TNB Cable Maintenance Manual

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TNB Distribution Division Maintenance Manual : Underground Cable System 2007

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Acknowledgement

We would like to express our deepest gratitude to TNB Distribution Division especially to Mr. Halim Osman, Chief Engineer, TNB Distribution Engineering Services for giving us the opportunity to develop TNB Distribution Division Maintenance Manual: Underground Cable System. Acknowledgement also goes to Muhammad Azizi Abdul Rahman and Jazimah Abd Majeed for their valuable contribution and assistance in developing this manual.

The project team would also like to express its highest gratitude to the TNBR Management team for their supports starting from the initiation until its completion as well as the various groups/units in TNBR especially to IT for their support in developing this manual.

Our deepest expression also to Dr. Prodipto Sankar Ghosh, RUP Consultant Plus Inc. (M) Sdn. Bhd for his guidance, patience, support and encouragement towards the successful completion of this manual development.

Special thanks to Huzainie Shafi Abd Halim, Radzlan Hisham Mohd Arifin and Zairul Aida Abu Zarim for their valuable contribution and support towards the smooth execution of this manual development.

Lastly we would like to extent our indebtedness to ILSAS whose valuable input has been a great help for the successful development of this manual.

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I. Purpose of the Manual

This manual outlines sets of recommended maintenance practices for underground cable system and to be used as a reference in the execution of related maintenance tasks by in-house of external service providers. Analysis of test results or interpretation, decision criteria and recommendations are generally based on available industry standards and experiences of subject matter experts (SME) in TNB Distribution. However, owing to unique equipment system design and characteristics, failure modes and performance as experienced by TNB Distribution, expert judgments must be exercised when finally applying these recommendations. In this respect, there is also a need to refer to other related documents namely manufacturers recommendations and other documented evidences related to operational historical performance of specific equipment as additional inputs to the decision-making process.

II. Scope and Validity

This manual covers full scope of maintenance, testing and diagnostics tasks for MV and LV underground cable system at three critical stages of the asset life namely: commissioning, in –service and re-commissioning after failure. Although the motivation in the development of this manual is more for the standardization of advanced diagnostic testing related to condition-based maintenance, the more routine inspections and maintenance tasks are also included for completeness and to ensure further standardization of these maintenance tasks.

The contents, or parts thereof, of the manual shall remain valid until such time further revision is made. The custodian of this Manual is Engineering Services, Engineering Department, and TNB Distribution.

III. Relevant Standards and References

Users of this Manual are advised to refer to the following set of standards and references so as to acquire more in-depth understanding of the relevant standards being quoted in this Manual and related subject matter. 1. IEEE 400-1991 – IEEE Guide for Making High Direct Voltage Tests on Owner Cable

Systems in the Field 2. IEEE 400.2 – 2004 – IEEE Guide for Field Testing of Shielded Power Cable Systems

Using Very Low Frequency (VLF) 3. IEEE 400 – 2001 – IEEE Guide for Field Testing and Evaluation of the Insulation of

Shielded Power Cable Systems 4. IEEE STD 1425 – 2001 IEEE Guide for the Evaluation of the Remaining Life of

Impregnated Paper Insulated Transmission Cable Systems 5. IEEE NO.83 -1963 – Radial Power Factor Tests on Insulating Tapes in Paper Insulated

Power Cable 6. Condition Assessment of Power Cables using Partial Discharge Diagnostic at Damped

AC Voltages – Frank Westler, SEBA KMT 7. Electric Cables Handbook, third edition – G.F. Moore BICC Cables 8. Electrical Power Equipment Maintenance and Testing - Paul Gill, Marcel Dekker Inc. 9. Tan Delta Cable Testing: Overview and Frequently Asked Questions – High Voltage Inc. 10. Condition Monitoring using Partial Discharge Method on Cable Mapping – Final Report

TNBR - Huzainie Shafi, John Foo, 2002.

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List of Abbreviations A Ampere AC Alternating Current AM Ampere Meter ASTM American Society for Testing and Materials BS British Standard CBM Condition Based Maintenance CM Condition Monitoring CMMS Computerised Maintenance Management System CRO Cathode Ray Oscilloscope CTC Critical Technology Challenges CTCs Critical Technological Challenges DC Direct Current DGA Dissolve Gas Analysis DS Dielectric Spectroscopy emf Electro Magnetic Field EPDM Ethylene Propylene Diane Monomer ERMS Enterprise Resource Management System F Farad FMECA Failure Mode Effect And Criticality Analysis GIS Geographical Information System HV High Voltage HVDC High Voltage Direct Current Hz Hertz IEC International Electrotechnical Commission IEEE Institute of Electrical Electronic Engineer IR Insulation Resistance km kilometre kV Kilo Volt LGB Laporan Gangguan Bekalan LV Low Voltage MIL-STD United States America Military Standard MTBF Mean Time Between Failures MV Medium Voltage NASA National Aeronautics and Space Administration nC Nano Coulomb O&M Operation and Maintenance O/C Open Circuit OWTS Oscillating Wave Testing System pC Pico Coulomb PD Partial Discharge PDEV Partial Discharge Extinction Voltage PDIV Partial Discharge Inception Voltage PE Polyethylene PILC Paper Insulated Lead Cable

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PM Preventive Maintenance PRN Probability Risk Number PT&I Predictive Testing And Inspection PVC Poly Vinyl Chloride RCM Reliability Centred Maintenance RPN Risk Priority Number SCADA Supervisory Control And Data Acquisition SF6 Sulphuric Hexafluoride TDR Time Domain Reflectrometry UG Underground VLF Very Low Frequency VM Volt Meter XLPE Cross Linked Polyethylene

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Table of Contents Acknowledgement ii

I. Purpose of the Manual iii

II. Date Completed and Period Covered iii

III. Recommended Standards and References iii

List of Abbreviations iv

Table of Contents vi

List of Figures and Tables x

1 Introduction......................................................................................................................13

1.1 Background ...............................................................................................................13

1.2 Maintenance Practice in United States Bureau of Reclamation, Denver, Colorado .15

1.2.1 Power Cables .....................................................................................................16

1.2.2 Circuit Breakers .................................................................................................16

1.2.3 Transformers ......................................................................................................16

1.3 Maintenance Practice in NASA ................................................................................17

1.3.1 Transformers ......................................................................................................19

1.3.2 Circuit Breakers and Switchgear .......................................................................19

1.4 TNB Distribution Division’s journey toward Best Maintenance Practice................21

2 Maintenance Management ...............................................................................................24

2.1 Background ...............................................................................................................24

2.2 Failure Patterns..........................................................................................................24

2.3 Maintenance Techniques...........................................................................................26

2.3.1 Reactive Maintenance........................................................................................27

2.3.2 Preventive or Calendar Based Maintenance ......................................................27

2.3.3 Predictive or Condition Based Maintenance......................................................28

2.3.4 Proactive Maintenance.......................................................................................28

2.4 Failure Modes, Effects and Criticality Analysis (FMECA)......................................29

2.4.1 Types of FMECA...............................................................................................30

2.4.2 Standards Related to FMECA............................................................................30

2.4.3 Prerequisites of FMECA....................................................................................30

2.4.4 Preparation of FMECA......................................................................................30

2.4.5 Limitations of FMECA......................................................................................32

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2.5 Frequency or Periodicity of Condition Based Maintenance Task.............................32

3 Cable Asset Category.......................................................................................................36

3.1 Categorization of Underground Cable and its Accessories in TNB Distribution Division System...................................................................................................................36

3.2 Construction of Cables and its Accessories ..............................................................38

3.2.1 XLPE Cable .......................................................................................................38

3.2.2 PILC Cable.........................................................................................................40

3.2.3 LV Cable............................................................................................................41

3.2.4 Joint....................................................................................................................43

3.2.5 Termination........................................................................................................44

3.2.6 Electrical Stresses in Joints and Terminations...................................................44

3.3 Severity, Probability and Detectability Ranking used in FMECA Exercise.............46

3.4 Failure Modes, Effects and Criticality Analysis (FMECA) for MV Cables.............47

3.5 Failure Modes, Effects and Criticality Analysis (FMECA) for MV Joints and Terminations ........................................................................................................................50

4 Cable Maintenance Testing..............................................................................................55

4.1 Background ...............................................................................................................55

4.2 Maintenance Matrix ..................................................................................................55 4.3 General Description of Identified On-Site Testing for Assessing the Integrity of Insulation..............................................................................................................................57

4.3.1 Non-Destructive/Diagnostic Test.......................................................................57

4.4 General Description of Identified On-Site Testing for Assessing the Integrity of Current Carrying Paths (Conductors, connectors and earthing shields) ..............................69

4.4.1 Contact Resistance Measurement of Joints and Terminations ..........................69

4.4.2 Continuity of Phase Conductor and Metallic Sheath.........................................69

4.5 Soaking Test..............................................................................................................70

5 Cable Maintenance Testing Procedure ............................................................................72

5.1 Background ...............................................................................................................72

5.2 Testing Equipment Specification ..............................................................................72

5.2.1 Testing Equipment Calibration ..........................................................................74

5.3 Commissioning, In-service and After Repair Maintenance Guidelines....................75

5.3.1 Commissioning Testing Guideline for Low Voltage Cables.............................75

5.3.2 In-service Maintenance Testing Guideline for Low Voltage Cables.................75

5.3.3 After Repair Testing Guideline for Low Voltage Cables ..................................76

5.3.4 Commissioning Testing Guideline for Medium Voltage XLPE Cable .............77

5.3.5 In-service Maintenance Testing Guideline for Medium Voltage XLPE Cable.78

5.3.6 After Repair Testing Guideline for Medium Voltage XLPE Cable ..................79

5.3.7 Commissioning Testing Guideline for Medium Voltage PILC Cable...............80

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5.3.8 In-service Maintenance Testing Guideline for Medium Voltage PILC Cable ..81

5.3.9 After Repair Testing Guideline for Medium Voltage PILC Cable....................82

5.4 Testing Procedure for Insulation Integrity ................................................................82

5.4.1 Tan Delta Test for MV Cables...........................................................................82

5.4.2 VLF Partial Discharge Mapping System ...........................................................85

5.4.3 Oscillating Wave Test System (OWTS) For PD Mapping & Tan-Delta...........87

5.4.4 Dielectric Spectroscopy .....................................................................................89

5.4.5 Insulation Resistance (IR) Testing Procedure....................................................92

5.5 Sheath Integrity Test .................................................................................................93 5.6 Testing Procedure for Current Carrying Path (Phase Conductors, connectors and earthing shields) ...................................................................................................................94

5.6.1 Contact Resistance for Joints and Terminations................................................94

5.6.2 Continuity Test for Metallic Sheath...................................................................95

5.6.3 Thermography Survey for Exposed Termination ..............................................96

5.7 Fault Location ...........................................................................................................97

5.7.1 Cable Fault Location..........................................................................................97

5.7.2 Sheath Fault Locator ..........................................................................................99

5.8 Test Sheet Templates ..............................................................................................102

5.8.1 LV Cables Inspection and Test Data Sheet......................................................103

5.8.2 MV XLPE Cables Inspection and Test Data Sheet .........................................105

5.8.3 MV PILC Cables Inspection and Test Data Sheet...........................................109

6 Cable Maintenance Testing Results’ Interpretation.......................................................113

6.1 Background .............................................................................................................113

6.2 Condition and Data Quality Indicators and Cable Condition Index........................113

6.3 Scoring ....................................................................................................................114

6.4 Weighting Factors ...................................................................................................114

6.5 Mitigating Factors ...................................................................................................114

6.6 Documentation ........................................................................................................115

6.7 Condition Assessment Methodology ......................................................................115

6.8 Tier 1 Condition Indicators of MV XLPE and PILC Cables ..................................117

6.8.1 Contact Resistance ...........................................................................................117

6.8.2 Cable Condition Indicator 1 – Thermography.................................................117

6.8.3 Cable Condition Indicator 2 – Tan Delta Test .................................................118

6.8.4 Cable Condition Indicator 3 – Insulation resistance test .................................119

6.8.5 Cable Condition Indicator 4 – Operation and Maintenance Performance.......120

6.8.6 Cable Condition Indicator 5 – Age ..................................................................120

6.8.7 Tier 1 - Cable Condition Index Calculations ...................................................121

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6.8.8 Tier 1 – Cable Data Quality Indicator..............................................................122

6.9 Tier 2 – Tests and Measurements of MV XLPE and PILC Cables.........................123

6.9.1 Partial Discharge Test ......................................................................................124

6.9.2 Dielectric Spectroscopy Test ...........................................................................125

6.9.3 Tier 2 – Total Cable Condition Index Calculations .........................................126

6.10 Combined Tier 1 and Tier 2 Cable Condition-Based Alternatives .........................127

7 Record Management of Cable Maintenance Testing Results ........................................129

7.1 Background .............................................................................................................129

7.2 Flow Chart for Record Management of Raw Waveform and Processed Data........129

7.3 Record Management of Raw Waveform and Processed Data of VLF PD .............131

7.4 Record Management of Raw Waveform and Processed Data of OWTS PD..........132

7.5 Record Management of Raw Waveform and Processed Data of DS......................136

7.5.1 XLPE................................................................................................................136

7.5.2 PILC.................................................................................................................138

7.6 Record Management of Raw Waveform and Processed Data of Thermography ...140

7.7 Record Management of IR and Tan Delta ..............................................................142

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List of Figures and Tables Figure 2.1 Growing Expectation of Maintenance....................................................................24 Figure 2.2 Probability of Failure with Age..............................................................................25 Figure 2.3 Failure Patterns.......................................................................................................26 Figure 2.4 Schematic Representation of Proactive Maintenance ............................................29 Figure 2.5 P-F Curve................................................................................................................33 Figure 2.6 P-F Interval.............................................................................................................33 Figure 2.7 Periodicity of Condition Based Maintenance.........................................................34 Figure 3.1 Construction of single core XLPE cable ................................................................39 Figure 3.2 Construction of three core XLPE cable..................................................................39 Figure 3.3 Construction of triplex XLPE cable .......................................................................40 Figure 3.4 Construction of PILC cable ....................................................................................41 Figure 3.5 Construction of PVC LV cable...............................................................................42 Figure 3.6 Construction of XLPE LV cable ............................................................................42 Figure 3.7 Construction of Premoulded type Joint .................................................................43 Figure 3.8 Types of connectors (a) mechanical (b) crimped ...................................................43 Figure 3.9 Construction of Termination ..................................................................................44 Figure 3.10 Electrical Stress at End of Cable Semi-Conductive Screen .................................45 Figure 3.11 Geometric Stress Control .....................................................................................45 Figure 3.12 High Dielectric Constant Stress Control ..............................................................45 Figure 4.1 Electric circuit of insulation under dc voltage test .................................................57 Figure 4.2 Insulation Current Characteristics ..........................................................................59 Figure 4.3 Representation of Cable .........................................................................................61 Figure 4.4 Comparison between new and old cable ................................................................62 Figure 4.5 Tangent delta in frequency sweep ..........................................................................63 Figure 4.6 Comparison between new and old cable under dielectric spectroscopy ................63 Figure 4.7 Equivalent circuit diagram of cable insulation with voids .....................................65 Figure 4.8 Occurrences of internal discharges.........................................................................66 Figure 4.9 PD Test Setup .........................................................................................................67 Figure 4.10 PD Pulse Generation in Cables.............................................................................67 Figure 4.11 PD Pulse Characteristic in Cables ........................................................................68 Figure 4.12 Contact Resistance Test Setup..............................................................................69 Figure 5.1 Connection between Analyzer and PILC Cable.....................................................83 Figure 5.2 Connection between HV Unit, Analyzer and XLPE Cable....................................85 Figure 5.3 Schematic of Test Circuit .......................................................................................87 Figure 5.4 Schematic of Test Circuit .......................................................................................89 Figure 5.5 Connection between Analyzer and PILC Cable.....................................................90 Figure 5.6 Connection between Analyzer, HV Unit and XLPE Cable....................................91 Figure 5.7 Connection of IR Testing Equipment.....................................................................93 Figure 5.8 Test set up for Sheath Integrity Test.......................................................................94 Figure 5.9 Connection of Test Leads to Cable Joint................................................................95 Figure 5.10 Shock wave discharge ..........................................................................................98 Figure 5.11 Fault Location Procedure Flowchart ....................................................................99 Figure 5.12 Sheath fault pre-location by the voltage drop method........................................100 Figure 5.13 Sheath fault location with DC voltage................................................................101 Figure 6.1 Flowchart for Calculating Cable Condition Index ...............................................116 Figure 7.1 Flow Chart of Raw Waveform and Processed Data.............................................130 Figure 7.2 Raw Waveform of PD VLF..................................................................................131

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Figure 7.3 Processed Data (PD Mapping) of PD VLF ..........................................................132 Figure 7.4 Raw Waveform of OWTS PD..............................................................................133 Figure 7.5 Raw Waveform of OWTS PD..............................................................................134 Figure 7.6 Processed Data (PD Mapping) of OWTS PD.......................................................135 Figure 7.7 Processed Data (Histogram) of OWTS PD ..........................................................135 Figure 7.8 Raw Waveform (Good Response) of XLPE DS ..................................................136 Figure 7.9 Raw Waveform (Non Deteriorated Response) of XLPE DS ...............................137 Figure 7.10 Raw Waveform (Voltage Dependent Response) of XLPE DS ..........................137 Figure 7.11 Raw Waveform (Leakage Current Response) of XLPE DS ..............................138 Figure 7.12 Raw Waveform of PILC DS...............................................................................139 Figure 7.13 Processed Data (Moisture Content) of PILC DS................................................140 Figure 7.14 Raw Waveform of Thermography......................................................................141 Figure 7.15 Processed Data of Thermography ......................................................................141 Table 1.1 Criticality Ranking...................................................................................................17 Table 1.2 Sample Maintenance Approach Table.....................................................................18 Table 3.1 Types of Underground Cables and its Accessories .................................................36 Table 3.2 Cable components and their function ......................................................................38 Table 3.3 Failure Severity Ranking and Definition .................................................................46 Table 3.4 Failure Probability Ranking and Definition.............................................................46 Table 3.5 Failure Detectability Ranking and Definition..........................................................47 Table 3.6 FMECA for MV Cables...........................................................................................48 Table 3.7 FMECA for MV Joints ............................................................................................51 Table 3.8 FMECA for MV Terminations ................................................................................52 Table 4.1 Cable Maintenance Matrix.......................................................................................56 Table 5.1 MV XLPE Cable for Insulation Integrity Test ........................................................72 Table 5.2 MV PILC Cable for Insulation Integrity Test..........................................................73 Table 5.3 LV Cable for Insulation Integrity Test ....................................................................73 Table 5.4 MV XLPE Cable for Sheath Integrity Test .............................................................73 Table 5.5 MV XLPE, MV PILC & LV for Integrity of Connections......................................73 Table 6.1 Contact Resistance.................................................................................................117 Table 6.2 Thermography........................................................................................................117 Table 6.3 Tan delta ................................................................................................................118 Table 6.4 Insulation resistance...............................................................................................119 Table 6.5 Operation and Maintenance Performance Scoring ................................................120 Table 6.6 Age Scoring ...........................................................................................................121 Table 6.7 Tier 1 Cable Condition Index ................................................................................121 Table 6.8 Cable Data Quality Indicator Scoring....................................................................122 Table 6.9 Final Tier 1 Cable Condition Index Value.............................................................122 Table 6.10 Cable Tier 1 Condition-Based Alternatives.........................................................123 Table 6.11 Partial Discharge Test Score Adjustment ............................................................124 Table 6.12 Dielectric Spectroscopy Test Score Adjustment .................................................125 Table 6.13 Total Cable Condition Index Value .....................................................................126 Table 6.14 Cable Condition Based Alternatives....................................................................127 Table 7.1 Processed Data of XLPE DS .................................................................................138

