TNB Cable Maintenance Manual

TNB Distribution Division Maintenance Manual : Underground Cable System

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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 inhouse 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 AC AM ASTM BS CBM CM CMMS CRO CTC CTCs DC DGA DS emf EPDM ERMS F FMECA GIS HV HVDC Hz IEC IEEE IR km kV LGB LV MIL-STD MTBF MV NASA nC O&M O/C OWTS pC PD PDEV PDIV PE PILC

Ampere Alternating Current Ampere Meter American Society for Testing and Materials British Standard Condition Based Maintenance Condition Monitoring Computerised Maintenance Management System Cathode Ray Oscilloscope Critical Technology Challenges Critical Technological Challenges Direct Current Dissolve Gas Analysis Dielectric Spectroscopy Electro Magnetic Field Ethylene Propylene Diane Monomer Enterprise Resource Management System Farad Failure Mode Effect And Criticality Analysis Geographical Information System High Voltage High Voltage Direct Current Hertz International Electrotechnical Commission Institute of Electrical Electronic Engineer Insulation Resistance kilometre Kilo Volt Laporan Gangguan Bekalan Low Voltage United States America Military Standard Mean Time Between Failures Medium Voltage National Aeronautics and Space Administration Nano Coulomb Operation and Maintenance Open Circuit Oscillating Wave Testing System Pico Coulomb Partial Discharge Partial Discharge Extinction Voltage Partial Discharge Inception Voltage Polyethylene Paper Insulated Lead Cable

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___________________________________________________________________________ PM PRN PT&I PVC RCM RPN SCADA SF6 TDR UG VLF VM XLPE

Preventive Maintenance Probability Risk Number Predictive Testing And Inspection Poly Vinyl Chloride Reliability Centred Maintenance Risk Priority Number Supervisory Control And Data Acquisition Sulphuric Hexafluoride Time Domain Reflectrometry Underground Very Low Frequency Volt Meter 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

1.3.1

Transformers ......................................................................................................19

1.3.2

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

1.4 2

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

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

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 3

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

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 5

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

Cable Maintenance Testing Procedure ............................................................................72 5.1

Background ...............................................................................................................72

5.2

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

5.2.1 5.3

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

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

5.7.1

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

5.7.2

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

5.8

6

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

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

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 6.9

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

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

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.

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___________________________________________________________________________ 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

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___________________________________________________________________________ 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 deenergized. 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

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___________________________________________________________________________ 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 runto-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.

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.

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.

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.

2

3

4

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___________________________________________________________________________ Ranking

5

Effect

Consequence

Catastrophic

Will produce death or multiple death or injuries, or the impact on operations will be disastrous, resulting in longterm 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

Equipment Item Number

Medium Voltage Circuit Breaker, Vacuum

Medium Voltage Circuit Breaker, SF6

Periodicity By Criticality Rank

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

PT&I-08

Power Factor Test

3A

3A

A

Brkr-03

Inspect and Test SF6 Circuit Breaker

3A

3A

A

PT&I-05

Test Insulation

3A

3A

A

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___________________________________________________________________________ Periodicity Codes The Periodicity Codes used by NASA are described below: D W M Q S A OC

= = = = = = =

Daily Weekly Monthly Quarterly Semi-Annually Annually 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.

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___________________________________________________________________________ •

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.

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___________________________________________________________________________

1.4 TNB Distribution Division’s journey toward Best  Maintenance Practice   The main follows: • • • •

themes for the TNB Electricity Technology Roadmap have been postulated as 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.

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___________________________________________________________________________ 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

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___________________________________________________________________________

Chapter 2

Maintenance Management

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___________________________________________________________________________

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. Third Generation

Second Generation First Generation • Fix it when it is broken

1940

1950

• Higher plant availability • Longer equipment life • Lower costs

1960

1970

• • • • •

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

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

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___________________________________________________________________________ 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.

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___________________________________________________________________________

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

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___________________________________________________________________________ • •

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 agereliability (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)

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___________________________________________________________________________

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

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___________________________________________________________________________ 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

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___________________________________________________________________________ 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):

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___________________________________________________________________________ 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. 1. 2. 3.

4.

5.

