Transformer Service Handbook - Version Int - V4 0 - Rev 3 PDF [PDF]

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Service Handbook for Transformers

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITY 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.

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ACKNOWLEDGEMENTS 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 Handbook for Transformers. Leif Carlzon, Group Vice President and Product Group Manager for Transformer Service, Asim Fazlagic, Vice President for Transformer Service North America, Dr. George Frimpong, Transformer Service expert in USA, Pierre Boss, Senior Transformer 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 handbook. 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 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

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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, Westinghouse, 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 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 on 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, how to interpret the results of these measurements. There are three ABB publications that provide theoretical coverage and discussions on transformers, short 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 is important for making informed decisions about any maintenance, repair or replacement activities. Therefore we address the topic of risk assessment/management of transformers. We present ABB’s methodology of risk assessment as applied to populations of transformers with the view of identifying the few that need the attention of asset managers. This provides them the ability to focus 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

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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 Kingdom Liam Warren In United States of America 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.

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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

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CONTENTS DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITY ........................................................ I ACKNOWLEDGEMENTS .......................................................................................................................II FOREWORD..........................................................................................................................................III AUTHORS ..............................................................................................................................................V 1

TRANSFORMER DESIGN CONSIDERATIONS ........................................................................... 17 1.1 CONFIGURATION ..................................................................................................................... 17 1.2 MECHANICAL CONSIDERATION .................................................................................................. 17 1.3 THERMAL CONSIDERATIONS ..................................................................................................... 18 1.4 DIELECTRIC CONSIDERATIONS.................................................................................................. 19 1.5 CONSTRUCTION TYPES ............................................................................................................ 19 1.5.1 Shell Form........................................................................................................................ 19 1.5.1.1 1.5.1.2 1.5.1.3 1.5.1.4

1.5.2

Design Features ................................................................................................................... 19 Mechanical Strength ............................................................................................................. 20 Thermal Capability ................................................................................................................ 22 Dielectric Characteristics........................................................................................................ 24

Core Form ........................................................................................................................ 26

1.5.2.1 1.5.2.2 1.5.2.3 1.5.2.4

Design Features ................................................................................................................... 26 Mechanical Strength ............................................................................................................. 27 Thermal Capability ................................................................................................................ 29 Dielectric Characteristics......................................................................................................... 30

1.6 BUSHINGS ............................................................................................................................. 32 1.6.1 Design and Construction of Capacitances in Condenser Bushings Complying with the IEEE Standards .................................................................................................. 32 1.6.2 Bushings Voltage Tap....................................................................................................... 36 1.6.3 Connections ..................................................................................................................... 38 1.6.3.1 1.6.3.2 1.6.3.3

Internal Electrical Connections ................................................................................................... 38 Draw Lead Connected Bushings................................................................................................ 38 Bottom Connected Bushings ..................................................................................................... 38

1.6.4 Liquid Level Indication ...................................................................................................... 38 1.6.5 Painting ............................................................................................................................ 39 1.7 ON-LOAD TAP CHANGERS ....................................................................................................... 40 1.7.1 Introductions..................................................................................................................... 40 1.7.2 North-American Practices ................................................................................................ 41 1.7.2.1 General Description of LTCs ................................................................................................. 41 1.7.2.2 Reactance Type LTCs........................................................................................................... 41 1.7.2.3 Arcing Control Methods......................................................................................................... 42 1.7.2.3.1 Arcing Tap Switch ............................................................................................................ 42 1.7.2.3.2 Arcing Switch and Tap Selector ........................................................................................ 42 1.7.2.3.3 Drive Mechanism for Reactance Type LTCs...................................................................... 43 1.7.2.4 Vacuum Interrupter Type LTCs.............................................................................................. 43 1.7.2.5 Resistance Type LTCs .......................................................................................................... 44 1.7.2.6 Drive Mechanisms for Resistance Type LTCs ........................................................................ 45 1.7.2.7 Failure Mechanisms for LTCs................................................................................................ 45 1.7.2.7.1 Electrical Connections ...................................................................................................... 45 1.7.2.7.2 Insulation System ............................................................................................................. 46 1.7.2.7.3 Control System................................................................................................................. 47 1.7.2.7.4 Mechanism ...................................................................................................................... 47

1.7.3

European Practices .......................................................................................................... 47

1.7.3.1 1.7.3.2 1.7.3.3

Resistance Type OLTCs ....................................................................................................... 47 Diverter Switch OLTC ........................................................................................................... 48 Selector Switch OLTC........................................................................................................... 49

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1.7.3.4 Tie-In Resistors..................................................................................................................... 51 1.7.3.5 Failure Mechanisms for OLTCs ............................................................................................. 52 1.7.3.5.1 Electrical Connections ...................................................................................................... 52 1.7.3.5.2 Insulation System ............................................................................................................. 53 1.7.3.5.3 Motor Drive Mechanism.................................................................................................... 53 1.7.3.5.4 Mechanism ...................................................................................................................... 53

1.8 STREAMING ELECTRIFICATION .................................................................................................. 54 1.8.1 Charging Tendency and its Effect of Streaming Electrification ........................................... 55 1.8.2 Mitigation Strategies for Streaming Electrification............................................................. 56 2 A PRACTICAL APPROACH TO ASSESSING THE RISK OF FAILURE OF POWER TRANSFORMERS ................................................................................................................................ 59 2.1 BACKGROUND......................................................................................................................... 59 2.2 LIFE MANAGEMENT PROCESS ................................................................................................... 59 2.2.1 Risk Assessment .............................................................................................................. 60 2.2.2 Layout of the Evaluation Procedure .................................................................................. 63 2.2.3 Evaluation Procedure........................................................................................................ 64 2.2.4 Probability of Failure – Individual Failure Rate................................................................... 66 2.3 ASSESSMENT OF THE TECHNICAL RISK OF FAILURE BY CATEGORY (MTMPTM PROGRAM) ............... 67 2.3.1 Mechanical Aspects.......................................................................................................... 67 2.3.2 Thermal Aspects............................................................................................................... 67 2.3.3 Electric Aspects - Risk of Dielectric Failure........................................................................ 67 2.3.4 Aspects Related to Accessory Failure ............................................................................... 67 2.3.5 Total Technical Risk of Failure .......................................................................................... 68 2.4 RISK MITIGATION .................................................................................................................... 70 2.5 SUMMARY .............................................................................................................................. 70 3

DIAGNOSIS OF TRANSFORMERS.............................................................................................. 71 3.1 DIAGNOSTICS METHODS FOR POWER TRANSFORMERS AND ACCESSORIES .................................. 71 3.1.1 Diagnostic Methods for Power Transformers..................................................................... 71 3.1.1.1 3.1.1.2 3.1.1.3

3.1.2

Diagnostic Methods for Bushings ...................................................................................... 74

3.1.2.1 3.1.2.2 3.1.2.3

3.1.3

Stresses Acting on Power Transformers ................................................................................ 72 Deterioration Factors and Failure Mechanisms....................................................................... 73 Diagnostic Methods............................................................................................................... 73 Stresses Acting on Bushings ................................................................................................. 75 Deterioration Factors and Failure Mechanisms....................................................................... 75 Diagnostic Methods............................................................................................................... 76

Diagnostic Methods for Surge Arresters............................................................................ 76

3.1.3.1 3.1.3.2 3.1.3.3

Stresses Acting on Surge Arresters ....................................................................................... 77 Deterioration Factors and Failure Mechanisms....................................................................... 77 Diagnostic Methods............................................................................................................... 78

3.2 GENERAL DIAGNOSIS TOOLS ..................................................................................................... 79 3.2.1 Oil Quality Assessment..................................................................................................... 79 3.2.1.1 Factors Affecting the Health and Life of Power Transformers ................................................. 79 3.2.1.2 Methods for Assessing the Quality of Transformer Oils........................................................... 80 3.2.1.2.1 Dielectric Breakdown Strength (BDV)................................................................................ 80 3.2.1.2.2 Interfacial Tension (IFT).................................................................................................... 80 3.2.1.2.3 Acid Neutralization Number .............................................................................................. 81 3.2.1.2.4 Power Factor.................................................................................................................... 82 3.2.1.2.5 Test for Oxygen Inhibitor................................................................................................... 82 3.2.1.2.6 Furan Analysis ................................................................................................................. 82 3.2.1.2.7 PCB Content .................................................................................................................... 83 3.2.1.2.8 Corrosive Sulphur............................................................................................................. 83 3.2.1.3 Moisture in Transformer Insulation Systems .......................................................................... 83 3.2.1.3.1 Transformer Oil ................................................................................................................ 84 3.2.1.3.2 Relative Humidity ............................................................................................................. 84 3.2.1.3.3 Paper (Cellulose).............................................................................................................. 85 3.2.1.3.4 Where Does the Water Come From .................................................................................. 86 3.2.1.3.5 Moisture Equilibrium between Oil and Paper in Transformers............................................. 86