Chapter 1 Chapter 1

Introduction Introduction

1 Introduction

1.1 Background Electrical distribution equipment is generally designed for a certain economic service life. Equipment life is dependent on operating environment, maintenance program and the quality of the original manufacture and installation. Beyond this service life period they are not expected to render their services up to expectation with desired efficiency. However, certain equipments are found to operate satisfactorily even after the expected economic life span which may be attributed to good site conditions and good maintenance. However, generally due to poor quality of raw material, workmanship and manufacturing techniques or due to frequent system faults, over loading, environmental effect, unexpected voltage swings and over voltage stresses on the system during the operation, many equipment fail much earlier than their expected economic life span. Moreover, due to the above cited reasons, the failure of vital equipment has become a regular feature and the high rate of failure has become a cause of concern for electrical utilities. The concept of simple replacement of power equipments in the system either before or after their economic service life, considering it as weak or a potential source of trouble, is no more valid in the present scenario of financial constraints. Today the paradigm has changed and efforts are being directed to explore new approaches/techniques of monitoring, diagnosis, life assessment and condition evaluation, and possibility of extending the life of existing assets (i.e. circuit breaker, cables, oil filled equipment like transformers, load tap changer etc., which constitute a significant portion of assets for distribution system). Minimization of the service life cycle cost is one of the stated tasks of the electrical power system engineers. For electrical utilities this implies for example to fulfill requirements from customers and authorities on reliability in power supply at a minimal total cost. The main goal is therefore to reach a cost effective solution using available resources which is captured by the concept of Asset Management. Maintenance is one of the areas where higher effectiveness is sought for, and utilities are implementing new strategies for maintenance and management of assets. The pressure to reduce operational and maintenance costs is already being felt and the concept of Preventive Maintenance is undergoing change. In practice, the traditional understanding of maintenance is to "fix it when it breaks". This is a good definition for repair, but not maintenance. This style of maintenance is reactive. In modern and forward thinking utilities, it has been realized that proactive, rather than reactive maintenance management brings the best results. Adopting a proactive approach to maintenance will improve maintenance effectiveness dramatically within the confines of the

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organizational and cultural environment of an existing, predominantly reactive maintenance program. Most equipment require regular and effective maintenance to operate correctly and meet their design specifications. The consequences of ineffective equipment maintenance can be huge in terms of system reliability indices, revenue loss and organizational image. Therefore, the importance of effective maintenance through condition monitoring of electrical equipment in the system is gaining importance to reduce the occurrence of such incidents. Assessing the condition and thereby reducing failures of equipment is a key to improving reliability and also effectively extending the life of equipment. Hence utilities are continuously in search of best maintenance practices other than traditional methods/techniques to assess the condition of equipment in service so that remedial measures can be taken in advance to avoid disastrous consequences thereby saving lot of valuable resources. The potential cost savings of Best Maintenance Practices can often be beyond the understanding or comprehension of management. Unfortunately, in some people's minds, the words "Best Practices" evoke some difficulty to understand, ever-changing and unachievable goal towards which they are supposed to focus without hope of ever attaining. "Best Maintenance Practices in Power Utilities" can be benchmarking standards, which are real, specific, achievable and proven standards for maintenance management and by adopting this will make any maintenance department more efficient to reduce operating and maintenance costs, improve reliability, and increase morale. Best Maintenance Practices comprise of standards and methods. Standards are the measurable performance levels of maintenance execution and methods and strategies are procedures that must be practiced in order to meet the standards. Overall, the combination of standards, and methods and strategies are elements of a Planned Maintenance Management system. This manual will introduce you to "Best Maintenance Practices in Power Utilities", define the standards and show you how to set target and reach the performance levels of Best Maintenance Practices. It will also provide you with detailed study on failure modes, criticality assessment, strategies and actions to be taken, maintenance procedures and analyses needed to execute Best Maintenance Practices. It has been shown that when maintenance is planned and scheduled, a twenty-five person maintenance force operating with proactive planning and maintenance scheduling can deliver the equivalent amount of work of a maintenance team of forty persons working in a reactive maintenance organization. A CMMS is critical to an organized, efficient transition to a proactive maintenance approach. The types of reports and data tracking that can be obtained from CMMS are work orders and all kinds of reports. A final item to consider when incorporating Best Maintenance Practices is integrating the use of contractors into the maintenance activity of the organization and following the same format of information/data to be collected and entered into CMMS.


The process of transition from a reactive maintenance organization to a totally proactive structure is not an overnight project. It will take time, effort and planning to accomplish. The transition requires commitment from all levels of the organization.

1.2 Maintenance Practice in United States Bureau of Reclamation, Denver, Colorado

Bureau of Reclamation has developed a document on their maintenance practices on electrical equipment owned and operated by them. Maintenance recommendations are based on industry standards and experience in Reclamation facilities. However, equipment and situations vary greatly, so Reclamation suggests other sources of information to be consulted (e.g., manufacturer’s recommendations, unusual operating conditions, personal experience with the equipment, etc.) in conjunction with these maintenance recommendations. Reclamation follows Preventive Maintenance (PM) practice of maintaining equipment on a regular schedule based on elapsed time or meter readings. The intent of PM is to “prevent” maintenance problems or failures before they take place by following routine and comprehensive maintenance procedures. The goal of Reclamation is to achieve fewer, shorter, and more predictable outages focused on the most important equipment. Reclamation categorized electrical maintenance activities into three types: Routine Maintenance – Activities that are conducted while equipment and systems are in service. These activities are predictable and can be scheduled and budgeted. Generally, these are the activities scheduled on a time-based or meter-based schedule derived from preventive or predictive maintenance strategies. Some examples are visual inspections, infrared scans, cleaning, functional tests, measurement of operating quantities, lubrication, oil tests, governor, and excitation system alignments. Maintenance Testing – Activities that involve the use of testing equipment to assess condition in an off-line state. These activities are predictable and can be scheduled and budgeted. They may be scheduled on a time or meter basis but may be planned to coincide with scheduled equipment outages. Since these activities are predictable, some offices consider them “routine maintenance” or “preventive maintenance.” Some examples are Doble testing, insulation resitance testing, relay testing, circuit breaker trip testing, alternating current (AC) hipot tests, high-voltage direct current (HVDC) ramp tests, battery load tests. Diagnostic Testing -Activities that involve use of testing equipment to assess condition of equipment after unusual events such as faults, fires, or equipment failure/repair/replacement or when equipment deterioration is suspected. These activities are not predictable and cannot be scheduled because they are required after a forced outage. Each office must budget for these events. Some examples are Doble testing, AC hipot tests, HVDC ramp tests, partial


discharge measurement, wedge tightness, core magnetization tests, pole drop tests, turns ratio, and core earth. Failure analysis studies complemented by industry standards and the preventive maintenance schedule practiced by Reclamation on their primary equipment are presented below.

1.2.1 Power Cables The cables used are either solid dielectric or oil-filled. In the case of critical circuits, periodic maintenance tests are justified during the life of the cable to determine whether or not there has been significant insulation deterioration due to operational or environmental conditions. Cables are tested in accordance with manufacturer’s recommendations and industry standards. When done properly, maintenance tests can detect cables that are approaching failure without accelerating the deterioration process. Direct current (DC) high potential tests effectively reduce in-service failures from faults of the cable or its accessories. Periodic direct-current maintenance tests are not practiced for XLPE cables. Except for infrared scanning, the cable circuit is de-energized before maintenance. For Oil filled cables oil analysis including DGA are done annually. Refer Appendix 1.1 for details of maintenance schedule for power cables.

1.2.2 Circuit Breakers Most breaker maintenance except infrared scanning are performed with equipment de-energized. Breakers are tested in accordance with manufacturer’s recommendations and industry standards. Contact resistance and motion analyzer tests are highly recommended for in-service breakers on a regular basis to monitor condition of the operating mechanism. Power factor and ac high potential tests with contacts open are also practiced but with lesser frequency. Moisture tests on gas in SF6 gas breakers are also done periodically. Meters and gauges are calibrated annually. Manufacturer’s instructions are strictly followed in performing ac high potential test on vacuum bottle to avoid X-radiation. Overhauling of breakers with new seals and contacts are done based on number of operations, load and timing analyzers information and/or guidelines. Refer Appendix 1.1 for details of maintenance schedule for vacuum and SF6 breaker.

1.2.3 Transformers Transformers are tested in accordance with manufacturer’s recommendations and industry standards. Bushings are tested based on Doble Guideline and the periodicity of test is adjusted depending on the condition. Annual infrared scanning for bushing is also practiced. Based on DGA results several electrical tests for the main windings and core earthing are recommended as per industry standards. Cooling accessories are also tested periodically for condition assessment. Pressure relief device and gas relays are also included in their


preventive maintenance schedule. Tap changer failure has been identified as one of the dominant failure modes and its maintenance schedule has also received prime importance. Refer Appendix 1.1 for details of maintenance schedule for oil-filled power transformers.

1.3 Maintenance Practice in NASA NASA Center has developed a guide to perform preventive maintenance tasks for facilities systems and sets initial Predictive Testing and Inspection (PT&I) alarm limits. In their journey of RCM they felt the necessity of the understanding of the selected machine's failure modes and the consequences of that failure. The maintenance approach followed by NASA is based upon identifying, mitigating, and/or preventing failure. For each equipment category the most common (the dominant) failure modes of the item with the highest probability of occurring are being identified. In addition to the failure mode NASA has also considered the consequence of failure. Table 1.1 provides the method used to rank system criticality based upon the consequences of failure. For the lowest ranked systems (identified as Rank Number 1 on Table 1.1), a run-to-failure approach is often used. And in the highest ranked systems (Ranking Number 5), a redesign effort is usually undertaken to shift the consequence of failure to a lower rank. The recommended strategy identified in the table is adjusted based upon stressful operating conditions and system redundancies.

Table 1.1 Criticality Ranking

Ranking Effect Consequence

1 Negligible The loss of function will be so minor that it would have no discernible effect on the facility or its operations.

2 Minimal

The loss will cause minimal curtailment of operations or may require minimal monetary investment to restore full operations. Normal contingency planning would cover the loss.

3 Marginal

The loss will have noticeable impact on the facility. It may have to suspend some operations briefly. Some monetary investments may be necessary to restore full operations. May cause minor personal injury.

4 Critical

Will cause personal injury or substantial economic damage. Loss would not be disastrous, but the facility would have to suspend at least part of its operations immediately and temporarily. Reopening the facility would require significant monetary investments.


Ranking Effect Consequence

5 Catastrophic

Will produce death or multiple death or injuries, or the impact on operations will be disastrous, resulting in long-term or permanent closing of the facility. The facility would cease to operate immediately after the event occurred.

NASA Reliability-Centered Maintenance Guide provides Predictive Testing and Inspection (PT&I) schedule including sample procedures. To determine the most effective intervals for maintenance tasks NASA follows age related maintenance actions in order to reduce the cost of unnecessary and/or ineffective maintenance. PT&I monitoring intervals are set in order to determine the onset of failure and to take an action before the failure occurs. According to NASA like all time/cycle tasks, if the interval is too short, there will be wasted effort (labor and material) and if the interval is too long, failures will occur. For each equipment category NASA has developed a table that identifies the maintenance approach for the Equipment Items within the category. The table includes the Equipment Item, the applicable procedures, and three Periodicity Codes. The Periodicity Codes are provided to assist the NASA Centers in determining how often to perform the maintenance task based upon the consequences of failure.

Table 1.2 Sample Maintenance Approach Table

Procedure Periodicity

By Criticality Rank Equipment Item

Number Description 2 3 4

Brkr-02 Inspect and Test Vacuum or Oil Filled Circuit Breaker

3A 3A A

PT&I-05 Test Insulation 3A 3A A

Medium Voltage Circuit Breaker, Vacuum

PT&I-08 Power Factor Test 3A 3A A

Brkr-03 Inspect and Test SF6 Circuit Breaker

3A 3A A Medium Voltage Circuit Breaker, SF6

PT&I-05 Test Insulation 3A 3A A


Periodicity Codes The Periodicity Codes used by NASA are described below: D = Daily W = Weekly M = Monthly Q = Quarterly S = Semi-Annually A = Annually OC = On Condition: usually based upon results of a Predictive Testing and Inspection (PT&I)

test Multiples of the above are sometimes used and are identified by a number followed by a letter. For example, 5A indicates a procedure is scheduled every 5 years. Maintenance schedule for transformers and circuit breakers practiced by NASA is presented here as sample.

1.3.1 Transformers Transformer dominant failure modes identified by NASA are deterioration of the electrical insulation, deterioration of the electrical connections, and exterior corrosion. Over time, heat generated internally slowly breaks down the paper insulation in all types of transformers. For oil filled transformers, the oil insulation system also deteriorates, also due to heat. In dry type units, moisture contamination contributes to the insulation deterioration. Repeated heating and cooling cycling can loosen connections, both internal (tap connections, winding termination points) and external (bushing connections). Harsh ambient conditions can corrode transformer tanks, cooling fins, and attached accessories such as control panels and conservator tanks. Most of the above failure modes progress slowly over time. Consequently go/no-go tests such as turns-ratio testing are ineffective at finding failure patterns. Trending test data is necessary to identify these failure patterns. The maintenance approach for transformers therefore focuses on using applicable PT&I technologies such as infrared thermography, oil testing and insulation power factor testing. The periodicity of condition monitoring tasks according to criticality ranking for all types of distribution transformers are detailed in Appendix 1.2.

1.3.2 Circuit Breakers and Switchgear

Circuit breakers used in NASA are as follows:

• Moulded Case – a sealed breaker with self-contained tripping and overload mechanisms.

• Oil Filled – mineral oil is the primary insulating medium. Normally medium and high voltage range.


• Vacuum – a ceramic cylinder contains the operating contacts. The insulating medium is a lack of air in the bottle, which allows for close contacts. This type of breaker is normally only used for medium voltage systems.

• Sulfur Hexafluoride (SF6) – SF6 is used as the insulating medium. Operating voltage can

be as high as 500 kV rated. Dominant failure modes for circuit breakers identified by NASA are binding in the operating mechanism, control circuitry failure, development of high resistance in the power connections, exterior corrosion, and deterioration of the electrical insulation. Of these failure modes, binding operating mechanism and control circuitry failure are the most common, resulting in a circuit breaker that will not open or close as required. For oil filled breakers the oil system also deteriorates due to repeated operations, and for SF6 breakers (SF6 gas is the insulating medium) leaks in the SF6 containment is a dominant failure mode. It should be noted in the periodicity section of the table in Appendix 1.2 that some breakers have recommended maintenance frequencies of no longer than three years, and only low voltage molded case breakers should be run to failure. The limiting factors for these determinations are both cost and reliability. Medium and high voltage units (especially SF6 and air breakers) also benefit from maintenance cycles of three years or less. The periodicity of condition monitoring tasks according to criticality ranking for all types of breakers is detailed in Appendix 1.2. Dominant failure modes for switchgear identified by NASA are high resistance at mechanical connections, control relay failure, and corrosion for units installed outdoors or in harsh environments. Additional failure modes that cause operational difficulties include racking mechanism failure (not allowing a breaker to be racked in/out) and shutter assembly/insulation barrier failure (which would not allow a breaker to be racked in or leave energized bus connection uncovered). Typically the bar made from copper bar stock is bent into specific angles and various lengths to fit the configuration of the switchgear. A failure at one of the mechanical connections normally results in a bus bar that becomes greatly distorted and not able to be reused. Replacement times depend on availability of the proper copper bar stock and then manufacturing it into the proper configuration. As a result the use of PT&I technologies, Infrared Thermography and Ultrasonic testing, become very important for long term reliability. The periodicity of condition monitoring tasks according to criticality ranking for all types of switchgears is detailed in Appendix 1.2.


1.4 TNB Distribution Division’s journey toward Best Maintenance Practice

The main themes for the TNB Electricity Technology Roadmap have been postulated as follows:

• Reliable and efficient delivery system • Intelligent power delivery systems • Value added electricity products and services • Enhance environmental management

Technology will play an important role to enable the improvements in reliability and operational efficiency on the existing electricity delivery infrastructure. The critical technological challenges (CTCs) during this period are described below:

• Improvement in operational efficiency • Application of modern maintenance techniques • Enhancement of grid system reliability • Improvement in quality of equipment, components, fuel, infrastructure and

systems design It therefore envisions that the following technologies can provide significant improvements to the operational efficiency of the power delivery systems:

• Condition-based monitoring and Risk-based Inspection of critical components • Basic SCADA for distribution systems • GIS-based network information systems and applications

The drive to enhance the utilization of utility assets requires significant improvements in maintenance techniques. In a highly competitive business environment, utilities are required to utilize their assets for longer periods, while reducing downtime or outages. One way in which this can be achieved is through the optimization of maintenance strategies. In the past, maintenance strategies have usually been dictated by the original equipment manufacturers to be time-based. These strategies are usually rather conservative. New sensing technologies have now enabled condition based monitoring and opened new dimensions in maintenance techniques and strategies. Data and information obtained from condition based monitoring can be analyzed for anomalies and trends. These analyses form the basis for predicting potential failures and scheduling maintenance strategies that would maximize on the operating hours, while minimizing failure. Therefore, the combination of sensing technologies together with information analyses and statistics provide the opportunity for what is called reliability centered maintenance. This technology allows for flexibility in maintenance strategies and allows utilities the ability to maximize the potential of their assets, while reducing unplanned outages and down times.


TNB Distribution Condition Based Maintenance (CBM) Program has been divided into following tasks:

I. Task 1: Maintenance assessment i. Review existing asset maintenance processes and work practices ii. Identify operation and maintenance cost improvement opportunities through

CBM application iii. Cite relevant industry’s best practices in CBM application

II. Task 2: Review existing asset management tools and systems

i. Assess sufficiency of data elements ii. Assess integration possibilities

of existing asset management tools (i.e.: ERMS, LGB, GIS)

III. Task 3: Develop CBM processes, methodologies and models i. Develop the CBM processes and methodologies ii. Conduct network risk and criticality analysis iii. Conduct equipment and network Failure Modes, Effects, and Criticality

Analysis (FMECA)

IV. Task 4: Define CBM implementation objectives, strategies and measures i. How to identify critical/high risk equipment to be prioritized ii. What CM technologies are relevant as identified through economic and risk

assessment iii. How to measure the cost effectiveness of the CBM strategies

V. Task 5: CBM network architecture, hardware and software

i. Define the architecture and functional specification of the computerized CBM system (CMMS)

ii. Identify interfacing possibilities with existing asset management system

VI. Task 6: Identify tangible benefits and evaluation measures related to CBM i. Define the tangible benefits of the CBM program (in terms of improved

system/component reliability and reduced/maintained operation and maintenance expenses)

ii. Specify the methodology to evaluate the effectiveness of the CBM program

VII.Task 7: CBM implementation master plan i. Conduct a pilot implementation of the master plan

VIII.Task 8: Propose implementation approach and work plan

i. Identify key activities, tasks, schedule and manpower requirements for implementing the TNB Distribution Division CBM Master Plan

TNB Distribution Division Maintenance Manual : Underground Cable System P a g e | 23___________________________________________________________________________ TNB Distribution Division Maintenance Manual : Underground Cable System P a g e | 23___________________________________________________________________________

Chapter 2 Chapter 2

Maintenance ManagementMaintenance Management

TNB Distribution Division Maintenance Manual : Underground Cable System P a g e | 24 ___________________________________________________________________________

2 Maintenance Management

2.1 Background With the increasing age of the population of assets, complex designs and changing expectations, organizations are making efforts to assess the internal condition of the equipment while in service before catastrophic failures can take place to ensure higher availability and reliability. Key challenges faced by maintenance engineers are as follows:

• To select the most appropriate techniques to deal with each type of failure process in order to fulfil all the expectations of the owners of the assets, the users of the assets and of society as a whole.

• In the most cost-effective and enduring fashion. • With the active support and co-operation of all the people involved.

At the wake of this avalanche of change, maintenance engineers are continuously in search for a new approach to maintenance that can be adopted to ensure that the physical asset will continue to do whatever its users want it to do in its present operating context and also strategies to maximise the life of the equipment at a minimal cost. Maintenance management is also responding to changing expectations. Since the 1930’s, the evolution of maintenance can be traced through three generations (shown in Figure 1) to capture growing expectations of the industries and more importantly maintenance engineers.

