insulation and oil forms acids as the transformer ages. The oxidation products form sludge and precipitate out inside the transformer. The acids attack metals inside the tank and form soaps (more sludge). Acid also attacks cellulose and accelerates insulation degradation. Sludging has been found to begin when the acid number reaches 0.40. At this point it is necessary to reclaim or replace the oil. The acid number is measured using the latest version of ASTM method D974. Figure 3-1 shows a plot of the relationship between acid number and interfacial tension as a function of the number of normal years of service for a transformer. 81  Figure 3-1: Interfacial Tensio Tensio n, Acid Number, and Ye Years ars in Servi Servi ce 3.2.1.2 3.2. 1.2.4 .4 Power Factor Power factor indicatesand/or the dielectric loss leakage currentsuch of the A high power indicates deterioration contamination by-products asoil. water, carbon, or factor other conducting particles; metal soaps caused by acids; attacking transformer metals; and products of oxidation. The test method for power factor is the latest version of ASTM D924, and the measurement is typically performed at 25 °C and 100 °C. Some ionic contaminants can often pass undetected at 25 °C but will reveal their presence as unacceptably high readings in the 100 °C test. ABB recommends always measuring the oil power factor at both suggested temperatures. temperatures. A high power factor at 25 °C and a low power factor at 100 °C typically indicate the presence of moisture, since the moisture will evaporate at 100 °C. On the other hand, a high power factor reading at both temperatures tempera tures or only at 100 °C typically indicates the presence of contam contaminants. inants. 3.2.1.2 3.2. 1.2.5 .5 Test for Oxygen Inhib ito r Moisture destructive to cellulose and even more so in the presence of oxygen. Itoil. is therefore is important to mitigate the effects of the presence of oxygen in transformer Oxygen inhibitors are the key to minimizing the effects of oxidation of oil. The two most common inhibitors used are 2-6 ditertiary butyl para-cresol (DBPC) and ditertiary butyl phenol (DBP). The first choice of attack by oxygen in the oil is the inhibitor molecules. This keeps the oil free from oxidation and its harmful by-products. However, as the transformer ages, the inhibitor is used up and needs to be replaced. Oxygen inhibitor content is measured using the latest version of ASTM method D2668. 3.2.1.2 3.2. 1.2.6 .6 Furan Analys is 2-Furfuraldehyde and some related substances, all belonging to a group of chemical compounds called furans, are formed when paper degrades. High furan content or a high production rate may indicate a high rate of paper degradation. When DGA results are not conclusive, furan analysis may aid the interpretation and give a more accurate 82  diagnosis. Section 3.3.2.2 provides a detailed discussion about analysis of furans in transformers. 3.2.1.2.7 3.2.1.2 .7 PCB Cont ent Environmental legislation legislation often requires that oil contamina contaminated ted with PCB is given special treatment. For this reason service providers may sometimes refuse to handle oil that has not been proven PCB-containing oil. to be PCB-free. There may also be strict rules for the disposal of 3.2.1.2 3.2. 1.2.8 .8 Corro sive Sulph ur In recent years there have been a significant number of failures, in different types of equipment, due to the formation of copper sulphide in the cellulosic insulation. Also, other problems due to the action of corrosive sulphur compounds in oil have been reported. It has become apparent that commonly accepted tests for corrosive sulphur used in oil specifications (ASTM D1275 (copper strip) or DIN 51353 (silver strip)) are not adequate. Several oils that have passed these tests have caused copper sulphide formation in real life and in some cases have resulted in failure of the transformer. New tests have been developed that have higher sensitivity and are more relevant for the failure (ASTM mechanisms A and newa more severe copper strip testtest has been introduced D1275 involved. method B), covered conductor deposition (“CCD”) has been developed to identify oils that may cause copper sulphide precipitation in cellulosic insulation. A simplified version of the latter test is presently under consideration as a new IEC standard test for corrosive sulphur. 3.2.1.3 MOISTURE IN TRANSFORMER INSULATION SYSTEMS [41] The presence of moisture in a transformer deteriorates the transformer insulation by decreasing both the electrical and mechanical strength. In general, the mechanical life of non-upgraded Kraft paper insulation is reduced by the presence of moisture; the rate of thermal deterioration of the paper is proportional to its water content [42]. Recent studies performed performed by SINTEF Energy Research have shown that if normal life is defined as ageing under dry, oxygen-free oxygen-free conditions, a moisture content of 1 % in non-upgrade non-upgradedd Kraft insulation can reduce life expectancy to 30 % of normal life. For 1 % moisture content in thermally upgraded Kraft insulation, the life expectancy is approx approximately imately 60 % of normal life. If the moisture content increases to 3-4 %, the life expectancy of the nonupgraded Kraft insulation will drop to approximately 10 % of normal life expectancy and thermally upgraded Kraft insulation will drop to approximately 25 % of normal life expectancy [43]. Electrical discharges can occur in a high-voltage region due to a disturbance of the moisture equilibrium equilibrium causing a low partial discharge inception voltage and higher partial discharge intensity [44]. Water in mineral oil transformers also brings the risk of bubble formation when water from the surface of the cellulosic insulation migrates into the oil and increases the local concentration of gases in the oil [45]. In the upcoming sections we discuss the presence of water in the main components of insulation system: oil and paper. 83  3.2.1.3 3.2. 1.3.1 .1 Transform er Oil Mineral transformer insulating oils are refined from predominantly crude oils. The refining processes could include solvent extraction, dewaxing, hydrogen treatment, or combinations of these methods to yield mineral insulating oil that meets the specification. It is mainly a mixture of hydrocarbon compounds of three classes: alkanes, naphthenes, and aromatic hydrocarbons. These molecules have little or no polarity. Polar and ionic s pecies areand a minor part properties of the constituents, their presence may greatly influence thespecies chemical electrical of the oil. but Polar c ompounds compou nds found in transformer oil usually contain oxygen, nitrogen, or sulfur. Ionic compounds are typically organic salts found only in i n trace quantities. Insulating oils, such as transformer oil, have a low affinity for water. However, the solubility increases markedly with temperature for normally refined naphthenic transformer oil. Water can exist in transformer oil in three states. In practical cases, most water in oil is found in the dissolved state. Certain discrepancies in examining the moisture content using different measurement techniques suggest that water also exists in the oil, tightly bound to oil molecules (bound (bound moisture), and especially in deteriorat deteriorated ed oil. When the moisture in oil exceeds the saturation value, there will be free water precipitated from the oil in suspension or drops. Moisture in oil is measured in parts per million (ppm) using the weight of moisture divided by the weight of oil (g/g). 3.2.1.3 3.2. 1.3.2 .2 Relative Humidi ty Relative humidity can be defined in terms of the moisture –mixing ratio r versus the saturation mixing ratio rs, %RH    rrs which is a dimensio dimensionless nless percentage. Relative humidity for air is the water vapor content of the air relative to its content at saturation. Relative humidity for oil is the dissolved water content of the oil relative to the maximum capacity of moisture that the oil can hold (the saturation limit). The higher the %RH, the closer the oil is to saturation. In a transformer, it is preferable to keep the %RH below 10-20 %, depending on voltage class (see Figure 3-2 for moisture content curves at different %RH). 84  Figure 3-2: Relative Humidity Curves for Transformer Oil 12 NOTE: NOT E: Below 30 °C, °C, the cur ves are not very accu rate. 3.2.1.3.3 3.2.1.3 .3 Paper (Cellu (Cellulo lose) se) The following four terms are often used interchangeably in the context of solid transformer insulation: pressboard, paper (or Kraft paper), transformer board, and cellulose. Although in the context of particular transformer insulation they may indicate different parts, e.g., paper tape, paper cylinders, transformer board cylinders, angle rings, blocks, etc. In the context of moisture equilibrium, they all generally refer to electrical-grade paper insulation manufactured from unbleached sulfate cellulose, basically consisting of a long chain of glucose rings. Insulation paper used in transformers can be completely dried, degassed, and oil impregnated. Insulation paper can be manufactured to different densities, shapes, and other properties for different applications. Water in paper may be found in four states: adsorbed to surfaces, as vapor v apor between between the cellulose fibers, as free water in capillaries, and as a bsorbed free water in the body of the insulation. The paper can contain much more moisture than the oil. For example, a 150 MVA, 400 kV transformer with about seven tons of paper can contain as much as 223 kg of water. If it is assumed that such a transform transformer er contains 80,000 liters of oil and assuming a 20 ppm moisture concentration in oil, the total mass of moisture in the oil is about 2 kg. This amount is much less than the moisture in the paper. The unit for moisture concentration in paper is typically expressed in percent, which is the weight of the moisture divided by the weight of the dry oil-free pressboard. 12 From IEEE Std 62-1995 85  3.2.1.3 3.2. 1.3.4 .4 Where Does the Wa Water ter Come From Moisture can be in the insulation when it is delivered from the factory. If the transformer is opened for inspection, the insulation can absorb moisture from the atmosphere. If there is a leak, moisture can enter in the form of water or humidity in air. Moisture is also formed by the degradation of insulation as the transformer ages. Most water penetration is the flow of wet air or rainwa rainwater ter through poor gasket seals due to pressure differences caused by some transformer cooling. During rain or snow, if apressure transformer is removed from service, transformer designs cool rapidly and the inside drops. The most common moisture ingress points are gaskets between bushing bottoms and the transformer top and the pressure relief device gasket. Small oil leaks, especially in the oil cooling piping, will also allow moisture ingress. With rapid cooling and the resultant pressure drop, relatively large amounts of water and water vapor can be pumped into the transformer in a short time. It is important to repair small oil leaks. The small amount of visible oil is not important in itself, but it indicates a point where moisture will enter the transformer. It is critical for life extension to keep transformers as dry and as free of oxygen as possible. Moisture and oxygen cause the paper insulation to decay much faster than normal and form acids, sludge, and more moisture. Sludge settles on windings and inside the structure, causing transformer cooling to be less efficient; therefore, the temperature rises slowly over time. Acids cause an increase in the rate of decay, which forms more acid, sludge, and moisture at a faster rate [46]. This is a vicious cycle with increasing speed, forming more acid and causing more decay. 3.2.1.3 3.2. 1.3.5 .5 Moist ure Equili bri um between Oil and Pape Paperr in Transfor mers Since there is more water in the cellulose than in the oil and a significant part of the protection of the transformer relies on the integrity of the cellulose insulation, it is important to know the moisture in the cellulose. Unfortunately, this cannot be measured directly without obtaining a sample of pressboard or paper from inside the transformer. Methods have been developed to estimate the moisture of the cellulose insulation from the moisture in the oil, based on the partitioning of water between the oil and the cellulose under certain conditions. When the transform transformer er is in equilib equilibrium rium operation, this provides a quick way of examining the moisture content in paper to predict future failure by measuring the moisture in oil. A set of moisture equi equilibrium librium curves is shown in Figure 3-3. The original curves have been modified to include the insulation moisture limits for different voltage classes of transformers. Given the average oil temperature of the transformer and the measured moisture content of the oil, the moisture content of the cellulose can be estimated from the chart in Figure 3-3. It can also be determined if the moisture content is excessive and action is required. Unfortunately, during regular operation of a transformer, the moisture in the oil and the cellulose are never in equilibrium. Moisture constantly migrates from the cellulose into the oil as the transformer load increases and the windings “heat” up. The reverse occurs when the load is reduced and the transformer windings “cool” down. Equilibrium is especially to establishoil at temperature low transformer situation improves somewhat difficult as the transformer getstemperatures. above 50 °C. ItThe is important for users of these curves to understand they may not be getting a true measure of the moisture in 86  the insulation. Advanced methods, such as the Dielectric Frequency Response (DFR) analysis allow the direct measurement of moisture in the cellulose insulation. This method is described in 3.3.3 of this handbook. 5.0 o 0 C o o 10 C o 20 C o 30 C 40 C 4.5 4.0 o 50 C 3.5 r e p 3.0 a P in e r 2.5 tu is o M2.0 % IEEE C57.106-2002 Insulation Moisture Limits o 60 C  69kV >69kV - <230kV  230kV o 70 C o 80 C 1.5 o 90 C 1.0 o 100 0.5 0.0 0 5 10 15 20 25 30 35 40 45 50 Moisture in Oil (PPM) Figure 3-3: 3-3: Oomme Oommen n Curves fo r Low Moisture Region Region of Moistu re Equilibrium fo r Pape Paper-O r-Oil il Systems [ 47]. (Note: Moistur e limit s fro m C57.10 C57.106-2 6-2002 002 and and s hown in Table 3-6 have been inserted into the equilibrium plot s.) In order to obtain the average temperature of the transformer, it is advisable to measure the temperature of the oil at the top and bottom oil sampling valves and then take an average. It is also advisable to use a calibrated thermometer for these measurements instead of relying on the readings of the temperature gauges. The data from the moisture equilibrium curves and the recommended limits for moisture in the solid insulation can be combined into a chart that gives the maximum allowed equilibrium moisture in the oil at any given temperature and each voltage range. This chart is shown in Figure 3-4. The chart indicates, for example, that at 60 °C the moisture content in a 145 kV transformer at equilibrium equilibrium should be no more than 30 ppm, whereas for a 69 kV transformer the limit is approximately 65 ppm. Based on the measured moisture in oil, the temperature, and the voltage class of a transformer, this chart can be used to provide some s ome indication of the moisture condition of a transfor transformer. mer. 87  Maximum Recommended Moist u re in Oil B ased on Maximum Re c o m me me n d e d M a xxii m u m M o i s t u r e i n C e l l u l o s e 10 0 ) m p p ( li O n i ti m i L e r u t s i o M  69kV 90 80 >69 - <230kV  230kV 70 60 50 40 30 20 10 0 0 10 20 30 40 50 60 o T e m p ( C) 70 80 90 10 0 Figure 3-4: Maximum Recommended Moisture in Oil versus Temperature 3.2.1. 3.2 .1.3 3.6 Ca Cautions utions in Estimation of Moisture Using Moisture Equilibri um Curves As discussed above, the moisture content of the oil samples taken from transformers can be measured using the Karl Fischer met method. hod. The moisture in the board is read from the equilibrium curves by projecting the measured moisture in oil onto the corresponding measurement temperature curve. There is potential for significant errors in this method at low temperatures and for low oil moisture contents due to the steepness of the equilibrium curves in this region. For example, if the measured moisture in oil is 10 ppm, and considering a measurement error of ±2 ppm, the moisture can range - 4.0 % weight 20 °Ctemperatures and betweenand 0.8 -much 1.1 %worse at 60 at °Clower (see Figure 3-5).from The3.2 spread is by smaller at athigher temperatures. If this method is to be used, the temperature of the insulation must be at least 50 °C in order to get reliable results. There is also always the question about whether the transformer is ever in equilibrium during normal operation. If there are concerns about the moisture content of the insulation, it is advisable that advanced diagnostic methods, such as dielectric frequency response, be used. 88  5.0 o o 0 C o 10 C o 20 C o 30 C 40 C 4.5 4.0 o 50 C 3.5 r e p 3.0 a P n i e r 2.5 u t is o M2.0 % o 60 C o 70 C o 80 C 1.5 o 90 C 1.0 o 100 0.5 0.0 0 5 10 15 20 25 30 35 40 45 50 Moistu re in Oil (PPM) (PPM) Figure 3-5: 3-5: Moisture Estimation Using Equilibriu m Curves 3.2.1.4 L IMITS FOR MEASUREMENT OIL QUALITY PARA METERS [48] The following tables (Table 3-5 and Table 3-6) show the various limits for assessing moisture in a transformer as set forth in the IEEE Std. C57.106-2002. These limits can be used as guidelines in making maintenance decisions about transformers. For example, if the %RH of water in the oil is greater than 30% and the corresponding moisture in the cellulose is greater than the limit specified for the voltage class, the transformer insulation may need to be dried. It would be advisable in this situation to contact ABB. Since a dry-out is an expensive process, advanced diagnostic methods, such as Dielectric Frequency Response (DFR), can be applied directly vverify erify the insulation moisture measurement. AnAnalysis independent assessment of a to fresh sample of oil would also be made to reassess the original diagnosis. Table 3-5: 3-5: G General eneral Guidelines fo r Interpretin g Data Expressed in Percent Sa Satur tur ation , - Condition of Cellulosic Insulation Percent Satur Satur ation Water in-Oil . 0-5 6-20 Dry insulation Moderate—wet, low numbers indicate fairly dry to moderate levels of water in the insulation. Values toward the upper limit indicate moderately wet insulation. Wet insulation Extremely wet insulation 21-30 >30 89  Table 3-6: Recommended Maximum Limit of Water Content in Mineral Insulating Oil of Operating Gas Blanketed, Sealed, Sealed, or Diaphrag m Conservator Transf orm ers a Av erag e Oil Temperature b Suggested Maximum Water Contents in mg/kg and Percent Saturation 50°C 60°C 70°C c c c mg/kg % saturati on mg/kg % saturati on mg/kg % saturati on 69 kV 27 15 35 15 55 15 >69 - <230 kV 12 8 20 8 30 8 230 kV and 10 5 12 5 15 5 greater NOTES 1 - These values are, by necessity, approximate but are adequate for f or maximum water-in-oil guides. 2 - The oil sample should, if practical, be taken when the load and oil temperatures have been relatively constant for 48 h. The intent is to obtain a sample when the moisture content in the transformer is close to equilibrium. If the load and/or ambient are variable, the oil temperature can be maintained relatively constant by controlling the amount of cooling in operation. If you are confident that the temperature gauges are in calibration, then record the top oil temperature at the time that the sample is taken. For Oil Natural Air Natural (ONAN) and Oil Natural Air Forced (ONAF) ratings, subtract 10 °C from the top oil to obtain the average oil temperature. If you are unsure of the gauge accuracy, record the actual sample temperature and add 5 °C to approximate the average oil temperature. 3 - The above values are based on the following approximate percent by weight of water in solid insulation values (see IEEE Std 62-1995):  69 kv 3% maximum >69 - <230 kv 2% maximum 230 kv and greater 1.25% maximum 4 - Saturation values (mg/kg) at 100% saturation: 50 °C - 175 / 60 °C - 245 / 70 °C - 335 a) The data in this table is from sealed transformers and may also apply to free-breathing type transformers. b) Calculated from formulas 1 and 2 in Clause 44 from Bruce, C. M., Christie, J. D., and Griffin. Paul [ 49] c) Equivalent measurement is parts per million, ppm. Table 3-7 and Table 3-8 are the recommended limits for oil quality tests performed on new and service aged transformers (always refer to the latest IEEE standards for the current suggested limits). Note that these are the suggested limits for acceptable conditions. If any measurements measurements are beyond the suggested limits, it is advisable to take another sample to confirm the first result. If the results are confirme confirmed, d, it is recommended you contact ABB for advice on further action. Table 3-9 provides some guidelines on actions to be taken based on the results of oil quality measurements. measurements. Table 3-7 3-7:: Test Limi ts for New Mineral Insulating Oil Re Received ceived in o r Processed fo r Ne New w Equipm ent Test and Method 69 kV Dielectric strengtha, ASTM D1816-97, kV minimum, 1 mm gapb: 2 mm gapb: Dissipation factor (power factor), ASTM D924-99e1, 25°C , % maximum: 100°C, %maximum: Interfacial tension, ASTM D971-99a, mN/m minimum: Color, ASTM D1500-98, ASTM units maximum: Visual examination, ASTM D1524-94 (1999): Value for Voltage Class >69 - <230 kV 230 kV - <345 kV 345 kV and above 25 45 30 52 32 55 35 60 0.05 040 0.05 040 0.05 0.30 0.05 0.30 38 38 38 38 1.0 1.0 1.0 0.5 Bright and clear Bright and clear Bright and clear Bright and clear 90  Test and Method 69 kV Neutralization number (acidity), ASTM D974-02, mg KOH/g maximum: Water Content, ASTM D1533-00, mg/kg maximumd: Oxidation inhibitor content when specified, ASTM D2668-96, Type I oil, % maximum: Type I oil, % minimum: Type II oil, % maximum: Type II oil, % minimum: Total dissolved gas, ASTM D2945-90 (1998): 0.015c Value for Voltage Class >69 - <230 kV 230 kV - <345 kV 345 kV and above 0.015c 0.015c 0.015c 20 10 10 10 0.3 >0.08 0.08 0.0 0.3 >0.08 0.5% or per 0.5% or per manufacturer’s manufacturer’s requirementse e requirements a) Oil dielectric testing in accordance with ASTM D877-00 has been replaced by ASTM D1816-97. b) Alternate measurements of 0.04 in and 0.08 in respectively for gaps. c) This value is more stringent than the ASTM D3487 requirement. d) Equivalent measurement is parts per million, ppm. e) This value should be obtained from a sample collected 24 to 48 hrs after the transformer is filled and applies only to transformers with diaphragm conservator systems. Table Table 3-8 3-8:: Suggested Li mits for Continu ed Use of Service-Aged Service-Aged Insulating Oil Test and Method 69 kV Dielectric strengtha, ASTM D1816-97, kV minimum, 1 mm gapb: 2 mm gapb: Dissipation factor (power factor) a, ASTM D924-99e1, 25oC, % maximum 100oC, % maximum Interfacial tension, ASTM D971-99a, mN/m minimum Neutralization number (acidity), Value Value for Voltage Class >69 - <230 kV 230 kV and abov e 23 40 28 47 30 50 0.5 5.0 0.5 5.0 0.5 5.0 25 30 32 ASTM D974-02, mg KOH/g maximum 0.20 0.15 0.10 Water content Refer to Table 3-6 Oxidation Inhibitor Content, ASTM D2668-96, Type II Oil 0.09% minimum, if in original oil. a) Older transformers with inadequate oil preservation systems or maintenance may have lower values. b) Alternate measurements of 0.04 in and 0.08 in respectively for gaps. 91  Table 3-9: 3-9: Ma Maint int enance Guidelin es for In-Service Oils [ 50] o Power Factor Results at 25 C Suggested Action 0.5% Acceptable >0.5% but 1.0% Investigate. Oil may require replacement or clay treatment. >1.0 but 2.0% Investigate. Oil may cause failure of equipment. Oil may require replacement or clay treatment. 2.0% Remove from service. Investigate. Oil may require replacement or clay treatment. Neutralization (mg K OH/gm) Results Suggested Action <0.05 Acceptable 0.05 but <0.15 Clay treat or replace at convenience. For 345 kV, clay treat or replace oil in immediate future. 0.15 but <0.50 Clay treat or replace oil in immediate future. 0.50 Replac Replace e oil. IFT (dynes/cm) Results Suggested Action 25 Acceptable 22 but <25 Clay treat or replace at convenience. For 345 kV, clay treat or replace oil in immediate future. 16 but <22 Clay treat or replace oil in immediate future. <16 Replac Replace e oil. 3.2.1.5 MOISTURE AND B UBBLE EVOLUTION IN T RANSFORMERS Water in a transformer reduces the insulation capability in the active part. Water affects the electric strength, power factor, ageing, losses, and mechanical strength of the insulation [51,52]. Not only does moisture in the cellulose decrease the breakdown strength of the insulation system and increase the ageing process, there is also potential danger due to enhanced chances of partial discharge activity and eventual breakdown of the insulation. Bubbles in a transformer may arise from several causes: 1) excessive gas generation from faults, 2) nitrogen supersaturation in the case of gas-blanketed units, and 3) gas/vapor release from overload conditions, particularly for paper insulated systems such as large and medium power transformers. In experiments on gas evolution performed at ABB [53, 54, 55], the following key observations were made: o o Bubble evo evolution lution tem temperature perature dec decreased reased ex exponentially ponentially with increa increasing sing m moisture oisture content. Bubble evo evolution lution tem temperature perature dec decreased reased ssignificantly ignificantly w with ith increasing gas conten contentt of oil at high moisture levels in the cellulose insulat insulation. ion. 92  The studies revealed that bubble evolution in paper-wrapped windings under overload conditions is significantly influenced by the moisture in paper which tends to be released as bubbles. At low moisture levels in paper, systems with low gas content and gas saturated systems behave somewhat similarly. It appears the dissolved gas is not the determining factor for bub bubble ble generation. Indeed, the data showed that bubble evolution from overload conditions may not happen below 200 oC in very dry transformers, regardless of the gas ocontent. A service aged transformer with two percent moisture may release at 140 C when overloaded. An empirical mathematical relationship to predict bubble evolution temperature [56] is shown graphically in Figure 3-6. 