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3.2.1.3.6 Cautions in Estimation of Moisture Using Moisture Equilibrium Curves ............................... 88 3.2.1.4 Limits for Measurement Oil Quality Parameters ..................................................................... 89 3.2.1.5 Moisture and Bubble Evolution in Transformers ..................................................................... 92

3.2.2

Dissolved Gas in Oil Analysis (DGA) ................................................................................ 96

3.2.2.1 Introduction........................................................................................................................... 96 3.2.2.2 Procedure............................................................................................................................. 97 3.2.2.3 Sampling .............................................................................................................................. 97 3.2.2.4 Extraction ............................................................................................................................. 97 3.2.2.5 Analysis................................................................................................................................ 97 3.2.2.6 Interpretation ........................................................................................................................ 99 3.2.2.7 Air ........................................................................................................................................ 99 3.2.2.8 Gas Spectrum – Types of Faults............................................................................................ 99 3.2.2.8.1 Hot Metal Surface............................................................................................................. 99 3.2.2.8.2 Examples of Hot Metal Surfaces ....................................................................................... 99 3.2.2.9 Overheated cellulose .......................................................................................................... 100 3.2.2.9.1 Examples of Overheated Cellulose ................................................................................. 100 3.2.2.10 Electrical Faults .................................................................................................................. 100 3.2.2.10.1 Examples of Electrical Faults......................................................................................... 100 3.2.2.11 Factors affecting gas concentration in transformers.............................................................. 101 3.2.2.11.1 Type and Brand of Oil ................................................................................................... 101 3.2.2.11.2 Oxygen......................................................................................................................... 101 3.2.2.11.3 Load............................................................................................................................. 101 3.2.2.11.4 Oil Preservation Systems .............................................................................................. 101 3.2.2.11.5 Gas Mixing ................................................................................................................... 102 3.2.2.11.6 Temperature................................................................................................................. 102 3.2.2.11.7 Gas Solubility in Oil....................................................................................................... 103 3.2.2.11.8 Other Factors................................................................................................................ 104 3.2.2.12 DGA Interpretation Methods................................................................................................ 106 3.2.2.12.1 Key Gas Method of Interpreting DGA............................................................................. 106 3.2.2.12.2 Individual and Total Dissolved Key-Gas Concentration Method ...................................... 107 3.2.2.12.3 Rogers Ratio Method .................................................................................................... 110 3.2.2.12.4 IEC Method .................................................................................................................. 112 3.2.2.12.4.1 Carbon Dioxide/Carbon Monoxide (CO2/CO) Ratio .........................................................112 3.2.2.12.4.2 IEC C2H2/H2 Ratio ..............................................................................................................113 3.2.2.12.4.3 IEC Recommended Method of Interpretation ...................................................................113 3.2.2.12.5 Duval Triangle Method for Diagnosing a Transformer Problem Using Dissolved Gas Analysis ................................................................................................ 114 3.2.2.12.6 ABB's Advanced Dissolved Gas Analysis Software (ADGA) ........................................... 117

3.2.3

Analysis of Particles in Transformer Oils ........................................................................ 118

3.2.3.1 Oil Sampling for Particle Analysis ........................................................................................ 118 3.2.3.2 Particle Counting ................................................................................................................ 118 3.2.3.2.1 Normal and Abnormal Particle Count Levels.................................................................... 119 3.2.3.3 Trace Metal Content of Particles.......................................................................................... 120 3.2.3.3.1 Method of Measurement ................................................................................................. 120 3.2.3.3.2 Normal and Abnormal Metallic Content of Particles in Oil................................................. 120 3.2.3.4 Diagnostic Examples of Particle Analysis............................................................................. 121 3.2.3.5 Effect of particles on dielectric strength of insulating oil ....................................................... 122 3.2.3.5.1 Current filtering practices on new transformers ................................................................ 122 3.2.3.5.2 Classification of contamination level ................................................................................ 123 3.2.3.5.2.1 Bare electrodes ....................................................................................................................123 3.2.3.5.2.2 Covered electrodes ..............................................................................................................123 3.2.3.5.3 Contamination deposited on insulating surface................................................................ 124 3.2.3.5.4 Recommended corrective action..................................................................................... 125

3.2.4

Winding Resistance Test ................................................................................................ 126

3.2.4.1

3.2.5 3.2.6

3.2.6.1 3.2.6.2 3.2.6.3

3.2.7

Measurement Method for Winding Resistance Measurement................................................ 126

Transformer Turns Ratio Test (TTR) ............................................................................... 128 Insulation resistance ....................................................................................................... 131 Measurement...................................................................................................................... 131 Interpretation ...................................................................................................................... 132 Polarization Index ............................................................................................................... 133

Insulation Power Factor Tests......................................................................................... 134

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3.2.7.1 Two-Winding Transformer ................................................................................................... 135 3.2.7.1.1 Testing of Two-Winding Transformers............................................................................. 136 3.2.7.2 Three-Winding Transformer................................................................................................. 139 3.2.7.3 Typical Insulation Power Factor Values................................................................................ 140 3.2.7.4 General Guidelines for Assessing Power Factor 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 and Diagnosis of Inadvertent Core Grounds................................................... 142

Excitation Current Tests.................................................................................................. 144 Measurement Setup............................................................................................................ 145 Analysis of Excitation Current Results.................................................................................. 148

Infrared Thermography Analysis of Transformers and Accessories ............................. 149

3.2.10.1 The Thermography Process ................................................................................................ 149 3.2.10.2 Criteria for Evaluating Infrared Measurements ..................................................................... 150 3.2.10.3 Example Uses of Infrared Thermography diagnostics on Power Transformers ..................... 150 3.2.10.3.1 Loose connection at bushing outlet terminal................................................................... 150 3.2.10.3.2 Blocked oil flow in radiators or radiator shut off .............................................................. 151 3.2.10.3.3 LTC overheating ........................................................................................................... 151 3.2.10.3.4 Low oil level in transformer or bushing ........................................................................... 152 3.2.10.3.5 Moisture contamination of surge arrester ....................................................................... 152

3.2.11

Bushings .................................................................................................................... 153

3.2.11.1 ANSI & IEC – Common Diagnostic Tools............................................................................. 153 3.2.11.1.1 Oil leakage inspection................................................................................................... 153 3.2.11.1.2 Insulator inspection and cleaning................................................................................... 153 3.2.11.1.2.1 Porcelain insulators ............................................................................................................153 3.2.11.1.2.2 Silicon rubber insulators.....................................................................................................153 3.2.11.1.3 Thermovision................................................................................................................ 153 3.2.11.1.4 Oil sampling from bushing ............................................................................................. 154 3.2.11.1.5 Dissolved Gas Analysis (DGA) ...................................................................................... 156 3.2.11.1.6 Moisture analysis .......................................................................................................... 156 3.2.11.1.7 Dielectric Frequency Response Analysis (DFRA)........................................................... 157 3.2.11.1.8 Partial Discharge measurements................................................................................... 157 3.2.11.1.9 De-polymerization analysis............................................................................................ 157 3.2.11.2 Diagnostics techniques for bushings complying with the ANSI/IEEE Standards..................... 158 3.2.11.2.1 Condenser Bushing Power Factor Tests........................................................................ 158 3.2.11.2.2 Factors Affecting C1 and C2 Capacitance and Power Factor Measurements .................. 159 3.2.11.2.3 Bushing Hot Collar Test ................................................................................................ 162 3.2.11.2.4 What to do when Bushing Power Factor Tests are Doubtful............................................ 164 3.2.11.2.5 Special Case – Type “U” Bushings ............................................................................... 164 3.2.11.2.5.1 History.................................................................................................................................164 3.2.11.2.5.2 Recommendation ...............................................................................................................170 3.2.11.2.6 Type “T” Bushings......................................................................................................... 173 3.2.11.3 Diagnostics and Conditioning on ABB Bushings Complying with the IEC Standard................ 174 3.2.11.3.1 Capacitance and tan measurement.............................................................................. 175 3.2.11.3.2 Temperature correction................................................................................................. 175

3.2.12

Measurements for Assessing the Condition of OLTCs/LTCs ....................................... 178