First Generation • Fix it when it is broken

Second Generation • Higher plant availability • Longer equipment life • Lower costs

Third Generation • Higher plant availability and reliability • Greater safety • Better product quality • No damage to the environment • Longer equipment life • Greater cost effectiveness

1940 1950 1960 1970 1980 1990 2000

Figure 2.1 Growing Expectation of Maintenance

2.2 Failure Patterns Traditional perception recommends that the best way to maximize the performance of assets is to overhaul or replace them at fixed intervals. This is based on the premise that there is a direct relationship between the amount of time equipment spends in service and the likelihood that it will fail, as shown in Figure 2.2, which suggests that most assets are


expected to operate reliably for a period "X", and then wear out. Traditional thinking suggests that X could be determined from historical failure records and manufacturer’s guidelines. This relationship between age and failure relationship is applicable for some failure modes that are typically associated with fatigue and corrosion.

Figure 2.2 Probability of Failure with Age

Today’s equipment is much more complex causing remarkable changes in equipment failure patterns. Figure 2.3 shows failure probability against age for a wide variety of assets. Pattern A is the well-known bathtub curve, and pattern B is the same as Figure 2.2. Pattern C shows slowly increasing failure probability with no specific wear out age. Pattern D shows low failure probability at start then a rapid increase to a constant level, while Pattern E shows a constant failure probability at all ages. Pattern F starts with high infant mortality and then drops to a constant or very slowly increasing failure probability.


Figure 2.3 Failure Patterns

2.3 Maintenance Techniques There has been tremendous growth in new maintenance concepts and techniques. They are broadly classified into following categories:

• Reactive maintenance • Preventative or Calendar based maintenance


• Predictive or Condition based maintenance • Proactive maintenance

2.3.1 Reactive Maintenance Corrective maintenance means fixing things either when they are found to be failing or when they have failed. It includes:

• Breakdown maintenance • Repair-when-fail • Run-to-failure

Strategy of reactive maintenance assumes that failure is equally likely to occur. Major downside of reactive maintenance is unexpected and unscheduled equipment downtime if failed or repair parts are not available. Both labour and materials are used inefficiently. Replacement parts are stocked at high levels which incurs high inventory cost.

2.3.2 Preventive or Calendar Based Maintenance Preventive maintenance usually means overhauling items or replacing components at fixed intervals. It includes activities like:

• scheduled inspection • adjusting alignments • cleaning and lubrication parts • replacement • calibration • repair of parts

The above tasks are performed at pre-defined intervals without regard to equipment condition or degree of use. It will reduce serious unplanned machine failure. The scheduled maintenance is based on MTBF (or failure rate). The major weakness is that in reality failures are equally likely to occur at random times and with a frequency unrelated to the average failure rate. Thus calendar-based maintenance can be costly and ineffective when it is the sole type of maintenance practiced. Although many ways have been proposed for determining the correct frequency of scheduled maintenance tasks, none are valid unless the in-service age-reliability (i.e. failure rate versus age) characteristics of the systems are known. To determine periodicity, the following techniques are recommended:

• Anticipating failure from experience • Failure distribution statistics • Conservative approach (due to lack of information)


2.3.3 Predictive or Condition Based Maintenance

Predictive or condition based tasks entail checking if something is failing. It includes: • Non-intrusive testing • Visual inspection • Operational data to assess machinery condition

To check whether something is failing the "failure-finding tasks" are carried out using various on-site testing methods. The data collected from on-site testing are called Condition Monitoring (CM) data. A few examples of CM data are:

• Flow rates • Temperature • Pressure • Electrical parameter • Ultrasonic testing • Vibration monitoring • Oil analysis • Optical sensing • Thermography

Usually FMECA is being practiced to identify condition monitoring techniques appropriate for different failure modes of equipment to assess their condition. The CM data are analysed using the following techniques to identify the precursors of failure:

• Trend analysis • Pattern recognition • Comparing tests results against specified limits • Statistical process analysis

Through trending or other predictive analysis methods, the maintenance interval is decided. For trending purposes a minimum of 3 monitoring points will be required before failure. CM does not give all types of equipment failure modes and therefore should not be the sole type of maintenance practiced.

2.3.4 Proactive Maintenance

This is the capstone of Reliability Centred Maintenance philosophy. It improves maintenance through better:

• Design • Installation • Maintenance procedures • Workmanship • Scheduling spare parts


It is characterised by an effective feedback system between the maintenance technician and design engineer. One must ensure that design mistakes made in the past are not repeated in future design. The equipment is viewed from life-cycle perspective. Constantly maintenance procedures are re-evaluated to find optimal mix. Its main objective is to extend machinery life and to obtain zero breakdown. The activities undertaken are schematically represented in Figure 2.4.

Figure 2.4 Schematic Representation of Proactive Maintenance

2.4 Failure Modes, Effects and Criticality Analysis (FMECA) Initially, the FMECA was called FMEA (Failure modes and effects analysis). The C in FMECA indicates that the criticality (or severity) of the various failure effects are considered and ranked. Today, FMEA is often used as a synonym for FMECA. These are methodologies designed to identify potential failure modes for an equipment or system, to assess the risk associated with those failure modes, to rank the issues in terms of importance and to identify and carry out corrective actions to address the most serious concerns. Failure modes, effects, and criticality analysis (FMECA) is a methodology to identify and analyze:

• All potential failure modes of the various components of a system • The effects these failures may have on the system • How to avoid and/or mitigate the effects of the failures on the system


FMECA is a very structured and reliable technique for failure analysis developed by the U.S. Military. FMECA is used during the early design phases to assist in selecting design alternatives with high reliability and high safety potential to ensure that all conceivable failure modes and their effects on operational success of the system have been considered. It also provides a basis for maintenance planning and provides a basis for quantitative reliability and availability analyses.

2.4.1 Types of FMECA FMECA are of three types:

• Design FMECA is carried out during equipment design phases to eliminate all conceivable failures that can happen during the whole life-span of the equipment.

• Process FMECA is focused on problems stemming from how the equipment is manufactured, maintained or operated.

• System FMECA looks for potential problems and bottlenecks in larger processes, such as entire production lines.

2.4.2 Standards Related to FMECA FMECA standards are:

• MIL-STD 1629 “Procedures for performing a failure mode and effect analysis” • IEC 60812 “Procedures for failure mode and effect analysis (FMEA)” • BS 5760-5 “Guide to failure modes, effects and criticality analysis (FMEA and

FMECA)”

2.4.3 Prerequisites of FMECA Prerequisites for FMECA studies are:

1. Defining the system to be analyzed and dividing it into manageable units called functional elements. 2. Collecting available information that describes the system to be analyzed; including drawings, specifications, schematics, component lists, interface information and functional descriptions. 3. Collecting information about previous and similar designs through interviews with design personnel, operations and maintenance personnel and component suppliers.

2.4.4 Preparation of FMECA FMECA worksheets (Appendix 2.1):


A suitable FMECA worksheet for the analysis has to be designed which can easily fit into the maintenance management system. A typical FMECA worksheet covering the most relevant columns is discussed below. Task No. Task Description1. In the first column a unique reference is assigned to a functional element. 2. The functions of the element are listed in the second column. Functions are also

categorized according to various operational modes for the element. 3. For each function of the element the potential failure modes are then identified and listed

in column three. Failure mode is defined as a functional failure or in other words a non fulfillment of the functional requirements of the functions specified in column 2.

4. The failure modes identified in column three are studied one-by-one. The failure mechanisms or causes that may contribute to a failure mode are identified and listed. Some failure modes are evident, others are hidden.

5. The effects each failure mode may have on other elements in the same subsystem (local effects) and/or on the system (global effects) are listed in column four. The resulting operational status of the system after the failure can be recorded, that is, whether the system is functioning or not, or is switched over to another operational mode.

6. In some cases consequences such as safety consequences, environmental consequences, operational consequences and economic consequences are also listed in separate columns in the worksheet.

7. The severity index rank corresponding to the failure mode is then assigned in column five. The severity classes and the ranks can be described in various ways. A typical example is shown below:

Rank Description 10 Catastrophic Failure results in major injury or death of personnel. 7-9 Critical Failure results in minor injury to personnel. 4-6 Major Failure results in a low level of exposure to personnel, or activates

alarm system. 1-3 Minor Failure results in minor system damage but does not cause injury to

personnel.

8. The likelihood that the failure will be detected is then listed in column six. An example of detectability ranking is given below:

Rank Description 1-2 Very high probability that the defect will be detected 3-4 High probability that the defect will be detected 5-7 Moderate probability that the defect will be detected 8-9 Low probability that the defect will be detected 10 Very low (or zero) probability that the defect will be detected

9. Failure rate or probability of failure for each failure mode is then listed in column seven.


An example of a classification is shown below:

Rank Description Very unlikely Once in 1000 years Remote Once in 100 years Occasional Once in 10 years Probable Once per year Frequent Once per month

More sophisticated numerical value of probability of failure can also be calculated and assigned using past record of failure data and using appropriate statistical modeling technique.

10. The various possibilities for detection of the identified failure modes are listed in column eight. These may involve on-line and off-line diagnostic testing and proof testing.

11. Possible actions to correct the failure and restore the function or prevent serious consequences are listed in column nine. Actions that are likely to reduce the frequency of the failure modes should also be recorded.

12. The risk related to the various failure modes is presented in column ten by Probability/Risk number (PRN). Sometimes it is called criticality assessment. A PRN is derived by assigning a numerical value to the frequency/probability of the failure mode and another value to the severity of the failure mode. More sophisticated PRN can be calculated by attaching different numerical weightings to different categories of failure consequences (safety, environmental, operational and economic). If historical failure rates and costs are available, these rankings can be refined using Pareto analysis.

Some methodology recommends computation of Risk Priority Numbers as shown below:

XXXXXRPN (risk priority number) = Fr x Cr x DetXXXXX

where, Fr = probability of occurrence, Cr = criticality or severity and Det = detectability

2.4.5 Limitations of FMECA In spite of being so popular FMECA also has downsides and they are:

• It is a tedious, time-consuming and expensive process • It is not suitable for multiple failures

2.5 Frequency or Periodicity of Condition Based Maintenance Task

Traditionally, the periodicity of condition based maintenance tasks used to be decided based on two factors; the frequency of the failure and/or severity of the failure. Sometimes these two are combined together and expressed as the criticality of the equipment. Recent studies


have shown that periodicity of condition based maintenance tasks should be based on more appropriate factor called failure period also known as the "P-F interval". Figure 2.5 illustrates this in the form of P-F curve, which shows how a failure starts and deteriorates to the point at which it can be detected (the potential failure point "P"). Thereafter, if it is not detected and suitable action taken, it continues to deteriorate - usually at an accelerating rate - until it reaches the point of functional failure ("F").

Figure 2.5 P-F Curve

The amount of time which elapses between the point where a potential failure occurs and the point where it deteriorates into a functional failure is known as the P-F interval, as shown in Figure 2.6. The P-F interval will vary with the failure modes.

Figure 2.6 P-F Interval

The P-F interval governs the periodicity with which the condition based maintenance tasks should be undertaken. The periodicity must be significantly less than the P-F interval if we


wish to detect the potential failure before it becomes a functional failure. Unless there is a good reason to do otherwise, it is usually sufficient to select a periodicity equal to half the P-F interval. If the P-F interval is too short for it to be practical to monitor for the potential failure, or if the nett P-F interval is too short for any sensible action to be taken once a potential failure is discovered, then the condition based task is not appropriate for the failure mode under consideration. For instance, Figure 2.7 shows how a P-F interval of 9 months and a periodicity of 1 month give a nett P-F interval of 8 months.

Figure 2.7 Periodicity of Condition Based Maintenance

Chapter 3 Chapter 3

Cable Asset Category

Cable Asset Category


3 Cable Asset Category

3.1 Categorization of Underground Cable and its Accessories in TNB Distribution Division System

The power cables have been subdivided into 4 voltage levels i.e. 33kV, 22kV, 11kV and 0.433 kV. Underground cables are further subdivided according to their insulation medium of various sizes and number of cores. The subdivision for joints is the same for underground cables. Assets that are critical to the system have been short-listed as per Table 3.1.

Table 3.1 Types of Underground Cables and its Accessories Category Types Size

630mm2 1 core Aluminium 300 mm2 1 core Copper 400 mm2 1 core Copper 500mm2 1 core Copper 630 mm2 1 core Copper 120 mm2 3 core Copper

33kV XLPE

185 mm2 3 core Copper 70 mm2 3core Aluminium 185 mm2 3core Aluminium PILC 400 mm2 3core Aluminium 70 mm2 1core Aluminium 150 mm2 1core Aluminium 240 mm2 1core Aluminium

22kV

XLPE

500 mm2 1core Aluminium 25 mm2 3core Aluminium 75 mm2 3core Aluminium 120 mm2 3core Aluminium 185 mm2 3core Aluminium

PILC

300 mm2 3core Aluminium 70 mm2 1 core Aluminium 500 mm2 1core Aluminium 95 mm2 Aluminium Triplex 150 mm2 Aluminium Triplex 240 mm2 Aluminium Triplex 95 mm2 3core Aluminium 150 mm2 3core Aluminium

Cables

11kV

XLPE

240 mm2 3core Aluminium


Category Types Size 300 mm2 1core Aluminium 500 mm2 1core Aluminium 500 mm2 1core Copper

PVC

630 mm2 1core Copper 25 mm2 4core Aluminium 70 mm2 4core Aluminium 120 mm2 4core Aluminium 185 mm2 4core Aluminium

XLPE

300 mm2 4core Aluminium 25 mm2 4core Aluminium 70 mm2 4core Aluminium 120 mm2 4core Aluminium 185 mm2 4core Aluminium

LV

PILC

300 mm2 4core Aluminium 630mm2 1 core Aluminium

33kV XLPE 500mm2 1 core Copper 70 mm2 3core Aluminium 185 mm2 3core Aluminium PILC 400 mm2 3core Aluminium 70 mm2 1core Aluminium 150 mm2 1core Aluminium 240 mm2 1core Aluminium

22kV

XLPE

500 mm2 1core Aluminium 120 mm2 3core Aluminium 185 mm2 3core Aluminium PILC 300 mm2 3core Aluminium 70 mm2 1 core Aluminium 500 mm2 1core Aluminium 240 mm2 Aluminium Triplex 95 mm2 3core Aluminium 150 mm2 3core Aluminium

Termination

11kV

XLPE

240 mm2 3core Aluminium 630mm2 1 core Aluminium

33kV XLPE 500mm2 1 core Copper 70 mm2 3core Aluminium 185 mm2 3core Aluminium PILC 400 mm2 3core Aluminium 70 mm2 1core Aluminium 150 mm2 1core Aluminium 240 mm2 1core Aluminium

Joints

22kV

XLPE

500 mm2 1core Aluminium


Category Types Size 120 mm2 3core Aluminium 185 mm2 3core Aluminium PILC 300 mm2 3core Aluminium 70 mm2 1 core Aluminium 500 mm2 1core Aluminium 240 mm2 Aluminium Triplex 95 mm2 3core Aluminium 150 mm2 3core Aluminium

11kV

XLPE

240 mm2 3core Aluminium 185 mm2 - 150 mm2 3core 185mm2 - 240 mm2 3core 400 mm2 - 240 mm2 3core

22 kV PILC - XLPE

400 mm2 - 500 mm2 3core 120 mm2 - 95 mm2 3core 185 mm2 - 150 mm2 3core

Transition Joints

11kV PILC - XLPE 300 mm2 - 240 mm2 3core

3.2 Construction of Cables and its Accessories Generally the major component and its function in power cables and accessories are as follows:

Table 3.2 Cable components and their function Component Function

Conductor / Ferrule Carrying current. The important criterion is the current carrying capacity of the conductor.

Insulation High resistance to the flow of current. Often referred to as dielectric.

Metallic Sheath To provide return path for fault current. Size depending on short circuit rating of the particular circuit.

Outer Sheath To provide mechanical protection.

3.2.1 XLPE Cable In TNB Distribution network there are single core, three core and triplex XLPE cables. 3.2.1.1 Single Core Cable The typical construction of single core XLPE cable is shown in Figure 3.1.


No. Designation 1. Conductor 2. Conductor screen 3. Insulation 4. Insulation screen

Insulation

5. Metallic sheath 6. Outer protection

Figure 3.1 Construction of single core XLPE cable

• Conductor: Aluminum or Copper. Size varies as shown in Table 3.1. • Insulation: XLPE sandwiched between semi-conductive materials that are conductor

screen and insulation screen using vulcanizing technique. • Metallic Sheath: Copper tape is applied helically with at least 15% overlap. • Outer Protection: Usually Polyethylene (PE).

3.2.1.2 Three Core Cable The typical construction of three core XLPE cable is shown in Figure 3.2.


Insulation

5. Metallic sheath 6. Filler 7. Core wrapping 8. Outer sheath

Outer protection

Figure 3.2 Construction of three core XLPE cable

• Conductor: Aluminum or Copper. Size varies as shown in Table 3.1. • Insulation: XLPE sandwiched between semi-conductive materials that are conductor

screen and insulation screen using vulcanizing technique. • Metallic Sheath: Copper tape is applied helically with at least 15% overlap. • Filler: To fill in the gap between conductors with polypropylene material to make it

round shape. • Outer Protection: Usually Polyethylene (PE).


3.2.1.3 Triplex Cable The typical construction of triplex XLPE cable is shown in Figure 3.1.


Insulation

5. Metallic sheath 6. Outer protection

Figure 3.3 Construction of triplex XLPE cable

• It is actually single core cable construction for each core but grouped together. • Conductor: Aluminum or Copper. Size varies as shown in Table 3.1. • Insulation: XLPE sandwiched between semi-conductive materials that are conductor

screen and insulation screen using vulcanizing technique. Currently in TNB only 11kV with triplex construction is in use.

• Metallic Sheath: Copper tape is applied helically with at least 15% overlap. • Outer Protection: Usually Polyethylene (PE).

3.2.2 PILC Cable In TNB Distribution network, PILC is used for 11kV and 22kV. The typical construction of PILC cable is shown in Figure 3.4.


No. Designation 1. Stranded aluminium conductor 2. Paper insulation 3. Filler paper 4. Manufacturer label 5. PVC tape 6. Bedding 7. Textile serving 8. Perforated metallic 9. Jute fillers 10. Copper-woven fabric tape 11. Lead sheath 12. Voltage label 13. Steel armour

Figure 3.4 Construction of PILC cable

• Conductor: Aluminum or Copper. Size varies as shown in Table 3.1. Are often wrapped in insulation paper.

• Insulation: Paper with impregnated oil. • Filler: Paper impregnated with oil. • Belt Insulation: Paper impregnated with oil. To provide extra insulation required

corresponding to ((VL/√3) - (VL/2)) volt. • Metallic Sheath: Lead shield. • Perforated Metallic Paper: Used for 22kV only. • Outer Protection: Usually jute with steel type armor.

3.2.3 LV Cable In TNB Distribution Division Network, there are two types of LV Cables: PVC and XLPE. 3.2.3.1 PVC LV Cable The typical construction of PVC LV cable is shown in Figure 3.5.


No. Designation 1. Sheath 2. Binder tape 3. Filler 4. Insulation 5. Conductor

Figure 3.5 Construction of PVC LV cable

• Conductor: Aluminum or Copper. Size varies as shown in Table 3.1. • Insulation: PVC. Usually colored according to the phase. • Binder Tape. • Filler: To fill in the gap between conductors with polypropylene material to make it

round shape. • Outer Protection/Sheath: Usually Polyethylene (PE).

3.2.3.2 XLPE LV Cable The typical construction of XLPE LV cable is shown in Figure 3.6.

No. Designation 1. Conductor 2. Insulation 3. Filler 4. Core Wrapping 5. Inner Sheath 6. Metallic Screen 7. Outer Sheath

Figure 3.6 Construction of XLPE LV cable

• Conductor: Aluminum. Size varies as shown in Table 3.1. • Insulation: XLPE. Usually colored according to the phase. • Filler: To fill in the gap between conductors with polypropylene material to make it

round shape. • Metallic Screen: Copper tape • Inner/Outer Sheath: Usually Polyethylene (PE).


3.2.4 Joint The typical construction of cable joint is shown in Figure 3.7.

Figure 3.7 Construction of Premoulded type Joint

• Connector: Aluminum or Copper depending on conductor type. For crimped type the size depends on conductor size whereas mechanical type has range taking capability.