6.

7.

Task Description In the first column a unique reference is assigned to a functional element. The functions of the element are listed in the second column. Functions are also categorized according to various operational modes for the element. 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. 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. 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. In some cases consequences such as safety consequences, environmental consequences, operational consequences and economic consequences are also listed in separate columns in the worksheet. 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 10 7-9 4-6 1-3

8.

The likelihood that the failure will be detected is then listed in column six. An example of detectability ranking is given below: Rank 1-2 3-4 5-7 8-9 10

9.

Description Catastrophic Failure results in major injury or death of personnel. Critical Failure results in minor injury to personnel. Major Failure results in a low level of exposure to personnel, or activates alarm system. Minor Failure results in minor system damage but does not cause injury to personnel.

Description Very high probability that the defect will be detected High probability that the defect will be detected Moderate probability that the defect will be detected Low probability that the defect will be detected Very low (or zero) probability that the defect will be detected

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

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___________________________________________________________________________ An example of a classification is shown below: Rank Very unlikely Remote Occasional Probable Frequent

10. 11.

12.

Description Once in 1000 years Once in 100 years Once in 10 years Once per year 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. 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. 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. 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

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___________________________________________________________________________ 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

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___________________________________________________________________________ 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 PF 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

Cable Asset Category

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___________________________________________________________________________

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 Cables

Types

Size 630mm 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 185 mm2 3 core Copper 70 mm2 3core Aluminium 185 mm2 3core Aluminium 400 mm2 3core Aluminium 70 mm2 1core Aluminium 150 mm2 1core Aluminium 240 mm2 1core Aluminium 500 mm2 1core Aluminium 25 mm2 3core Aluminium 75 mm2 3core Aluminium 120 mm2 3core Aluminium 185 mm2 3core Aluminium 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 240 mm2 3core Aluminium 2

33kV

XLPE

PILC 22kV XLPE

PILC

11kV XLPE

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___________________________________________________________________________ Category

Types

Size 300 mm 1core Aluminium 500 mm2 1core Aluminium 500 mm2 1core Copper 630 mm2 1core Copper 25 mm2 4core Aluminium 70 mm2 4core Aluminium 120 mm2 4core Aluminium 185 mm2 4core Aluminium 300 mm2 4core Aluminium 25 mm2 4core Aluminium 70 mm2 4core Aluminium 120 mm2 4core Aluminium 185 mm2 4core Aluminium 300 mm2 4core Aluminium 630mm2 1 core Aluminium 500mm2 1 core Copper 70 mm2 3core Aluminium 185 mm2 3core Aluminium 400 mm2 3core Aluminium 70 mm2 1core Aluminium 150 mm2 1core Aluminium 240 mm2 1core Aluminium 500 mm2 1core Aluminium 120 mm2 3core Aluminium 185 mm2 3core Aluminium 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 240 mm2 3core Aluminium 630mm2 1 core Aluminium 500mm2 1 core Copper 70 mm2 3core Aluminium 185 mm2 3core Aluminium 400 mm2 3core Aluminium 70 mm2 1core Aluminium 150 mm2 1core Aluminium 240 mm2 1core Aluminium 500 mm2 1core Aluminium 2

PVC

LV

XLPE

PILC

33kV

XLPE PILC

22kV XLPE Termination PILC

11kV XLPE

Joints

33kV

XLPE PILC

22kV XLPE

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___________________________________________________________________________ Category

Types

Size 120 mm 3core Aluminium 185 mm2 3core Aluminium 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 240 mm2 3core Aluminium 185 mm2 - 150 mm2 3core 185mm2 - 240 mm2 3core 400 mm2 - 240 mm2 3core 400 mm2 - 500 mm2 3core 120 mm2 - 95 mm2 3core 185 mm2 - 150 mm2 3core 300 mm2 - 240 mm2 3core 2

PILC

11kV XLPE

22 kV

PILC - XLPE

11kV

PILC - XLPE

Transition Joints

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.

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No. 1. 2. 3. 4. 5. 6.

Designation Conductor Conductor screen Insulation Insulation screen Metallic sheath Outer protection

Insulation

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.

No. 1. 2. 3. 4. 5. 6. 7. 8.