3.2.12.1 Number of Operations......................................................................................................... 178 3.2.12.2 Resistance of the Electrical Connections ............................................................................. 178 3.2.12.3 Temperature....................................................................................................................... 178 3.2.12.4 Motor Current ..................................................................................................................... 178 3.2.12.5 Acoustic Signal ................................................................................................................... 178 3.2.12.6 Relay Timing....................................................................................................................... 179 3.2.12.7 Gas-in-Oil Analysis ............................................................................................................. 179 3.2.12.7.1 Items Specific to the European Practice........................................................................ 179 3.2.12.7.1.1 Scope ..................................................................................................................................179 3.2.12.7.1.2 History.................................................................................................................................179 3.2.12.7.1.3 Faults in OLTCs possible to indicate by DGA...................................................................179 3.2.12.7.1.4 The Stenestam ratio...........................................................................................................180 3.2.12.7.1.5 Important principals for interpretation of DGAs in OLTC .................................................180 3.2.12.7.1.6 Interpreting the Stenestam ratio ........................................................................................180 3.2.12.7.1.7 Typical gas concentrations ................................................................................................181

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3.2.12.7.2 Important to bear in mind .............................................................................................. 182 3.2.12.7.3 North-American Practice ............................................................................................... 182 3.2.12.8 Moisture ............................................................................................................................. 183

3.3 ADVANCED DIAGNOSTIC TOOLS .............................................................................................. 184 3.3.1 Assessment of Mechanical Properties - Frequency Response Analysis (FRA) ................ 184 3.3.1.1 Introduction......................................................................................................................... 184 3.3.1.1.1 Purpose of FRA measurements ...................................................................................... 184 3.3.1.1.2 When should FRA measurements be performed?............................................................ 184 3.3.1.2 Standards........................................................................................................................... 185 3.3.1.3 General description of the FRA method ............................................................................... 185 3.3.1.3.1 Principle of the measurement.......................................................................................... 185 3.3.1.3.2 Practical set-up .............................................................................................................. 186 3.3.1.4 Commercial equipment ....................................................................................................... 187 3.3.1.5 Detailed measurement procedure........................................................................................ 187 3.3.1.5.1 Test preparation ............................................................................................................. 188 3.3.1.5.2 Tap changer position ...................................................................................................... 188 3.3.1.5.3 Treatment of un-tested terminals..................................................................................... 189 3.3.1.5.4 Test leads: ..................................................................................................................... 189 3.3.1.5.5 Test Set-up .................................................................................................................... 189 3.3.1.6 Reporting of FRA measurements......................................................................................... 192 3.3.1.6.1 General information: ....................................................................................................... 192 3.3.1.6.2 Transformer information:................................................................................................. 192 3.3.1.6.3 Description of each measurement: .................................................................................. 192 3.3.1.6.4 Instrumentation: ............................................................................................................. 193 3.3.1.6.5 Cabling: ......................................................................................................................... 193 3.3.1.7 Basic interpretation and on-site quality check....................................................................... 193 3.3.1.7.1 Some “normal” FRA spectra ........................................................................................... 194 3.3.1.7.2 Meaning of different frequency ranges in an FRA spectrum ............................................. 197 (A) When only the current FRA measurement data are available:....................................................... 197 3.3.1.7.3 Comparison between open- and short-circuit measurements ........................................... 197 3.3.1.7.4 Comparison between high- and low-voltage windings ...................................................... 197 3.3.1.7.5 Comparison between phases.......................................................................................... 197 (B) When further data are available................................................................................................... 198 3.3.1.7.6 Comparison with historical data....................................................................................... 198 3.3.1.7.7 Comparison with twin or sister units ................................................................................ 198 3.3.1.7.8 History of the unit ........................................................................................................... 198 3.3.1.7.9 Other diagnostic data...................................................................................................... 199 3.3.1.8 Examples of problems diagnosed using FRA ....................................................................... 199 3.3.1.8.1 Axial Winding Collapse................................................................................................... 199 3.3.1.8.2 Hoop Buckling................................................................................................................ 200 3.3.1.8.3 Shorted Turns ................................................................................................................ 202

3.3.2

Assessment of Thermal Properties ................................................................................. 204

3.3.2.1 Degree of Polymerization (DP) ........................................................................................... 204 3.3.2.1.1 DP versus Life Plots ....................................................................................................... 204 3.3.2.1.2 Latest Research Findings on DP Analysis ....................................................................... 207 3.3.2.2 Furanic Compound Analysis................................................................................................ 207 3.3.2.2.1 Origin of Furanic Compounds ......................................................................................... 207 3.3.2.2.2 Detection of Furanic Compounds .................................................................................... 208 3.3.2.2.3 Correlation Curves of Furanic Content with DP................................................................ 208 3.3.2.2.4 Issues to Consider in Using Furan Analysis..................................................................... 209

3.3.3

Dielectric Frequency Response as a Tool for Troubleshooting Insulation Power Factor Problems .................................................................................................. 211

3.3.3.1 Introduction......................................................................................................................... 211 3.3.3.2 Dielectric frequency response and X-Y model ...................................................................... 211 3.3.3.3 Causes of High Power Factor in Transformer Insulation ....................................................... 214 3.3.3.3.1 Comparison of DFR to Power Factor Measurement ......................................................... 214 3.3.3.3.2 Influence of Oil Conductivity and Moisture on PF and DFR .............................................. 215 3.3.3.4 Dielectric Frequency Response Signature and Identification Techniques .............................. 216 3.3.3.4.1 Identification of high Core-Grounding Resistance Problems ............................................. 217 3.3.3.4.2 Identification of Paper Contamination Problems............................................................... 220 3.3.3.4.3 Low Temperature Effect on Insulation Power Factor........................................................ 220 3.3.3.5 Summary............................................................................................................................ 222

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3.3.4

Assessment of Electrical Properties - Partial Discharge Measurements .......................... 223

3.3.4.1 Purpose of measurement .................................................................................................... 223 3.3.4.2 Electrical PD Measurement on Transformers ....................................................................... 224 3.3.4.2.1 Calibration...................................................................................................................... 225 3.3.4.2.2 PD measuring procedure................................................................................................ 226 3.3.4.2.3 An Advanced PD system ................................................................................................ 226 3.3.4.3 Procedure for Investigation of PD Sources........................................................................... 228 3.3.4.4 Acoustical Partial Discharge Measurement on Transformers ................................................ 233 3.3.4.4.1 Acoustic PD Wave Characterization................................................................................ 233 3.3.4.4.2 Acoustic Partial Discharge Localization ........................................................................... 235

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FAULT ANALYSIS ..................................................................................................................... 237 4.1 GUIDANCE FOR PERFORMING FAILURE ANALYSIS ....................................................................... 237 4.1.1 Introduction..................................................................................................................... 237 4.1.2 Failure definition ............................................................................................................. 239 4.1.3 Classification of failures .................................................................................................. 239 4.1.4 General information on malfunctions and failures ............................................................ 240 4.1.5 Systematic failure 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 ........................................................................ 242 Data and information at the time of fault inception ................................................................ 243 Deciding on continued operation or additional investigations ................................................ 246 Assessment of the extent of damage on site ........................................................................ 247 Assessment of external damage on site............................................................................... 248

Diagnostic measurements and their interpretation ........................................................ 249

4.1.6.1 Routine measurements on site ............................................................................................ 250 4.1.6.1.1 Oil analysis .................................................................................................................... 250 4.1.6.1.2 Insulation resistance and tan ........................................................................................ 250 4.1.6.1.3 Measurement of transformer ratio ................................................................................... 250 4.1.6.1.4 Measurement of winding resistances............................................................................... 251 4.1.6.1.5 Measurement of short-circuit impedance ......................................................................... 251 4.1.6.1.6 Excitation at low voltage ................................................................................................. 252 4.1.6.2 Special diagnostic measurements ....................................................................................... 252 4.1.6.2.1 Gas-in-oil analysis .......................................................................................................... 252 4.1.6.2.2 Measurement of partial discharges.................................................................................. 254 4.1.6.2.3 FRA method................................................................................................................... 255 4.1.6.2.4 Measurement of polarization effects for assessing the moisture ....................................... 256 4.1.6.3 Inspection of core-and-coil assembly on site ........................................................................ 256 4.1.6.3.1 General preconditions..................................................................................................... 256 4.1.6.3.2 Safety precautions.......................................................................................................... 257 4.1.6.3.3 Checks to be conducted ................................................................................................. 257 4.1.6.4 Dismantling the defective transformer .................................................................................. 258 4.1.6.4.1 Preconditions ................................................................................................................. 258 4.1.6.4.2 Inspection ...................................................................................................................... 259 4.1.6.4.3 Inspection of the core-and-coil assembly after lifting out of the tank.................................. 259 4.1.6.4.4 Inspection of the windings............................................................................................... 260 4.1.6.5 Typical fault patterns of windings ......................................................................................... 260 4.1.6.5.1 Short-circuit faults........................................................................................................... 260 4.1.6.5.2 Electrical flashover ......................................................................................................... 261 4.1.6.5.3 Thermal faults ................................................................................................................ 263 4.1.6.6 Inspection of the core and the tank ...................................................................................... 263