• Semi-conducting conductor shield: Same function as conductor shield of cable. • Insulation: Usually EPDM (Ethylene Propylene Diene Monomer) rubber material and

silicone. • Semi-conducting insulation shield: Same function as insulation shield of cable. • Metallic Shield: Breaded Copper Strip or Copper stocking bonded with the main cable

copper tape at both ends. • Outer Protection: Resin to protect joint body from mechanical damage.

3.2.4.1 Different Types of Connectors Currently, two types of connectors, Mechanical and Crimped Connector, are in use in TNB Distribution System as shown in Figure 3.8.

(a) Mechanical connector (b) Crimped connector

Figure 3.8 Types of connectors (a) mechanical (b) crimped


3.2.4.2 Different Joint Design 1. Taped Resin – See Appendix 3.1 2. Heat Shrink – See Appendix 3.2 3. Premoulded – See Appendix 3.3 4. Liquid Transition – See Appendix 3.4 5. Dry Transition – See Appendix 3.5

3.2.5 Termination The typical construction of termination is shown in Figure 3.9.

Figure 3.9 Construction of Termination

• Connector/Lug: Aluminum or Copper depends on conductor type, sometimes bimetal.

Size also depends on conductor size. • Insulation: Skirted shed if outdoor. Unskirted for indoor type. • Semi-conductive material: High K for both conductor and insulation screen. • Outer protection: Must have environmental sealing if outdoor type.

3.2.6 Electrical Stresses in Joints and Terminations In joint and termination build-up, the most important criterion is insulation screen cut back. This is where the high electrical stress lay (Figure 3.10). To control it, there are 2 ways either with geometric stress control or dielectric stress control as shown in Figure 3.11 and Figure 3.12 respectively. It depends on manufacturer’s design and preference.


Figure 3.10 Electrical Stress at End of Cable Semi-Conductive Screen

Figure 3.11 Geometric Stress Control

Figure 3.12 High Dielectric Constant Stress Control


3.3 Severity, Probability and Detectability Ranking used in FMECA Exercise

The important features of FMECA exercise are ranking of the severity index, detection factor and failure probabilities corresponding to various failure modes. All the above indices are ranked in a 10 point scale with their respective descriptions and are presented in Table 3.3, Table 3.4, and Table 3.5.

Table 3.3 Failure Severity Ranking and Definition Effect Severity of Effect Ranking

Hazardous (without warning)

Very high severity ranking when a potential failure mode affects safe system operation without warning

10

Hazardous (with warning)

Very high severity ranking when a potential failure mode affects safe system operation with warning

9

Very high System inoperable with destructive failure without compromising safety

8

High System inoperable with equipment damage 7 Moderate System inoperable with minor damage 6 Low System inoperable without damage 5

Very low System operable with significant degradation of performance

4

Minor System operable with some degradation of performance

3

Very minor System operable with minimal interference 2 None No effect 1

Table 3.4 Failure Probability Ranking and Definition

Failure Probability Failure Probability in 1 Year Ranking >1 in 2 10 Very High: Failure is almost

inevitable 1 in 3 9 1 in 8 8

High: Repeated failures 1 in 20 7 1 in 80 6

Moderate: Occasional failures 1 in 400 5

1 in 2,000 4 Low: Relatively few failures

1 in 15,000 3 1 in 150,000 2

Remote: Failure is unlikely <1 in 1,500,000 1


Table 3.5 Failure Detectability Ranking and Definition Detectability Likelihood of Detection Ranking Absolute Uncertainty

Control cannot detect potential cause/mechanism and subsequent failure mode

10

Very Remote Very remote chance the control will detect potential cause/mechanism and subsequent failure mode

9

Remote Remote chance the control will detect potential cause/mechanism and subsequent failure mode

8

Very Low Very low chance the control will detect potential cause/mechanism and subsequent failure mode

7

Low Low chance the control will detect potential cause/mechanism and subsequent failure mode 6

Moderate Moderate chance the control will detect potential cause/mechanism and subsequent failure mode

5

Moderately High

Moderately high chance the control will detect potential cause/mechanism and subsequent failure mode

4

High High chance the control will detect potential cause/mechanism and subsequent failure mode

3

Very High Very high chance the control will detect potential cause/mechanism and subsequent failure mode

2

Almost Certain

The control will detect potential cause/mechanism and subsequent failure mode

1

3.4 Failure Modes, Effects and Criticality Analysis (FMECA) for MV Cables

Medium Voltage Cable’s dominant failure modes identified by TNB Distribution Division are critical mechanical damage to cable insulation, damaged oversheaths due to corrosion, increase in power factor/decrease in insulating resistance due to ageing and water-treeing, localized defect due to increase in electrical stresses and localized defect/insulation ageing due to thermal ageing. Due to continuous and cyclical dielectric and thermal stresses most of the above failure modes progress slowly over time the insulation system further deteriorates. Consequently go/no-go tests such as spot reading of insulation resistance value and tan delta value at fixed voltage and frequency are ineffective at finding failure patterns. Trending test data is necessary to identify these failure patterns. The maintenance approach for cables therefore focuses on using applicable condition monitoring technologies such as polarization index, tan delta with voltage sweep, dielectric spectroscopy and partial discharge testing. The appropriate condition monitoring technologies corresponding to various failure modes are being identified through detailed FMECA exercise. The FMECA for cables is shown in Table 3.6. The periodicity of condition monitoring tasks according to criticality ranking for all types of failure modes are also detailed in Table 3.6.

TNB Distribution Division Maintenance Manual : Underground Cable System P a g e | 48 ____________________________________________________________________________________________________________________

Table 3.6 FMECA for MV Cables

Failure mode Failure effects Sev Failure

cause Failure

mechanism Prob Current design

controls Det CN RPN Recommended

activities Freq.

To map cable route Continuous

Multi purpose tunnel

Critical mechanical damage to

cable insulation

Severe damage to

cable 7

Hard impact due to sharp object

Reduction/damage of insulating materials (due to 3rd party digging)

4 None 8 28 224

Armored cable

Damaged oversheaths

Corrosion of metal

sheath; water

ingress - leading to

ageing water trees on

cable without

radial water barrier

4

3rd party damage, brittleness, external contamination of solvents, oils, bitumen, etc.

Degradation and damage to insulating materials

5 None 8 20 160 HVDC oversheath integrity test

After laying, then after 5 years, then depending

on test results

Dissipation factor measurement

2 mths. after laying, then

after 10 years, then depending

on test results

Ageing, water treeing 4 Water ingress

Water ingress in insulation area through damaged oversheath or through conductor on damaged cable/accessories

6 None 8 24 192

Dielectric Spectroscopy

Increase in power

factor/decrease in insulating resistance

Decrease of insulation strength

4 Overheating Overheating due to soil dry out or current overload

3 None 8 12 96 Dissipation factor measurement



on test results

Localized defect

Local increase in electrical stresses

4 Manufacturing defect

Defect not detected during acceptance test and factory quality control - leading to localized increase of electrical defects as cable gets older

2 None 8 8 64 PD measurement


after 5 years, then

depending on test results


Failure mode Failure effects Sev Failure

cause Failure



activities Freq.




on test results

PD measurement


after 5 years, then

depending on test results

Localized defect and insulation

ageing

Thermal ageing of insulation;

Local increase of electrical

stressess; Damaged

oversheath

3

External stresses due to cable environment changes

Abnormal cable bending (mechanical damage); increase in soil thermal resistivity

3 None 8 9 72




on test results


3.5 Failure Modes, Effects and Criticality Analysis (FMECA) for MV Joints and Terminations

Medium Voltage Cable joints dominant failure modes identified by TNB Distribution Division are localized defect caused by assembly error, localized defect caused by material defect and insulation ageing. For terminations additional dominant failure modes identified by TNB Distribution Division are localized defect caused by environmental stresses, localized defect caused by insulator tracking and insulation ageing due to water penetration. Most of the above failure modes progress slowly to deteriorate the condition of the joints and terminations over time. The maintenance approach for joints and terminations therefore focuses on using applicable condition monitoring technologies such as tan delta measurement with voltage sweep, partial discharge testing and contact resistance measurement. The appropriate condition monitoring technologies corresponding to various failure modes are being identified through detailed FMECA exercise. The FMECA for joints and terminations are presented in Table 3.7 and Table 3.8 respectively. The periodicity of condition monitoring tasks according to criticality ranking for all types of failure modes for joints and terminations are also detailed in Table 3.7 and Table 3.8 respectively.


Table 3.7 FMECA for MV Joints Failure mode

Failure effects Sev Failure

cause Failure



activities Freq.

Localized defect

Localized increase of electrical stresses

6 Assembly error

Improper assembly leading to bad connection, which in turn results in increase of localized electrical stresses

4 - 8 24 192 PD measurement

After laying, then after 5 yrs., then

dependant on test results

PD measurement


dependant on test results Insulation

ageing

Reduced insulating property

6 Assembly error

Assembly error leading to imperfect sealing

4 - 8 24 192


2 mths. after laying, then after 10 yrs.,

then dependant

on test results

Localized defect

Localized increase of electrical stresses

6 Material defect

Defective prefabricated joints installed





Table 3.8 FMECA for MV Terminations

Failure mode Failure effects Sev Failure cause

Failure mechanism Prob

Current design


activities Freq.

External surface conductivity measurement

2 yrs. or longer,

dependant on site

pollution level

Localized defect

External leakage current. Insulator

chalking (leading to loss of hydrophobicity)

for polymeric type terminations

7 Pollution

Surface pollution degrading insulating material

2 - 8 14 112

Visual inspection

Localized defect

Increase of electrical stresses 7 Insulator

tracking

Pollution providing current path for tracking to occur

2 - 8 14 112 Visual inspection

2 yrs. or longer,

dependant on site

pollution level

Localized defect

Increase of electrical stresses 7 Improper

application

Mechanical damage leading to localized electrical stresses at the point of damage

2 - 8 14 112 Visual inspection After laying

Localized defect

Localized increase of electrical/environmental

stresses 7

Degradation of external and internal insulating surfaces

PD activity leads to degradation of insulating surfaces

2 - 8 14 112 Visual inspection

2 yrs. or longer,

dependant on site

pollution level

Localized defect

Localized increase of electrical 6 Assembly

error

Mechanical damage due to assembly error




Insulation ageing/localized defect

Water penetration 6 Assembly error

Imperfect sealing due to assembly error causing water penetration

4 - 8 24 192

PD measurement, dissipation factor measurement, visual inspection

After laying, then after 10

yrs., then dependant

on test results


Failure mode Failure effects Sev Failure cause

Failure mechanism Prob

Current design


activities Freq.

Localized defect

Uneven voltage distribution 7

Internal insulating compound leaking

Internal insulating compound leaking causing uneven insulation, which leads to uneven voltage distribution (only for porcelain insulators)

3 - 8 21 168 Visual inspection Every 2 yrs.

Chapter 4

Cable Maintenance

Testing


4 Cable Maintenance Testing

4.1 Background The commissioning of any power cables, regardless of its sizes or significance, is a routine but a critical phase of asset management function so as to ensure non-problematic or effective introduction and integration of power cable to the power delivery system. A lack of knowledge and experience in dealing with commissioning and possible arising technical issues could result in delays in commissioning in power cables and associated power delivery systems with consequential revenue losses. Whilst in service, asset managers of electric utilities have an even bigger responsibility to operate and maintain the power cable in such a way so as to derive optimal return on investment and service reliability. The asset managers are therefore in search of successful cable diagnostic techniques commercially available for performing test in the field on distribution power cables. The objective of any diagnostic test is to identify in a non-destructive way a potential problem that may exist in the power cables so that preventive action can be taken to avoid possible in service failure of that cables circuit. This is applicable to both cables and associated accessories.

4.2 Maintenance Matrix The maintenance matrix summarises the list of maintenance testing identified for various categories of cables in TNB Distribution System under different conditions, such as commissioning, in-service and after repair. The maintenance matrix is shown in Table 4.1.


Table 4.1 Cable Maintenance Matrix Condition Monitoring

Technologies XLPE PILC LV

Purpose Technologies 1Commissioning 2In-

Service

3After Repair

Commissioning In-

Service After

Repair Commissioning

In-Service

After Repair

Insulation Resistance

Tan-delta Partial Discharge Mapping

Insulation Integrity


Sheath Integrity

HVDC Sheath Test

Contact Resistance Test

Metallic Sheath Continuity

Integrity of Connections

Thermography

1Newly installed cables prior to first energization 2Condition-based maintenance practice 3After replacement of faulty section


4.3 General Description of Identified On‐Site Testing for Assessing the Integrity of Insulation

The field testing methods identified in the maintenance matrix for commissioning, in-service and after repair are non-destructive or diagnostic test.

4.3.1 Non‐Destructive/Diagnostic Test Non-destructive electrical tests are usually carried out on the equipment insulation to ensure that its electrical characteristics comply with the specification without destroying or jeopardizing the insulation. In most cases, the non-destructive testing is also referred as diagnostic testing where result interpretation is required. In practical this testing method is widely used for condition monitoring activity whereby trending of the test results will be monitored closely thus giving more information compared to spot test reading. The most popular non-destructive test includes Insulation Resistance, Polarization Index, Tangent Delta/Dissipation measurement, Dielectric Spectroscopy measurement, Partial Discharge, etc many more that will not be discussed in this guideline. 4.3.1.1 HVDC test When dc voltage is applied to insulation, the electric field stress gives rise to current conduction and electrical polarization. Consider an elementary circuit as shown in Figure 4.1 below, that shows a dc source, a switch and insulation specimen. When the switch is closed, the insulation become electrified and a very high current flows at the instant the switch is closed. However, these currents immediately drop in value, and decreases at slower rate until it reaches a nearly constant value. The current drawn by the insulation may be analyzed into several components namely Capacitance charging current, Dielectric absorption current, Surface leakage current, Partial Discharge current and volumetric leakage current.

C – Represents charging current RA – Represents absorption current RL – Represents volumetric leakage current

Figure 4.1 Electric circuit of insulation under dc voltage test


4.3.1.1.1 Capacitance Charging Current The capacitance charging current is high as the dc high potential is applied and this charging current is a function of time and will decrease as the time of the application of voltage increases. It is the initial charging current when voltage is applied and therefore not of any value for test evaluation. Test readings should not be taken until this current has decreased to a sufficient low value. 4.3.1.1.2 Dielectric Absorption Current The dielectric absorption current is also high as the test voltage is applied and decreases as the voltage application time increases, but at slower rate than the capacitance charging current. This current is also high but not as high as the capacitance charging current. The absorption current can be divided into two currents called “reversible” and “irreversible” charging currents. The irreversible charging current is of the same general form as the reversible charging current, but is much smaller in magnitude. The irreversible charging current is lost in the insulation and thus is not recoverable. Again, sufficient time should be allowed before recording test data so that the reversible absorption current has decreased to a low value. 4.3.1.1.3 Surface Leakage Current The surface leakage current is due to the conduction on the surface of the insulation where the conductor emerges and point of earth potential. This current is not desired in the test results and should therefore be eliminated by carefully cleaning the surface of insulation to eliminate the leakage paths, or should be captured and guarded out of the meter reading. 4.3.1.1.4 Partial Discharge Current The partial discharge current, also known as corona current, is caused by over stressing the air at sharp edges of the conductor due to high voltage test. This current also not desirable and should be eliminated by the use of stress control shielding at such points during test. However this current does not occur at lower voltages, such as insulation resistance test voltages. 4.3.1.1.5 Volumetric Leakage Current The volumetric leakage current that flows through the insulation volume itself is of primary importance. This is the current that is used to evaluate the conditions of the insulation system under test. Sufficient time should be allowed for the volumetric current to stabilize before test reading is recorded. The total current, consisting of various leakage currents as described above is shown in Figure 4.2.


Figure 4.2 Insulation Current Characteristics

4.3.1.1.6 Dielectric Phenomenon and Polarization Generally dielectric has the property of both temporary and permanent absorption of electrical charges and property of conduction. When a voltage is applied to a dielectric, forces on the positive and negative charges inherent in the particles that make up the dielectric tend to orient the particles in line with the applied field. Some dielectric materials have molecules that have an uneven number of atoms that is, having asymmetrical arrangement of charges. When such molecules are placed in an electric field, they will migrate in an electric filed, thus becoming polarized with the electric field. Such molecule is called “dipole”. Dipole plays an important role in the electrical characteristics of such insulation. A dipole may be represented by a particle having a small positive charge at one end and a small negative charge at the other end. When these dipoles are subjected to dc voltage, they are polarized and become aligned with respect to positive and negative polarity of the dc voltage. This phenomenon is known as dipole polarization. Polarization phenomenon is influenced strongly by the material properties, structure and condition of insulation. On the other hand, charged particles, i.e. particles with positive and negative charges, which are not interrupted by interfacial barriers and can travel through the dielectric from one electrode to the other, constitute the leakage current and are not part of the polarization phenomenon.


4.3.1.1.7 Insulation Resistance Testing In general this test may be conducted at applied voltage of 250 – 15,000 V. The testing equipment used is a megohmmeter, either hand cranked, motor driven or electronic, which indicates the insulation resistance in Mega ohms or Giga ohms. The quality of insulation is variable, dependent upon temperature, humidity and other environmental factors. Therefore, all readings must be corrected to standard temperature for the class of equipment under test. The insulation resistance measurement can be useful in giving an indication of deteriorating trends in the insulation system. However the insulation resistance value alone does not indicate the weakness of neither the insulation nor its total dielectric strength. The reading only allows a rough check of the insulation condition. Therefore, comparison of this value with previous values is of utmost importance. A continued reducing value trend, exhibited the deterioration of insulation. Hence it is of great importance to record each interval value with corrected to the specific temperature reference for consistency purposes. 4.3.1.1.8 Polarization Index The polarization index test is a specialized application of the dielectric absorption test. A good insulation system shows a continued increase in its insulation resistance value over a period of time in which voltage is applied. On the other hand, an insulation system that is contaminated with moisture, dirt and the like will show a low insulation resistance value. In good insulation, the effect of absorption current decreases as time increases. In bad insulation, the absorption effect is prevailed by high leakage current. The time resistance method is less dependent of temperature and equipment size. It can provide conclusive results as to the condition of the insulation. The ratio of time-resistance readings can be used to indicate the condition of insulation system. Polarization index is carried out at applied voltages of DC volts which slightly below the phase voltage of particular cable rating. Using an electronic megohmmeter will give an indication of insulation resistance in Mega ohms or Giga ohms. Cable terminations at both ends are cleaned before making the measurement in which special cleaning solvent is used. Subsequently after the cleaning, earthing mechanism via cable sheath was also checked and verify through the conductor resistance measuring devices. To get an accurate reading guard connection can be used to eliminate the presence of surface leakage current that might affect the measurement. Insulation resistance measurement values are recorded at 1 minute and 10 minutes of voltage application. The ratio at 10 minutes to 1 minute will determine the polarization index value. 4.3.1.1.9 Tangent Delta Tan Delta, also called Loss Angle or Dissipation Factor testing, is a diagnostic method of testing underground cables to determine the quality of the cable insulation. Cable approaches the properties of perfect capacitor provided that the insulation is free from defect. In a perfect


capacitor, the voltage and current are phase shifted 90º. If there is an impurity or defects resistance of the cable will decrease resulting in an increase in resistive current. Therefore it will no longer be a perfect capacitor and the voltage and current will no longer be shifted 90º. It will be less than 90º. The angle between the phase shift is called delta ( δ ) or loss angle.

Figure 4.3 Representation of Cable

Figure 4.3 shows a representation of the cable. The tangent of δ is measured. This will indicate the level of resistance in the insulation. The greater the angle means the worse the cable is. The tangent delta essentially provides the same qualitative assessment as a power factor test. With power factor the cosine of the angle between the voltage and current is measured, yielding the power factor. Meanwhile the tangent delta is the tangent of the complimentary angle. For slight angle, the tangent delta readings will be the same as the power factor. As the angle, hence loss, increases the tangent delta and the power factor will not be the same. Below is the calculation of Dielectric Loss,

Pd = V2ωCtanδ …………………………………………Equation ( 4.1) From the equation above, it’s clearly shown that tangent delta can be measured by varying the voltage or frequency. By varying the voltage called Tip-up whereas by varying the frequency it is called dielectric spectroscopy. If the insulation of the cable is perfect, the tan delta will not change as applied voltage is increased. If the cable has water tree contamination, thus changing the capacitive nature of the insulation, then the tangent delta will be higher at the higher voltages. The increase in loss angle with the increasing voltage indicates high resistive current element in the insulation as shown in Figure 4.4.