Designation Conductor Conductor screen Insulation Insulation screen Metallic sheath Filler Core wrapping Outer sheath

Insulation

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).

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___________________________________________________________________________

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

No. 1. 2. 3. 4. 5. 6.

Designation Conductor Conductor screen Insulation Insulation screen Metallic sheath Outer protection

Insulation

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.

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___________________________________________________________________________

No. 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.

Designation Stranded aluminium conductor Paper insulation Filler paper Manufacturer label PVC tape Bedding Textile serving Perforated metallic Jute fillers Copper-woven fabric tape Lead sheath Voltage label 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.

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___________________________________________________________________________

No. 1. 2. 3. 4. 5.

Designation Sheath Binder tape Filler Insulation 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. 1. 2. 3. 4. 5. 6. 7.

Designation Conductor Insulation Filler Core Wrapping Inner Sheath Metallic Screen 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).

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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

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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.

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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

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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 Hazardous (without warning) Hazardous (with warning) Very high High Moderate Low Very low Minor Very minor None

Severity of Effect Very high severity ranking when a potential failure mode affects safe system operation without warning Very high severity ranking when a potential failure mode affects safe system operation with warning System inoperable with destructive failure without compromising safety System inoperable with equipment damage System inoperable with minor damage System inoperable without damage System operable with significant degradation of performance System operable with some degradation of performance System operable with minimal interference No effect

Ranking 10 9 8 7 6 5 4 3 2 1

Table 3.4 Failure Probability Ranking and Definition

Failure Probability

Failure Probability in 1 Year

Ranking

Very High: Failure is almost inevitable

>1 in 2

10

1 in 3

9

1 in 8

8

1 in 20 1 in 80 1 in 400 1 in 2,000 1 in 15,000 1 in 150,000 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.

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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.

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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 mAmeter. 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.

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___________________________________________________________________________ • • • •

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.

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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 

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5.8.1 LV Cables Inspection and Test Data Sheet 

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5.8.2 MV XLPE Cables Inspection and Test Data Sheet 

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5.8.3 MV PILC Cables Inspection and Test Data Sheet 

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Chapter 6

Cable Maintenance Testing Results’ Interpretation

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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 Thermography Tan delta Insulation resistance Operation and maintenance performance Age

Condition Indicator 1 2 3 4 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 nonroutine. 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

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___________________________________________________________________________ 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

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___________________________________________________________________________ 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.

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Figure 6.1 Flowchart for Calculating Cable Condition Index

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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 The connection is healthy and phases can be put into service > 50 µΩ but less than 100 µΩ The connection can be put into in any particular phase or all service with caution the phases > 100 µΩ in any particular The connection must be phase or all the phases 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 Normal. The monitoring 3 difference between phases is frequency of 24 months can be

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

2

maintained. The monitoring frequency should be revised to 12 months.

1

The monitoring frequency should be revised to 3 months.

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 XLPE: tan δ (2 U0) < 1.2 E-3 and [tan δ (2 U0) - tan δ (U0)] < 0.6 E-3

Score 3

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

2

The monitoring frequency should be revised to 6 months.

1

The monitoring frequency should be revised to 3 months.

PILC: tan δ (50Hz) < 2.3 E-3 XLPE: 1.2 E-3 ≥ tan δ (2 U0) < 2.2 E3 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 E3 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

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___________________________________________________________________________ Results

Score

Action

XLPE: tan δ (2 U0) ≥ 2.8 E-3 or [tan δ (2 U0) - tan δ (U0)] ≥ 1.5 E-3

0

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

PILC: tan δ (50Hz) ≥ 3.5 E-3

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 XLPE: DAR value ≥ 1.6

Score 3

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

2

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

1

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

0

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

PILC: PI value ≥ 3.0 XLPE: 1.1 < DAR value < 1.5 PILC: 1.5 < PI value < 3.0 XLPE: 1.0 < DAR value < 1.1 PILC: 1.0< PI value < 1.5 XLPE: DAR value < 1.0 PILC: PI value < 1.0

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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 3 are normal Some abnormal operating 2 conditions experienced and/ or additional maintenance above normal occurring Significant operation outside 1 normal and/or significant additional maintenance is required. Severe abnormal operating 0 conditions experienced and/ or additional maintenance above normal occurring

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-ofthe-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

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___________________________________________________________________________ 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.