4.1.7 4.1.8

Final assessment of the failure and the fault.................................................................... 264 Case Studies .................................................................................................................. 265

4.1.8.1 4.1.8.2 4.1.8.3

5

ONLINE DIAGNOSTIC MONITORS FOR TRANSFORMERS AND KEY ACCESSORIES .......... 284 5.1 5.2 5.3

xii

Case 1: Examination of a transformer affected by partial discharges.................................... 265 Case 2: Analysis of a failure caused by overvoltages at no-load switching operation ........... 275 Case 3: Fault analysis on a generator step-up Transformer following an internal flashover . 279

POWER TRANSFORMER (TANK & CORE) .................................................................................. 284 LOAD TAP CHANGER ............................................................................................................. 285 BUSHING & CT ..................................................................................................................... 285

5.4 6

EXAMPLE MONITORING SYSTEMS ........................................................................................... 286

PREVENTIVE MAINTENANCE OF TRANSFORMERS............................................................... 294 6.1 BASIC AGEING PROCESSES .................................................................................................... 294 6.1.1 Introduction..................................................................................................................... 294 6.1.2 Paper Degradation.......................................................................................................... 295 6.1.3 On-site Drying Methods .................................................................................................. 298 6.1.3.1 6.1.3.2

6.1.4

Traditional methods............................................................................................................. 298 On-site drying with low frequency heating (LFH) in combination with hot-oil spray ................ 299

Oil reclaiming.................................................................................................................. 300

6.1.4.1 6.1.4.2 6.1.4.3

Online oil reclaiming technology ......................................................................................... 300 Comparison with oil change................................................................................................. 300 Long- term stability.............................................................................................................. 300

6.2 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 Schedule........................................................................................... 302 Quarterly Maintenance Schedule......................................................................................... 303 Annual Maintenance Schedule with The Transformer De-energized ..................................... 304

Maintenance of Components .......................................................................................... 305

6.2.2.1 Transformer liquid and insulation......................................................................................... 305 6.2.2.2 Bushings and joints............................................................................................................. 306 6.2.2.3 Off-load tap changer (DETC)............................................................................................... 306 6.2.2.4 On-load tap changer ........................................................................................................... 307 6.2.2.5 Motor drive unit ................................................................................................................... 307 6.2.2.6 Oil filtering unit.................................................................................................................... 307 6.2.2.7 Coolers............................................................................................................................... 307 6.2.2.8 Liquid conservator with rubber diaphragm (COPS)............................................................... 307 6.2.2.9 Gaskets.............................................................................................................................. 307 6.2.2.10 Surface protection............................................................................................................... 308 6.2.2.10.1 Painted surfaces ........................................................................................................... 308 6.2.2.10.2 Zinc coated 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 .................................................................................................... 312 The Inspection .................................................................................................................... 313 Electrical Tests ................................................................................................................... 314

Maintenance of Bushings................................................................................................ 315 Maintenance and Service of OLTCs/LTCs ..................................................................... 317 General Quality Information for Various Types of LTCs................................................... 318

6.2.7.1 6.2.7.2

7

Recording of disturbances................................................................................................... 308 Fault localizations advice for oil-immersed transformers ....................................................... 309

North-American Practices.................................................................................................... 318 European Practice .............................................................................................................. 322

REPAIR, REFURBISHMENT AND RETROFIT ........................................................................... 324 7.1 PREPARATION PHASE ............................................................................................................ 325 7.2 UNTANKING AND DISASSEMBLY OF ACTIVE PART ....................................................................... 326 7.3 REPAIR OF THE TRANSFORMER ............................................................................................... 327 7.4 ASSEMBLY AND TANKING OF THE ACTIVE PART .......................................................................... 328 7.5 DRYING ................................................................................................................................ 328 7.6 FINAL ASSEMBLY ................................................................................................................... 329 7.7 HIGH VOLTAGE TESTING ........................................................................................................ 329 7.8 QUALITY PLAN ..................................................................................................................... 330 7.9 FACILITIES FOR SITE REPAIR .................................................................................................. 330 7.9.1 Temporary Workshops.................................................................................................... 331 7.9.1.1 7.9.1.2 7.9.1.3

7.9.2

Steel Buildings.................................................................................................................... 331 Large Tents ........................................................................................................................ 331 Foundation for a Temporary 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................................................................................................................. 333 Drying equipment ........................................................................................................... 333 High voltage test equipment............................................................................................ 333

ENVIRONMENTAL ASPECTS ................................................................................................... 334 8.1 CONTAMINATION OF OILS WITH PCB (POLYCHLORINATED BIPHENYLS) ....................................... 334 8.1.1 General .......................................................................................................................... 334 8.1.2 Dehalogenation Processes Using Sodium and Lithium Derivatives.................................. 335 8.1.3 Dehalogenation Processes Using Polyethyleneglycol and Potassium Hydroxide ............. 335 8.1.4 Dehalogenation in Continuous Mode by Closed Circuit Process...................................... 335 8.2 ELECTROMAGNETIC COMPATIBILITY (EMC) ............................................................................. 335 8.2.1 Introduction..................................................................................................................... 335 8.2.2 Methods to Reduce EMF Levels in Existing Substations ................................................. 336 8.3 AUDIBLE NOISE ..................................................................................................................... 336 8.3.1 Introduction..................................................................................................................... 336 8.3.2 Background .................................................................................................................... 337 8.3.2.1 8.3.2.2

Characteristics of Transformer Noise................................................................................... 337 Propagation of Sound ......................................................................................................... 337

8.3.3 Criteria for Community Noise Levels ............................................................................... 337 8.3.4 Requirements ................................................................................................................. 338 8.3.5 Methods of Substation Noise Control .............................................................................. 338 8.4 RELEASE OF INSULATING OIL.................................................................................................. 340 8.4.1 Introduction..................................................................................................................... 340 8.4.2 Use of Synthetic Ester .................................................................................................... 340 8.4.3 Use of Natural Ester ...................................................................................................... 341 9

ECONOMICS OF TRANSFORMER ASSET MANAGEMENT ..................................................... 342 9.1 FAILURE STATISTICS FOR POWER TRANSFORMERS................................................................... 342 9.1.1 CIGRE Survey of Failures in Large Power Transformers ................................................ 342 9.1.2 Canadian Electricity Association Forced Outage Report ................................................. 344 9.2 ECONOMICS OF TRANSFORMER MANAGEMENT FOR FLEETS AND SPECIFIC UNITS ........................... 347 9.2.1 Introduction..................................................................................................................... 347 9.2.2 General Concept for Economics of Transformer Management......................................... 348 9.2.3 Description of the Simulation Model ................................................................................ 349 9.2.4 Case Study by a Utility.................................................................................................... 350 9.2.5 Conclusions.................................................................................................................... 352

10

HEALTH AND SAFETY ASPECTS / RECOMMENDATIONS ..................................................... 353 10.1 PREAMBLE ........................................................................................................................... 353 10.2 INTRODUCTION ..................................................................................................................... 353 10.3 SCOPE ................................................................................................................................. 353 10.4 DEFINITIONS ......................................................................................................................... 354 10.5 SAFETY MANAGEMENT .......................................................................................................... 355 10.6 DOCUMENTATION .................................................................................................................. 355 10.7 ELECTRICAL SAFETY RULES ................................................................................................... 356 10.7.1 General Rules ............................................................................................................ 356 10.7.2 Communication and Control Rules.............................................................................. 356 10.7.3 Rules for working on dead Electrical Equipment.......................................................... 357 10.7.4 Rules for working on or very near live Electrical Equipment......................................... 361 10.7.5 Switching.................................................................................................................... 361 10.7.6 Work on or very near live conductors .......................................................................... 361 10.7.7 Testing and Commissioning........................................................................................ 362 10.8 W ORK AT HEIGHT: ADDITIONAL SAFETY EQUIPMENT FOR POWER TRANSFORMERS. ...................... 362 10.8.1 “NO-RISK SYSTEM”................................................................................................... 362 10.8.2 “Fall Arrest Towers and Base Plates”.......................................................................... 365

xiv

10.9 APPENDICES......................................................................................................................... 365 10.9.1 Appendix 1 - Minimum working clearance ................................................................... 366 10.9.2 Appendix 2 - Minimum design clearances where power lines cross or are in close proximity 368 10.9.3 Appendix 3 - Minimum separation across point of disconnection in air......................... 369 10.9.4 Appendix 4 - Principles of Risk Assessment................................................................ 370 10.9.5 Appendix 5 - Example of Sample Risk Assessment Sheet. ......................................... 371 10.9.6 Appendix 6 - Electrical Job Hazard Analysis Sheet. .................................................... 372 10.9.7 Appendix 7 - Sample Safety Check Sheet................................................................... 374 10.9.8 Appendix 8 - Sample Safety Permit to work. ............................................................... 376 10.9.9 Appendix 9 - Sample Energized Electrical Work Permit............................................... 378 REFERENCES.................................................................................................................................... 379 INDEX................................................................................................................................................. 390 ABB TRANSFORMERS SERVICE GENERAL BROCHURES ........................................................... 395 ABB TRANSFORMERS SERVICE PRODUCT LEAFLETS................................................................ 405 ABB TRES NORTH AMERICA SERVICE BROCHURES.................................................................... 423 CONTACT LIST FOR MAIN ABB SERVICE CENTERS...................................................................... 454

xv

1 TRANSFORMER DESIGN CONSIDERATIONS [1] 1.1

CONFIGURATION

There are two basic configurations for power transformers: core form and shell form. The principal physical difference between the two constructions 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 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 using interconnected 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 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 CONSIDERATION