200 Values are calculated for 1 atmosphere 180 Gas o C Content , e r u t 160 a r e p m e T n o it u l o v 140 E e l b b u B 0% 1% 2% 3% 4% 5% 6% 7% 8% 9% Zer o ga s content systems Obser ved for N2 satur satur ated sys systems tems 120 100 0.0 1 .0 2 .0 3.0 4 .0 % Mois ture in Coil Figur e 3-6: 3-6: Bubble Evolu tion Temperatur e vs. M Mois ois ture Content in Paper Paper and Gas C Cont ont ent in Oil If the loading guidelines suggested by IEEE Std C57.91 for transformers under various load conditions are superimposed on Figure 3-6, some rather critical decisions can be 93  made for what transformers can be operated under what load conditions. The resulting chart is shown in Figure 3-7. 200 190 180 o Z er er o ga s content C 170 , e r u t 160 a r e p m e T 150 n o ti lu o v 140 E e l b b u 130 B Normall L ife Expectancy Loading Norma Planned Loading Beyond Nameplate Long-term Emergency Loading Short-term Emergency Loading Observed for N2 saturated systems 120 110 100 0 .0 1 .0 2 .0 3.0 4 .0 % Moisture in Coil Figure 3-7: 3-7: Loading Guidelines Based on Moisture Content of Cellulose Cellulose Insulation The loading guidelines shown in Table 3-10 can be derived from Figure 3-7 and IEEE C57.91. The table should be read as follows: a transformer with approximate gas content of 9 % and moisture content of up to 2.0 % can be operated under long-time emergency so be long as the hottest spot temperature never exceeds Another 140 °C. However, it conditions should never operated under short-term emergency conditions. important observation is that transformers with insulation moisture content greater than 0.8 % may be exposed to significant risk of failure if operated under short-term emergency loading conditions. 94  Table 3-10: Loading Limits Based on Moisture Content Hottest Spot Temperature ° ( C) Cellulo Ce llulo se Moisture (%) Zero gas N2 saturated content system system 120 130 3.9 2.9 3.3 2.6 140 2.2 2.0 180 0.8 0.8 Overload Type Normal Loading Planned O/L Beyond N/P Long Time Emerg. (1-3 mo.) Short-Time Emerg. (½ -2 hrs) Overload Level with 40°C Ambient 0% 6% 12% 40% A word of caution should be given here regarding the preceding discussion. It is our experience that an accurate determination of the transformer hotspot temperature, especially on older transformers, can only be made after an updated engineering calculation using modern design programs. programs. Relying on readings from hotspot gauges or on test reports may result in significant underestimation (or in some cases overestimation) of the true hotspot temperatures. Also before it is important to aget a proper measure of the moisture content of the paper insulation subjecting transformer to overload conditions. At present, the Dielectric Frequency Response method (see section 3.3.3.4) is the most accurate means of estimating the moisture content of the paper insulation in transform transformers. ers. For most transformers, especially those that are continuously loaded, a more significant si gnificant effect of moisture in the insulation is the increased ageing associated with the moisture in the cellulose insulation. Ageing calculations given in IEEE Std C57.91 assume dry, oxygen-free insulation. insulation. Dry insulation is assume assumedd to be approximately 0.5% moisture or less. Field measurements done by ABB have demonstrated that most transformers in the utility network have moisture levels higher than this. Since the ageing rate of insulation is dependent on the temperature, the moisture level in the insulation, and the oxygen in the dry oil, transformers. the actual ageing rates are often much higher than might be assumedlevel for normal 95  3.2.2 3.2.2.1 DISSOLVED GAS IN OIL ANALYSIS (DGA) [57] INTRODUCTION For many years the method of analyzing gasses dissolved in the oil (DGA) has been used as a tool in transformer diagnostics. The method has been used for several purposes: to explanation detect incipient to supervise suspect transformers;which to test hypothesis or for thefaults; probable cause of failures or disturbances havea already occurred; and to ensure that new transformers are healthy. DGA could also be used as part of a scoring system in a strategic ranking of a transformer population. What is said about DGA for transformers is also applicable to reactors, instrument transformers and bushings. It is worth noting that DGA is a fairly mature technique and is employed by several ABB transformer companies around the world either in own plant or in co-operation with affiliated or independent laboratories. In assessing dissolved gases in oil, the rate of increase of different gases during a time interval is the most important indicator of the health of the unit. The actual gas levels may of may not be of consequence for the operation or the health of the transformer. The idea behind the use of dissolved gas analysis is based on the fact that during its lifetime, all oil/cellulose insulated systems generate decomposition gases under the influence of various stresses - both norma normall and abnormal. The gases that are of interest for the DGA ana analysis lysis are shown in Table 3-11. Table 3-11 3-11:: Diss olved Gases in Min eral O Oil-fill il-fill ed Transf Transf orm ers Gas Ga s Symbol Hydrogen Methane Ethylene Ethane H2 CH4 C2H4 C2H6 Acetylene Propene 2 2 C C3H H6 Propane C3H8 Carbon monoxide monoxi de Carbon dioxide Oxygen CO CO2 O2 Nitrogen N2 TDCG Total dissolved combustible gases Comments Not used under ANSI/IEEE standards Not used under ANSI/IEEE standards (=H2+CH4+C2H4+C2H6 +C2H2+CO) All gasesThe except oxygen nitrogendistribution may be formed during the depend degradation of the these insulation. amount and and the relative of these gasses on the type and severity of the degradation and stress. 96  Over the years several different schemes have been proposed as evaluation schemes for DGA. Severa Severall of these techniques are presented in the IEEE Standard C57.104 and IEC Publication 60599. A number of faults can not be detected by DGA. One example is faults that are not in contact with the oil. Other examples are faults in which only very small energies are released or in which the energy is spread over a large surface or large volume. Such faults are typically associated with sporadic discharges or weak discharges. 3.2.2.2 PROCEDURE The procedure for performing DGA consists of essentially four steps: - Sampling of oil from the transformer - Extraction of the gases from the oil - Analysis of the extracted gas mixture through gas chromatog chromatography. raphy. - Interpretat Interpretation ion of th thee analysis according to an evaluation scheme scheme.. 3.2.2.3 SAMPLI NG Suitable locations for sampling are valves in the cooler/radiator circuit. Because of design limitations it may not always possible to take samples from these locations. Other places from which to draw samples are the cover, bottom valve, the conservator and from the Buchholz relay. In addition, care must be taken to make sure the sa sample mple is not exposed to the atmosphere and that gases are not lost during sampling or transportation to the laboratory. For more general information about sampling of gases refer to the latest version of IEC Standard 60567 or ASTM Standard 3613. Figure 3-8 shows the sampling methodology used by ABB. 3.2.2.4 EXTRACTION The removal of the gases from the oil can be accomplished by various methods: methods: - Partial degassing (single-cyc (single-cycle le vacuum extraction) - Total degassing (multi-cycle vacuum extraction) - Stripping by flushing the oil with another gas. - The he head-space ad-space technique in which gases are “equalized” between a ffree ree ggas as volume and the oil volume. 3.2.2.5 A NALYSIS After extraction the gas mixture is fed into adsorption columns in a gas chromatograph (GC) where the different gases are adsorbed to various degrees and reach the detector after different periods of time. In this way the gas mixture is separated into individual chemical compounds and their concentrations are calculated in volume gas at standard temperature and pressure (STP) per oil volume and expressed in parts per million (ppm). It should be emphasized that this extraction and analysis may involve analytical errors. It mayshould therefore be difficult from try twotodifferent laboratories. One not jump from to onedirectly lab tocompare another results but instead stick with one wellreputed lab. 97  SAMPLING OF OIL FOR GAS ANALYSIS Important things to consider : The syringe piston must be clean at use. Used hoses shall not be returned to ABB Transformers. Please remember to note the number of the syringe in the questionaire. Connect the hose and T-piece to the syringe according to the picture. Connect the hose from the sampling valve to the T-piece. Put the hose with the T-piece in a bucket and open the valve on the transformer. Flush min. 3 times the valve and hose volume. Let the oil flow during the sampling. Turn the handle on the syringe valve as in the picture and suck carefully in about about 15 ml. of oil into the syringe. Hold the syringe so that the valve points upwards and press the air and oil out. No airbubbles should be left. Suck carefully 20 ml of oil into the syringe. No air bubbles shall be seen in the syringe. Close the valve on the syringe by turning the handle on the syringe valve as in the picture. Setfo/ta 980903 KR Gasanalys provtagning engelsk Figure 3-8: ABB Method for Sampling Oil for Gas Analysis 98  3.2.2.6 INTERPRETATION In order to properly interpret the results of the gas analysis, it is necessary to determ determine ine the gas production rate for the period period under consideration, i.e. how much the gas levels have changed over a given time period. The absolute gas levels seldom give a sufficient s ufficient good basis for the interpretatio interpretation. n. 3.2.2.7 AIR Oxygen (O2) and nitrogen (N2) come from the air. Air contains about 20% oxygen and about 80% nitrogen. The levels in the oil could be respectively 30,000 and 80,000 ppm at air saturation. Oxygen and nitrogen have different solubility in oil. It is unusual to measure oxygen levels below 1,000 ppm and nitrogen levels below 2,000 ppm. The air content may be used to check the sampling procedure. The air content must not jump up and down between subsequent samples. samples. If that is the case, one can suspect that the samples have not been taken with sufficient accuracy. The oxygen level could decrease at high temperatures of the oil. Oxygen is also consumed during periods of strong ageing of oil and cellulose. A small amount (up to 200 ppm) of carbon dioxide, CO 2 may also come from air, but only if the oil is i s saturated with air (around 10%). 3.2.2.8 3.2.2.8 3.2. 2.8.1 .1 GAS SPECTRUM – TYPES OF F AULT S Hot Metal Surface  The hydrocarb hydrocarbons: ons: methane (CH4), ethylene (C2H4), ethane (C2H6), propene (C3H6), propane (C3H8) etc. are mainly produced produced from hot oil.  Acetylene (C2H2) is not produced unt untilil temperatures close to 1000 ºC. One example is glowing spots due to circulating currents in the ccore. ore.  The oil boils boils at arou around nd 32 3200 ºC. This m means eans tha thatt that it is difficu difficultlt to obta obtain in a stab stable le temperature on a metal surface above this temperature limit.  The oil starts to degrade already at 80-100 ºC, even if the degradation rate is very slow. One a higher temperature form fores. example C2H4eramakes nd C3Hit6possible than CHto4 and C3H8.needs More gas is formed at higher to temperatur temperatures. This togeth together use ratios between hydrocarbons to get an estimation of the temperature around the fault. 3.2.2.8 3.2. 2.8.2 .2 Examples of Hot Metal Surfaces The following are examples of situations in a transformer that could result in hot metal faults:  A bolted joint w which hich ha hass lost totally or partly its clam clamping ping fo force rce  A very high high resistance betwe between en the cleats and lea leads ds and the bus bushing. hing.  A damaged damaged draw rod or a wrongly assembled assembled draw rod that m makes akes a bad contact at the connection.  Bad contact in soldered or welded leads.  When there is a current running in the draw rod of the bushing. contacts fro from m the selecto selectorr that becomes hot w with ith tim time. e.  Sliding contacts  Currents due to stray fluxes in the tank. 99   Inadvertent grounds that create circulating current currents. s.  Increased Increas ed resist resistance ance of the selector contacts for the tap changer.  Circulating currents in the core. A low res resistance istance betw between een ddifferent ifferent cor coree steel packages or to metallic parts or to high burrs on the sheets.  Induced currents currents ddue ue to non com compensated pensated cur currents rents in the cor coree window window..  Currents in metal ppieces ieces which should have bbeen een insulated or or which have damaged damage d insulation. Consider which joints there are in the unit, core c ore bolts, etc.  Closed loops loops fo forr cur currents rents bbecause ecause of dam damaged aged insulation between between parallel parallel conductors.  The insulati insulation on of the steel band aaround round the core becomes damaged. damaged. 3.2.2.9 OVERHEATED CELLULOSE Carbon oxide (CO) and carbon dioxide (CO2) come mainly from hot cellulose. They are produced at moderate temperatures temperatures (< 150 ºC) with the ratio CO/CO2 = 0.3. 3.2.2.9 3.2. 2.9.1 .1 Examples of Overheated Cell Cell ulos e  Overheated conductor insulation  Insulated Insulat ed multiple grounds which conduct a high current Parallel conductors conductors with com common mon covering w which hich com comee into electrical contact with each other Conductors for the cleats and leads Winding conductors, obstructed cooling, loosened/w loosened/wrongly rongly po positioned sitioned oil gu guiding iding ring  Overcurrents because of leakage fields  Circulating currents in the yoke bolts  Any of the conditions in tthe he “Hot metal surface” list that involve surfaces that are covered with cellu cellulose. lose.    3.2.2.10 ELECTRICAL FAUL TS Electrical faults mainly produce hydrogen (H2) and acetylene (C2H2). For a low energy partial discharge, hydrogen is the main gas that is generated. For a high energy partial discharge, acetylene and other hydrocarbons hydrocarbons may also be found. 3.2.2.10 3.2. 2.10.1 .1 Examples of Electri cal Faults  When a joint joint used fo forr equaliz equalizing ing a pot potential ential becomes lose, one end can be at a floating potential with partial discharges. Sometimes this fault can include overheating of the cellulose  Continuous strong strong par partial tial di discharges scharges betw between een para parallel llel conductors conductors with a certa certain in potential difference. A strong partial discharge will sooner or later lead to a flashover  Break in a soldered connection which cause partial discharges  Floating potential, shielding ring, toroids  Partial discharges between turns/cond turns/conductors uctors which are next to each other Partial discharges due to inadequate impregnation or air bubbles bubbles enclosed in the  insulation. 100 3.2.2.11 3.2.2.11 3.2. 2.11.1 .1  FACTORS A FFECTING GAS CONCENTRAT ION IN TRA NSFORMERS Type and Brand of Oil Recently it has been shown that different oils show different gassing patterns. In particular, some additives, for example example oxygen inhibitors, influence the gassing pattern. 3.2.2.11.2 Oxygen It has long been known that the concentration of oxygen has an impact on the ageing of materials. The ageing of both the solid and liquid insulation materials has an impact on the gassing rate. It has been experienced that the factor of the gassing with/without oxygen is dependent on temperature. 3.2.2.11.3 Load An increase in the load gives directly an increase in the temperature. A higher temperature tempera ture gives a higher gassing rate. 3.2.2.11 3.2. 2.11.4 .4 Oil Preservatio n Systems Presently, state-of-the-art gas analysis is done mostly on oil samples taken from transformer units. The interpretation of gas analysis results is based on gas-in-oil composition. Under identical conditio conditions, ns, a transform transformer er the withgas gasconcentration space allowsinpart of the gases to be distributed into the gas space. Therefore, oil would be less than the total gas generated. The three main types of oil preservation systems are illustrated in Figure 3-9. It is readily seen that only Type II comes close to preserving all the gases in the oil. While both Types I and II are sealed systems, Type III allows gases to be lost to the atmosphere. Figure 3-9: Oil Preservation Systems for Power Transformers If there are increasing levels of nitrogen, oxygen, and carbon dioxide in a conservator type transformer, there is a possibility the tank has a leak or the oil may have been poorly processed. In this case, it is advisable to check the diaphragm or bladder for leaks and to check for oily residue around the Buchholz relay and other gasketed openings. There should be fairly low nitrogen and especially low oxygen in a 101  conservator type transformer. transformer. With time some air could leak through the bladder and raise the oxygen and nitrogen levels. 3.2.2.11 3.2. 2.11.5 .5 Gas Mixi ng Concentration of gases in close proximity to an active fault will be higher than in the DGA oil sample. As distance increases from a fault, gas concentrations decrease. Equal mixing of dissolved in the total volume of oil complete depends on time of and oil circulation. there are no pumpsgases to force oil through radiators, mixing gases in the totalIf oil volume takes longer. With pumping and normal loading, complete mixing equilibrium should be reached within a few days and will have little effect on DGA if an oil sample is taken then or long after a problem begins. 3.2.2.11.6 Temperature There is an old chemist's rule of thumb stating that a small increase in temperature (515 ºC) can yield a two or threefold increase in gassing rate. The basic explanation of this phenomenon is found in the well-known Arrhenius equation, which holds true for most chemical reactions. Gas production rates increase exponentially with temperature and directly with volume of oil and paper insulation. Temperature decreases as the distance from the fault increases. Temperature at the fault centre is highest, and oil and paper there will produce the most gas. As distance from the fault increases the temperature decreases, and the rate of gas generation also decreases. Because of the volume effect, a large heated volume of oil and paper can produce the same amount of gas as a smaller volume at a higher temperature. It is impossible to tell the difference by just analyzing the DGA. It is important to note that the ambient temperature directly influences the gassing rate. If there is a fault, the higher the ambient temperature, temperature, the higher would be the gassing rate. A gas generation chart [58] [59] is shown in Figure 3-10. Note that temperatures at which gases form are only approximate. Moreover, the figure is not drawn to scale and is only to be used for purposes of illustrating temperature relationships, gas types, and quantities as fault temperature vary in a transformer. These relationships represent what generally has been proven in controlled laboratory conditions using a mass spectrometer. The vertical band at left side of the chart shows what gases and approximate relative quantities are produced under partial discharge conditions (low energy discharge events). The total hydrogen produced by a partial discharge in oil could be as much as 75% of the total gases, the remaining part being composed of small percentages of hydrocarbons, in decreasing order C2H2 > CH4 > C2H4 > C2H6. With paper or pressboard added to the system, some CO is also produced. Discharges in cellulose alone produce CO and H2 in large quantities, in approximately equal quantities. Various beginrelative formingamounts in a transformer specific temperatures.temperatures. From Figure 3-10 wegases can see of gas asat well as approximate Hydrogen and methane begin to form in small amounts around 150 °C. Methane (CH 4), 102  ethane (C2H6), and ethylene (C2H4) production peaks at certain temperatures and declines as temperature increases beyond the peak. At about 250 °C, production of ethane (C2H6) starts. At about 350 °C, production of ethylene (C2H4) begins. This suggests that low temperature thermal faults will produce virtually no ethylene, but plenty of ethane and methane. Acetylene (C2H2) starts above 700 °C. This indicates that a thermal fault of greater than 700 °C can produce trace amounts of acetylene. Larger amounts of acetylene may only be produced above 900 °C and by internal arcing. The C2H4/C2H6 ratio is a good indicator of the hotspot temperature for mild to moderate cases of overheating. The following expression is generally used as an approximation of the oil decomposition temperature in terms of the C 2H4/C2H6 ratio [60]: T ( o C )  100  C2 H 4 C2 H 6  150 Figure 3-10: Combustion Gas Generation versus Temperature 3.2.2.11 3.2. 2.11.7 .7 Gas Solubi lit y in Oil Transformers with gas space above oil have the possibility of distribution of gases between the liquid and gas space. These gases, except for the nitrogen in the gas space and trace amounts of oxygen, are generated during transformer operation and afterwards distribute between between the oil and gas space according to the laws of distribution. In a closed system, if gas generation proceeds at a slow rate, and mixing is effective, equilibrium equilibriu m is attained attai ned soon. The deciding factors in gas distribution are the solubility of 103  the gas in the liquid medium and the prevailing temperature. The more soluble gases would be found in a higher proport proportion ion in the oil than the less soluble ones. On the other hand, the less soluble gases would be found in a higher proport proportion ion in the gas space. The solubility of gases in oil varies with temperature and pressure. The solubility of all transformer gases increase proportionally with pressure . The solubility of hydrogen, nitrogen, carbon monoxide, and oxygen increases with temperature. The solubility of carbon dioxide, acetylene, ethylene, and ethane decreases with increasing temperature. The solubility of methane remains remains almost cconstant onstant with temperature. Figure 3-11 shows the distribution coefficient (or Ostwald coefficient) of gases at 1 atmosphere. These coefficients are used to compute the gas space concentration corresponding to the concentration in oil and vice versa. 10 li O n is 1 t n e i c if f e o C y ti li b u l 0.1 o S s a G C2H6 CO2 C2H4 C2H2 CH4 O2 CO N2 H2 0.01 0 20 40 60 80 10 0 o Temperature ( C ) Figure 3-11: Gas Distribution Coefficients at 1 Atmosphere From the chart it is i s clear that the solubility of acetylene in oil is i s much greater than that of hydrogen in oil. Indeed at 25 °C and 1 atmosphere, the solubility of acetylene is 122 % and that of hydrogen is 5.6 %. It is clear that transformer oil has a much greater capacity for dissolving acetylene than hydrogen. It should be noted that gas from the gas space is lost l ost as the pressure in the gas space is released. 3.2.2.11 3.2. 2.11.8 .8 Other Factors Below is a list of factors that are known to influence the gassing rate. However, there is presently no consensus on how the individual factors affect the gassing rate. 104 - - -  Temperature distribution in the oil and in the cellulose cellulos e  Since the gassing is strongly temperature dependent, the temperature distribution will be important for the gassing. Average winding temperatu temperature re  When the tem temperature perature distribut distribution ion is no nott exactly known, the average winding temperature rise could be a good approximation.  Ambient temperature  Governs the absolute temperatu temperatures res in the transform transformers ers Oil production process  It ha hass bee beenn show shownn that how the ooilil is manufa manufactured ctured can influence the gassing. The oil production process could be more or less harmful to the oil. Transforme Transformerr history  What the transformer has gone through could be accumulated in the insulation. The most common cases are when gasses are dissolved in the cellulose and released at degassing or at temperature changes Repair Tests load loss test  No Electrical tests Unaged insulation material  New cellulose hhas as w weak eak links in the materia material,l, w which hich aare re cut early early in the ageing process, giving higher gassing rates in the beginning Type of cellulose insulation: The manufactur manufacturing ing processes and the ingredients in the board have an influence on the gassing rate  Kraft, Insuldur, Thermally upgraded  Pressboard - - - Low density, High density Laminated wood Different manufacturers Laminated polyester or casein glued board Type of design: Since the gassing is m measured easured in ppm/day ppm/day or m ml/day, l/day, it is of importance the volumes of oil, solid insulation and its ratio.  