Results XLPE: Under 10 years PILC: Under 20 years XLPE: Between 11 to 20 years PILC: Between 21 to 30 years XLPE: Between 21 to 30 years PILC: Between 31 to 40 years XLPE: Above 30 years

Table 6.6 Age Scoring Score 3

Action -

2

-

1

-

0

-

PILC: Above 40 years

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 1 2 3 4

Condition Indicator Thermography Tan Delta Insulation Resistance Operation and Maintenance Performance

Score

Weighting Factor 0.70 0.80 1.00 0.53

Total Score

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___________________________________________________________________________ No 5

Condition Indicator

Score

Weighting Factor

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

Total Score

0.30

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 All Tier 1 testing equipment were calibrated Subtract 0 within the recommended calibration frequency AND results are reliable. One or more of the Tier 1 testing equipment Subtract 0.5 were calibrated between 0 and 6 months past the recommended calibration frequency. One or more of the Tier 1 testing equipment Subtract 1.0 were calibrated between 6 and 12 months past the recommended calibration frequency. One or more of the Tier 1 testing equipment Subtract 1.5 were calibrated more than 12 months past the recommended calibration frequency.

Action -

-

-

-

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.

No 1 2 3 4 5

Table 6.9 Final Tier 1 Cable Condition Index Value Condition Indicator Score Weighting Factor Thermography 0.70 Tan Delta 0.80 Insulation Resistance 1.00 Operation and Maintenance History 0.53 Age 0.30

Total Score

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6

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) 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) ≥ 3.0 and < 7.0 (Fair) ≥ 0.0 and < 3.0 (Poor)

Maintain the normal frequency of Tier 1 test. Revise frequency of Tier 1 tests to 6 months interval. Make arrangements for Tier 2 tests. 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.

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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 Score Adjustment Action Subtract 0 Normal. The monitoring periodicity of all Tier 1 tests can be maintained at 24 months. Practice partial discharge test if necessary. Subtract 0.5 Retest the cable for partial discharge 2 < Severity Index < 5 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. Results Severity Index < 2

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

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___________________________________________________________________________ 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 Subtract 0 Normal. The monitoring periodicity XLPE: Good response: of all Tier 1 tests can be maintained No significant gap between the at 24 months. Practice partial frequency sweep responses at discharge test if necessary. different voltages. PILC: % Moisture Content < 0.5 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 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 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.

Subtract 1.0

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

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Score Adjustment Subtract 1.5

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

PILC: % Moisture Content > 2.5

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.

No 1 2 3 4 5

6

7 8

Table 6.13 Total Cable Condition Index Value Condition Indicator Score Weighting Factor Thermography 0.70 Tan Delta 0.80 Insulation Resistance 1.00 Operation and Maintenance 0.53 Performance Age 0.30 Tier 1 Cable Condition Index (Sum of Individual Total score) (Condition Index should be between 0 and 10) 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) Tier 2 Partial Discharge Score Adjustment (value can be 0, -0.5, -1.0 or -1.5) 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.

Total Score

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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)

≥ 3.0 and < 7.0 (Fair) ≥ 0.0 and < 3.0 (Poor)

Continue O&M without restriction. Maintain the normal frequency of Tier 1 test. Repeat Tier 2 test as needed. Repeat both Tier 1 & Tier 2 test after 6 months from this condition assessment activity. 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

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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.

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Figure 7.1 Flow Chart of Raw Waveform and Processed Data

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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.

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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.

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Figure 7.4 Raw Waveform of OWTS PD

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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.

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Figure 7.6 Processed Data (PD Mapping) of OWTS PD

Figure 7.7 Processed Data (Histogram) of OWTS PD

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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

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

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

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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

Good response Non deteriorated response Voltage Dependent response Leakage Current response

Gap between the frequency sweep responses at different voltages No

Hysterisis Effect No

Leakage Current Effect No

Yes Yes Yes

No Yes Yes

No No 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.

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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.

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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.

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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

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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.