guide-to-power-system-earthing-practice-final(june2009)[1].pdf

Guide to Power System Earthing PracticeJune 2009

New Zealand Electricity Networks

GUIDE TO POWER SYSTEM EARTHING PRACTICE

DISCLAIMERThis Electricity Engineers’ Association (EEA) New Zealand Electricity Networks Guide to Power System Earthing Practice has been prepared by representatives of the electricity supply industry for the purpose of providing principles on general earthing practices for use by the industry. The EEA New Zealand Electricity Networks Guide to Power System Earthing Practice sets out general earthing practices considered appropriate for the electricity supply industry; it is expected that the generating and electricity network companies will develop their own procedures to implement these practices. Although the EEA New Zealand Electricity Networks Guide to Power System Earthing Practice is recommended by industry representatives, it is not legally binding. As such, the Electricity Engineers’ Association and the industry representatives involved in formulating this guide can accept no liability or responsibility for any injury, loss, damage, or any other claims caused by, or resulting from any inaccuracy in, or incompleteness of the EEA New Zealand Electricity Networks Guide to Power System Earthing Practice.

COPYRIGHT © 009

Copyright is owned by the Electricity Engineers’ Association of New Zealand (Inc.) (EEA), PO Box 5324, Lambton Quay, Wellington, 6145.

All rights reserved. No part of this work may be reproduced or copied in any form or by any means (graphic, electronic or mechanical, including photocopying, recording, taping, or information retrieval systems) without the written permission of the copyright owner.


FOREWORDThe electricity supply industry has both general and specific safety responsibilities placed on it by the Health and Safety in Employment Act 1992, the Electricity Act 1992 and Regulations made under those Acts.

The industry recognises those legal responsibilities and has therefore developed the EEA New Zealand Electricity Networks Guide to Power System Earthing Practice to provide industry-wide safe earthing guidelines.

The EEA New Zealand Electricity Networks Guide to Power System Earthing Practice does not override any legislative requirements.

This guide was produced for the Electricity Engineers’ Association of New Zealand by the following working group members in consultation with engineers from the electrical power supply industry in New Zealand.

• Tas Scott, Orion NZ Ltd (Chairman)

• Des Abercrombie, Vector Ltd

• Peter Berry, EEA

• Rodger Griffiths, Westpower Ltd

• Stephen Hirsch, Orion NZ Ltd

• Gerald Irving, Transpower NZ Ltd

• Bruno Lagesse, Mitton Electronet Ltd

• William Lowe, Energy Safety

• Alan Marshall, Opus International Consultants Ltd (representing Telecom NZ Ltd)

• Michael O’Brien, New Zealand Committee for the Co-ordination of Power and Telecommunications Systems (NZCCPTS)

• Gerry Ryan, Transpower NZ Ltd

Comments for the revision of this guide are welcomed and should be forwarded to:

EEA Guide to Power System Earthing Practice – Convenor

PO Box 5324

Wellington 6145

New Zealand


COnTEnTS

DISCLAIMER .................................................................................................................................2

COPYRIGHT ..................................................................................................................................2

FOREWORD ..................................................................................................................................3

PREFACE ......................................................................................................................................8

InTRODUCTIOn ............................................................................................................................8

SECTIOn 1 – SCOPE, PURPOSE, InTERPRETATIOn, GLOSSARY AnD nUMBERInG ..........91.1 Purpose .............................................................................................................91.2 Scope ................................................................................................................91.3 Interpretation .....................................................................................................91.4 Referenced Acts and Regulations ...................................................................121.5 Referenced and other Relevant Standards and Documents ...........................121.6 Latest Versions ................................................................................................141.7 Glossary of Abbreviations ................................................................................14

SECTIOn – GEnERAL REQUIREMEnTS ................................................................................162.1 General ............................................................................................................162.2 Design Requirements for Earthing Systems ...................................................162.3 Hazards and Electrical Concepts ....................................................................172.4 EPR Risk Management ...................................................................................222.5 Acceptable Touch and Step Voltage Limits .....................................................232.6 Critical Design Parameters ..............................................................................232.7 EPR Voltages Transferred to Third Party Assets .............................................242.8 Types of Earth Electrodes ...............................................................................252.9 Materials of Earth Electrodes and Corrosion Considerations ..........................262.10 Joints of Earth Electrodes ...............................................................................282.11 Current Rating of Conductors and Joints ........................................................282.12 Hazard Mitigation ............................................................................................302.13 Switchgear Operating Mechanisms .................................................................322.14 Surge Arresters ...............................................................................................332.15 Station Fencing ...............................................................................................342.16 Connection Points for Temporary Earths .........................................................352.17 Earth Electrode Enhancement ........................................................................352.18 Testing and Maintenance ................................................................................36

SECTIOn – EPR RISk MAnAGEMEnT ...................................................................................37

3A. PROBABILISTIC METHOD .........................................................................................373.1 Risk Identification and Analysis .......................................................................403.2 Risk Evaluation Criteria ...................................................................................413.3 Cost Benefit Analysis and Mitigation ...............................................................423.4 Probabilistic Risk Management Process .........................................................443.5 Permissible Touch and Step Voltage Limits ....................................................45

3B. DETERMINISTIC METHOD ........................................................................................463.6 Exposure Definitions .......................................................................................473.7 Permissible Touch Voltages ............................................................................483.8 Permissible Step Voltages ...............................................................................503.9 Case Studies ...................................................................................................523.10 References ......................................................................................................53


SECTIOn – RISk MITIGATIOn MEASURES ...........................................................................544.1 Earthing System Impedance Reduction ..........................................................544.2 Gradient Control Conductors ...........................................................................554.3 Neutral Earthing Resistors ..............................................................................564.4 Resonant Earthing ...........................................................................................574.5 Overhead Earth Wires (OHEW) ......................................................................574.6 Cable Screens .................................................................................................584.7 Surface Insulating Layer ..................................................................................584.8 Separation of HV and LV Earthing ..................................................................604.9 TT System of Supply .......................................................................................624.10 Interference with Services ...............................................................................624.11 Other Mitigation Measures ..............................................................................634.12 References ......................................................................................................63

SECTIOn – HV A.C. STATIOnS ................................................................................................645.1 Introduction ......................................................................................................645.2 Design Requirements for HV a.c. Station Earthing Systems ..........................645.3 Design Aspects ................................................................................................645.4 Important Design Parameters .........................................................................665.5 Soil Resistivity .................................................................................................665.6 Maximum Earth Fault Current .........................................................................675.7 Maximum Earth Fault Duration ........................................................................675.8 Touch and Step Voltage Hazards ....................................................................685.9 Mitigation of EPR Hazards ..............................................................................685.10 Transferred Voltages .......................................................................................695.11 430 V, 650 V and 2,500 V Earth Potential Rise Contours ...............................715.12 Equipment Earthing and Bonding ....................................................................725.13 Joints for Equipment Earthing Conductors ......................................................725.14 Disconnectors and Earth Switches ..................................................................735.15 Equipment Reinforced Concrete Pads and Holding-Down Bolt Cages ...........735.16 Buildings ..........................................................................................................745.17 Fences .............................................................................................................745.18 Lightning Shielding and Lighting .....................................................................745.19 Portable Earthing Connections ........................................................................755.20 Control Cabinet Earths/ ODJBs .......................................................................755.21 Earthing of Control and Instrumentation Cables Within the Earth Grid ...........765.22 Earthing of Power Cables within the Earth Grid ..............................................775.23 Feeder Cables .................................................................................................775.24 Transformer Neutral Earthing ..........................................................................785.25 Generator Neutral Earthing .............................................................................785.26 Voltage transformers and Capacitor Voltage Transformers .............................795.27 VT/CT Secondary Circuits ...............................................................................795.28 400/230 V System ...........................................................................................795.29 Earthing Conductor and Joint Specification ....................................................805.30 OHEW .............................................................................................................805.31 Power Stations, Customer Substations and Industrial Installations ................815.32 Installation and Commissioning .......................................................................815.33 Testing and Maintenance ................................................................................81


SECTIOn – DISTRIBUTIOn CEnTRES AnD EQUIPMEnT ....................................................836.1 Introduction ......................................................................................................836.2 Design Requirements for Distribution Centres and Equipment

Earthing Systems ............................................................................................836.3 Design Aspects ................................................................................................846.4 Reliable Detection and Clearance of HV Earth Faults ....................................856.5 EPR Risk Management ...................................................................................856.6 Control of Dangerous EPR Impressed on Third Party Assets

and Personnel .................................................................................................966.7 Segregated HV and LV Earthing .....................................................................986.8 Earthing Systems for Distribution Centres and Equipment ...........................1006.9 Connection of Neutral to Earth ......................................................................1006.10 Earthing of Fittings at Distribution Centres ....................................................1016.11 Earthing of Fittings at Distribution Equipment ...............................................1026.12 Safety While Operating Disconnectors ..........................................................1036.13 Earthing Connections ....................................................................................1036.14 Low Voltage Earthing Conductors Associated with LV Systems ...................1046.15 Connections to Earthing Electrodes ..............................................................1046.16 Surge Arresters .............................................................................................1056.17 Soil Resistivity ...............................................................................................1056.18 Earthing Arrangement Examples ...................................................................1056.19 Testing and Maintenance ..............................................................................106

SECTIOn 7 – OVERHEAD ELECTRIC LInES 0 kV A.C. AnD ABOVE .................................1077.1 Introduction ....................................................................................................1077.2 Corridor Management ...................................................................................1077.3 Steel Lattice Structures .................................................................................1087.4 Steel and Concrete Poles ..............................................................................1107.5 Wood Poles ................................................................................................... 1117.6 Electrodes and Counterpoise Earthing ..........................................................1127.7 Overhead Earth Wire .....................................................................................1137.8 Lightning Surge Arresters ..............................................................................1147.9 Guy Wire Insulators .......................................................................................1157.10 Clearance of Earth Faults ..............................................................................1157.11 Tower Footing Resistances ...........................................................................1177.12 EPR Assessment ...........................................................................................1197.13 Lightning ........................................................................................................1257.14 Voltages Impressed onto Other Circuits or Utilities .......................................126

Appendix A – Voltage Limits (Informative) ...........................................................................128

Appendix B – Case Studies (Informative) ............................................................................137

Appendix C – Examples of Earthing Arrangements (Informative) ........................................168

Figure 1 – Touch and Step Voltages around a Substation ...............................................21

Figure 2 – Example of Transferred Voltage ......................................................................21

Figure 3 – Copper Conductor Ratings for Bolted Connections (250°C) ...........................30

Figure 4 – Copper Conductor Ratings for Welded Connections (400°C) .........................30

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Figure 5 – Probabilistic Risk Management Flowchart ............................................................44

Figure 6 – Method for Calculating Touch and Step Voltage Limits .........................................45

Figure 7 – Deterministic Method Flowchart ............................................................................47

Figure 8 – Touch Voltage Limits for Special Locations Excluding Shoe Resistance ..............49

Figure 9 – Touch Voltage Limits for Normal Locations Including 2,000 Ω Shoes ...................50

Figure 10 – Step Voltage Limits for Special Locations Excluding Shoe Resistance ................52

Figure 11 – Variation of EGVR with Earth Grid Impedance ......................................................54

Figure 12 – Configuration of a Practical TT System .................................................................62

Figure 13 – Typical EGVR at 11 kV Faulted Sites ....................................................................89

Figure 14 – Hazardous Step Voltage Zone around Electrode ..................................................93

Figure 15 – IEC 60479-1 Curve c2 .........................................................................................128

Figure 16 – Touch and Step Voltage Circuit Parameters ........................................................129

Figure 17 – Touch Voltage Shock Circuit ................................................................................132

Figure 18 – Effective (Loaded) Permissible Touch Voltages ..................................................133

Figure 19 – Step Voltage Shock Circuit ..................................................................................135

Figure 20 – Loaded Permissible Step Voltages ......................................................................136

Figure 21 – Location of Pole Mounted Transformer ...............................................................137

Figure 22 – Touch Voltages on the Pole .................................................................................139

Figure 23 – Step Voltages around the Pole ............................................................................140

Figure 24 – Touch Voltages for Basic Earth Grid ....................................................................147

Figure 25 – Touch Voltages around Basic Earth Grid with Crushed Rock .............................148

Figure 26 – Touch Voltages around Earth Grid with a Gradient Control Conductor Outside the Perimeter Fence ..............................................................................149

Figure 27 – Touch Voltages for Substation with Crushed Rock and Gradient Control Conductors Inside and Outside the Perimeter Fence .........................................149

Figure 28 – Touch Voltages for Earth Grid with Additional Driven Rods .................................150

Figure 29 – EPR Contours around Substation .......................................................................152

Figure 30 – 650 V EPR Contours around Substation .............................................................153

Figure 31 – Touch Voltages on 66 kV Tower ..........................................................................158

Figure 32 – Step Voltages around 66 kV Tower .....................................................................158

Figure 33 – Step Voltages around 66 kV Tower for Lower Limit .............................................159

Figure 34 – Example of Earthing Arrangement in HV a.c. Station ..........................................168

Figure 35 – Example of Earthing Arrangement for Earth Switches in HV a.c. Station ...........169

Figure 36 – Example of Earthing Arrangement for Pole Mounted Transformer ......................170

Figure 37 – Example of Earthing Arrangement for Air Break Isolator with other Equipment ..171

Figure 38 – Example of Earthing Arrangement for Lightning Sure Arresters ..........................172


Figure 39 – Example of Earthing Arrangement for HV Installations at Consumers’ Premises .........................................................................................173

Figure 40 – Example of Earthing Arrangement for Ground Mounted Kiosk ...........................174

Table 1 – Brief Guide on Selecting Earthing Electrode Design .............................................26

Table 2 – Mitigation Options ..................................................................................................31

Table 3 – Risk Management Matrix .......................................................................................41

Table 4 – Crushed Rock Specification ..................................................................................59

Table 5 – HV a.c. Station Routine Inspection Plan ...............................................................82

Table 6 – Typical Touch Voltages as a Percentage of EGVR................................................91

Table 7 – Radius of Step Voltage Hazard Area around Conductive Poles ............................92

Table 8 – Extent of Step Voltage Hazard Zone around Earth Electrodes .............................93

Table 9 – Typical Minimum Separation Distances between HV and LV Earths for 11 kV Distribution .............................................................................................99

Table 10 – Equipment Site Routine Inspection Plan .............................................................106

PREFACE

This guide has been written to provide guidance based upon current industry best practice and international standards.

InTRODUCTIOn

This guide is intended to provide general guidance on acceptable methods for ensuring the safety of earthing systems associated with high voltage power systems and provide a means of compliance with relevant safety legislation.

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SECTIOn 1 – SCOPE, PURPOSE, InTERPRETATIOn, GLOSSARY AnD nUMBERInG

1.1 PURPOSE

The purpose of this guide is to give guidance and advice on safe earthing practices for high voltage a.c. power systems adequate to meet the requirements of electricity safety legislation.

1. SCOPE

1..1

This document provides guidance on power system earthing in general as set out in sections 1 to 4, and also includes specific sections for:

(a) High voltage (HV) a.c. stations (section 5);

(b) Distribution centres, equipment, and lines up to 33 kV (section 6);

(c) High voltage a.c. transmission/sub-transmission lines of 50 kV and over (section 7).

1..

This guide does not apply to:

(a) Aspects of low voltage (LV) earthing on consumers’ installations, which are covered by the Wiring Rules (AS/NZS 3000);

(b) Systems not operated at a normal frequency of 50 Hz;

(c) Temporary earthing;

(d) Specific requirements related to Single Wire Earth Return (SWER) systems, including requirements associated with steady state EPR issues.

NOTE: This guide covers EPR issues associated with earth faults on SWER systems.

1. InTERPRETATIOn

In this guide, unless the context otherwise requires, the following definitions apply:

Disconnector – means any disconnector, earth switch, air break switch (ABS), air break isolator (ABI), sectionaliser, auto-recloser, etc.

Distribution centre – means any substation from which electricity is supplied direct at low or high voltage to an electrical installation that belongs to a consumer or end user. The distribution centre may consist of one or more transformers on a pole, on the ground, underground, or in a building; and includes the enclosure or building surrounding the transformer(s) and switchgear, if any, but does not include HV a.c. stations.

Distribution equipment – means pole or pad mounted equipment such as lightning arresters, ring main units (RMUs), capacitors, regulators and disconnectors (ABSs, ABIs, sectionalisers, etc.) on a distribution network other than distribution centres.


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Distribution system – means that portion of an electricity supply system from where electricity at low or high voltage is conveyed from a distribution centre, to the premises of consumers connected to that distribution centre, but does not include distribution or service mains.

Earthed – means electrically connected to the general mass of the earth.

Earth electrode – means a conducting element or electrically bonded group of conducting elements in electrical contact with the earth and designed for dispersing electric currents into the earth.

Earth fault current path – means the complete loop through which earth fault current flows. It includes system plant as well as dedicated earth connections and the main body of the earth.

Earth grid – means a system of interconnected bare conductors buried in the earth providing a common earth for fittings. The grid may be specifically designed to control surface potential gradients.

Earth grid return current – means the portion of total earth fault current that flows between the earth grid and the surrounding soil.

NOTE – This current determines the EGVR of the earthing system.

Earth grid voltage rise (EGVR) – means the voltage rise to remote earth on a metallic structure connected to an earthing system during an earth fault.

Earth potential rise (EPR) – means a rise in potential on the earth surface relative to reference earth.

Earth impedance in respect of an earth electrode system – means the ohmic impedance at system frequency between the electrode system and the general mass of earth.

Earthing conductor – means a conductor connecting any part of an earth electrode to fittings required to be earthed.

Earthing system – means all conductors, electrodes, clamps or other connections used to provide a path to earth.

High voltage (HV) – means voltage exceeding 1,000 volts a.c.

Hazard – means a potential source of harm.

HV a.c. station – means a HV station that has a controlled access area and a specific earth grid. This includes Transpower grid connection points, zone substations, HV switching stations, generating stations (including switchyards), air insulated indoor substations, gas-insulated substations (GIS), etc., but does not include distribution centres and distribution equipment.

Informative – means the information provided is only for guidance and is not a mandatory requirement of the guide.

May – means that a provision is truly optional. Some implementers may choose to include the measure because it serves a particular local requirement, while others may omit the same measure and still comply with this guide.

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Metal-to-metal touch voltage – means the difference in potential between metallic objects or structures that may be bridged by direct hand-to-hand or hand-to-feet contact

Mitigation – means a measure or measures taken to reduce any hazard or any risk.

Multiple earthed neutral (MEn) system – means a system of earthing in which the earthing conductor within an electrical installation is connected to the neutral as well as to an earthing electrode. In this system, the distribution system neutral is earthed at the point of supply at a distribution centre, and at one or more points along the distribution or service mains, and provides a continuous electrical path between the consumer and the distribution centre earthing point.

Must – means that the provision is a mandatory requirement of the guide, i.e. the provision is required to be carried out in order to comply with the guide.

normal location – means any urban or rural areas other than special locations.

normative – means a requirement forms part of the essential provisions of a Standard or guide and must be carried out in order to comply with the guide.

Risk – means a combination of both the probability of an event (that may result from the presence of any hazard) and the associated consequence of that event.

Risk assessment – means the determination that a given level of risk is tolerable or otherwise.

Should – means that valid reasons may exist in particular circumstances to ignore a particular provision, but the full implications have to be understood and carefully weighed before choosing a different course.

Special location – means any urban or rural area where a significant gathering of people may occur, particularly situations and/or where people may not be wearing footwear. Special locations could be found in areas such as within a school’s grounds or within a children’s playground, orwithin a school’s grounds or within a children’s playground, or within a public swimming pool area, or at a popularly used beach or water recreation area, or in a public thoroughfare.

Station – means substation or generating station.

Step voltage – means the difference in surface potential experienced by a person bridging a distance of one metre with the person’s feet apart, without contacting any other earthed object.

System voltage – means the difference of potential normally existing between conductors, or between conductors and earth (phase-to-phase in a multi phase system and phase-to-earth in a single phase system).

Telecommunications system – means all plant that is part of a telecommunications network. This includes cables, aerial lines, pillars, exchange equipment, and customers’ fixed telecommunications wiring and attached equipment (e.g. PABXs, phones, etc.).

Touch voltage – means voltage that will appear between any point of hand contact with uninsulated metalwork and any point on the surface of the ground within a horizontal distance of one metre from the vertical projection of the point of contact with the uninsulated metalwork.


1

1. REFEREnCED ACTS AnD REGULATIOnS

This guide was written to comply with the New Zealand Electricity Act 1992 and the New Zealand Electricity Regulations 1997 and their amendments as well as the Electricity (Hazards from Trees) Regulations 2003. The Electricity Regulations are currently under review and will be replaced by the Electricity Safety Regulations, which, with the amended Act, will have content intended to safeguard members of the public and their property. The guide is also intended to provide guidance to asset owners on the practicable steps that employers must take to safeguard their own employees, contractors’ employees, and members of the public in the vicinity of work places as required by the Health and Safety in Employment Act 1992.

1. REFEREnCED AnD OTHER RELEVAnT STAnDARDS AnD DOCUMEnTS

AS 2067:2008 Substations and high voltage installations exceeding 1 kV a.c.

AS/NZS 3000 Electrical installations. Also known as the Australian/New Zealand Wiring Rules.

AS/NZS 3835 Earth potential rise – Protection of telecommunication network users, personnel and plant – Parts 1 & 2.

AS/NZS 4360 Risk management.

AS/NZS 4853 Electrical hazards on metallic pipelines.

AS/NZS 60479-1 Effects of current on human beings and livestock. Part 1: general aspects (Equivalent to IEC 60479-1:1994).

BS 7354 Code of practice for design of high voltage open terminal stations.

BS EN 50341-1:2001 Overhead electrical lines exceeding a.c. 45 kV. General requirements and common specifications.

CJC 5:1997 Coordination of power and telecommunications – Low frequency induction, Standards Australia, 1997.

EEA EEA guide to risk based earthing system design.

EEA EEA guide to temporary earthing of distribution overhead lines.

EEA EEA guide to work on de-energized distribution overhead lines.

ECP 34 NZ ECP for electrical safe distances.

ECP 41 NZ ECP for single wire earth return systems.

ENA EG1 Electricity Networks Association (Aust) Substation earthing guide.

ENA C(b)1 Electricity Networks Association (Aust) Guidelines for design and maintenance of overhead distribution and transmission lines.

IEC 60071 Insulation coordination multiple parts.

IEC 61936-1 Power installations exceeding 1 kV a.c.

IEC 60364-4-44 Low voltage electrical installations – Part 4-44 Protection for safety – Protection against voltage disturbances and electromagnetic disturbances.

IEC 60479-1:2005 Effects of current on human beings and livestock. Part 1: General aspects.

1


IEEE Standard 80 Guide for safety in a.c. substation grounding.

IEEE Standard 81 Guide for measuring earth resistivity, ground impedance and earth surface potentials of a ground system.

IEEE Standard 81.2 Guide for measurement of impedance and safety characteristics of large, extended or interconnected grounding systems.

IEEE Standard 142 Recommended practice for grounding of industrial and commercial power systems.

IEEE Standard 524a IEEE Guide to grounding during the installation of overhead transmission line conductors.

IEEE Standard 665 Standard for generating station grounding.

IEEE Standard 837 Qualifying permanent connections used in substation grounding.

IEEE Standard 998:1996 IEEE Guide for direct lightning stroke shielding of substations.

IEEE Standard 1313: IEEE Standard for power systems – Insulation coordination (three 1993 parts).

IEEE Standard 1410: IEEE Guide for improving the lightning performance of electric power 2004 overhead distribution lines.

ITU-T K33 Limits for people safety related to coupling into telecommunications system from a.c. electric power and a.c. electrified railway installations in fault conditions.

ITU-T K53 Values of induced voltages on telecommunications installations to establish telecom and a.c. power and railway operators’ responsibilities.

NZCCPTS Application guide for earth potential rise.

NZCCPTS Application guide for neutral earthing resistors or reactors.

NZCCPTS Application guide for SWER HV power lines.

NZCCPTS Application guide for cable separations – Minimum separations between power and telecommunication cables.

NZCCPTS Application guide for costs apportioning.

NZCCPTS Application guide for cable sheath bonding.

NZCCPTS Fundamentals of calculation of earth potential rise in the underground power distribution cable network.

NZS 4407 Methods of sampling and testing road aggregates.

NZS 4407.1:1991 Methods of testing road aggregates – Preliminary and general.

SAA/SNZ HB 436 Risk management guidelines – Companion to AS/NZS 4360.

SM-EI Safety manual – Electricity industry (three parts in two manuals).

TNZ B/2:2005 Specification for construction of unbound granular pavement layers, Transit New Zealand.

TNZ M/10:2005 Specification for asphaltic concrete, Transit New Zealand. And Notes to the specification for asphaltic concrete, Transit New Zealand.


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TNZ P/9:1975 Specification for construction of asphaltic concrete, Transit New Zealand.

Abelson Peter The Value of Life and Health for Public Policy, Macquarie University, Economic Record Conference Edition, Vol. 79, pp. 2-13, June 2003.

Abelson Peter Establishing a Monetary Value for Lives Saved: Issues and Controversies, Sydney University, Cost-Benefit Conference, Office of Best Practice Regulation, Canberra, November 2007.

Farber Daniel and The shadow of the future: Discount rates, later generations, and the Hemmersbaugh environment, Vanderbilt Law Review 46: 267-304, 1993. Peter

Hileman Andrew R Insulation co-ordination for power systems, Marcel Dekker Inc., 1999.

Ministry of Transport The Social Cost of Road Crashes and Injuries: June 2007 update.

Viscusi and Aldy The Value of a Statistical Life: A Critical Review of Market Estimates Throughout the World, Harvard Law School John M. Olin Center for Law, Economics and Business Discussion Paper Series 2002.

1. LATEST VERSIOnS

Unless a specific date is given in the text for a particular reference, users of this guide should refer to the latest edition. Any amendments to referenced New Zealand and Joint Australian/New Zealand Standards can be found at http://www.standards .co.nz. Amendments to New Zealand legislation can be found at http://www.legislation.co.nz.

1.7 GLOSSARY OF ABBREVIATIOnS

AAC All aluminium conductor

a.c. Alternating current

ABI Air break isolator

ABS Air break switch

ACSR Aluminium conductor steel reinforced

ALARP As low as reasonably practical

CB Circuit breaker

CBA Cost benefit analysis

CBR California bearing ratio

CT Current transformer

CVT Capacitor voltage transformer

DA Data acquisition

d.c. Direct current

1


EEA Electricity Engineers’ Association of New Zealand Inc.

EMC Electromagnetic compatibility

EMI Electromagnetic interference

EPR Earth potential rise

EPZ Equipotential zone

EGVR Earth grid voltage rise

HV High voltage > 1 kV a.c. or > 1.5 kV d.c.

Hz Hertz

kg Kilogram

kV Kilovolts (1,000 volts)

LV Low voltage ≤ 1 kV

MEN Multiple earthed neutral

MVA Mega volt amps

NER Neutral earthing resistor

NET Neutral earthing transformer

NZECP New Zealand electrical code of practice

ODJB Outdoor junction box

OH Overhead

OHEW Overhead earth wire

PPE Personal protective equipment

PV Present value

PVC Polyvinyl chloride

RCD Residual current device

RMU Ring main unit

SCADA Supervisory control and data acquisition

SWER Single wire earth return

t Time (in seconds)

TFR Tower footing resistance

TT Terra-Terra system of supply

VA Volt-amperes (generally expressed in kVA or MVA)

VoSL Value of statistical life

VT Voltage transformer


1

SECTIOn – GEnERAL REQUIREMEnTS

.1 GEnERAL

Depending on access, location and exposure levels, metal structures and equipment that may be livened to dangerous voltage levels as a result of an earth fault should be bonded to earth. This can be achieved by permanent connections to electrodes in contact with the general body of earth.

Power system earthing is typically required to ensure that earth faults associated with the power system are detected so that the earth fault protection devices are effectively operated to disconnect the supply. When a fault on a high voltage power system causes current to flow to earth, the earthing system should also ensure that the voltage difference between conducting parts that may be momentarily livened, and which may be contacted by a person, does not present a significant risk of serious harm. Hazardous voltages between conductive parts may typically appear between the hand and one or both feet (i.e. touch voltages), or between the two hands (i.e. metal-to-metal touch voltages), or between one foot and the other (i.e. step voltages). Such voltage differences can occur within power system stations, and also on metallic structures along the length of, or close to power lines, under earth fault current conditions. Earthing, in conjunction with other mitigation measures, can be used to control dangerous voltage differences to acceptably safe levels.

During earth fault conditions, voltage differences will exist between station equipment and the main body of earth. These voltage differences may need to be controlled, to ensure that insulation breakdown or failure does not occur on apparatus connected to points outside the station. Cable sheaths, metallic pipes, fences, etc. that are connected to the station earthing system will transfer earth fault voltages from the station earth electrode to the remote points. Similarly, cable sheaths, metallic pipes, etc. that are connected to remotely earthed structures but isolated from the station earth electrode will transfer the earth fault voltage of the remote structure into the station.

. DESIGn REQUIREMEnTS FOR EARTHInG SYSTEMS

The performance of the earthing system(s) must satisfy the safety and functional requirements of the high voltage power system, including lines, substations and the associated fittings and equipment. The earthing system may be used jointly or separately for the protective or functional purposes according to the requirements of the power system.

The design, selection and installation of the earthing systems must ensure the requirements of 2.2.1 and 2.2.2 are met:

..1 Performance requirements

The performance requirements for an earthing system include:

(a) Proper functioning of electrical protective devices. This entails reliable detection of HV earth faults and either clearing the fault or minimising the resulting fault current.

(b) Managing the risks associated with step and touch voltages in accordance with Electricity Regulations, applicable standards and guidelines.

(c) Managing the risks associated with EPR transferred onto third party plant, staff and users (i.e. telecommunications, railways, pipelines, etc.) in accordance with Electricity Regulations, applicable standards and guidelines.

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.. Functional requirements

The functional requirements for an earthing system include:

(a) Earth fault currents and earth-leakage currents can be carried without danger and without exceeding design limits for thermal, thermo-mechanical and electro-mechanical stresses.

(b) The value of earthing impedance is in accordance with the protective requirements and is continuously effective over the planned lifetime of the installation with due allowance for corrosion and mechanical constraints.

. HAzARDS AnD ELECTRICAL COnCEPTS

..1 Sources of hazards

Electrical hazards in the form of touch, step or transferred voltages can appear on the metal structures or equipment associated with, or nearby, high voltage power systems, due to one or a combination of the following factors:

(a) Electrical insulation failure, or mechanical failure or both, causing earth fault current to flow, and EPR to occur;

(b) Human error, resulting in accidental livening of station equipment, and/or lines circuits;

(c) Electromagnetic induction;

(d) Static charges induced on de-energised lines due to atmospheric conditions;

(e) Lightning strikes to in-service/de-energised lines;

In addition, electrical interaction can occur between power system earthing and nearby third party systems. This interaction may involve EPR, or transferred EPR, stress to the insulation of telecommunications circuits, induced voltages, or the creation of voltage differences between the EPR of power system earthing and the independent earthing (either local or remote) of other systems such as private generating plant, or telecommunications systems. The consequences of such differential voltages may involve both insulation breakdown and component failure (e.g. electronic equipment). This may impose a potentially hazardous voltage on third party network conductors, which may conduct this voltage to locations well removed from the fault location. There it may present a hazard to the third party network’s staff and customers, as well as to the third party network’s plant, and possibly associated customers’ plant.

In some cases, common HV and LV network earths may be of particular concern as detailed in section 4.8.

The widespread use of customers’ mains-powered digital electronic equipment, such as cordless telephones, etc., has increased the possibility of damage to such telecommunications equipment and of harm to the telecommunications network users and personnel.

This guide does not include detailed guidance on issues of EPR transferred onto third party systems. For the telecommunications system, detailed guidance is available from a series of publications issued by the New Zealand Committee for the Co-ordination of Power and Telecommunication Systems (NZCCPTS). The NZCCPTS publications are listed in section 1.5 of this guide, and provide detailed information on assessing the likely levels of hazards involved and suitable means of mitigating these. For pipelines, detailed guidance can be obtained from AS/NZS 4853.


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It should also be noted that the voltage-time safety criteria for telecommunications equipment and users differ from the step and touch values used in earthing design. The relevant criteria for telecommunications equipment and users are detailed in the Electricity Regulations. Similar criteria are typically used by the railway industry.

.. Earth potential rise (EPR)

An earth fault will result in an EPR. During an earth fault, there is significant current (fault current) flowing from the power source into the fault point. This current then returns to the source through the ground surrounding the fault point or earth mat. The soil has inherent resistivity and the current flowing through this resistance causes voltages to appear on the soil surface and, consequently, an EPR. The value of this at the earth mat is determined by the resistance between the earth matvalue of this at the earth mat is determined by the resistance between the earth mat and the remote earth as well as the magnitude of the earth fault current.