Size = rating  Oil volume  Solid insulation volume Design materials: It has been shown that many design materials have impact on gassing. Most famous is perhaps inadequately inadequately cured epoxy inside i nside radiators and reactor cheeses that produces hydrogen. hydrogen. Another famous type of material material is the catalytic material. Among this group are zinc and stainless steel in transformers; transformers; as well as core steel insulation. These materials also enhance hydrogen production :   Glue, Epoxy Paint 105  -  Zinc  Stainless steel Phenomenon  Transport in aand nd out of insulation: It has been shown that the solubility of carbon oxide (CO) and carbon dioxide (CO 2) is temperature dependent. This means that the content of these gases will change when the temperature changes. These gases will go out into the oil to a certain extent when the oil gets colder.  “Sweating”: If the level of a particular particular gas in the the so solid lid insulation is high high,, it could take a substantial amount of time before the gas in the insulation is in equilibrium with the gas in the oil. 3.2.2.12 3.2.2.12 3.2. 2.12.1 .1 DGA INTERPRETATION METHODS Key Gas Method of Interpr eting DGA In this method, one looks for the most prominent gas - the one which differs most from an expected "normal" level (or change). For example, during overheating of cellulose the main decomposition gases are CO and CO 2. During a partial discharge or corona activity, H2 is formed. If the partial discharges involve cellulose, carbon oxides will be present as well. During a more severe electric discharge, for example arcing, C2H2 will be produced. Normally H2 and smaller amounts of CH4 and C2H6 will also be produced during arcing discharges. Further, if cellulose is involved in the fault, CO will be produced. If oil is overheated, the hydrocarbons are the main gases produced – normally the saturated hydrocarbons such as C 2H6 at lower temperatures and unsaturated hydrocarbons such as C2H4 at higher temperatures. At very high temperatures, overheated oil will produce C2H2. CO2, O2 and N2 can also be absorbed from the air if there is an oil/air interface or if there is a leak in the tank. For Type I preservation systems that have a nitrogen blanket, nitrogen in the oil may be near saturation. As described above, each key gas is identified with a certain type of fault. There are four fault patterns that can be associated ass ociated with key gases as shown in Table 3-12. The key gas is frequently the predominant gas in the mixture of generated gases in the oil, but occasionally another gas could be in high concentration. Such variations are possible, because over a wide range of temperatures each gas attains a maximum generation rate at a certain temperature. Depending on the temperature present at the fault site, one gas or the other may be in larger proportion. It should be noted that small amounts of H2, CH4, CO2, and CO are produced by normal ageing. Thermal decomposition of oil-impregnated cellulose produces CO, CO 2, H2, CH4, and O2. Substantial decomposition of cellulose insulation begins at only about 100°C or less. Faults will produce internal hotspots of far higher temperatures than these, and the resultant gases show up in the DGA. Table 3-12: 3-12: Key Gas and Fa Fault ult Type Guide 106  Fault Pa Pattern ttern Conductor Overheating Key Gas CO2/CO (Carbon Oxides) Oil Overheating C2H4 (Ethylene) Secondary Gases CH4 and C2H4 if the fault involves an oil-impregnated structure CH4 and smaller quantities of H2 and C2H6. Traces of C2H2 if fault is severe or involves electrical contacts. Partial Discharge H2 (Hydrogen) CH4 and minor quantities of C2H6 and C2H4 Arcing C2H2 (Acetylene) H2, and minor quantities of CH4, C2H4 3.2.2.12 3.2. 2.12.2 .2 Possi ble Findin gs Discoloration of paper insulation. Overloading and/or cooling problem. Bad connection in leads l eads or tap changer. Stray current path and/or stray magnetic flux. Metal discoloration. Paper insulation destroyed. Oil heavily carbonized. Weakened insulation from ageing and electrical stress. Pinhole punctures in paper insulation with carbon and carbon tracking. Possible carbon particles in oil. Possible loose shield, poor grounding of metal objects. Metal fusion, (poor contacts in tap changer or lead connections). Weakened insulation from ageing and electrical stress. Carbonized oil. Paper destruction if it is in the arc path or is overheated. Indiv idu al and Total Dissol ved Key-Gas Concentr ation Method A four-condition DGA guide to classify risks to transformers with no previous problems has been developed in IEEE C57.104 [61]. The guide uses combinations of individual gases and total combustible gas concentration. This guide is not universally accepted and is only one of many tools used to evaluate transformers. The four conditions are defined below: Condition 1: Total dissolved combustible gas (TDCG) below this level indicates the transformer is operating satisfactorily. Any individual combustible gas exceeding specified levels in Table 3-13 should have additional investigation. Condition 2: TDCG within this range indicates greater than normal combustible gas level. Any individual combustible gas exceeding specified levels in Table 3-13 should have additional investigation. A fault may be present. Take DGA samples at least often enough to calculate the amount of gas generation per day for each gas (see Table 3-14 for recommended sampling frequency and actions). Condition 3: TDCG within this range indicates a high level of decomposition of cellulose insulation and/or oil. Any individual combustible combustible gas exceeding specified levels in Table 3-13 should have additional investigation. A fault or faults are probably present. Take DGA samp samples les at lleast east often enough to calculate the amount amount of gas generat generation ion per day for each gas (see Table T able 3-14). Condition 4: TDCG within this range indicates excessive decomposition of cellulose insulation and/or oil. Continued operation could result in failure of the transformer (see Table 3-14). If TDCG and individual gases are increasing significantly (more than 30 ppm/day), the fault is active and theincrease transformer should be de-energized 4 levels are reached. A sudden in key gases and the rate when of gasCondition production is more important in evaluating a transformer than the amount of gas. One exception is 107  acetylene (C2H2). The generation of any amount of this gas above a few ppm indicates high energy arcing. Note however, that trace amounts (a few ppm) can be generated by a very hot thermal fault (500 °C). One-time arcs caused by a nearby lightn lightning ing strike or a high-voltage surge can also generate acetylene. If C 2H2 is found in the DGA, oil samples should be taken weekly to determine if additional acety acetylene lene is being generated. If no additional acetylene is found and the level is below the IEEE Condition 4, the transformer may continue in service. However, if acetylene continues to increase, the transformer has an active high-energy internal arc and should be taken out of service. Further operation is extremely hazardous and may result in catastrophic failur failure. e. Table 3-13 assumes that no previous DGA tests have been made on the transformer or that no recent history exists. If a previous DGA exists, it should be reviewed to determine if the situation is stable (gases are not increasing significantly) or unstable (gases are increasing significant significantly). ly). Deciding whether gases are increasing significantly depends on the particular transformer. Table 3-13 3-13:: Disso lved Key Gas Con Con centratio n Li mits in Parts Parts Per Million (pp m) Status H2 (Hydrogen CH4 (Methane C2H2 (Acetylene C2H4 (Ethylene C2H6 (Ethane CO CO2 (Carbon Monoxide) (Carbon Dioxide) TDCG 2,500 2, 2,500-4,000 500-4,000 4,001-10,000 >10,000 720 721-1,920 1,921-4,630 >4,630 Condit ion 1 Condition 100 120 1 50 65 350 Condition 2 101-700 121-400 2-9 51-100 66-100 351-570 Condition 3 701-1,800 701-1,800 401-1,000 10-35 101-200 101-150 571-1,400 Condition 4 >1,800 >1,000 >35 >200 >150 >1,400 * CO2 is not included in adding the numbers for TDCG because it is not a combustible gas Compare the current DGA to earlier DGAs. If the production rate (ppm/day) of any one of the key gases and/or TDCG (ppm) has suddenly gone up, gases are probably increasing significantly. Refer to Table 3-14, which gives suggested actions based on total amount of gas in ppm and rate of gas production in ppm/day. Before going to Table 3-14, determine transformer status from Table 3-13; that is, look at the DGA and seeerifisthe transformer is ining Condition 1, 2,level 3, orfor4.any Theindividual conditiongas foror a particular transform transformer determine determined d by find finding the highest by using the TDCG. If the TDCG number shows the transformer in Condition 3 and an individual gas shows the transformer in Condition 4, the transformer is in Condition 4. Always be conservative and assume the worst until proven otherwise [62]. 108  Table 3-14: Actions Based on Dissolved Combustible Gas Condition s Condition 1 TDCG Level or Highest Individual Gas (See Table 4) 720 ppm of TDCG or TDCG Generation Rates (ppm/Day) <10 10-30 >30 <10 Quarterly 10-30 Monthly >30 Monthly <10 Monthly 10-30 Weekly 3-13 >30 Weekly >4,630 ppm of TDCG or highest condition based on individual gas from <10 Weekly 10-30 Daily >30 Daily Table 3-13 Condition 3 Condition 4 Sampling Interval Annually: 6 months for EHV transformers Quarterly Monthly highest condition based on individual gas from Condition 2 Sampling Intervals and Operating Actions for Gas Generation Rates 721-1,920 ppm of TDCG or highest condition based on individual gas from Table 3-13 1,941-4,630 ppm of TDCG or highest condition based on individual gas from Table Table 3-13 Opera Operating ting Procedures Continue normal operation. Exercise caution. Analyze individual gases to find c ause. Determine load dependence. Exercise caution. Analyze individual gases to find c ause. Determine load dependence. Exercise extreme caution. Analyze individual gases to find c ause. Plan outage. Call manufacturer and other consultants for advice. Exercise extreme caution. Analyze individual gases to find c ause. Plan outage. Call manufacturer and other consultants for advice. Consider removal from service. Call manufacturer and other consultants for advice. NOTES: 1. Either the Highest Condition C ondition Based on Individual Gas or Total Dissolved Combustibl Combustible e Gas can determine the condition (1, 2, 3, or 4) of the transformer. For example, if the TDCG is between 1,941 ppm and 2,630 ppm, this indicates Condition 3. However if hydrogen is greater than 1,800 ppm, the transformer is in Condition 4, as shown in Table 3-13. 2. W hen the table says “determine load dependence,” this means, if possible, find out if the gas generation rate in ppm/day goes up and down with load. Perhaps the transformer is overloaded. Take oil samples every time the load changes; if load changes are too frequent, this may not be possible. NOTES: 3. Either the highest c ondition based on individual gas or total dissolved combustible gas can determine the condition (1, 2, 3, or 4) of th thee transformer. For example, if the TDCG is between 1,941 ppm and 2,630 ppm, this indicates Condition 3. However if hydrogen is greater than 1,800 ppm, the transformer is in Condition 4, as shown in Table 3-13. 4. W hen the table says “det “determine ermine load dependence,” this means, if possible, find out if the gas generation rate in ppm/day goes up and down with load. Perhaps the transformer is overloaded. Take oil samples every time the load changes; if load changes are too frequent, this may not be possible. 5. To get TDCG generation g eneration rate, divide the change in TDCG by the number of days between ssamples amples that the transformer has been loaded. Down-days should not be included. The individual gas generation rate ppm/day is determined by the same method. Sampling intervals and recommended actions : When sudden increases occur in dissolved gases, the procedures recommended recommended in Table 3-14 should be followed. Table 3-14 is paraphrased from Table 3 in IEEE C57.104-1991. The table indicates the recommended sampling intervals and actions for various levels of TDCG in ppm. An increasing gas generation rate indicates a problem of increasing severity; therefore, as the generation rate (ppm/day) increases, a shorter sampling interval is recommended (see Table 3-14). Some information has been added to the table from IEEE C57-104-1991 as can be inferred from the text. If the cause of the gassing can be determined and the risk can be assessed, the sampling interval may be extended. For example, if the core is tested 109  with a M -meter and an additional core ground is found, even though Table 3-14 may recommend a monthly sampling interval, an operator may choose to lengthen the sampling interval since the source of the gassing and generation rate is known. A decision should never be made on the basis of just one DGA. It is very easy to contaminate the sample by accidentally exposing it to air. Mishandling may allow some gases to escape to the atmosphere and other gases, such as oxygen, nitrogen, and carbon dioxide, to migrate from the atmosphere into the sample. If you notice a transformer problem from the DGA, the first thing to do is take another sample for comparison. 3.2.2.12.3 3.2.2.12 .3 Roger Rogers s Ratio Method In interpreting gas analysis results, relative gas concentrations are found to be more useful than actual concentrations. For most purposes, only five gas concentrations (H2, CH4, C 2H6, C 2H4, and C2H2) are sufficient. According to the scheme developed by R.R. Rogers [63] and later simplified by the IEC, three gas ratios define a given condition. It is important to note that in developing the ratio analysis, Rogers considered gas measurements from mostly conservator type transformers with open expansion tanks (Type III transformers). Like the key gas analysis discussed above, this method does not provide guaranteed answers, but is only an additional tool to use in analyzing transformer problems. The three-ratio version of the Rogers Ratio Method uses the following ratios: R1 = C2H2/C2H4 R2 = CH4/H2 R3 = C2H4/C2H6 Note that the Rogers Ratio Method is for analyzing faults and not for detecting the presence of faults. Its use requires the establishment of a problem based on the total amount of gas (using IEEE limits) or increased gas generation rates. A good system to determine whether there is a problem is to use Table 3-13 (latest version) in the Key Gas Method. If two or more of the key gases are in Condition 2 and the gas generation is at least 10% per month of the L1 limit (Table 3-17), there is a high likelihood of a problem. If a gas used in the denominator of any ratio is zero, or is shown in the DGA as not detected (ND), use the detection limit of that particular gas as the denominator. This gives a reasonable ratio to use for diagnosis. A further refinement in applying the ratio methods is to subtract gases that were present prior to any sudden gas increases. This takes out gases that have been generated up to the point of analysis due to normal ageing and prior problems. This is especially true for ratios involving gases that are generated during normal ageing, H2, and the cellulose insulation gases CO and CO 2 [64]. In using these ratios, it is advisable to never make a decision based only on a ratio if either of the two thatrule ratio is less than times theinaccuracies amount thehave gas chromatog chromatograph raph cangases detectused [64].inThis makes sure that10 instrument little effect on the ratios. If either of the gases is lower than 10 times the detection limit, it 110  is most likely that the transformer does not have the particular problem that this ratio deals with. When a fault occurs inside a transformer, there will be more than enough gases present to make the ratios valid. Detection limits for the key gases are shown in Table 3-15. Table 3-15 also provides possible diagnoses based on the values of the three ratios. Table 3-15: 3-15: Rogers Ratios f or Key Gases Code Range of Ratios C2H2/ C2H4 CH4/ H2 C2H4/ C2H6 <0.1 0.1-1 1-3 >3 0 1 1 2 1 0 2 2 0 0 1 2 C2H2/ C2H4 CH4/ H2 C2H4/ C2H6 Case Fault Type 0 No fault 0 0 0 1 Low energy partial discharge 1 1 0 1 1 0 1-2 0 1-2 2 3 High energy partial discharge Low energy discharges, sparking, arcing 4 High energy discharges, arcing 1 0 2 5 Thermal fault less than 150°C (see note 2) 0 0 1 0 2 0 0 2 1 6 7 8 Thermal fault temp. range 150-300°C (see note 3) Thermal fault temp. range 300-700°C Thermal fault temp. range over 700°C (see note 4) Gas Detection Limit s C2H2 C2H4 CH4 H2 C2H6 1 ppm 1 ppm 1 ppm 5 ppm 1 ppm 10 x Detection Limit s 10 ppm 10 ppm 10 ppm 50 ppm 10 ppm Problems Found Normal ageing Electric discharges in bubbles, caused by insulation voids, super gas saturation in oil or cavitation (from pumps), or high moisture in oil (water vapor bubbles). Same as above but leading to tracking or perforation of solid cellulose insulation by sparking or arcing. This generally produces CO and CO 2. Continuous sparking in oil between bad connections of different potential or to floating potential (poorly grounded shield etc); breakdown of oil dielectric between solid insulation materials. Discharges (arcing) with power follow through; arcing breakdown of oil between windings or coils, between coils and ground, or load tap changer arcing across the contacts during switching with the oil leaking into the main tank. Insulated conductor overheating This generally produces CO and CO2, because this type of fault generally involves cellulose insulation. Spot overheating in the core due to flux concentrations. Items below are in order of increasing temperatures of hotspots. Small hotspots in core. Shorted laminations in core. Overheating of copper conductor from eddy currents. Bad connection on winding to incoming lead or bad c ontacts on load or no-load tap changer. c hanger. Circulating currents in core. This could be an extra core ground, (circulating currents in the tank and core). This could also mean stray flux in the tank. 0 2 2 These problems may involve cellulose insulation, which will produce CO and CO2. Notes: 1. There will be a tendency for ratio C 2H2 /C2H4 to rise from 0.1 to above 3 and the ratio C 2H4 /C2H6 to rise from 1-3 to above 3 as the spark increases in intensity. The code at the beginning stage will then be 1 0 1. 2. These gases come mainly from the decomposition of the cellulose, which explains the zeros in this code. 3. This fault condition is normally indicated by increasing gas concentrations. CH 4/H2 is normally about 1, the actual value above or below 1, is dependent on many factors, such as the oil preservation system (conservator, N 2 blanket, etc.), the oil temperature, and oil quality. 4. Increasing values of C 2H2 (more than trace amounts), generally indicates a hotspot higher than 700 oC. This generally indicates arcing in the transformer. If acetylene is increasing and especially if the generation rate is increasing, the transformer should be de-energized as further operation is extremely hazardous. General Remarks: 1. Values quoted for ratios should be regarded as typical (not absolute). There may be transformers with the same problems whose ratio numbers fall outside the ratios shown at the top of the table. 2. Combinations of ratios not included in the above codes may occur in the field. If this occurs, the Rogers Ratio Method will not work for analyzing these cases. 3. Transformers with on-load tap changers may indicate faults of code type 2 0 2 or 1 0 2 depending on the amount of oil interchange between the tap changer tank and the main tank. 111  If samples from Type I transformers (N2 blanket) are compared to those from Type II transformers (sealed conservator), it is necessary to make adjustments to gas concentrations and consequently some gas ratios used for diagnostic purposes. Fortunately, major major adjustment is required only for the hydrogen concentration. Details of the adjustment procedure were derived by Oommen [65]. The only gas ratio that needs significant adjustment is the CH4/H2 ratio. The adjustment factor is 0.44 at 25 °C. This means that a gas ratio obtained from measurement on a Type I transformer should be multiplied by 0.44 to equate to a measurement on a Type II transformer. Since Rogers developed his method based on sample from Type III transformers, there is some uncertainty about strict enforcement enforcement of ratio codes to all types of transform transformers. ers. With this qualification, it may be pointed out that the ratio codes are of great value in diagnosing transformer transform er faults. The severity of faults identified in transform transformers ers using the Rogers ratio patterns is shown in Table 3-16. The level of urgency in correcting a problem will obviously depend on the severity of the fault. While it may be sufficient to place a transformer with an overheating conductor problem on a watch list, one with an arcing fault might require immediate removal from service and subsequent investigatio investigation. n. Table 3-16: 3-16: Order of Severity of Transfo rmer Faults Increasing Order of Se Severit verit y 1 2 3 4 5 6 7 8 3.2.2.12.4 3.2.2.12 .4 Fa Fault ult Pa Patterns tterns Normal Conductor Overheating Oil Overheating, Mild Oil Overheating, Moderate Oil Overheating, Severe Partial Discharge, Low Energy Partial Discharge, High Energy Arcing Pa Pattern ttern # in Table 3-15 0 5 6 7 8 1 2 3,4 IEC Method Metho d The IEC method (See IEC 60599 latest version is second edition 1999-03) uses five different types of faults and three basic ratios. The method is very similar to the Rogers Ratio above. The faults and ratios are as follows:        PD Partial discharges D1 Discharges of low energy D2 Discharges of high energy T1 Thermal fault, T < 300 °C T2 Thermal fault, 300°C < T < 700 °C T3 Thermal fault, T > 700 °C Basic ratios: C2H2/C2H4, CH4/H2 and C2H4/C2H6 3.2.2.12 3.2. 2.12.4.1 .4.1 Carbon Dioxid e/C e/Carbon arbon Monoxi de (CO2/CO) Ratio 2 and CO from oil-impregnated paper insulation increases rapidly The formation of CO with temperature. Incremental (corrected) CO2/CO ratios less than 3 are generally considered as an indication of probab probable le paper involvement in a fault, with some degree 112  of carbonization. Normal CO2/CO ratios are typically in the range 5 - 9. Ratios above 10 generally indicate indicate a therm thermal al fault with the involvem involvement ent of cellulose. If CO is increasing around 70 ppm or more per month (generation limit from IEC 60599), there is probably a fault. In order to get reliable CO2/CO ratios in the equipment, CO2 and CO values should be corrected first for possible CO2 absorption from atmospheric air; and CO2 and CO background generation (see 6.1 and clause 9 of IEC 60599). The background generation result from the ageing of cellulosic insulation, overheating of wooden blocks and the long term oxidation of oil. For example, if air-breathing equipment is saturated with approximately 10% of dissolved air, there could be up to 300 l/l (ppm) of CO2 just from the air. In sealed equipm equipment, ent, air is normally excluded but may enter through leaks. The concentration of CO2 will be in proportion to the amount of air present. When excessive paper degradation is suspected (CO2/CO /CO < 3), it is adv dvis isaable to ask for a furanic compounds analysis or a measurem measurement ent of the degree of polymerization of paper samples, if this is possible. 3.2.2.12.4.2 IEC C2H2/H2 Ratio In power transformers equipped with on-load tap changers (OLTC), the tap changer operations produce gases corresponding to discharges of low energy in the main tank (D1). If some oil or gas communication is possible between the OLTC compartment and the main tank, or between the respective conservators, these gases may contaminate the oil in the main tank and lead to wrong diagnoses. The pattern of gas decomposition in the OLTC, however, is quite specific and different from that of regular low energy discharges in the main tank. 3.2.2.12 3.2. 2.12.4.3 .4.3 IEC Recommended Method of Interpret ation a) Reject or correct inconsiste inconsistent nt DGA values. Calculate the rat rate e of gas increase since the last analysis, taking into account the precision of the DGA results. If all gases are below typical values of gas concentrations and rates of gas increase, report as "Normal DGA/healthy equipment". If at least one gas is above typical values of gas concentrations and rates of gas increase, calculate gas ratios and identify fault. Check for eventual erroneous diagnosis. If necessary subtract last values from present ones before calculating ratios, particularly in the case of CO and CO2. If DGA values are above typical values but below 10 times the analytical detection limit, see the section in IEC 60599 on “Uncertainty “Uncertainty of ratios”. b) Determin Determinee if gas concentrations and rates of gas increase are above ala alarm rm values. Verify if fault is i s evolving towards final sstage. tage. Determine Determine if paper is involved. c) Take proper action according to the best engineering judgment. It is recommended recommended to: 1) Increase sampling frequency frequency (quarter (quarterly, ly, monthly or other) when the gas concentrations concentratio ns and their rates of increase exceed typical vvalues, alues, 2) Consider immediate action when gas concentrations and rates of gas increase exceed alarm values. 