Figure 4.4 Comparison between new and old cable The tan delta testing equipment has an AC high voltage source. This high voltage is needed to energize the cable. The length of the cable that can be tested will depends on the AC voltage source used. It is generally advantageous to test shorter length rather than a long cable, the more precise we can be in determining whether the cable is bad or good. Usually VLF voltage source is used. The standard VLF source can test 4-6 km. 4.3.1.1.10 Dielectric Spectroscopy It is a measurement of tan delta over a range of voltage and frequency. By varying the frequency and the voltage, the response can provide more information about the insulation than varying only one factor. The tangent delta below 1Hz is sensitive to degradation due to water trees in XLPE cables. The tangent delta also offers a comparative assessment of the aging of PILC. Tangent delta will decrease if the frequency is raised as shown in Figure 4.5. When the voltage is varied, the tangent delta remains relatively the same, thus indicating the good condition of cable.


Figure 4.5 Tangent delta in frequency sweep

From Figure 4.6, when looking at new cable the voltage is varied from 3kV to 6kV, the tangent delta stays relatively the same, thus indicating the good condition of the cable. Whereas in old cable when the voltage is varied from 3kV to 6kV, the tangent delta increases with voltage, thus indicating that water tree is present in this cable.

Figure 4.6 Comparison between new and old cable under dielectric spectroscopy

When making dielectric spectroscopy measurements on cable circuits containing accessories, users should be aware that the presence of certain types of accessories could dominate the


results obtained. In particular, accessories that utilize stress grading materials may results in high value of tangent delta at elevated voltage. Using tangent delta measurement test it is not possible to find the location of the cable defects. For any value of tangent delta, there could be many minor defects or a few major defects, it cannot discriminate since it is not a fault finding tool. For varying the voltage, AC high voltage source is required. Due to the voltage source limitations, this test can only be applied for medium voltage cables with maximum length of 2-3 km. 4.3.1.2 Partial Discharge 4.3.1.2.1 Definition Electric discharges which do not bridge electrode are called partial discharge. Between the electrodes a sound dielectric is present in the form of solid, liquid, or gaseous insulator. Examples of this type of discharge are discharges in a cavity in a solid dielectric (both electrodes are shielded from the discharges by the solid), discharge on a surface (at least one electrode is shielded by a solid dielectric), and discharges around a sharp point at high voltage (the discharge is shielded from one electrode by column of non-ionized gas). Although the magnitude of such discharge is usually small they can cause progressive deterioration and ultimate failure, so that it is essential to detect their presence as a non-destructive control test.

Partial discharge belongs to a far greater group of gas discharges. In all these discharge gas molecules are ionized by impact of electrons. The newly formed electrons gain speed in an electric field, ionizing more molecules by impact, so that an avalanche of electrons is formed. The electrons in the avalanche and the ions left behind move towards the electrodes, thereby forming a passage of current through the gas. 4.3.1.2.2 Classification The term ionization is often used for partial or internal discharges. This is incorrect the scope of this term is far broader according to its definition: a process by which an atom becomes electrically charged due to losing or gaining one or more of extra nuclear electrons. There are generally three classification of partial discharges namely corona discharge, surface discharge and internal discharge. Corona discharges are discharges taking place around an electrode placed in a highly non-uniform field. Corona discharge is usually observed as a bluish glow accompanied by hissing sound. These discharges cause ionisation of the air and produces ozone. The combined action of bombardment of ions and the chemical compounds formed during corona discharge leads to the degradation of the insulation.


The second type of partial discharge is the surface discharge. Surface discharges are discharges that take place along an interface between two dielectric media. The formation of surface discharge normally preceded with the sufficient flow of surface leakage current in the presence of moisture and impurity or imperfections of the surface. Flow of this current along the interface causes surface heating (I2R heating). This heating action then causes drying of the moisture and thus dry bands are formed due to the imperfections or impurities on the surface islands. When the potential difference across these dry bands exceed its breakdown strength, surface discharge or scintillations will take place. These discharges when left alone are able to bridge the conductors and hence total failure of the insulation system.

The third classification and by far the most common in power cable insulation is internal discharge. Internal discharges are partial discharges occurring internal to the insulation system. This is usually caused by the presence of voids or cavities within the insulation system. These voids when experience a potential gradient greater than its breakdown strength will cause a discharge bridging the two affected surfaces of the particular void. A discharge internal to the void will cause localised burning of the insulation and when left alone, these voids will grow on to form an electrical tree, and hence causing failure of the insulation. Insulation of power cables can be modeled by its equivalent capacitance and resistances. Lumped parameters are employed in this case for ease of analysis. The equivalent electrical circuit of the insulation system can be modeled as Figure 4.7 below.

Figure 4.7 Equivalent circuit diagram of cable insulation with voids


As shown in Figure 4.7, a void is typically represented by a parallel resistor and capacitor. When the total insulation systems see the applied voltage, a voltage drop will be impressed upon this parallel combination of resistance and capacitance representing the void. In the event where the voltage drop across the void exceeds its respective breakdown voltage, termed Inception Voltage (Vi), a discharge will take place thus, bridging the void. When the void is bridged the voltage across the void collapses until the point of extinction where the discharge is extinguished. The voltage at this point of extinction is termed as the extinction voltage (Ve). Once this discharge is extinguished, the voltage across the void resumes increases in the direction of the applied voltage until the next inception voltage is reached and hence a repetition of the above cycle.

Figure 4.8 Occurrences of internal discharges

The requirement for an increasing build-up of voltage across the void before the inception voltage is reached gives partial discharge the characteristic traits of only occurring either in the first and third quarter of the test voltage waveform. Partial discharges occurring in the first quarter (positive rising voltage) is termed as negative polarity discharge whereas discharges occurring in the third quarter (negative rising voltage) are termed positive polarity discharges. This is represented in Figure 4.8. This notation of discharges is derived from the fact that the classical method of detection measures partial discharges as voltage pulses. 4.3.1.2.3 Partial Discharge Location Using Travelling Wave Technique Partial discharges occurring within the insulation of the power cables will result in charge accumulation at the point of discharge. This charge accumulation in turn creates two travelling waves that travel in opposite direction to each other, towards the two ends of the cable. The voltage wave can be described as:

2i(t)ZV o

i×

= …………………………………..….. Equation ( 4.2)

where Zo is the surge impedance of the cable under test and i(t) reflects the rate of charge accumulation. This voltage wave can be detected through the following test setup and equipment as shown in Figure 4.9.


Figure 4.9 PD Test Setup

The voltage wave can be effectively measured by ensuring that the effective detection impedance of the system equals the surge impedance of the test cable. By measuring these discharge pulses and comparing their time of arrival, quantification of discharge magnitude and the number of discharges, as well as, determination of the location of the various discharges can be made.

In determining the location of the discharge, the time of arrival of the discharge pulse would have to be closely monitored. For a discharge, two pulses will be generated and will travel towards the two ends of the cable as shown in Figure 4.10. By effectively measuring the time of arrival of the first and second pulse, together with the arrival of the third pulse which is a reflection of the first pulse that travels twice the whole length of the cable, the discharge location can be deduced.

Figure 4.10 PD Pulse Generation in Cables

Considering End A as the measurement end, then the first pulse propagating towards this end would serve as the reference pulse. The second pulse would travel towards End B and be reflected back along the length of the cable towards End A. The time this pulse reaches End A is recorded as tB. The first pulse after having reached End A would also be reflected and transverse towards End B where again it is reflected towards End A. This pulse when detected at End A is called the third pulse. Figure 4.11 depicts the phenomenon described above. The time by which this third pulse is detected at End A (referenced to the first pulse) is recorded and for the purpose of our analysis denoted as tC.


Figure 4.11 PD Pulse Characteristic in Cables

The location of the discharge can be easily computed by the following ratio:

100×−

=BC

tttX

C………………….………………….Equation ( 4.3)

where X is the location of the discharge in percentage of cable length from the detection end, End A. A characteristic feature of the discharge signal is indicated by the attenuation of the discharge pulses measured. The attenuation of the pulses as it transverse the cable conductor leads to the general characteristic of discharges as indicated below, where the magnitude of the pulses decreases from the first pulse to the last. 4.3.1.2.4 High Voltage Source

• VLF (0.1 Hz) Test: VLF testing at 0.1 Hz, and lower frequencies for longer cable lengths, has been used successfully to measure dissipation factor and PD levels in cables and their accessories, is less damaging to the insulation than dc testing and can locate potential failure sites reliably. VLF has the advantage that the energy requirements are 1/600 for 60 Hz voltages and 1/500 for 50 Hz voltages, so the test sets can be much smaller than for normal operating frequency test sets. Portability is of utmost importance for field testing. VLF PD detection has been successfully employed to find major defects in cable accessories.

• The Oscillating Wave Test System (OWTS): The Oscillating Wave Test System was developed as a non-destructive, after laying test, standardized by the IEC. Further development has led to a diagnostic suitable for off-line applications in noisy environments. The OWTS produces ac voltages in the range of 20 to 1000 Hz depending upon the cable length and can be used for PD pattern analysis provided there are no high disturbances present. This is also used for dissipation factor measurements. Refer Appendix 4.1 for details on Partial Discharge Theory.


4.4 General Description of Identified On‐Site Testing for Assessing the Integrity of Current Carrying Paths (Conductors, connectors and earthing shields)

This kind of test is conducted to check the low resistance ohmic values of the connections and the continuity of the phase conductor and also metallic sheath.

4.4.1 Contact Resistance Measurement of Joints and Terminations This test is to assist in determining poor connection in installing conductor to conductor jointing for both straight through joints and terminations. A limit for acceptable value varies with the ferrule types, procedures used and tools used. A reading exceeding 50 µΩ indicates that a poor connection exists. The manufacturers usually recommend that a 10-100 amperes testing equipment be used. This test should be conducted after the installation of ferrule and before the build up of insulation in joints and terminations. Figure 4.12 shows the set-up for contact resistance measurement.

Figure 4.12 Contact Resistance Test Setup 4.4.2 Continuity of Phase Conductor and Metallic Sheath This also uses the same principal of the contact resistance measurement but with the lower value of ampere. The value of resistance may vary from hundreds of milliohm to few ohms depending on the length of the circuit, type of conductor material and type of joints. The measurement set-up is same as shown in Figure 4.12.


4.5 Soaking Test The recommendation is to follow detail commissioning tests for Medium Voltage power cables. Alternative to detail commissioning test can be the following:

(a) The insulation test shall be applied for 1 minute between each phase conductor and sheath

(b) The circuit shall be under soak for at least 24 hours To bypass (b), the work conditions shall be considered as emergency or as determined by the Engineer-in-Charge. The soak test is basically to energize the cable at the rated voltage without any load.

Chapter 5

Cable Maintenance

Testing Procedure


5 Cable Maintenance Testing Procedure

5.1 Background This chapter will discuss testing equipment required, commissioning & in-service maintenance guidelines, detail testing procedures for all the identified tests and CMMS data capturing templates for both underground Medium Voltage and Low Voltage Cables. The detail guidelines for cable fault locating will also be discussed toward the end of this chapter.

5.2 Testing Equipment Specification The following testing equipments are required to perform the testing requirements for commissioning, in-service, and after repair maintenance tasks are shown in Table 5.1 – Table 5.5.

Table 5.1 MV XLPE Cable for Insulation Integrity Test Task Maintenance Test Testing equipment Minimum Technical Specification

Tan-delta Test Tan-delta Test Set with VLF HV Source

Max voltage: 57kVrms

Max current: 90mA Freq range: 0.01Hz – 1.0Hz Max Load: 2µF at 0.1 Hz Waveform: Sinusoidal Tan Delta Range: 0.1 to 1000 10-3

PD Mapping Test Set with VLF HV Source

Max voltage: 40kV Max current: 40mA Freq range: 0.01Hz – 1.0Hz Max Load: 2µF at 0.1 Hz Waveform: Sinusoidal Partial Discharge

Mapping Test

PD Mapping Test Set with OW HV Source

Max voltage: 60kVpeak

Max current: 7mA Freq range: 50Hz-500Hz Max Load: 2.0 µF Min PD: 1pC-100nC

Dielectric Spectroscopy Test

Tan-delta Test Set with sweep frequency analyzer

Max Output Volt: 30kVpeak

Max current: 15-40mApeak at the rate of 0.01-2.5Hz Max Load: 10µF Freq Range: 0.0001-100Hz


Insulation Resistance Test

Megohmeter Test Set (3 Terminal Tester)

Max voltage: 10kV dc Max current : 2mA Max resistance: 5TΩ (digital meter)


Table 5.2 MV PILC Cable for Insulation Integrity Test Task Maintenance Test Testing equipment Minimum Technical Specification

Tan-delta Test Power Frequency Tan-delta Test Set

Max voltage: 200V Max current: 50mA Frequency: 50Hz

PD Mapping Test Set with VLF HV Source


Max current: 40mA Freq range: 0.1Hz – 1.0Hz Max load: 2µF at 0.1Hz Waveform: Sinusoidal Partial Discharge

Mapping Test PD Mapping Test Set with OW HV Source


Max current: 7mA Freq range: 50Hz-500Hz Max Load: 2.0 µF Min PD: 1pC-100nC

Dielectric Spectroscopy Test

Tan-delta Test Set with sweep frequency analyzer

Max voltage: 200Vpeak

Max current: 50mApeak

Freq range: 0.0001 – 1kHz




Max voltage: 10kV dc Max current : 2mA Max resistance: 5TΩ (digital meter)

Table 5.3 LV Cable for Insulation Integrity Test

Task Maintenance Test Testing equipment Minimum Technical Specification




Max voltage: 10kV Max current : 2mA Max resistance: 5TΩ (digital meter)

Table 5.4 MV XLPE Cable for Sheath Integrity Test


Sheath Integrity HVDC Sheath Test DC Pressure Test Set

Output voltage: 20kV DC Output current: 20mA Maximum Testing Duration: 30 min

Table 5.5 MV XLPE, MV PILC & LV for Integrity of Connections


Contact Resistance Test

Milliohmmeter Test Set (4 Terminal Tester)

Max current : 0-200A Resistance Range: 0-500 µΩ Resolution: 1 µΩ

Integrity of Connections

Metallic Sheath Continuity Digital Multimeter

Measurement Ranges: Max Voltage: 600Vrms

Max Current: 10Arms

Resistance Range: 400Ω – 40MΩ Capacitance range : 5nF – 5µF



Milliohmmeter resistance Test Set

Max current:10A Resistance range: 0-5 Ω Continuity Selection Mode

Thermography InfraRed Camera

Temperature Range: 0oC – 500oC

Sensitivity: ± 0.3oC Focal range: 0.4m to infinity Should be able to measure: 1. Absolute value of hot spot

temperature 2. Colour thermal image of focused

object 3. Isotherm temperature 4. Dual spot delta temperatures 5. Measured temperatures shall be

corrected for effects of solar emittance, atmospheric temperature.

All testing equipment shall be in good mechanical and electrical condition. Accuracy of metering in testing equipment shall be appropriate for the test being performed but not in excess of two percent of the scale used. Waveshape and frequency of testing equipment output waveforms shall be appropriate for the test and the tested equipment.

5.2.1 Testing Equipment Calibration

• There has to be a calibration program which assures that all applicable testing equipment is maintained within rated accuracy.

• The accuracy shall be directly traceable to TNB approved accredited test laboratory following International Standard.

• Testing equipment shall be calibrated in accordance with the following frequency schedule:

– TNB testing equipment: every 12 months – Contractor testing equipment: every 12 months, where contractor must ensure

the evidence of calibration test certificate • Dated calibration labels shall be visible on all testing equipment. • Records, which show date and results of testing equipment calibrated or tested, must

be kept up to date. • Up-to-date testing equipment calibration instructions and procedures shall be

maintained for each testing equipment. • Calibrating standard shall be of higher accuracy than that of the testing equipment

being tested.


5.3 Commissioning, In‐service and After Repair

Maintenance Guidelines

5.3.1 Commissioning Testing Guideline for Low Voltage Cables 5.3.1.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for loose screws, bolts and nuts. 3. Inspect for damaged core. 4. Ensure that the surface markings are legible. 5. Inspect ends of cable for proper seals. 6. Inspect for discolored, cracked or brittle insulation and/or jacket. 7. Inspect for signs of sharp bends. 8. Inspect for signs of corrosion, discoloration and oxidation of metallic shield. 9. Inspect compression-applied connectors for correct cable match and indentation. 10. Note if there is any cable core crossing. 11. Record results on the appropriate test sheet (See Section 5.8.1). 5.3.1.2 Testing 1. Inspect all crimped electrical connections for high resistance using low-resistance

ohmmeter in accordance with Section 5.6.1. 2. Perform continuity tests on each cable phase using multimeter or low resistance

ohmmeter in accordance with Section 5.6.2. 3. Perform insulation-resistance tests on each cable phase-to phase and phase-to-earth.

Applied voltage should be 1000V dc for one minute in accordance with Section 5.4.5. 4. Record results on the appropriate test sheet (See Section 5.8.1). Note All the above identified tests should be carried out on de-energized cables.

5.3.2 In‐service Maintenance Testing Guideline for Low Voltage Cables

5.3.2.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for evidence of overheating.


3. Inspect for loose screws, bolts and nuts. 4. Inspect for damaged core. 5. Inspect for discolored, cracked or brittle insulation and/or jacket. 6. Inspect for signs of sharp bends. 7. Note if there is any cable core crossing. 8. Record results on the appropriate test sheet (See Section 5.8.1). 5.3.2.2 Testing 1. Inspect all crimped electrical connections for high resistance using thermographic

survey in accordance with Section 5.6.3 as and when required. 2. Perform continuity tests on each phase using ohmmeter in accordance with Section

5.6.2 as and when required. 3. Perform insulation-resistance tests on each cable phase-to phase and phase-to-earth.

Applied voltage should be 1000V dc for one minute in accordance with Section 5.4.6 as and when required.

4. Record results on the appropriate test sheet (See Section 5.8.1). Note Thermographic survey should be performed on energized cables. All other identified tests should be carried out on de-energized cables.

5.3.3 After Repair Testing Guideline for Low Voltage Cables 5.3.3.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for evidence of overheating. 3. Inspect for loose screws, bolts and nuts. 4. Inspect for damaged core. 5. Ensure that the surface markings are legible. 6. Inspect ends of cable for proper seals. 7. Inspect for discolored, cracked or brittle insulation and/or jacket. 8. Inspect for signs of sharp bends. 9. Inspect for signs of corrosion, discoloration and oxidation of metallic shield. 10. Inspect compression-applied connectors for correct cable match and indentation. 11. Record results on the appropriate test sheet (See Section 5.8.1). 5.3.3.2 Testing 1. Same group of tests to be followed as listed under commissioning of Section 5.3.1. 2. Record results on the appropriate test sheet (See Section 5.8.1).


5.3.4 Commissioning Testing Guideline for Medium Voltage XLPE Cable

5.3.4.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for loose screws, bolts and nuts. 3. Inspect for damaged core. 4. Ensure that the surface markings are legible. 5. Inspect ends of cable for proper seals. 6. Inspect for discolored, cracked or brittle insulation and/or jacket. 7. Inspect for signs of sharp bends. 8. Inspect for signs of corrosion, discoloration and oxidation of metallic shield. 9. Inspect compression-applied or mechanical connectors for correct cable match and

indentation. 10. Inspect for shield grounding and cable support. 11. Record results on the appropriate test sheet (See Section 5.8.2). 5.3.4.2 Testing 1. Inspect all bolted or crimped electrical connections for high resistance using low-

resistance ohmmeter in accordance with Section 5.6.1. 2. Perform a shield continuity test on each power cable by ohmmeter method in

accordance with Section 5.6.2. 3. Perform sheath integrity test using high voltage DC in accordance with section 5.5. 4. Perform tan delta test with voltage sweep ranging between 0.5UO and 2UO using 0.1Hz

AC voltage waveform in accordance with section 5.4.1.2. 5. Perform tan delta test with frequency sweep at varying voltages (dielectric

spectroscopy test) in accordance with section 5.4.4.2. 6. Perform partial discharge test at 1.7UO using either 0.1 Hz AC voltage waveform in

accordance with Section 5.4.2 or oscillating voltage waveform for all the phases in accordance with Section 5.4.3.