The soil surface voltages are highest at the fault location or the source substation earth mat, and reduce as the distance from the fault location or the source substation earth mat increases. Equipotential contours reflect all the locations that would have the same voltage on the soil surface during an earth fault. The closer the contours are to each other, the steeper the voltage gradients are. This results in:

(a) A higher touch voltage;

(b) Higher step voltages close in, but lower step voltages further out;

(c) A smaller step voltage hazard zone;

(d) A lower EPR in the nearby soil;

(e) Smaller EPR hazard zones;

(f) Fewer problems with EPR hazard to other nearby utility plants (e.g. telecommunications plant).

If a human or animal contacts two different voltages simultaneously, a voltage difference will be applied across the body. This will cause a current to flow in the body. The current that may be harmful is influenced by a number of factors including fault duration, the contact area, the body current path and the impedance characteristics of the skin and the body.

Hand-to-hand or more typically hand-to-foot voltages are known as touch voltages. A touch voltage occurs when the surface a person is touching and the surface a person is standing on, or a second location that they are touching, are at different voltages. Hence touch voltages occur where there is contact with a conductive structure where a current path occurs through the body to a location at a different potential during an earth fault.

Transferred voltages are a specific form of touch voltages. Voltages can appear on any long metallic object during an earth fault, when the object is in electrical contact with the soil surface and passes across the EPR voltage contours. Typical examples are wire fences, telephone wires or gas pipelines. There are two separate consequences. First, the metallic object will attain the EPR voltage of the soil surface that it is in contact with. It may conduct or transfer this voltage from the area close to the fault point to a location some distance away. A significant touch voltage may then occur through a person touching the metallic object while standing on a soil surface well beyond the immediate influence of the fault. Secondly, the reverse can also occur, where the

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metallic object may conduct or transfer a low voltage into an area close to the fault point. The soil surface may have attained a high EPR voltage as a result of the fault. A significant touch voltage may then occur, again through a person touching the metallic object but in this instance with the person standing close to the fault point.

Foot-to-foot voltages are known as step voltages. A step voltage occurs when a stride is taken and the soil surface under each foot is at different voltages. A step voltage can only be experienced when both feet are in simultaneous contact with the ground and each foot is on a different voltage contour. This results in a current path through the body from foot to foot during an earth fault.

2.3.3 Electricfield(capacitive)coupling

Electric field (capacitive) voltages typically can be coupled onto an insulated metallic object in an electric field from an energised circuit. A typical example of electric field coupling is the voltage that appears on a de-energised overhead circuit running alongside an energised circuit.

When contact is first made with the isolated object, the capacitor will discharge and the final voltage on the object is likely to be low. As long as the stored energy is not very large the discharge current will be low. However, if the stored energy is large, such as on a relatively long de-energised circuit in parallel with an energised circuit, the discharge current may be high and dangerous.

Bonding the isolated object to earth will effectively discharge capacitive coupled voltages.

Capacitive coupling is rarely an issue for the public. Electric utilities’ employees working on de-energised circuits or equipment have to take necessary precautions such as applying temporary earthing to ensure that capacitive coupled voltages are minimised.

2.3.4 Magneticfieldinduction

Currents (steady state or earth fault currents) flowing through a circuit in parallel with metallic conductors can cause hazardous voltages to be magnetically induced into the parallel metallic conductor.

Induced voltages may be a hazard to telecommunications equipment and personnel and must be limited to electrically safe values.

Induced voltages may also be a hazard in gas, oil or other pipelines, where they run parallel to high voltage transmission or distribution lines. Hazards arise to personnel inspecting and maintaining such pipelines.

Induced voltages may also be hazardous to the public on fences or other metallic conductors that run parallel to power lines.

Further discussion of magnetic field induction is outside the scope of this guide. Further information about magnetic field induction may be obtained from:

(a) CJC 5:1997 Coordination of power and telecommunications – Low frequency induction, Standards Australia, 1997.

(b) AS/NZS 4853 Electrical hazards on metallic pipelines.


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.. Lightning strikes

Even though lightning activity in New Zealand is typically low compared to many other regions of the world, lightning is still considered a significant source of hazards to employees. Lightning overvoltages and currents can travel a long way over overhead lines and affect personnel working on earthing systems.

It is impractical to provide adequate protection to personnel in the form of earthing and equipotential bonding during lightning conditions because lightning surges typically have high current magnitude and rate of rise.

This guide does not cover lightning protection in detail. Information on insulation coordination and lightning protection may be obtained from:

(a) IEC 60071 Insulation coordination (multiple parts) ;

(b) Hileman Andrew R, Insulation coordination for power systems, Marcel Dekker Inc., 1999;

(c) IEEE Standard 998-1996 IEEE Guide for direct lightning stroke shielding of substations;

(d) IEEE Standard 1313-1993 IEEE Standard for power systems – Insulation coordination (three parts);

(e) IEEE Standard 1410-2004 IEEE Guide for improving the lightning performance of electric power overhead distribution lines.

NOTE: All personnel are required to stop handling all conductors including those associated with any earthing system until the lightning hazard has passed. This is a requirement from SM-EI 3.702.

.. Touch voltage

Touch voltage is the voltage generated during an EPR event that may appear between any point of contact with uninsulated metalwork and any point on the surface of the ground within a horizontal distance of one metre from the vertical projection of the point of contact with the uninsulated metalwork.

Touch voltages typically appear between a hand and one or both feet of a person touching a temporarily livened earthed structure while standing on the ground surface one metre away from the structure (see Figure 1).

A touch voltage may also appear between the two hands of a person simultaneously touching two earthed structures that are temporarily livened. This is termed the ‘metal-to-metal touch voltage’ and may only be an issue if one or both objects are not bonded to the grid.

For a HV a.c. station with an earth grid, the maximum touch voltage that can develop in the mesh of the grid is termed the mesh voltage. Because of the equipment and structures in a HV a.c. station, it is possible for someone to be touching structures or items of equipment, including mobile plant, while standing at the centre of a mesh.

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Figure 1: Touch and Step Voltages around a Substation

..7 Step voltage

Step voltage is the difference in surface potential experienced by a person bridging a distance of one metre with the person’s feet apart, without contacting any other earthed object. Examples of a step voltage are shown in Figure 1.

.. Transferred voltage

The transferred voltage is a special case of touch voltage whereby a voltage is either transferred to the substation from a remote point or is transferred from the substation to the remote point (see Figure 2). In that case, the touch voltage may be approaching the full EGVR.

Where voltage rises on the earthing system are transferred by metalwork such as neutral conductors of a MEN system, water pipes, and the like to locations remote from the installation, allowance may be made for voltage drop in these conductors. Otherwise, the transferred potential should be considered to be equal to the EGVR.

Figure 2: Example of Transferred Voltage


Voltages may also be transferred to third party plant and equipment via the potential rise in the ground. Additional information on the transfer of hazardous voltages to third party assets is provided in section 2.7.

.9.9 Hazards to equipment

While people (and animals) are susceptible to electric current, plant and equipment are also susceptible. Any plant such as data and communications cables and equipment may be severely damaged by high voltage gradients appearing on the earthing systems during an earth fault.

Limits for equipment can vary significantly and it is difficult to provide specific values. Modern telecommunications equipment (cordless telephones, facsimile machines, multiplex equipment) is susceptible to damage from excessive voltage. Close liaison between the network operator and third parties must occur at the early stages of any development or alterations to either party’s network.

. EPR RISk MAnAGEMEnT

The occurrence of earth faults on power systems causing hazardous voltage differences and the presence of human beings in simultaneous contact with these voltage differences are both probabilistic in nature. Therefore the risk associated with these events can be determined using statistical methods.

The concept of electrical safety formulated by the Electricity Regulations is that, ‘there is no significant risk of injury or death to any person, or of damage to any person or property, as a result of the use of the works, electrical installations, or associated equipment, or of the passage of electricity through those works, electrical installations, fittings, electrical, electrical appliances, or associated equipment as the case may be.’

For a dangerous situation to arise, a power system earth fault must coincide with a person being at a location exposed to a consequential hazardous voltage. Fortunately, few human electric shock incidents have been recorded to date in these situations.

A low earth resistance is not always necessary to provide a safe earthing system. The earthing system design is required to keep the voltage gradients across the earthing system under earth fault conditions within safe levels to prevent danger to persons or equipment.

Traditionally, an earthing system with a low overall earth resistance was considered to be safe but there is not a simple relationship between the resistance of the earthing system (e.g. ‘10 Ω’) and the magnitude of shock voltage that can arise in any particular situation. Appropriate analysis is therefore required that takes into account all the necessary factors and includes risk assessment.

Earthing system design and testing can show the existence of possible hazardous voltages. The risks associated with these hazardous voltages should be identified and evaluated against given criteria to determine whether the risk needs to be mitigated.

To manage the risk from EPR events, either of the following two methods may be used:

(a) The probabilistic method; or

(b) The deterministic method.

Risk management is more fully addressed in section 3.


. ACCEPTABLE TOUCH AnD STEP VOLTAGE LIMITS

The hazard to human beings is that a current will flow through the region of the heart that is sufficient to cause the heart to go into ventricular fibrillation. The current limits, for power-frequency purposes, are derived from an established international standard such as IEEE Standard 80 or IEC 60479-1 (AS/NZS 60479.1).

The current limits need to be translated into voltage limits for comparison with the calculated step and touch voltages, taking into account the impedance present in the body current path. The voltage limits should take into account the following factors:

(a) The proportion of the human body current flowing through the region of the heart;

(b) The human body impedance for the current path;

(c) The contact resistance between the human body contact points and conductive surfaces in the return path (e.g. soil (at remote earth potential), earth electrode);

(d) The duration of the current flow through the human body.

. CRITICAL DESIGn PARAMETERS

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The following design parameters are critical as they form the basis for the calculations and assumptions that define the earthing systems required at locations where mitigation is required to achieve electrical safety:

(a) Design fault currents;

(b) Design fault duration;

(c) Site soil resistivity.

.. Design fault current

Prior to carrying out any earthing grid design, it is necessary to accurately establish the realistic earth return fault current.

Often only a small proportion of the prospective earth fault current may return via the earth grid proper. In some cases, fault current is diverted from the grid via cable screens, overhead earth wires or other bonded conductors such as pipelines. Some of the earth fault current may also circulate within an earth grid and not contribute to the EGVR. Therefore, before calculating the EGVR, touch voltages and step voltages, it is important to first calculate the realistic earth grid return current.

.. Design fault duration

For the calculation of allowable step and touch voltages, primary protection clearing time should be used.

For thermal rating, guidelines are given in section 2.11.


.. Soil resistivity

The soil resistivity can vary significantly with soil moisture content. This is an important aspect that needs to be considered when designing earthing systems. From a protection point of view, earthing systems should be designed based on the highest value of soil resistivity likely to be encountered on the site. However, the effect of soil resistivity variation on step and touch voltages depends on many factors and no simple guideline can be applied.

Data on soil resistivity variation with ‘seasons’ is not available for New Zealand. In many areas of New Zealand, where the soil moisture content is relatively constant due to regular rainfalls, ‘seasonal’ resistivity variation may not be significant. However, significant seasonal changes in soil moisture content in other areas may result in significant soil resistivity variation and, where possible, this should be taken into consideration.

For areas where significant seasonal variation in soil moisture content is expected, a conservative value of soil resistivity should be used for a design. For these situations, designs should check the sensitivity of safety levels to soil resistivity variations.

The Wenner method is the most commonly used method to measure soil resistivity. It also has the advantage of being one of the simplest methods to use and is recommended. The raw data obtained from the soil resistivity measurements is difficult to interpret and is not very useful for the design of earth electrodes. The data needs to be converted into a model that is representative of the soil resistivity at the site. Computer software can be used for this purpose.

When conducting soil resistivity tests it is important to carry out enough measurements so that an accurate soil resistivity model of the site can be derived. Measurements at a minimum number of 12 probe separations are recommended to ensure an accurate soil resistivity model can be derived. The larger probe separations should be in proportion to the size of the earth electrode/grid.

The soil resistivity model will give an indication of the structure of the soil at the site. If lower soil resistivity layers are evident from the model, then the use of deep driven rods may be considered.

.7 EPR VOLTAGES TRAnSFERRED TO THIRD PARTY ASSETS

During a HV phase to earth fault at a HV earthing system including HV conductive pole and LV MEN system that is bonded to the HV earthing system, the resultant EGVR on the HV earthing system can present a hazard to third party network plant, customers and personnel, by either of the following mechanisms:

.7.1 Hazard from nearby HV earthing systems or HV conductive poles

Third party plant such as telecommunications network plant in the road reserve (e.g. buried cable, pits, pillars, pedestals, joints, cross-connect cabinets, electronic cabinets) or railway signalling circuits or pipelines, are all effectively referenced to remote earth. This means that the EPR in the ground may stress the insulation of any adjacent telecommunications network plant, railway signalling assets and pipeline protective coatings to the full value of that EPR.


.7. Hazard arising from common HV/LV earthing systems

When a HV phase to earth fault occurs at a distribution transformer that has a common HV/LV earthing system, the resultant EGVR appears on both the distribution transformer HV earthing system and on the neutral of the LV MEN system supplied by that transformer. This means the earth potential in all buildings supplied by the distribution transformer will rise to the level of the HV earthing system EGVR (minus a small amount of volt drop along the neutral). Any mains-powered third party equipment in those buildings that is also connected to a remote earth will be stressed by virtually the full EGVR.

The main category of third party mains-powered equipment affected in this way is telecommunications equipment including equipment located in residential dwellings such as fax machines, answer machines, cordless phones, and, most commonly, computer modems. This equipment will be connected to a (remote) telephone exchange earth reference via the telecommunications network copper cable pairs, and hence will be stressed by the EGVR on the LV MEN system.

For limiting interference to telecommunication networks Electricity Regulation 58 deems EPR or induced voltages not likely to be hazardous where they do not exceed:

(a) 650 Vrms for fault durations ≤ 0.5 s; or

(b) 430 Vrms for fault durations > 0.5 s.

Additional information on EPR transfer to third party plant may be obtained from the following publications:

(c) AS/NZS 4853:2000 Electrical hazards on metallic pipelines;

(d) AS/NZS 3835:2006 Earth potential rise – Protection of telecommunication network users, personnel and plant – Parts 1 & 2.

. TYPES OF EARTH ELECTRODES

Only the following types of earth electrodes may be used:

(a) Vertical rods or pipes driven not less than 1.8 m into the ground;

(b) Horizontal grid or mesh;

(c) Horizontal bare buried conductors;

(d) Electrodes embedded in foundations;

(e) Metal reinforcement in concrete or other earth conductors in concrete.

A brief guide to selecting earthing electrode designs is set out in Table 1.


Table 1: Brief Guide on Selecting Earthing Electrode Designs

Description Example

Simple driven rod Domestic or light industrial MEN earths

Array of driven rods, horizontal conductors or rings

Roadside ground or pole mounted distribution transformers

Interconnection of a number of separate earthing systems

Distribution and associated LV MEN systems

Buried grid of horizontal conductors with or without driven rods

HV a.c. stations

Interconnection of any of the above with other large conductive structures (dams, foundations)

Power station

The design of the electrode should take into consideration the type and moisture content of the soil.

The type and embedded depth of the earth electrodes should be such that soil drying and freezing will not increase the earth resistance of the earth electrodes above the required value. Where practicable, the earth electrodes should be embedded below permanent moisture level, except for electrodes that are used for gradient control. Typically, in New Zealand, a burial depth of at least 500 mm for horizontal conductors is recommended to minimise the effects of changes in temperature and soil moisture content. In many situations, this depth is also adequate to avoid freezing of the soil surrounding the buried earth conductor. Greater burial depth should be considered in areas where freezing can occur for a significant portion of the year. Such areas are typically associated with higher ground.

The addition of driven rods to a HV a.c. station earth grid usually has a small effect on the impedance of the earth grid unless the driven rods reach lower soil layers with a reduced resistivity. Driven rods should be separated by at least a distance equal to the length of the rods. Additional rods enclosed within rows of other rods are ineffective in reducing the overall impedance.

.9 MATERIALS OF EARTH ELECTRODES AnD CORROSIOn COnSIDERATIOnS

In areas where corrosion is likely to be severe, the electrodes should be of hard drawn copper, copper bonded/clad or stainless steel, or other metal of such nature or so treated to be not less resistant to corrosion than hard drawn copper, or copper bonded or stainless steel.

In areas where corrosion is not severe, galvanised or plain steel electrodes may be used.

Aluminium should generally not be used as a buried electrode for the following reasons:

(a) Aluminium may corrode in certain soils and the layer of aluminium oxides is non conductive for all practical earthing purposes.

(b) Gradual corrosion caused by alternating currents may also be a problem under certain conditions.

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However, in some areas where the corrosion of copper is particularly severe, the use of aluminium may be considered. Around Rotorua and Taupo for example hydrogen sulphide (H2S) gas causes relatively rapid corrosion of copper, and in such areas, aluminium has been found to be more robust.

Aluminium should only be used after a thorough assessment of all circumstances. Aluminium is anodic to many other metals, including steel and, when connected to these other metals, aluminium may sacrifice itself to protect the other metals. If aluminium is used, the high purity electric conductor grades are recommended.

Where aluminium is used, it is necessary to have a regular inspection programme that includes testing and hand digging to inspect conductor condition. The inspection intervals may need to be more frequent than those listed in Table 5 (HV a.c. stations) or Table 10 (distribution centres, etc), whichever applies to the earthing installation considered.

As an alternative to aluminium, the use of zinc plated copper conductors should be considered.

Copper is by far the most common metal used for earthing systems. It has a high conductivity and has the advantage that it does not generally corrode. Copper bonded or clad steel is usually used for driven rods. The minimum thickness of the copper coating must be 250 μm (micron) to minimise the risk of rapid corrosion of the copper bonded/clad steel rods.

However, copper is often responsible for causing galvanic corrosion of other metals such as steel that are buried in the vicinity of copper.

Corrosion can have a significant impact on the integrity of both the buried electrode and the earthing connections. The design, selection of materials, and construction of the earth electrodes must take into consideration the possible deterioration and increase of resistance due to corrosion over the expected life of the installation.

There are many causes of corrosion of earthing conductors and rods, which include the following:

(c) Uneven distribution of moisture in the vicinity of the electrode;

(d) The acidity and chemical content of the soil, as well as the presence of foreign materials including cinders, scrap metal or organic material;

(e) The presence of stray electric current – particularly d.c.;

(f) The interconnection of dissimilar metals in the soil or above ground where moisture is present.

The latter is among the most common causes of corrosion of earth electrodes. For example, the connection of copper electrodes to galvanised steel water pipes may cause rapid corrosion of the water pipes.

The resistivity of the soil, as an electrolyte, is an important factor associated with corrosion. Soils having resistivities lower than approximately 15 Ω-m are likely to cause severe corrosion. Corrosion should be slight in soils having resistivities higher than approximately 200 Ω-m.

The mitigation of corrosion is complex and it is not possible to lay down rigid rules for good practice. If corrosion problems are encountered or are anticipated, these should be investigated on a case by case basis.


In areas where a considerable quantity of buried galvanised steel or structural steel is present near a copper earth electrode, stainless steel may be an attractive alternative to copper.

The use of concrete to encase the earth electrode may be used to mitigate corrosion. Conductive concrete may also be used. Concrete encased galvanised steel electrodes and steel reinforced foundations can be effective earth electrodes.

Connections that are above ground should be protected from moisture, using a waterproof compound. Copper earthing connections should also be tin plated or should be treated with other suitable compounds before being protected from moisture.

.10 JOInTS OF EARTH ELECTRODES

All buried connections, crossings and joints of earth electrodes should be welded using suitable exothermic products and moulds or by brazing. Compression or wedge type fittings may also be used underground provided these have met the requirements of IEEE Standard 837. Bolted connections must not be used underground.

Exothermic products used for welding earthing conductors must comply with the requirements of IEEE Standard 837. Exothermic mixtures must only be used with manufacturer approved moulds. Exothermic mixtures from a particular supplier must not be used in moulds from a different supplier.

Exothermic welding must only be performed by operators who have been specifically trained by a suitably qualified representative of the equipment supplier or any accredited training provider. Operators who have not carried out exothermic welds in the last six months should attend a training/refresher course before attempting to weld.

Brazed joints above or below ground are acceptable. It is recommended to provide additional mechanical retention before brazing a joint. Mechanical retention must be provided to ensure that enough brazing material flows into the interface between the two metals to fill the gap.

.11 CURREnT RATInG OF COnDUCTORS AnD JOInTS

The conductor used for earthing of primary plant must be rated to withstand short circuit currents without damage or deterioration.

When selecting a fault clearing time to be used for rating buried earth conductors, the following should be considered:

(a) All earthing conductors forming the station or distribution transformer earth electrodes must meet the requirements of IEEE Standard 80 conductor sizing factors, and a factor of safety as per section 11.3 of IEEE Standard 80-2000 in determining the conductor size. A factor of safety is required to take into account the long duration these conductors are expected to be in service and relied upon (during which prospective earth fault level could rise), and the corrosive nature of the ground soil in which they are installed.

(b) A long established New Zealand practice of rating buried conductors to withstand the expected worst case short circuit current for 3 s may be used as this is considered to meet the requirements of IEEE Standard 80. Alternatively, a lesser time than 3 s may be used, but only if two reasonably independent protection systems (that is 100%

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redundancy) will ensure fault clearance occurs in the lesser time, even if any one item of the protection systems fails to operate, and provided that the requirements of (a) are satisfied. Protection system include relays, CTs, VTs, d.c. supplies, communications systems (where appropriate) and CBs.

NOTE: The term reasonably independent secondary protection systems is not intended to imply a requirement for primary equipment to be duplicated, and only applies to secondary equipment, including current transformer cores, relay and communication systems, and in combination with a highly reliable/duplicated secondary d.c./a.c. power supplies.

When assessing suitable earth fault clearing times for the rating of buried and above ground earthing conductors, auto-reclose events may also need to be considered.

Earthing conductors also need to be physically robust and this should be considered as part of the selection process.

The buried earth conductors in an earth grid can be rated for lower fault currents, as the fault current will disperse into the ground. Typically, the buried conductors are rated for 70% of the highest prospective fault current. Additional information is given in section 5.

For conductor rating calculations, ambient temperatures of 20°C should be used for buried conductors and 30°C for above ground conductors.

For bolted or compression joints, the maximum temperature that the earthing conductor will reach must not exceed 250°C. A maximum temperature of 400°C is allowed for earthing conductors that are welded or brazed. When designing a brazing joint to withstand a temperature of 400°C, care should be taken to ensure that the brazing filler is rated for this temperature. Brazing fillers are typically rated for temperature well in excess of 400°C. Additional mechanical retention such as rivets should be used for brazed joints where appropriate. The use of solder should be carefully considered since solder typically has a much lower melting point than brazing filler.

Figure 3 and Figure 4 show the conductor ratings for various sized conductors and various fault durations (i.e. 0.5 s to 3 s) for both bolted and welded connections.

Further details on conductor ratings can be obtained from IEEE Standard 80.


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Figure 3: Copper Conductor Ratings for Bolted Connections (250°C)

Figure 4: Copper Conductor Ratings for Welded Connections (400°C)

.1 HAzARD MITIGATIOn

Once hazards associated with an earthing system are identified, mitigation must be considered. Some typical mitigation options are summarised in Table 2. These are presented as a guide only. It is important that local conditions and all alternative options are considered during the planning of risk mitigation. Various mitigation options are discussed in more detail in section 4.

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Table 2: Mitigation Options

Mitigation options Advantages Disadvantages Comments

Reduction in earthing system resistance

Can reduce EGVR and associated touch and step voltages

May require extensive additional earthing at significant expense (NOTE 1)

Often only effective if earth resistance is reduced to at least 40-50% of power system source impedance. Should be investigated at early stages to check viability. Can be very effective in significant urban areas by bonding neutrals from adjacent MEN systems to create an extensive earthing system

Installation of gradient control conductors

Easy to implement Can extend step voltage hazards further out

Very effective. Practical in most situations. Extensively used for HV a.c. station. earthing

NER Limits earth fault currents. Limits induced voltage into telecommunications circuits

Cost, although offset by lower ratings for cable sheaths.

Usually very effective for zone substations. Reduces the risks on distribution centres especially when the NER impedance is high relative to the distribution centre MEN earth impedance

Resonant earthing (Petersen Coils)

Eliminates EPR hazards. Improves system reliability

Cost Extensively and successfully used in Europe. Significant system and operation changes

OHEW Can greatly reduce EPR and induced voltages

Cost, additional pole loading, may create more frequent EPR hazard around towers or poles

Can be very effective

Cable screen bonding Can greatly reduce EPRs and induced voltage

May transfer EPR to other areas

Can be very effective. Requires proper analysis to confirm suitability

Crushed rock Can reduce touch and step voltage hazards significantly.

Not easy to specify correctly and installation requires care.

Very effective especially for substation earthing. Preferred method for substations. Should be considered as part of substation designs. May not be effective for lines 66 kV and above.

Asphalt Can reduce touch and step voltage hazards significantly

Asphalt requires integrity checks

Very effective especially for substation earthing and lower voltage distribution system. May not be effective for lines 66 kV and above


Mitigation options Advantages Disadvantages Comments

Separation of HV and LV earthing for Distribution Centres

Eliminate the hazards for the LV installation and for third party services supplied to the customer installation

Sometimes difficult to implement. Not commonly used in NZ at present. Provides no protection from HV line to LV line contact

Can be effective. Maintaining the integrity of the separation may be difficult to achieve in practice. The integrity may be compromised by LV electrode encroachment on the separation distance and by connections to other LV neutrals

TT System Easy to implement Not presently used in NZ. Will require special dispensation from the regulator

May be difficult to maintain the integrity of the system. Other contractors who do not know about the system may change it back to a MEN system

Install physical barriers or fences

Low cost, suited to smaller areas of hazards

Requires maintenance Very effective

Isolation of specific metallic conductors such as fences

Minimal cost provided few conductors require isolation

Requires regular integrity checks

Very effective. Must ensure all conductors located

Alternative power or telecommunications route

Can offer significant risk reductions even with lower physical protection

May involve additional planning issues and costs

Dependent upon risks associated with new route. Should always be considered

Isolation (telecommunications)

Low cost where few customers affected

High cost where many customers affected

Very effective

Reduce fault clearance times

May be easy to implement May require significant protection review and upgrade

Only likely to be useful if hazardous voltages do not exceed tolerable levels significantly

NOTE 1: Since this may push out any EPR contours, there is a greater chance of affecting third party plant (e.g. telecommunications networks). This may also push touch and step hazards further out – possibly into new more ‘sensitive’ areas (e.g. a children’s playground).

.1 SWITCHGEAR OPERATInG MECHAnISMS

Operating handles of earth switches and disconnectors may be a significant source of EPR hazards if the handles are not sufficiently earthed. The manual operation of an earth switch or disconnector may cause hazardous currents to flow through the earth switch or disconnector operating mechanism. Since this operation requires the presence of an operator near the structure, the operator may be subjected to hazardous touch and step voltages.

For earth switches or disconnectors located within earth grids, it is relatively easy to protect the operator against hazardous voltages. If the earth grid has been designed to be safe from touch and step voltage hazards, there is no risk to the operator. However, the operator may still be in a position to receive a significant non-fatal electric shock. For this reason, additional safety measures are usually taken to further limit touch voltages for the operator. An equipotential zone is created


for the operator by providing an earth mat (operator mat) where the operator would be standing to operate the switch or disconnector. The operator mat is bonded to the operating handle but is not bonded directly to the earth grid. In addition, it is advantageous to bond the operating rod/shaft and the mechanism box to the support stand or directly to the earth grid. The use of insulating gloves may also be considered.

For earth switches or disconnectors on a distribution network, it is more difficult to protect the operator against hazardous voltages. The installation of a buried gradient control conductor under the area where the operator will be standing could be considered. Alternatively, a driven rod is installed under the position where the operator will be standing. The buried gradient control conductor or the driven rod must be bonded to the earth switch mechanism. These measures will help to mitigate touch voltages on the operating handles but in most cases are unlikely to be enough. The use of insulating gloves is recommended.

.1 SURGE ARRESTERS

Earthing requirements for surge protection differ from earthing requirements for the control of EPR hazards. For surge protection especially from lightning, the inductance of an earthing conductor can have a significant effect on the overvoltage seen by an item of equipment. Because high frequencies are involved in a lightning surge, even a straight piece of earthing conductor can have a significant inductance. Also, the distance between the equipment and surge arresters can have a significant effect on the overvoltage at the equipment.

Typically, surge arresters should be placed as close to the equipment as possible and should have short connecting leads to the equipment and to the earth electrode. Surge arresters must not be earthed to an earth electrode that is separate from the equipment earth electrode.

For distribution centre transformers, the best protection levels are achieved when the surge arresters are installed directly on the transformer tank. The earth path between the surge arresters and the transformer tank is then minimised and the protection effectiveness of the surge arresters is maximised. When this configuration is implemented, the fuses typically end up on the supply side of surge arresters relative to the transformer. Lightning surge current discharged by the arrester passes through the fuses and may result in nuisance operation of the fuses. The frequency of nuisance failures is dependent on the type and rating of the fuses.

Surge arresters used for the protection of cable terminations should be earthed as directly as possible to the cable screens and to an earth electrode.

The placement of surge arresters in HV a.c. stations is dependent on the presence of overhead earth wires on the lines. If overhead earth wires are used on the lines, surge arresters may be placed further from the equipment being protected provided the risk of back-flashovers close to the substation on the lines is adequately managed. An insulation coordination study is usually carried out to strategically place surge arresters around the substation so that all or most of the equipment is protected.

For HV a.c. stations where the lines do not have overhead earth wires, the risk of equipment failures is typically higher. Surge arresters should then be placed as close as possible to the transformers and protection of the other substation equipment can be achieved by the use of surge arresters at the station entrances.


When surge arresters are installed on a steel structure and the structure is relied upon for the earthing of the arresters, i.e. a transformer tank, it is necessary to ensure that the cross sectional area of the steel is adequate (steel is significantly less conductive than copper) and that a good connection is achieved on the steel structure. Paint films and rust on the steel structure must be avoided.

.1 STATIOn FEnCInG

During an EPR event at a substation surrounded by a metallic fence, touch voltage hazards on the fence may be significant. Therefore, the earthing of the fence is very important since the public generally has access to the fence.

The design of the substation earthing system must include investigation of hazardous touch voltages on the fence and the risk associated with these. There may also be step voltages outside the fence that may be hazardous to the public.

The following options for earthing the fence should be reviewed as part of the design:

(a) The fence is bonded to the earth grid and is either located within the earth grid or outside the earth grid;

(b) The fence is located outside the earth grid and may be either earthed to a separate earthing conductor or earthed through the metallic support posts.

Typical practice in New Zealand has been option (a). The fence is bonded to the earth grid and is either located within or outside the earth grid.

Mitigation of touch voltages on a fence typically involves one or a combination of the following measures:

(c) The reduction of the earth grid impedance;

(d) The installation of a strip of crushed rock or asphalt outside the fence;

(e) The use of gradient control conductors;

(f) The use of non-conductive (e.g. timber) fences.

NOTE: If a fence is located outside the earth grid and is bonded to the grid, then the addition of a gradient control conductor outside the fence effectively means that the fence is contained within the earth grid.

To mitigate touch voltage hazards on the fence the option of locating the fence outside the earth grid may also be considered. This involves providing a separation distance between the fence and the earth grid, and bonding the fence either to a separate earth conductor or relying on the fence metallic supports for earthing. Touch voltage hazards are mitigated by placing the fence at or near an EPR contour that would result in acceptable touch voltages on the fence. A gradient control conductor located outside the fence and bonded to the fence can be added to limit touch voltages if required.


For this option to work effectively, it is necessary to maintain the same separation distance between the fence and the earth grid around the whole perimeter of the earth grid. Also, the following should be considered:

(g) Maintain the separation distance between the fence and the earth grid at all times. The separation distance may be compromised by other services such as metallic water pipes or by other earth conductors added at a later stage;

(h) The falling of an overhead live conductor onto any fence may cause additional hazards. However, the probability of such a conductor falling on a fence is considered low;

(i) Variation in the soil resistivity around the site may cause touch voltages to appear on the fence at various locations. This issue cannot be predicted by modelling and can only be verified by testing.

.1 COnnECTIOn POInTS FOR TEMPORARY EARTHS

The provision of earthing points for the application of temporary earths inside HV a.c. stations must be considered as part of the earthing design. The earthing points should be positioned to ensure that temporary earths can be safely applied to equipment.

The provision for temporary earthing on distribution networks is beyond the scope of this document. Guidelines for temporary earthing on distribution networks can be obtained from the EEA ‘Guide to work on de-energised distribution overhead lines’.

.17 EARTH ELECTRODE EnHAnCEMEnT

Methods of electrode enhancement include the encasement of the electrode in conducting compounds and the chemical treatment of the soil surrounding the electrode. These methods may be considered in certain circumstances as a possible solution to the problem of high electrode resistance to earth. They may also be applied in areas where considerable variation of electrode resistance is experienced due to seasonal climatic changes.