113  3.2.2 3.2 .2.12 .12.5 .5 Duval Triangle Me Method thod for Diagnosing a Tra Transformer nsformer Proble Problem m Using Dissolved Gas Analys An alys is [66] Duval developed this method in the 1960s using a database of thousands of DGAs and transformer problem diagnoses. This method has proven to be accurate and dependable dependab le over many andthis is now gaining in popular popularity. The and how it is used is described below.years Before method is applied, it isity. best to method follow these steps: 1. First determine whether a problem exists by using the IEEE method above, and/or Table 3-17 below. At least one of the hydrocarbon gases or hydrogen (H 2) must be in IEEE Condition 3, and increasing at a generation rate (G2) from the table below, before a problem is confirmed. To use Table 3-17 below without the IEEE method, at least one of the individual gases must be at L1 level or above and the gas generation rate at least at G2. If there is a sudden increase in H 2 with only carbon monoxide (CO) and carbon dioxide (CO2) and little or none of the hydrocarbon gases, use the (CO2/CO ratio) below to determine if the cellulose insulation is being degraded by overheating. 2. Once a problem has been determined to exist, use the total accumulated amount of the three Duval Triangle gases and plot the percentages of the total on the triangle to arrive at a diagnosis. Also, calculate the amount of the three gases used in the Duval Triangle, generated since the sudden increase in gas began. Subtracting out the amount of gas generated prior to the sudden increase will give the amount of gases generated since the fault began. Detailed instructions and an example are shown below. a) Take the amount (ppm) of methane (CH4) in the DGA and subtract the amount of CH4 from an earlier DGA, before the sudden increase in gas. This will give the amount of methane generated since the problem started. b) Repeat this process for the remaining two gases, ethylene (C2H4) and acetylene (C2H2). c) Add the three numbers (differences) obtained by the process of step b) above. This gives 100 % of the three key gases generated since the fault. d) Divide each individual ga gass difference by the total difference difference of gas obtaine obtained d in step c) above. This gives the percentage increase of each gas of the total increase. e) Plot the percentage of each gas on the Duval Triangle, beginning on the sside ide indicated for that particular gas. Draw lines across the triangle for each gas parallel to the hash marks shown on each side of the triangle (see Figure 3-12). The triangle coordinates, corresponding to DGA results in ppm, can be calculated as follows: %C2H2 = 100x/(x+y+z); %C2H4 =100y/(x+y+z); %CH4 = 100z/(x+y+z); where x = C2H2, y = C2H4, z = CH4. 114  The diagnostic regions in the triangle are defined as: PD = Partial Discharge T1 = Thermal Fault less than 300 °C T2 = Thermal Fault between 300 °C and 700 °C T3 = Thermal Fault greater than 700 °C D1 = Low Energy discharge (Sparking) D2 = High Energy discharge (Arcing) DT = Mix of Thermal and Electrical Faults Table 3-18 provides examples of the typical faults in transformers for each of the diagnostic categories in the Duval analysis triangle. The table is derived from the IEC draft 60599 (Edition 2) [64]. Figure 3-12: 3-12: Coordi nates and Fault Zones o f the Duval Triangle CAUTION: Do not use theisDuval Triangle determine or notthat a transform transformer has aa problem. problem. Notice, there no area on thetotriangle for awhether transformer does noterhave The triangle will show a fault for every transformer whether it has a fault or not. Use the key gas or TDCG methods to determine if a problem exists before applying the Duval Triangle. The Duval Triangle is used only to diagnose what what the problem is. As with other methods, a significant amount of gas must already be present before this method is valid. 115  Table 3-17 3-17 : L1 Li mits and Generation (G1 (G1,, G2) R Rate ate Per Per Month Limi ts Ga Gas s L1 Limit s G1 Limit s (ppm per month) G2 Limits (ppm per month) H2 CH4 C2H2 C2H4 C2H6 CO CO2 100 75 3 75 75 700 7,000 10 8 3 8 8 70 700 50 38 3 38 38 350 3,500 NOTE: In most cases, acetylene (C2H2) will be zero, and the result will be a point on the right side of the Duval Triangle. Compare the total accumulated gas diagnosis and the diagnosis obtained by using only the increase-in-gases after a fault. If the fault has existed for some time, or if generation rates are high, the two diagnoses will be the same. If the diagnoses are not the same, always use the diagnosis of the increase in gases generated by the fault, which will be the more severe of the two. Table 3-18 3-18:: Example of Faults fro m the Duval Analysi s of Power Transfo rmers Fa Fault ult Type Partial discharges Discharges of low energy Discharges of high energy Overheating less than 300°C Overheating 300 to 700°C Overheating over 700°C Examples Discharges in gas-filled cavities in insulation, resulting from incomplete impregnation, high moisture in paper, gas-in-oil super-saturation or cavitation (gas bubbles in oil), leading to X wax formation on paper. Sparking or arcing between bad connections of different floating potential, from shielding rings, toroids, adjacent discs or conductors of different windings, broken brazing, closed loops in the core. Additional core grounds. Discharges between clamping parts, bushing and tank, high voltage and ground, within windings. Tracking in wood blocks, glue of insulating beam, winding spacers. Dielectric breakdown of oil, load tap changer breaking contact. Flashover, tracking or arcing of high local energy, or with power follow through. Short circuits between low voltage and ground, connectors, windings, bushings, and tank, windings and core copper c opper bus and tank, in oil duct. Closed loops between two adjacent conductors around the main magnetic flux, insulated bolts of core, metal rings holding core legs. Overloading the transformer in emergency situations. Blocked or restricted oil flow in windings. Other cooling problems, pumps valves, etc. Stray flux f lux in damping beams of yoke. Defective contacts at bolted connections (especially bus bar), contacts within tap changer, connections between cable and draw rod of bushings. Circulating currents between yoke clamps and bolts, clamps and laminations, in ground wiring, bad welds or clamps in magnetic shields. Abraded insulation between adjacent parallel conductors in windings. Large circulating currents in tank and core. Minor currents in tank walls created by high uncompensated magnetic field. Shorted core laminations. Notes: 1. 2. 3. X wax formation comes from Paraffinic oils (paraffin based); however, naphthenic ooils ils are not immune to X wax formation The la last st overheating problem in the table is for faults oover ver 700°C. Recent laboratory discoveries have found that acetylene acetylene can be produced in trace amounts at 500°C, which is not reflected in this table. Transformers that show trace amounts of acetylene are probably not active arcing but may be the result of high-temperature thermal faults. It may also be the result of one arc, due to a nearby lightning strike or voltage surge. A bad connection at the bottom of a bushing can be confirmed by comparing infrared scan scanss of the top of the bushing with a sister bushing. When loaded, heat from a poor connection at the bottom will migrate to the top of the bushing, which will display a markedly higher temperature. If the top connection is checked and found tight, the problem is probably a bad connection at the bottom of the bushing. 116  3.2.2.12 3.2. 2.12.6 .6 ABB' s Adv anced Disso lved Gas Analys is Software (ADG (ADGA) A) It has been ABB’s experience that the design and application of a transformer can make it have its own unique gassing pattern. ABB has developed an internal software package that expertise combines and DGAtransformer raw data, ratios, trending, key indicators, and ABB's resident design construction knowledge to interpret the results. By combining ABB's design and manufacturing knowledge with the analysis capabilities of the software, the analysis is able to offer greater analytical depth than what is standard practice in the industry. The program has the ability to pinpoint specific sources and causes of gas generation, rather than simply identify general categories of gas generation. shows the results of an analysis performed with this software. In addition to the individual gas concentrations, the program requests the rate of generation of each gas and a series of inputs relating to the type of oil preservation system and application of LTC, etc. The results are a prioritized list of diagnoses and colour-coded pictorials of the severity of each gas concentration and diagnostic ratio. The likely sources of the fault can be obtained by activating activati ng an explanation screen. Figure 3-13 Figure 3-13: 3-13: Adv anced DGA Analysis o f Power Transform er GasGas-in-Oil in-Oil Sample 117  3.2.3 ANALYSIS OF PARTICLES IN TRANSFORMER OILS [67] Transformer manufacturers and utilities currently use particle contamination as another means of monitoring oil quality in transfor transformers. mers. This is due to the increasing awareness of the factors that influence the dielectric strength of oil. High-level particle contamination is recognized as an important factor. The breakdown strength of transformer oil is a function of the concentration, size, shape, and type of the particles and the moisture level in the oil. In performing these analyses, identification of the particles is important in determining the source of particle generation in operating transformers. The chief sources of particulate matter in transformers are cellulosic dust and fibers and residual dirt. Iron particles, particles of copper, and other metals could exist from manufacturing operations. The factory filtering and flushing operations remove most of these particles; therefore, the particle level would be relatively low. Some undesirable conditions in service, such as pump problems and electrical discharges, tend to generate particles; therefore, the periodic monitoring of particle level should be considered part of the preventive maintenance program. Many field problems are detected by electrical tests and gas analysis, but a few, such as pump bearing, wear may not be apparent. Pump bearing wear strength is of particular interest, because metallic particles generate generated d could reduce the dielectric of the transformer insulation. 3.2.3.1 OIL SAMPL ING FOR PARTI CLE A NALYSIS In taking samples for particle count analysis, the oil should be taken from the bottom valve of transformers via flexible tubing. At least a gallon of oil should s hould be allowed allowed to flow out to purge the lines before the sample bottle is introduced into the flowing stream. The bottle itself should be clean; ultrasonic cleaning is preferable in most cases. Large bottles should be rinsed in the oil stream even if they are pre-cleaned. The bottles should be capped soon after sampling. In spite of these precautions, particle contamination from outside sources may not be completely eliminated. When high counts are measured, a second s econd sample should be taken to check for sampling errors. 3.2.3.2 PARTICL E COUNTING [68] Particle size analyzers are used to perform particle counting in transformer oils. These instruments use the principle of light blockage to estimate the size of each particle as it passes through a micro cell in which a transverse light beam is applied. The crosssectional area of the particle is automatically automatically estimated, and this area is converted to an equivalent circle or ellipse. The measured particle size may be expressed as the diameter of this circle or as the major diameter of the ellipse. Since most particles are non-spherical, non-spher ical, especially dust and wear particles, the ellipse approximation approximation is preferr preferred. ed. Until 2000, the optical particle counters used for transformer fluid analysis were calibrated using a standard suspension of what is known as ACFTD (Air Cleaner Fine Test Dust) particles in a hydrocarbon fluid (MIL 5606) of comparable viscosity. The standard for calibrating particles based on the ACFTD method is ISO 4406-1999 [69]. The ACFTD calibrat calibration ion method has since been replaced with ISO 11171 [70] and ASTM method D6786, which specifies a solution of Medium Test Dust (MTD). The conversion of a sample of particle sizes from ACFTD to MTD methods is given in Table 3-19. 118  Table 3-19: 3-19: Pa Parti rti cle Size Conversion ACFTD Size ( m) MTD Size ( m) 1.0 3.0 5.0 4.2 5.1 6.4 10.0 15.0 20.0 50.0 100.0 9.8 13.6 17.5 38.2 70.0 Counting is done in the cumulative mode, i.e., for any specified size, the number of particles above that size would be measured. The ACFTD method suggested reporting cumulative particle counts 1, 5, 10, 15, 25, 50, and 100 m sizes. These correspond roughly to the recommended sizes of 4, 6, 10, 14, 21, 38, and 70 m sizes for the newer MTD method. The level of contamination in a unit is determined via a contamination code that depends on the number cumulativewith particles in a to defined range given per milliliter of oil. The contamination code isofdetermined reference the scheme in ISO-44061999. A segment of the scheme is shown in Table 3-20. To determine the contamination code, particle levels at three sizes are used, 4 m, 6 m, and 14 m. These roughly correspond to the ACFTD sizes of 1 m, 5 m, and 15 m. Table 3-20: 3-20: Pa Parti rti cle Contamin ation Cod e 3.2.3.2 3.2. 3.2.1 .1 Number of Particles per Millil iter CODE CODE Number 5000 to 10,000 2500 to 5000 1300 to 2500 640 to 1300 320 to 640 160 to 320 20 19 18 17 16 15 80 40to to160 80 20 to 40 10 to 20 5 to 10 14 13 12 11 10 Normal and Abnor mal Particl e Count Levels From experiments performed by ABB, it appears that units with greater than 150 particles above 5 m per milliliter of oil using the MTD method (or 150 particles above 3 m per milliliter of oil using the ACFTD) deserve further analysis and possibly inspection if other tests prove positive. These values are not intended to be an upper limit on the permissible particles in operating transformers. However, particle size analysis should be supplemented by quantitative trace metal analysis as described below. 119  3.2.3.3 T RACE METAL CONTENT OF P ARTICL ES The sources of particles with metallic content have already been mentioned. In this section the technique used to measure trace metallic levels and the results obtained will be described. 3.2.3.3 3.2. 3.3.1 .1 Method of Measurement Measurement Several methods exist for trace metal analysis of oil samples. The most commonly used methods at present are ICP (inductively coupled plasma) atomic absorption and atomic emission and x-ray fluorescence. The atomic absorption technique is especially suited for very low-level contamination levels (in the parts per billion ranges). Unlike emission spectroscopy and x-ray fluorescence, it does not directly identify all the elements present in a sample; the presence of each element has to be tested using standards in atomic absorption spectroscopy, and a selection of metals is detected by ICP. Atomic absorption is therefore a time consuming technique if several elements are to be tested. In the AAS technique the sample is “atomized” in a flame or furnace at temperatures in the 1,500-3,000 °C range. For each element to be tested, a separate hollow cathode lamp of that element is mounted and energized to produce emission lines of characteristic wavelengths. The emission beam is allowed to pass through the vapor. If the vapor has atoms of the same element, these atoms would absorb energy from the beam in proportional to the concentration of atoms. The exact methodology has to be worked out for each type of analysis. If particles are extremely fine, e.g., below 10 microns, the sample would be more or less homogeneous, and the furnace technique could be used. Only micro liters of the oil sample are required, and no sample preparation is needed. However, the reproducibility of the furnace technique is not high when small samples are used, and many particles suspended in oil are greater than 10 microns. This type of analysis would give metallic content of both suspended and dissolved material. This procedure of only analyzing suspended particles has been found to be reproducible and correlates well with units having known sources of contamination. Meaningful metal analysis can be confined to four elements: iron, copper, lead, and zinc. All these elements could be analyzed easily by the flame technique using air/acetylene flame. The selection of iron and copper needs no explanation. Lead and zinc are elements normally found in the pump bearing alloy material. It must be pointed out that lead and zinc could be present in oil from other sources such as solders, zinc plated parts, and paints; also, the wear of the alloy may not produce particles of the same composition. Lead and zinc are relatively low melting, and may be partly lost during wear process and sample preparation. Iron oxide is a component of dirt, dust, and impure clay; theref therefore, ore, a bad sam sample ple could show excessive iron content. 3.2.3. 3.2 .3.3 3.2 Normal and Abnormal Me Metallic tallic Content of Particl Particl es in Oil The metallic content of particles is expressed, for convenience, in parts per billion (ppb) units, which could be better stated asdetection micrograms/ml. For very theoflevels iron, copper, lead, and zinc approach limits, 1-2 ppb. Anclean upperoil, limit 5 ppb of is 120  typically observed for each element in clean oil with total particle count not exceeding 500. Based on a limited study of 200 samples taken by ABB from both factory and field units, the following levels appear normal for both factory and field units: Iron: 10 ppb, max. Copper: 20 ppb, max. If levels greater than these are measured, further study may be required. Most units with reported bearing problems show higher than average upper levels. Considerable caution should be used in the application of these limits. First, the analysis technique between laboratories should be standardized. Secondly, the total volume of oil in the transformer should be taken into account. The oil volume in large power transformers could vary from 10,000 to 30,000 gallons. If particles originate from general degradation degradation processes, the particle concentration would be uniform regardless of the size of the transformer. If, however, particles originate from a localized mechanical problem, the total oil volume would influence particle concentration. This is especially true of oil sampleslevel tested fromberesidual oil after flushing operations. Both the particle level may and metallic could higher than normal. However, such concentrated samples still be of value for metal identification. The levels suggested above do not correct for transformer transform er si size. ze. 3.2.3.4 DIAGNOSTIC EXAMPLES OF PARTICL E A NALYSIS Table 3-21 shows some examples of problem diagnoses using particle analysis. They show that excessive high particle levels may indicate wear and degradation. Also, excessive copper content may be associated with pump bearing wear problems in some cases. These examples and others reported in the open literature demonstrate that particle level analysis coupled with AAS is a useful technique to monitor metallic contamination in transformer oil. Table 3-21: Diagnostic Examples of Particle Analysis METALLIC CONTENT (ppb) Case Descript ion Total Particles Visible Particles Pump failure from impeller and thrust bearing wear. Sample taken from bottom of unit after pump failure. 58,225 31 Iron 8.8 Copper 107.7 Lead 15.5 Zinc 6.9 Pump problem from radial bearing wear. Sample was taken from a unit with suspected pump problems. Pump motor winding short. This analysis was performed after a pump 750 6 17.6 75 2.7 3.8 619 3 3.5 116.8 12.1 17.2 winding failure in a factory situation. Comments The excessive copper content confirms the problem. Shiny metallic particles were visible. Pump bearing wear may not always produce such high levels, but AAS and particle counting could still be used to test whether the problem exists. Visual inspection showed that the rear radial bearing had frozen on the axle; the pump was, however, still operating. Although particle count is deceptively low, the metallic analysis showed excessive copper content. The shorting caused gas generation oil decomposition in the pump from housing. 121  3.2.3.5 EFFECT OF PARTICLES ON DIELECTRIC STRENGTH OF INSULAT ING OIL 13 [71] The effect of particles on the dielectric strength of transformers has been characterized to a large extent. Experimental investigations have been numerous and most of them show a sizeable reduction of dielectric strength, especially if a large oil volume is used and the voltage is applied over a long time period. Since investigations were mostly carried out on bare electrodes, they are relevant relevant only for the case of discharges initiated in the oil. For discharges initiated at the electrode-to-oil interface, the effect of particleinitiated discharges on the insulation is obviously considerable but has not yet been characterized. The measurement of the particle content in an oil sample has shown large discrepancies when results from different laboratories laboratories are compared. Measurem Measurements ents on different samples, carried out in a single laboratory, appear to be much more consistent and successive measurements on the same sample have shown very good repeatability. Particle counting is somewhat hampered by the very small volume of the oil sample compared compared to the total oil volum volume e of oil in the transformer. transformer. Depending on the sampling valves and techniques used, it is possible to measure completely different particle concentrations in the same transformer. In spite of these difficulties, it is necessary to establish recommendations since the detrimental effect of particles has been identified conclusively in a number of failures either in the field or during factory acceptance tests. The experience of utilities and manufacturers reveals that this type of failure is observed almost exclusively on EHV transformers. This is believed to be linked to the smaller ratio of test voltage to service voltage and the large oil volume found in EHV EH V transformers. The most vulnerable part of the transformer is the high-voltage bushing shield and high-voltage lead, especially if the insulation is provided mainly by a large oil volume without subdividing barriers. This effect appears to be enhanced when these components are located in a turret. 3.2.3. 3.2 .3.5 5.1 Current filt ering practices on new transformers It is quite normal for a newly manufactured transformer to have a significant content of particles, mainly cellulose. is now common apply a filtering procedure to to theEHV oil, before proceeding with theItacceptance tests. to This precaution applies mainly transformers. In a study by a CIGRE working group, most of the manufacturers that were consulted do not actually count particles but establish a factory procedure that simply calls for a certain number of passes of the oil through a filter. After installation at the site, a similar procedure of oil filtering is recommended for these more sensitive transformers. This precaution allows some contamination to be eliminated that could originate from the coolers, the erection procedure or the oil itself. Only a few manufacturers manufa cturers have set limits on the particle count acceptable before commissioning. In those few cases, the applicable limit is 1,000 particles larger than 5 m per 100 ml oil volume. A more realistic measurement of particles is somewhat easier at this stage since the filtering creates a large oil circulation outside the transformer tank and allows for the use of on-line particle counting with a continuous supply of hom homogenized ogenized oil. 13 CIGRE SC A2 (ex 12) WG 17, - Particles in Oil, Nov. 199 19999 122 3.2.3. 3.2 .3.5 5.2 3.2.3.5.2.1 3.2.3.5. 2.1  Classification of contamination level Bare elect electro rodes des Most of the reported experiments are made with bare electrodes, using test cells as specified by IEC 60156 or ASTM D-1816. However, some of the tests have been carried out with plane electrodes or bushi bushing ng shields of very large dimensions. The presence of particles, whether conducting material or cellulose fibers, always reduces the average breakdown voltage. The reduction factor varies widely and it cannot be readily related to the oil volume under stress, voltage application method or type of contaminant. contaminant. The particle counting counting m method ethod is another poss possible ible cause of the dispersion. It must be noted that these reductions in dielectric strength are applicable only to the oil and cannot be applied to a system where the electrodes are covered with solid insulation. It is the CIGRE Working Group’s opinion that, because of its small volume, the IEC electrode is not the best configuration for evaluating the effect of particles. In normal transformer oil, the amount of particles per unit of volume is rather small and the standard procedure procedure for oil testing does not allow sufficient time for the particles to move to the right place. Coaxial test cells have been suggested by France and tried by others. This gives a continuous oil flow and therefore a larger oil volume is actually tested. The coaxial test cell appears to be the best tool presently available to quantify the effect of particles on the dielectric strength of insulating oil. The effect of moisture is significant, especially in the presence of cellulose fibers. This can be best illustrated with a set of results from Sinz [72]. The effect of moisture is obvious, as is the better sensitivity of the coaxial test cell as compared to the IEC test cell. It is therefore recommended that the water content be reported along with the particle content especially when dealing with cellulose particles. The voltage application method is also questioned. It is argued by some researchers that the step voltage procedure allows the test cell to be under voltage for a longer time and increases the probability of a particle moving closer to the area of maximum field stress. It is also al so noted that from a practical point of vview, iew, the average breakdown voltage is not as interesting as the minimum breakdown voltage. It is suspected that the particles might increase the dispersion of the breakdown voltage and it is recommended that the dispersion be reported along with the average values. It appears that the IEC test method is not appropriate for showing the detrimental effect of the particles. There is a need to develop a standardized method that would call for a large oil volume and a long duration of voltage application. 