7. Perform an insulation-resistance test utilizing a megohmmeter with a voltage output of at least 2500 volts. Individually test each conductor with all other conductors and shields grounded in accordance with Section 5.4.5. Test duration shall be one minute.

8. Record results on the appropriate test sheet (See Section 5.8.2). Note All the above identified tests should be carried out on de-energized cables.


5.3.5 In‐service Maintenance Testing Guideline for Medium Voltage XLPE Cable

5.3.5.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for evidence of overheating. 3. Inspect for loose screws, bolts and nuts. 4. Inspect for damaged core. 5. Inspect for discolored, cracked or brittle insulation and/or jacket. 6. Inspect for signs of sharp bends. 7. Inspect for shield grounding and cable support. 8. Record results on the appropriate test sheet (See Section 5.8.2). 5.3.5.2 Testing 1. Inspect all exposed bolted or crimped electrical connections using thermographic

survey in accordance with Section 5.6.3, 24 months after commissioning for new installation. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

2. Perform a shield continuity test on each power cable by ohmmeter method in accordance with Section 5.6.2 after 24 months from commissioning. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

3. Perform sheath integrity test using high voltage DC in accordance with section 5.5 after 24 months of commissioning. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

4. Perform tan delta test with voltage sweep ranging between 0.5UO and 2UO using 0.1Hz AC voltage waveform in accordance with section 5.4.1.2 after 24 months of commissioning. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

5. Perform tan delta test with frequency sweep at varying voltages (dielectric spectroscopy test) in accordance with section 5.4.4.2. Follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

6. Perform partial discharge test at 1.7UO using either 0.1 Hz AC voltage waveform in accordance with Section 5.4.2 or oscillating voltage waveform for all the phases in accordance with Section 5.4.3. Follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

7. Perform an insulation-resistance test utilizing a megohmmeter with a voltage output of at least 2500 volts. Individually test each conductor with all other conductors and shields grounded in accordance with Section 5.4.5 after 24 months of commissioning.


Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition. Test duration shall be one minute.

8. Record results on the appropriate test sheet (See Section 5.8.2). Note To obtain the first set of testing data for cables already in-service the prioritized maintenance plan should be referred. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition. Thermographic survey should be performed on energized cables. All other identified tests should be carried out on de-energized cables.

5.3.6 After Repair Testing Guideline for Medium Voltage XLPE Cable

5.3.6.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for loose screws, bolts and nuts. 3. Inspect for damaged core. 4. Ensure that the surface markings are legible. 5. Inspect ends of cable for proper seals. 6. Inspect for discolored, cracked or brittle insulation and/or jacket. 7. Inspect for signs of sharp bends. 8. Inspect for signs of corrosion, discoloration and oxidation of metallic shield. 9. Inspect compression-applied and mechanical connectors for correct cable match and

indentation. 10. Inspect for shield grounding and cable support. 11. Record results on the appropriate test sheet (See Section 5.8.2). 5.3.6.2 Testing 1. Same group of tests to be followed as listed under commissioning of Section 5.3.4. 2. Record results on the appropriate test sheet (See Section 5.8.2).


5.3.7 Commissioning Testing Guideline for Medium Voltage PILC Cable

5.3.7.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for loose screws, bolts and nuts. 3. Inspect for damaged core. 4. Inspect ends of cable for proper seals. 5. Inspect for discolored, cracked or brittle insulation and/or jacket. 6. Inspect for signs of sharp bends. 7. Inspect compression-applied and mechanical connectors for correct cable match and

indentation. 8. Inspect for shield grounding and cable support. 9. Record results on the appropriate test sheet (See Section 5.8.3). 5.3.7.2 Testing 1. Inspect all bolted or crimped electrical connections for high resistance using low-

resistance ohmmeter in accordance with Section 5.6.1. 2. Perform a shield continuity test on each power cable by ohmmeter method in

accordance with Section 5.6.2. Perform tan delta test with low voltage 50 Hz AC voltage waveform in accordance with

section 5.4.1.1. Perform tan delta test with frequency sweep at varying voltages (dielectric

spectroscopy test) in accordance with section 5.4.4.1. 6. Perform partial discharge test at 1.7UO using either 0.1 Hz AC voltage waveform in

accordance with Section 5.4.2 or oscillating voltage waveform for all the phases in accordance with Section 5.4.3.

7. Perform an insulation-resistance test utilizing a megohmmeter with a voltage output of at least 2500 volts. Individually test each conductor with all other conductors and shields grounded in accordance with Section 5.4.5. Test duration shall be one minute.

8. Record results on the appropriate test sheet (See Section 5.8.2). Note All the above identified tests should be carried out on de-energized cables.


5.3.8 In‐service Maintenance Testing Guideline for Medium Voltage PILC Cable

5.3.8.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for loose screws, bolts and nuts. 3. Inspect for damaged core. 4. Inspect for discolored, cracked or brittle insulation and/or jacket. 5. Inspect for signs of sharp bends. 6. Inspect for shield grounding and cable support. 7. Record results on the appropriate test sheet (See Section 5.8.3). 5.3.8.2 Testing 1. Inspect all exposed bolted or crimped electrical connections using thermographic

survey in accordance with Section 5.6.3, 24 months after commissioning for new installation. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

2. Perform a shield continuity test on each power cable by ohmmeter method in accordance with Section 5.6.2 after 24 months from commissioning. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

3. Perform tan delta test with low voltage 50Hz AC voltage waveform in accordance with section 5.4.1.1 after 24 months from commissioning. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

4. Perform tan delta test with frequency sweep at varying voltages (dielectric spectroscopy test) in accordance with section 5.4.4.1. Follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

5. Perform partial discharge test at 1.3UO using either 0.1 Hz AC voltage waveform in accordance with Section 5.4.2 or oscillating voltage waveform for all the phases in accordance with Section 5.4.3. Follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition.

7. Perform an insulation-resistance test utilizing a megohmmeter with a voltage output of at least 2500 volts. Individually test each conductor with all other conductors and shields grounded in accordance with Section 5.4.5 after 24 months of commissioning. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition. Test duration shall be one minute.

8. Record results on the appropriate test sheet (See Section 5.8.3).


Note For cables already in-service should follow the prioritized maintenance plan to obtain the first set of testing data. Thereafter follow the guideline given in Chapter 6 for appropriate frequency of monitoring based on health condition. Thermographic survey should be performed on energized cables. All other identified tests should be carried out on de-energized cables.

5.3.9 After Repair Testing Guideline for Medium Voltage PILC Cable

5.3.9.1 Inspection 1. Inspect for signs of physical damage. 2. Inspect for loose screws, bolts and nuts. 3. Inspect for damaged core. 4. Inspect ends of cable for proper seals. 5. Inspect for discolored, cracked or brittle insulation and/or jacket. 6. Inspect for signs of sharp bends. 7. Inspect for signs of corrosion, discoloration and oxidation of metallic shield. 8. Inspect compression-applied and mechanical connectors for correct cable match and

indentation. 9. Inspect for shield grounding and cable support. 10. Record results on the appropriate test sheet (See Section 5.8.3). 5.3.9.2 Testing 1. Same group of tests to be followed as listed under commissioning of Section 5.3.7. 2. Record results on the appropriate test sheet (See Section 5.8.3).

5.4 Testing Procedure for Insulation Integrity

5.4.1 Tan Delta Test for MV Cables 5.4.1.1 Tangent Delta for MV PILC 1. This test should be performed on de-energized cable. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety


Rules. Before going into operation, local safety regulations and safety precautions for the protection against direct or indirect contact of live parts have to be met accordingly.

3. Remove cable terminations (if possible). Make sure that zero voltage condition exists. 4. Ensure that the application of the diagnostic voltage does not lead to flashovers to

other nearby items of the cable station which are in service. 5. Keep all phases earthed at near end except the one under test. Remove the earth at far

end (open). 6. Clean the terminations with cotton cloth and appropriate cleaning solvent. 7. Before making any measurement, analyzer should be calibrated. Usually manufacturer

will supply calibration box. Connect the calibration box to the analyzer. 8. Connect the Negative/Ground lead to cable shield as shown in Figure 5.1. 9. Connect Positive lead to one core (e.g. Red core) as shown in Figure 5.1. 10. Set the frequency to 50Hz (power frequency). 11. Set the voltage to 200 V peak (or the maximum voltage of the testing equipment that

recommended by the manufacturer). 12. After all the necessary safety action are done, then start the measurement. 13. Take measurement:

• Tangent delta and • Capacitance value.

14. Stop the measurement. 15. When the measurement is completed, record the value of the identified data in the

appropriate test sheet. 16. Repeat steps 9-15 for the remaining phases.

Figure 5.1 Connection between Analyzer and PILC Cable

For interpretation of results refer section 6.8.3. Refer Appendix 5.2 for testing equipment details.


5.4.1.2 Tangent Delta for MV XLPE 1. This test should be performed on de-energized cable. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety




end (open). 6. Clean the terminations with cotton cloth and appropriate cleaning solvent. 7. Connect testing equipment protective earth lead to station earth. 8. Connect the phase to be diagnosed to the HV unit as shown in Figure 5.2. 9. Connect the guard ring with braided shield around the bottom of the sealing ends as

shown in Figure 5.2. The guard must not have any contact with earth. 10. Connect the power supply. 11. Switch ON the power supply and testing equipment. 12. Set the frequency to 0.1Hz. 13. Set the Step Test Voltage as below:

Step 1: 0.5*Uo

Step 2: 1*Uo

Step 3: 2*Uo

14. Take measurement: • Tangent delta and • Capacitance value.

15. Stop the measurement. 16. Switch OFF the high voltage unit. 17. Disconnect and Discharge the tested phase. 18. When the measurement is completed, record the value of the identified data in the

appropriate test sheet. 19. Repeat steps 8-18 for the remaining phases. For interpretation of results refer section 6.8.3. Refer Appendix 5.1 for testing equipment details.


Figure 5.2 Connection between HV Unit, Analyzer and XLPE Cable

5.4.2 VLF Partial Discharge Mapping System 1. This test should be performed on de-energized cable. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety




end (open). 6. Clean the terminations with cotton cloth and appropriate cleaning solvent. 7. Connect testing equipment protective earth lead to station earth. 8. Check the power supply and detection system prior to connecting the cable. 9. Set up the power supply and connect the detection filter ready for use but do not

connect the final link to the cable under test as shown in Figure 5.3. 10. Ensure that the filter unit is earthed as shown in Figure 5.3. 11. A buffer amplifier should be used in the signal lead connecting between the detection

filter and measuring terminal as shown in Figure 5.3. 12. Energize the system. 13. Connect HV supply to cable via HV Coupling filter as shown in Figure 5.3. 14. Calibrate cable length using TDR. 15. Connect a pulse calibrator at the cable end. 16. Capture a waveform which consists of two pulses, one direct from the pulse generator

and the other, a reflection from the far end. Measurement of the difference between the leading edges of these pulses gives the travel time.


17. Once the travel time has been noted capture the cable length into analyzer. 18. Disconnect the pulse calibrator. 19. Repeat steps 15-18 on the other two phases (Yellow phase to earth, Blue to earth) and

phase to phase (Red phase to Yellow phase, Yellow phase to Blue phase and Blue phase to Red phase).

20. Set up measuring equipment so that the trigger level is slightly in excess of the background noise level.

21. The time base should be set so that the pulse travel time covers the majority of the display width, allowing maximum accuracy.

22. After all the necessary safety actions are taken energize the cable. 23. Slowly increase the voltage on the cable until partial discharge is observed. Minor

adjustment of the measuring equipment triggering may be required. 24. If partial discharge occurs, record inception voltage (PDIV), PD frequency and other

relevant data giving a filename. 25. Slowly increase the voltage until Uo voltage and record all PD data and give the

filename. 26. If partial discharge occurs in more than one locations record the data in separate file

names. 27. Increase the test voltage until 1.3Uo for in-service test and 1.7Uo for commissioning

test and record the data in separate file names. 28. Slowly decrease the voltage until partial discharge not being observed. 29. Record Extinction Voltage (PDEV) 30. Slowly decrease the voltage until 0 Volt. 31. Stop the measurement. 32. Switch the high voltage button OFF. 33. Disconnect and Discharge the tested phase. 34. Repeat steps 20-33 for other two phases. 35. Analyze the data. 36. When the analysis is completed, record the value of the identified data in the

appropriate test sheet (Refer Section 5.8). 37. Produce, annotate and store partial discharge raw data including maps with

appropriate File name in accordance with guideline stated in Section 7.3.


Figure 5.3 Schematic of Test Circuit


5.4.3 Oscillating Wave Test System (OWTS) For PD Mapping & Tan‐Delta

1. This test should be performed on de-energized cable. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety




end (open). 6. Clean the terminations with cotton cloth and appropriate cleaning solvent. 7. Connect testing equipment protective earth lead to station earth. 8. The OWTS HV Unit connection terminal with the earth connector must be connected

to earth as shown in Figure 5.4. 9. Connect the HV unit cable to the power cable termination. 10. Calibrate cable length using TDR. 11. Connect a pulse calibrator at the cable end. 12. Capture a waveform which consists of two pulses, one direct from the pulse generator

and the other, a reflection from the far end. Measurement of the difference between the leading edges of these pulses gives the travel time.

13. Once the travel time has been noted capture the cable length into analyzer. 14. Disconnect the pulse calibrator. 15. Repeat steps 11-14 on the other two phases (Yellow phase to earth, Blue to earth) and

phase to phase (Red phase to Yellow phase, Yellow phase to Blue phase and Blue


phase to Red phase). 16. Calibrate of PD magnitude and PD pulse velocity* / cable length using the IEC 60270

PD calibrator. 17. Connect the PD pulse calibrator across the test object (cable termination). 18. Connect the calibrator connector (+) to the OWTS HV unit or directly on the cable

termination. 19. Connect the calibrator connector (-) to the earth connection of the OWTS HV unit or

on an earthed part of the cable termination. 20. Select PD calibration value higher than the value which could be expected during the

measurement, e. g. • for PD measurements on service aged paper/oil insulated cables, or service aged

polymeric cables with discharging faults a PD calibration value in the range of 1nC....100 nC could be used,

• for PD measurements on polymeric insulted cable without insulation faults a PD calibration value in the range 100pC...5000pC could be used.

21. After all the necessary safety actions are taken energize the cable. 22. Switch on the HV power supply. 23. Set the voltage [kV] to a preferable value between 0.5Uo ~ 2Uo. 24. Start with a low voltage level e.g. 2 kV and slowly increase the voltage. 25. In the case at the particular voltage level no PD activity has been observed, there is no

necessity to store the data. 26. If partial discharge occurs, record inception voltage (PDIV), PD frequency and other

relevant data giving a filename. 27. Slowly increase the voltage until Uo voltage and record all PD data and give the

filename. 28. Increase the test voltage until up to 1.3Uo for in-service test and 1.7Uo for

commissioning test and record the data in separate file names. 29. Slowly decrease the voltage until partial discharge cannot be observed. 30. Record Extinction Voltage (PDEV). 31. Save all the data. 32. Slowly decrease the voltage until 0 Volt. 33. Stop the measurement. 34. Switch off the HVDC Power Supply Unit. 35. Disconnect and Discharge the tested phase. 36. Repeat steps 23-35 for other two phases. 37. Analyze the data. 38. When the measurement is completed, record the value of the identified data in the

appropriate test sheet (Refer Section 5.7). 39. Produce, annotate and store partial discharge raw data including maps with

appropriate file name in accordance with guideline stated in Section 7.4.


Figure 5.4 Schematic of Test Circuit


5.4.4 Dielectric Spectroscopy 5.4.4.1 MV PILC Cable 1. This test should be performed on de-energized cable. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety




end (open). 6. Clean the terminations with cotton cloth and appropriate cleaning solvent. 7. Before making any measurement, analyzer should be calibrated. Usually manufacturer

will supply calibration box. Connect the calibration box to the analyzer. 8. Connect the Negative/Ground lead to cable shield as shown in Figure 5.5. 9. Connect Positive lead to one core (e.g. Red core) as shown in Figure 5.5.


Figure 5.5 Connection between Analyzer and PILC Cable

10. Set the frequency from 50Hz (or the maximum frequency of the testing equipment that

recommended by the manufacturer) to 0.01Hz. In some equipment the frequency is already preset.

11. Set the voltage to 200 V (or the maximum voltage of the testing equipment that recommended by the manufacturer).

12. After all the necessary safety actions are done, then start the measurement. 13. Perform the measurement:

• Tangent delta and • Capacitance value at 50 Hz.


appropriate test sheet (Refer Section 5.8). 16. Repeat steps 9-15 for the remaining phases. 17. Produce, annotate and store tan delta and capacitance raw data with appropriate file

name in accordance with guideline stated in Section 7.5.2. For interpretation of results refer section 6.9.2. Refer Appendix 5.2 for testing equipment details. 5.4.4.2 MV XLPE Cable 1. This test should be performed on de-energized cable. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety




end (open).


6. Clean the terminations with cotton cloth and appropriate cleaning solvent. 7. Before making any measurement, analyzer should be calibrated. Usually manufacturer

will supply calibration box. Connect the calibration box to the analyzer. 8. Connect the Negative/Ground lead to cable shield as shown in Figure 5.6. 9. Connect Positive lead to one core (e.g. Red core) as shown in Figure 5.6.

Figure 5.6 Connection between Analyzer, HV Unit and XLPE Cable

10. Set the frequency from 100Hz (or the maximum frequency of the testing equipment that is

recommended by the manufacturer) to 0.01Hz. In some equipment the frequency range is already preset.

11. Set the testing voltage in the following sequence 0.25Uo, 0.5Uo, 1Uo, 0.5Uo and 0.25Uo, e.g. • 11kV: 1500 3000 6000 3000 1500, • 33kV: 4500 9000 19000 9000 4500

12. After taking all the necessary safety actions are done, then start the measurement. 13. Perform the measurement:

• Minimum tangent delta and • Capacitance value at 0.01 Hz.

14. Stop the measurement. 15. Switch off the high voltage unit. 16. When the measurement is completed, record the value of the identified data in the appropriate

test sheet (Refer Section 5.8). 17. Disconnect and Discharge the tested phase. 18. Repeat steps 9-17 for the remaining phases. 19. Produce, annotate and store tan delta and capacitance raw data with appropriate file name in

accordance with guideline stated in Section 7.5.1. For interpretation of the results see section 6.9.2. Refer Appendices 5.2 and 5.3 for Testing equipment details.


5.4.5 Insulation Resistance (IR) Testing Procedure 1. This test should be performed on de-energized cable. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety


3. Remove cable terminations (if possible). Make sure that zero voltage condition exists using phasing stick (MV) or voltage indicators (LV).

4. Ensure that the application of the diagnostic voltage does not lead to flashovers to other nearby items of the cable station which are in service.

5. Keep all phases earthed at near end except the one under test. Remove the earth at far end (open).

6. Clean the terminations with cotton cloth and appropriate cleaning solvent. 7. Clean the other end of cable with cotton cloth and appropriate cleaning solvent. 8. Connect the Guard (G) terminal to insulation using copper band as shown in Figure

5.7. 9. Connect the positive (+) terminal to Red core and the negative (-) terminal to shield as

shown in Figure 5.7. 10. Apply voltage according to:

• LV Cable : 0.5kV • MV 11kV Cable : 2.5kV • MV 22/33kV Cable : 5.0kV

11. After all the necessary safety actions are done, then start the measurement. 12. Apply recommended test voltage. 13. Wait for the measurement to stabilize according to:

• LV Cable : 1 minute • MV XLPE Cable : 1 minute • MV PILC Cable :10 minutes

Note: If there is a mixed cable i.e. XLPE and PILC, follow the time for XLPE cables.