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. The mechanical stresses developed during normal operation are low, but the stresses generated by a system short circuit event can be quite large. Also, the 17

magnitude of these stresses increase with the size 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 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 (oil natural, air natural/oil natural, air forced – 100 %/133 %) – the old designation was OA/FA ONAN/ONAF/ONAF – (oil natural, air natural/oil forced, air forced/ oil 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 two stages of auxiliary cooling are employed, the equipment is generally divided equally among the two stages. The designation for cooling 18

with auxiliary fans and pumps is defined in the standards as (past nomenclature shown in parentheses): ONAN/ODAF (oil natural, air natural/oil directed, air forced – 100 %/133 %) – the old designation was OA/FOA. ONAN/ODAF/ODAF (oil natural, air natural/oil directed, air forced/ oil directed, air forced – 100 %/133 %/167 %) – the old designation 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.

1.4

DIELECTRIC CONSIDERATIONS

The transformer insulation system must be designed to withstand the normal operating voltages as well as over-voltages during lightning events, system short circuits, and system switching surges. In addition, consideration 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 over- voltages. 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 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 winding.

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 in the tank bottom section. The core is positioned horizontally around the outside of the winding and acts as a protective shell around the 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 through the heat exchanger. With either mode of cooling, the oil passes through a heat exchanger where it cools prior to reentering the tank at 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.

Figure 1-1: Partial Cutaway of a Shell Form Transformer 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 external to the windings is only the force corresponding to a single pair of winding groups (see Figure 1-2).

Figure 1-2: Section Through a Shell Form Winding Group with a High-Low Coil Configuration (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 perpendicular to the face of the pancake 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 low. The total force magnitude in a shell form design can be reduced considerably with multiple high-low coil arrangements. Even with this advantage it is essential to have a 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 CAPABILITY

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 which the oil travels from 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 the core adequately cools this area; therefore, oil ducts within 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 (see Figure 1-4).

22

Figure 1-4: Partial Cutaway of a Shell Form Transformer Illustrating OA (Self-Cooled) Cooling Action

As the load on a transformer increases, the energy generated by the losses in the coil system will increase in 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 Action 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 coils and from coil to ground are directly proportional, respective to the cross-sectional area of the coil and the area of its 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 terminate 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 of voltage. The highest voltage winding is on the outside of the assembly. 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: Partial Cutaway of a Core Form Transformer

Cooling of the core and coil assembly is accomplished by oil circulation through ducts between the coils and also ducts within the core. The oil flow from 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, and the stress is transmitted to the winding tube (see Figure 1-9).

Figure 1-9: Section Through a Core Form Winding Group with an Expanded View of One Coil and Spacers (arrows illustrate mechanical forces)

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 tensile strength of the HV winding conductor 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

Figure 1-10: Partial Cutaway of a Core Form Transformer Showing the Support Structure for Core and Coils 1.5.2.3

T HERMAL CAPABILITY

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 is a helical winding that uses insulated rectangular or transpose conductors and is cooled by oil flow through ducts on either side of the coil. The core has 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: Partial Cutaway of a Core Form Transformer Illustrating (a) ONAN (Self-Cooled) Cooling Action; and (b) OFAF (Forced-Cooled) 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: Partial Cutaway of a Core Form Transformer Showing Coils, Insulation, and Tap Leads

31

1.6

BUSHINGS [2]

Bushings may be classified by design as follows: Condenser type: a) Oil-impregnated paper insulation, with interspersed conducting (or condenser) layers of oil-impregnated paper insulation continuously wound with interleaved lined paper layers b) Resin-bonded paper insulation, with interspersed conducting (condenser layers) c) Resin-impregnated paper insulation. Bushing in which the major insulation is impregnated with a curable epoxy resin Non-condenser type: a) Solid core or alternate layers of solid and liquid insulation b) Solid mass of 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 interchangeability of products among different manufacturers. 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 BUSHINGS COMPLYING WITH THE IEEE STANDARDS [4] ABB condenser bushings (e.g. Type “O Plus C”, Type AB) are designed for transformer 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 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 C1 (main) and C2 (tap) capacitances. The C1 capacitance is formed by the main oil/paper insulation between the central conductor 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 layer/foil is permanently 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 connection 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 divider. The voltage developed across the C2 capacitance is modified by the potential device and is used for operation of relays, and other instruments. Also, the voltage tap can be used for measuring the power factor and capacitance of C1 and C2 insulation of the bushing. In addition, this tap can be used for monitoring the partial discharge during factory tests and 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

CENTER CONDUCTOR

Figure 1-13: Design Details of a Typical Condenser Bushing, 115kV and Above

Condenser bushings rated 69 kV and below are provided with C1 capacitance as per the IEEE Standards. This capacitance, which is considered 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 connected to the test tap. These bushings 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 between the condenser core and the mounting flange, and the tap insulator. Under normal operating conditions, the C1 layer/foil is automatically grounded 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 C2 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

CENTER CONDUCTOR

Test Tap

Mounting Flange (Grounded)

C1

C2

Figure 1-14: Design Details of a Typical Condenser Bushings, 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, flange extension, spring assembly, sight bowl, lower support, and clamping nut form an oil-tight shell to contain the condenser and insulating oil. The 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

Figure 1-15: Cutaway View of ABB Type AB Bushing 138 kV of Bushing Capacitances

1.6.2 BUSHINGS VOLTAGE TAP ABB bushings rated 115 kV and higher (e.g. Type O Plus C) have a small housing containing a voltage tap outlet just above the mounting flange. 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 conjunction with a potential/monitoring 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 under the heading of “Maintenance.” When a connection is to be made to the voltage tap, either for use with a potential device or for power factor measurement, 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 VOLTAGE TO THE BUSHING WITH THE VOLTAGE TAP 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 DIELECTRIC 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 BUSHINGS

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 of the bushing. 1.6.4 LIQUID LEVEL 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, the filler level should be satisfactory for the life of the bushing. Since fluctuations in oil level will necessarily occur with changing temperatures, 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 equipped 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 disappeared 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 PERSONAL INJURY, 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 wiped with a commercial safety solvent and then wiped dry. The cleaned area should then be coated with suitable outdoor gray enamel paint.

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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 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 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 LTCS

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 transformers. 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 overload. When changing tap positions, the LTC mechanism must “make before break” 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 LTCS

Reactance type LTCs use a preventive auto transformer, usually housed in the main transformer tank and connected in series with the main low-voltage winding 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 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 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 reserved. This reprint implies no endorsement, either tacit or expressed, of any company, product, service, or investment opportunity.

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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 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 auto to carry the full load current plus the circulating current. However, a major shortcoming of the reactance type LTC is that the inherent inductance of the preventive auto transformer increases the arcing time as the fixed and moving contacts separate. Three different 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

Arcing 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. 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 wear and coking, the contamination of oil in this type of LTC mechanism is much more severe than any other arcing-in-oil mechanism.

Figure 1-18: Arcing Tap Switch Reactance LTC

1.7.2.3.2

Arcing Switch 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.

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Figure 1-19: Arcing Switch-and-Tap Selector Reactance LTC

1.7.2.3.3

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 circulating current. Most manufacturers state that, if this occurs, the mechanism must be returned to a normal operating position as soon as possible or the transformer load must be reduced to one-half of the nameplate rating. This off-tap position can also occur in the arcing switch-and-tap 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 LTCS

The vacuum interrupter-and-tap selector type is a significant improvement over other reactance LTC mechanisms. In effect, the arcing current is diverted from the 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 usually last for the life of the transformer, since they are not burdened with arcing and the associated contact wear. 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.

Figure 1-20: Vacuum Interrupter Reactance Type LTC 1.7.2.5

RESISTANCE T YPE LTCS

Resistance type LTCs place resistors in the circuit to limit the circulating current during the time that the tap change is taking place. The principal difference between resistance type LTCs and reactance type mechanisms is that the resistance type never 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 zero. The high speed of the mechanism also contributes 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

Figure 1-21: Resistance Type LTC 1.7.2.6

DRIVE MECHANISMS FOR RESISTANCE TYPE LTCS

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. 1.7.2.7

FAILURE MECHANISMS FOR LTCS

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 are discussed below.