3.2.3.5. 3.2. 3.5.2.2 2.2 Covered electro des Very little experimental data is available on the effect of part particles icles with electrodes coated with insulating material. For natural (factory) contamination, a reduction of 29% on the average breakdown voltage was found. Hydro-Québec, EHV Weidmann, runpressboard some tests spacers with plane electrodes and ina collaboration combination with of pressboard sheetshas and to simulating the main insulation between high-voltage and low-voltage windings in a large 123  transformer. The introduction of aluminum powder in the insulating oil only slightly reduced the average breakdown voltage (7%), but the reduction on the minimum value was more significant (32%). It is i s possible that the breakdown mechanism involved here is quite different from the one in section 3.2.3.5.2.1. 3.2.3. 3.2 .3.5 5.3 Contamination deposited on insulatin g surface Some researchers have endeavored to quantify the impact of conducting particles when deposited on insulating structures. Hydro-Québec, in collaborat collaboration ion with EHV Weidmann, has investigated the effect of aluminum deposited on spacers in the main insulat insulation ion of a transformer. In this case, the aluminum was diluted in a solvent which was then applied with a brush on the side of the pressboard spacer. Two pressboard pieces spaced 12mm apart were used to simulate a 12-mm oil duct; three pressboard pieces equally spaced at 6-mm were used to simulate two, 6-mm oil ducts. The reduction in average breakdown value was 24 % for the single duct and 14% for the double oil duct. A similar test, without the pressboard barrier, was carried out on a larger scale by ABB at the request of Hydro-Québec. Here again the aluminum powder was applied with a brush. With this contamination, the average breakdown voltage was reduced from 400 kV to 280 kV, a reduction of 30 %. Ta Table ble 3-22: 3-22: Typical contamination levels encountered on power transform er insulating oil (ISO class) Maximum Ma ximum c ount per 100 ml Contamination designation Typical occurrence 5 m 15 m Up to 8/5 250 32 None IEC cleanliness requirement for sample bottle filled with a clean solvent 9/6 to 10/7 1000 130 Low Excellent oil cleanliness encountered during factory acceptance test and transformer commissioning 11/8 to 15/12 32000 4000 Normal 16/13 to 17/14 18/15 and above 130000 16000 Marginal High Contamination level typical for transformers in service Contamination level found on a significant number of transformers in service Contamination level rare and usually indicative of abnormal operating conditions Vincent [73] reported an experiment with a piece of pressboard contaminated with carbon particles and subjected to divergent fields in a rod-plane configuration. In this case, carbon particles were collected on the surface of the pressboard by subjecting it to an AC electric field in an oil container that is heavily polluted with carbon. The electric field which allowed the particles to be collected was perpendicular to the surface while the test field was tangential. During the test with the 1-min step voltage application, it was observed that the electric field near the tip of the rod had a cleansing effect on the 124  pressboard, progressively removing most of the deposited carbon. The breakdown voltage of the contaminated sample was therefore not significantly lower than the clean one. 3.2.3.5 3.2. 3.5.4 .4 Recommended corr ectiv e action Corrective action for the reduction of particle content should be initiated only after proper evaluation of the dielectric strength of the oil. For screening purposes, the IEC 60156 test procedure is adequate but if there is a discrepancy between the contamination level and the dielectric strength of the oil, the dielectric test should be repeated with a procedure capable of showing the detrimental effect of particles, if any. For the purpose of these recommendations, a “marginal” dielectric performance is defined as a reduction of 30% or more of the new oil characteristics. The recommen recommended ded action for EHV transformers in service is summarized in Table 3-23. Table 3-23: Recommended action for contaminated oil Contaminatio n l evel evel Dielectric strength Recommended Re commended action No further action. Normal Good Poor Identify type of part particles. icles. Good Probably dirt or dry cellulose. Repeat dielectric strength with a test procedure appropriate for particles. Marginal Identify type of particles. Check moisture content. Filtering may be considered. Recheck particle count. Recheck dielectric strength with a test procedure appropriate for particles. Investigate source of particles. Marginal Good High Marginal Filtration or replacement is strongly recommended. 125  3.2.4 WINDING RESISTANCE TEST This test is a measure of the resistance of the conductors in the transformer winding. The resistance measurement is corrected to either 75 °C or 85 °C, depending on the average winding temperature rise of the transformer. The correction temperature is the average winding rise plus 20 °C. If the temperature rise for the transformer transformer is 55 °C, the winding resistance is corrected to 75 °C, and if it is 65 °C, the resistance is corrected to 85 °C. The winding resistance will typically change if there are shorted turns, loose connections on bushings, loose connections or high-contact resistance in tap changers and broken winding strands. These conditions will typically lead to hotspots in the winding or the affected areas and generate hot metal gases in the oil. The gases to look for in a DGA in case of poor connections are ethylene, ethane, and to some extent, methane. If the DGA suggests the possibility of any of the situations mentioned above, a winding resistance test is in order. Figure 3-14: 3-14: Lo w Resistanc e Ohmmeter - Bidd le Model 2470 247001 01 ((Courtesy Courtesy of Megger)14 3.2.4.1 MEASUREMENT METHOD FOR WINDING RESISTANCE MEASUREMENT Winding resistance measurements measurements are perform performed ed with a low-resistance ohmmeter such as shown in Figure 3-14. For a three phase wye-connected transformer, the resistance is measured for each phase-to-neutral winding; if delta-connected, the resistance is measured for each phase-to-phase winding. Note that for delta-connected transformers, the measured resistance for each phase is composed of a parallel combination of the winding under test and the series combination of the remaining windings. It is therefore recommended to make three measurements for each phase-to-phase winding in order to obtain the most accurate results. It is also recommended to allow the transformer to sit de-energized until temperatures are equalized (difference between top and bottom temperatures does not exceed 5 °C – ANSI/IEEE C57.12.90) before making resistance measurements. According to IEC 60076-1, in order to reduce measurement errors due to changes in temperature, some precautions should be taken before the measurement is made. For Dry type transformers , the transformer shall be at rest in a constant ambient temperature tempera ture for at least 3 hours. For Oil immersed transformers , the transformer should be under oil and without excitation for at least least 3 hours. In addition, it is im important portant to ensure that that the average ooilil 14 From website: http://www.megger.com/us/. 126  temperature (average of the top and bottom oil temperatures) is approximately the same as the winding temperature. To avoid an inadmissible winding temperature rise during the measurement, it is also recommended that the measuring current should be limited to no more than 10 percent of the rated current of the winding. In order to diagnose possible problems, the measured results are compared to the factory values, values of other phases of the same transformer, or sister units, if available. Before making such comparisons, the resistance has to be converted to a common temperature base of 75 °C or 85 °C, depending on what is reported on the transformer transform er factory test sheet. The corrected resistance is calculated c alculated as: RCT  RM CF  (CF  CT )  Winding Temp( o C ) where: RCT = Corrected resistance CF = 234.5 for copper windings; 225 for aluminum windings (IEEE C57.12.90) CF = 235 for copper windings; 225 for aluminum windings (IEC 60076-1) CT = 75 for 55C rise transformers; 85 for 65C rise transformers RM = Measured winding resistance Consistency in measurements and record keeping are the keys to making the proper analysis using this test. If the unit has a tap changer, it is important to compare resistances for the same tap position. The contact resistance of other tap positions can be investigated by moving taps and repeating the measurements. A measurement is deemedareacceptable no other further investigation if the individual phase readings within 2% and of the phase readings isforneeded three phase transformers or within 2% of the reported factory value for single phase transformers. Changes greater than 2% may be due to loose connections, broken conductor strands, short circuits, or bad tap changer contacts, or they can be caused by uncertainty in the temperature correction. For very low resistance values, it is not uncommon for measurements to be outside of the 2% limit even in a perfectly normal transformer. In such cases the measurement tolerances of test equipment may not be sufficient to resolve the acceptable 2% limit between measurements. When readings are outside the 2% range, it is recommended to investigate further or to consult the transformer manufacturer to determine acceptability of the results. 127  3.2.5 TRANSFORMER TURNS RATIO TEST (TTR) The function of a transformer is to transform power from one voltage level to another. The ratio test ensures that the transformer windings have the proper turns to produce the voltages required. The “turns ratio” is a measure of the RMS voltage applied to the primary terminals to the RMS voltage measured at the secondary terminals: r  Np Ns  Ep Es Where: r = voltage ratio E = open-circuit voltage N = number of turns p = primary s = secondary The IEEE standard (IEEE Standard 62) states that when rated voltage is applied to one winding of the transformer, all other rated voltages at no load shall be correct within one half of one percent of the nameplate readings. It also states that all tap voltages shall be correct to the nearest turn if the volts per turn exceed one half of one percent of the desired voltage. The ratio test verifies that these conditions are met. The IEC 60076-1 standard defines the permissible deviation of the actual to declared ratio as follows: Principal tapping for a specified first winding pair: the lesser of ± 0.5% of the declared voltage ratio or 0.1 times the actual short-circuit impedance. Other taps on the first winding pair and other winding pairs must be agreed upon, and must not be lower than the smaller of the two values stated above. Deviations in turns ratio readings indicate problems in one or both windings. In particular, the TTR test is useful for identifying shorted turns or open circuits in the windings, incorrect winding connections, and other internal faults or tap changer defects. If possible, the ratio at each tap setting should be checked against the nameplate ratio for each tap. Measurements are typically made by applying a known low voltage across the highvoltage winding (as a primary) so that the induced voltage on the secondary is lower, thereby reducing reducing hazards while pperform erforming ing the test. For a three pphase hase delta delta/wye /wye or wye/delta transformer, a three phase equivalency test is performed, i.e. the test is performed across corresponding single windings. The appropriate test configurations for various connections for three phase two-winding two-winding transformers are shown in Table 3-24. One of3-15. a variety of test sets used for performing these measurements is shown in Figure 128  Figure 3-1 3-15: 5: Three Phase TTR Test Set (C (Cour our tesy of Megger)15 The TTR test value should not be greater than 0.5 % or less than 0.5 % of the calculated values. For a three phase three-winding transformer, the following measurements will be made in a TTR assessment. Table 3-24: 3-24: TT TTR R Me Measurement asurement Configu ratio ns Connection Apply Voltage Voltage Acr os s Wi nd in g Measur e Voltage Measur Acr os s Wi nd in ing g Calculate Voltage Ratios Delta-Delta H1-H2 X1-X2 VH1-H2/VX1-X2 H1-H3 H2-H3 H1-H2 H1-H3 H2-H3 H0-H1 H0-H2 H0-H3 H0-H1 H0-H2 H0-H3 X1-X3 X2-X3 X0-X3 X0-X2 X0-X1 X0-X1 X0-X2 X0-X3 X1-X2 X1-X3 X2-X3 H1-H3/VX1-X3 VH2-H3 X2-X3 VH1-H2/VX0-X3 VH1-H3/VX0-X2 VH2-H3/VX0-X1 VH0-H1/VX0-X1 VH0-H2/VX0-X2 VH0-H3/VX0-X3 VH0-H1/VX1-X2 VH0-H2/VX1-X3 VH0-H3/VX2-X3 Delta-Wye Wye-Wye Wye-Delta For a three-winding transformer, the ratios can be from the primary to both the secondary and the tertiary windings and can be used in further diagnosing which winding may to have a problem. For problem example, a wye/wye/wye Table 3-25 can be used diagnose possible problems s inin the 0-1 phase of configuration, the transform transformer. er. Table 3-25: 3-25: Using TTR to Diagno se Winding Pro blems Measure Voltage App ly Voltage H0-H1 H0-H2 H0-H3 15 ® X0 X0-X1 -X1 Y0-Y1 Possible Diagnosis Ratio Abnormal Ratio Abnormal Ratio OK Ratio Abnormal Ratio Abnormal Problem in X0-X1 Winding Problem in H0-H1 Winding Ratio OK Problem in Y0-Y1 Winding From Megger Website: W ebsite: http://www.megger.com/us/products/ProductDetails.php?ID=233&Description=ttr .  129 Note that the TTR test can only indicate if one of the problems problems listed above is present in the transformer. It cannot pinpoint the exact location of the fault. This must be investigated via an internal inspection, which may involve un-tank un-tanking ing the transform transformer. er. 130  3.2.6 INSULATION RESISTANCE The insulation resistance test, also called Megger test, is used to determine the leakage current resistance of the insulation. The resistance is a function of the moisture and impurity content of the insulation as well as the insulation temperature. At a constant voltage, the resistance also depends on the strength of the electric field across the insulation and therefore is a function of the size and construction of the transformer. Primarily, this measurement gives information about the condition of the insulation and ensures that the leakage current is adequate adequately ly small. 3.2.6.1 MEASUREMENT Insulation resistance of a transformer is measured by means of a resistance meter using a DC voltage. In measuring resistance, it is recommended to always be sure that the tank and core are grounded. Each winding of the transformer is then short circuited at the terminals. Resistance measurements are made between each winding and all other windings grounded. Windings are never left floating during insulation resistance measurements. When any winding is installed with a solid ground, the ground must be removed in order to measure the insulation resistance of that winding to the other windings grounded. If the ground insulation resistance that winding cannot be measured. It is cannot treated be as removed, part of thethe grounded section of the of circuit. Insulation resistance is expressed in mega ohms (M ). On a two winding transformer the following measurement configurations are used: 1. Measure from th the e high voltage winding winding to the lo low w voltage windin windingg and ground [H-LG] 2. Measure from the low voltage winding to the hhigh igh voltage winding and ground [L-HG] 3. Measure from th the e high and low voltage windin windingg to ground [HL [HL-G] -G] This test is easily performed in the field. Many manufacturers require that this test be performed a transformer, to preclude start up failure entry of moistureprior into totheenergizing transformer during shipment or storage. The test caused can alsobydetect other ground circuits that may exist in the transformer that may have been caused by shipping damage. damage. The test checks the complete circuit – bushings, leads and coils. The measurement duration is 1 minute. The resistance readings R15 and R60 are taken 15 and 60 seconds after connecting the voltage. In order to compare these readings with future measurements, it is important to record on the test report, the temperature, measuring voltage, the meter used, as well as the measured resistances. Since insulation resistances may vary with applied voltage, any comparisons must be made with measurements at the same voltage. WARNINGS The following precautions should be taken in performing the insulation resistance test: test: 131   The test should bbee discontin discontinued ued imm immediately ediately if the curre current nt beg begins ins to increase without stabilizing  Under no conditions should tthe he test be m made ade while the transformer is under vacuum  After the test has been completed all terminals should be grounded for a period of time sufficient to allow any trapped charges to decay to a negligible value 3.2.6.2 INTERPRETATION The IEC Standard 60076-1 and the IEEE Standard C57.12.90 provide no limits for insulation resistances. However, the rratio atio R60:R15, also called the absorption ratio, is normally in the range 1.3 – 3 in a dried transformer. The condition of the insulation can also be determined by comparing the measured resistance at 1 minute, R 60, to a minimum value for the voltage class of the winding. This comparison is performed only after all measurements are converted to their 20 °C equivalents using the coefficients in Table 3-26. For example, if the measured value is 20 M at 12 °C, according the table this measurement measurement is equivalent to 11,8 (=20 x 0,59) M at 20 °C. The minimum measured resistance corrected to 20 °C is given by the relationsh relationship ip16 : R60  CE kVA Where:  kVA is the rrated ated capacity of tthe he winding under test,  C is a constant: o 0.8 for oil-filled transformers at 20 °C, or o 16.0 for dry, com compound pound filled or unt untanked anked ooilil filled transform transformers ers  E is the voltage rating of the winding under test  R60 is the 1 minute reading of insulation resistance of winding to ground with other windings grounded or between windings in M at 20°C Table 3-26: Insulation Resistance Correction Factors For Conv ersion o f Test Temperatu Temperatu re to 20 °°C C [74] o o o Temp ( C) Coeffic ient Temp ( C) Coeffic ient Temp ( C) Coefficient 0 5 10 11 12 13 14 15 16 17 0.25 0.36 0.50 0.54 0.59 0.62 0.66 0.70 0.76 0.82 24 25 26 27 28 29 30 31 32 33 1.33 1.40 1.50 1.60 1.74 1.85 1.98 2.10 2.30 2.45 41 42 43 44 45 46 47 48 49 50 4.20 4.50 4.80 5.10 5.60 5.95 6.20 6.80 7.20 7.85 16 M. Horning et. al., Transformer Maintenance Guide, pp. 108-109, 2001 132  o 3.2.6.3 o o Temp ( C) Coeffic ient Temp ( C) Coeffic ient Temp ( C) Coefficient 18 19 20 21 22 23 24 0.86 0.96 1.00 1.08 1.15 1.25 1.33 34 35 36 37 38 39 40 2.60 2.80 3.00 3.20 3.40 3.70 3.95 55 60 65 70 75 80 11.20 15.85 22.40 31.75 44.70 63.50 POLARIZATION INDEX Polarization index is the relationship between the measured resistance after 10 minutes and that measured after 1 minute. Since the conduction processes are enhanced for an insulation system that is contaminated with moisture or impurities, the leakage current will increase at a greater rate than for a dry, clean insulation. Consequently, under the same test configuration, the insulation resistance of a wet or contaminated insulation system will settle faster and at a lower value than that for a dry insulation. The result is that the polarization index for a wet insulation will be lower than that for a dry insulation system. the polarization index is a ratio,can it does not require conversion to a common Since temperature base before comparisons be made. It also does not require for there to be previous measurem measurements ents before an assess assessment ment of the insulation condition can be made. The following guidelines are used to assess the condition of insulation based on the polarization index. Table 3-27 3-27:: Polarization Ind ex Interpretatio n Guide Polarization Index Insulation Condition <1 >2 Unsatisfactory Good 133  3.2.7 INSULATION POWER FACTOR TESTS Insulation power factor tests are performed on transformer insulation to determine the condition of the capacitive insulation between the windings, between windings and core, and between windings and the tank or other grounded components in the transformer. There are three test modes essential to the evaluation of an insulation system: Ungrounded Specimen Test (UST), Grounded Specimen Test (GST), and Grounded Specimen Test with Guard (GST/g). These configurations allow various sections of the insulation system to be tested separate separately. ly. Power factor test instrume instruments nts typically have three leads: an output high-vo high-voltage ltage lead for energizing the test object, input measurement, and ground leads that measure current through the insulation system. Internally, switches allow either input lead to be connected to a current/wattmeter input or guard, depending on the testing configuration. In the UST configuration, current flowing in the insulation between the high-voltage lead and the measurement lead is measured by connecting the measurement lead to the current/wattmeter input. The ground lead is connected to the guard, and therefore currents that flow through the ground lead measured by the In thebyGST configuration, all currents flowing from theare HVnot lead to ground are meter. measured the meter. This is accomplished by internally connecting both the measurement and the ground leads to the input of the current/wattmeter. In the GST/g configuration, the measurement lead is connected to the guard, and the ground lead is connected to the input to the current/w c urrent/wattmeter attmeter device. The only measured current is what is in the direct path from the HV lead to ground. The UST values can also be calculated from the difference betw between een the measured GST and the GST/g values. v alues. The reason for making all these measurements is to allow for the evaluation of the various sections of insulation in the transformer. However, the most important of these measurements is the UST test, since it measures across the major insulation of the transformer. The power factor is calculated from the measured current and watts loss recorded by the meter according to the following equation: PF(%) = 10 x Loss(Watts)/Current(m Loss(Watts)/Current(mA) A) A system that is widely used by utilities in measuring power factor of insulation systems is Doble Engineering’s M4000 Automated Insulation Analyzer shown in Figure 3-16. Figure 3-16: 3-16: Doble M400 M4000 0 Autom ated Insulatio n Analyzer 17 17 From the Doble Engineering Website: www.doble.com 134 3.2.7.1  T WO-WINDING T RANSFORMER In order to perform power factor tests on a three phase, two-winding transformer, it is necessary to connect all high-voltage bushing bushingss together and all low-voltage and neutral bushings together. Figure 3-17: Schematic of Two-Winding Transformer Insulation Capacitance for Power Factor Measurements 18 The capacitance between these two terminals and between each terminal and the ground terminal, terminal, represented by the tank and core, are shown schematically s chematically in Figure 3-17. In Figure 3-17, the capacitances are defined as follows:  CH represents the insulation between the high-voltage winding conductor and the grounded tank and core. The capacitance takes into account the HV bushings, structural insulating members, the de-energized tap changer insulation, and the insulating fluid.  CL represents the insulation between the low-voltage winding conductors and the grounded tank and core. The capacitance takes into account the LV bushings, the winding insulation, the structural insulating members, the LTC insulation, and the insulating fluid. CHL represents the insulation the the highand low-voltage windings and  includes the winding insulation between barriers and insulating fluid. 18 The IEC equivalent nomenclature for the winding terminals is as follows: H1=1U; H2=1V, H3=1W; X1=2U; X2=2V; X3=2W, X0=2N 135  3.2.7.1 3.2. 