14. Record IR readings for : • LV Cable and MV XLPE : 30 seconds and 1 minute • MV PILC : 1 minute and 10 minutes.


appropriate test sheet (Refer Section 5.8). 17. Switch off the testing equipment. 18. Disconnect, short the tested core with the earthing sheath for at least 10 seconds. 19. Repeat steps 8-18 for the remaining phases. 20. Once completed all the phases of the tested cable should be shorted to earth for at least

5 minutes for LV cables and 30 minutes for MV cables before energization.


Figure 5.7 Connection of IR Testing Equipment


5.5 Sheath Integrity Test 1. This test should be performed on de-energized cable. This test is applicable to single

core cable only. This test can be performed on cable with graphite coating. 2. Switching should be done by Authorised Person (AP) in accordance with TNB Safety


3. Make sure that zero voltage condition exists using phasing stick (MV) or voltage indicators (LV).

4. Ensure that the application of the diagnostic voltage does not lead to flashovers to other nearby items of the cable station which are in service.

5. Keep all phases earthed at near end except the one under test. Remove the earth at far end (open).

6. Remove the earthing shields at both near and far ends. 7. Clean the terminations with cotton cloth and appropriate cleaning solvent. 8. Clean the other end of cable with cotton cloth and appropriate cleaning solvent. 9. Ensure that the input voltage to the test set is regulated. Current

Connect the near end earthing shield to the HV terminal (+) of the HVDC Test Set and the (-) terminal of the HVDC Test Set to substation earth as shown in Figure 5.8.

10.


Figure 5.8 Test set up for Sheath Integrity Test

11. Set the timer to 2 minute. 12. Apply 5.0 kV DC test voltage. 13. After taking all the necessary safety actions then start the measurement. 14. Stop the testing after 2 minute. 15. When the testing is completed, record the value of the identified data in the appropriate test

sheet (Refer Section 5.8). 16. Switch off the testing equipment. 17. Reconnect the earthing shield to the substation earthing. If any fault exists then it will be indicated by the high leakage current value and it would be difficult to raise the voltage to 5.0 kV. This fault can be located by sheath fault locater as discussed in Section 5.6.2. Refer Appendix 5.6 for testing equipment details.

5.6 Testing Procedure for Current Carrying Path (Phase Conductors, connectors and earthing shields)

5.6.1 Contact Resistance for Joints and Terminations 1. This test is performed for new installation or after repair. The cable should be in de-energized

condition. The test is carried out after installation of connectors and before insulation build-up of joints or terminations.

2. Clean the test leads, ferrule and lug with appropriate solvent using cloth.


3. Connect the power supply cable of the testing equipment (if applicable). 4. Connect the test leads to the C1, C2, P1 and P2 terminals of the testing equipment. 5. Make connection on to the joint/termination under test as shown in Figure 5.9.

Figure 5.9 Connection of Test Leads to Cable Joint

6. Switch on the power supply (if applicable). 7. Set the current to 100A. 8. Start the measurement. Usually an audible BLEEP will sound during this time to warn the

operator that measurement is still in progress. 9. Observe the indication as shown below:

Display Indication Action to be taken ---- Indicates Over range

Select a lower range ---- with O/C lead lighted. Indicates Open circuit

Measurement should not be made if this warning message is displayed.

10. When the measurement is completed, record the micro ohm value in the appropriate test sheet (Refer Section 5.8).

11. Switch off the testing equipment and the power supply (if applicable). 12. Repeat steps 5-11 for the remaining joints/terminations. For interpretation of results refer section 6.7.1.

Refer Appendix 5.7 for testing equipment details.

5.6.2 Continuity Test for Metallic Sheath 1. This test is performed for both new installation, in-service after repair conditions. 2. This test should be performed on de-energized cable. 3. Switching should be done by Authorised Person (AP) in accordance with TNB Safety


4. Ensure that zero voltage condition exists using phasing stick (MV) or voltage indicators (LV).

5. Make sure the other end of cable is shorted to earth. 6. This test uses multimeter with two test leads. Connect one lead at Voltage terminal and

another lead at ground.


7. Put the meter at ohm reading. 8. Check core to core continuity. In order to do that one test lead connected to Red core

and another test lead connected to Yellow core. Then change to another core until all combination listed below has been tested.

• For LV Cables, there are 6 combinations: – Red-Yellow – Red-Blue – Red-Neutral – Yellow-Blue – Yellow-Neutral – Blue-Neutral

• For MV Cables, there are 3 combinations: – Red-Yellow – Red-Blue – Yellow – Blue

9. Check continuity for each core with sheath. One test lead connected to core and another test lead connected to sheath. Repeat until all combination listed below has been tested.

• For LV Cables, there are 4 combinations: – Red-Sheath – Yellow-Sheath – Blue-Sheath – Neutral-Sheath

• For MV Cables, there are 3 combinations: – Red-Sheath – Yellow-Sheath – Blue-Sheath

10. When the measurement is completed, record the ohm value in the appropriate test sheet (Refer Section 5.8).

5.6.3 Thermography Survey for Exposed Termination 1. The measurement should be performed on energized cable. 2. Identify load conditions at time of inspection. 3. Thermographic test should be performed during periods of maximum possible loading but not

less than 40 percent of rated load of the electrical equipment being inspected. 4. Switch on the Infra Red Camera. 5. Calibrate the camera with a known source. 6. Select the appropriate emissivity for the test. 7. Adjust the focal length. 8. Shoot the laser on the phase under test. 9. Record the temperature difference between the area of concern and the reference area. 10. Save all the data that can be obtained from the camera. 11. When the measurement is completed, record the value of the identified data in the appropriate

test sheet (Refer Section 5.8). 12. Repeat steps 7-11 for other phases.


13. Produce, annotate and store thermal imaging raw data including profile with appropriate File name in accordance with guideline stated in Section 7.6.

For interpretation of results refer section 6.7.2.

5.7 Fault Location

5.7.1 Cable Fault Location The steps in a correct approach for cable fault location are in the proper sequence as follows:

• Analysis of fault • Prelocation • Pin Pointing • Confirmation and re-test

1. Collect and record all information related to the faulty cable and the circumstances. 2. Analysis of Cable Fault

• Insulation Resistance Tests in accordance with 5.3.6 • Continuity Tests in accordance with 5.5.2 • Burning of the Fault

3. Prelocation of Cable Faults

• Conventional methods of prelocation of cable faults is by bridge • The Pulse Echo, Impulse Current and Arc Reflection and Secondary Impulse

Method are working on the principle of travelling wave. 4. Bridge or Loop Method

This conventional method is largely based on various forms of bridge circuit where the DC or low frequency parameters of cables were measured. Limitations:

i. Great difficulty in detecting intermittent or flashing faults. ii. Requires very accurate & up-to-date cable route record to ensure reliable

results for fault on feeder which consists of a number of different conductor sizes or materials.

iii. Induced voltages from power plants or feeders in proximity would cause disturbance in the measuring equipment.

iv. Accuracy of the results obtained is very much affected by the test leads and contact resistance.


5. Pulse Echo Time Domain Reflectometry (TDR) Method A simple method which works on travelling wave principles. It is applicable to all series faults and for shunt faults with Rf > Zo/10 & Rf< 10Zo respectively.

6. Impulse Current Method Working on traveling wave principles, it is applicable to all types of faults. 7. Arc Reflection or Secondary Impulse Method G~ I' It)

The equipment consists of three (3) main components, i.e. the Pulse Echo Equipment (with built-in Transient Recorder), the Filter Unit and the Surge Voltage Generator.

8. Pin Pointing

The exact location of cables and conductors is an essential aspect of modern cable fault finding and helps to save existing cable networks from damage. Pin-pointing is the application of a test that positively confirms the exact position of the fault. Before the commencement of pin-pointing, the prelocated fault distance should be marked on the cable route which is measured by means of a trumeter. Pin-pointing is normally carried out by the shock wave discharge method as shown below in Figure 5.10.

9. The fault can be detected by the use of a semisphone.

Figure 5.10 Shock wave discharge 10. Confirmation & Re- Test

After the pin-pointed position of the fault has been marked & exposed, check for physical signs of fault. If there is, then the fault is confirmed. Quite often there are no physical signs, then the exposed cable or joint is confirmed again by means of the semisphone. After confirmation, the fault should be cut away, insulation resistance and continuity test should be carried out on the two remaining cable sections to determine the soundness of these cable sections. The insulation resistance & continuity tests are again carried out after jointing, followed by pressure test before supply can be restored.


Figure 5.11 Fault Location Procedure Flowchart

Details of Cable Fault Location is given in Appendix 5.8.

5.7.2 Sheath Fault Locator 1. Establish a low resistance connection between the two cores and the faulty screen at

the far end of the cable. 2. In order to carry out the measurement from one point of the cable, two healthy cores

of the same cable system are used as auxiliary leads and are connected to the faulty screen at the far end of the cable with very low resistance connection in order to keep the voltage drops occurring there at a minimum. The connection diagram is as shown in Figure 5.6.2.


3. These auxiliary leads serve as “test leads” the resistances of which do not influence

the measurement since the test current flowing to earth does not flow on them.

Figure 5.12 Sheath fault pre-location by the voltage drop method

4. Connect the MFM 5 to safety earth by means of the earthing lead supplied. 5. Switch on the MFM 5 and, in the first stage, increase the voltage until a constant

current flows – note down current value and test voltage U1. 6. As per figure 5.6.2, in the test mode 1 the DC generator feeds a current via screen and

fault resistance into the earth. 7. On the section A-B, a DC voltage drops and is measured by means of the built-in mA-

meter. One pole of the testing equipment is directly connected to A. The potential of B is fed to the testing equipment via the screen section B-C and core 1.

8. In the second stage, increase the voltage until an equal current as in stage 1 is

obtained. Note down test voltage 2. 9. In the second stage, the feed-in voltage is fed to the end of the screen via core 2. Now,

the test current flows via section C-B and the fault into the earth, whereby the resulting voltage drop reaches the testing equipment via the screen B-A on the one hand via core 1 on the other hand.

10. Calculate the fault distance by the formula mentioned below.


• A DC voltage that is connected between earth and screen, driver a current into the earth at the insulation fault.

• This current which flows through the screen from the point of entry to the point of exit, cause a voltage drop U1 on the screen.

• If this measurement is carried out from the far end of the cable, then a voltage drop U2 is present on this section of the screen.

• If the length of the cable is known, the fault distance can be calculated by a simple ratio equation into which the two component voltage U1 and U2 are to be inserted:

Lx = Lg ___U1___

U1 + U2 Lx = Fault distance Lg = Total cable length U1= Component voltage A-B U2= Component voltage C-B

11. Pinpoint Location of Sheath Faults with DC Voltage 12. Disconnect the screen from earth at both ends. Joints must be floating.

Figure 5.13 Sheath fault location with DC voltage

13. Connect the BT 500/IS or the MFM 5 to the screen of the cable and to system earth.

Use maximum 2 kV for PVC and maximum 5 kV for PE sheaths.


14. As shown in Figure 5.6.3, a DC voltage of suitable value which is connected between screen and earth, induces a current into the earth at the point of insulation damage and thus causes a voltage peak at the point of exit.

15. The measurement of this voltage peak leads to a pinpoint location of the point of

damage since the centre of the peak lies directly over the sheath fault. 16. In the practical measurement, there will be change in polarity of the voltage over the

fault. This should be borne in mind especially in the event of stray currents or the formation of electrolytic elements.

17. The use of a pulsed DC voltage is of great help since only the rate of increase is to be

evaluated on the meter. 18. Additionally, a pulsed DC voltage involves a lower thermal load at the fault, thus

avoiding damage to the insulation of the cable end neighboring cable systems during the test.

19. The two earth spikes of the ESG 80-2 are to be inserted into the earth over the track of

the cable in the pre-located area. If the earth is too hard, they can also be positioned alongside the track.

20. The use of pulsed voltage is to be recommended. In the area around the voltage peak,

a pointer deflection is visible on the meter. Now the direction and the value of increase are to be observed. If the two earth spikes are equidistant to the fault, then a Zero value will be obtained on the meter. If however an extraneous voltage is present, then the point of fault can only be recognized by the absence of the pulsed voltage. A second measurement with the earth spikes turned through 90° gives a second coordinate, thus leading to a final pinpoint location.

Details of Sheath Fault location is given in Appendix 5.9.

5.8 Test Sheet Templates


5.8.1 LV Cables Inspection and Test Data Sheet


5.8.2 MV XLPE Cables Inspection and Test Data Sheet


5.8.3 MV PILC Cables Inspection and Test Data Sheet

Chapter 6

Cable Maintenance

Testing Results’ Interpretation


6 Cable Maintenance Testing Results’ Interpretation

6.1 Background Determining the existing condition of power cables is an essential step in analyzing the risk of failure. This chapter provides a process for arriving at a Cable Condition Index. This condition index may be used as an input to the risk-and-economic analysis computer model where it adjusts cable life expectancy curves. The output of the economic analysis is a set of alternative scenarios, including costs and benefits, intended for management decisions on replacement or rehabilitation.

6.2 Condition and Data Quality Indicators and Cable Condition Index

The following condition indicators are generally regarded by TNB Distribution Division as providing a sound basis for assessing cable condition: Tier 1:

Maintenance Tests/Condition Condition Indicator Thermography 1 Tan delta 2 Insulation resistance 3 Operation and maintenance performance 4 Age 5 Tier 2:

Maintenance Test Dielectric spectroscopy

Partial discharge These indicators are based on Tier 1 tests and measurements conducted by utility staff or contractors over the course of time. The indicators are expressed in numerical terms and are used to arrive at an overall Cable Condition Index. Additional information regarding cable condition may be necessary to improve the accuracy and reliability of the Cable Condition Index. Therefore, in addition to the Tier 1 condition indicators, this Manual describes a “toolbox” of Tier 2 tests and measurements that may be applied to the Cable Condition Index, depending on the specific issue or problem being addressed. Tier 2 tests are considered non-routine. However, if Tier 2 data is readily available, it may be used to supplement the Tier 1 assessment. Alternatively, Tier 2 tests may be deliberately performed to address Tier 1 findings. Results of the Tier 2 analysis may either increase or decrease the score of the Cable


Condition Index. The Cable Condition Index may indicate the need for immediate corrective actions and/or follow-up testing. The Cable Condition Index is also suitable for use as an input to the risk-and-economic analysis model. This manual assumes that tests and measurements are conducted and analyzed by staff suitably trained and experienced in cable diagnostics. In the case of more basic tests, this may be qualified staff those who are competent in these routine procedures. More complex tests and measurements may require a cable diagnostics “experts”. This manual also assumes that tests and measurements are conducted on a frequency that provides accurate and current information needed by the assessment. It will be necessary to conduct tests prior to this assessment to acquire current data. Results of the cable condition assessment may cause concern that justifies more frequent monitoring. TNB DISTRIBUTION DIVISION should consider the possibility of taking more frequent measurements or the installation of on-line monitoring systems that will continuously track critical parameters. This will provide additional data for condition assessment and establish a certain amount of reassurance as cable alternatives are being explored. Note: A zero score of ANY Tier 1 test or measurement may be adequate in itself to require immediate call for Tier 2 test to be conducted. A negative Total Cable Condition Index Value would require immediate de-energization, or prevent re-energization, and planning for replacement.

6.3 Scoring Cable condition indicator scoring is somewhat subjective, relying on cable condition experts. Relative terms are used and compared according to industry accepted levels; or to baseline or previous (acceptable) levels on this cable; or to cable of similar design, construction, or age operating in a similar environment.

6.4 Weighting Factors Weighting factors used in the condition assessment methodology recognize that some condition indicators affect the Cable Condition Index to a greater or lesser degree than other indicators. These weighting factors were arrived at by consensus among cable design and maintenance personnel with extensive experience.

6.5 Mitigating Factors Every cable is unique and, therefore, the methodology described in this chapter cannot quantify all factors that affect individual cable condition. It is important that the Cable Condition Index arrived at is scrutinized by engineering experts. Mitigating factors specific to


the utility may determine the final Cable Condition Index and the final decision on cable replacement or rehabilitation.

6.6 Documentation Substantiating documentation is essential to support findings of the assessment, particularly where a condition indicator score is less than 3 (i.e., less than normal). Test results and reports, photographs, O&M records, or other documentation should accompany the Cable Condition Assessment Summary Form.

6.7 Condition Assessment Methodology The condition assessment methodology consists of analyzing each condition indicator individually to arrive at a condition indicator score. The scores are then weighted and summed to determine the Tier 1 Cable Condition Index. The Tier 1 Cable Condition Index is then adjusted by data quality adjustment score to arrive at final Tier 1 Cable Condition Index value. The final Tier 1 Cable Condition Index is applied to the Cable Condition-Based Alternatives in Table 6.10, to determine the recommended course of action. Reasonable efforts should be made to perform Tier 1 tests and measurements. The Tier 2 tests will be performed based on Cable Condition-Based Alternatives. The Tier 2 adjustment scores will further modify the final Tier 1 Condition Index value to arrive at the Total Cable Condition Index value. The Total Cable Condition Index value is applied to the cable condition based alternatives in Table 6.14. This strategy must be used judiciously to prevent erroneous results and conclusions. An example of the above methodology for MV cables is illustrated in Figure 6.1.


Figure 6.1 Flowchart for Calculating Cable Condition Index


6.8 Tier 1 Condition Indicators of MV XLPE and PILC Cables

6.8.1 Contact Resistance Contact resistance is the most important factor in determining the condition of the terminations/joints because, being performed at the time of commissioning or after repair. These tests can identify internal arcing, bad electrical contacts, hot spots, partial discharge, or overheating of conductors. The “health” of the connections is reflective of the health of the cable itself. Results of the contact resistance analyses are applied to Table 6.1 to arrive at an appropriate mitigating action.

Table 6.1 Contact Resistance This test is done during installation. If any concern identified then it is rectified before putting the cable into service. Therefore this test results are not consider for condition assessment while the

cable is in service. Results Score Remarks/Action

Less than 50 µΩ in all the phases

- The connection is healthy and can be put into service

> 50 µΩ but less than 100 µΩ in any particular phase or all the phases

- The connection can be put into service with caution

> 100 µΩ in any particular phase or all the phases

- The connection must be replaced

6.8.2 Cable Condition Indicator 1 – Thermography Thermography is important factor in determining the condition of the exposed terminations because, being performed periodically it may be the first indication of a problem. These tests can identify internal arcing, bad electrical contacts, hot spots, partial discharge, or overheating of conductors. The “health” of the connections is reflective of the health of the cable itself.

Table 6.2 Thermography This test is done on exposed terminations during cable in-service at every 24 months interval

under normal condition. This test results are considered for condition assessment while the cable is in service.

Results Score Action The hot spot temperature difference between phases is

3 Normal. The monitoring frequency of 24 months can be


less than 5 degree centigrade maintained. The hot spot temperature difference between phases is > 5 degree centigrade but less than 10 degree centigrade

2 The monitoring frequency should be revised to 12 months.

The hot spot temperature difference between phases is > 10 degree centigrade but less than 20 degree centigrade


The hot spot temperature difference between phases is > 20 degree centigrade

0 Remove the cable from service and perform tan delta tests immediately.

6.8.3 Cable Condition Indicator 2 – Tan Delta Test

Table 6.3 Tan delta This test is done on cables at regular interval of 24 months under normal condition. This test

results are considered for condition assessment while the cable is in service.

Results Score Action XLPE: tan δ (2 U0) < 1.2 E-3 and [tan δ (2 U0) - tan δ (U0)] < 0.6 E-3 PILC: tan δ (50Hz) < 2.3 E-3

3 Normal. The monitoring frequency of 24 months can be maintained.

XLPE: 1.2 E-3 ≥ tan δ (2 U0) < 2.2 E-3 and 0.6 E-3 ≥ [tan δ (2 U0) - tan δ (U0)] < 1.0 E-3 PILC: 2.3 E-3 < tan δ (50Hz) < 3.0 E-3


XLPE: 2.2 E-3 ≥ tan δ (2 U0) < 2.8 E-3 and 1.0 E-3 ≥ [tan δ (2 U0) - tan δ (U0)] < 1.5 E-3 PILC: 3.0 E-3 < tan δ (50Hz) < 3.5 E-3



Results Score Action XLPE: tan δ (2 U0) ≥ 2.8 E-3 or [tan δ (2 U0) - tan δ (U0)] ≥ 1.5 E-3 PILC: tan δ (50Hz) ≥ 3.5 E-3

0 Remove the cable from service and perform Tier 2 tests (whichever applicable) immediately.

6.8.4 Cable Condition Indicator 3 – Insulation resistance test

Table 6.4 Insulation resistance This test is done on cables at regular interval of 24 months for MV cables and 60 months for LV cables under normal condition. This test results are considered for condition assessment while the

cable is in service.