.17.1 Conductive concrete and other compounds

The use of conductive concrete and other compounds, such as bentonite, is a practical means of reducing the resistance of earth electrodes. It can also result in electrode resistance values that are less susceptible to fluctuation with temperature, humidity and soil moisture content than non-encased electrodes. In some circumstances, it may be the only practical way of reducing the electrode resistance to within acceptable limits.

.17. Chemical treatment

Chemical treatment of the soil surrounding an electrode should only be considered in exceptional circumstances where no other practical solution exists, as the treatment requires regular maintenance. Since there is a tendency for the applied salts to be washed away by rain, it is necessary to reapply the treatment at regular intervals.

Chemicals should only be applied if these are approved for use by local authorities.


.1 TESTInG AnD MAInTEnAnCE

Owners of works are required to take all practicable steps to maintain their earthing systems to meet the requirements for safety and functional operation. Owners must establish and operate administrative systems (including records of checks undertaken) that provide periodic safety checks at reasonable intervals appropriate to the operating environment and operational risks.

The asset owner should determine appropriate inspection and test intervals based on its knowledge of its earth electrodes installation and design standards, and on its understanding of environmental conditions and assessment of risk, e.g. soil conditions, theft of copper, etc.

The earth impedance of an earthing system should be determined by testing at the time of installation to verify that the actual earth impedance is below its maximum desired value and also to establish a benchmark against which later measurements can be compared.

Continuity tests carried out to verify the integrity of earthing connections between equipment and the earth grid, and between the earth grid and the system neutrals should test to a common reference point (or several common reference points depending on the size of the substation) using a micro-ohmmeter. A maximum resistance of approximately 10 milli-ohm per bond test should be obtained.

When work has taken place that may have interfered with the earthing system, the system in that area must be inspected and checked. All parts of the earthing system exposed by excavation should be inspected for damage or deterioration.

Where there is any probability of significant corrosion of the buried earth grid, more frequent inspections of the earth grid and connections must be carried out and replacements made where necessary.

To enable the integrity of the earthing installation over a long period of time and its suitability for present fault levels to be assessed the following records must be maintained:

(a) Initial design calculations where applicable;

(b) Results of periodic inspections and measurements;

(c) Updating of fault level;

(d) Drawings showing the earth electrode layout including location and size of all earth conductors and driven rods, and the location of all grid connections and/or joints.

Additional guidelines are provided in sections 5, 6 and 7.

7


SECTIOn – EPR RISk MAnAGEMEnT

Risk management is an internationally recognised tool for designing systems and processes. Information about risk management be obtained from AS/NZS 4360 and SAA/SNZ HB 436.

New Zealand Electricity Regulations reflect an outcome-based approach to EPR safety involving risk management instead of requiring certain prescriptive criteria to be met as in the deterministic method. This enables network companies to design systems based on optimising costs but at the same time minimise risks to the public.

To manage the risk from EPR events, either of the following two methods may be used:

(a) The probabilistic method;

(b) The deterministic method.

The probabilistic method identifies the types and extent of the region or area where an individual or a group of individuals is potentially at risk. It then evaluates the likelihood of a hazard event occurring when an individual or group of individuals is present.

The probabilistic method is suitable as a general approach and may be applied to any location. It is especially suitable for locations where hazard events are relatively rare and or where exposure would be typically very short.

The deterministic method determines if hazardous step and touch voltages are present on the basis of internationally acceptable limits of body currents. Probabilities of exposure to the hazard and of the hazard occurring are not calculated. The method proceeds with the design of the earthing system to ensure calculated body currents are reduced to acceptable limits.

The deterministic method has been adopted for controlled areas, such as substations, where faults are relatively frequent. It is also adopted elsewhere as a threshold beyond which harm is exceedingly unlikely to occur.

A PROBABILISTIC METHOD

During earth faults on HV network assets, there may be some areas or zones on or around the structures where hazardous step and touch voltages occur. The risk associated with these hazardous voltages must be managed. This may require a change in design to eliminate or reduce the risk where required or in cases where the risk of harm is already acceptably low, no further action is required.

The probabilistic method is an earthing system design process whereby the risk associated with hazardous voltages is identified and evaluated against given criteria to determine whether the risk needs to be mitigated.

This method is comprehensively described in the EEA ‘Guide to risk based earthing system design’.

The probabilistic method essentially consists of the following main elements:


The probabilistic approach assumes, should a fault occur while a person is located in a hazard area, that:

(a) The person simultaneously makes electrical contact with the hazard;

(b) The contact resistance surfaces external to the person are conductive, that is, typically the ground conditions are damp, and the other point of contact is fully conducting, that is, treated as metallic or having no resistance;

(c) That the clothing and footwear of the person, age weight and condition are such that fatal fibrillation will occur.

The method then proceeds to evaluate the level of risk of death based on these assumptions.

The risk associated with power system earth faults depends on two factors:

(d) The probability that a person may be exposed to a potentially hazardous voltage;

(e) The consequences of exposure to that hazardous voltage.

In the context of this guide, risk is therefore defined as:

RiskA combination of both the probability of an event (that may result from the presence

of any hazard) and the associated consequence of that event

The risk assessment requires the frequency of earth faults to be estimated for a particular structure or group of structures, and also requires estimation of the level of exposure individuals may have to the hazards associated with these faults.

As only limited recorded data may be available for specific structures, the assessment may need to be based on records of typical fault statistics for similar assets. It may also require the type of land use to be categorised and typical exposure levels to be applied.

The risk management process in the context of this guide may be divided into the following steps:

Step 1 Collect basic data: earth fault current, fault clearing time, soil resistivity and probability of earth fault occurring. Consider the effects that EPR transfer may have on all nearby third party plant.

Step 2 Determine the minimum earthing system that could meet the functional requirements. Detailed design is necessary to ensure that all exposed conductive parts, are earthed. Extraneous conductive parts that may constitute a hazard must be earthed. Any structural earth electrodes associated with the installation should be bonded and form part of the earthing system. If not bonded, it is necessary to verify that all appropriate safety requirements are met.

9


Step 3 Based on soil characteristics and the likely proportion of total earth fault currents flowing into the local earthing system (see section 2.6), determine the maximum EGVR.

Step 4 Based on the earth fault clearing time and the top soil layer resistivity, determine the tolerable touch and step voltages as detailed in sections 3.7 and 3.8. Additional tolerable limits may be determined as required following the procedure detailed in Appendix A. Also determine the tolerable transferred voltage limits. The transferred limits are dependent on the type of third party asset being considered. The tolerable voltage limits may be used as means of compliance as per Step 5 and Step 7.

Step 5 If the EGVR is below the tolerable step, touch and transferred voltage limits, the design is basically completed and can proceed from Step 10.

Step 6 If not, determine actual step, touch and transferred voltages inside and outside the earthing system.

Step 7 If the actual step, touch and transferred voltages are below the tolerable limits, the design is basically completed. Proceed to Step 10.

Step 8 If not, assess the risk.

Step 9 If required, improve the design and identify and implement appropriate risk treatment measures and then recalculate the residual risk level following treatment. Typical mitigation measures are discussed in section 4.

Step 10 Check on other requirements:

(a) Determine if low voltage equipment is exposed to excessive stress voltage. If this is the case, proceed with mitigation measures, which can include separation of HV and LV earthing systems;

(b) Consider the need to implement any particular precautions against lightning and other transients.

Step 11 The design can be refined, if necessary, by repeating the above steps.

Step 12 Provide installation support as necessary to ensure the design requirements are fulfilled and staff safety risk is effectively managed.

Step 13 Review the installation for physical and safety compliance following the commissioning programme.

Step 14 Documentation of the earthing system design should include a physical installation description, (e.g. drawing), as well as details of the electrical assumptions, design decisions, any risk analysis (context, assumptions, methodology, risk control options adopted, etc.), commissioning data and supervision and maintenance requirements.

The steps do not have to be followed in the order given above. In some cases, it may be more appropriate to start with a risk assessment, for example, where the asset owner wants to classify sites into risk categories.

In the following sections, a brief outline of the probabilistic method is provided and the explanations are limited to a simple case (base line case). This brief outline is by no means comprehensive and, before applying the risk assessment process, it is essential to be familiar with the details of the risk assessment process that is contained in the EEA ‘Guide to risk based earthing system design’.


0

.1 RISk IDEnTIFICATIOn AnD AnALYSIS

All life has an associated level of risk; however, the nature of that risk is a significant factor in the tolerance of society to it. The identification of the risk may be categorised according to the consequence (shock, injury or fatality), whether the individual has a choice (voluntary or involuntary) or whether multiple individuals are exposed to the hazard.

3.1.1 Identificationofvoluntaryandinvoluntaryrisk

There is little tolerance for involuntary risks associated with hazards for which there is no escape, no warning and no opportunity for individual judgement. Public exposure to EPR events is classified as involuntary risk.

Voluntary risk associated with activities for which individuals have control over the outcome, (e.g. smoking or not following correct maintenance procedures), are more tolerable as individuals may choose to avoid exposure to the associated hazards. In such cases the occurrence of a hazard is therefore often related to the exposure of the individual(s) who caused the hazard and risk analysis can be complex. Thus, voluntary risk and risk to maintenance personnel who may be involved in activities that may cause the hazard will not be included in the following summary of risk assessment.

.1. Individual and societal risk

The risk associated with a hazard may be classified according to the type and number of people who may be affected by the hazard. The individual risk represents the acceptable risk to an individual, while the societal risk represents the acceptable risk to single or multiple individuals of sensitive members of society to whom injury or fatality may result in a widespread adverse social response, (e.g. a class of school children).

.1. Quantitative risk analysis

A quantitative value may be determined that is proportional to the probability of individual exposure when an earth fault occurs. The following example is valid provided the conditions specified in (a) to (d) are applicable to the situation under review:

(a) The occurrence of earth faults is random;

(b) Earth faults are equally likely to occur independent of season or time of day;

(c) Earth faults are independent of exposure (exposed individuals do not cause faults and faults do not cause individuals to become exposed);

(d) The length of an earth fault is considerably less than the average length of exposure.

For situations where one or more of conditions (a) to (d) are not applicable, a more detailed risk assessment must be carried out as described in the EEA ‘Guide to risk

based earthing system design’.

1


The probability that a dangerous event may occur may be calculated using an exposure factor (Ef) and an earth fault frequency factor (Ff).

The exposure factor represents the annual exposure of an individual to a hazard:

yeara in hours of Number

hours) (in yearper exposure of durationTotalE

f=

The earth fault frequency factor (Ff) represents the earth fault frequency:

Ff = Average number of hazardous EPR events per year

The probability ‘P’ that the specified hazard event occurs when an individual is exposed to that hazard.

P = Ef Ff

The societal risk is represented by the equivalent number of people N and accounts for the reduction in tolerance for injury or fatality to large numbers of people. If n people are present in the hazard area at any given time then the equivalent number of people is:

N = n for n < 4 n2 – n for n ≥ 4

The scaling factor N may be used to calculate an ‘equivalent probability’ Pe that is equivalent to the individual risk probability after the adjustment N for societal tolerance has been introduced.

Pe = N Ef Ff

. RISk EVALUATIOn CRITERIA

The calculated equivalent probability may be assessed according to the risk management matrix of Table 3 to determine a qualitative estimate of the risk associated with a hazard.

Table 3: Risk Management Matrix

Equivalent probability

(per annum)

Riskclassificationfor individual death

Resulting implication for hazard mitigation

> 10-4 High IntolerableMust prevent occurrence regardless of costs

10-4 – 10-6 Intermediate

ALARP for Intermediate RiskMust minimise occurrence unless risk reduction is

impractical and costs are grossly disproportionate to safety gained

<10-6 LowALARP for Low Risk

Minimise occurrence if reasonably practical and cost of reduction is reasonable given project costs

Risk analysis must always be applied with caution and wisdom. Risk analysis cases, that do not prove straightforward, or that give results that are significantly different from the standard solutions, should be peer reviewed by a professional expert in safety-related risk analysis.


..1 The ALARP principle

The as-low-as-reasonably-practicable (ALARP) principle is an internationally recognised tool for the evaluation of risk. It offers an appropriate method for the evaluation of risks associated with earthing hazards.

The ALARP region represents the limits in which the risk should be lowered to levels as low as is reasonably practical and where some trade-off between risk and the relative benefit may be appropriate.

This ALARP region is subdivided into two areas. For the higher area the risk must be minimised if it is ‘reasonably practicable’ to do so and costs are not ‘grossly disproportionate’ to safety gained. This level of risk is described as ‘intermediate’. For the lower area, the risk is termed ‘low’ and should be minimised if it is reasonably practical to do so and if the cost of reduction is reasonable given the project costs. Within the ALARP region, cost-benefit type analysis may be used to determine the appropriate level of resources that should be allocated to reducing the risk associated with the earthing system. Thus the ALARP principle allows cost to be taken into account in determining how far to go in the pursuit of safety, so that if a risk reduction measure involves ‘grossly disproportionate’ cost, it is not ‘reasonably practicable’.

. COST BEnEFIT AnALYSIS AnD MITIGATIOn

Cost benefit analysis can be applied to assess the cost of public deaths. In some cases it may also be prudent to include indirect as well as direct costs in a cost benefit analysis. These indirect costs may include legal costs and less tangible items like cost to reputation and corporate public image.

Where risk has been deemed to be ‘intermediate’, then it is appropriate to carry out a cost benefit analysis (CBA) to establish the relative cost of risk treatment or the value of the risk reduction options. In the ‘low’ risk case a CBA will also help establish whether any possible risk treatment option is cost-effective. In the case of human safety, to carry out such an analysis, it is necessary to use a ‘value of life’ figure – normally referred to as the value of statistical life (VoSL).

Various studies of VoSL carried out around the world [1], [2] show that values varying between approximately $2 million and $20 million have been used in various countries, including Australia and New Zealand. Abelson stated that, given research findings as a whole and values employedAbelson stated that, given research findings as a whole and values employed in Europe, $3 million to $4 million would appear to be a plausible VoSL for a healthy prime age individual in Australia at present. In New Zealand, the Ministry of Transport [4] uses a VoSL of $3.2 million. This value has been used by the Ministry in all safety evaluations across all three transport modes (road, maritime and aviation), as decided by the Government in 1991 (NZ Gazette notice 4983).

The selection of a VoSL for carrying out CBAs when evaluating EPR risks needs to account for the following:

(a) The public’s expectation that power systems are ‘safe’ provided they are not tampered with;

(b) The possibility that those at risk may be ‘vulnerable’ (young, old, infirm);

(c) The ‘involuntary’ nature of the risk to the public;

(d) The utility’s image and reputation.

For the purpose of this guide, a VoSL of $10 million has been used.


For example, if the equivalent probability Pe has been calculated as 10-5, then the risk level is ‘intermediate’. This means that a cost benefit analysis should be done to determine if it is cost-effective to implement risk treatment measures. This equivalent probability is equivalent to one individual fatality per 100,000 years (= Pe-1) and since the VoSL is $10,000,000, over a period of 100,000 years the liability per year is:

yearper100$10x1x000,000,10$

PxVoSLP

VoSLL

5

e1e

==

==

−

−

Where: L = Asset owners liability per year (dollars).

The present value of risk treatment can be calculated using the remaining lifespan of the asset, the liability per year and the expected rate of interest on an alternative investment (discount rate). The present value (PV) figure calculated is considered a positive return as the investment into the elimination of hazards will result in a reduction of the liability equal to the PV.

Where: PV = Present value (dollars) L = The asset owner’s liability per year (dollars) D = Discount rate (fractional rate of interest) Y = Number of years which the asset will remain potentially hazardous (years).

If a discount rate of 0.04 (4%) is used then the present value of the reduction in liability can be calculated as approximately $2,148 for a remaining asset lifetime of 50 years. A discount rate of 4% is used in this context as a conservative representation of the interest on the opportunity cost investment. The choice of discount rate has a significant effect on the PV calculated and should be chosen carefully [5].

The PV is used to provide a guide on the appropriate level of expenditure that should be used when determining whether risk treatment is a cost-effective option. The PV is compared to risk treatment costs to ensure that costs are not grossly disproportionate to the reduction in liability.

In this case, comparing this figure to the costs of risk treatment (say $5,000), it appears that the implementation of treatment is not cost-effective. However, as this Pe equates to an ‘intermediate risk’, the cost is clearly not ‘grossly disproportionate’ and so risk treatment should be applied.

In certain situations the implementation of a risk treatment option may not entirely eliminate the probability of fatality, but merely reduce the probability to a lower value. A cost benefit analysis may be applied using the amount by which the probability has been reduced to determine whether the risk treatment option is worthwhile.

It should also be borne in mind that, even for ‘low risk’ situations where CBA indicates risk treatment is not required, a continuous monitoring and review process still needs to be carried out to ensure that the overall risk level remains within the ‘low risk’ region. In the case of high cost projects it may be argued that relatively low cost risk treatment is always to be incorporated as this is the precautionary approach.


. PROBABILISTIC RISk MAnAGEMEnT PROCESS

A risk management flowchart based on Steps 1 to 14 is provided in Figure 5.

Figure 5: Probabalistic Risk Management Flowchart

NOTE: For the ‘low’ risk category, the risk is generally acceptable. However, risk treatment should be applied if the cost of the risk treatment was small compared to the overall project cost. A cost benefit analysis may be required to assess the cost of the risk treatment against the overall project cost.


Depending on the asset and the circumstances, the steps in the flowchart may be applied in a different order.

. PERMISSIBLE TOUCH AnD STEP VOLTAGE LIMITS

The hazard to human beings is that a current will flow through the region of the heart that is sufficient to cause ventricular fibrillation. Permissible current limits may be derived from either IEC 60479-1 or IEEE 80. IEC 60479-1 curve c2 is the appropriate curve to be used for this purpose. For earthing system design, current limits need to be translated into voltage limits for comparison with the calculated touch and step voltages taking into account the impedance present in the body current path.

For the purpose of applying the deterministic method or the probabilistic method, touch and step voltage limits must be derived based on the following criteria:

(a) The proportion of current flowing through the region of the heart;

(b) The body impedance along the current path. For voltage limits derived using IEEE 80 current limits, a fixed body impedance of 1,000 Ω is used. For voltage limits derived from IEC 60479-1 curve c2, the IEC 60479-1 50% body impedances are used;

(c) The applicable series resistance such as between the body contact points and the soil or protective equipment such as shoes;

(d) The fault duration.

The sequence to be followed to determine the voltage limits is shown in Figure 6.

Figure 6: Method for Calculating Touch and Step Voltage Limits

Details of the method for calculating touch and step voltage limits are shown Appendix A.


B DETERMInISTIC METHOD

The deterministic method consists of meeting safety criteria based on internationally acceptable levels of risk. Design of earthing systems based on these safety criteria can be carried out where it is not desirable to carry out a full risk assessment. In this process, the safety criteria are acceptable step and touch voltage limits that may be applied to various situations and depend on the broad risk associated with these situations. Two typical locations, special locations and normal locations, were defined to represent broad risk categories and are detailed in section .6.

The deterministic method is typically used for HV transmission substation and distribution zone substations where it is considered that any exposure to calculated body currents above appropriate levels selected from international standards such as IEEE 80, or the IEC 60479-1 are unacceptable. Hence, the deterministic method is used in situations where it is considered there are both high contact voltage hazards and high fault frequency rates that electrical workers in these environments can be exposed to. IEEE 80 sets the industry benchmark for the practices applied to these kinds of locations.

The deterministic method may also be applied to distribution centres and distribution equipment, especially to those where a high public exposure can be expected.

The practice of classifying locations, into normal locations, and special locations, where there can be very high exposure levels, provides a basis for mitigating around the perimeter of HV transmission substations and zone substations. In these situations, empirical formulae may be used to mitigate the hazards to acceptable levels. Alternatively, the probabilistic method may also be used.

If the deterministic criteria are satisfied in areas accessible to the public, then no further measures/ mitigation is required. It is only where the deterministic criteria are exceeded in such areas that the more onerous probabilistic approach may be required.

Step and touch voltage limits are derived from the current limits of IEC 60479-1 or IEEE Standard 80 as detailed in section 3.5 and Appendix A. Earthing systems are designed to ensure that step and touch voltages do not exceed these limits. The design process is illustrated in Figure 7.

IEEE Standard 80 limits are typically used for evaluating EPR safety associated with HV a.c. stations and are not covered further in the following sections since the derivation of limits from IEEE Standard 80 is relatively simple, being based on formulae. For HV a.c. stations, impedances of shoes and gloves have historically not been considered when assessing EPR safety for HV a.c. stations. This approach has provided some conservatism to the designs. Additional information on the use of IEEE Standard 80 for HV a.c. stations is given in section 5. More information about the IEEE Standard 80 safety limits may be obtained directly from the standard.

Step and touch voltage limits have been derived from the current limits of IEC 60479-1 and are presented in sections 3.7 and 3.8.

The following recommended voltage limits for touch and step voltages are appropriate risk management strategies for minimising these hazards. However, it must be remembered that these voltage limits do not remove all risk. So, if even lower voltages can be readily achieved at no or little extra cost, this should still be done.

7


Figure 7: Deterministic Method Flowchart

. ExPOSURE DEFInITIOnS

..1 Special location

A special location is defined as any area where a significant gathering of people may occur in particular situations and/or where people may not be wearing footwear.

Special locations could be found in areas such as within a school’s grounds or within a children’s playground, or within a public swimming pool area, or at a popularly used beach or water recreation area, or in a public thoroughfare.

Special locations can either be in urban or rural areas.

.. normal location

A normal location is defined as any urban or rural area other than a special location.


.7 PERMISSIBLE TOUCH VOLTAGES

Using the method detailed in Appendix A, touch voltage curves based on IEC 60479-1 have been calculated below for special and normal locations. The calculation of touch voltages using IEEE Standard 80 current limits is easily achieved using equations as detailed in Appendix A and has not been carried out in this section.

IEC 60479-1 contains body impedance data for dry, water-wet and saltwater-wet conditions and also for three surface areas of contact. For the purposes of this document, the body impedances for dry and water-wet conditions and for the large contact surface area are considered appropriate. However, the data for dry and water-wet conditions are very similar, especially for fault durations below 1.5 s. Therefore, as a simplification, only the slightly conservative data for the water-wet conditions have been used.

.7.1 Special location

Acceptable touch voltage limits have been developed for use in special locations assuming the following:

(a) Bare hands;

(b) One hand-to-feet current path;

(c) The 50% human body impedance value in IEC 60479-1, for the given voltage applied across the body. (This human body impedance value is exceeded by 50% of the population);

(d) Human body current derived from the 5% probability of ventricular fibrillation curve (IEC 60479-1 curve c2, for the left hand-to-foot current path), for the appropriate maximum fault duration;

(e) Additional contact impedance with the ground;

(f) Bare feet.

Typical permissible touch voltage curves in Figure 8 have been developed for use in special locations. The curves apply for contact impedance with various soil resistivities between 50 Ω-m and 1,000 Ω-m or contact impedance for crushed rock or asphalt. Shoe impedance must not be considered for special locations.

49


Figure 8: Touch Voltage Limits for Special Locations excluding Shoe Resistance

NOTE 1: For the curves in Figure 8 a resistivity value of 5,000 Ω-m has been used for crushed rock and 15,000 Ω-m for asphalt.

2: The dashed section of the asphalt curves in Figure 8 indicates voltage limits for which the withstand voltage of the asphalt layer may be exceeded (see section 4.7).

3.7.2 Normallocation

Acceptable touch voltage limits have been developed for use in various normal locations assuming the following:

(a) Bare hands;

(b) One hand-to-feet current path;

(c) The 50% human body impedance value in IEC 60479-1, for the given voltage applied across the body. (This human body impedance value is exceeded by 50% of the population);

(d) Human body current derived from the 5% probability of ventricular fibrillation curve (IEC60479-1 curve c2, for the left hand-to-foot current path), for the appropriate maximum fault duration;

(e) Additional contact impedance with the ground;

(f) Impedance of 2,000 Ω per shoe.

Typical permissible touch voltage curves in Figure 9 have been developed for use in normal locations. The curves apply for contact impedance with various soil resistivities between 50 Ω-m and 1,000 Ω-m or contact impedance for crushed rock or asphalt.


50

Figure 9: Touch Voltage Limits for Normal Locations including 2,000 Ω Shoes

NOTE 1: For the curves in Figure 9 a resistivity value of 5,000 Ω-m has been used for crushed rock and 15,000 Ω-m for asphalt.

2: The dashed section of the asphalt curves in Figure 9 indicates voltage limits for which the withstand voltage of the asphalt layer may be exceeded (see section 4.7).

3.8 PermissiblestePVoltages

Using the method detailed in Appendix A, step voltage curves based on IEC 60479-1 have been calculated below for special and normal locations. The calculation of touch voltages using IEEE 80 current limits is easily achieved using equations as detailed in Appendix A and has not been carried out in this section.

IEC 60479-1 contains body impedance data for dry, water-wet and saltwater-wet conditions and also for three surface areas of contact. For the purposes of this document, the body impedances for dry and water-wet conditions and for the large surface area of contact are considered appropriate. However, the data for dry and water-wet conditions are very similar, especially for fault durations below 1.5 s. Therefore, as a simplification, only the slightly conservative data for the water-wet conditions have been used.

The heart-current factor defined in IEC 60479-1 permits the calculation of currents through paths other than left hand-to-feet, that represent the same danger of ventricular fibrillation as that corresponding to the body current curves c1, c2 and c3. AS/NZS 60479:1-2002, which is based on the earlier IEC 60479-1:1991, did not include a heart-current factor for the foot-to-foot path. Historically, the heart-current factor for the foot-to-foot path has been taken as one that is conservative.

1


In IEC 60479-1:2005 a heart-current factor of 0.04 has been introduced for the foot-to-foot path. This implies that 25 times more current flowing through the foot-to-foot path is required to create the same risk of ventricular fibrillation compared to the current flowing in the left hand-to-feet path. For example, a current of 2,000 mA from foot-to-foot has the same likelihood of producing ventricular fibrillation as a current of 80 mA from left hand-to-both-feet.

According to IEC 60479-1:2005, the heart-current factors are to be considered as only a rough estimation of the relative danger of the various current paths inducing ventricular fibrillation.

A heart-current factor of 0.04 for the foot-to-foot path is very low and would produce very high tolerable step voltage limits and corresponding high tolerable currents. However, such high currents may cause other serious effects such as:

(a) Internal injuries;

(b) Burns;

(c) Cardiac arrest other than ventricular fibrillation;

(d) Irreversible damage to cells and tissue;

(e) Respiratory effects including functional disturbance of respiratory control, paralysis of respiratory muscles, damage to the neural activation pathways for these muscles, and damage to the respiratory control mechanism within the brainstem.

Respiratory effects, if permanent, may lead to death.

Also, if current flows through critical parts such as the spinal cord, death can occur.

The above effects are under consideration and, for them, thresholds are not yet defined by IEC 60479-1.

Therefore, it is considered prudent to use a more conservative heart-current factor. A heart-current factor of 0.1 is considered appropriate and has been used in this guide for calculating permissible prospective step voltage limits (see Appendix A4).

..1 Special location

Acceptable step voltage limits have been developed for use in special locations assuming the following:

(a) Foot-to-foot current path;

(b) The 50% human body impedance value in IEC 60479-1, for the given voltage applied across the body. (This human body impedance value is exceeded by 50% of the population);

(c) Human body current derived from the 5% probability of ventricular fibrillation curve (IEC 60479-1 curve c2, for the left hand-to-foot current path), for the appropriate maximum fault duration;

(d) Additional contact impedance with the ground;

(e) Bare feet.

Typical permissible touch voltage curves in Figure 10 have been developed for use in special locations. The curves apply for contact impedance with various soil resistivities between 50 Ω-m and 1,000 Ω-m or contact impedance for crushed rock or asphalt. Shoe impedance shall not be considered for special locations.


Figure 10: Step Voltage Limits for Special Locations excluding Shoe Resistance

NOTE 1: For the crushed rock curve in Figure 10, a resistivity value of 5,000 Ω-m has been used for crushed rock.

2: The curve for asphalt is not provided in Figure 10 since the withstand voltage of the asphalt layer will most likely be exceeded for the very high limits that would be associated with asphalt (see section 4.7). Therefore the asphalt layer should not be considered for step voltage limits.

.. normal location

The prospective tolerable step voltage limits are very high, especially for the shorter earth fault durations, and may be well in excess of the withstand voltages for shoes. For this reason, footwear impedance should be ignored when assessing step voltages and the prospective tolerable limit curves from Figure 10 should be applied.

.9 CASE STUDIES

Case studies to illustrate the principles detailed in section 3.8 are included in Appendix B.


.10 REFEREnCES

[1] ‘The Value of Life and Health for Public Policy’, Peter Abelson, Macquarie University, Economic Record Conference Edition, Vol. 79, pp. 2-13, June 2003.

[2] ‘The Value of a Statistical Life: A Critical Review of Market Estimates Throughout the World’, Viscusi and Aldy, Harvard Law School John M. Olin Center for Law, Economics and Business Discussion Paper Series 2002.

[3] ‘Establishing a Monetary Value for Lives Saved: Issues and Controversies’, Peter Abelson, Sydney University, Cost-Benefit Conference, Office of Best Practice Regulation, Canberra, November 2007.

[4] ‘The Social Cost of Road Crashes and Injuries: June 2007 update’, Ministry of Transport, New Zealand.

[5] ‘The Shadow of the Future: Discount Rates, Later Generations, and the Environment’, Farber, Hemmersbaugh, Vanderbilt Law Review 46: 267-304, 1993.


SECTIOn – RISk MITIGATIOn MEASURES

In this section, measures that can be used to mitigate the risk of injury or death to people arising from EPR events on power systems are presented. Most of the mitigation measures are concerned with reducing the hazards.

.1 EARTHInG SYSTEM IMPEDAnCE REDUCTIOn

Reduction in the impedance of an earthing system can be effective in reducing the EPR hazards. However, since the fault current usually increases as the earth grid impedance decreases, the effectiveness of the reduction depends on the impedance of the earth grid relative to the total earth fault circuit impedance. For the reduction to be effective, the reduced impedance needs to be low compared to the other impedances in the faulted circuit. Typically, the earth grid impedance must approach the power system source impedance before the EGVR starts decreasing significantly.

For example, consider an earth fault at a zone substation fed via a 33 kV line from a Transpower substation with a prospective earth fault level of 7 kA. The source impedance and the earth grid impedance at the Transpower substation is approximately j2.7 Ω and 0.5 Ω respectively. Figure 11 shows the EGVR and the earth fault current at the zone substation as a function of the zone substation earth grid impedance. For this example, the zone substation has been assumed to be located close to the Transpower substation, (i.e. the line impedance is approximately zero).

As the impedance of the zone substation earth grid is reduced from 20 Ω to 5 Ω, the EGVR is only reduced from 18.4 kV to 15.5 kV since the earth fault current increases from 0.9 kA to 3.1 kA. As the zone substation earth grid impedance reduces below the power system source impedance, the reduction in the EGVR becomes more significant.

Figure 11: Variation of EGVR with Earth Grid Impedance


If the earthing system earth impedance is reduced by enlarging the earthing system, then even though the EGVR on the earthing system will reduce, the resultant EPR hazard voltage contours may be pushed out further. In some circumstances, the increase in the size of the EPR contours may be significant for a small reduction in the EGVR. As a result, the size of any transferred EPR hazard zones will increase. Whether this is a desirable end result will depend on the specifics of a particular situation.

If the earthing system earth impedance is reduced by bonding remote earths to it, then the resultant reduced EGVR is also spread to the remote earths. This also introduces new transferred EPRs onto the earthing system anytime there is an earth fault causing EPR at any of these remote earths. Examples of this include bonding towers to substations via overhead earth wires, and bonding the earthing system to extensive LV MEN systems. This mitigation measure can be very effective in significant urban areas where an extensive earthing system can be obtained by bonding together neutrals from adjacent MEN systems.

If the main problem that needs to be addressed is the size of the transferred EPR hazard zone, one option that could be considered is making the earthing system smaller. This will shrink the size of these hazard zones, but at the cost of increasing the EGVR on the system and the associated touch voltages.

For this reason, a starting point for the design of many HV earthing systems could be to make them no bigger than they have to be to meet essential performance requirements.

. GRADIEnT COnTROL COnDUCTORSTouch voltages on a structure can be controlled by burying a conductor at a distance of one metre from the structure. These conductors increase the voltage on the ground at the position where a person could be standing, thereby reducing the voltage difference between the structure and the person’s feet. These conductors are termed gradient control conductors and are widely used for the control of touch voltages on earthed structures.

In HV a.c. stations, gradient control conductors are often used for the control of touch voltages outside the station security fence. These conductors, which are typically buried at a depth of 0.5 m, one metre outside the fence, are very effective when used in conjunction with a 1 m wide strip of crushed rock or asphalt installed around the outside of the fence. Often this effective mitigation measure cannot be implemented because the fence is installed on the boundary of the property. When designing HV a.c. stations, consideration should be given to installing the security fence at least one metre into the property to provide for a strip around the fence.