1.7.2.7.1

Electrical Connections

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 becomes depleted, the underlying copper surface of the contact 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 increases the deposition rate of the oxides and can lead to coking failures. Coke, a black carbon material, is a by-product of oil degradation and is 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 surface, increasing mating resistance and heat by virtue of the higher I2R power loss. The added heat anneals the spring material that holds the 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]. 1.7.2.7.2

Insulation 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 the insulation capability of the oil is of 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, CO2, H2, and hydrocarbon compounds like CH4, C2H6, 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 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. 1.7.2.7.3

Control System

The switching of the LTC is controlled and monitored by a system of relays and RTUs. A failure of any of these components will lead to a failure of the 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 operation when the main contact is moving from one position to another Reduce the circulation current that will start with the switching operation when one loop in the regulation winding is short circuited The arcs during the switching operation are normally extinguished at the first current/voltage 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 tank. The tap selector, which makes the connection to the tap (regulating) winding, is placed under the diverter switch. Figure 1-22 shows the layout of a typical diverter switch tap changer and Figure 1-23 shows a complete switching sequence between taps.

Figure 1-22: An ABB diverter switch tap changer of type UC.

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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 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

Figure 1-24 : Selector switch tap-changers of UZ and UBB type

50

UZ design with fixed contacts in a circle and the main contact surrounded by the transition contacts at the top.

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 that the arc has extinguished. The transition resistor contact, M2, carries the load current.

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 transition resistor contact M2 has broken at the fixed contact 1, and the arc has extinguished. The transition resistor and the transition 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 : Example of a switching sequence for selector switch tap-changers

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 transformer tank. If the voltage over the selector is too high, 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.

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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 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

FAILURE 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

Electrical Connections

The contacts where the breaking takes place are typically of copper/tungsten 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 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 on 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.

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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-changers. 1.7.3.5.2

Insulation 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. 1.7.3.5.3

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 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, it can prevent the tap-changer from operating.

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1.8

STREAMING ELECTRIFICATION

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 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. Several factors have been shown to influence the likelihood of streaming electrification in transformers. These include the electrostatic charging tendency of the oil, the oil flow velocity, the conductivity of the oil, the insulation temperature, 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 static electrification, generates a potentially 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 streaming electrification as described above.

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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 (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 ( 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 is typically in the range of 0-150 C/m3. The charging tendencies of oils in “normal” field units have been measured in the range of 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 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. For example, if low-charging tendency oil is in a transformer that has high flow velocities, and the transformer insulation is cold (as in a startup), 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 a part of the installed base of inherited ABB transformers, ABB design engineers have the capability to determine the 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 1-2: Limits for Charging Tendency in Service Transformers ECT ( C/m3) 400

Potential for Streaming Electrification Normal Moderate to High High

1.8.2 MITIGATION STRATEGIES FOR STREAMING ELECTRIFICATION It is assumed that streaming electrification 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 generation process that aggravates the 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 electrification process is highly dependent 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-charging 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 generation 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 and leakage ducts there 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 oil space was found to play a very important role in the level of charge generation that occurs in the ducts and more importantly at the tips of the washers and the entrance regions to the ducts. It appears the local eddy effects generated in the lower plenum become 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 that cause the charging tendency of the oil to increase 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 hopefully dislodge most of the impurities from the cellulose. Retrofitting with low-charging oil may then be effective. Perhaps the most important observation was that the electrification process can be controlled via modifications of the operational processes of the transformer. Charge density measurements revealed a tremendous decrease in charge accumulation in the upper plenum beyond 50 °C, even under full pumping capabilities. The transformer can therefore be operated 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 recommends that utilities should ensure that all winding temperature 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 manufacturers recommend a chemical approach to solving this issue. They focus on reduction of the ECT by using additives (inhibitors). This technique could lead to a reduction in the risk of static electrification, especially for old transformer designs.

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2 A PRACTICAL APPROACH TO ASSESSING THE RISK OF FAILURE OF POWER 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 transformer asset with available resources. The importance 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 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 capabilities, and operational characteristics 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

LIFE MANAGEMENT PROCESS

Transformer risk assessment is a part of an overall unit oriented transformer life management process. This process has the following major ingredients: 1. A screening process to identify units for further scrutiny. 2. Condition analysis and more or less detailed design evaluation of individual units. 3. Life assessment decisions and their implementation (life extension via 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 evaluation, inspection, repair, or replacement. 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 dependent on other factors such as strategic and environmental 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 mentioned above. However, the functional forms of these aspects are very complex 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 economic) importance is a measure of the negative consequences of the failure. The result of the combined evaluation of the technical risk and importance in a risk management investigation is normally presented in either of two ways: As a Risk Index defined as a normalized product of the technical risk and relative importance as shown in Figure 2-1. In a two-dimensional diagram exemplified in Figure 2-2 and Figure 2-3 with 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

Risk Index

Technical Risk*Relative Importance

Transformer Units

Figure 2-1: Risk Index for a Number of Transformers

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 as well as diverse relative importance. In the diagrams, each transformer in the fleet is assigned a technical risk of failure and a 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 importance 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 A in the figures exemplify 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 reclosing practices or trimming trees in a right of way. Another strategy of risk management involves reducing the relative importance of a transformer. This is illustrated in the figures by case B. This strategy might involve moving a higher-risk transformer to a less critical location. It might also include adding a parallel spare 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 by the case C. 2.2.2 LAYOUT OF THE EVALUATION PROCEDURE Our risk assessment procedure focuses on the transformer functionality or suitability-for-use [11]. We address various aspects that might jeopardize or negatively influence this suitability-for-use.

Influential aspects on the suitability for use of the transformer

Technical suitability

Accessories

Mechanical suitability

Main tank

Electric suitability

Non-technical suitability

Economical incentives

Strategic reasons

Environmental reasons

Thermal suitability

Figure 2-4: Various 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 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 stress conditions. Also, metal parts at high temperature could pose a risk to the transformer. 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. Accessory failures: 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 overall structure. ABB has methods of different complexity 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 available information in order for the evaluation to be economically reasonable. The data for reasoning is then pre-processed data based on 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.

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I. Overall unstructured 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: Procedures for obtaining the technical risk value for a transformer

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 design 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 ranking is for practical reasons applied only to a reduced number of transformers since 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. Sometimes an absolute assessment of the individual failure rate of a unit is desired. A first approximation to this is achieved by combining the 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 = f (Technical Risk)

INDIVIDUAL FAILURE RATE

Figure 2-6: Combination of a statistical failure rate function with a technical parameter value to obtain an estimation of the individual failure rate of the addressed transformer

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2.3

ASSESSMENT OF THE TECHNICAL RISK OF FAILURE BY CATEGORY (MTMPTM PROGRAM)

The algorithms for technical risk of failure, as discussed above, are based on influential factors related to the individual subcategories [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 in a given year. For example, it is typically the case that transformers having a higher incidence of through-faults have the highest relative risk of short circuit failure. These transformers are generally located in substations feeding distribution lines. 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 of service of 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 affecting random failure can be: the type of transformer, the location, cases where a transformer must be removed from service to de-gas the oil, loading 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 individual failure rate) is obtained either directly from method 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 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 transformers is also calculated based on the replacement cost for the transformer or the criticality of the transformer to system reliability. In order to develop a priority for addressing mitigation strategies for the transformers, a plot of the risk of failure vs. the importance is shown in Figure 2-8.

40

Number of Units

35 30 25 20 15 10 5

Total Failure Risk

Figure 2-7: Total Risk of Failure of Transformers

68

6.125

5.625

5.125

4.625

4.125

3.625

3.125

2.625

2.125

1.625

1.125

0.625

0.125

0

100

Relative Importance

80

A 60

40

20

B

0 0.0

1.0

2.0

3.0

4.0

5.0

6.0

Probability of Failure

Figure 2-8: Categorization of Risk (Technical Risk or probability of failure and relative importance) Profiles for Power Transformers

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 recommendations for mitigation 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 for the high accessory risk factor was traced to a conditional factor associated with a leaking high-voltage bushing. On the other hand, the unit labeled B is 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.

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2.4

RISK MITIGATION

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 and risk mitigation actions. In such 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 appropriate 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, pump, 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.