7.1.1 .1 Testing of Two-Windin g Transform ers For a two-winding transformer, transformer, there are six different tests that are performed to assess the insulation condition in the various parts of the transformer insulation. For each test, high voltage is applied to one set of windings, and current from the other winding and the ground terminal are fed into the measurement equipment. Table 3-28 shows which measurement lead is applied to the transformer windings for each test configuration. It also shows which measurement leads, if any, are guarded and ultimately the insulation capacitance that is measured. Figure 3-18 - Figure 3-23 show the actual test setup for the tests described in Table 3-28. Table 3-28: 3-28: P Power ower Factor Measurement Setup fo r Two-Windin g Transfor mers Test Mode HV Windin g LV Windin g Tank/C Tank/Core ore Measur Measur ed Capacitance GST GST/g HV Lead HV Lead Gnd. Lead Gnd. Lead CH+CHL CH UST HV Lead Meas. Lead Meas. Lead (on guard) Meas. Lead Gnd. Lead (on guard) Gnd. Lead Gnd. Lead CHL GST GST/g UST Meas. Lead Meas. Lead (on guard) Meas. Lead HV Lead HV Lead HV Lead Gnd. Lead (on guard) CL+CHL CL CHL Figur e 3-18: 3-18: Power Factor Me Measurement asurement of CHL CHL + CH Insul ation (GST (GST)) 136  Figur e 3-19: 3-19: Power Factor Measurement of CH Insulatio n (GST/g) (GST/g) Figure 3-20: Power Factor Measurement of CHL Insu lation (UST) (UST) 137  Figur e 3-21 3-21 : Power Factor Mea Measurement surement of CHL CHL + CL Insulatio n (GS (GST) T) Figure 3-22: 3-22: Power Factor Measu Measu rement of CL Insulatio n (GST/g) (GST/g) 138  Figure 3-23: Power Factor Measurement of CHL Insu lation (UST) (UST) 3.2.7.2 T HREE-WINDING T RANSFORMER The various insulation capacitances of a three-windin three-windingg transformer are shown in Figure 3-24. The power factor of each of these insulation sections can be examined by the measurement measurem ent configurations defined in Table 3-29. Figure 3-24: Schematic of Three-Winding Transformer Insulation Capacitance for Power Factor Measurements 139  Table 3-29: Power Factor Measurement Configuration for Three-Winding Transformers Test Mode HV Windin g LV Winding TV Winding Tank/C Tank/Core ore Measur Measur ed Capacitance GST/g HV Lead Meas. Lead Meas. Lead Gnd. Lead CH GST/g (on HVguard) Lead (on guard) Meas. Lead (on guard) HV Lead Gnd. Lead CL Gnd. Lead CT UST Meas. Lead (on guard) Meas. Lead (on guard) HV Lead HV Lead UST Gnd. Lead (on guard) Gnd. Lead (on guard) Gnd. Lead (on guard) Gnd. Lead (on guard) CHL UST Gnd. Lead (on guard) Meas. Lead GST/g 3.2.7.3 Meas. Lead (on guard) Meas. Lead Gnd. Lead (on guard) HV Lead Meas. Lead CHT CLT TYPICAL I NSULATION POWER FACTOR VAL UES In a study conducted by Doble Engineering Company, the power for theshown highvoltage winding to ground insulation for 760 transformers shows thefactor distribution in Figure 3-25. The corrected power factor for up to 95 percent of the transform transformers ers was below 0.7 %. Figure 3-25: 3-25: High Voltage to Ground Insulation Power Factor for Representative Representative Good Good Insulation Systems 140 3.2.7.4  GENERAL GUIDELINES FOR A SSESSING POWER F ACTOR VAL UES In making an assessment of a power factor reading, it is advisable to compare the test results to previous measurements. The rate of increase in power factor would show a condition that has stabilized or is rapidly deteriorating. The following are general guidelines provided by Doble Engineering in assessing power factor results for oil-filled power transformers: Table 3-30 3-30:: Power Facto Facto r Diagnosi s for Oil-Filled Power Transform ers Power Factor Factor Reading Reading 0.5% >0.5% BUT 0.7% >0.7% BUT 1.0% (& Increasing) >1.0% Possible Insulation Condition Good Deteriorated Investigate Bad For oil-filled distribution transformers, the power factor numbers in the table are doubled. For power factor values that are classified as bad or investigate, other test methods are necessary to positively identify the cause of the high power factor. Such tests include dissolved gas-in-oil analysis, moisture-in-oil analysis, dielectric frequency response analysis (DFR), frequency response analysis (FRA/SFRA), and power factor tip-up test. Most of these tests are discussed in more detail in later sections. A discussion of the power factor tip-up test follows. 3.2.7.5 POWER FACTOR T IP-UP T ESTS The power factor tip-up test is perform performed ed by applying voltage in equal steps from zero to the maximum allowed voltage. The test is performed on the section of insulation with highest power factor reading. For each applied voltage, the current and watts loss through the insulation is measured, and the power factor is calculated. If moisture or other polar contaminants are the cause of the high power factor, the measured power factor will be essentially the same for all applied voltages. If the power factor increases with voltage, there is likely ionic contamination and/or carbonization of the oil or windings for oil-filled transformers. For dry type transformers, the problem may be due to ionic contaminants or the presence of voids in the winding insulation. insulation. 141  3.2.8 CORE INSULATION RESISTANCE MEASUREMENT Generally, the core laminations in a core form type transformer are insulated from ground, and the core is deliberately grounded at a single point. Measurement of the core insulation resistance allows for investigating accidental grounds which result in circulating currents if thereofisthe more than one connection between the core and ground. The dielectric withstand core-to-ground insulation is typically specified to be above 2 kV AC. The intentional core ground connection is usually mounted under a manhole at the top of the transformer or through the tank wall via a small low-voltage bushing. Either design allows the ground to be easily disconnected and allows a measurement of the resistance between core and ground. However, there are shell form designs in which the core ground is inaccessible. In such cases this measurement cannot be made. Several factors can lead to an inadvertent ground connection to the core: the coreground insulation can deteriorate to a point where the insulation becomes resistive; the core-ground insulation can become damaged during transportation of a transformer; or the core-ground insulation can become damaged in a through-fault incident. If an unintentional unintention core ground is established as a The result of any thehotspots above conditions, will likely beal circulating currents in the core. result willofbe in the corethere and surrounding metal structures. The presence of these hotspots can be detected using a DGA screening. Key gases to look for are ethane, ethylene, and/or possibly methane. Depending on the location of the hotspots, cellulose may be involved, and the gases may include CO and CO2. 3.2.8.1 MEASUREMENT AND DIAGNOSIS OF INADVERTENT CORE GROUNDS The gas signature attributable to hotspots due to inadvertent core grounds can also be present if there is a poor connection at the bottom of a bushing or a bad tap changer contact. Therefore, this test is only necessary if a winding resistance test shows that all connections are good and if the tap changer contacts are assessed to be in good condition. The test is performed using a standard DC Megger® such as the one shown in Figure 3-26. The two test leads of the Megger test set are connected between the isolated core-ground lead and the transformer transformer ground. A DC voltage of no more than 1000 volts is applied across the leads, and the resistance is measured. Depending on the resulting resistance, Table 3-31 can be used to guide what action must be taken. 142  Figure 3-26: DC Megger Megger Test Set (Courtesy o f Megger) 19 Table 3-3 3-31: 1: Diagnosi ng Inadvertent Core-Ground Problems Measured Core Ground Resistance  1000 M  100 M  10 to < 100 M  1 to < 10 M Possible Interpretation Interpretation New transformer. Good coreground insulation. Service aged transformer. Acceptable core ground insulation. Deteriorating core ground insulation. Deteriorated insulation is possible cause of circulating currents. 200-1000 Ohms Possible high-resistance ground between core and ground. < 10 Ohms Solid connection between core and ground. Action NONE NONE Investigate cause of deterioration and mitigate. Investigate and correct before re-energization. Check to make sure a limiting resistor is not being used in the core-ground circuit. If not, there is a possible high-resistance ground that must be corrected. Investigate and correct before re-energization. If the core-ground insulation is less than 10 M , the first step in investigating the inadvertent ground connection connection is to switch to an ohmmeter and measure the resis resistance tance between the core and ground. This should help establish whether there is a solid ground connection or a high-resistance ground present. In either case, there are field techniques available in eliminating the unintentional grounds (see IEEE Standard 62). 19 From AVO website: http://www.avomegger.com/. http://www.avomegger.com/ . 143  3.2.9 EXCITATION CURRENT TESTS The excitation current test is one of the means of identifying problems associated with the core or winding of the transformer. The test can possibly detect core problems such as shorted core laminations and poor joints. Winding problems detected include short circuited or open circuited turns, poor electrical connections, tap changer problems, and other possible core and winding problems. The exciting current consists of a magnetizing component and a loss component. The magnitude of the magnetizing component is determined by the shape of the performance curve of the core steel, its operating flux density, and the number of turns in the primary winding. The loss component is determined by the losses in the core. Joint construction severely affects the magnitude of the excitation current. Changes in the hysteresis and eddy current characteristics due to handling the steel also affect the excitation current. To perform the test, voltage is applied to the primary windings one at a time with all other windings left open. The excitation current of a transformer is the current which the transformer draws when voltage is applied to its primary terminals with the secondary terminal(DC) open.tests. It is important to perform the excitation current tests before any direct current DC tests leave a residual magnetism in the core that would distort an excitation current test. Before performing an excitation current test, the following steps are necessary [75]:  Disconnect all loads and de-energize the transformer.  It is recommended that the test voltage be applied to the HV w windings. indings. Exercise caution in the vicinity of all transformer terminals because voltage will be induced in all windings during a test.  Winding terminals terminals normally grounded in-service should be grounded during tests, except for the particular winding energized for the test. load ad tap changer (LTC) should be set to neutral, then to  For routine tests, the lo one step above neutral, then to one step below neutral, and then to full raise or full lower. To ensure that the tap selector is functioning properly throughout the entire range of selection, you may want to perform tests on all LTC positions.  Test voltages should not exceed the rated line-to-line voltage for deltaconnected windings or rated line-to-neutral voltage for wye-connected windings. These tests are generally made at 2.5, 5, or 10 kV, as the capacity of the test equipment permits.  Test voltages should should be the same for each phase. Because of tthe he nonlinear behavior of exciting current, test voltages should be set accurately if results are to be compared. If excitation tests have previously been performed, the same test voltage should be used for the current test. 144  Excitation current tests performed on all tap positions of a transformer with a reactance-type load tap changer can have the following patterns. The currents measured on the even steps and neutral positions are similar to each other but different from those measured on the odd steps. The currents measured on the odd steps are similar to each other. The difference is attributed to how the reactorswitching device is connected to the tap winding when the tap is on an even or odd position. For the even numbered and neutral positions, the two contacts of the reactor-switching device are on the same stationary contact. For odd numbered positions, the switching contacts bridge adjacent stationary stationary contacts [76]. 3.2.9.1 MEASUREMENT SETUP The excitation current test can be performed using any high-voltage source and a precision amplifier. However, since both are present in a power factor test set, these test sets are normally used to perform the excitation current test. The testing mode for all measurements is set to UST (Ungrounded Specimen Test). See Figure 3-27, Figure 3-28, and Figure 3-29 for the setup of the excitation current measurements for various transformer configurations. Table 3-32 is a summary of the test connections and the means for analyzing test results. For single phase transformers, the test is performed with high-voltage windings energized alternately from opposite ends and reading the excitation current in both configurations. The two currents obtained should be the same. Currents recorded for single phase transformers should be compared either with similar units or with data obtained from previous tests on the same unit. If single phase excitation current tests were included in the factory test specifications, comparing test data reveals changes undergone between between the factory aand nd the field. For three phase wye-connected transformers, the three measurements routinely made are H1-H0, H2-H0, and H3-H0. The usual pattern of the exciting current values is such that two of the measure measuredd currents are high aand nd similar, and the remaining one is lower. The lower value is usually associated with the winding wound on the middle leg because the reluctance of the magnetic circuit associated with this winding is lower than the other two windings. also beordone the individual of three phase transformers if theThis unitshould is suspect, if theoninitial exciting phases current measurements are questionab questionable. le. For three phase delta-connected transformers, the three measurements routinely made are H1-H2, H2-H3, and H3-H1. The usual pattern for these transformers is two measured currents that are approximately equal and higher than the third measured current. Again, the lower current value is ordinarily associated with the winding wound on the middle leg [77]. With delta-connected transformers, the two highervalued currents are occasionally not equal. This can be attributed to the shunting affect of the un-energized winding being parallel with the energized winding. Test procedures are available to eliminate the shunting effect of the un-energized winding [76]. 145  20 Table 3-32: 3-32: Excitation Current Test Connecti on Usin g Power Factor Test Set Transformer Type and Connection Energized Lead Measurement Lead 21 Single Phase H1 H2 Three Phase Core Form Wye-Connected 3-limb core Three Phase Shell Form Wye-Connected D core Three Phase Core Form WyeConnected 5-limb core Three Phase Shell Form Wye-Connected 7-limb core Three Phase DeltaConnected Floating Terminals Measured Excitation Current Normal Current Pattern H2 H1 X1 X2 X1 X2 IH1-H2 IH2-H1 IH1-H2 ~ I H2-H1 H1 H2 H3 H0 H0 H0 H2 H3 ,X 1 X2 X3 H1 H3 ,X 1 X2 X3 H1 H2 ,X 1 X2 X3 IH1-H0 IH2-H0 IH3-H0 (I H1-H0 ~ I H3-H0) > I H2-H0 H1 H2 H3 H0 H0 H0 H2 H3 ,X 1 X2 X3 H1 H3 ,X 1 X2 X3 H1 H2 ,X 1 X2 X3 IH1-H0 IH2-H0 IH3-H0 (I H1-H0 ~ I H3-H0) > I H2-H0 H1 H2 H3 H0 H0 H0 H2 H3 ,X 1 X2 X3 H1 H3 ,X 1 X2 X3 H1 H2 ,X 1 X2 X3 IH1-H0 IH2-H0 IH3-H0 IH1-H0 ~ I H2-H0 ~ I H3-H0 (The middle phase may be slightly higher) H1 H2 H0 H0 H2 H3 ,X 1 X2 X3 H1 H3 ,X 1 X2 X3 IH1-H0 IH2-H0 (I H1-H0 ~ I H3-H0) > I H2-H0 H3 H0 H1 H2 ,X 1 X2 X3 IH3-H0 H1 H2 H3 H2 H3 H1 X1 X2 X3 X1 X2 X3 X1 X2 X3 IH1-H2 IH2-H3 IH3-H1 Ground Lead H3 H1 H2 (I H2-H3 ~ I H3-H1) < I H1-H2 Table 3-32 lists the forms of transformer construction, the associated magnetic core configuration, and the usual pattern of core excitation current measurements. In old designs with non-step lap cores, the quality of the joint gaps has a large effect on the magnitude of the exciting current such that end phases can have significantly different measured values of exciting current. The magnitude of the difference can well be in the same range or even higher than the difference between the measured exciting current of the middle and end phases. Therefore, the rules on the relative magnitudes of the exciting current may not apply to these cores. In such cases, only much greater differences need to be considered as an indication of a problem. 20 The IEC equivalent nomenclature for the winding terminals is as follows: H1=1U; H2=1V, H3=1W; 21 H0=1N; X1=2U; X2=2V; X3=2W, X0=2N All measurements are performed with the test set in UST mode.  If the secondary winding is wye connected, the neutral (X 0) should be connected to ground. 146  Figure 3-27: Excitation Current Test Method for Single Phase Transformers Figure 3-28: 3-28: Excitatio n Current Test Method f or Three Phase W Wye-C ye-Con on nected Transfo rmers Figure 3-29: 3-29: Excitatio n Current Test Method f or Three Phase Delta-C Delta-Connect onnect ed Transfo rmers 147  3.2.9.2 A NALYSIS OF EXCITATION CURRENT RESULTS If the excitation current is less than 50 mA, the difference between the two higher currents for a three phase transformer should be less than 10 %. If the excitation current than 50 mA,these the difference should begreater. less than 5 %.this In general, there is isangreater internal problem, differences will be When happens,if other tests should also show abnormalities and an internal inspection should be considered. If factory tests or prior tests exist, the results should be compared with them to assess any deviations. High precision does not appear to be necessary in excitation current tests. The serious faults that have been found have increased excitatio excit ationn curr current ent magni tudes by greater than 10% over nnorm ormal al values [75]. 148  3.2.10 INFRARED THERMOGRAPHY ANALYSIS OF TRANSFORMERS AND ACCESSORIES Thermography is a method of inspecting electrical and mechanical equipment by obtaining heat distribution pictures. This inspection method is based on the fact that most components in a system show an increase in temperature when malfunctioning [78]. problems caused a change of in local resistance will consume more powerAny andlocalized generate heat. The local by temperature the resulting hotspot will be higher than the surrounding temperatures or that of a reference point. By observing the heat patterns in operational system components, infrared thermography is now used to detect loose connections, unbalanced load and overload conditions, component deterioration, and other potential problems [79]. 3.2.10.1 T HE T HERMOGRAPHY PROCESS The inspection tool used by thermographers is the thermal imager (infrared camera). These are sophisticated devices that measure the natural emissions of infrared radiation from a heated object and produce a thermal picture. Modern thermal imagers are portable with easily operated controls (see Figure 3-30 for an example IR camera). As physical contact with the system is not required, inspections can be made under full operational conditions, resulting in no downtime. Figure 3-30: Infrared Camera - FLIR Model ThermaCAM® P65 22 When an object is heated, it radiates electromagnetic energy. The amount of energy is related to the object’s temperature. The thermal imager can determine the temperature of the object without physical contact by measuring the emitted energy. The energy from a heated object is radiated at different levels across the electromagnetic electromagnetic spectrum. In most industrial applications, it is i s the energy radiated at infrared wavelengths wavelengths which is used to determine the object’s temperature. The thermal imager focuses the emitted energy via an optical system onto a detector. The detector converts infrared energy into an electrical voltage which is used to build the thermal picture in the operator’s viewfinder on board the thermal imager after amplification and complex signal processing. 22 FLIR website: http://www.flirthermography.com/cameras/camera/1016/ . 149  3.2.10.2 CRITERIA FOR EVALUATING INFRARED MEASUREMENTS When carrying out thermographic inspections, faults are often identified by comparing heat patterns in similar components operating under similar loads. There is typically software available with the infrared camera to analyze the temperature signature of the object under test. A reference point is establis established hed on the object for normal temperature. The temperature rise of all other pointsare on hotspots the objecton is then evaluated relation of to the reference point temperature. If there the object, the in criticality hotspots is evaluated in regards to the magnitude of deviation from the reference temperature (temperature rise above reference). There are several guidelines for diagnosing the criticality based on the temperature rises. For example, in performing temperature-rise tempera ture-rise tests on transform transformers, ers, it is recommended that the surface temperatur temperaturee of the tank, as measured by an infrared cam camera, era, be no more than 20 °C higher than the top oil temperature of the transformer [80]. Criteria established by NASA in evaluating electrical components at its facilities are given in Table 3-33. Table 3-33: 3-33: Infrared Temperature Crit eria 23 3.2.10.3 Criticality Temperature Above Reference, Industry Nominal 0 to 10 oC Intermediate 10 to 20 oC Serious 20 to 40 oC Critical over 40 oC EXAMPLE USES OF INFRARED THERMOGRAPHY Condition Nominal possibility of permanent damage. Repair next maintenance period. Possibility of permanent damage. Repair soon. Probability of permanent damage to item and surrounding area. Repair immediately. Failure imminent. DIAGNOSTICS ON P OWER TRANSFORMERS [81] 24 This section provides a few examples of the use of infrared therm thermography ography to diagnose problemss in transformers and acc problem accessories. essories. 3.2.1 3.2 .10.3 0.3.1 .1 Loose connection at bushing outlet terminal When there is a loose connection at the terminal from the bushing to the bus work, it will lead to overheating of the bushing top terminal when under load. The thermograph will show the bushing terminal as hot, while the body of the porcelain will show normal temperatures. tempera tures. Figure 3-31 shows a thermograph of a hot bushing terminal. 23 NASA RCM Specs. Examples are used courtesy of FLIR Systems: www.flirthermography.com. www.flirthermography.com . 24 150  Figure 3-31: Bushing Terminal Overheating Thermograph 3.2.1 3.2 .10.3 0.3.2 .2 Bloc ked oil flow in radiators or radiator shut off In case of a malfunction that stops or restricts the flow of oil through a radiator, this will show up on an infrared scan. The image will reveal dim areas where the oil flow is restricted and brighter areas where normal oil flow is taking place. Figure 3-32: 3-32: Thermograph y of a Shut-Off Ra Radiato diato r Bank 3.2.10.3 3.2. 10.3.3 .3 LTC overheatin g Under normal operating conditions and because of I2R and eddy current heating, the main tank of a transformer will have a higher temperature than the LTC tank in which there is essentially no heat generation under non-switching conditions. If hotspots develop in the LTC compartment, this will increase the overall temperature of the LTC compartment, which may become hotter than the main transformer tank. Such a situation will be evident on an infrared scan, as shown in Figure 3-33. 151  Figure 3-33: 3-33: LTC C Compartm ompartm ent Overheating Due to Possib le Hots Hots pot s in LTC 3.2.1 3.2 .10.3 0.3.4 .4 Low oil level in transformer or bushing If a transformer (or especially a bushing) has a low oil level, a thermograph will show a dim image for the region without oil and a much brighter image in the areas with oil. An example of this defect is shown in Figure 3-34. Figure 3-34: Low Oil Level in Transformer 3.2.10.3 3.2. 10.3.5 .5 Moist ure contami natio n of surge arrester When the internal components of an arrester become contaminated with moisture due to poor sealing or defects in the porcelain, the resistance of the internal components will increase. Depending on the extent of the contamination, sections of the surge arrester body will show localized overheating as compared to other arresters on the transformer. In this case, the moist regions will show up as dim regions in the thermograph image [82]. 152  3.2.11 3.2.11.1 3.2.11.1 3.2. 11.1.1 .1 B USHINGS ANSI & IEC – COMMON DIAGNOSTIC TOOLS Oil leakage ins pecti on A visual inspection for leakage may be performed during normal station supervision. 3.2.11.1 3.2. 11.1.2 .2 Insul ator ins pectio n and cleaning Under conditions of extreme pollution it may be necessary to clean the insulator surface. The bushing MUST be offline before and during any cleaning operations. 3.2.11.1 3.2. 11.1.2.1 .2.1 Porcel ain ins ulato rs Clean the porcelain insulator with water-jet or wiping with a moist cloth. If necessary, ethyl-alcohol or ethyl-acetatte may be used. 3.2.11.1 3.2. 11.1.2.2 .2.2 Sili con rubber ins ulator s Clean the porcelain insulator with water-jet or wiping with a moist cloth. If necessay, ethyl-alcohol or ethyl-acetatte may be used. 1,1,1, -Thrichlorethane or Methylchloride are not recommended due to their possibly harmful and environmentally detrimental properties. 3.2.11.1.3 Thermovision Hot spots on the bushing surface can be detected by using an Infrared (IR)-sensitive camera (see Figure 3-35). At maximum rated current, the bushing outer terminal should show a temperature of about 35-45 °C above the ambient air. Significantly higher temperatures, especially at lower current loading, can be an indication of bad connections. Figure 3-35 3-35 : Me Measureme asurement nt in dicating po or cu rrent path b etween etween bushin g inn er and outer terminal 153  3.2.11.1 3.2. 