Gradient control conductors can also be used to control touch voltages on distribution centres and equipment.

Table 6 in section 6.5.2 details typical touch voltage levels as a percentage of EGVR for various pole or pad mounted transformer or equipment arrangements. The touch voltage on a pole or pad mounted transformer and equipment is typically between 40% and 50% of the EGVR if the earth electrode is distributed on two sides of the distribution centre or equipment. When the earth electrode is installed on one side only, the touch voltage is typically between 60% and 70% of the EGVR. If one gradient control conductor is installed at a distance of one metre around the earthed structure, the touch voltage is reduced to approximately 20 – 30% of the EGVR, depending on the configuration of the earth electrode, (i.e. to one side only or on two sides). The touch voltage can be further reduced by the installation of a second gradient control conductor at a distance of one


metre out from the first conductor, (i.e. two metres from the earthed structure). In this case, the touch voltage is approximately 15 – 20% of the EGVR.

Step voltages can also be controlled with the use of gradient control conductors. Gradient control conductors may be positioned in a concentric configuration at increasing distances from the structure, i.e. 1 m, 2 m, etc., and the buried depth of each gradient control conductor is increased as the distance increases. However, this measure may not be always effective or practical. It may also push the hazard further out from the structure.

. nEUTRAL EARTHInG RESISTORS

Neutral earthing resistors (NERs) are employed in distribution networks to limit the current that would flow through the neutral star point of a transformer or generator in the event of an earth fault.

NERs can be very effective in reducing induction into parallel services such as telecommunication circuits or pipelines.

NERs can also reduce the EGVR at a faulted site on a distribution line, but the reduction may not always be significant and may not always result in a site that is safe from EPR hazards. For example, with a 20 Ω NER installed at an 11 kV source, the EGVR at a faulted site with an earth electrode resistance of 10 Ω will be approximately between 1.5 kV and 2 kV. For a faulted site with a resistance of 50 Ω, the EGVR may be as high as 4 kV even with the 20 Ω NER.

Many distribution centres and other structures, such as concrete poles that are not bonded to an extensive MEN system, are likely to have earth electrode resistances of 50 Ω or more. This implies that conventional NERs, which typically have an impedance of no more than 50 Ω, cannot usually be used as a universal fix for EPR hazards in these situations. Additional measures for controlling EPR hazards may often be required. (A Petersen Coil (see section 4.4) can, however, be very effective as a universal fix for EPR hazards in these situations, even in areas of high soil resistivity.)

In urban areas, conventional NERs on 11 kV and 22 kV distribution systems can be used to control EPR on structures and distribution centres that are bonded to significant MEN systems.

The use of NERs for the control of EPR hazards should be investigated on a case-by-case basis.

For a faulted site to be guaranteed to be safe of EPR hazards, the source impedance, including the NER, should be approximately 10 times higher than the earth electrode resistance of the faulted site. In general, in rural areas, this is unlikely to happen in practice except for high resistance NERs, (i.e. 600 – 800 Ω). Where standard NERs are used (with current limits of 200 – 500 A), this implies that the resistance of the faulted site should be relatively low (i.e. less than approximately 2 Ω), to ensure that the NER eliminates EPR hazards from the faulted site. Therefore, NERs on 22, 33 or 66 kV feeders may be effective in eliminating EPR hazards at zone substations, which typically have resistances of 2 Ω or less.

NERs have been successfully used in urban areas to control transferred voltages to telecommunications circuits. Telecommunications equipment is typically able to withstand voltages well in excess of what would normally be hazardous to human beings.

Operation and system changes, such as the replacement of surge arresters, may be required.

Detailed information is available in NZCCPTS ‘Application guide for neutral earthing resistors or reactors’.

7


. RESOnAnT EARTHInG

A Petersen Coil is an inductance that is connected between the neutral point of the system and earth. The inductance of the coil is adjusted so that, on the occurrence of a single phase to earth fault, the capacitive current in the unfaulted phases is compensated by the inductive current passed by the Petersen Coil.

Upon the occurrence of an earth fault, the system capacitance discharges into the fault and the faulted phase voltage collapses to a very low value, leaving a very small residual current flowing in the fault. This current is so small that any arc between the faulted phase and earth will not be maintained and the fault will extinguish. Transient faults do not result in supply interruptions and in some jurisdictions permanent earth faults can be left on the system without the supply being interrupted while the fault is located and repaired.

Modern systems provide automatic tuning of the inductance to accommodate changes in network topology.

To increase safety and to eliminate restriking faults on underground cables, some systems also provide electronic compensation to reduce the remaining residual current and voltage on the faulted phase to zero.

Resonant earthing can reduce MEN EPR to a safe level even in systems with high MEN resistance. In many European countries, resonant earthing is the normal method of obtaining acceptable EPR and hence acceptable step and touch voltages in electrical networks, and acceptable control of EPR impressed on third party systems (telecommunications, railway, pipelines, etc.) and personnel.

. OVERHEAD EARTH WIRES

Overhead earth wires (OHEWs) are typically used on transmission lines at or above 110 kV, usually at least over the first kilometre of line out from the HV a.c. station. OHEWs are also sometimes used on distribution lines (11 kV and above) for the first kilometre out from the substation but this is not common in New Zealand.

While the primary purpose of the OHEW is to provide lightning shielding for the substation, bonding of the OHEWs to the earth grid can significantly reduce earth fault current through the station earth grid for faults at the station or at conductive poles or towers bonded to the OHEW.

Inductive coupling between the OHEW and the faulted phase conductor can significantly reduce the earth return current during fault conditions at conductive poles or towers bonded to the OHEW. This, in turn, reduces the EPR levels at both the substation and at the conductive pole or tower. However, the incidence of (transferred) EPR events at the conductive poles or towers will become more frequent.

For a bus earth fault at a substation, the OHEWs can divert significant current away from the substation earth grid. The net effect of the OHEWs is to reduce the impedance of the overall earthing system (earth grid and tower/pole footing electrodes in parallel) thereby reducing the EGVR.

While bonding the OHEWs to the station earth grid will have the effect of reducing the hazards at the station, hazards at the nearby towers/poles will increase. The frequency of voltage rises at the nearby towers/poles will increase since each station EGVR will be transferred to the nearby towers/


poles. On the other hand, bonding the OHEWs to the station earth grid will have the opposite effect of reducing the voltage rise at the tower/pole bases for earth faults on the nearby towers/poles.

Consideration must be given to the OHEW size (fault rating), particularly for the first few spans from the substation. For the first two kilometres from the substation, the OHEWs should be rated for the full station prospective earth fault current associated with the line voltages. However, it is not necessary to rate the OHEWs for a 3 s fault duration. Shorter fault durations may be considered depending on the protection schemes used.

. CABLE SCREEnS

Bonded cable screens provide galvanic and inductive return paths for fault current for both cable faults and destination substation faults.

For an earth fault at a remote destination substation connected to a cable bonded at one end only, all the fault current will return to the source substation via the associated earthing systems. The result is typically a high EPR at both the source and destination substations, and possibly high induced-voltages into parallel third party conductors (e.g. telecommunications conductors).

Bonding of cable screens to the earthing systems at both ends is advantageous in most situations. However, the transfer of EPR hazards from a HV a.c. station to a remote site via the cable screens should be considered as part of the design. For extensive cabled networks where screens are bonded at both ends, the transfer of EPR hazards is unlikely to be an issue. In some cases, where a low proportion of the distribution network is cabled, investigation may be necessary to determine the extent of any EPR transfer issues via zone substations and LV neutrals.

The bonding of single core cables at both ends may affect the rating of the cables, depending on the cable configuration (due to induced currents in the screens and sheaths). Care should be taken to ensure the rating of the cable is adequate for the application. Alternatively, cross bonding should be applied.

The rating of the cable screen should be adequate for the expected fault current and for the current induced in the screen during normal operation.

Detailed information is contained in NZCCPTS ‘Application guide for cable sheath bonding’ (and in its associated companion document ‘Fundamentals of calculation of EPR in the underground power distribution cable network’).

.7 SURFACE InSULATInG LAYER

To limit the current flowing through a person contacting a temporary livened earthed structure, a thin layer of high resistivity material is often used on top of the ground surface. This thin layer of surface material helps in limiting the body current by adding resistance to touch and step voltage circuits.

Crushed rock is used mainly, but not exclusively, in HV a.c. stations for the following reasons:

(a) To increase tolerable levels of touch and step voltages during a power system earth fault;

(b) To provide a weed-free, self-draining surface.

9


Asphalt may also be used in HV a.c. stations but is likely to be more expensive than crushed rock. Asphalt has the advantage of providing easy vehicle access. Vehicle access over crushed rock may sometime be problematic especially if the base was not prepared properly and if the crushed rock specification is not adequate.

Asphalt and crushed rock can also be used to control touch and step voltages around towers and poles located in public access areas.

Limited data is available on the flashover withstand of asphalt, which may be as low as 4 kV for a 50 mm thick sample. Therefore, where asphalt is used for mitigation, touch voltage should not exceed 4 kV and step voltage should not exceed 8 kV. For applications where these limits are exceeded, the withstand voltage should be considered based on the type of asphalt that is being considered.

Chip seal and concrete must not be used to control touch and step voltages due to their low resistivity. However, reinforced concrete may be used to create equipotential zones for the control of hazardous touch and step voltages.

When crushed rock is used to control touch and step voltage hazards, the following criteria must be used in the design:

(c) The resistivity of crushed rock is 5,000 Ω-m provided the crushed rock complies with the specification detailed below;

(d) The thickness of the crushed rock layer is 125 mm ± 25 mm.

NOTE:

1: The insulating property of crushed rock can be easily compromised by pollution (e.g. with soil). Therefore, regular inspection and maintenance of a crushed rock layer is required to ensure that the layer stays clean and maintains its minimum required thickness.

2: The insulating property of asphalt can be compromised by cracks and excessive water penetration. The integrity of the asphalt layer used for surface treatment must be maintained.

All crushed rock material must be screened and crushed from river-run gravel or quarried aggregate. The source material must consist of hard, sound material of uniform quality, free from soft or friable stone, wood, clay, or other deleterious material.

Crushed rock comprising a combination of large and small particle sizes ensures sufficient interlocking and thus is suitable for both driving and walking on. When tested in accordance with NZS 4407.1, Test 3.8.2, the particle size distribution of the crushed rock must comply with the limits given in Table 4:

Table 4: Crushed Rock Specification

Crushed rock particle size distribution limits

(% passing by dry mass)

Aperture (mm)

7. . 19 1. 9. .7

Lower Limit 100 65 20 0 0 0

Upper Limit 100 85 50 25 10 5


0

When tested in accordance with NZS 4407.1, Test .14, each of the five crushed aggregate fractions between the 37.5 mm and 6.7 mm test sieves must contain not less than 90% by mass of stones with at least two significant broken faces. Smooth river pebbles are unsuitable for use in switchyards.

The crushed rock must be laid on a level well compacted basecourse surface, (i.e. 100 mm AP40).

When asphalt is used in mitigating step and touch voltage hazards, a resistivity of 15,000 Ω-m must be used. The asphaltic concrete must be 50 mm minimum thickness to TNZ M/10 specification1 and laid in accordance with TNZ P/9[2]. A tack coat is required.

Close attention is required to the preparation of the ground prior to the application of crushed rock or asphalt. The asphaltic concrete should be laid on a level well compacted basecourse surface constructed in accordance with TNZ B/2 specification over a subgrade with a minimum California Bearing Ratio (CBR) of 5%. The surface of the prepared basecourse should be sprayed with weedkiller prior to the laying of asphaltic concrete.

Crushed rock or asphalt should not be used to fill in any hollows in the subgrade.

. SEPARATIOn OF HV AnD LV EARTHInG

When an earth fault takes place at the HV side of a distribution centre, the EGVR on the HV earth electrode is transferred to the MEN system via the neutral conductor. For the earthing of the HV and LV systems, two acceptable methods are to either bond the two earthing systems together or to segregate them. Segregation is achieved by introducing a physical separation between the HV and LV earthing systems.

Where there is a significant density of earth electrode on the LV system such as in urban areas, the preferred method of earthing is to bond the HV and LV earthing systems. Large earth electrode densities are typically achieved in large urban distribution networks that are interconnected via cable screens bonded at both ends and via interconnected neutral conductors. The critical factor is the overall EGVR of the earthing system and, if it is low, then a bonded HV and LV earthing system is preferred.

For systems with smaller densities of earth electrodes such as rural and smaller urban installations where it is usually difficult to achieve low EGVR, it may be advantageous to control touch and step voltage hazards on the MEN system and EPR hazard to telecommunications network users, personnel or plant, by segregating the HV and LV earthing systems. Care is required to ensure that the neutral of the segregated LV system is not bonded to the LV MEN of another transformer that does not also have segregated HV and LV earthing systems.

Segregation of HV and LV earthing systems ensures that only a small portion of the EGVR on the HV earthing system is transferred onto the LV earthing system. Touch and step voltages, and voltages that are transferred to third party equipment such as telecommunications equipment are controlled in this way. Mitigation of EPR hazards on structures connected to the HV earthing system may be required.

Segregated HV and LV earthing systems may sometimes be difficult to maintain for the following reasons:

(a) The integrity of the physical separation may be difficult to maintain into the future. Other

1


earthed structures may be installed at later stages within the physical separation distance. If the minimum separation required is small, this is less likely to be a problem;

(b) The system is not currently commonly used in New Zealand and therefore may be compromised in the future by a contractor who is unfamiliar with the system. However, if this practice becomes more common, this should become less of a problem.

The minimum separation distance required between the distribution centre HV and LV earthing systems is dependent on:

(c) The size of the HV earthing system;

(d) The maximum EPR on the HV earthing system;

(e) The distances to, and relative sizes of, the different earths bonded to the LV MEN system.

Typical minimum separation distances required between any portion of the HV and LV earthing systems are given in Table 9 of section 6.7.

It must be recognised that separate HV and LV earthing systems may not be effective in controlling hazardous step and touch voltages in the event of a HV line to LV line contact at the distribution transformer, or on a conjoint HV/LV line section. The following options may be considered for protecting against HV to LV contacts:

(f) Ensure the configuration of LV lines at the distribution transformer pole are such that a HV line to LV line contact is unlikely;

(g) Replace the LV lines over conjoint HV/LV spans with:

(i) LV buried cable

(ii) LV lines on a separate poles, or

(iii) LV aerial bundled conductor cable that is insulated to withstand the full HV conductor voltage.

Before considering the separation of HV and LV earth electrodes at distribution transformers, make sure that the transformer is able to withstand the maximum EPR on the HV earthing system, without breaking down to the LV side of the transformer, (e.g. via HV/LV winding breakdown, transformer earthed core to LV winding breakdown, or transformer tank to LV neutral breakdown). The withstand voltage on most 11 kV transformers should be adequate but on 22 kV transformers the possibility exists that the EGVR on the HV earth electrode may cause a flashover between the case and the LV winding or across the LV bushing.

NOTE: Transformers that are connected to segregated earth electrodes will be more at risk of failures from lightning surges. If required, additional surge protection should be provided for these transformers.

When the LV earthing system is segregated from the HV earthing system at a distribution centre, the total earth impedance of the LV earthing system plus associated MEN earths, must be sufficiently low to ensure the HV feeder protection to the distribution centre will trip. A safety factor of two should be used in calculating this maximum earth impedance value. This means that the calculated resistance should be divided by the safety factor of 2 and ensures that the HV protection will operate in the event of a HV line to LV line contact, or a HV/LV winding insulation breakdown in the distribution transformer.


.9 TT SYSTEM OF SUPPLY

The TT system of supply (IEC 60364-4-44) is an alternate method of connecting installations to the network that could be considered for situations where there are only a few earth connections, such as in a rural area where a single distribution transformer feeds a single farm house, or in urban areas where the ground resistivity is high and/or the number of earthing connections to the neutral are limited. In these cases, when applying the MEN system, it is normally impractical to reduce the voltage rise on the earthing system to a safe value when the neutral connection is not intact. Furthermore, the current generated by a LV earth fault is unlikely to be sufficient to operate the service fuse.

Under the TT system, exposed metalwork within an installation is connected to the main earth but not to the neutral. In practice, this is achieved by removing the neutral-earth link in the main switchboard.

To provide effective earth fault protection, it is imperative to use a RCD. The main switch is a convenient point at which to install this device. As the RCD is not required for personal protection, and to minimise the risk of spurious trippings from normal leakage within the installation, a RCD sensitivity of 150 mA is suggested.

It should be noted that the TT system is currently not permitted under the Electricity Regulations and it will be necessary to apply to the Secretary for a dispensation. Nevertheless, application of such a system will ensure that the installation is safe in the event of a failed neutral connection, something that may not be possible when employing the MEN system in the situations noted above.

Figure 12 shows the typical configuration of a practical TT system that could be employed.

Figure 12: Configuration of a Practical TT System

.10 InTERFEREnCE WITH SERVICES

As described in section 2.7, EPRs caused by HV system earth faults can couple into third party equipment such as telecommunications equipment or pipelines or railway lines where these are located in the vicinity of the HV earthing system. Since telecommunications circuits and pipelines are typically referenced to remote earth, voltages coupled onto the third party equipment by the power system earth fault may be large depending on the value of the EPR voltage in the immediate vicinity of the third party equipment.


Voltages on telecommunications equipment resulting from these EPR events can cause hazards for telecommunications employees and or failure of equipment. EPR voltages in the ground surrounding buried pipelines can cause failure of the pipeline insulating layer thereby compromising the cathodic protection system that may be installed, and increasing the risk of corrosion.

To mitigate EPR hazards on third party equipment caused by earth faults on HV earthing systems, adequate separation is usually effective. Where it is possible, alternative routes should be investigated for the power system or the third party equipment.

For telecommunications equipment, it may also be possible to mitigate the EPR hazard by isolating the telecommunication equipment. Isolation of telecommunications equipment is usually cost- effective where few customers are affected. However, where many customers are affected, the cost may be prohibitive.

For a HV a.c. station, isolation of water pipes, the telephone circuits and pilot cables are typically provided to eliminate the transfer of EPR hazards.

.11 OTHER MITIGATIOn MEASURES

Other mitigation measures that may be considered include:

(a) The installation of insulating barriers or fences;

(b) Isolation of specific metallic conductors;

(c) Reduction of fault clearing times.

Access to structures where hazardous touch voltages may be present can be restricted by the installation of safety barriers or fences. These barriers or fences would typically be non conductive such as wood, plastic or rubber. For example, a tower could be surrounded by a wooden fence to restrict access to the tower base, or a sheet of rubber could be wrapped around the base of a steel or concrete pole. The installation of isolation barriers usually requires ongoing maintenance.

Isolation of specific metallic conductors may be considered in some cases. However, if a metallic conductor could become alive, then isolation is not permitted.

To ensure that touch voltages cannot appear on a water tap, isolation of the tap can be achieved by the installation of a plastic section of pipe.

EPR hazards can be mitigated by a reduction in the fault clearing time. This may be easy to implement in certain situations and may only be advantageous for cases where the hazardous voltages do not exceed tolerable levels significantly. In some situations this may require significant protection review and upgrade, and may prove impracticable. The need for adequate protection grading may also limit the effectiveness of this measure.

.1 REFEREnCES

1 TNZ M/10 ‘Specification for asphaltic concrete’, Transit New Zealand, 2005. See also Notes to the specification of asphaltic concrete.

2 TNZ P/9 ‘Specification for construction of asphaltic concrete’, Transit New Zealand 1975.

TNZ B/2 ‘Specification for construction of unbound granular pavement layers’ Transit New Zealand, 2005.


SECTIOn – HV A.C. STATIOnS

.1 InTRODUCTIOn

The most recognised publication on which the design of HV a.c. stations earth grids have been based is IEEE Standard 80 and HV earth grids that meet the requirements of this publication are deemed to meet the requirements of this guide.

An example of a HV a.c. substation earthing arrangement is shown in Figure 34.

. DESIGn REQUIREMEnTS FOR HV a.c. STATIOn EARTHInG SYSTEMS

An earthing system for a HV a.c. station should be designed and installed to effectively handle the expected maximum earth fault current and to limit earth potential rise (EPR) and gradient voltages so that there is no significant risk of injury or death to any person over the planned lifetime of the installation.

To achieve this, the following requirements must be met.



(a) Proper functioning of electrical protective devices. This entails reliable detection of HV earth faults and either rapidly clearing the fault or minimising the resulting fault current;

(b) Manage the risks associated with step and touch voltages in accordance with Electricity Regulations, applicable standards and guidelines;

(c) Controlling EPR transferred onto third party services, plant and staff (i.e. telecommunications, railways, pipelines, etc.) in accordance with regulations, applicable standards and guidelines.



(a) Earth fault currents and earth-leakage currents can be carried without danger and without exceeding design limits for thermal, thermo-mechanical and electro-mechanical stresses;


. DESIGn ASPECTS

The risk associated with EPR hazards on earthing systems of HV a.c. stations may be managed either by the probabilistic method or the deterministic method. However, earth fault frequencies typically associated with HV a.c. stations and the presence of workers on site, sometimes for long periods, dictate that the risks associated with the stations are comparatively high. For these reasons, in practice the deterministic method is typically used for the design of the station earth


grids. The probabilistic method may be used for areas outside the security fence but this should be carried out with caution because of the typically high earth fault frequencies for some types of fault.

An earthing system for a HV a.c. station consists typically of a buried horizontal grid of copper conductors with or without additional driven rods. Usually the grid extends over the whole area occupied by the substation.

The horizontal conductors are positioned to enable all metalwork in the substation (steel structures, equipment stands, fences, etc.) to be bonded to the earthing system so that a direct low resistance path to earth is provided for earth fault currents.

When these high earth fault currents flow into the earth, earth potential gradients that may be dangerous to people are established within and around the substation. These earth potential gradients can be controlled by the use of additional earthing and other techniques.

For a HV a.c. station earthing system, the design of the grid to provide low resistance connections to earth for metalwork and to control step and touch voltages in most cases ensures that the grid impedance is more than adequate to meet earth fault protection requirements.

If required, the earth grid may be extended beyond the substation structure fence and/or interconnected with other earthing systems to ensure a sufficiently low overall resistance to remote earth.

NOTE: 1: This may require the approval of other parties such as the landowner.

2: For new sites, this may form part of the site selection criteria.

In very large substations the impedance of the transformers on the low voltage side is generally a fraction of an ohm. For instance a 90 MVA transformer may have a zero sequence impedance as low as 0.2 ohm at 22 kV. This makes it evident that any appreciable resistance in the station earthing system will have a major effect on the magnitude of the earth fault current.

The following typical steps should be taken to design a substation earth grid:

(a) One of the first tasks to be carried out is a site visit for the measurement of soil resistivity. The soil resistivity data is then processed to determine a soil resistivity model for the site;

(b) The applicable earth fault currents are calculated;

(c) The applicable earth fault current durations are determined;

(d) Using the substation layout drawing, a basic earth grid is provided to form the substation earth electrode. The basic earth grid typically consists of the following:

(i) An earthing conductor surrounding the area covered by the substation equipment and structures. This earthing conductor, which encloses as much area as practical, helps to avoid high current densities

(ii) A grid is then formed by using parallel conductors within the loop. The parallel conductors are typically laid along the structures or rows of equipment to provide for short equipment connections

(iii) At all cross connections, the earth grid conductors are bonded together;


(e) The primary roles of the earth grid are to ensure that the earth grid impedance is sufficiently low to enable effective operation of the protection system and that no dangerous surface potential gradients exist. Therefore, using the soil resistivity model and the worst earth fault current, duration, and touch, step and mesh voltages are reviewed. Transferred voltages are also reviewed;

(f) Depending on the outcome of the touch and step voltage review, additional grid conductors may be required. Extending the earth grid beyond the substation fence may be an option that should be considered and decisions need to be made concerning the bonding of the fence to the earth grid;

(g) Driven rods may be required to reduce the impedance of the earth grid. To start with, driven rods should be located at the corners of the grid. If required, additional ground rods can be located along the perimeter of the grid.

Horizontal grid conductors are buried at a shallow depth but not less than 500 mm below the surface to control step and touch voltages over the grid area.

However, the resistivity of the surface layer (top 1,000 to 2,000 mm) can in some locations fluctuate widely because of seasonal drying or freezing, resulting in significant changes in grid impedance. In such locations driven rods sufficiently long to penetrate into lower layers of soil with more constant resistivity are provided to lessen the effect of seasonal changes on grid impedance.

The above concepts are developed in more detail in the following sections and a case study is given in Appendix B2.

. IMPORTAnT DESIGn PARAMETERS

The following design parameters form the basis for the design of an earthing system for HV a.c. stations:

(a) Soil resistivity;

(b) Maximum earth fault current;

(c) Maximum earth fault duration.

. SOIL RESISTIVITY

Soil resistivity is a critical parameter for the design of an earthing system and for determining the safety limits for the evaluation of touch and step voltage hazards.

The resistivity of the soil surrounding an earth electrode has a significant impact on its resistance. Soil resistivity also has a bearing on the voltage gradients that are to be expected at the soil surface during earth fault conditions.

The general moisture content of the soil should be considered and adjustment to the soil resistivity data made if required.

The Wenner method is the preferred technique for measuring soil resistivity.

Soil resistivity tests should be carried out at test-probe spacings that are proportional to the expected dimensions of the earthing system. Spacings should be as large as possible.

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The test-probe spacings for small to medium size substations (≤ 0 m x 0 m) should vary between 0.5 m and 40 m. For each test traverse, measurement of soil resistivity should be carried out for a minimum of 12 to 15 different spacings of the test probes. Typical spacings may be: 0.5, 1, 1.5, 2, 2.5, 3, 4, 6, 8, 10, 15, 20, 25, 30 and 40 m. For larger substations, probe spacings up to 60 m or more should be used.

Soil resistivity tests should be carried out away from metallic objects such as other earth electrodes, buried water pipes, fences, etc.

The measured data should be evaluated to determine a soil resistivity model for the site. Determination of the correct soil resistivity model for the site is an important aspect of the design. Earthing design software may be used to assist in determining a soil resistivity model on which to base the earthing system design.

. MAxIMUM EARTH FAULT CURREnT

Prior to carrying out any earthing system design, it is necessary to determine realistic earth fault currents for the system.

Two distinct earth fault current values are used in the design of an earth grid:

(a) The maximum fault current that will flow in the earthing system is used for rating the earthing conductors;

(b) The earth grid return current is used to evaluate EPR issues including touch and step voltage hazards.

When calculating earth fault currents, the fault circuit impedances should be taken into account since these impedances (the overhead line and cables plus the earth impedances) may significantly affect (reduce) the magnitude of the earth fault current.

The calculation of the earth fault currents should include the d.c. offset.

Care must be taken in calculating the earth grid return current since only a proportion of the fault current may return via the earthing system. In some systems, earth fault current is diverted from the earthing system via cable screens or other bonded conductors such as pipelines.

Effects of network expansion on the fault current to be used for the design should be considered.

Some EPR hazard mitigation measures, such as lowering the grid resistance, may result in an increased earth grid return current. This should be taken into account during the earthing design process.

.7 MAxIMUM EARTH FAULT DURATIOn

Two earth fault duration times are used in the design of an earth grid.

For the sizing of the earthing conductors, an earth fault with duration should be selected as detailed in section 2.11.

For the evaluation of touch and step voltage hazards, the primary protection operating times should be used as stated in section 2.6.3.


. TOUCH AnD STEP VOLTAGE HAzARDS

The earthing system must be designed to control touch, step, and mesh voltages as far as practicable.

Earth fault durations need to be considered to determine the current that results in the worst case when assessing hazardous touch and step voltages. To determine the worst case situation, earth fault currents at different voltage levels and different fault durations cannot be directly compared. All earth fault currents and associated durations should be converted to their one second equivalents for comparison.

Tolerable step and touch limits should be calculated based on IEEE Standard 80 or IEC 60479-1 fibrillation current limits as in section and Appendix A.

When designing according to IEEE Standard 80, the calculated step and touch voltages are limited to prevent heart fibrillation due to accidental contact by a person weighing 70 kg within the site (restricted access areas) and 50 kg in public access areas.

Glove impedance should not be included in the calculations of touch and step voltage limits. The designer should consider whether it is appropriate to include shoe impedance. In some situations it may be prudent to exclude shoe impedance when considering hazards outside the security fence.

A record should be kept of all information on the determination and control of shock currents.

.9 MITIGATIOn OF EPR HAzARDS

Typical mitigation measures that may be used to control touch and step voltage hazards in an HV a.c. station may include the following:

(a) Reducing the resistance of the earth grid;

(b) Reducing the fault current flowing into the earth grid;

(c) Reducing the fault duration;

(d) Installing gradient control conductors;

(e) Bonding OHEWs to the earth grid;

(f) Bonding feeder cable sheath to earth electrodes at both cable ends;

(g) Using surface treatment such as crushed rock or asphalt to increase tolerable touch and step voltages.

Some of these measures are described in more detail as follows.

The earth grid voltage rise (EGVR) can be reduced by reducing the resistance of the earth grid. However, where the source impedance is relatively low (high fault levels), reducing the earth grid impedance may not reduce the EGVR by much (since the fault current may increase while the earth grid impedance decreases). Therefore, the costs involved in achieving a lower earth grid resistance should be evaluated against the benefit gained.

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The use of NERs may be considered for the reduction of the EGVR of the earth grid and inductive interference with telecommunication circuits.

NOTE: The use of NERs is typically limited to the lower voltages (11 kV to 33 kV).

The use of NERs may require review of the protection system and can have significant economic implications. Surge arrester ratings need checking.

Fault current flowing into the earth grid may also be reduced by diverting fault currents through cable sheaths to other earth electrodes. The effect on the cables of diverting fault current into cable sheaths (i.e. heating) should be considered.

Gradient control conductors buried 1 m outside and 1 m inside a security fence are effective in controlling hazardous touch voltages on fences.

Bonding of the OHEWs to the earth grid may result in a substantial portion of the earth fault current being diverted away from the earth grid. This may result in a significant reduction of the station EGVR. However, connecting the OHEWs to the earth grid will usually have the effect of increasing the hazard at the tower/pole bases. The frequency of voltage rises at the nearby towers/poles will increase since each station EGVR will be transferred to the nearby towers/poles. On the other hand, bonding the OHEWs to the station earth grid will have the beneficial effect of reducing the voltage rise at the tower/pole bases for earth faults on the nearby towers/poles.

Where crushed rock is used to control touch and step voltage hazards for a zone substation, the following criteria should be used in the design:

(h) The resistivity of crushed rock is 5,000 Ω-m;

(i) The thickness of the crushed rock layer should be 125 mm ± 25 mm.

The crushed rock should comply with the specification given in section 4.7. Smooth uncrushed rock is not suitable.

Asphalt is considered to be a suitable surface material for the control of surface resistivity provided the touch voltage does not exceed approximately 4 kV. For design purposes a resistivity of 15,000 Ω-m and a minimum depth of 50 mm should be used for asphalt. Asphalt must meet the specification detailed in section 4.7.

When planning a new substation design, consideration should be given to allowing for at least a 1 m wide strip of land around the outside of the security fence for burying a gradient control conductor and/or for applying surface treatment. Common practice is to allow a strip sufficiently wide to facilitate inspection and maintenance, and to install an outer boundary fence.

NOTE: In rural areas a stock fence is frequently used to prevent damage by stock to the station security fence and to the surface treatment layer.

.10 TRAnSFERRED VOLTAGES

All conducting pathways including water pipes, telecommunications cables, gas pipelines etc., leaving the earth grid area for remote locations should be isolated, except for power cable sheath/armouring and overhead earthwires (OHEWs), which are discussed further in sections 5.23 and 5.30.


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Steam pipelines (which may require special attention with respect to touch and step voltages) are normally bonded.

Isolation facilities are designed and tested at 25 kV a.c. for 1 minute as a minimum standard. Higher test voltages may be required for locations having a higher voltage rise.

The design of substation earth grids should consider:

(a) The transfer of earth grid potentials to a remote earth;

(b) The transfer of a remote earth potential into a station; and

(c) The breakdown of cable oversheaths because of voltage differences:

(i) Between metallic screens or sheaths earthed at the station and the ground surrounding a cable

(ii) Between metallic screens or sheaths earthed at a remote point and the ground surrounding a cable

(iii) Appearing in the ground surrounding a station in which the cable is buried.

EPR effects on telecommunication and other third party equipment located near a substation must be considered.

Where it is deemed that a new earthing system installation or a modification to an existing earthing system or the network may affect third party assets, third party representatives should be contacted to discuss the appropriate mitigation measures.

Telecommunications circuits into high voltage stations may be protected by the appropriate use of isolation transformers and/or optocouplers, high voltage insulated communications cables, and specially designed cubicles with isolating barriers and isolated work platforms on the telecommunications side of the cubicle.