Results Score Action XLPE: DAR value ≥ 1.6 PILC: PI value ≥ 3.0

3 Normal. The monitoring periodicity of 24 months for MV cables and 60 months for LV cables can be maintained.

XLPE: 1.1 < DAR value < 1.5 PILC: 1.5 < PI value < 3.0

2 The monitoring periodicity should be revised to 6 months for MV cables and 24 months for LV cables.

XLPE: 1.0 < DAR value < 1.1 PILC: 1.0< PI value < 1.5

1 The monitoring periodicity should be revised to 3 months for MV cables and 12 months for LV cables.

XLPE: DAR value < 1.0 PILC: PI value < 1.0

0 Remove the Cable from service and perform Tier 2 tests (if applicable) immediately for MV cable. Replace LV cables.


6.8.5 Cable Condition Indicator 4 – Operation and Maintenance Performance

Operation and maintenance (O&M) history may indicate overall cable condition. O&M history factors that may apply are:

• Sustained overloading. • Abnormal temperatures indicated by infrared scanning. • Nearby lightning strikes or through-faults. • Abnormally high partial discharge detected. • Increase in breakdown maintenance or difficulty in acquiring spare parts. • Anomalies determined by physical inspection • Previous failures on this cable. • Failures or problems on cable of similar design, construction, or age operating in a

similar environment. Qualified personnel should make a subjective determination of scoring that encompasses as many operation and maintenance factors as possible under this Indicator. Results of the O&M history are analyzed and applied to Table 6.5 to arrive at an appropriate Condition Indicator Score.

Table 6.5 Operation and Maintenance Performance Scoring Results Score Action

Operation and Maintenance are normal

3 -

Some abnormal operating conditions experienced and/ or additional maintenance above normal occurring

2 -

Significant operation outside normal and/or significant additional maintenance is required.

1 -

Severe abnormal operating conditions experienced and/ or additional maintenance above normal occurring

0 -

6.8.6 Cable Condition Indicator 5 – Age Cable age is an important factor to consider when identifying candidates for cables replacement. Age is one indicator of remaining life and upgrade potential to current state-of-the-art materials. During the life of the cable, the insulating properties of materials which are used for electrical insulation, especially XLPE, deteriorate. Although actual service life varies


widely depending on the manufacturer’s design, quality of assembly, materials used, operating history, current operating conditions, and maintenance history, the average expected life for a large population of cables is statistically about 40 years. Apply the cable age to Table 6.6 to arrive at the Condition Indicator Score.

Table 6.6 Age Scoring Results Score Action

XLPE: Under 10 years PILC: Under 20 years

3 -

XLPE: Between 11 to 20 years PILC: Between 21 to 30 years

2 -

XLPE: Between 21 to 30 years PILC: Between 31 to 40 years

1 -

XLPE: Above 30 years PILC: Above 40 years

0 -

6.8.7 Tier 1 ‐ Cable Condition Index Calculations Enter the condition indicator scores from the tables above into the Cable Condition Assessment Summary form at the end of this Chapter. Multiply each condition indicator score by the Weighting Factor, and sum the Total Scores to arrive at the Tier 1 Cable Condition Index. The value of the individual weighting factor of the Tier 1 Condition Indicator is determined by the expert. The sum of all the weighting factors should be equal to 3.33.

Table 6.7 Tier 1 Cable Condition Index No Condition Indicator Score Weighting

Factor Total Score

1 Thermography 0.70 2 Tan Delta 0.80 3 Insulation Resistance 1.00

4 Operation and Maintenance Performance

0.53


No Condition Indicator Score Weighting Factor

Total Score

5 Age 0.30 Tier 1 Cable Condition Index

(Sum of Individual Total score) (Condition Index should be between 0 and 10)

6.8.8 Tier 1 – Cable Data Quality Indicator The Cable Data Quality Indicator reflects the quality of the test and measurement results used to evaluate the cable condition under Tier 1. The more current and complete the tests and measurements, the higher the rating for this indicator. The normal testing frequency is defined as the organization’s recommended frequency for performing the specific test or inspection. Qualified personnel should make a subjective determination of scoring that encompasses as many factors as possible under this indicator. Results are analyzed and applied to Table 6.8 to arrive at a Cable Data Quality Indicator Score.

Table 6.8 Cable Data Quality Indicator Scoring Results Score Adjustment Action

All Tier 1 testing equipment were calibrated within the recommended calibration frequency AND results are reliable.

Subtract 0 -

One or more of the Tier 1 testing equipment were calibrated between 0 and 6 months past the recommended calibration frequency.

Subtract 0.5 -

One or more of the Tier 1 testing equipment were calibrated between 6 and 12 months past the recommended calibration frequency.

Subtract 1.0 -

One or more of the Tier 1 testing equipment were calibrated more than 12 months past the recommended calibration frequency.

Subtract 1.5 -

The Tier 1 Cable Condition Index is adjusted by the Cable Data Quality Indicator Score to attain the final Tier 1 Cable Condition Index Value as shown in Table 6.9.

Table 6.9 Final Tier 1 Cable Condition Index Value No Condition Indicator Score Weighting

Factor Total Score

1 Thermography 0.70 2 Tan Delta 0.80 3 Insulation Resistance 1.00 4 Operation and Maintenance History 0.53 5 Age 0.30


No Condition Indicator Score Weighting Factor

Total Score

Tier 1 Cable Condition Index (Sum of Individual Total score) (Condition Index should be between 0 and 10)

6 Cable Data Quality Indicator Score Adjustment (value can be 0, -0.5 ,-1.0 or -1.5)

Final Tier 1 Cable Condition Index Value (Condition Index should be between 0 and 10)

Based on the final Tier 1 Cable Condition Index Value the suggested recommendations on the testing frequency of Tier 1 and proposal for Tier 2 tests are mentioned below in Table 6.9.

Table 6.10 Cable Tier 1 Condition-Based Alternatives Final Tier 1 Cable Condition Index Value Suggested Course of Action

≥ 7.0 and ≤ 10.0 (Good) Maintain the normal frequency of Tier 1 test. ≥ 3.0 and < 7.0 (Fair) Revise frequency of Tier 1 tests to 6 months

interval. Make arrangements for Tier 2 tests. ≥ 0.0 and < 3.0 (Poor) Perform Tier 2 tests immediately.

6.9 Tier 2 – Tests and Measurements of MV XLPE and PILC Cables

Tier 2 tests and measurements generally require specialized equipment or training, may require an extended outage to perform. A Tier 2 assessment is not considered routine. Tier 2 inspections are intended to affect the Cable Condition Index number established using Tier 1 but also may confirm or refute the need for more extensive maintenance, rehabilitation, or cable replacement. Note that there are many tests that can give information about the various aspects of cable condition. The choice of tests should be made based on known information gathered by O&M history, other test results, company standards, and Tier 1 assessment. Many Tier 2 tests are used to detect or confirm a defect in the cable. Since Tier 2 tests are being performed by, and/or coordinated with, knowledgeable technical staff, the decision on which test is most significant and how these tests overlap in application is left to the experts. For Tier 2 evaluations, apply only the applicable adjustment factors per the instructions above and recalculate the Cable Condition Index using the Cable Condition Assessment Survey Form at the end of section 6.8. An adjustment to the Data Quality Indicator score may be appropriate if additional information or test results were obtained during the Tier 2 assessment.


6.9.1 Partial Discharge Test This test is performed with the cable de-energized and may show the necessity for further investigation on the location of the defects or removal from service. Results are analyzed and applied to Table 6.10 to arrive at a Cable Condition Index adjustment.

Table 6.11 Partial Discharge Test Score Adjustment Results Score Adjustment Action

Severity Index < 2 Subtract 0 Normal. The monitoring periodicity of all Tier 1 tests can be maintained at 24 months. Practice partial discharge test if necessary.

2 < Severity Index < 5

Subtract 0.5 Retest the cable for partial discharge after 6 months. The monitoring periodicity of all Tier 1 tests should be revised to 6 months.

5 < Severity Index < 7 Subtract 1.0 Retest the cable for partial discharge after 3 months. Arrange for replacement of defective section(s).

Severity Index > 7 Subtract 1.5 Indicates serious problem requiring immediate evaluation, additional testing and consultation with experts. Recommendation is to remove from service immediately and replace the cable.

6.9.1.1 Severity Index Calculation The related parameters are shown in equations 6.1 – 6.6.

K=k1*k2………….………….. Equation ( 6.1)

k1 = Vi/Vo………….………….. Equation ( 6.2)

k2 = Ve/Vo………….………….. Equation ( 6.3)

where, k1 = Inception Voltage Factor k2 = Extinction Voltage Factor Vi = Inception Voltage Ve = Extinction Voltage Vo = Phase Voltage

A = Qm/Qa………….………….. Equation ( 6.4)

where, A = Discharge Factor Qm = Maximum Discharge Qa = Average Discharge


D = Nm/NT………….………….. Equation ( 6.5)

where, D = Density Factor Nm = Number of Discharges @ L ± 10m NT = Total Number of Discharges L = Location of Highest Discharge

S = (A·D)/K………….………….. Equation ( 6.6)

where, S = Severity Factor K = Critical Factor

6.9.2 Dielectric Spectroscopy Test This test is performed with the cable de-energized and may show the necessity for further investigation on the location of the defects or removal from service. Results are analyzed and applied to Table 6.12 to arrive at a Cable Condition Index adjustment.

Table 6.12 Dielectric Spectroscopy Test Score Adjustment Results Score Adjustment Action

XLPE: Good response: No significant gap between the frequency sweep responses at different voltages. PILC: % Moisture Content < 0.5

Subtract 0 Normal. The monitoring periodicity of all Tier 1 tests can be maintained at 24 months. Practice partial discharge test if necessary.

XLPE: Non deteriorated response: Significant gap between the frequency sweep responses at different voltages with no hysteresis effect. PILC: 0.5 < % Moisture Content < 2.0

Subtract 0.5 Retest the cable for dielectric spectroscopy after 6 months. The monitoring periodicity of all Tier 1 tests should be revised to 6 months.

XLPE: Voltage dependent response: Significant gap between the frequency sweep responses at different voltages with hysteresis effect. PILC: 2.0 < % Moisture Content < 2.5

Subtract 1.0 Retest the cable for Dielectric Spectroscopy after 3 months. Arrange for replacement of defective section(s).


Results Score Adjustment Action XLPE: Leakage current response: Wide gap between the frequency sweep responses at different voltages with hysteresis and leakage current effects. PILC: % Moisture Content > 2.5

Subtract 1.5 Indicates serious problem requiring immediate evaluation, additional testing and consultation with experts. Recommendation is to remove from service immediately and replace the cable.

The sample examples of Non-Deteriorated, Voltage Dependent and Leakage Current responses are illustrated in section 7.5.1.

6.9.3 Tier 2 – Total Cable Condition Index Calculations Enter the Tier 2 adjustments from the tables above into the Total Cable Condition Index Value Form as shown in Table 6.12. Subtract the sum of these adjustments from the Final Tier 1 Cable Condition Index to arrive at the Total Cable Condition Index. The value of the individual weighting factor of the Tier 1 Condition Indicator is determined by the expert. The sum of all the weighting factors should be equal to 3.33.

Table 6.13 Total Cable Condition Index Value No Condition Indicator Score Weighting Factor Total Score 1 Thermography 0.70 2 Tan Delta 0.80 3 Insulation Resistance 1.00 4 Operation and Maintenance

Performance 0.53

5 Age 0.30 Tier 1 Cable Condition Index

(Sum of Individual Total score) (Condition Index should be between 0 and 10)

6 Cable Data Quality Indicator Score Adjustment (value can be 0, -0.5, -1.0 or -1.5)

Final Tier 1 Cable Condition Index Value (Condition Index should be between 0 and 10)

7 Tier 2 Partial Discharge Score Adjustment (value can be 0, -0.5, -1.0 or -1.5)

8 Tier 2 Dielectric Spectroscopy Score Adjustment (value can be 0, -0.5, -1.0 or -1.5)

Total Cable Condition Index Value (Condition Index should be between 0 and 10) A negative Total Cable Condition Index Value would require immediate de-energization, or prevent re-energization, and planning for replacement.


6.10 Combined Tier 1 and Tier 2 Cable Condition‐Based Alternatives

The Cable Condition Index – either modified by Tier 2 tests or not – may be sufficient for decision making regarding cable condition based alternatives as shown in the Table 6.14. The Index is also suitable for use in the risk and-economic analysis model, which will be discussed in the Maintenance Planning Manual.

Table 6.14 Cable Condition Based Alternatives Total Cable Condition Index Value Suggested Course of Action

≥ 7.0 and ≤ 10.0 (Good) Continue O&M without restriction. Maintain the normal frequency of Tier 1 test. Repeat Tier 2 test as needed.

≥ 3.0 and < 7.0 (Fair) Repeat both Tier 1 & Tier 2 test after 6 months from this condition assessment activity.

≥ 0.0 and < 3.0 (Poor) Reduce the load based on expert judgment and arrange for replacement of section(s). If necessary online condition assessment such as partial discharge monitoring can also be undertaken while waiting for the replacement.

Chapter 7

Record Management of

Cable Maintenance

Testing Results


7 Record Management of Cable Maintenance Testing Results

7.1 Background This section of the manual deals with the record management of various identified tests. Tests that generate waveforms and processed data are archived either in floppy drive or in separate server. The processed data are transferred to CMMS via recommended test data sheet. The tests that yield numerical data are directly fed into the CMMS via recommended test data sheet.

7.2 Flow Chart for Record Management of Raw Waveform and Processed Data

The raw waveforms of PD VLF, PD OWTS, DS and Thermography image are saved using unique file name for each cable circuit. These waveforms can only be read with the help of analyzing software provided by the testing equipment manufacturers. The saved raw waveforms should be archived either in floppy drives or in a separate server. The raw waveforms are further processed using the respective analyzing software to obtain “processed data”. These processed data usually presented in tabular form and are possible to be copied and pasted in either as word document or excel document. The data from these processed data are then extracted and filled into the recommended test data sheet for further processing by the Computerized Maintenance Management Software (CMMS). The CMMS also has input from other tests such as IR and Tan Delta via test data sheet as shown in the Figure 7.1.


Figure 7.1 Flow Chart of Raw Waveform and Processed Data


7.3 Record Management of Raw Waveform and Processed Data of VLF PD

The sample raw waveforms of VLF PD test is shown in Figure 7.2 below. These raw data waveforms for all the phases should be saved with appropriate filenames and stored either in floppy drives or in a separate server. These raw waveforms can only be viewed using the appropriate analyzing software provided by the manufacturer of the testing equipment.

Figure 7.2 Raw Waveform of PD VLF

The above three pulse raw waveforms are further processed by the analyzing software to generate the PD mapping plot and several PD parameters such as amplitude, counts and location. A sample of such output data is shown in the Figure 7.3. The numerical values of the identified parameters can be extracted from the following processed output and can be recorded into the test data sheet. After this these values can be keyed into CMMS for interpretation. The periodicity of archiving the test data sheet information should be same as the service life of the respective cables.


Figure 7.3 Processed Data (PD Mapping) of PD VLF

7.4 Record Management of Raw Waveform and Processed Data of OWTS PD

The sample raw waveforms of OWTS PD test is shown in Figures 7.4 and 7.5 below. These raw data waveforms for all the phases should be saved with appropriate filenames and stored either in floppy drives or in a separate server. These raw waveforms can only be viewed using the appropriate analyzing software provided by the manufacturer of the testing equipment.


Figure 7.4 Raw Waveform of OWTS PD


Figure 7.5 Raw Waveform of OWTS PD

The above three pulse raw waveforms are further processed by the analyzing software to generate the PD mapping plot and several PD parameters such as amplitude, energy, counts and location. A sample of such output data is shown in the Figure 7.6 and Figure 7.7. The numerical values of the identified parameters can be extracted from the following processed output and can be recorded into the test data sheet. After this these values can be keyed into CMMS for interpretation. The periodicity of archiving the test data sheet information should be same as the service life of the respective cables.


Figure 7.6 Processed Data (PD Mapping) of OWTS PD

Figure 7.7 Processed Data (Histogram) of OWTS PD


7.5 Record Management of Raw Waveform and Processed Data of DS

The sample raw waveform of the DS test is shown in Figure 7.8 below. These raw data waveforms for both XLPE and PILC should be saved with appropriate filenames and stored either in floppy drives or in a separate server. These raw waveforms can only be viewed using the appropriate analyzing software provided by the manufacturer of the testing equipment.

7.5.1 XLPE The sample raw waveforms of DS test of XLPE Cables for non deteriorated response, voltage dependent response and leakage current response are shown below in Figures 7.8, 7.9, 7.10, and 7.11.

Figure 7.8 Raw Waveform (Good Response) of XLPE DS


Figure 7.9 Raw Waveform (Non Deteriorated Response) of XLPE DS

Figure 7.10 Raw Waveform (Voltage Dependent Response) of XLPE DS


Figure 7.11 Raw Waveform (Leakage Current Response) of XLPE DS

The above raw waveforms are further processed by the analyzing software to generate the deviation between the frequency sweeps at different voltages and also the hysterisis effect. A sample of such output data is shown in the Table 7.1. The numerical values of the identified parameters can be extracted from the following processed output and can be recorded into the test data sheet. After this these values can be keyed into CMMS for interpretation. The periodicity of archiving the test data sheet information should be same as the service life of the respective cables.

Table 7.1 Processed Data of XLPE DS Response Gap between the frequency

sweep responses at different voltages

Hysterisis Effect

Leakage Current Effect

Good response No No No

Non deteriorated response Yes No No Voltage Dependent response Yes Yes No Leakage Current response Yes Yes Yes

7.5.2 PILC The sample raw waveform of the DS test for PILC Cable is shown in Figure 7.11 below. These raw data waveforms should be saved with appropriate filenames and stored either in floppy drives or in a separate server. These raw waveforms can only be viewed using the appropriate analyzing software provided by the manufacturer of the testing equipment.


Figure 7.12 Raw Waveform of PILC DS

The above raw waveforms are further processed by the analyzing software to generate the moisture content in paper insulation. To estimate the moisture content of paper insulation, several internal files are used by the software to extract the required information. A sample of such output analysis is shown in the Figure 7.13. The numerical values of the identified parameters can be extracted from the following processed output and can be recorded into the test data sheet. After this these values can be keyed into CMMS for interpretation. The periodicity of archiving the test data sheet information should be same as the service life of the respective cables.


Figure 7.13 Processed Data (Moisture Content) of PILC DS

7.6 Record Management of Raw Waveform and Processed Data of Thermography

The sample raw waveform of the Thermography image for exposed Cable Terminations is shown in Figure 7.14 below. These raw data waveforms should be saved with appropriate filenames and stored either in floppy drives or in a separate server. These raw waveforms can only be viewed using the appropriate analyzing software provided by the manufacturer of the testing equipment.


Figure 7.14 Raw Waveform of Thermography

The above raw waveforms are further processed by the analyzing software to generate the temperature by the software using several internal files. A sample of such output analysis is shown in the Figure 7.15. The numerical values of the identified parameters can be extracted from the following processed output and can be recorded into the test data sheet. After this these values can be keyed into CMMS for interpretation. The periodicity of archiving the test data sheet information should be same as the service life of the respective cables.

Figure 7.15 Processed Data of Thermography


7.7 Record Management of IR and Tan Delta The test data for IR and Tan Delta are numerical values and can be recorded directly into the test data sheet without further processing. After this these values can be keyed into CMMS for interpretation. The periodicity of archiving the test data sheet information should be same as the service life of the respective cables.

TNB Cable Maintenance Manual

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