11.1.4 .4 Oil sampli ng from bus hing Oil samples shall preferably be taken during dry weather conditions. If, due to some urgent reason, the sample is taken under any other conditions, the following must be observed: - Clean the area around the sampling plug carefully. Protect the area around the sampling plug from rain. The internal pressure of the bushing must not be altered before and after the sampling as the bushing is supposed to work within a specified range. This requirement is satisfied if the sample is taken when the mean temperature of the bushing is between 0°C and 30°C. The time when the bushing is open shall be as short as possible. Flushing with dry air or nitrogen is normally not necessary. The oil removed from the bushing shall always be replaced by the same volume of new transformer oil. The new oil shall comply with IEC 296, class II and shall be clean and dry. The gasket shall s hall always be replaced when the bushing is re-sealed re-sealed.. Sampling procedure for GOB, GOE and GOH The sample is taken from a plug pl ug in the top of the bushing, preferably with a syringe with a rubber hose connected. The location for the sampling plug is shown in Figure 3-36. The dimension of the gasket is given in Table 3-34. The material of the gasket shall be Nitrile rubber with a hardness of 70 Shore. 154  Figure 3-36 3-36 : Location of oil sampling p lugs on s ome of the most common bu shing typ es. The tightening torque for the M8 sealing plug on GOB, GOE and GOH shall be 20 Nm. The tightening torque for the M16 sealing plug on GOE shall be 50 Nm. Table 3-34 3-34:: Dimensi ons for gask ets. Gasket M8 d (mm) 8 D (mm) 16 T (mm) 3 M16 5/8" 14 14 35 35 4 4 Sampling pr ocedure for GOEK, Sampling GOEK, GOM GOM and other bushings with sampling valve on the flange Connect the end of the hose to a suitable nipple and connect the nipple to the valve on the flange. The thread in the valve is (R 1/4") BSPT 1/4". Suck out the oil. Depend D epending ing on the temperature the pressure inside the bushing might be above or below atmospheric pressure. After the sampling is finished the bushing shall not be energized within 12 hours. Sampling p roc edure for GOA, GOA, GOC GOC and GOG On the GOA, GOC and GOG bushings, the oil samples are taken from the hole for the oil level plug on the top housing as shown in Figure 3-36. If the bushing is vertically 155  mounted, the oil level is right at the plug level at 20°C. The sample is sucked out by a syringe. If the oil temperature is slightly higher than 20°C the oil level will be above the plug level. In such a case the hose on the syringe should be equipped with a nipple as shown in Figure 3-37. The oil plug is removed and the hose with the nipple is attached immediately. If the temperature is below 20 °C, the oil level will be below the plug and the sample is sucked out according to Figure 3-38. The tightening torque for the 5/8" sealing plug shall be 50 Nm. Figure 3-3 3-37 7 : Samplin g o n GOA at T>20 °C Figure 3-3 3-38 8 : Samplin g o n GOA at T<20 °C 3.2.11.1 3.2. 11.1.5 .5 Disso lved Gas Analys is (DG (DGA) A) This method for diagnostics can only be used on oil filled bushings, for example, GOx types. Normally, it is not recommen recommended ded to take oil samples from bushings. The bushing is sealed and tightness tested at the time of manufacturing. In order to take an oil sample, the bushing has to be opened and this introduces a risk of improper re-sealing after the sampling is finished. However, when a problem is known, for example e xample high power factor over C1, there might be a need for oil sampling and gas analysis. The interpretation of the analysis is done according to Technical Report IEC 61464. If questions remain, ABB can assist with the evaluation. 3.2.11.1 3.2. 11.1.6 .6 Moist ure analysis There is awhen risk of improperly sealingfora example bushing high if it ispower opened to over take C an1, oil sample. However, a problem is known, factor there might be a need for oil sampling and moisture analysis. 156  It is sometim sometimes es difficult to get the proper moisture moisture content in bushing oil. Compared to a transformer, a bushing has a much higher ratio of paper to oil. This means that regardless of the bushing manufacturing process, there will always be much more moisture in the paper than in the oil. In paper the moisture content is measured in percent, whereas in oil the moisture content is measured in parts per million (ppm). Depending on the temperature of the bushing, the moisture will move from the paper to the oil or from the oil to the paper. Due to this, a bushing will always show much higher moisture content in the oil after a certain time of high temperature operation. To get a proper value, the oil sample should be taken at least 48 hours after the entire bushing has reached room temperature temperature.. The bushing is delivered from ABB with maximum moisture content in the insulating oil of 3 ppm. If considerably higher concentrations are measured, the sealing system is likely damaged on the bushing. If the moisture content is greater than 10 ppm, a tan  measurement of the bushing C1 capacitance should be performed. If the moisture content is greater than 20 ppm, the bushing should be taken out of service. 3.2.11.1 3.2. 11.1.7 .7 Dielectri c Frequency Response Analys is (DF (DFRA) RA) This method which is discussed elsewhere in greater detail in this handbook involves measuring the capacitance and dielectric losses over a frequency spectrum rather than at a fixed frequency. The status of the insulating material can be obtained from analyzing the measured loss and capacitance spectra. This method may in the future become the preferred method and an alternative to DGA for diagnosing bushing problems. The main advantages are that the bushing does not need to be opened and proper analysis can be performed regardless of the temperature of the bushing during the measurement. The shape and frequency shift of the spectra are the main elements used for diagnosis. 3.2.11.1 3.2. 11.1.8 .8 Partial Disch arge measurements Partial discharge measurement is primarily used as routine testing method by the manufacturer. Partial discharge may indicate external corona or internal insulation breakdown. If used for diagnostic on installed transformers it will show the sum of the partial discharges in the bushing and transformer insulation. External discharges in switchyards may be suppressed by use of external connected measuring coils. By use of newly developed acoustic sensors, partial discharges may be located. This method requires skilled personnel, who have knowledge of bushing and transformer design to do the measurement. 3.2.11.1 3.2. 11.1.9 .9 DeDe-pol pol ymerizatio n analysi s De-polymerization analysis is a method of determining ageing of cellulose in OIP bushings. The method requires that the bushing is taken apart and a paper sample is taken from the condenser body. 157  3.2.11.2 DIAGNOSTICS TECHNIQUES TECHNIQUES FOR BUSHINGS COMPLYING WITH THE ANSI/IEEE STANDARDS 3.2.11.2 3.2. 11.2.1 .1 Condenser Bushi ng Power Factor Tests Table 3-35 shows a listing of the possible power factor tests for bushing insulation. The test connections for these tests are shown in Figure 3-39 – Figure 3-40. Table 3-35 3-35:: Power Facto Facto r Tests for Bu shin gs Test Mode Center Conductor Potential/ Power Factor Tap Flange Measured Capacitance Insulation Involved UST GSTg HV Lead Meas. Lead (on guard) Meas. Lead HV Lead Gnd. Lead Gnd. Lead C1 C2 Main core insulation Tap insulation core insulation between tapped layer and bushing ground sleeve, portion of liquid or compound filler, portion of watershed near flange Figur e 3-39: 3-39: Bush ing C1 P Power ower Factor Mea Measur sur ement Setup (US (UST) T) 158  Figure 3-40: Bush ing C2 P Power ower Factor Mea Measu su rement Setup (GST (GST/g) /g) In performing power factor tests on bushings, the following practice is recomm recommended: ended: Short circuit the windings under test  Clean bushings bushings to m minimize inimize the effects ooff surf surface ace leakage leakage currents currents  Ground opposite windings  Remove test tap cover from bushing under test  Perform C1 test in UST mode  If necessary, necessary, perform overall test in GST mode  Perform C2 test in GST/g mode  Replace test cap cover 3.2.11.2 3.2. 11.2.2 .2 Factors Aff ecting C1 and C2 Capacitanc Capacitanc e and Power Factor Mea Measurements surements As mentioned above, the C1 and C2 capacitance of condenser bushings rated 115 kV and above are strictly s trictly controlled by design and are mainly dependent upon the condition of the oil-impregnate oil-impregnatedd paper insulation. The pow power er factor aand nd capac capacitance itance test values values under normal circumstances are not affected much by external factors. However, under conditions of contamination contamination and high humidity, these measurem measurements ents may be significantly affected. In addition, capacitively coupled resistive paths to ground may affect these measurements. These may include supporting structures, wooden crates that are moist/wet, resistance between bushing mounting flange and the transformer tank, stray effect from other objects, and external connections during testing. Although, the IEEE Standard C57.19.01 specifies a limit 0.5 % for C1 power factor for oil impregnated paper insulated bushings, ABB Type O Plus C, AB, and T condenser bushings have C1 power factor values that are well below this limit.  159 Condenser bushings rated 69 kV and below as mentioned earlier, have the main C 1 capacitance, which which is strictly controlled by ddesign. esign. The capacitance aand nd power factor values behave the same behavior and characteristics as those for the 115kV and above bushings. However, these bbushings ushings have aan n inherent C2 capacitance, which is dependentt upon a few outer layers of paper with adhesive, an oil gap between dependen the the flange a nd the layers condenser the can tap t ap insulator. insulator Variations adhesive in outerand paper and core, other and factors rresult esult in. power factorin variations in bushings of the same style number. In addition, the close proximity of the C1 layer with the mounting flange results in greater fringing effect between the two parts. As a result of this, the porcelains, oil, and air surrounding the bushing can affect the C 2 power factor test values. In particular, high current Type T condenser bushings with a short mounting flange and a long internal C1 layer/foil tend to exhibit higher power factors because of greater coupling effect betwee betweenn the C1 layer/foil and the surrounding materials. Depending upon the design, the C2 power factor of these bushing bushingss can range from 0.1 % to 2 %. It is important to note that the IEEE Standard does not specify any limit for C2 power factor. For bushings bushin gs rated 69 kV an andd below, the IEEE Sta Standard ndard only requires stamping of C1 power factor capacitance ce TN on started the nam nameplate. eplate. As frequent requests from customers, custom ers,and ABBcapacitan Inc. Alamo, stamping the aC2result poweroffactor and capacitance test values on bushing nameplates since December of 2002. With this addition, the nameplates of all AB, O Plus C, and T condenser bushings are now stamped with factory test values of C1 and C2 power factor and capacitance. However, because of the reasons mentioned above, users may see a greater variation in C2 power factor and capacitance values in differe different nt bushings of the same design. It is important to compare the initial test values before installation with the nameplate values. To verify nameplate values (especially for Type T bushin bushings), gs), the measurements should be made with the bushing mounted on a metallic test tank/stand with the lower end porcelain immersed in dry good quality oil. There T here should be sufficient clearance (at least 16 - 20 inch) from the bushing lower porcelain/terminal to the grounded tank. For C2 measurement, the center conductor should be guarded and the test tap voltage should not exceeding 1 kV. Once the bushing has been installed in the apparatus, it should be retested to establish a benchmark value. It is important to compare the subsequent field test values with the initial benchmark value after installation. Table 3-36 provides typical and questionable power factor values for bushings from several manufacturers and of various types. 160  Table 3-36: 3-36: T Typic ypic al Bushi ng Power Factors Manufacturer Type Description Typical PF (%) Questionable PF (%) General Electric A Through Porcelain 3 5 General Electric A High Current 1 2 General Electric B Flexible cable, compound-filled 5 12 General Electric D 1.0 2.0 General Electric F 0.7 1.5 General Electric L 1.5 3.0 General Electric LC 0.8 2.0 General Electric OF 0.8 2.0 General Electric S 1.5 6 General Electric U LAPP LAPP Ohio Brass Ohio Brass Ohio Brass Ohio Brass Westinghouse Westinghouse ERC PRC, PRC-A Class LKType A ODOF, Class G, Class L ODOF, Class G, Class L S, OS, FS RJ D Oil-filled upper portion, sealed Oil-filled, sealed Oil-filled upper portion, sealed Oil-filled upper portion Oil-filled expansion chamber Force C & CG, Rigid Core Compound-filled Comment Type S, no form letter (through porcelain) redesigned as Type A Type S Form F, DF & EF were redesigned as Type B, BD, and BE respectively See special instructions for Type U in section that follows. Epoxy Resin Core, plastic or oil-filled Paper Resin Condenser Core 0.8 0.8 1.5 0.4 1.0 1.0-5.0 2.0-4.0 Solid Porcelain Semi Condenser 1.5 0.8 1.0 1.5 Change of 22% from Nameplate value Change of 16% from Nameplate value 2.0 2.0 3.0 Westinghouse 1.5 3.0 Westinghouse 1.0 2.0 0.25-0.5 0.5-1.0 Modern Condenser Bushings 25 Typical C2 power factors for older PRC design range from 4-15% due to injected c ompound during manufacturing process Manufactured prior to 1926 and after 1938 Manufactured between 1926 and 1938 Bushings on OCB and instrument transformers 92 kV to 139 kV (except Type O, O-A1, OC, and O+C) Bushings on power and distribution transformers of all ratings (except Type O, O-A1, OC, and O+C) (e.g. ABB Type A, O+C) 25 Doble Testing Power Apparatus Bushings, 2004 International Conference of Doble Clients 161  3.2.11.2 3.2. 11.2.3 .3 Bush ing Hot Collar Test In cases where a bushing does not have a bushing tap, the C 1 and C2 power factor measurements measurem ents described above cannot be performed. In such cases, a hot collar test is performed. Thisand test oil-filled applies bushings to compound-filled bushings, solid porcelain filled bushings, that are not equipped with taps andbushings, for whichgasthe bushing overall test cannot be performed. The hot collar test is also useful for various other bushing checks:  To check bushing bushing oil level on oil-filled bushings without either either sight glasses oorr liquid level gauges  For bushings with with suspect or defectiv defectivee oil level gauges, to check bushing oil level  As a supplemen supplementt test w when hen overa overallll or ttap ap tests indicate po possible ssible problem problem.. The test is performed by applying single or multiple collars to various sections of the bushing. Figure 3-41 shows the setup for a single-collar test in UST mode. This configuration measures a portion of the insulating watershed, sight glass, core insulation in upper area, and liquid or compound filler in the upper area of the bushing. Figure 3-42 shows a similar setup but in GST mode. In addition to the items measured in the UST mode, this configuration also measures the surface leakage from the collar to the LV lead and from the collar to the bushing flange. Because the test measures smaller sections of material, very small dielectric losses and currents are recorded. Consequently, small changes in either value have tremendous impact on the value of the calculated power factor. It is therefore advisable to use the value of the measured dielectric loss as the determining factor in assessing the results of the hot collar test. The recommended acceptable acceptable limits for hot collar tests are 0.1 W at 10 kV and 0.006 W at 2.5 kV. Also, the dielectric loss for the same section in the same type of bushing should be approximately equal. As a cautionary note, because relatively small currents are being measured in this test, it is important to clean and dry the bushings before performing this test. The following cleaners have been suggested by various utilities: dry TM TM clean cloth, water and soap, Colonite , and Windex with Ammonia. It is never recommended to use evaporative solvents on bushings. 162  Figur e 3-41: 3-41: Hot Collar UST Mode Power Factor Test Figure 3-42: 3-42: Hot Coll ar GST Mode Mode Pow er Factor Test A hot collar test can yield one of three results: watt losses in normal range, increased watt losses, or decreased current. Increased values in watt losses ( 0.1 W) typically indicate contamination contamination in the insulation system. Decreased values in current (compared 163  to similar bushings) may indicate the presence of voids in the insulation or low liquid or compound level in the bushing. 3.2.11.2 3.2. 11.2.4 .4 What to do when Bus hing Power Factor Tests are Doubtful The following steps are helpful in confirming or clarifying bad bushing power factor results: 1. Re-chec Re-checkk all all connections, including ground lead and bushing flange ground 2. Make sure ground connect connection ion is good 3. Check test circu circuitit used for for the measurement measurement 4. Check test set an andd test set leads leads 5. Visually inspect bushing sheds an andd oil 6. Clean and dry all surfaces 7. Compare an andd ana analyze lyze results of similar bu bushings shings 8. Research the histo history ry of the bushing for for flashover or line line surge activity 9. Verify temperature correction factor was used for C1 and overall tests (note that C2 power factors are not temperature corrected) 10. If still uncertain uncertain,, contact the manufactur manufacturer er 3.2.11.2 3.2. 11.2.5 .5 3.2.11.2.5.1 Special Case – Type “ U” Bus hings [83] History General Electric, a major player in the electrical world since the early 1900s, was engaged in the development and manufacture of apparatus bushings since as early as 1920. In the quest to develop the best bushing in the world, GE created many different types and styles of bushings such as Types A, F, L, LC, OF, T, and U for both transformer transform er and circuit breaker applications. Let’s concentrate on the Type U bushing history and technology first. Type U bushings were manufactured with voltage ratings from 15 kV through 800 kV. A Type U bushing is a condenser withporcelain oil-impregnated an mounting oil-filled shell. The shell consists of a cap,design an upper weatherpaper casing,inside a metal flange, a lower porcelain, and a lower porcelain support. For sealing purposes, all parts are held together under a centrally clamped spring tension method. The principle behind a condenser bushing is to incorporate equal capacitance layers to provide equal voltage steps, resulting in a uniform voltage grad gradient ient throughout the bushing body and over the bushing surface. The type of design and the materials within a condenser core may differ between manufacturers, but the design intention is the same. The type of construction used in some Type U designs was a herringbone pattern, surface-printed ink that formed the capacitive layers. A plain Kraft paper was wound into the condenser between between the active ink-lined paper layers. For most of the production, both the lined paper and the plain paper were .008 inches in thickness (see Figure 3-43). 164  Figure 3-43: 3-43: Surface-Printed Ink Cond enser In 1979, American Electric Power Service Corporation reported increasing power factors in Type U bushings at the Doble Client Conference. Since 1979, the concern for the Type U bushing rising power factor has increased dramatically due to documented accounts of bushing failures. Do you have Type Type U bushi ngs on yo ur system? Most likely you do. From 1954 to 1986, the time period that GE was manufa manufacturing cturing Type U bushings, GE was the leader with 65 to 70 percent of the US market. They were supplying bushings to their own transformer manufacturing facilities and to other transformer manufacturers, as well as supplying replacement bushings directly to end users. In this timeframe, the Type U bushing was known as the best product on the market, utilizing standardization standardization of parts with a proven field record. So, what is the cause(s) related to the increase in power factor in Type U bushings? Through Doble Client Conferences, utility feedback, insurance company reports, General Electric documents, and our own investigations, ABB has accumulated data and has the followin followingg concern for Type U bushings. The condenser design with ink-lined paper with plain Kraft paper allowed a gap at the ends of the active layers in the condenser core. A heavily loaded transformer will generate heat internal to the bushing, subject the bushing to a higher immersion oil temperature, and consequently increase internal temperature in the bushing. The heated bushing oil expands and intensifies the pressure in the confined gas space, which causes an increased quantity of gas to become dissolved in the oil. Cyclic reduction in transformer load and/or reduction of ambient temperature allow cooling of the As the oiloccurs cools, rapidly it contracts, reducing the pressure ofoilits will gas develop blanket. Ifa the bushing pressureoil.reduction enough, the gas-saturated tendency to evolve bubbles of gas. This evolution will first occur in the highest  165 electrically stress regions of the bushings, normally between the lined paper and the plain paper layers of the bushing core. A critical combination of gas bubbles and dielectric stress causes partial discharges to occur within the insulation system. The long-term effect of the discharges is an increase in the dielectric losses in the insulation system, resulting in an increased power factor. Have Ha ve you heard heard of mi grating ink ? This is a process that could also be a contributing factor to Type U bushing rising power factors. Although GE designed and specified the herringbone ink process, they did not manufacture the paper, nor did they apply the Rescon conductive ink. The paper/ink process was completed by outside contractors. Reports as early as 1979 show that portions of the Rescon ink “herringbone pattern” had transferred from the printed paper layers to the plain Kraft paper layers. Investigations have revealed where Rescon printed paper made contact with the overlapping plain paper, evidence of corona action or evidence of slight burning was found. (See Figure 3-44) Ink/particulates aggravated GE’s manufacturing system. During the cutting of hued and plain Kraft paper while winding the condensers, ink/paper particulates were generated, further complicating complicating the rising power factor phenomenon. By 1985, GE had made many internal quality improvements to the design and processing of bushings. GE implemented an oil flushing procedure for all bushings in order to reduce the particles that may have originated with the bushing core insulation. Also, GE commissioned a new closed-loop continuous filtration oil system intended to improve bushing oil quality. Figur e 3-44 3-44:: Rescon Condu ctiv e Ink Ink Transfers f rom th e Prin Prin ted Pa Paper per Layers (left) to the Plain Kraft Paper Paper Layers or Conduct or (right), Resulting Resulting in Corona Action and Slight Bu rning (circled) 166  What kV ratings of Type U bushi ngs us ed herring herring bone ink proc essing? The herringbone ink process was used in Type Ty pe U bushings in the voltage range 15-345 kV. However, some Type U bushings in this voltage range have metal foil designed condensers. Most bushings 345 kV and above have foil designed condensers, but many have herringbone lined paper. Should y ou be conc erned erned onl y wit h Type U condenser bus hings rated rated 15-34 15-345 5 kV? Type U bushings were manufactured using a flex seal design. The flex seal is a copper diaphragm located in the top cap of bushings 161 kV and above. The flex seal (see Figure 3-45) was designed to allow for the expansion/contraction or movement of parts during thermal cycling of the bushing. Figure 3-45: Flex Seal Seal Design The flex seal diaphragm in many cases, depending on catalog number and application, carries the current from the main conductor to the cap cover to the upper terminal connection. As the diaphragm experienced movement, acting as an accordion, the diaphragm could experience mechanical stresses, which would crack and result in a leak. Since the diaphragm is internal to the bushing, and is placed above normal oil level, where could the bushing leak? During processing of the oil in the transformer, the oil could be evacuated from the bushing by vacuum if the bushing was inclined, or the bushing could become filled with oil during the transformer vacuum/fill process. If the bushing is full of oil (with no expansion space) and if the bushing is applied at higher temperatures, the oil will expand and compromise the gasketing system. The flex seal system is connected to the main conductor with a sswell well seal gasket and a seal nut. This connection is also under oil and under spring tension of the bushing. The 167  upper connection at the cover relies totally on the cover bolt tightness to adequately carry the current from the flex seal through the cover to the customer terminal connection. If the cover bolts have become loose over time, hotspots will develop, which will compromise the cover gaskets. This situation is best revealed in the field by utilizing thermal scans with infrared apparatus. Hotspots such as this can lead to catastrophic failure if not resolved immediately. GE recognized that the flex seal s eal design could be improved upon, so they introduced the slip seal design in 1976 (see Figure 3-46). The slip seal design totally eliminates the flex seal but still s till allows the bushing to expand and contract during therm thermal al cy cycling. cling. Figure 3-46: Slip Seal Seal Design What about about t op termin al overheating overheating i ssues? Many Type U bushings were designed and manufactured to have the ability to change top terminals in the field. For instance, if a customer damaged the external threading of a top terminal, they could replace the top terminal without removing the bushing from the transformer. Also, draw lead bushings have a removable top terminal to allow disconnection from the transformer winding lead without requiring entry to or removal of oil from the transforme transformer. r. Type U bushings, if designed to have removable top terminals, require routine maintenance to ensure top terminal tightness. If the top terminal becomes loose, a hotspot may occur. Overheating of the top terminal may deteriorate the bushing’s gasketing system, which could compromise the integrity of the insulating system and possibly result in failure. Slip seal bushings, 161 kV and above, rated 1,600 amperes and are perfect candidates for top terminal overheating if adequate maintenance is notabove, performed. 