Barrier isolation should be considered for control and communications cables so that it is physically impossible for a person to touch the incoming and outgoing cable terminals simultaneously. This is typically achieved using an insulating board mounted within a circuit isolation cabinet containing an isolation platform and doors front and rear. The cables leaving the earth grid terminate on one side of the board, with the local cabling on the other side. Isolating facilities are fitted to the off-site cable terminals.

Metalwork bonded to the earth grid and projecting beyond the earth grid, or conductively coupled because of its proximity may introduce a hazard from transferred potential and must be considered during the design and mitigated as required to achieve safety.

For existing substations with metal pipes leaving the substation, the transfer of hazardous voltages off-site should be investigated. If required, transfer of voltage off the site should be prevented by isolating the metal pipes from the grid. This can be achieved by installing insulating sections of suitable plastic pipes or other non-conducting material outside the boundary of the switchyard. The length of insulating sections required depends on the EPR of the grid but should have a minimum length of 10 m. Metal pipes that pass the substation close to the earth grid should also be considered. For new substations, only plastic water pipes should be used to enter the switchyard.

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Adjacent metallic fencing not associated with the substation, should not be bonded to the substation fence. Isolation capable to withstand the full earth fault EPR should be used to isolate adjacent metallic fences from the substation fence. The isolation measure should be such as to prevent a person from bridging the isolation barrier with outstretched arms. Assume a 2 m reach for a person.

Even with adjacent fences isolated from the substation fence, touch voltages may appear on adjacent fences. The designer should consider whether additional isolation sections should be used to reduce the risk associated with the transferred voltages on the adjacent fences.

Transferred voltages on earthing systems associated with local service supply transformers installed outside the switchyard should be considered and the EPR hazards evaluated and mitigated as required.

.11 0 V, 0 V AnD ,00 V EARTH POTEnTIAL RISE COnTOURS

The designer/reviewer must co-ordinate with telecommunications representatives to ensure any interference with telecommunications equipment, cables or lines is minimised so far as is reasonably practicable and complies with the Electricity Regulations.

Induced voltages onto telecommunications systems are limited to:

(a) 430 V for faults of duration greater than 0.5 s (primary protection time);

(b) 650 V for faults of duration less than or equal to 0.5 s (primary protection time).

The design/review should take into consideration the following:

(c) Near substation facilities, telecommunications companies are concerned with:

(i) The voltages on the earth bars and neutrals at any building, public, private or industrial that has telecommunications cables or equipment

(ii) The voltage on the ground where there is a kiosk or junction box with telecommunications equipment

(iii) The voltage on the ground where there are telecommunications cables;

(d) The earth/neutrals of buildings may be affected by voltages that are:

(i) Impressed onto the earth/neutrals by rising to the earth potential

(ii) Transferred onto the earth/neutrals via a MEN system.

The locations of the 430 V, 650 V and 2,500 V EPR contours are determined around the substation site and affected areas outside the site. The fault current used in the calculations is as defined in section 5.6.


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.1 EQUIPMEnT EARTHInG AnD BOnDInG

All fittings and any uninsulated metalwork, other than cable screens or armouring, that are liable to become alive should be connected to the earthing system with a minimum of one conductor capable of carrying the expected maximum fault current for the duration, (i.e. the duration selected for the design) of any fault that may liven the fitting or uninsulated metalwork. Some fittings that are out of reach as defined by the Electricity Regulations may not require bonding to an earthing system. However, the safety of personnel should be considered when deciding which fittings to earth. An example of bonding to the earth grid is shown in Figure 34 in Appendix C. Cable screens and armouring should be treated in accordance with sections 5.22 and 5.23. Transformer neutrals are covered in section 5.21.

All conductive equipment and support structures should be earthed to the grid with a minimum of one earthing conductor except power transformers, which require a minimum of two conductors.

Tanks of power transformers must be bonded to the earth grid via two diametrically separated earthing conductors.

All earthing conductors must be electrically and mechanically sound and rated for their application (see section 2.11). Earthing conductors should be installed in such a way that they are protected from mechanical damage.

Earthing of equipment mounted on electrically conductive structures must be by means of earthing conductors connected directly to the grid or to the support structure. Bonding to the grid using support structures should not be made through bolted flanges. A short conductor jumper may be used to provide bonding across a bolted flange.

Equipment bonding should be made at either the earthing terminal welded to the equipment or holes drilled and tapped to take suitably sized bolts. Tapping is not necessary if accessible nuts can be used.

Surge arresters should be bonded to the earth grid using the shortest possible electrical path. Bonding of the surge arresters to the earth grid should be achieved through steel support structures and earthing conductors. Surge arresters mounted directly on a transformer tank may not require additional earthing conductors to the earth grid.

.1 JOInTS FOR EQUIPMEnT EARTHInG COnDUCTORS

All bolted equipment connections and joints should be electrically and mechanically robust and corrosion resistant. Intermediary bi-metal jointing devices should be used if required, e.g. for connecting copper to aluminium joints. The recommended bolt material to suit conductor and clamp must be used. The bolts, washers and nuts may be stainless steel or other suitable metals. Where stainless steel is used, the bolts and nuts should not be made from the same type of stainless steel, to avoid the nuts fusing onto the bolts. Type 316 is suggested for the bolts and type 304 for the nuts and washers. Alternative methods of preventing fusing between bolts and nuts may be used. The torques applied to the nuts and bolts should not exceed the recommended values from the manufacturer.

Before making or remaking a joint, all jointing surfaces should be smooth and free from burrs. Joints with tinned or cadmium-plated surfaces should be cleaned thoroughly with a stiff non-metallic brush or scouring pad (e.g. nylon).

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When making or remaking a joint, corrosion issues between dissimilar metals should be considered and jointing compounds should be used where appropriate. Flat copper earthing conductors can also be tinned before bolting to equipment.

When a flat copper earthing conductor is to be run and secured to a galvanised steel structure, the copper strap should be stood off from the galvanised surface using a suitable insulating material.

.1 DISCOnnECTORS AnD EARTH SWITCHES

An example of the earthing arrangement for an earth switch is shown in Figure 35.

Bonding to the handle and to the linkage rod should be carried out using a flexible lead or braid with a minimum dimension of 25 mm2. Sleeves should be provided to ensure that the leads cannot bend sharply at the lugs.

Where an operator earth mat is installed:

(a) The operator earth mat should be bonded to the operating handle using a PVC insulated earthing conductor;

(b) The operator mat should not be directly bonded to the earth grid;

(c) The operator mat should be large enough to allow an operator to remain on the mat during operation of the disconnector and earth switch;

(d) The mat may be embedded into a concrete pad or installed on top of a concrete pad. Alternatively, the reinforcing in a concrete pad can be used as an operator mat.

Linkage (operating) rods and mechanisms are typically connected to an equipotential bonding point near the mechanism box.

The earthing blades of earth switches should be bonded to the earth grid with a separate earthing conductor rated for the full fault current.

The support post/structure for the earth switches and disconnectors should also be bonded to the earth grid.

.1 EQUIPMEnT REInFORCED COnCRETE PADS AnD HOLDInG-DOWn BOLT CAGES

Bonding of concrete pads reinforcing should be considered as part of the design.

Typically, small reinforced concrete pads (covering an area less than 2 m2) are not required to be bonded to the earth grid. Reinforcing of larger pads should be bonded to the earth grid. Bonding should be achieved at one location only except for pads with sides exceeding 5 m in length where a bond should be provided at approximately 5 m intervals along the sides. A re-bar that is tied to many other re-bars should be selected for bonding.

Holding-down bolt cages are not required to be bonded to earth.


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.1 BUILDInGS

All metal components of substation buildings, including cladding, should be bonded to the earth grid.

Reinforced concrete floors should be bonded to the earth grid at regular intervals. The interval depends on the layout of the floor and an interval of approximately 5 m is recommended. Additional bonds may be required if the floor is made up of discontinuous reinforcing sections.

Adequate earthing straps should be provided within buildings containing primary equipment such as switchgear for earthing of the equipment. At least two earthing connections should be provided between these earthing straps and the earth grid.

Metallic cable duct edging should be bonded to earth.

.17 FEnCES

Switchyard security fences should be bonded to the earth grid unless it is advantageous not to bond the fence to the earth grid for touch voltage hazard reasons. Careful consideration of all safety aspects should be carried out before making the decision of not bonding the fence to the earth grid.

Bonding of fences should be carried out at intervals not greater than 20 m.

Fences located outside the earth grid and not bonded to the earth grid should be earthed to a separate earth conductor or through the support posts. For the effective control of touch voltages on the fence, the separation distance between the fence and the earth grid outer conductors should be constant around the perimeter of the fence. Any remaining hazardous touch voltages between fences located outside the earth grid and not bonded to the earth grid should be mitigated following the deterministic method or assessed using the probabilistic method.

.1 LIGHTnInG SHIELDInG AnD LIGHTInG

To create an effective pathway for transient overvoltages due to lightning, the conductor connecting the earth grid to an OHEW should be as straight as possible.

The lightning protection system may consist of masts and/or shield wires, and should be designed as a separate system.

It is common practice in switchyards to use the station earthing system as the lightning earth termination system. The lightning earth termination system may be a separate system but should be bonded to the station earth grid. Isolation between the lightning earth termination system and the station earth grid is permitted but is not recommended because in most situations it would not be possible to maintain adequate isolation levels to prevent side flashes.

Light fittings may be installed on lightning masts.

Where appropriate, lighting poles should form part of the lightning shielding system for the substation.

All lighting and lightning poles must be bonded to the earth grid.

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It is not necessary to install a separate earthing conductor to the top of metallic lighting and lightning poles. However, wooden lightning poles require an earthing conductor between the rod at the top of the poles and the earth grid.

Concrete poles may require an earthing conductor if there is not sufficient earthing integral in the pole itself through the re-bar or internal earthing conductors.

Earthing conductors for lightning protection should have a minimum cross sectional area of 35 mm2. Larger earthing conductors may be required if the conductors are required to also carry significant earth fault currents.

Lightning protection and quantitative analysis on the effects of lightning surges are beyond the scope of this guide.

.19 PORTABLE EARTHInG COnnECTIOnS

Terminals for the application of portable earths should be provided to ensure that all equipment phase terminals can be easily and effectively earthed.

The attachment points for the tail clamps should be designed to allow for easy connection of the clamps.

It is usual practice to provide one tail clamp connection point for each head connection terminal. However, where equipment is compactly designed it may be possible to use one tail clamp connection point. If a single connection point is used it is located so that the connection of earthing leads does not interfere with maintenance activities.

.0 COnTROL CABInET EARTHS / ODJBs

The steelwork/chassis of each control cabinet must be bonded to the earthing system in the control room.

An earth bar or stud should be provided in the cabinet for the earthing of the cabinet to the earthing system.

The cabinet steelwork should be earthed using either an insulated 16 mm2 stranded earth wire or a 20 x 4 mm strap bolted to an 8 mm earthing stud welded to the cabinet interior or bolted directly to the cabinet earthing terminal.

The equipment in each cabinet must be earthed to the control cabinet earth bar or stud.

A minimum earthing conductor size of 2.5 mm2 PVC insulated copper is recommended for the equipment earths.

For equipment that has separate technical/functional earth terminals (i.e. separate from the equipment chassis earth) consideration should be given to connecting the technical earths from each switchboard or group of cabinets to the station earth at one point only. This would require the use of insulated earthing conductors and insulated earth terminals/bars.

Cabinet doors should be bonded to the main cabinet steelwork unless the door is made mostly of non-conductive material such as glass, in which case it may not be necessary to bond the cabinet door.


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.1 EARTHInG OF COnTROL AnD InSTRUMEnTATIOn CABLES WITHIn THE EARTH GRID

Transient phenomena typically occur in substation due to switching operation, lightning, etc. These transient phenomena can cause electromagnetic interference (EMI) of substation equipment by coupling through interconnection control and communications cables. Detailed explanations of electromagnetic compatibility (EMC) issues are beyond the scope of this guide.

Cables consisting of twisted pairs earthed at one end together with an overall screen or armouring that is earthed at both ends provide good protection against EMI. These types of cables should be used for cables running outside in the yard.

Inside control rooms, cables with single screens may be considered. Unshielded cables are typically only used for short cable runs.

Cables with additional shielding such as double screen cables with a braided or taped overall screen (rather than armouring) should be considered for sensitive analogue signals. In an environment where interference is an issue, running these cables through metal tubes or metal cable channels can also be considered.

Where control, protection and communications cables with single screens are used, these should be bonded to earth at one end only.

If the screen of a control, instrumentation or fibre optic cable is not connected to earth at a cable termination within the earth grid then it must be adequately insulated from earth and not exposed to touch.

Additional information is provided in 5.21.1 and 5.21.2.

.1.1 Screened twisted pair cabling for use in SCADA and data acquisition (DA) systems

The steel wire armour of SCADA and DA multicore cables should be earthed at both ends via glands or metal clamps and the gland plates should be bonded to the station earth mat.

The copper screens of cables in series or radial connections should be securely interconnected and bonded to earth at a single point. To provide adequate mechanical strength for the connections, 4 mm² PVC insulated bonding conductors should be used. In the outdoor junction box (ODJB), the screen of the incoming cables should be connected only to those outgoing cables that receive their cores.

.1. Control, protection, instrumentation and 00 V power cables

The steel wire armour multicore cables should be earthed at both ends via glands or metal clamps and the gland plates should be bonded to the station earth mat.

A spare core in a multicore cable should not be used as an earth wire. This is to minimise the possibility of fault current flowing through it during system earth faults and damaging the cable by overheating.

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The screens of the multipair instrumentation cables without additional overall screens are usually earthed at a single point typically located in the control building. If the screen of the same cable were to be earthed at a different part of the station, current that could damage the screen could flow through the screen.

. EARTHInG OF POWER CABLES WITHIn THE EARTH GRID

The screens of three core cables may be bonded to earth at both ends provided the screens are rated for the full expected fault current that may flow.

The screens of single core cables should not be bonded to earth at both ends if:

(a) The screens are not rated for the earth fault current that is expected to flow;

(b) The cable is not adequately rated taking into account circulating currents in the screens.

. FEEDER CABLES

There are advantages and disadvantages in earthing the screens of feeder cables at both ends.

Bonding the screens to earth at both ends will result in earth fault current and EPR transfer to and from the substation.

The effects of the transfer of earth fault current and EPR should be considered as part of the design.

Bonding to earth of feeder cable screens at both ends may be considered if it is advantageous from an EPR transfer point of view.

Where bonding of feeder cable screens at both ends is implemented for single core cables, ensure that the cables are rated to take into account the effects of the circulating currents in the screens.

The screens of feeder cables bonded to earth at both ends should be rated for the full expected earth fault currents.

If it is not advantageous to bond a cable screen at both ends, then two options exist:

(a) The screen can be bonded to the station earth grid and isolated at the remote end; or

(b) The screen can be bonded at the remote end and isolated at the station end.

The isolated end of the cable requires enough isolation to ensure that a flashover does not occur during an earth fault. The typical isolation level is 25 kV a.c for one minute as a minimum.

The isolation device must be tested at the required voltage level for one minute.

When deciding which end of a cable screen should be isolated consideration should be given to the detection of an earth fault in the event of a cable fault.

Old cables that have no effective insulation over their screens cannot usually have their screens isolated at one end.

These old cables often provide very good earthing for the substation and the design of the earth grid should be revisited if one or more of these old cables is replaced with new XLPE type cables.


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If surge arresters are installed on a feeder cable termination to an overhead line, the screens should be bonded to the surge arresters and to earth.

Cross-bonding of long cable screens may be carried out to limit induced screen voltages and screen circulating currents.

. TRAnSFORMER nEUTRAL EARTHInG

The earthing of the power system neutral:

(a) Provides an earth reference for the power system;

(b) Prevents abnormal system over-voltages during intermittent earth faults; and

(c) Permits the selective operation of current operated earth fault protection.

Power system neutral earthing must comprise one of the following connections:

(d) A solid connection, usually to the neutral terminal transformer star connected winding;

(e) An impedance connection employing a resistance, a reactance, a Petersen Coil, an earthing transformer or a combination of earthing transformer and resistance.

For solidly earthed transformers, the neutral busbar and support insulators, if installed, and the neutral conductor should be adequately insulated if required to obtain a single point bond. The neutral earthing conductor must be rated for the full expected earth fault current.

For impedance earthed transformers, the neutral earthing conductor system must be insulated for the maximum anticipated neutral point voltage.

Even if a connection of the neutral to the earth grid is provided through an impedance/resistance, the earthing conductor must be rated for the full expected earth fault current.

. GEnERATOR nEUTRAL EARTHInG

A special situation exists in the case of generator neutral earthing. In these cases it is often desirable to provide a relatively high impedance connection to earth to minimise the fault current that would flow in the event of an earth fault. This reduces the risk of significant damage to the stator windings or the stator laminations, under earth fault conditions.

However, if the earth resistance is too high, this can lead to transient overvoltages occurring during an earth fault because of the effects of winding capacitance.

For high voltage stator windings, a common approach is to apply a two winding Neutral Earthing Transformer (NET) to the generator stator neutral terminal with a low voltage secondary resistor chosen so that the reflected impedance in the primary side of the transformer is equal to the total capacitive reactance of the generators and their associated cabling and unit transformers. This provides sufficient damping to minimise the likelihood of transient overvoltages while at the same time minimising the prospective fault energy within the stator windings.

Furthermore, to reduce the risk of earth fault current contributions from the connected network, a delta winding is often used on the generator side of the unit transformer, to ensure that the only source of zero sequence current is via the high impedance NET.

79


It is important not to create a potential earth loop path by having both the generator and transformer generator-side neutral points (if a star winding is used) simultaneously earthed as this would allow potentially high levels of third harmonic triplen currents to flow in the stator and transformer leading to increased losses and possibly thermal damage if the equipment is not appropriately derated.

. VOLTAGE TRAnSFORMERS AnD CAPACITOR VOLTAGE TRAnSFORMERS

The primary neutral of outdoor voltage transformers (VT) and the neutral end of the capacitor in a capacitor voltage transformer (CVT) should be bonded to the earth grid directly or through its supporting structure. Bonding should not be made through bolted flanges since these cannot be relied on to provide adequate bonding. Earthing jumpers should be used across bolted flanges. Neutral earthing for a group of VTs should be made either individually or first to a common point before being bonded to the earth grid.

.7 VT/CT SECOnDARY CIRCUITS

Voltage and current transformer secondary circuit neutrals must be earthed via an isolating link at one point for a 3-phase set.

It may be necessary to parallel current transformer secondaries, e.g. for bus zone protection. In this situation the secondary circuit must be earthed at one point only.

Delta-connected secondary windings must have one phase earthed.

. 00/0 V SYSTEM

Within the boundaries of a substation, 400/230 V systems should comply with the requirements of AS/NZS 3000 except that:

(a) Separate earth conductors must not be run between the main switchboard and sub-switchboards since these are usually not rated for the expected fault current;

(b) A neutral to earth link should not be inserted in the main switchboard. (A neutral to earth link may be inserted if the designer has ensured that the neutral earth conductor between the transformer and the main switchboard is large enough to handle the expected full earth current);

(c) A neutral to earth link must not be inserted in sub-switchboards.

The earth bar in the main switchboard and sub-switchboards must be bonded to the earth grid.

If a substation has a local service supply from outside the substation, significant earth fault currents may flow over the neutral conductor from the substation to the external MEN system or from the external MEN system to the substation. Also, the transfer of the full station EGVR to an external MEN system should be considered. Significant EGVR may be transferred in this way to residential or commercial properties connected to the external MEN system. The frequency of EPR events at the station may create high risk for consumers connected to the external MEN system.

The neutral conductor from the local service supply outside the substation must be rated to carry the full expected earth fault current.


0

.9 EARTHInG COnDUCTOR AnD JOInT SPECIFICATIOn

Earthing system conductors should be sufficiently large to:

(a) Minimise the probability of mechanical damage;

(b) Minimise the consequence of minor corrosion; and

(c) Provide adequate current carrying capacity.

If necessary, earthing systems should be upgraded where fault levels increase above the original design level.

The required conductor size should be calculated as defined in section 2.11 or using the method from IEEE Standard 80 or an equivalent standard.

All buried earthing conductors should comprise copper conductors except in areas where there may be corrosion. Suitable metals should be selected for these areas.

The rating of the main earth grid conductor should be calculated using a value of 70% of the maximum earth fault current as set out in section 5.6.

All buried earthing conductors should have a minimum size of 50 mm2.

For the connections between HV equipment and the grid, the size of the earthing conductor must be based on the maximum earth fault current (100%). For structures that do not support energised equipment, such as a fence or sheet metal cladding on a building, etc., the conductor should be appropriately sized taking into account a reasonable estimate of current share and the size of the metal being bonded. Conductor size should not be less than 50 mm2.

All equipment earthing conductors providing the connection to the earth grid should have a minimum size of 50 mm2.

The design fault time for all sizing calculations should be as set out in section 5.7.

.0 OHEW

When considering the design of the earth grid and hazard mitigation, the effects from having external OHEWs bonded to the earth grid should be considered. The design should aim for the safest outcome, depending on whether the OHEWs are bonded or not.

OHEWs within the station should be electrically connected to the station earth grid. If isolation is required, this should be provided outside the switchyard.

Earth fault current flow along the OHEWs should be taken into consideration as part of the design when calculating earth grid return currents.

The transfer of EPR hazards from the earth grid to the tower/pole bases should be considered as part of the design as well as the reduction in risk associated with earth faults at towers/poles with having the OHEWs bonded to the station earth grid.

OHEW should be bonded to the terminal structure and to the earth grid, either through the terminal structure or through a separate earthing conductor.

It is recommended to install a single disc insulator between each OHEW and the terminal gantry with the bonding conductor bridging the insulator. This is required to prevent current flow through the termination hardware.

1


.1 POWER STATIOnS, CUSTOMER SUBSTATIOnS AnD InDUSTRIAL InSTALLATIOnS

Where HV a.c. stations are situated immediately adjacent to other stations, customer substations, and large industrial sites, it is common practice to combine the earthing systems. This is beneficial as it effectively creates a larger grid for the dissipation of fault current and the reduction in the resistance to remote earth, thereby lessening the magnitude of the earthing requirement at both installations. In some cases, particularly for small sites, care is required to ensure that no hazardous voltages are transferred off-site onto the customer’s network.

NOTE: Further information on the earthing of power stations and large industrial sites is contained in IEEE Standard 142 ‘Recommended practice for grounding of industrial and commercial power systems’.

Earthing connections between physically separated earth grids (or parts of an earth grid) must comprise at least two conductors connected to separate locations at each earth grid. Each conductor must be rated for the maximum fault current that could flow between the earth grids.

Approval of other parties may be required.

. InSTALLATIOn AnD COMMISSIOnInG

Special precautions are taken when installing earthing components near underground services and as such, details on the location of these services are provided in the design.

Typical underground services include water supply and firefighting facilities, stormwater and sewage drains, pipes, earthing, power, control, and communication cables.

Prior to commissioning, the installed earthing system is tested to:

(a) Ensure the integrity of the system i.e. ensure that the connections are correctly terminated and continuity to the earth grid is complete;

(b) Validate the position of the relevant EPR contours;

(c) Validate the EPR safety of the design and confirm that the actual earth grid resistance to remote earth is in accordance with the calculated design value.

The designer ensures that these tests can be easily and economically applied to the proposed earth system.

. TESTInG AnD MAInTEnAnCE

The integrity of the earthing system should be verified by appropriate periodic inspections and tests. The asset owner should determine appropriate inspections and test intervals based on knowledge of its earth electrodes’ installation and design standards, and on its understanding of environmental conditions and assessment of risk, e.g. soil conditions, copper theft, etc.

The integrity of the earth bonding conductors should be tested at each HV a.c. station at regular intervals. These tests should include all primary and secondary plants and in particular, the HV switchgear and transformer neutral connections. Continuity tests should be carried out to a common reference point (or several common reference points depending on the size of the substation) using a micro-ohmmeter. Expect a resistance of less than 10 mΩ per bond test.

Records of all tests and designs must be maintained by the asset owner.


The recommended test and inspection intervals should not exceed those detailed in Table 5.

Table 5: HV a.c. Station Routine Inspection Plan

Description Description Comments

Visual inspection to ensure integrity of system components above ground

1-2 years

Visual check of primary and secondary plant earth conductors and connections, and ground surface.

Check earth conductors and connections for physical damage, looseness and corrosion. Check integrity of surface, i.e. weeds, consistency/thickness of crushed rock. Particular attention should be given to areas of new installations or excavated areas and to areas where the theft of copper may be an issue.

Test to ensure electrical integrity

5-10 years

Resistance measurement of primary and secondary plant earthing/bonding connections. Substation earth resistance, and touch and step voltage measurement by current injection.

For bond tests, record all plant to a common reference point. Expect < 10 milliohms per bond test.

Review of earthing system

10-16 years

Complete review of zone substation earthing, including check of fault level, test results, risk analysis, and applicable standards. Visual inspection of buried conductors may be required if inspection and test results indicate issues.

This review should be completed earlier if significant network or site works are undertaken.


SECTIOn – DISTRIBUTIOn CEnTRES AnD EQUIPMEnT

.1 InTRODUCTIOn

In the recent past, Electricity Regulations required network companies to provide a MEN system neutral impedance to earth of 10 Ω or less.

The origin of the requirement to achieve 10 Ω is obscure. This requirement does little to ensure electrical safety, and has resulted in distribution centre earth electrodes that are large and expensive without significant safety gained from EPR hazards. The large earth electrodes often required to achieve 10 Ω meant that interference with third party assets was unduly increased.

With the removal of the requirement to achieve 10 Ω, more flexibility is provided for the design of an earth electrode to optimise cost and better manage the risk associated with EPR events, not only for the equipment connected to the earth electrode but also for third party equipment.

. DESIGn REQUIREMEnTS FOR DISTRIBUTIOn CEnTRES AnD EQUIPMEnT EARTHInG SYSTEMS

An earthing system for a distribution centre and equipment should be designed and installed to effectively handle the expected maximum earth fault current and to limit EPR voltages so that there is no significant risk of injury or death to any person over the planned lifetime of the installation.

To achieve this, the following requirements must be met.



(a) Proper functioning of electrical protective devices. This entails reliable detection of HV earth faults and either clearing the fault or minimising the resulting fault current.

(b) Managing the risks associated with step and touch voltages in accordance with Electricity Regulations, applicable standards and guidelines.

(c) Controlling EPR transferred onto third party services, plant and staff, (i.e. telecommunications, railways, pipelines, etc.) in accordance with Electricity Regulations, applicable standards and guidelines.



(a) Earth fault currents and earth-leakage currents can be carried without danger and without exceeding design limits for thermal, thermo-mechanical and electro-mechanical stresses;



. DESIGn ASPECTS

The performance requirements should be considered as part of the design of earthing systems for distribution centres and equipment.

A case study is given in Appendix B1.

..1 Proper functioning of electrical protective devices

The first performance requirement is to ensure the proper functioning of electrical protective devices. For a protection system that detects the earth fault current and disconnects the supply, it is important to ensure that, where possible, enough fault current flows to earth. The magnitude of the earth fault current depends on the resistance of the earthing system associated with the faulted site. Guidelines on how to calculate the required resistances are provided in section 6.4.

.. Manage the risks associated with EPR hazards

The second performance requirement involves managing the risk from EPR hazards associated with earthing systems of distribution centres and equipment. This risk may be managed either by the probabilistic method or the deterministic method.

It is usually not practical and economical to carry out specific earthing design for each site except if the risk determined according to the EEA ‘Guide to risk based earthing system design’ has been determined to be high or at the high end of the intermediate band.

Typically, the probabilistic method is used to determine the risks associated with typical locations around the network. Installations in similar locations are usually grouped into broad categories and the risk calculated for each category. Based on the risk applicable to a category, mitigation measures are determined for all installations in this category.

If it is not desirable to use the probabilistic method, the deterministic method may be used and the installations or group of installations would be classified either as special locations or normal locations.

Further information and guidelines are presented in section 6.5.

.. Control of transferred EPR hazards

EPR on HV earthing systems can cause hazardous voltages to be transferred onto LV MEN systems and metallic parts/equipment bonded to the LV MEN systems. Hazards associated with these transferred voltages need to be controlled.

EPR on earthing systems can also cause hazardous voltages to be transferred into third party equipment such as telecommunications equipment or pipelines or railway lines where these are located in the vicinity of the earthing system. Because telecommunication circuits, railway signalling circuits and pipelines are typically referenced to remote earth, the transferred voltages may be large depending on the value of the EPR voltage.

The issue of transferred voltages to third party equipment needs to be discussed with the relevant third party representative. Typically, when considering mitigation of hazardous voltages transferred onto third party equipment, the deterministic method is applied. In some circumstances, the probabilistic method could be used provided the third party representatives are in agreement.

Additional information is provided in section 6.6.


. RELIABLE DETECTIOn AnD CLEARAnCE OF HV EARTH FAULTS

Electricity Regulation 60(1)(a) requires that works must incorporate an earthing system that ensures the effective operation of protection fittings in the event of earth fault currents.

In an alternating current system that relies on earth fault current detection and disconnection of the supply in the event of an earth fault, the earth fault current at a faulted site must ensure the correct operation of the protective devices that disconnect the supply.

Where fuses are used for protection, the impedance of the earthing system at a faulted site should be such as to ensure operation of the fuses.

Where it is not economical or practical to achieve a low enough impedance of the earthing system at a faulted site to ensure fuses operate in a timely manner, the impedance of the earthing system must ensure operation of the feeder protection.

The earth fault current flowing at a faulted site depends on the impedance of the earth fault current path. Impedance of earth fault current paths for distribution systems may include:

(a) The transformer winding impedance (source impedance);

(b) The impedance of source substation earth grid;

(c) The impedance of any NER or neutral impedance device;

(d) The impedance of the distribution system phase conductor;

(e) The impedance of the return earth path between the location of the fault and the distribution centre earth electrode; and

(f) The impedance of the earthing system at the faulted site including the MEN system impedance. Where segregated HV and LV earthing is used, the impedance of the HV earthing system at the faulted site must not include the LV MEN system.

A minimum factor of safety of two (2) should be used when calculating the required resistance at the distribution centre or the distribution equipment for the required protective device operating values. This means that the calculated resistance should be divided by the safety factor of two. This allows a safety margin for events like seasonal variation in soil resistivity, physical damage to the earthing system, or possible corrosion to part of the earthing system.

..1 Fuse operation

Fuses are installed on distribution centres and equipment and, where possible, some network companies prefer to have an earth fault on an item of equipment cleared by the fuses rather than by the feeder protection. This is to ensure continuity of supply for consumers not directly affected by the fault.

The following example shows how the resistance of the earth electrode at the faulted site is calculated to ensure that fuses clear the fault before the feeder protection operates.


Example:

A 100 kVA, 11 kV transformer is protected by a set of T link fuses. Typically, the fuses may be rated at 10 A for this size of transformer. The protection on this feeder at the zone substation is set to operate at 20 A and in 1 s. The following criteria apply to this example:

(a) The transformer is located 10 km from the zone substation;

(b) The source transformer is a 10 MVA 8% with a solidly earthed neutral and has an impedance XS of approximately j1 Ω;

(c) The conductor is Gopher with a series resistance of 1 Ω/km;

(d) The conductor impedance for earth fault calculations is approximately 1 + j0.4 Ω per km with a total impedance ZL = (RL + XL) of 10 + j4 Ω for 10 km of line;

(e) The zone substation earth grid has a resistance RZone of 1 Ω.

Typical total clearing time-current characteristics curve show that the 10 A fuses require the following currents IFuse to operate in the time indicated:

(f) 180 A, 0.2 s;

(g) 92 A, 0.75 s.

Ignoring the phase angle between the voltage and current, the total impedance ZT of the earth fault current path is then:

ZT = |XS + RZone + ZL + RSite + RFault| = Vph/IFuse

(R (RZone + RL + RSite + RFault)2 + (XS +XL)2]

For the purposes of this calculation, it has been assumed that the impedance of the fault RFault is a maximum of 1 Ω.

To ensure that a fuse clears an earth fault in 0.2 s, the maximum allowed resistance for the earth electrode at the faulted site is then approximately:

RSite (Vph/IFuse)2 – (XS +XL)2] – (RZone + RL + RFault)

(6,50V / 180A)2 – (1j + 4j)2] – (1 + 10 +1) Ω

= 23 Ω

The above calculation does not allow for a safety factor of two as specified in section 6.4. Taking into consideration the safety factor, the maximum allowed resistance for the earth electrode at the faulted site is then approximately:

RSite = 10 Ω (0.2 s clearing time)

This may not be easy to achieve in practice and a longer fault clearing time may be considered. Repeating the calculations for a fault clearing time of 0.75 s gives the following maximum allowed resistance for the earth electrode at the faulted site:

RSite = 28 Ω (0.75 s clearing time)

7


For a transformer connected to a MEN system, the resistances calculated above include the resistance of the MEN system. If the MEN system is reasonably large, and the soil resistivity is reasonably low, these resistances may be achievable with limited expense and effort.