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3 DIAGNOSIS OF TRANSFORMERS Power transformers are of prime importance for electrical power systems. The condition of a power transformer is crucial for its successful operation 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 condition 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]

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 summarized 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. 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 high density transformer board used for winding spacers and mechanical supports; and Kraft-based medium to high density transformer board used as 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 transformers. 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 shorttime load overcurrents, fault currents mainly caused by system short circuit and inrush currents while under energization 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, transient impulse 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 for a reliable evaluation of the risk of failure. The experience and interpretation capabilities of transformer experts are crucial 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 AND F AILURE 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 dielectric strength after 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 consequence of: Short circuit faults Local overheating due to circulating currents, current unbalance or the effects of leakage flux Insulation failure under electric stress (dielectric failure), perhaps as the final stage of a scenario involving previous short-circuit faults and/or local overheating, and Accessory failures (bushings, tap changers, coolers, surge-arresters, etc.). Faults can be classified as developing in one of three time scales: An immediate fault where electrical breakdown occurs within 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, weeks, or months; A deterioration of HV insulation over a period of months or years. Diagnostic techniques have been introduced mainly to detect the presence of small local faults and to monitor their 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.

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Table 3-1: Most Important Diagnostic Techniques Used for Power Transformers

STATUS OF THE DIAGNOSTIC 3 TECHNIQUE

PROVEN EFFECTIVENESS OF THE DIAGNOSTIC 4 TECHNIQUE

A A A A A

M L H M/H H

A A

H M

ON

B

M/H

ON

B

M/H

ON ON

B A

L H

28

ON

A

M

29

OFF-S

A

L

ON ON

B B

M/H M/H

30, 31 32

OFF-S OFF-S

A A

H H

33

PROBLEMS

DIAGNOSTIC TECHNIQUES

SERVICE CONDITIONS OF THE 2 EQUIPMENT

MECHANICAL

1. Excitation Current 2. Low-voltage impulse 3. Frequency response analysis 4. Leakage inductance measurement 5. Capacitance

OFF-S OFF-S OFF-S OFF-S OFF-S

GAS-IN-OIL ANALYSIS 6. Gas chromatography 7. Equivalent Hydrogen method

THERMAL

OIL-PAPER DETERIORATION 8. Liquid chromatography-DP method 9. Furan Analysis HOTSPOT DETECTION 10. Invasive sensors 11. Infrared thermography

ON ON

REFERENCE

21 22 23

24, 25 26

27

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 DIAGNOSTIC METHODS FOR BUSHINGS Bushings provide insulated terminals carrying current into and out from power apparatus, such as transformers, reactors, circuit breakers and HVDC valve halls. They additionally serve as mechanical supports for external bus and lines, as well as for internal supports, such as circuit breaker contacts.

2 3 4

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 H = high, M = medium, L = low

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Bushings are constructed to numerous design considerations, but commonly consist 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 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 condenser 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, in porcelain Oil-impregnated, oil-immersed Resin-bonded, either oil or gas-immersed Resin-impregnated, oil-immersed 3.1.2.1

STRESSES ACTING ON BUSHINGS

Apparatus bushings are subject to the effects of internal apparatus voltage, current, temperature, and contamination but are also subject to external atmospheric and environmental conditions as well as mechanical stresses. 3.1.2.2

DETERIORATION F ACTORS AND F AILURE MECHANISMS

Bushing insulation integrity degrades in normal service from internal moisture, internal PD and tracking from external corona, flashover and tracking from ageing, and 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. 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.

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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 3-2: Most Important Diagnostic Techniques Used for Bushings

DIAGNOSTIC TECHNIQUES

SERVICE CONDITIONS OF 5 THE EQUIPMENT

STATUS OF THE DIAGNOSTIC 6 TECHNIQUE

PROVEN EFFECTIVENESS OF THE DIAGNOSTIC 7 TECHNIQUE

REFERENCE

Moisture

Capacitance/Power Factor Tap voltage DC resistance Hot-collar

OFF-S ON OFF-S OFF-S

A A A A

H M L H

34, 35, 36, 37 34, 35, 36, 37 34, 37 37

Corona

Partial discharge (PD) Radio-influence voltage (RIV) Capacitance/Power Factor DC resistance Capacitance/Power Factor Tap voltage PD/RIV Capacitance Power Factor AC dielectric loss Infrared scanning

OFF-S ON OFF-S OFF-S OFF-S ON/OFF-S

B B A A A A A A A A

M/L M H L H M M/L M H H

37 37 34, 35, 36, 37 34, 37 34, 35, 36, 37 34, 37 34, 37 34, 37 37 37

PROBLEMS

Ageing Short-circuited condensers Internal surface leakage Poor connections

OFF-S OFF-S OFF-S ON

3.1.3 DIAGNOSTIC METHODS FOR SURGE ARRESTERS Surge arresters are used as protective devices to limit the amplitude of possible overvoltages in the electrical network. However, most of the time 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. made 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 7

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 H = high, M = medium, L = low

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A very important feature is that the voltage distribution 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. 3.1.3.1

STRESSES ACTING 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 deterioration in the arrester. Mechanical stresses are normally taken entirely by the porcelain insulator, whereas the active arrester parts are well protected. 3.1.3.2

DETERIORATION F ACTORS AND F AILURE 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 of the gaps can also be affected. Tightness is a must for good performance 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 stage is thermal runaway. Grading capacitor deterioration: Less frequent than grading resistor deterioration, but essentially the same effect. Gap 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. For healthy and well-designed arresters, the failure rate should not be higher than about 1/1,000 per year.

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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 policy. Otherwise diagnostic techniques are not likely to be more intensively used than just being included in the maintenance programs. 3.1.3.3

DIAGNOSTIC METHODS

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

External pollution

DIAGNOSTIC TECHNIQUES

SERVICE CONDITIONS OF 8 THE EQUIPMENT

STATUS OF THE DIAGNOSTIC 9 TECHNIQUE

CONVENTIONAL SURGE ARRESTERS - Visual inspection ON - Measurement of external leakage ON current

Heating of grading resistors

-Thermovision

Deterioration of grading system

- Leakage current under controlled voltage - Watt loss under controlled voltage - 60 Hz spark-over voltage

PROVEN EFFECTIVENESS OF THE DIAGNOSTIC TECHNIQUE 10

A ?

L L

ON

A

M

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

REFERENCE

38 38 38

METAL-OXIDE SURGE ARRESTERS

External pollution

Deterioration of varistor blocks

8

- 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

OFF-S = equipment out of service at site, OFF-L = equipment out of service in laboratory, ON = equipment in service

9

A = generally applied, B = development stage 10 H = high, M = medium, L = low

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39 38 40

3.2

GENERAL DIAGNOSIS TOOLS 3.2.1

3.2.1.1

OIL QUALITY ASSESSMENT FACTORS AFFECTING THE HEALTH AND LIFE OF POWER T RANSFORMERS 11

The three main components subject to deterioration and contamination in a 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. The presence of these elements in the transformer 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

Water Entering as a Vapor

Direct exposure of the insulation to air during installation and inspection. Ingress by viscous movement of wet air through unsealed oil expansion systems (conservator tanks) and through loose or cracked gaskets (at flange connections). As a byproduct of the ageing of the insulation system

Liquid Water

Damaged water heat exchangers. When the transformer is under less than 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

Particles

Storage Mode Most of the water is stored in the thin structure that operates at oil bulk temperature (20-30% of the total insulation mass). Presence of “wet zones” (typically bottom part of insulation of outer winding). Concentration in the vicinity of hotspots Bound water-in–oil. Typically on the bottom parts of the tank and coolers. Diffusion into the oil. Temperature migration. Movement of ice by oil flow.

Migration in oil. Sediment under effect 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.

11

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 also the dimensions of the cellulosic insulation structures. Parts of the insulation that are in contact with less heated layers of bulk oil may have notably higher 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 3.2.1.2.1

METHODS FOR ASSESSING THE Q UALITY OF T RANSFORMER OILS Dielectric Breakdown 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 dielectric 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. 3.2.1.2.2

Interfacial Tension (IFT)

This test (ASTM D-971-99a) is used to determine the interfacial tension between the oil sample and distilled water. The oil sample is put into a beaker of distilled water at a temperature 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 particles extend across the water/oil interface line and weaken the tension between the two liquids. The more particles are present, the 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 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

Acid Neutralization 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.

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Figure 3-1: Interfacial Tension, Acid Number, and Years in Service 3.2.1.2.4

Power Factor

Power factor indicates the dielectric loss leakage current of the oil. A high power factor indicates deterioration and/or contamination by-products such as water, carbon, or 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. 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 or only at 100 °C typically indicates the presence of contaminants. 3.2.1.2.5

Test for Oxygen Inhibitor

Moisture is destructive to cellulose and even more so in the presence of oxygen. It is therefore important to mitigate the effects of the presence of oxygen in transformer oil. 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. 3.2.1.2.6

Furan Analysis

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

PCB Content

Environmental legislation often requires that oil contaminated with PCB is given special treatment. For this reason service providers may sometimes refuse to handle oil that has not been proven to be PCB-free. There may also be strict rules for the disposal of PCB-containing oil. 3.2.1.2.8

Corrosive Sulphur

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 mechanisms involved. A new more severe copper strip test has been introduced (ASTM D1275 method B), and a covered conductor deposition test (“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 T RANSFORMER 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 by SINTEF Energy Research have shown that if normal life is defined as ageing under dry, oxygen-free conditions, a moisture content of 1 % in non-upgraded Kraft insulation can reduce life expectancy to 30 % of normal life. For 1 % moisture content in thermally upgraded Kraft insulation, the life expectancy is approximately 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 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.