168  How do you know if your Type U bushings have herringbone ink condensers or foil condensers, flex seal seal syst ems, slip s eal eal designs, or removable top terminals? Contact ABB! ABB Alamo has the documentation for all GE bushings. We have all of the original design, test, and manufacturing data for Type U bushings. If you have the catalog number group number from the nameplate of your bushings, can help identify the and type the of bushing design to ev aluate evaluate your critical needs, such asABB bushing maintenance, repair, refurbishment, or replacement. Can Ca n a Type U bushin g be refurbi shed? Depending on the age, voltage class, current rating, design, and the condition of the existing bushing, Type U bushings may be refurbished. Certain Type U bushings are excellent candidates for refurbishment. If the bushing external parts are in good condition and the concern centers on the herringbone ink condenser or flex seal system, it is very economical to refurbish Type U bushings rated 115 kV and above or bushings below 69 kV that have a high current rating (such as 4,000 am amps ps and above). The key to refurbishin refurbishingg Type U bushings is access to the original design documents and having trained, experienced people. All bushings refurbished by ABB will be updated with the latest ABB design enhancem enhancements ents and will carry a new nameplate and warranty. Were Type U bushings manufactured and supplied to the field with oil con taminated taminated with PCB? PCB? Yes! We cannot determine the content of PCB in a bushing by the serial number, catalog number or the group number off of the nameplate. The only way to determine the PCB level is to have the oil tested. We can give some guidelines. Bushings manufactured by GE Pittsfield from 1954 to 1973 can have PCB levels that range from 50 to 500 ppm. From 1973 to 1980 we have test reports reporting levels from 2 to 50 ppm PCB. From 1981 to 1986 the levels are normally non-detectable non-detectable or less than 1 ppm PCB. What criteria should be used to evaluate evaluate bushings on your s ystem? If you have bushings with herringbone-lined ink paper condensers, GE’s recommendations, recomme ndations, “Criteria for Concern,” for Type U bushings in 1979 were:  If the capacitance capacitance has increase increasedd by 10 % or more from nnameplate, ameplate, rem remove ove the bushing from service.  If the P.F. is below 1.5 %, there is no cause for con concern. cern.  If the P.F. exceeds 1.5 %, but is less tha thann 3 %, the bushing is in the reg region ion for concern.  If the capacitance capacitance cha change nge is below 5 % of nam nameplate eplate value, there is little risk of failure.  If the P.F. eexceeds xceeds 3 %, re remove move the bu bushing shing from service.  169 In 1985, Doble Company published recommended limits for Type U bushings.  A power power factor of 1.0 1.0 % is que questionab stionable, le, rath rather er than than 1.5 1.5 %. Today, ABB has approximately a 65 % market share of new bushings sold into the US and is the leading supplier replacement for Type U bushings to the Utility and Industrials in the Unitedof States. ABB hasbushings the following recommendations:  If the bushing power factor factor doubles original nameplate value, the bushing is questionable and should be replaced or refurbished.  If the capacitance increases to 110 % of the origin original al installation vvalue, alue, the bushing is questionable and should be replaced or refurbished. How can ABB make these recommendations, and on what basis can these statements stateme nts be made? Being the sounding board for 170 major utilities and many industrials across the US, we have seen the electrical industry increase awareness of Type U bushings due to high power factors and failures of Type U bushings. At the same time, we have noticed maintenance periods have been extended beyond recommended recomme nded levels. In today’s compe competitive titive marketplace, companies have downsized maintenance programs and extended periodic maintenance from 1 year intervals up to 3 years and as high as 5 years or more. Through field surveys and field experience, we have noted that if a Type U bushing is exhibiting a rise in power factor, the rise accelerates very quickly once the action has started. Therefore, many utilities know that if they are on a 3- or 4-year maintenance interval and a bushing exhibits a rising power factor, the bushing will not perform for the next 3- or 4-year period without failure. The normal practice is to remove the bushings from the transformer immediately. Once the corona (partial discharge) activity has started, the remaining service life of the bushing can be very short, and it could c ould fail catastrophical catastrophically. ly. 3.2.11.2.5.2 Recommendation  If possible, measure power factor and capacitance on a yearly basis.  If power factor factor is on the rrise, ise, replace or refu refurbish rbish bush bushings. ings. If yo youu have fflex lex seal design bushings, thermal scan the units for hotspots, check for low or high oil levels, and complete power factor and capacitance testing on a yearly basis. If bushings exhibit any of the above-mentioned scenarios, the bushing should be replaced or refurbished. 170   If you have bushings with removable top terminals, proper maintenance m must ust be applied on a yearly basis either by thermal scan or manual inspection methods. For manual inspection of top terminals, check to see if the terminal can be loosened first. If the terminal cannot he removed, the terminal may have seen overheating and/or corrosion build-up and should be removed from service. If the are terminal termsigns inal can removed, inspect the gasket top term terminal inal gasket and d lookortohave see aif  there of corrosion. cbe orrosion. If the terminal appears to bean brittle permanent set, replace the gasket. When replacing the gasket, be sure to lubricate the gasket with petroleum jelly to prevent twisting of the gasket as the terminal is tightened. Tighten the top terminal to the correct torque values with the proper tools or fixtures. Top Terminal Size Inch – Threads Torque ft lbs (Nm) 1.125-12 1.500-12 35 (48) 100 (136)  If bushing top term terminals inals show signs of cor corrosion rosion oorr the top terminal cannot bbee removed, we recommend replacement or refurbishment of the bushing. Top terminal overheating can compromise the bushing gasketing system or create loss of life of the bushing insulating system. This could result in a catastrophic failure if the proper action is not taken. Bottom connected bushings 161 kV and above rated 1,600 amp and above can be refurbished to the new ABB Unified top terminal design per Figure 3-47. The ABB Unified top terminal design eliminates top terminal maintenance and overheating, corrosion, or deteriora deteriorating ting gasketing systems. Figur e 3-47: 3-47: Unifi Unifi ed Top Terminal 171  Who can rebuild or refurbi sh Type U bushin gs to be li ke new? new? Some major utilities have tried to rebuild their own bushings, a few small business service shops have tried, and other bushing manufacturers have also tried to rebuild Type U bushings. Most rebuilds by people other than ABB rely on guesswork or reverse engineering to determine the makeup and design of the original bushing. GE went through many design changes through the years. GE designed and manufactured manufactu red over 5,000 different catalog or styles of bushings, and within each catalog or style there are an average of 7 design and manufacturing changes. That means there are over 35,000 different Type U bushing designs in the field today. The key to rebuilding Type U bushings is to have all the documentation, such as the drawings, design changes, manufacturing processes, and test data. ABB has this design and original manufacturing information as well as design engineers and technicians experienced with GE technology. Table 3-37 shows typical design information for Type U bushings. ABB will not rebuild bushings without the original design information. If applicable or economical for the customer, ABB rebuilds Type U bushings to the latest technology. Table 3-37 3-37:: Typic al Type U Bushin g Design Info rmation Bushing kV 15-69 115-138 161-230 Current Rating Herringbone Ink Condenser Foil Condenser Design 400 400/1,200 2,0003500 4,000 800 800/1,200 1,800 800 yes yes yes yes yes yes yes yes 550 800 Flex Seal Design Slip Seal Design Economical to Refurbish yes yes yes yes yes 800/1,200 345 Removable Top Terminal yes 1,600 yes yes 800 See Note1 See Note 1 yes 800/1,200 See Note 1 See Note 1 yes 1,600 See Note 1 See Note 1 yes 800 yes yes 800/1,200 yes yes 1,600 yes yes 800 yes yes 800/1,200 yes yes 1,600 yes yes See Note 2 See Note 2 See Note 2 See Note 2 See Note 2 See Note 2 See Note 2 See Note 2 See Note 2 See Note 2 See Note 2 See See Note 3 See Note 3 See Note 3 See Note 3 See Note 3 See Note 3 See Note 3 See Note 3 See Note 3 See Note 3 See Note 3 See yes yes yes yes yes yes yes yes yes yes Note 2 Note 3 Note 1: To verify herringbone ink or foil design condensers, the bushing catalog # and group # from the nameplate must be supplied. Note 2: To verify if bushing utilizes flex seal design, the bushing catalog # arid group # from the bushing nameplate must be supplied. Note 3: To verify If bushing utilizes slip seal design, the bushing catalog # and group # from the bushing nameplate must be supplied. 172  Are Ar e th ere oth o ther er reaso r easons ns why wh y a cus c usto to mer shou sh ou ld refur ref ur bish bi sh bush bu sh ings in gs? ? Depending on state and government regulations, the economical benefit in refurbishment If a customer buys new product, what happens to the old product? Most can likely,vary. the customer must scrap or dispose of porcelain materials, metals materials, and bushing oil on top of dealing with the PCB issues. Sometimes the disposal fees are very expensive. Do you know the regulations and laws of disposal in your state? They are changing daily. Be careful. There are organizations that provide services to decontaminate PCB laden bushings. The decontaminated parts can be used to rebuild a bushing that carries the full warranties of a new bushing. Refurbishing bushings could be an economic and viable solution to your problems. 3.2.11.2 3.2. 11.2.6 .6 Type “ T” Bush ing s Is the Type “ T” bushing a predecessor predecessor to the Type “ U” bushing manufactured manufactured by General Electric? Type “T” bushings were designed and manufactured by General Electric for low-voltage, high-current, low-corona, transformer applications. GE supplied low-voltage, highcurrent, stud type or bulk type bushings (Type “A” bushings) for many years, and then the market demanded a bushing with low corona values. GE’s answer to the market demand was the ultimate low-corona condenser bushing technology, the Type “T.” GE manufactured Type “T” bushings from 1971 to 1985. Type “T” bushings range from 25 kV to 34.5 kV and current ratings 600 ampere draw lead to 18,000 ampere bottom connected. These bushings were designed for low-voltage applications; therefore, GE designed bushings for horizontal and vertical applications. To achieve maximum low corona values, not obtainable by bulk type bushings, GE incorporated a condenser into the design. Why is there a concern concern with Type “T” bushings? Type “T” bushings are basically designed and manufactured in the same manner as Type “U” bushings. Outside shell and mechanical parts are very similar. What about the condenser core process? The condenser design and process is the same as the Type “U” using herringbo herringbone ne ink lined printed paper. Should you be concerned concerned about all Ty Type pe “ T” bushings? No. Some Type “T” bushings are designed for high-temperature (125 °C) applications. Units designed for high-temperature applications used Nomex winding paper with foil inserts for gradients. The ink process could not be applied to the Nomex winding paper. 173  Is the concern for Type “ T” bushings as valid as as the concern for Type Type “ U” bushi ngs even though they are a low-voltage bushing? Yes! Even more so. The normal application of these bushings is on the low-voltage side of transformer with higher current ratings, higher sometimes area applied in bus ducts. When these bushings aretemperatures, subjected to and thermal cycling,they gas bubbles trapped in high-stress areas of the lined ink printed paper condenser can create partial discharge leading to a high power factor or failure of the bushing. How do you know if you have herringbone ink lined pape paperr or foil gradients gradients in your Type Typ e “ T” bushings? bushings? Contact ABB. If you know the General Electric catalog number and the group number from the nameplate of the bushing, ABB can research the General Electric drawings in our archives and verify the type of design. If you wish to discuss applications, such as high temperature, ABB can also verify if the units are suitable for 105 °C or 125 °C applications. Many transformer manufacturers, utilities, and contractors tend to misapply bushings in high-temperature applications assuming that higher current rated bushings can be applied at higher temperature ratings. Overload conditions described in IEEE Standard C57.19.100 section 4 are normally abused more with Type “T” and bulk-type bushings than other types of bushings. The updated ABB “ Criteria for Concern” Concern” (power factor and capacitance values) and recommend recommended ed maintenance applies to Type “T” bushings as well as Type “U” bushings. Can you buy new bushings to replace Type “ T” bushings or can Type “ T” Can bushings be refurbished? refurbished? Yes & yes! ABB offers direct replacement bushings for Type “T” bushings. ABB manufactures Type “T” bushings today with the same dimensional and electrical characteristics as the General Electric bushings for ease of installation, proper fit, and application, but ABB has incorporated into today’s Type “T” the advanced technology and superior condenser condenser design of the ABB Type T ype O Plus C bushing. Although Type “T” bushings are low voltage, they are typically high current, and the economics of refurbishment is well worth the effort. Normally, a refurbished bushing is approximately 65 % of the cost of a new bushing. Please be aware that GE went through many gasketing system design changes in the early stages of the Type “T” design. ABB utilizes the original GE design data and drawings to update bushings bushings to the best design and latest technology when refurbishing bushings to “as new” condition. 3.2.11.3 DIAGNOSTICS AND CONDITIONING ON ABB B USHINGS COMPLYING WITH THE IEC STANDARD In general, bushings delivered from ABB shall be considered maintenance free. However, inspection and field service experience will in some cases lead to the need for diagnostics on bushings. In the following section, a review of different methods and interpretations interpretat ions iiss given. 174  WARNING Make sure that the transformer is de-energized and out of service before any work i s performed performed on the bushing. 3.2.11.3.1 3.2.11.3 .1 Capacit ance and tan measurement Prior to taking a condenser bushing into service, and on suspected faults, the capacitance and dissipation factor should be measured and compared with the values given on the rating plate or in the routine test report. In connection with these tests, the electrical connection between transformer tank and bushing flange shall also be checked, for instance with a buzzer. 3.2.11.3 3.2. 11.3.2 .2 Temperatur Temperatur e cor recti on The measured dissipation factor value shall be temperature corrected according to the correction factors given in Table 3-38. GOx stands for all oil-impregnated paper condenser bushings (OIP) and GSx stands for resin-impregnated paper condenser bushings (RIP). For all bushings it shall be assumed that the bushing has the same temperature as the top oil of the transformer. The test should be performed at a temperature as high as possible. Correction shall be made to 20°C. The corrected dissipation factor (tan ) shall be compared with the value on the rating plate or in the test report. Table 3-38 3-38 : Correctio n factor s for tan Range (°C) Correctio n to 20° 20°C C OIP Correctio n to 20 °C RIP 0-2 3-7 8-12 13-17 18-22 23-27 28-32 33-37 38-42 43-47 48-52 53-57 58-62 63-67 68-72 73-77 78-82 83-87 0.80 0.85 0.90 0.95 1.00 1.05 1.10 1.15 1.20 1.25 1.30 1.34 1.35 1.35 1.30 1.25 1.20 1.10 0.76 0.81 0.87 0.93 1.00 1.07 1.14 1.21 1.27 1.33 1.37 1.41 1.43 1.43 1.42 1.39 1.35 1.29 Interpretation of the measurement, OIP and RIP bushings 0-25% 0-2 5% inc rease: The value is recorded and no further measures are taken. 25-40% increase: The measuring circuit is checked regarding leakage and external interferences. External interference can come from nearby current carrying equipment and bus bars. If the difference remains, the problem may be due to moisture. The 175  gaskets of the oil level plugs need to be replaced according to the product information for the bushing. The measured value is recorded, and the bushing can be put back into service. 40-75% 40inc rease:within Perform the measures discussed for 25-40% increase and repeat the 75% measurement one month. More than 75% increase: The bushing shall be taken out of service. However, if the dissipation factor is less than 0.4%, the bushing may be restored to service even if the increase in percentage from the initial value is greater than 75%. Capacitance: The measured capacitance, C1 shall be compared with the value given on the rating plate of the bushing or with the 10 kV routine test report. If the measurement is more than 3% from the nameplate value, there could be a partial puncture of the insulation. An extremely low value C 1 value (disruption) may be due to transport damage and the bushing must not be returned to service. In either case, please contact ABB. The C2 capacitance is influenced by the way the bushing is mounted onto the transformer and should not be used for diagnostics. Comments on dissipation factor of OIP bushings: The dissipation factor is a critical property in oil filled condenser bushings and is mainly determined by the moisture level in the paper and the amount of contamination in the insulation system. The power factor is also very much dependent on the temperature; the principal behavior is shown in Figure 3-48 for different different temperatures and moisture levels. Figure 3-48 3-48:: Tan as a fun ction of temperature and and mois tur e level in OIP OIP bu shin gs. It is clearly visible that the measurements at elevated temperature are more sensitive. At 20 °C, moisture levels between 0.1% and 1% show approximately the same 176  dissipation factor. At elevated temperature (90°C) they differ by a factor of 5 or more. For proper diagnostics, the important property is the dissipation factor at elevated temperature and not the dissipation factor at 20 °C. Comments on dissipation factor RIP bushings: Before a RIP bushing is put in service on a transformer, it is possible for its tan  value to deviate from the nameplate value. This deviation is most probably due to moisture penetration into the surface layer of the RIP. For example, this can happen if the bushing is stored without its protective sealed bag. This allows air with high humidity to penetrate the outer surface layer of the bushing. Normally, the tan  value will decrease to its initial nameplate value if the bushing is stored indoors, in a controlled humidity environment for a week. If the transformer transform er is energized with the bushing in service, the tan  value value will decrease to its nameplate value within a couple of hours. Comments on po wer factor measurements measurements b etween etween the test tap and and th e mounting flange on OI OIP P or RIP RIP bushi ngs: There are several reasons to not use this value as a diagnostic tool.  Primarily this this dissipation fa factor ctor is spe specified cified to be less than 5% accord according ing to IEC 60137. This means that unless specified, no attention is paid to decreasing this dissipation factor value in the same manner as for the dissipation factor over the main insulation.  The test tap is connected to the ooutermost utermost earthed layer on the condenser condenser body. The solid layer outside the earthed layer contains an adhesive together with cellulose to make the condenser body more stable. The dissipation factor of the combination of cellulose and adhesive is much harder to control than that of only cellulose insulation. It is for this reason that the dissipation factor of this insulation section is not used for diagnostic purposes. Moreover, the adhesive material affects the dissipation factor differently for different bushings.  It should be pointed out that under operational conditions, the outer layer of the bushing insulation is earthed. Consequently, the insulation between the outer layer and the mounting flange is not subjected to an electrical stress and therefore do not cause any dielectric heat losses.  It is likely that if the bush bushing ing is pla placed ced in conta contaminated minated are areas, as, contaminants contaminants on the outside of the test tap affect the results. Moisture around the test tap also affects the measurement.  It should be pointed pointed out that if the test voltage (500 (500V V if the testtest-tap tap insulatio insulation n is delivery tested with 2kV and 2.5 to 5 kV if the test tap is delivery tested with 20kV) is exceeded, partial discharges may occur in the region of the test tap. This will affect the measurement. Taking all the variations men mentioned tioned above into account, the dissipation factor of the test tap insulation can vary between 0.4-3.0 %. 177  3.2.12 3.2.12.1 MEASUREMENTS FOR ASSESSING THE CONDITION OF OLTCS/LTCS26 NUMBER OF OPERATIONS It is common to measure the number of operations of the LTC. From the number of operations, it is possible to estimate the level of deterioration of the device based on experience. This measure is typically a function of the LTC manufacturer and type. 3.2.12.2 RESISTANCE OF THE ELECTRICAL CONNECTIONS It is known that the initial contact resistance has a very strong influence on the estimated useful life of the contact. If the connection resistance of the contacts is known, it is possible to calculate an estimate of the remaining life of the contacts. This is done with help of a mathematical ageing model that depends on such quantities as the current load, the connection design, ambient temperature, and others. The contact resistance can be measured with a micro-ohmmeter and the transformer in a deenergized state. 3.2.12.3 T EMPERATURE This measurement is based on the fact that under normal operating conditions, the main tank of a transformer, because of the I 2R and eddy current heating, will have a higher temperature than the LTCcompartment where there is essentially no heat generation under non-switching conditions. Under steady state conditions, the temperature difference between the two tanks will follow a known pattern. As the LTC switch contacts age and wear, their resistance increases and hotspots develop under normal loading conditions. The hotspots will increase the overall temperature of the LTC tank, and the difference between it and the main tank temperature will begin to deviate from the known pattern. The onset of severe contact wear can therefore be estimated by using the temperature difference between the main tank and the LTC. Most of the systems available on the market use magnetic clamp temperature sensors and computer software to measure and track the temperature difference. 3.2.12.4 MOTOR CURRENT Under normal operating conditions, the motor that drives the LTC gears and switching contacts have a distinctive signature. Any significant deviations from this signature may signal problems (gear or contact wear, binding, etc.) in the LTC mechanism. For LTCs in which the switching mechanism is controlled by a spring, deviations of the motor current from the normal signature can be used to diagnose looseness in the tensioning of the spring. 3.2.12.5 ACOUSTIC SIGNAL During the switching of the LTC, an acoustic signal is generated [84]. This signal can be measured using a piezoelectric sensor. If there is a change in the gears or the switching contacts, the acoustic signature will be different from the normal case. To perform this diagnosis, the measured acoustic signals are compared with a certain

ABB -Service Handbook for Transformers

Related documents

Products

Support

ABB -Service Handbook for Transformers

Related documents

Add this document to collection(s)

Add this document to saved

Suggest us how to improve StudyLib