Discrimination between fuses and main protection may be difficult to achieve in practice. For instance, in many rural networks one or more consecutive reclosers could be present on a distribution line and the earth fault protection for each of these devices needs to be graded both in terms of earth fault current and operating time. Often the final recloser could have an earth fault setting as low as 5 A with an operating time of 0.4 seconds while distribution transformers further down the line could be protected with 20 A fuses, depending on the transformer size. In this situation, it would be impractical to provide discrimination through reducing the distribution transformer earth electrode resistance because of the extremely low, and often unachievable, values of resistance that would be required.

Further negative impacts that can result from installing an extensive ground electrode to try and achieve a very low resistance include substantially increased costs and much larger equipotential contours that can increase the risk of damage to nearby telecommunications equipment.

.. Feeder protection operation

The example in section 6.4.1 illustrates that, for many situations, relatively low resistances are required at the faulted equipment site to ensure that fuses clear an earth fault before the main feeder protection operates. These low resistances may be difficult and expensive to achieve in practice even if the resistance of a connected MEN system was included.

In many situations, it will not be possible to rely on the fuses and the main feeder protection will have to be relied on to clear the earth fault.

The following example shows how the resistance of the earth electrode at the faulted site is calculated to ensure that the fault is cleared by the feeder protection.

Example:

In this example, an 11 kV distribution system is considered:

Typical New Zealand HV earth fault protection settings are:

Rural 6 A

Urban 40 A

The maximum earth fault total path impedance for 11 kV systems becomes:earth fault total path impedance for 11 kV systems becomes:

Rural 6,350/6 = 1,058 Ω

Urban 6,350/40 = 159 Ω

It would be extremely rare for the sum of the zone substation earth grid impedance, zone substation transformer source impedance and the 11 kV line (cable) impedance (for the earth fault current path), to exceed:

Rural 60 Ω

Urban 10 Ω


For the HV earthing system of the distribution centre or equipment (including any bonded LV MEN system) and the fault arc, this leaves a maximum impedance of:

Rural < 998 Ω

Urban < 149 Ω

Applying the safety factor of two as specified in section 6.4, the maximum resistance allowed for the earthing system of the distribution centre or equipment is:

Rural < 500 Ω

Urban < 75 Ω

Additional safety factors may be applied if network companies consider that these are required.

The above maximum distribution transformer HV earthing system earth impedance limits apply to the earth impedance of the distribution transformer HV earthing system including any bonded LV MEN systems and other HV earths.

Similar calculations can be carried out for section 6.6 and 22 kV systems.

. EPR RISk MAnAGEMEnT

Managing the risk associated with EPR hazards on and around distribution centres and equipment earthing systems involves the use of the probabilistic method or the deterministic method.

The probabilistic method is typically used to identify risk associated with categories of structures that are grouped according to their broad locations and the expected exposure of people to hazards at these broad locations. A risk assessment of a complete network may be the starting point in identifying which categories of installations may or may not require mitigation. For example, small installations in rural areas where exposure to EPR hazards would be minimal may not require any mitigation of EPR hazards if the risk associated with these installations is identified as low.

Once structures or group of structures that require mitigation have been identified, the probabilistic method may be applied until the risk is deemed to be acceptable. Alternatively, if desired, the deterministic method may be applied to mitigate the hazards to ensure that the risk is acceptable.

For the purposes of evaluating the risk associated with earth faults on earthed HV structures and when considering mitigation measures for these structures, an understanding of the magnitude and size of the hazard areas is required. This may be achieved through measurements of step and touch voltage hazards on or through modelling of the affected structures using sophisticated software.

In this section, typical data is provided on the expected EGVR for typical distribution systems and on the magnitude of associated touch voltages. The extent of hazardous step voltage areas around structures is also provided for typical structures and associated earthing systems. The step voltage hazard areas are based on limits calculated using a top soil layer of 100 Ω-m for a fault clearing time of 1 s and effectively give an indication of the expected maximum areas for each voltage level.

Mitigation measures are also discussed.

9


..1 Maximum EGVR on the HV earthing system

The EGVR on the earthing system of distribution centres and equipment during an earth fault depends on the various factors including:

(a) The source transformer impedance;

(b) The earth grid resistance of the source substation;

(c) Additional neutral impedance (i.e. NER, etc.);

(d) The impedance of the earthing system at the faulted site;

(e) The impedance of the interconnecting line or cable (which is dependent on the length).

On 11 kV rural feeders (and possibly some urban lines also) the EGVR at faulted sites is typically in the range 1 kVrms to 6.3 kVrms (see Figure 13).

Figure 13: Typical EGVR at 11 kV Faulted Sites

Figure 13 is based on the following parameter values:

(i) Zone substation earth grid resistance = 0.2 Ω;

(ii) Prospective earth fault current = 10 kA (lower prospective earth fault currents do not make a significant difference except close to the substation);

(iii) No NER;

(iv) Line conductor impedance = 0.4 Ω + j0.6 Ω per km;

(v) 0 ohm arc resistance.

For 22 kV distribution networks, the typical EGVR values will be double those shown in Figure 13.


90

The maximum EGVR on the HV plant earthing system, HV conductive pole (concrete or steel), or distribution transformer earthing system will have a big impact on the requirements (b) and (c) of section 6.2.1.

This maximum EGVR can be controlled by:

(f) Installing a Petersen Coil at the source zone substation, which virtually eliminates the earth fault current and the resulting EGVR;

(g) Installing a NER at the source zone substation.

This limits the maximum earth fault current level, but the reduction may not always be significant and may not always result in a site that is safe from EPR hazards. See section 4.3.

Many distribution centres and other structures such as concrete or steel poles that are not connected to extensive MEN systems, are likely to have relatively high earth electrode resistances (> 50 Ω) in many areas of New Zealand with the result that a typical NER (10 – 50 Ω) will have a limited effect on reducing EPR for these sites. Additional measures for controlling EPR hazards will often be required in these areas. However, urban distribution centres, and other HV earthing systems, bonded to an extensive interconnected urban MEN system, will typically have very low earth impedances (0.1 – 3 Ω). Even relatively low impedance NERs can have a major impact on reducing the maximum EPR on these earthing systems. The use of NERs for the control of EPR hazards should be investigated on a case-by-case basis.

(h) Bonding the HV earth (or HV conductive pole) to an extensive interconnected MEN system

This lowers the effective impedance to earth of the earthing system. In some specific situations, (i.e. high risk situations), this may be very effective.

(i) Interconnection of isolated pockets of MEN systems to each other via the neutral

This creates a much larger MEN system in urban areas and lowers the impedance to earth of the earthing system.

(j) Using an overhead earth wire to bond the HV earth (or HV conductive pole) to other HV earths and/or HV conductive poles, and possibly also back to the source zone substation earth grid.

This lowers the effective impedance to earth of the earthing system. However, the earth fault frequency will increase for the bonded sites, since a fault at any of the HV earths (or HV conductive poles) will result in EPR at ALL of the bonded sites. If the reduction in resistance gained does not have a significant impact on reducing the EPR, the risk may increase resulting in a worse situation. When considering this option, the risk should be carefully assessed.

In many cases, it is unlikely that bonding a few HV earths or conductive poles together will reduce the effective impedance sufficiently to make a significant difference to the EPR unless the overhead earth wire is bonded back to the source substation earth grid.

NOTE: A reduction in the impedance of an earthing system can be effective in reducing the EPR hazards. However, as set out in section 4.1, the fault current increases as the impedance decreases and the effectiveness of the reduction depends on the impedance of the earthing system relative to the total earth fault circuit impedance. For the reduction to be effective, the reduced impedance needs to be low compared to the other impedances in the faulted circuit. Therefore, care should be taken to ensure that any method used to reduce the impedance of the earthing system is effective.

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.. Touch voltage hazards on faulted structures

Touch voltages around an earthed structure depend on the EGVR at the structure and on the size of the earthing system. They can be estimated as a percentage of the EGVR for various combinations of structures and electrodes. Typical touch voltage values as a percentage of the EGVR on structures, for the case of homogeneous soil resistivity, are shown in Table 6.

Two types of earth electrodes have been considered:

(a) The electrode is located along a straight line on both sides of the pole or kiosk;

(b) The electrode is located along a straight line on one side of a pole or kiosk.

The effect of having a gradient control conductor around a pole or kiosk reduces the touch voltage on the structure and this effect is also shown in Table 6.

Typically, touch voltages as a percentage of the EGVR vary between 40% and 70% on structures where gradient control conductors are not used. If one gradient control conductor is buried (0.5 m deep) 1 m away from the structure, the touch voltage as a percentage of EGVR will vary between 25% and 30%. With two gradient conductors, at one metre and two metres away from the structure, it is possible to reduce the touch voltages to approximately 15%.

Table 6: Typical Touch Voltages as a Percentage of EGVR

Site Type Typical Electrode Typical Touch Voltage as % EGVR

Conductive pole without additional earthing 60%

Conductive pole without additional earthing and with one gradient conductor (1 m out) 35%

Conductive pole without additional earthing and with two gradient conductors (1 and 2 m out) 20%

Kiosk with electrodes on two sides 50%

Pole mounted equipment with rods on two sides 40%

Kiosk with electrodes on one side 60%

Pole mounted equipment with electrode on one side 60%

Kiosk with electrode on both sides and one gradient control conductor (1 m out) 25%

Pole mounted equipment with electrodes on two sides and one gradient control conductor (1 m out) 25%

Kiosk with electrodes on one side and one gradient control conductor (1 m out) 30%

Pole mounted transformer with electrode on one side and one gradient control conductor (1 m out) 30%

Pole mounted transformer or kiosk with electrode on both sides and two gradient control conductors (1 and 2 m out)

15%

PoleKioskPole KioskPoleRodKiosk with gradient Pole with gradient

Rod


9

In Table 6 the following parameters apply:

(i) The conductive pole has a footing of 1.5 m to 3 m deep and up to 0.3 m diameter;

(ii) The first gradient control conductor is at 1 m spacing from the pole or kiosk;

(iii) The second gradient control conductor is at 2 m spacing from the pole or kiosk;

(iv) The electrodes are made up of driven earth rods interconnected with bare copper wire.

.. Step voltage hazards around faulted sites

In this section, typical step voltage hazard areas have been estimated around conductive distribution poles (without additional earthing) and around earth electrodes associated with equipment. Depending on the soil resistivity (layers and values), the actual step voltage hazard areas may be smaller or larger than the calculated values, but not significantly so. These areas may be used in assessing the risk, but when applying the deterministic approach, actual step voltage hazards should be calculated.

The sizes of step voltage hazard areas have been estimated based on the maximum phase to earth voltage being present on the conductive pole or on the earth electrode. In many cases, the EGVR will be lower than the phase to earth voltages as set out in section 6.5.1 and these areas of step voltage hazards may not actually exist.

The radii of hazardous step voltage areas around conductive poles (without additional earthing) for various system voltages are shown in Table 7. Shoe impedance has not been included in these step voltage calculations as recommended in section 3.8.2.

Table 7: Radius of Step Voltage Hazard Area around Conductive Poles

System Voltage

(kV)

Radius of Hazardous Step Voltage Area (m)

Earth Fault Clearing Time = 1. s Earth Fault Clearing Time = 0. s

11 2.5 1

22 4 2

33 5 2.5

Table 7 shows that the areas of step voltage hazards around poles are small and in some cases, it may be possible to ignore these hazards.

For step voltage hazards around earth electrodes associated with transformers and other equipment, it is not as simple as specifying the radius around the earth electrode. In these cases, step voltage hazards zones have been defined as the zone covered by a contour drawn at a distance from any part of the earth electrode. This is illustrated in Figure 14 for an earth electrode associated with a transformer kiosk.

9


Figure 14: Hazardous Step Voltage Zone around Electrode

Typical distances between the earth electrode and the end of the hazardous step voltage zone are shown in Table 8 for various examples of earth electrodes associated with a transformer kiosk. The electrodes considered consist of multiple driven rods of various lengths with the separation between the rods equal to the length of the rods. Shoe impedance has not been included. The data shown in Table 8 can also be applied to pole mounted equipment.

Table 8: Extent of Step Voltage Hazard Zone around Earth Electrodes

Earth Electrode

Distance to Edge of Hazardous Step Voltage Area (m)

Earth Fault Clearing Time = 1. s Earth Fault Clearing Time = 0. s

11 kV kV kV 11 kV kV kV

2 x 1.8 m 3 5 7 11 2 3

2 x 5 m 3 5 7 0 2 3

4 x 5 m 2 5 8 0 21 2

10 x 5 m 11 5 9 0 0 21

NOTE 1: Only present on the side of the kiosk opposite to the earth electrode

.. Touch and step voltage hazards around occupied buildings

If a HV fault at a distribution centre results in hazardous EPR appearing on the associated LV MEN, then touch voltage hazards may be created on conductive objects on the outside of buildings that are bonded to the LV MEN, (e.g. taps). Step voltage hazards are unlikely to be created in the vicinity of the LV earth electrodes and other metallic objects connected to the MEN.


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.. Discussion of mitigation measures

Where required, mitigation of EPR should be based on information provided in section 4.

Mitigation of EPR hazards associated with distribution centres and equipment including conductive poles (concrete and steel) would typically involve the combination of various measures.

NERs can be used to reduce EGVRs on earthing systems and usually have to be used in conjunction with other mitigation measures. Better reduction in EGVR is obtained with higher resistance NERs.

Touch voltage hazards may be mitigated using gradient control conductors. Additional mitigation in the form of surface insulating layers such as crushed rock or asphalt may be used to further reduce touch voltages. Touch voltages can only exist on earthed structures that can be touched. If a structure cannot be touched then there is no risk to the public.

Isolation of structures from touch using insulating barriers such as wooden fences or protective covers can be a very effective means of mitigating touch voltage hazards. For example, earthed equipment installed on a wood pole would not have hazardous touch voltages since all metalwork within 2.5 m of the ground must be insulated. The same requirement applies to concrete poles but touch voltage hazards may exist on concrete poles because of the conductive nature of the pole.

Step voltages are more difficult to mitigate than touch voltages. However, section 6.5. has shown that step voltage hazard areas around distribution transformers and equipment will either be very small or will not exist. The risk associated with these step voltage hazards will be low for many cases.

Step voltage hazards may be mitigated by using soil surface treatment such as the application of crushed rock or asphalt. Restricting access, where possible, to step voltage hazard zones can also be effective.

Mitigation of hazardous step and touch voltages associated with conductive poles may be difficult to achieve in practice since the location of the poles often precludes the application of mitigation measures. With most existing concrete poles it is not possible to make an electrical connection with the reinforcing steel within the pole. Where it is desirable to mitigate hazardous step and touch voltages on and around a conductive pole, the use of a wood pole or another non-conductive material such as fibreglass or a polymer may be considered in place of the conductive pole.

To mitigate hazardous EPR voltages transferred to the LV MEN system, segregation of HV and LV earth electrodes may be considered (see section 4.8). This will only be effective if adequate separation is provided between the HV earth and the LV earth to ensure that the transferred voltage is within the required limit. Minimum separation distances are given in section 6.7.

In some circumstances, it may be advantageous to apply the TT system of supply to mitigate EPR hazards. As previously stated in section 4.9, special dispensation is required before the system of supply can be changed from a MEN system to a TT system. Dispensation may be provided on a case-by-case basis.

When using the deterministic method for the management of the risk associated with EPR hazards, the following should be considered:

(a) Rural areas

At customers’ buildings, where members of the public may touch an external earthed conductive

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surface that is quite distant from any associated earthing system, the touch voltage is effectively the full EPR on the LV MEN. As shown in section 6.5.1, EPR voltage on LV MEN systems connected to HV earth electrodes may be between 1 kVrms and 6.3 kVrms.

Practical ways of mitigating hazardous EPR voltages at these customers’ buildings to anything close to the required touch voltage limits for normal or special locations are:

(a) Installing a Petersen Coil at the source zone substation;

(b) Having separate HV and LV earthing systems at the distribution transformer;

(c) Restricting access to the earthed conductive surfaces.

(b) Extensive interbonded MEn system

In an extensive interbonded MEN network, step and touch voltage limits applicable to special or normal locations are likely to be achieved without additional mitigation, due to:

(a) The very low earth impedance of the extensive interbonded MEN network;

(b) Direct connections between the extensive interbonded MEN network and the source zone substation in the form of overhead earth wires or cable screens (where such direct connections has been provided). This direct connection reduces the HV fault current returning through the body of the earth and will result in a very low level of EPR on the LV MEN;

(c) HV fault current passing into the body of the earth through the extensive interbonded MEN network earths will cause the potential in ground between these earthing points to rise, making any potential gradients in the urban area shallower, and reducing the actual step and touch voltages.

As a result, a simple HV earthing system comprising only two 1.8 m long earth rods will be all that is required in many cases, when that HV earthing system is bonded to an extensive urban MEN system.

An extensive interbonded MEN network should have an overall impedance to earth of less than 0.5 Ω. This can be estimated by determining the resistance of a representative sample of single residential earth electrode resistances and dividing by the number of installations. For cable networks where screens are bonded at both ends, the objectives may be met with fewer installations.

(c) Smaller MEn systems

To control the touch and step voltage hazard in areas with ‘limited MEN islands’, one or more of the following options may be considered:

(a) Install additional bonding between nearby MEN systems, to achieve a MEN impedance of less than 0.5 Ω;

(b) Install significant earth fault current limitation (e.g. NERs) to reduce the EPRs;

(c) A combination of the above.

Power companies may do an audit of MEN interconnections (including any connections to the source zone substation earth grid) in their urban areas, to identify opportunities to increase and strengthen these interconnections, especially in multiple directions.


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. COnTROL OF DAnGEROUS EPR IMPRESSED On THIRD PARTY ASSETS AnD PERSOnnEL

During a HV phase to earth fault at a HV earthing system including a HV conductive pole and a LV MEN system that is bonded to the HV earthing system, the resultant EGVR on the HV earthing system can present a hazard to third party network plant, customers and personnel. Further details on EPR transferred to third party assets are set out in section 2.7.

This means that electrical systems should not be constructed near third party assets where interference limits may be exceeded. Therefore, the identification of third party assets and equipment must form part of project planning for an earth electrode installation.

Adequate separation distances between electrical systems and telecommunication systems are required to ensure that interference limits are not exceeded.

The Electricity Act requires that all third party stakeholders must be notified of any new installation, modification or extension to the HV network that will affect or is likely to affect third party assets that are constructed in, on, along, over, across, or under a road. Notification is not required if the work does not affect the third party asset. Notification should form part of the planning stages for the intended work. Details of earthing arrangements and any interference mitigation measures proposed should be included in this notification. Adequate notice should be provided during the planning stages for the intended work to allow any hazards to be identified, discussed, and where necessary addressed either by changes to the proposed work, or by mitigation installed on the third party network, prior to commissioning.

Alterations to an existing HV network that could introduce new EPR hazards include the following:

(a) Increasing the earth fault current by increasing the line or cable size or replacing the source transformer with a larger transformer;

(b) Increasing the voltage on an existing line (e.g. by upgrading an 11 kV line to 22 kV);

(c) Increasing the size of an HV earthing system. This will reduce the resistance of the HV earthing system but it increases the extent of the hazard zone;

(d) Replacing a HV non-conductive pole (e.g. wood) with a conductive pole, (e.g. concrete).

..1 Telecommunications EPR transfer issues

For telecommunications interference issues, network companies should contact the telecommunications companies to discuss the appropriate minimum separations from the various types of telecommunications plant that are appropriate for their area and any mitigation required.

The following issues concerning telecommunication EPR transfers should be considered:

(a) Rural areas

In rural areas, the EGVR at 11kV/400V distribution transformers is typically in the range shown in Figure 13. For 22kV/400V distribution transformers, the EGVR is typically twice that shown in Figure 13. As a result, if the distribution transformer has a common HV/LV earthing system,

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substantial damage often occurs to mains-powered customers’ telecommunications equipment in buildings supplied by the transformer during an EPR event.

The associated insulation breakdown then results in the transfer of hazardous EPR (typically in the range 1 kVrms to 6 kVrms) via telecommunications network cable pairs to the telephone exchange. Insulation breakdown within telecommunications network cables to adjacent cable pairs is likely to occur in many situations, spreading this EPR to other customers’ premises. This can present a hazard to telecommunications network customers, personnel and equipment throughout the area.

As outlined in section 6.5.1, the reduction of EGVR on HV earthing systems is possible but it is usually impractical and uneconomical to reduce this EGVR to anything close to levels of 430/650 Vrms that would be required to ensure that telecommunications plant and equipment are not affected. In these circumstances, the separation of HV and LV earth electrodes may be considered to mitigate the risk (see section 4.8). As previously mentioned, separation of HV and LV earth electrodes may not be very effective on networks where overhead LV is run under HV conductors since HV to LV contacts on the lines will bypass the segregation of HV and LV at the transformer.

Section 6.7 gives typical required minimum separation distances between HV and LV earth electrodes.

(b) Urban areas with an extensive interbonded MEn system

In urban areas with an extensive interbonded MEN network, the EGVR is highly likely to be less than 430 Vrms, and may well be less than 280 Vrms. This is supported by Telecom’s experience of an almost total lack of damage history from power network faults in urban areas to power plant bonded to an extensive interbonded MEN network. Therefore, no mitigation of transferred voltages is expected to be required for power plant bonded to an extensive interbonded MEN network in these areas.

(c) Smaller MEn systems

To control the EGVR levels on LV MENs in areas with ‘limited MEN islands’, one or more of the following options may be considered:

(a) Install additional bonding between nearby MEN systems, to achieve a MEN impedance of less than 0.5 Ω;

(b) Install significant earth fault current limitation (e.g. NERs) to reduce the EPRs;

(c) A combination of (a) and (b).

Power companies may do an audit of MEN interconnections (including any connections to the source zone substation earth grid) in their urban areas, to identify opportunities to increase and strengthen these interconnections, especially in multiple directions.


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.7 SEGREGATED HV AnD LV EARTHInG

When providing segregation between HV and LV earths, the HV and LV earthing systems should be designed to ensure that the protective devices operate effectively.

Sufficient separation of HV and LV earth electrodes should be provided to ensure that any EPR transferred from the HV earthing system onto the LV earthing system minimises the risks associated with the following hazards:

(a) Hazardous voltages transferred onto the telecommunications network; and

(b) Touch and step voltage hazards transferred onto the MEN system.

Typical minimum separation distances are given in sections 6.7.1 and 6.7.2 for these two hazards. Closer separations than the typical minimum distances may be possible but these closer separation distances must be determined by specific design.

Separate HV and LV earthing systems may not be effective in controlling hazardous step and touch voltages in the event of a HV line to LV line contact at the distribution transformer, or on a conjoint HV/LV line section. Options for protecting against HV to LV contacts are outlined in section 4.8.

For interbonded MEN systems segregation of HV and LV earth electrodes may be practically difficult. Care is required to ensure that the neutral of the segregated LV system is not bonded to the LV MEN of another transformer that does not also have segregated HV and LV earthing systems.

Transformers with segregated HV and LV earth electrodes must be able to withstand the maximum EGVR of the HV earthing system, without breaking down to the LV side of the transformer, (e.g. via HV/LV winding breakdown, or transformer tank to LV conductor breakdown). The withstand voltages on most 11 kV transformers should be adequate but on 22 kV transformers the possibility exists that the EGVR on the HV earth electrode may cause a flashover across the LV neutral bushing.

NOTE: Transformers that are connected to segregated earth electrodes will be more at risk of failures from lightning surges. To reduce this risk, a surge arrester is usually provided between the HV and LV earths.

When the LV earthing system is segregated from the HV earthing system at a distribution centre, the total earth impedance of the LV earthing system plus associated MEN earths must be sufficiently low to ensure the HV feeder protection to the distribution centre will trip. A safety factor of two should be used in calculating this maximum earth impedance value. This ensures that the HV protection will operate in the event of a HV line to LV line contact, or a HV/LV winding insulation breakdown in the distribution transformer.

.7.1 Hazardous voltages transferred onto telecommunications networks

Typical minimum separation distances between HV and LV earths for 11 kV distribution transformers are set out in Table 9.

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Table 9: Typical Minimum Separation Distances between HV and LV Earths for 11 kV

Distribution Transformers

Size of MEn systemSize of HV earth electrode NOTE 1

Minimum separation distance

(m)

Medium to large MEN system (> 50 customer earths)

Small 2

Large 5

Small MEN system (5 to 50 customer earths)

Small 2

Medium 5

Large 10 NOTE 2

Very small MEN system (< 5 customer earths)

Small 10

Medium 30 NOTE 2

Large 50 NOTE 2

NOTE:

1: The Small HV earth electrode is based on a minimum earthing system consisting of two vertical driven 1.8 m long rods, spaced 1.8 m apart, connected together with bare earth wire.

Examples of a Medium HV earth electrode include:

(a) Two vertical driven 5.4 m long rods, spaced 5.4 m apart, connected together with bare earth conductors;

(b) Four vertical driven 3.6 m long rods, spaced 3.6 m apart, connected together with bare earth conductors;

(c) Six vertical driven 1.8 m long rods, spaced 1.8 m apart, connected together with bare earth conductors.

Examples of a Large HV earth electrode include:

(d) Two vertical driven 10.8 m long rods, spaced 10.8 m apart, connected together with bare earth conductors;

(e) Five vertical driven 5.4 m long rods, spaced 5.4 m apart, connected together with bare earth conductors;

(f) Ten vertical driven 1.8 m long rods, spaced 1.8 m apart, connected together with bare earth conductors.

2: This minimum separation distance assumes that the closest consumer earth is also at a distance of at least the minimum separation distance from the HV earth electrode. For 22 kV distribution transformers, the typical minimum separation distances will be approximately double the distances in Table 9.

To practically achieve the larger minimum separation distances, consideration should be given to installing the LV earth one span away from the HV earth. However, consideration should also be given to the risk associated with a broken earthing conductor to the LV earth.


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.7. Touch and step voltage hazards transferred onto the MEn system

The separation distances required for the control of touch and step voltage hazards transferred onto the MEN system are larger than the distances required for the control of transferred voltages onto the telecommunications network. These distances are typically between 30 and 100 m for 11 kV distribution transformers depending on the size of the HV earthing system. The larger separations are required for larger HV earthing systems. The separation distances are not significantly dependent on the size of the MEN earthing systems. For 22 kV transformers, the separation distances are typically twice the above values. Therefore, for the control of touch and step voltage hazards, it is preferable to install the LV earth electrode one span away from the HV earth electrode.

NOTE: A customer earth that is closer than the typical minimum separation distances will compromise the effectiveness of the separation even if the above typical minimum separation distances between the HV and LV earths are met.

Where risks associated with transferred touch and step voltage hazards onto the MEN system have been identified, separation of HV and LV earths always reduces these risks even if the above typical minimum separation distances cannot be achieved. This is especially true for the larger MEN systems. Also, the number of customers affected depends on the physical size of the HV earth electrode. So, it is beneficial to keep the size of the HV earth electrode as small as possible.

. EARTHInG SYSTEMS FOR DISTRIBUTIOn CEnTRES AnD EQUIPMEnT

An earthing system for distribution centres or distribution equipment consists typically of one or more driven rods in parallel and interconnected by buried horizontal copper conductors. For distribution centres, two separate banks of driven rods have typically been used to facilitate disconnection of each bank for resistance testing.

Modern test equipment is available to enable resistance testing to be carried out without disconnecting the earth electrode. The use of such testing equipment would enable the installation of a single bank of driven rods.

The length of the rods is typically between 1.8 m and 10 m.

.9 COnnECTIOn OF nEUTRAL TO EARTH

In a low voltage alternating current system, the neutral conductor must be earthed at or near the distribution centre (see section 6.7). It should also be earthed at such other places as will ensure that under fault conditions the earthing system provides a low impedance path for earth fault currents. Where applicable, fault conditions must include those faults involving the associated high voltage system.

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In calculating the earth impedance of a combined HV/LV distribution system, account may be taken of all connections of the neutral conductor to earth, including:

(a) The earth connection at the distribution centre as specified in section 6.7;

(b) Such earths as may be installed on the distribution system;

(c) The earth connections at consumers’ installations; and

(d) The effect of any permanent interconnections (i.e. where no links are fitted) between the neutral conductor of a given distribution system and the neutral(s) of other distribution system(s).

In a high voltage system, the neutral conductor must be earthed at or near the source of supply by:

(e) Direct earthing of the neutral point;

(f) Earthing through an artificial neutral point obtained from an earthing transformer;

(g) Earthing in accordance with paragraph (a) or (b) via an earthing resistor or reactor.

In addition the neutral may be earthed at other points in the system.

.10 EARTHInG OF FITTInGS AT DISTRIBUTIOn CEnTRES

This section applies to distribution centres.

All fittings associated directly with any high voltage system should be earthed as follows:

(a) A minimum of two independent earth electrodes should be provided and connected in such a manner that either can be disconnected independently for the purpose of testing; or

(b) Where equipment is available to allow for measurement of earth electrode resistances without disconnection of the electrodes, a single earth electrode may be used.

The following fittings should be connected to the earthing system of a distribution centre:

(c) Transformers and circuit breakers;

(d) Metallic cable sheaths or screens;

(e) Low voltage neutrals, except where separate HV and LV earthing systems are installed, in which case only the LV neutrals must be connected to the LV earthing system;

(f) Portable earth connection bar;

(g) Pad reinforcing mesh or electrode installed in the pad (for pad mounted equipment);

(h) Lightning arresters; and

(i) Any uninsulated metalwork within 2.5 m of the ground that may become alive.

Bonding of fittings, LV neutrals and other earthed metal work should be done through earth bars. One or more interconnected earth bars may be used depending on the requirements and space constraints. In some cases, it might be desirable to have one earth bar for all the local earthing conductors and a separate earth bar for LV neutral, LV sheath and HV sheath conductors. Separate terminal bars must be connected together by means of a suitably sized conductor.


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Earth bars should be arranged in such a way that the disconnection of one earth connection does not interfere with other earth connections.

All fittings and any uninsulated metalwork, other than cable screens or armouring, that are liable to become alive should be connected to the earthing system (but may not require a separate earthing connection), which may include the MEN system. Some fittings that are out of reach from the public may not required bonding to an earthing system. However, the safety of personnel should be considered when deciding which fittings to earth.

.11 EARTHInG OF FITTInGS AT DISTRIBUTIOn EQUIPMEnT

This section applies to fittings of distribution equipment other than at distribution centres.

The following fittings should be connected to the earthing system of a distribution equipment site:

(a) Auto-reclosers;

(b) Disconnectors (ABS, ABI, sectionalisers, etc.);

(c) Metallic cable sheaths or screens;

(d) Low voltage neutrals, if applicable;

(e) Portable earth connection bar;

(f) Pad reinforcing mesh or electrode installed in the pad (for pad mounted equipment);

(g) Lightning arresters; and

(h) Any uninsulated metalwork within 2.5 m of the ground that may become alive.

All fittings and any uninsulated metalwork, other than cable screens or armouring, that are liable to become alive should be connected to the earthing system (but may not require a separate earthing connection). Any such metalwork may also be connected to a multiple earthed neutral system. Some fittings that are out of reach from the public may not required bonding to an earthing system. However, the safety of personnel should be considered when deciding which fittings to earth.

Considerations should be given to mounting the fittings of HV disconnectors above a height of 2.5 m so that no part of the fittings is below 2.5 m above ground level especially in urban areas where the risk are typically higher than in rural areas. This will ensure that the fittings cannot be touched by members of the public.

The metal operating handles of all high voltage disconnectors should be directly earthed unless the handles are insulated to the full working voltage.

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.1 SAFETY WHILE OPERATInG DISCOnnECTORS

Unlike disconnectors located in any HV a.c. station (see section 5.14), an environment in which touch voltages are unlikely to exist, disconnectors used on distribution networks outside substations will typically have touch voltage hazards on them in the event of an earth fault. Since the disconnectors are located mostly on private and public land, equipotential operator mats are not usually provided for these disconnectors and operators may be at risk.

To avoid hazardous touch voltages on the operating handles, insulating gloves should be used by operators.

In addition to gloves, the use of one of the following risk control options is recommended (options (a) and (b) are preferred):

(a) A portable equipotential operator mat;

(b) A gradient control conductor (i.e. a ring or loop) installed under the location where the operator will be standing;

(c) A driven rod installed under the location where the operator will be standing.

The earth electrodes or the operator mat should be bonded to the operating handle and rod using flexible leads or braids. Sleeves should be provided at the lugs to ensure that the leads cannot bend sharply at the lugs.

Auto-reclosers carry a lower risk profile than ABSs with moving parts that are exposed to the elements and may be subject to significant wear. Because of this lower risk, gloves may not be required for the operation of auto-reclosers. Utilities need to decide whether gloves should be worn by their staff and/or contractors when operating auto-reclosers or whether a different method of mitigating touch voltages should be applied.

.1 EARTHInG COnnECTIOnS

Conductor ratings for both bolted and welded connections for various fault clearance times can be determined as set out in section 2.11. These clearance times relate to the protection associated with the portion of high voltage line.

Earthing conductors, where exposed, must be:

(a) 0.6/1 kV rated; and either

(b) Green or green/yellow PVC insulated; or

(c) Enclosed in insulating conduit.