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3.2.1.3.1

Transformer 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 species are a minor part of the constituents, but their presence may greatly influence the chemical and electrical properties of the oil. Polar compounds found in transformer oil usually contain oxygen, nitrogen, or sulfur. Ionic compounds are typically organic salts found only in 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 moisture), and especially in deteriorated 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). 3.2.1.3.2

Relative Humidity

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 dimensionless 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).

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Figure 3-2: Relative Humidity Curves for Transformer Oil 12 NOTE: Below 30 °C, the curves are not very accurate. 3.2.1.3.3

Paper (Cellulose)

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 between the cellulose fibers, as free water in capillaries, and as absorbed 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 transformer 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

3.2.1.3.4

Where Does the Water 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 rainwater through poor gasket seals due to pressure differences caused by transformer cooling. During rain or snow, if a transformer is removed from service, some transformer designs cool rapidly and the pressure 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. 3.2.1.3.5

Moisture Equilibrium between Oil and Paper in Transformers

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 transformer is in equilibrium 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 equilibrium 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 difficult to establish at low transformer temperatures. The situation improves somewhat as the transformer oil temperature gets above 50 °C. It 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

0C

o

o

10 C

o

20 C

o

30 C

40 C

4.5 4.0 o

50 C

% Moisture in Paper

3.5 IEEE C57.106-2002 Insulation Moisture Limits

3.0 o

60 C

2.5

69kV >69kV - 69 - 30

.

Condition of Cellulosic Insulation

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

89

Table 3-6: Recommended Maximum Limit of Water Content in Mineral Insulating Oil of Operating Gas Blanketed, Sealed, or Diaphragm Conservator Transformers a Average Oil Temperature

b

Suggested Maximum Water Contents in mg/kg and Percent Saturation 50°C 60°C 70°C c c c mg/kg % saturation mg/kg % saturation mg/kg % saturation 27 15 35 15 55 15 12 8 20 8 30 8 10 5 12 5 15 5

69 kV >69 - 69 - 69 - 69 - 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 KOH/gm) Results

Suggested Action

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 performed 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.

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 there is more than one connection between the core and ground. The dielectric withstand of the 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 core ground is established as a result of any of the above conditions, there will likely be circulating currents in the core. The result will be hotspots in the core 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 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 Test Set (Courtesy of Megger)19

Table 3-31: Diagnosing Inadvertent Core-Ground Problems Measured Core Ground Resistance 1000 M 100 M 10 to < 100 M 1 to < 10 M

Possible 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 is to switch to an ohmmeter and measure the resistance 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/.

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 open. It is important to perform the excitation current tests before any direct current (DC) tests. 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 windings. Exercise caution in the vicinity of all transformer terminals because voltage will be induced in all windings during a test. Winding terminals normally grounded in-service should be grounded during tests, except for the particular winding energized for the test. For routine tests, the load tap changer (LTC) should be set to neutral, then to 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 be the same for each phase. Because of the 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 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 the factory and 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 measured currents are high and 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. This should also be done on the individual phases of three phase transformers if the unit is suspect, or if the initial exciting current measurements are questionable. 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

Table 3-32: Excitation Current Test Connection Using Power Factor Test Set20 Transformer Type and Connection

Energized Lead

Measurement 21 Lead

Floating Terminals

Measured Excitation Current

Normal Current Pattern

Single Phase

H1 H2

H2 H1

X1 X2 X1 X2

IH1-H2 IH2-H1

IH1-H2 ~ I H2-H1

Three Phase Core Form W ye-Connected 3-limb core

H1 H2 H3

H0 H0 H0

H 2 H 3 ,X1 X2 X3 H 1 H 3 ,X1 X2 X3 H 1 H 2 ,X1 X2 X3

IH1-H0 IH2-H0 IH3-H0

(IH1-H0 ~ IH3-H0 ) > I H2-H0

Three Phase Shell Form W ye-Connected D core

H1 H2 H3

H0 H0 H0

H 2 H 3 ,X1 X2 X3 H 1 H 3 ,X1 X2 X3 H 1 H 2 ,X1 X2 X3

IH1-H0 IH2-H0 IH3-H0

(IH1-H0 ~ IH3-H0 ) > I H2-H0

Three Phase Core Form W yeConnected 5-limb core

H1 H2 H3

H0 H0 H0

H 2 H 3 ,X1 X2 X3 H 1 H 3 ,X1 X2 X3 H 1 H 2 ,X1 X2 X3

IH1-H0 IH2-H0 IH3-H0

IH1-H0 ~ IH2-H0 ~ I H3-H0 (The middle phase may be slightly higher)

Three Phase Shell Form W ye-Connected 7-limb core

H1 H2 H3

H0 H0 H0

H 2 H 3 ,X1 X2 X3 H 1 H 3 ,X1 X2 X3 H 1 H 2 ,X1 X2 X3

IH1-H0 IH2-H0 IH3-H0

(IH1-H0 ~ IH3-H0 ) > I H2-H0

Three Phase DeltaConnected

H1 H2 H3

H2 H3 H1

X1 X2 X3 X1 X2 X3 X1 X2 X3

IH1-H2 IH2-H3 IH3-H1

(IH2-H3 ~ I H3-H1 ) < I H1-H2

Ground Lead

H3 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; H0=1N; X1=2U; X2=2V; X3=2W, X0=2N 21 All measurements are performed with the test set in UST mode. If the secondary winding is wye connected, the neutral (X0) should be connected to ground.

146

Figure 3-27: Excitation Current Test Method for Single Phase Transformers

Figure 3-28: Excitation Current Test Method for Three Phase Wye-Connected Transformers

Figure 3-29: Excitation Current Test Method for Three Phase Delta-Connected Transformers

147

3.2.9.2

ANALYSIS 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 is greater than 50 mA, the difference should be less than 5 %. In general, if there is an internal problem, these differences will be greater. When this happens, 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 excitation current magnitudes by greater than 10% over normal 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]. Any localized problems caused by a change in local resistance will consume more power and generate heat. The local temperature of 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 spectrum. In most industrial applications, it is the energy radiated at infrared 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 established on the object for normal temperature. The temperature rise of all other points on the object is then evaluated in relation to the reference point temperature. If there are hotspots on the object, the criticality of the 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 tests on transformers, it is recommended that the surface temperature of the tank, as measured by an infrared camera, 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: Infrared Temperature Criteria 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

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.

EXAMPLE USES OF INFRARED T HERMOGRAPHY DIAGNOSTICS ON POWER T RANSFORMERS [81]

This section provides a few examples24 of the use of infrared thermography to diagnose problems in transformers and accessories. 3.2.10.3.1

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. 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.

24

150

Figure 3-31: Bushing Terminal Overheating Thermograph 3.2.10.3.2

Blocked 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: Thermography of a Shut-Off Radiator Bank

3.2.10.3.3

LTC overheating

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: LTC Compartment Overheating Due to Possible Hotspots in LTC 3.2.10.3.4

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 3.2.10.3.5

Moisture contamination 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 3.2.11.1.1

BUSHINGS

ANSI & IEC – COMMON DIAGNOSTIC T OOLS Oil leakage inspection

A visual inspection for leakage may be performed during normal station supervision. 3.2.11.1.2

Insulator inspection 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. 3.2.11.1.2.1

Porcelain insulators

Clean the porcelain insulator with water-jet or wiping with a moist cloth. If necessary, ethyl-alcohol or ethyl-acetatte may be used. 3.2.11.1.2.2

Silicon rubber insulators

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 : Measurement indicating poor current path between bushing inner and outer terminal

153

3.2.11.1.4

Oil sampling from bushing

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 always be replaced when the bushing is re-sealed. Sampling procedure for GOB, GOE and GOH The sample is taken from a plug 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 : Location of oil sampling plugs on some of the most common bushing types.

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: Dimensions for gaskets.

Gasket M8 M16 5/8"

d (mm) 8 14 14

D (mm) 16 35 35

T (mm) 3 4 4

Sampling procedure for GOEK, 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. Depending 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 procedure for GOA, 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 3-37 : Sampling on GOA at T>20 °C

Figure 3-38 : Sampling on GOA at T