Insulated conductors must be used wherever electrical workers may come into contact with the conductor.


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Buried conductors should be copper and bare unless there are special reasons for using insulated copper or other metals.

Earthing system conductors must be sufficiently large to:

(d) Minimise the probability of mechanical damage;

(e) Minimise the consequence of minor corrosion; and

(f) Provide adequate current carrying capacity.

If necessary earthing systems must be upgraded where fault levels increase above the original design level.

For the connections between HV equipment and the grid, the size of the earthing conductor must be based on the maximum earth fault current (100%).

All earthing conductors should have a minimum size of 35 mm2.

.1 LOW VOLTAGE EARTHInG COnDUCTORS ASSOCIATED WITH LV SYSTEMS

Conductors used to connect the neutral terminal or bar of a LV system to the earth bar, or the neutral conductor of an outgoing overhead line, must not be smaller than that calculated for the HV earthing conductors based on the expected fault current and duration.

.1 COnnECTIOnS TO EARTHInG ELECTRODES

Where conductors are connected to earth electrodes and are accessible to the public (as at pole type distribution centres or where the neutrals within the distribution system are connected to earth), those conductors must be protected against mechanical damage.

The conductors must be brought out of the ground parallel and close to the foot of the pole and must be protected to a height of 2.5 m. Fibreglass channel section or a suitable wood or a suitable plastic material (i.e. PVC or Polyethelene) may be used to provide mechanical protection.

Joints between earthing conductors and earth electrodes must be of adequate mechanical strength and current carrying capacity and so arranged to ensure that there will be no failure of the connection under any conditions of use or exposure that may be reasonably anticipated. Clamps and similar mechanical connections must be so designed and constructed that the connection will not slacken off under use.

Where conductors connecting driven electrodes in parallel are not kept above the ground, they must be buried no less than 0.5 m below the surface. Connections of conductors to such electrodes must be made by brazing or exothermic welding processes or by suitable compression fittings. Compression or wedge type fittings may also be used provided they have met the requirements of IEEE Standard 837. Bolted connections must not be used underground.

If test links (earth bars) are inserted in earthing conductors connected to electrodes, they must be bolted links and arranged so that the opening of one link does not interfere with earth connections other than the one under test.

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.1 SURGE ARRESTERS

Lightning surge arresters should be installed as close as possible to the equipment being protected and should be earthed to the equipment earth reference point (i.e. casing, frame, tank, etc.) by an earth connection that is as short as possible to present a low impedance path to high frequency currents.

For transformers, the surge arresters can be mounted directly on the transformer tank or on a bracket close to the bushing to minimise lead lengths.

Surge arresters used for the protection of cables should be mounted as close as possible to the cable terminations to enable the leads used to bond the surge arresters to the cable screens to be kept as short as possible.

The installation of surge arresters close to equipment may result in protection fuses being located on the supply side of the surge arresters, which may increase nuisance tripping of fuses.

Any inadvertent break in the earth conductor of a surge arrester will raise the voltage of the conductor connected to the surge arrester to full phase voltage.

Consideration should be given to selecting surge arresters based on temporary overvoltages that are applicable to impedance earthed systems. Surge arresters would then not need to be upgraded if a solidly earthed system was changed to an impedance or resonant earthed system.

.17 SOIL RESISTIVITY

Where required for the equipment earth electrode design, soil resistivity should be measured using the Wenner method.

Soil resistivity tests should be carried out at test-probe spacings that are proportional to the expected dimensions of the earthing system.

For 11 kV and 22 kV rural and urban distribution installations, measurements should be taken for test-probe spacings varying between 0.5 m and 15 m. For each test traverse, measurement of soil resistivity should be carried out for a minimum of 12 different spacings of the test probes. Recommended spacings are: 0.5, 1, 1.5, 2, 2.5, 3, 4, 6, 8, 10, 12 and 15 m.

Soil resistivity tests should be carried out away from metallic objects such as other earth electrodes, buried water pipes, fences, etc.

The measured data should be evaluated to determine a soil resistivity model for the site. Determination of the correct soil resistivity model for the site is an important aspect of the design. Earthing design software may be used to assist in determining a soil resistivity model on which to base the earthing system design.

.1 EARTHInG ARRAnGEMEnT ExAMPLES

Examples of earthing arrangements are included in Appendix C. These examples illustrate typical earthing arrangements for a few specific situations. The user of this guide should develop their own earthing arrangements to suit their own situations where required.


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.19 TESTInG AnD MAInTEnAnCE

The integrity of the earthing system should be verified by appropriate periodic inspections and tests. The asset owner should determine appropriate inspections and test intervals based on knowledge of its earth electrodes installation and design standards, and on its understanding of environmental conditions and assessment of risk, e.g. soil conditions, copper theft, etc.

Resistance testing of all new earth electrodes or all electrodes of assets where work has been conducted should be carried out prior to connection to the MEN system.

Where practical, resistance tests should also be carried out on earth electrodes at distribution centres connected to the LV MEN system.

It is also recommended that the integrity of the earth bonding conductors be tested at regular intervals. This is a continuity test across bonds. Expect a resistance of less than 10 mΩ per bond test.

Records of all resistance tests and designs must be maintained by the asset owner.

.19.

For distribution centres and equipment sites, the test and inspection intervals should not exceed those detailed in Table 10.

Table 10: Equipment Site Routine Inspection Plan

Description Frequency Description Comments

Visual inspection to ensure integrity of system components above ground

1 – 2 yearsVisual check of earth conductors, connections and protective covers.

Check earth conductors and connections for physical damage, looseness and corrosion. Particular attention should be given to areas of new installations or excavated areas and to areas where the theft of copper may be an issue.

Test to ensure electrical integrity

5 – 10 years

Resistance (bonding continuity) measurement of plant earthing/bonding connections. Earth electrode resistance measurement. Touch and step voltage measurement where required. Visual inspection of buried conductors may be required if inspection and test results indicate issues.

Compare resistance to earth with previous results to check for any obvious trend (i.e. resistance to earth decreasing over time). For bond tests, expect < 10 milliohms per bond test.

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SECTIOn 7 – OVERHEAD ELECTRICAL LInES 0 kV A.C. AnD ABOVE

7.1 InTRODUCTIOn

Overhead electrical transmission lines form an extensive electrical network that transmits power throughout the country to all the regional load centres. Each has a nominal operating extra high voltage, ranging from 50 kV to 220 kV. For the purpose of this guide these overhead electrical lines are referred to as transmission lines. The integrity of each transmission line is critical to maintaining a continuous electrical supply to any particular load centre. Consequently, the transmission lines are designed to operate with very low rates of failure that would cause an earth fault at a particular transmission structure.

Some companies may have the majority of their lines operating at nominal voltages less than 50 kV. They may choose to apply a common policy for all their lines and adopt other practices described elsewhere in the guide. They may for instance apply the practices described in section 6 to all lines below 110 kV.

Sections of transmission lines may be close to roads and buildings where the public is regularly present. The earthing systems for transmission line structures provide paths for electric fault currents, such as from lightning, to flow safely to earth. This ensures that protection operates while minimising any hazards in the vicinity of the structures.

Transmission lines require high speed, high integrity protection to achieve rapid fault clearance. Hence transmission line earth faults normally involve very short duration high fault currents, at a very low incident rate.

Transmission lines are designed to achieve large power transfers. Through magnetic field induction (see section 2.3.4) these lines create voltages on metallic conductors that run parallel to the lines. Induction can be particularly significant for nearby power lines, telephone lines, conveyors, pipelines, railways and fences. Induced voltages are continuously present while the transmission line is operating, but substantially increase when the balanced transmission line magnetic field is distorted when fault currents flow during a line fault.

Extra high transmission voltages impose a voltage by electric field capacitive coupling (see section 2..) on any nearby insulated metallic conductor. However, the electric field strength at the insulated conductor is reduced because the transmission lines are normally some distance from such conductors and, consequently, the stored energy retained in capacitively charged metallic conductors is not generally significant.

Case studies are presented in Appendix B.

7. CORRIDOR MAnAGEMEnT

Transmission line structures must have safe earthing systems that provide a means of carrying electric currents into the earth under normal and fault conditions. This must be achieved without exceeding operating and equipment limits or adversely affecting continuity of supply.

The line support structure earthing arrangements direct earth fault currents, including lightning, down the structures to the earthed footings and buried electrodes. Hazardous voltages can occur on and around transmission line structures during these earth faults. For a dangerous situation to arise, a power system earth fault must be coincident with a person being in the vicinity of the earthing system.


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Transmission line structures should preferably be sited away from locations where they would be frequently visited, contacted, or subject to an inappropriate activity that increases the likelihood of an incident. This will assist in minimising the risk of exposure to a transmission line earth fault where a person is close by and potentially exposed to a hazardous voltage. Alternatively, barriers or fences may be necessary.

The design of transmission lines should be such that the probability of a person in the vicinity of a structure being exposed to the danger of a hazardous voltage is unlikely or minimised.

The design of transmission lines should also be such that the risks of transferred EPR hazards onto third party assets such as metallic fences, railway systems, telecommunications plant, pipelines, MEN networks, etc., are minimised.

7. STEEL LATTICE STRUCTURES

Steel lattice structures are either painted or galvanised steel structures formed from steel cross members bolted together to form a supporting lattice. They are electrically continuous with multiple cross connections and bolted conducting paths. They should not require an independent downlead.

The structural members and the bolted connections should be sufficient to conduct both line fault currents and lightning strikes directly to earth. This should occur without damage being sustained to the steelwork. The paint surface does not require special electrical attributes. There should be sufficient contact through the bolt fittings to conduct the prospective fault current to earth.

7..1 Steel lattice structures overhead earth wire

When a transmission line insulator fails or when the line is struck by lightning, the structure steelwork should conduct some or all of the fault current to earth. When an overhead earth wire (OHEW) is fitted, a proportion of the fault current should flow away from the structure along the OHEW to the substation earth mat. Similarly, when an OHEW is installed a proportion should find alternative paths to earth across on the OHEW and down through a number of the adjacent steel lattice structures. See section 7.7.

OHEWs should be electrically connected to the steelwork through either the OHEW fixings or through a dedicated jumper wire. Where a jumper wire is fitted this should be rated for the prospective fault current. Typically, a 37/2.25 mm low tensile annealed 1350 aluminium jumper should be adequate for most applications. The installation of a single disc insulator should be considered, fitted on the supporting fixings, and in parallel with the jumper wire. This ensures that circulating currents do not flow through the fixings, and minimises corrosion of the fixings. To be effective, the insulator should have in excess of 300 mm electrical creepage distance.

7.. Steel lattice structures earth electrode connection

Steel lattice structures should be electrically connected to their foundations through external straps to the reinforcing. These straps must be adequately rated for the prospective fault current, the environmental conditions, and for mechanical strength. Typically 50 mm by 5 mm copper earth straps should be connected from each leg to the steel reinforcement of the supporting concrete pile. The concrete piles should act as the earth electrode for the structure. If these straps are on an exposed section of the tower leg, their condition and integrity can be routinely monitored. This

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is not always possible, particularly where theft is a concern in which case the straps may need to be buried or covered.

The design of the joints, between the earth strap and the steelwork and the connection to the pile reinforcement, must consider both the prospective fault current for the joint and prevention of the corrosion of the joint. Typically these joints should either be bolted or formed with an exothermic weld.

Supplementary earthing electrodes may be installed to reduce the tower footing resistance. These should generally be connected with a non-insulated copper earth bar 25 mm by 5 mm bonded to the supplementary electrodes with exothermic weld or similar joints. The buried conductors should typically be installed 300 mm below ground level following the route of the transmission line to minimise impact to adjacent land owners, as they influence the EPR voltage contours. Where these additional electrodes are required they should typically be to a depth of 4 m or greater and located 20 m from the tower legs to prevent drying out and achieve the most economic electrode distribution. The electrode position should be either marked or the electrode connection mounted in an inspection box.

7.. Steel lattice structures earthing plate

An earthing plate should be located on each of the cross arms, and reasonably accessible for the line workers to attach tail clamps close to their work sites. Typically, the plates should be capable of withstanding a fault of 25 kA for 1 second and wide enough to allow at least three tail clamps to be secured to each plate. The galvanised earthing plates should be fixed with two bolts to the same main tower member, which should be at least 45 mm wide and 6 mm thick, to maintain the fault current rating. To prevent corrosion, sealant or fresh galvanic rich paint should be applied to the prepared mating surfaces when securing the plate. The upper portion of the plate should be masked-off during tower painting. The EEA ‘Guide to work on de-energised distribution overhead lines’ describes practices that should be followed in installing portable earth equipment.

7.. Steel lattice structures earth potential risk

There should be no hazard from touching steel members during normal operation. Stray leakage currents may be present, particularly when there is high humidity, but these should not be at levels that are hazardous. Also, where structures are painted, the touch voltage is unlikely to exceed the insulation properties of the paint surface.

In the majority of cases an earth fault is caused when either the line is struck by lightning or a transmission insulator fails and hazardous voltages could occur both on and around the steelwork. These will last for the duration of the fault. Generally faults should be cleared within 100 ms.

The voltage that the steel could potentially reach in the event of an earth fault is the EGVR as described in section 6.5.1 for distribution lines. The maximum EGVR occurs close to the substation. The EGVR should progressively reduce with distance from the source, primarily due to the inductive impedance of the transmission line. These issues are described in section 7.12.

In most cases during an earth fault, sizeable voltages occur on and around the base of the structure. Where the voltage rise is potentially hazardous, the need for and form of mitigation can be assessed by applying the probabilistic method described in section 3.


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7. STEEL AnD COnCRETE POLES

Concrete poles used for 50 kV and above, particularly those used in the national grid, should have provision for bonding to the internal reinforcing or to an internal conductor. Consequently, like steel poles, concrete poles should be treated as conductive structures.

These transmission poles should not generally be used to mount plant or equipment other than line surge equipment. An external equipment earth downlead should not be required, unless installed for pole mounted equipment. These, where fitted, should be bonded to the internal reinforcement.

The cross arms of concrete poles may be steel or may be wood. In the case of steel cross arms, a positive path to earth must be established to prevent pole damage with bonding of the crossarm to the internal earth conductor, or reinforcement.

By installing binding wire between internal longitudinal reinforcement and the laterals on concrete poles, sufficient multiple paths exist to form a conductive cage. This generally negates the need for an internal conductor or an external downlead. The reinforcement should be bonded to any lightning shielding such as arc horns, spikes or OHEWs. The reinforcement should be bonded to steel cross arms. The upper sections of insulated guys should similarly be connected either directly to the reinforcement or to a bonded component. The poles must therefore have several external fittings connected to the reinforcement that allow the bonding straps to be connected to the reinforcement. A 120 mm2 copper bonding strap should typically have an adequate fault current capacity to connect the external equipment to these fittings.

An above ground fitting should be provided on the pole to allow a permanent external earth electrode, where installed, to be connected to the concrete reinforcement. Similar provision should be made on the steel poles.

Concrete exhibits some insulation qualities, but is hygroscopic and attracts moisture, becoming conductive when wet. It is therefore assumed to always be conductive for transmission line design purposes. The buried section should be assumed to be at ground potential.

The buried portion should act as an earth electrode. Generally, for both steel and concrete poles, supplementary permanent earthing electrodes are only required to ensure protection performance.

7..1 Workplace earth point connection

When work is carried out on overhead conductors, by line workers from a position on a support structure, a cluster mount or similar workplace earthing point must be installed to achieve equipotential zone (EPZ) bonding. This should be located on the pole in close proximity to the work site and below the point where the line workers’ feet contact the pole. The pole must have means for the cluster mount or earthing point to make good electrical contact with the steel pole or be bonded to the reinforcement of the concrete poles.

Some consideration in the design should be given to the permanent facilities that may be required to accommodate the installation of the portable earths. The requirements for portable earths are described in the EEA ‘Guide to work on de-energised distribution overhead lines’.

For steel poles a lug welded to the pole can identify the position where the cluster mount should be fitted.

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On concrete poles without a downlead, cluster mounts or an earthing point should be bonded or mounted onto a pole fitting for EPZ bonding. The pole fitting must be connected to the reinforcement. Neither this fitting nor its internal connection to the reinforcement is typically fault rated, so an independent temporary earth electrode should be installed when the cluster mount is fitted. When the temporary earth electrode, cluster mount or workplace earth point are being used to achieve an EPZ, these fittings and leads must be rated for the prospective fault current as these form the prospective fault path.

Where no means exist of making a cluster mount or workplace earth point EPZ bond to the concrete reinforcement, then a potential difference may occur during a fault. Restrictions should be applied to the use of the pole to access the transmission line. These should be designed to eliminate as far as practical, the exposure of the line workers to a potentially hazardous voltage.

7.. Steel and concrete pole earth potential risk

Steel poles and concrete poles, like steel lattice structures, should both be regarded as conductive structures during an earth fault and evaluated accordingly. See section 7.3.4.

Concrete does have some insulation properties that make it less likely to present a touch hazard. However, the insulation properties are not always present and concrete is often punctured during such an event with the limited cover between the earthed reinforcement and the touched surface. The insulation qualities, though significant, should therefore be ignored and represent a further factor of safety in the EPR assessment.

The foundations for steel lattice structures are more extensive than for poles. This has the effect of reducing the EGVR for steel lattice structures. However concrete and steel poles are generally earthed by a single foundation rather than being distributed as in the case of steel lattice structures. The area where hazardous voltages may occur around poles is therefore smaller than for steel lattice structures. The factor that predominates between these is site specific and must form part of the assessment.

7. WOOD POLES

Wood poles must be considered to be partially conductive.

The insulation properties of the wood limit earth fault currents passing down the pole and prevent an effective earth path. Consequently, except for special circumstances, the wood pole acts as an insulator.

Where a line worker is climbing the wood pole, the pole must however be considered sufficiently conductive to be hazardous. Potentially, the line worker may be simultaneously in contact with two sections of pole and exposed to a hazardous potential difference.

A downlead may be fitted to a wood pole. This provides an effective earth path. Downleads are only fitted where a path to ground is required to prevent lightning damage or to provide earthing for equipment located on poles.

A wood pole, where fitted with a downlead, must be considered to be a conductive structure and the conditions described for the steel and concrete poles must apply requiring metalwork to be bonded to the downlead. An earth electrode must be required to earth the downlead and achieve the required footing resistance.


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7..1 Workplace earth point connection

The EEA ‘Guide to work on de-energised distribution overhead lines’ describes practices that should be followed in installing portable earth equipment. Some consideration in the design should be given to the permanent facilities that may be required to accommodate the installation of the portable earths.

When work on overhead conductors is carried out by line workers from a position on a wood pole, a cluster mount or similar workplace earthing point must be installed to achieve EPZ bonding. This should be located on the pole in close proximity to the work site and below the point where the line worker’s feet contact the pole.

Poles should have means for cluster mounts to be connected to the downleads where fitted. In other cases, two coach screws should be installed penetrating beyond the centre of the pole and at 90° to each other, and should be bonded together. The coach screws should achieve the required connection to the partially conductive central core of the wood pole. The cluster mount or earthing point should be mounted onto one or more of these coach screws.

The cluster mount must be cabled to an independent temporary earth electrode. The earth electrode should be in addition to any permanently installed electrodes. Consequently, any permanently installed leads, fittings and electrodes that do not form part of the prospective fault path may have a lower fault current capacity than required for the portable earths.

7.. Wood pole earth potential risk

Wood poles without downleads are non conductive or partially conductive and are not hazardous except potentially when they are climbed.

No hazardous touch or step voltages occur on or around the bases of wood poles. Consequently wood poles without downleads can be used as a means of mitigation for EPR where steel or concrete poles would otherwise require mitigation measures to be applied.

7. ELECTRODES AnD COUnTERPOISE EARTHInG

Reducing the resistance to remote earth at a structure by providing a low impedance path to earth for faults will assist in ensuring reliable protection operation for earth fault conditions. Good low resistance to ground achieves low tower footing resistance (TFR). Generally, earthing to the foundations or pole root and butt plate or OHEW achieves an adequate reduction in the TFR for protection to operate. Where this is not sufficient, supplementary electrodes or counterpoise earthing should be considered and, when adopted, these should be directly connected to the structure.

Concrete is hygroscopic and hence attracts moisture. A concrete foundation in soil behaves as a semiconducting medium with a resistivity typically of 30 Ω-m. The connection from the support structure to the concrete reinforcement should be made through a direct clamp or welded coupling. No reliance should be given to a fortuitous connection. Care should be taken to prevent d.c. currents that result from the rectification of any a.c. current at the steel concrete interface from causing corrosion of the reinforcement A threshold potential of 60 V d.c. exists below which no corrosion will effectively occur. The design should be such as to ensure that this threshold is seldom exceeded.

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Galvanic corrosion must be considered in the choice of materials, the jointing technique, and equipment that is interconnected. However, it should be noted that concrete reinforcement has a similar potential electrolytic voltage to copper and therefore can be connected.

The suitability of connections to other earth networks should be assessed before the connection is made. Unsuitable connections can result in a rapid loss of the buried earthing conductor. Installations close to earth networks with cathodic protection should similarly be assessed.

Supplementary earth electrodes, where fitted, should be of an appropriate length to take advantage of low resistance soil layers.

Freezing and seasonal variations in ground moisture levels may affect the resistivity of the first 2 m of soil typically, requiring electrodes to be installed to a depth of 4 m. The most effective separation between driven rods to ensure maximum combined conductivity should be at least equal to the length of the rods.

In high resistivity soils or where resistance to driving rods is encountered, the electrode can be installed in an augured hole backfilled with bentonite slurry or similar product.

Counterpoise earths and connections to the structure should be sufficiently deep to avoid them being accidently damaged. Burial to a depth of 300 mm or more is adequate. By running these counterpoise earths parallel to the transmission line route, the influence on other land users is minimised, with the highest earth fault voltages remaining contained within the transmission line corridor.

Typically, to optimise the design and eliminate single point failures, the copper electrodes are positioned symmetrically either side of the support structure. Flat 25 mm by 5 mm copper conductors are generally used for the counterpoise earth for ease of jointing and service life. The support structure acts as the interconnection between the various counterpoise earths.

7.7 OVERHEAD EARTH WIRE

Transmission lines may have one or more overhead earth wires (OHEWs) suspended above the phase conductors, reducing the risk of being struck by lightning. A shield angle of 25° often reduces the risk sufficiently, though this may be reduced to a shield angle of 20° for critical lines where the normal risk of shielding failure cannot be tolerated.

The OHEWs start at the substation, are directly connected to the substation earth mat and are typically suspended over at least the first 1 km out from the substation.

Tower footing resistances of poles or towers should be below 20 Ω for the section of OHEW within 1 km of the substation to prevent back-flash steep fronted wavefronts being imposed on the substation. See section 7.11.1.

OHEWs also form an alternative earth return path to the substation. OHEWs are connected to the poles or towers either via the suspension shackles or a bonding conductor. See section 7.3.1.

A 7/2.25 mm annealed AAC jumper conductor is sufficient for the fault energy, lightning performance, and conductor movement that a jumper conductor may typically be subjected to. An insulator may be fitted where a jumper conductor is used to limit current flow through the alternative suspension shackle path to earth. A single disc insulator with 300 mm electrical creepage is adequate.

The OHEW should be adequate for conducting both earth fault currents and lightning. In general, they should be capable of conducting the majority (75%) of the highest possible fault current


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without failing, and for a period in excess of the backup protection time, such as the circuit breaker failed protection time, followed by an auto reclosing event. See section 7.10.

To prevent damage by a lightning strike, the OHEW should have individual strands nominally greater than 2.0 mm diameter.

The performance of the OHEW in conducting the maximum fault current depends on the inductance (mutual coupling) of the conductor and to a lesser extent on its resistance. The OHEW should therefore be located close to the phase conductors. The requirement for a specific shielding angle between the OHEW and the phase conductors usually dictates how close the OHEW can be placed to the phase conductors. The use of two OHEWs reduces both the resistance and the inductance of the OHEWs while maintaining the shield angle.

The sag characteristics of the OHEW conductor should be selected to be equal or less than the phase conductors to prevent phase/OHEW clashing.

7. LIGHTnInG SURGE ARRESTERS

Transmission lightning arresters are installed to reduce line outages and thereby improve transmission line performance. They enhance the effectiveness of OHEWs and assist in eliminating back-flashovers and flashovers across the line insulation. Surge arresters are usually employed where poor ground conditions are encountered that otherwise make it difficult to achieve low tower footing resistances.

Arresters operate rapidly when high voltages occur on the conductor, conducting these high voltage currents to the earthed structure. By this action they limit the voltage across the line insulation to less than its critical flashover voltage, preventing an uncontrolled discharge over the insulation. As a result, lightning strikes do not operate the protection and the transmission line remains in service.

The arrester characteristics (for either gapped or gapless arresters) should be matched to the insulation withstand voltage and the transmission line operating characteristics. This is to ensure that the arrester does not operate prematurely, and only when lightning over-voltages occur on the transmission line. Transmission line arresters should be selected so that they do not operate for a fault at the substation or on another transmission line. Should they operate during switching operations, or for voltage transients, or power system over-voltages, an increased frequency of earth faults would be transferred to the line structures. The consequential EPR on these structures may not be acceptable and it may also cause arresters to prematurely fail. Transmission line arresters do not have the capacity for frequent operations as required from substation lightning arresters.

Line arresters should have sufficient capacity for the energy transfer that occurs when they operate, which may be a limitation for structures with low TFR. Gapless arresters fitted with a disconnector device that isolates the arrester if it fails, allows failed units to be identified. Failed gapped arresters are more difficult to locate and their condition should be regularly monitored. The gap should be selected to prevent conduction under normal line operating conditions after the unit has failed.

The device’s mechanical mountings, flexible connections and failed unit disconnector device should be designed to achieve the required levels of reliability assumed for the line in the EPR assessment.

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7.9 GUY WIRE InSULATORS

It is often desirable to install insulators in transmission pole guys.

Currents may flow to earth in an uninsulated guy wire leading to corrosion on the fittings and reduced soil adhesion to the buried fixings. These issues need to be considered and adequate mechanical safety factors applied to the design of the guy wire fittings. Insulators should prevent these earth currents.

Guy wires need to be taken into account when assessing EPR as uninsulated guy wires can conduct earth fault currents beyond the area of the poles. Similarly, line maintenance practices need to address the risks to ground staff from exposed guy wires and the associated transferred EPR. Insulators on the guys should prevent the potential exposure.

Insulators where fitted, should be selected to minimise corrosion to fittings that otherwise may reduce the integrity of the guy system, Consequences of transferred EPR and risks to line workers from exposed guy wires should also be considered. For conductive structures, a nominal 28 kV insulator rated for the ultimate tensile strength of the guy system should be sufficient. For non-conductive wood poles, the guy insulator should be similar to the line insulator to prevent the possibility of the guy acting as the earth path during an earth fault. The guy insulator should also be rated to the ultimate tensile strength of the guy system.

Insulators should be located so that line workers are not exposed to hazardous potential differences in the event of an earth fault. Typically, guy insulators should be located at high level on the guys, with the earthed bottom sections beyond the reach of the line worker both while climbing the pole and working on the line.

In some cases an insulated tube may be installed on the lowest section closest to the ground to prevent rodents climbing the guys. Such a measure will also prevent inadvertent contact of the guy wire by the ground crew.

7.10 CLEARAnCE OF EARTH FAULTS

Transmission lines are fitted with a variety of high performance relays designed to detect fault currents flowing to earth. The design for the earthing of the transmission line must ensure the correct operation of these protection relays to detect the fault. This requirement must be achieved for the range of different network configurations, prospective fault currents and types of faults that may apply.

The adoption of solid state protection equipment provides exceptional performance in ability to detect faults, discriminate between faults, and reliability to initiate fault clearance.

Faults are normally detected by protection equipment at both ends of each circuit. The protection equipment closest to the fault may operate first, or the equipment at both ends may operate at the same time, depending on the zone where the fault occurs and protection settings. If the protection at one end operates first, the assigned circuit breakers should open to disconnect that end of the circuit. The detection of the earth fault is often signalled via a high integrity communication link to the protection at the far end of the circuit. The protection equipment should then open the associated far end circuit breakers to ensure the circuit is isolated and the fault is cleared.

This initial action may be followed by an auto-reclosing sequence, where an attempt is made to re-close the circuit breakers. Where the fault is no longer present, the protection equipment should be


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automatically reset. Where a fault remains, the protection should again operate to clear the fault. Further auto-reclosing should not normally be attempted.

In some locations or for certain network configurations the communication link may not apply. In such cases, the opening of the far end circuit breaker should be dependent on the detection of the fault by the far end protection equipment. The earthing design should take these elements into account.

7.10.1 Earth fault clearance times

Equipment must be rated appropriately to ensure prospective fault currents can be conducted for the duration likely to occur in service.

A range of network configurations should be analysed to determine prospective fault currents at the particular location of interest. Protection performance should be assessed to determine how it will perform with either a plant or system failure. The earthing system should be rated to ensure that normal or single contingency events would not result in the failure of the earthing equipment. If such a failure were to occur, the protection equipment may not operate to clear the fault and dangerous voltages could then remain on conductive structures.

Often the communication link between terminal stations is duplicated so that failure of the communication link can be considered as an abnormal and double contingency event. Provision for communication link failure is then not necessary.

Transmission line structures can be some distance from the source of electrical energy, in which cases the potential fault currents can be significantly reduced by the line impedance. Assessment of the earth fault currents should take this into account.

The protection times that are generally adopted assume zero fault impedance with no impedance between the conductor and the connected conductive structure. Other impedances such as source, line, and tower footing resistance should be allowed for. This approach is appropriate when designing for worst case conditions.

The prospective fault current estimates should include an allowance for future network growth and development. In addition, as the capacity of the earthing equipment may reduce with time, it is normal to apply a margin of safety to allow for a limited reduction in performance.

Often earthing equipment is designed to be adequate for a 3 s fault duration, though this can be reduced to 1 s where protection backup times establish that longer faults need not be considered. It may be established that this can be further reduced through careful consideration of the possible events and the protection performance.

A fault is initially cleared as soon as the relevant circuit breakers are opened. After a short time the auto-reclosing sequence (where installed) closes the circuit breakers; unless the fault has cleared, (e.g. lightning strike), fault currents will recur until the circuit breakers are again open. For transmission lines further auto-reclosing is not generally attempted. Protection settings are generally selected to allow a shorter duration for the auto-reclose tripping of the circuit breaker.

When considering EPR hazards, earth fault currents are present for both of these two periods. The longer of these two periods should be used in the hazard analysis. This covers the worst case as any EPR hazard is removed when the fault is cleared. When determining tower fault frequencies, the two periods, initial and auto-reclose, should be considered as a single event rather than two

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separate faults, as an individual would not generally remain in contact with the conductive structure following the initial EPR event.

When rating plant, it is appropriate to assume heat is not dissipated in the interval between two consecutive fault current periods and therefore the cumulative time for both periods should be used for the duration of the earth fault in the calculation.

Fault currents are extinguished when the arc is quenched in the circuit breaker. This occurs before the circuit breaker is fully open. The fault currents also may be reduced as soon as one of the circuit terminals is isolated from the network with the opening of the first of the circuit breakers. The design has an increased margin of safety by not including an allowance for these factors.

7.11 TOWER FOOTInG RESISTAnCES

Tower footing resistance (TFR) is the resistance that the tower or pole has between the conductive structure and remote earth. In the event of an earth fault, this series resistance applies between the tower and the resistances of the earth’s soil layers. The value of the TFR is dependent on the structure’s earth electrodes including any conductor in contact with earth. Considerable costs may be incurred in constructing an earth electrode network to achieve a low TFR where high resistivity soil conditions occur.

The TFR must be designed to achieve satisfactory earthing of the structure and, where required, control the number of back-flashovers during lightning events.

The TFR shall be sufficiently low to ensure correct operation of protection and interrupting devices. With modern electronic protection, very low measured earth fault power is required to operate the protection. Though a low TFR is preferable, where modern protection is fitted a TFR in excess of 100 Ω may be sufficiently low for the protection to operate satisfactorily.

7.11.1 Back-flashover

In addition to the protection operation requirement, in certain situations a reduced TFR may be required to prevent back-flashover. This should occur where the structure is fitted with an OHEW and is within 1 km of a substation. It should also occur where low transmission line outage rates are a particular requirement.

Following a lightning strike to the OHEW, the tower’s or pole’s voltage can become raised to a very high level unless the TFR is low. This high voltage may exceed the insulation level of the line and result in a flashover across the line insulation from the structure to one or more phase conductors. This back-flashover causes the circuit to trip and a steep voltage wavefront to be imposed on the phase conductors.

OHEWs may be fitted for, typically, 1 km from the substation to shield the phase conductors from a direct lightning strike. Steep voltage wavefronts are also created by back-flashovers resulting from lightning strikes and, if these back-flashovers occur close to the substation, severe steep voltage wavefronts may enter the substation and risk causing failure of equipment. Substation equipment insulation should be protected from these steep voltage wavefronts and hence from potentially consequential catastrophic damage. When used in conjunction with low tower footing resistances, the OHEW provides a system where the risk of back-flashovers occurring close to the substation is controlled. To control back-flashovers, a TFR typically less than 20 Ω should apply for each transmission line structure within the shielded portion terminating at the substation. Steep voltage


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wavefronts from lightning strikes would then only originate on conductors beyond the shielded region and would be sufficiently attenuated before reaching the substation to be of concern.

Back-flashovers will often occur for a section of line comprising the adjacent structures closest to the initial incident, though this is considered as a single event. A back-flashover will cause the transmission line protection to trip and an outage to occur. Outages may need to be minimised on critical lines, or double circuit outages (where two circuits are on a single structure) may need to be minimised, or a particular design outage rate for a line may need to be achieved. In each of these cases, the maximum acceptable TFR should be calculated and the proportion of lightning strikes that will result in back-flashover determined. As this is an average performance criteria for the transmission line, some groups of structures can be allowed to have higher TFRs. To limit incidences of back-flashovers, this may require an average TFR of 10 Ω.

7.11. Relationship to EPR

The TFR affects the EPR at and near the affected support structure and the resulting touch voltage that an individual would potentially be exposed to during an earth fault. It also affects the extent of hazardous step voltages around the affected structure.

Where a deterministic EPR assessment is followed, the TFR should be shown to be appropriate to limit touch and step voltages to acceptable levels.

Where a probabilistic EPR assessment is undertaken, the TFR should be shown to achieve an acceptable probability of exposure to hazardous voltages. Where this is exceeded, mitigation measures should be evaluated to reduce the probability. It should be noted that work to reduce the TFR by installing a more extensive earth electrode network is likely to increase the area around the structure where hazardous step and transfer voltages apply and may therefore be counter productive, resulting in an increased probability of exposure to hazardous voltages.

Wood poles are effectively non conductive and the requirements of TFR do not apply except where a conductive down lead is fitted.

7.11. Periodic measurement of tower footing resistance

Tower footing resistance measurement must be undertaken periodically.

Where the transmission structures are in rural locations the frequency of inspection is usually dictated by the need for protection and disconnection equipment to operate satisfactorily. Typically this can be achieved with measurements carried out at regular intervals of a representative sample to establish that an adequate proportion of line earth electrodes are operational.

In urban locations or where major farm buildings are within 30 m of a transmission structure, the frequency may be increased. The interval depends on a number of factors. With properly designed earthing the electrodes do not deteriorate rapidly and the earthing performance is dependent on multiple paths that are not critical to maintaining earthing performance in the event of loss of any particular element. By adopting an increased frequency of measurement, early detection of any structure earthing deterioration and reduced performance is possible. The frequency of measurement is dependent on the criticality of the tower footing resistance. Hence, for most locations, as the earth fault frequency is relatively low, a 15 – 20 year interval of inspection and measurement may be acceptable. For locations close to substations where equipment could

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be damaged, or for lines where back-flashover prevention is critical, an 8 – 10 year interval of inspection and measurement may be desirable.

7.11. Record of earth network

A record should be made of the buried earth network.

The conductor type, the depth of the conductor, the electrode length, the type of tees and the positions of conductors, tees and electrodes should all be recorded on a site plan for the structure. Site plans should show the orientation of the transmission line, have a scale included and a compass position showing the north reference.

7.11. Measurement of tower footing resistance

Tower footings should be tested with proven instrumentation and by operators trained in their use.

Typically, a suitable instrument should be able to measure over the range 0.01 Ω to 1999 Ω and achieve an accuracy within 10%. A suitable test method is the Wenner test arrangement. The current spike should have a 70 m lead as a minimum, the potential spike a 50 m lead and two earth spikes should be applied. Earth spikes with a length of approximately 400 mm should be adequate for most measurements. The instrument should have a self-diagnostic check that registers when earth spike resistance is too high. During the test, values must be recorded for the potential spike at three or more distances from the structure. The results must be correlated on site, so that any significant disparity between tests can be checked, and where appropriate selected tests can be repeated.

The OHEW need not be disconnected where the measurement is to confirm that the earthing system performance is adequate from a protection point of view. The OHEW should however be isolated from the structure prior to testing or alternative measurement techniques adopted when a low TFR is required. Generally this should be limited to structures requiring a low rate of back-flashover or where specific EPR issues need to be assessed.

Alternative parallel earth paths will influence the measurement and so, where non-electric wire fencing or similar is close to the structure, the test connections need to be run out perpendicular to this to minimise the influence of such earth paths on the measurement. The test leads should also be run perpendicular to the line to avoid interference from the line. Although both of these are preferable, particularly the first, this is not always physically possible and in many cases, the test leads have to be run underneath the line.

7.1 EPR ASSESSMEnT

A deterministic approach as described in section 3B may be adopted if a structure has a high incidence of earth fault or other abnormal circumstances prevail.

Transmission line earth faults however are rare events, occurring for an extremely short period of time but during which dangerous voltages may be present. These characteristics are particularly appropriate for a probabilistic method of assessment as described in section 3A and therefore this form of assessment should generally be used.


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Generic type EPR studies may be undertaken for particular situations, such as for particular categories of land use, to determine a broad level of risk associated with these particular categories. Where an EPR assessment has been undertaken for a particular category of land use, this may be applied to other categories of land use with similar levels of occupancy and EPR characteristics. The probabilistic calculation assumes normal patterns of land use, and this should be reflected in the basic generic type EPR studies undertaken.

The probabilistic approach uses typical or average data. To achieve a satisfactory margin of safety, relevant parameters are applied that would rarely be exceeded. As a number of parameters are involved, the separate margins accumulate making it extremely improbable that any specific event would incur a greater risk than calculated.

Rural locations away from roads should typically not require an EPR assessment because of their very low levels of occupancy, the low frequency of earth faults, and their short durations. An EPR assessment should be undertaken where this does not apply, including where buildings are close to the structure or intensive farming practices such as vineyards are being adopted.

As wood poles are effectively non conductive if they do not have a conductive downlead, they should not require an EPR assessment.

7.1.1 EPR earth fault duration

Where there is adequate recorded data of clearance times for a particular transmission line, this may be used to determine a time that is not exceeded for more than 10% of earth faults.

Alternatively, protection studies should be used to establish clearance times based on anticipated normal protection and circuit breaker performance where this is likely to be achieved in 90% of incidences. Protection systems and circuit breakers used in transmission lines have a very low incidence of failing to operate, significantly less than 5%. Because of this low probability, backup protection times should not typically be used in EPR assessments.

Generally, where duplicate protection is fitted and dual communication links are used, 0.1 s clearance times should be achieved. On lines where there is no reliable communication link and detection by the far end protection is required to clear faults, clearance times of 0.15 s may be more appropriate although they may be exceeded for structures close to the line end substations where Zone 2 clearing times apply. In the limited areas where lines are not fitted with fast acting high integrity protection, fault clearing times may be longer in which case the implications of protection equipment failures should also be considered.

7.1. EPR fault current

A prospective maximum fault current should be calculated for each structure.

As the majority of earth faults are single phase to ground, this is typically used as the fault criterion with zero fault impedance. Each fault current should be calculated assuming feeds from both ends of the transmission line, and applying the appropriate source, line and tower footing impedances.

As OHEWs connect all structures together, structures on either side of the faulted structure contribute to reducing the fault current. Typically, a reduction of 80% is achieved in practice and this reduction can be assumed in calculating the prospective fault current at a particular structure.

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7.1. Region of EPR hazard

For generic type studies, the following should be assumed:

(a) The region around the base of a structure needs to be of sufficient size to ensure identification of prospective hazardous step and touch potentials during earth faults;

(b) A 500 Ω-m soil resistivity in accordance with curve UD2 of BS EN 50341 should be assumed for calculation of the contact impedance with the ground when calculating the foot to ground additional impedance R2;

(c) A series impedance of 4,000 Ω should be assumed for footwear in step calculations, (i.e. 2,000 Ω per shoe as per Appendix A1 of this guide and BS EN 50341) or 1,000 Ω for footwear in touch calculations except where 20% of the local population is known to not wear any footwear.

(d) Touch and step voltage limits must be based on fibrillation current curve c2 from IEC 60479-1 as detailed in this guide and as per BS EN 50341. The derivation of the voltage limits must follow the methodology detailed in this guide (see section 3.5 and Appendix A of this guide).3.5 and Appendix A of this guide). of this guide).). This methodology is also detailed in BS EN 50341 for touch voltages.

A generic study can be adopted for specific sites where a similar degree of exposure is expected, and where a similar region of EPR hazard is likely, and where the soil resistivity data is not significantly above 500 Ω-m.

Soil resistivity measurements must be taken for the site. In non-critical locations a homogeneous soil with uniform resistivity should be adequate for the assessment. In critical urban locations the assessment may justify greater accuracy with the resistivity split into two layers where this is considered to be more representative of soil resistivity conditions. With the complexity of two layer calculation and the limited difference that will result in the hazard area around the structure, this will be only required rarely, restricted to locations with high levels of occupancy.

For specific situations beyond the scope of a generic study, the assessment should be based on actual soil resistivity site data.

Touch and step voltages around the structure should be assessed to determine their likelihood of being hazardous. The fibrillation current curve c2 from IEC 60479-1 should be used to determine levels of voltage that, if exceeded, cannot be tolerated. Voltage less than the maximum tolerable value reflect a level that can be tolerated by the general population where there is a minimal risk of ventricular fibrillation, and that is applicable to relatively rare short duration events such as earth faults on transmission lines.

For step voltages, a person must be assumed to be at full stride with feet one metre apart. They should be assumed to be walking towards the structure perpendicular to the ground voltage gradient contours. This gives the worst case condition for the step voltages, which occurs at a right angle to the EPR contours around the structure at full stride with both feet in contact with the ground.

For touch voltages, a person must be assumed to be standing on the ground one metre away, touching the exposed surface of the conductive structure. Left hand to left foot body impedance parameters should be applied.

The region where touch and step voltages exceed safe exposure limits is hazardous.

Hazardous touch voltages caused by any transferred voltages should be identified. This includes conductive objects that can be touched and can be hazardous where they form a continuous


1

conductive path to a location some distance away. This may provide a hazardous potential by either transferring a voltage away from the structure, or by introducing an earth reference to the structure. Mitigation measures are very effective in removing this by providing an insulated section or air gap in the conductive path.

This also includes shorter conductive objects where these are close to the structure and typically perpendicular to the EPR gradient contours, where the object can be touched and can be hazardous. A high resistivity surface around the object can be an effective mitigation technique, (e.g. bark or asphalt around a large metal kiosk).

The regions where transfer touch voltages exceed safe exposure limits and that remain potentially hazardous following completion of the mitigation measures must be identified. The extent of the touch, step and transfer regions should be used to calculate the exposure factor Ef for the structure, described in section 3.1.3 of this guide.

7.1. EPR earth fault frequency

Transmission line earth faults are infrequent and there is unlikely to be data related to a particular structure. Typical or general data should be used for structures on the particular transmission line or transmission lines derived from lines having similar characteristics including operating voltage.

Structures that have an unusually high frequency of earth faults should be investigated and the cause of the high incident rate rectified to achieve an acceptable risk profile for the site.

Transmission lines should not operate beyond the characteristics for which they are designed, to prevent increasing earth fault events.

Transmission lines should be carefully maintained and defective equipment replaced to maintain the required low levels of earth fault frequency on transmission line structures, and to minimise those caused by plant failure.

Structures fitted with OHEWs will be exposed to fault currents when structures either side have an earth fault. This may increase the earth fault frequency, with up to three structures either side being included.

The calculated earth fault frequency Ff should be used to calculate the probability of an event Pe (see section 3.1.3).

7.1. EPR mitigation

The EPR hazard assessment should identify regions where the level of occupancy requires the hazards to be mitigated.

Where the initial assessment indicates the risk to be low or intermediate (see section 3), then this should be further minimised where reasonable to do so. Typically, mitigation for a tower of $5,000 for low risk and $25,000 (2009 values) for towers with an intermediate risk should be appropriate for urban locations. This expenditure is appropriate if it mitigates the risk and achieves a significant reduction in the probability of exposure to hazardous voltages.

Where the probability of exposure from hazardous EPR needs to be reduced or where the costs of further improvement are to be assessed, sections 2.12 and 4 identify the hazard mitigation measures that should be considered.

1


Improvements in earth fault clearance times reduce the severity of the hazard as well as the likelihood of exposure. For transmission lines, the risk is consequentially reduced and the improvement is seen for the entire transmission line. This, typically, would be by adoption of high performance and reliable protection schemes or enhanced communication.

The provision of physical barriers, non-metallic fences, vegetation/landscaping and signage are designed to deter frequent exposure, limiting the occasions when an individual would be in direct contact with the structure while standing on the ground. Alternatively, a 50 mm thick asphalt pad or a non-conductive covering or coating on the structure, interposes an insulating layer between the person and the structure or ground. Such layers minimise the potential of exposure during an earth fault from touching a structure and step voltage close to a structure.

The locating of seats, bus stops and public facilities close to a structure should be avoided (by appropriate structure siting) to reduce occasions where the public is likely to remain for long periods and congregate close to a structure.

The erection of an OHEW provides a parallel return path for the fault currents. The diversion of a major portion of the fault current through the OHEW reduces the fault current through specific structures, which also reduces the resulting EPRs. However, the frequency of fault currents passing through the structures on a line where an OHEW exists will increase. The reduction achieved in the EPR is more pronounced for low resistivity soils but the improvements may be relatively limited for high resistivity soils. The assessment for installing an OHEW should consider the reduced EPR voltage levels countered with their increased frequency. Resonant earthing achieves a reduction in fault current to levels that are non hazardous but may not be cost-effective or practical on transmission circuits. However, such a system does have the benefit of providing mitigation for the district or region where resonant earthing is provided.

Reduction of structure TFR by the use of pole butt plates, counterpoise earthing and low resistivity backfill lowers the EPR by providing a low impedance path to earth for fault currents. However, as the fault current to be dissipated increases, there may be little effect on EPR, with only exceptionally low resistivity soils achieving sufficient reduction to allow the step and touch voltages to be considered not hazardous. Rather it may extend the area over which hazardous voltages occur and hence the probability of exposure. The benefits may be limited to a reduction in probability of exposure gained from lower transfer voltages, some of which will be below the level where they need to be considered.

Grading rings reduce the potential difference that a person is exposed to, creating an ‘equipotential’ area around a structure and are particularly appropriate for localised touch voltage concerns. The effectiveness of grading rings is reduced for high resistivity soils. Where further reduction in voltage is required, multiple concentric rings at increasing depths may be required. Like the reduction of structure TFR, grading rings increase the probability of exposure as they tend to extend the area over which hazardous voltages and transfer voltages occur, which may be more consequential.

The area where transfer voltages could be potentially hazardous to a person should generally be minimised. For conductors located close to a structure, typically this is achieved by the removal of the metallic conductor, reducing the continuous length of the conductor, inserting a section of high dielectric strength material or improving its insulation characteristics to reduce susceptibility to EPR. This may be in addition to or in place of a reduction in EPR as a result of a reduction in the fault current.


1

Through applying a probabilistic assessment, improbable scenarios can be discounted and a typical solution found for the particular type of conductor and its transfer voltage characteristics. Generally, this can be then applied for other locations where that type of conductor is encountered.

Earth faults on transmission lines are both rare and of exceedingly short durations. Transfer voltages should be mitigated to prevent unacceptable levels of exposure of hazardous voltages to an individual. It is not generally cost-effective to exceed this and achieve an outcome where plant and equipment would not potentially be damaged. Processes and procedures should be implemented to minimise hazards to those employed on this type of equipment commensurate with any remaining risk.

Typically it is more cost-effective to repair the equipment where it is established that the equipment failure was caused by an earth fault event than to remove the possibility of it being damaged, while ensuring plant providing important services are not installed close to transmission line structures.

7.1. Rural area EPR assessment

In locations remote from urban centres and roads, the occasions are generally limited where a member of the public is either in contact with, or adjacent to, a line support structure. The incidences of transmission line earth faults are similarly rare and of such short duration, that there should be negligible risk of a person being present during an earth fault. Hence the risks, in a typical rural area, of injury from an earth fault on a transmission line can generally be ignored.

To ensure this is the case, practices should be avoided that may either increase the likelihood of an earth fault at a structure or increase the frequency of visits to the area where a significant EPR may occur. The areas that should be considered are tree management, burn-off control measures, pollution controls, irrigation practices, fencing, farm building location and cultivation where crops require hand pruning or harvesting. General guidance for these is given below. Where rural activities cannot be avoided, an EPR assessment must be undertaken as the risks may no longer be negligible.

The Electricity (Hazards from Trees) Regulations detail the issues with trees close to transmission lines. By following these regulations, the trees should not cause an increase in the rate of earth faults and an EPR assessment should not be required.

Burn-offs, significant sources of emissions of particulates, dust, hot gas or corrosive particles, and blasting, should either be managed or restricted as they potentially increase incidences of earth fault. Established practices should be implemented and then an EPR assessment should not be required.

Guidelines should be followed on irrigators close to transmission lines. These guidelines should address the issues that could potentially increase the frequency of earth faults, managing movement, positioning of irrigators and use of upwards spray jets. The need for fitting of bird spikes to transmission structures should be considered where irrigators may enhance bird activity and insulator failures. The adoption of such guidelines ensures that the risk of exposure to a hazardous EPR is not increased by irrigation.

Breaks in the fencing or wooden sections should be installed in stock wire fencing where these may transfer a potentially hazardous EPR beyond the immediate area of the transmission support structure. Electrified fencing should not need to be considered. Typically, where a fence runs close to a transmission line structure, a gap or a break in the wire fence 30 m either side of the

1


structure should minimise the transfer. This consequently removes the risk of exposure beyond the immediate vicinity around the structure from voltages transferred onto fencing. A further EPR assessment should not then be required.

By ensuring a reasonable distance is maintained from the transmission support structure for farm buildings that are frequently visited, their influence should be minimal and the buildings should not significantly increase the probability of exposure and consequential need for an EPR assessment.

Crops that require hand pruning or harvesting should typically be avoided around a transmission structure. The activity may significantly increase exposure of those undertaking the work to potentially hazardous EPR in the event of an earth fault. Consequently an EPR assessment should be undertaken and mitigation measures established should these activities occur close to the transmission support structure.

7.1 LIGHTnInG

Lightning strikes are generally the primary cause of earth faults on transmission lines. A lightning strike is characterised by high peak current and with an exceptionally steep rate of increase. The median peak current of the lightning strike is approximately 30 kA with a duration measured in microseconds.

Transmission line earthing systems should safely direct lightning surge currents to earth, and thereby prevent prolonged transmission line outages and damage to both the conducting structure and the substation equipment.

New Zealand has a relatively low incidence of lightning with few populated regions exceeding a ground flash density of 0.2 flashes/km2/year. Consequently, transmission lines in this country do not require the same provisions for lightning strikes that are necessary internationally.

Where provided, the OHEW is positioned to intercept the lightning strike and shield the phase conductors from direct strikes. Lightning discharge current passes along the OHEW and down the connected structures. Where an OHEW is not installed, the upper conductor is likely to be struck but shields the lower conductors.

A flashover of the insulation may be expected from a lightning strike when the voltage on the conductor reaches a value close to the insulation wet critical flashover voltage, thus causing an earth fault. This may occur for a small proportion of lightning strikes where the OHEW fails to shield the conductor. It will occur for a large proportion of lightning strikes where an OHEW is not installed. Once a flashover occurs, an earth fault is created when power follow current flows to earth and, though the voltage rapidly diminishes, it may sustain the fault, which then continues as a power system fault.

Transmission line protection should detect a sustained earth fault and isolate the relevant transmission line. The duration of the outage before auto reclosing and re-energising the line should be sufficient to allow the surge energy to be dissipated to earth and prevent a second trip from a single strike. It should be rare for a lightning event not to be cleared in this way.

Lightning arresters when installed provide an active controlled path from a phase conductor to the structure. This should clamp the voltage, preventing a flashover or a back-flashover. Effectively, power follow current does not flow through the surge arresters, eliminating the need for the protection to operate and averting the tripping of a transmission line struck by lightning.


1

The design for a transmission line with an OHEW should take into account the frequency of back-flashover by calculating the percentage of lightning strikes with the capacity to cause a back-flashover. A proportion of the lightning strikes may have sufficient current for this phenomenon to occur and is more likely for structures with a high TFR or with a lower insulation rating. A back-flashover occurs when the current flowing through a tower causes a voltage build up on the structure beyond the withstand level of the insulation. Such phenomena typically causes an earth fault with a flashover between the structure and a phase conductor, and in some instances will cause more than one flashover.

Where two circuits are on a structure the design should take into account the frequency of a double circuit outage and the implications for maintaining the supply, see section 7.11.1.

Where lightning strikes a conductor, substation plant and equipment connected to the conductor need to be protected from the severity of the rate of rise of voltage. Induction and surface corona reduce the steepness of the voltage wavefront as it passes along the transmission line, reducing the risk to equipment connected to the conductor. For this reason, it is advantageous to control back-flashovers close to the substation (see section 7.11.1) and ensure that both of the potential causes of voltage surges originate far enough from the substation so that they are sufficiently attenuated by the time they reach the substation. Back-flashovers close to the substation should be controlled by the installation of OHEWs for a distance out from the substation and by providing low tower footing resistances for each tower on this section of line. Typically, a minimum line length of approximately 1 km from the substation should be adequate.

The current capacity of components should not need to be enhanced to be adequately rated for a lightning event due to the short duration of lightning events. Consideration should, however, be given to the significant mechanical forces that occur where currents are induced between close parallel conductors during the lightning event. Typically, 70 kN fittings are used to secure OHEWs.

7.1 VOLTAGES IMPRESSED OnTO OTHER CIRCUITS OR UTILITIES

As described in section 2.3.3, capacitive coupling causes potentially hazardous voltages to be created on nearby parallel de-energised circuits. This can have safety implications to maintenance workers. This should be considered where transmission lines run parallel for several spans, to circuits on other lines that may be de-energised. This is more significant for a de-energised transmission or distribution circuit in close proximity, particularly where structures can be shared by both energised and de-energised circuits. The design of the installation should identify any conductors likely to be of concern for work safety, because of proximity between circuits so that the need for special safe working procedures is identified.

Magnetic field induction should be considered as described in section 2..4 for conductors that are within the transmission line corridor, are insulated and electrically continuous and run parallel to the transmission line.

During a transmission line fault, the earth fault current will typically be much greater than the nominal operating capacity of the transmission line. Consequently the magnetic field induced voltage that will occur on any parallel conductor during an earth fault will be greater than the steady state induced voltage. The design of the installation should identify conductors that could potentially have hazardous touch voltages present during a transmission line earth fault. As these earth faults are infrequent and last for a very short period typically, a probabilistic assessment

17


should be undertaken for the associated risk as detailed for EPR in section 7.12.

Distribution line utilities are not likely to have the voltage insulation or earthing system capacity able to discharge transmission voltages if a conductor inadvertently came in contact with a transmission line. Where lines cross, distribution lines should be located below transmission lines so that, if a distribution line conductor falls, the transmission voltage will not be transferred onto the distribution line and apply potentially hazardous voltages onto the distribution network.


1

APPEnDIx A VOLTAGE LIMITS(Informative)

Appendix A details the calculation of permissible prospective touch and step voltage limits. These calculations are based on the procedure from Figure 6.

A1 FIBRILLATIOn CURREnT LIMITSA1.1 IEC 079-1

IEC 60479-1 contains a number of body current curves. Curve c2, which corresponds to a 5% probability of fibrillation, is considered by standards such as IEC 6196-1 and BS EN 5041 to present a low risk and may be considered as an acceptable minimum requirement.

Curve c2 is shown in Figure 15. This curve applies to a current path of left hand-to-both-feet.

Figure 15: IEC 60479-1 Curve c2

A1. IEEE 0

According to IEEE Standard 80, the fibrillation current that a human body can tolerate depends on the weight of the person and on the duration of the flow of the current through the body (i.e. on the duration, t, of the earth fault).

19


For public access areas, IEEE Standard 80 assumes a body weight of 50 kg and calculates the acceptable body current as:

seconds) t current, Hz 50 (for A t

0.116 Ib == .......................................................... ( Eq. 1)

For assessing touch and step voltage hazards in the restricted access area inside a station, IEEE 80 Standard uses the following acceptable body current:

seconds) t current, Hz 50 (for A t

0.157 Ib == .......................................................... ( Eq. 2)

The above equations are valid for fault durations, t, between 0.3 and 3 s.

A SHOCk CIRCUITFor touch and step voltage shock situations, parameters that are significant for the step and touch voltage circuits are shown in Figure 16. The parameters are further detailed in the following sections.

Figure 16: Touch and Step Voltage Circuits Parameters

For touch and step voltages, the relevant circuit parameters are:

(a) The body impedance, Zb;

(b) The resistance of shoes, Zss or Zst;

(c) The contact resistance of feet-to-soil, Zc.

Gloves resistance may also be considered. However, this parameter only applies to electrical workers and since gloves are only used for certain operations, this parameter is usually ignored in New Zealand.


10

A.1 BODY IMPEDAnCE

The body impedance depends on the voltage across the human body. Body impedance also depends on the current path through the body. For example, the hand-to-feet impedance is lower than the hand-to-hand impedance.

The European approach for calculating step and touch voltage limits is based on IEC 60479-1; it uses body impedances that depend on the voltage across the body and considers the current path through the body. The probability distribution of the body impedance is also considered.

The IEEE 80 approach uses a fixed body impedance of 1,000 Ω and distinguishes between two human body weights, 50 kg and 70 kg. The current path through the body is not considered.

A. RESISTAnCE OF SHOES

Footwear provides additional series resistance in the shock circuit. Resistance of shoes varies greatly depending on the type of shoe and on whether the shoe is dry or wet. In addition to having a resistance, a shoe will also exhibit a flashover voltage. The ability of a shoe to withstand voltage depends on the type of shoe, on the amount of wear and on whether the shoe is dry or wet.

Shoe resistance may vary from 500 Ω to 3,000 kΩ while the withstand voltage may vary between 500 V up to 20 kV. Low withstand voltage is typically associated with wet shoes.

Various standards allow for shoe resistance as follows:

(a) BS 7354:1990 allows a shoe resistance of 4,000 Ω to be used for substation earthing design;

(b) BS EN 50341-1 uses a shoe resistance of 2,000 Ω for calculating touch voltage limits for locations where people are expected to be wearing shoes;

(c) ITU K33 allows the use of the following shoes resistances for calculating the voltage limits:

Type and state of shoesShoe Resistance (kΩ)

Leather sole Elastomer sole

Dry shoes 3,000 2,000

Wet or damp shoes, hard soil 5 30

Wet or damp shoes, loose soil 0.25 3

The type and distribution of footwear is likely to vary greatly around New Zealand. In addition, a culture of going bare-foot exists, which further complicates the issue. Because of the wide range of shoe resistances, it is necessary to select a relatively low value that can be used for determining voltage limits.

For the purpose of this guide, a value of 2,000 Ω is recommended for all normal locations. This value has been selected because it is the lowest value currently published in a standard.

There is only limited information on withstand voltage associated with footwear. BS 7354

131


acknowledges that the withstand voltage of worn footwear has not been well researched. This standard recommends a limiting value of 5 kV for touch and step voltages. However, since there are two shoes in series in a step shock circuit, a value of 10 kV has been recommended in this guide for step voltages.

When considering the effect of shoe resistances, the touch voltage circuit will include the resistance of two shoes in parallel while the step voltage circuit will include the resistance of two shoes in series.

A2.3 ContACtresistAnCeoffeet-to-soil

The contact resistances between the feet and the soil may appreciably increase the resistance of the shock circuit especially if a thin layer of high resistivity material is used on the surface.

For soil with a surface resistivity, , the contact resistance is calculated as:

For step voltages,

Zcs = 6ρs ...................................................................( Eq. 3)

For touch voltages,

Zct = 1.5ρs ...................................................................( Eq. 4)

As described in section 4.7, thin layers of high resistivity material can be used to reduce the current flowing through the human body. For a thin layer of high resistivity material on top of the soil, a derating factor, Cs is required to account for the difference in magnitude between the resistivity of the thin layer (ρl) and the resistivity of the underlying soil ( ), and also to account for the thickness of the layer (hl).

............................................................ (Eq. 5)

The contact resistance is then calculated as:

For step voltages,

lscs C 6 Z ρ= ................................................................... (Eq. 6)

For touch voltages,

lsct C 1.5 Z ρ= ................................................................... (Eq. 7)


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A TOUCH VOLTAGE CIRCUITA typical touch voltage shock circuit for the situation depicted in Figure 16 is shown in Figure 17.

Figure 17: Touch Voltage Shock Circuit

The prospective touch voltage, VTP, may be determined by the acceptable body current, Ib multiplied by the sum of the various impedances considered in the shock circuit.

........................................................... (Eq. 8)

For touch voltages, a current path of left hand to feet is assumed. According to Table 12 of IEC 60479-1:2005, F=1 for touch voltages.

sct 1.5 Z ρ= .......................................................... (Eq. 9)

If Z1s is the resistance of one shoe, then:

2

Z Z 1s

st = .........................................................(Eq. 10)

................................................... (Eq. 11)

Prospective touch voltage limits can be calculated by substituting the relevant body impedances, soil resistivities and the IEC 60479-1 or IEEE Standard 80 body current limits.

1


Equation 11 can be re-written as follows:

( )sstbbbTP 1.5 Z I Z I V ρ++= ....................................................(Eq. 12)

( )ctstbbbTP Z Z I Z I V ++= or

€

VTP = VTL + lb Zst +Zct( )

.........................................................( Eq. 13)

The term Ib Zb is the loaded touch voltage, VTL, and values of loaded permissible touch voltages for normal and special locations are shown in Figure 18.

Figure 18: Effective (Loaded) Permissible Touch Voltages

NOTE: The difficulty in calculating prospective touch voltage limits based on the IEC 60479-1 standard is that the human body impedances are dependent on the voltage across the body. To calculate the correct touch voltage limit corresponding to a tolerable body current limit an iterative process is required making the calculation complicated. Because of this, the loaded touch voltage curve in Figure 18 has been produced to simplify the calculation of the tolerable prospective touch voltages. The effective touch voltage curve has been derived based on curve c2 of Figure 15 and on the voltage dependent 50% body impedances from IEC 60479-1:2005 for water-wet conditions and large contact surface areas (10,000 mm2).

To calculate the permissible touch voltage limit for a particular fault duration, equation 13 can be used.


1

The calculations of permissible touch voltage limits are shown in the following examples:

Example 1 – using IEC 60479-1

(a) The fault duration is 0.5 s;

(b) The soil resistivity is 200 Ω-m;

(c) Shoes with a resistance of 2,000 Ω are considered;

(d) The situation is a normal location;

(e) The permissible body current for 0.5 s, read from curve c2 in Figure 15, is 0.2 A;

(f) The loaded touch voltage is determined as 200 V from Figure 18.

Therefore,

Ib = 0.2 A From Figure 15 using curve c2 and 0.5 s.

VTL = Ib Zb = 200 V From Figure 18 for 0.5 s.

Zst = 2,000/2 = 1,000 Ω For two shoes in parallel.

1.5 = 300 Ω From equation 9.

The prospective touch voltage limit is then:

VTP = 200 + 0.2(1,000 + 300) = 460 V

This limit is similar to the value that can be read from the 200 Ω-m curve of Figure 9.

Example – using IEEE Standard 80

(a) The fault duration is 0.5 s;


(c) Shoes with a resistance of 2,000 Ω are considered;

(d) The situation is a public access area i.e. 50 kg body weight.

Ib 0.116/0.5 0.164 A

Zb = 1,000 Ω

Zst = 2,000/2 = 1,000 Ω

1.5 = 300 Ω

VTP = 0.16(1,000 + 1,000 + 300) = 377 V

NOTE: The calculation of touch voltages is more complicated where a thin layer such as asphalt or crushed rock is concerned and involves the inclusion of the term CS (see equations 5, 6 and 7).

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A STEP VOLTAGE CIRCUITA typical step voltage shock circuit for the situation depicted in Figure 16 is shown in Figure 19.

Figure 19: Step Voltage Shock Circuit

The prospective step voltage, VSP, for a fault duration, t, may be determined by the acceptable body current, Ib/F, multiplied by the sum of the various impedances considered in the shock circuit. The factor, F, is the heart-current factor as detailed in section 5.9 of IEC 60479-1.

For a foot-to-foot path, the heart-current factor of 0.1 is given in Table 12 of IEC 60479-1:2005.

( )cssbb

SP Z Z Z F

I V ++=

......................................................... (Eq. 14)

scs 6 Z ρ= ........................................................ (Eq. 15)

If Z1s is the resistance of one shoe, then:

1sss Z 2 Z = .........................................................( Eq. 16)

( )csssbb

SP Z Z Z F

I V ++= ........................................................ (Eq. 17)

( )csssb

bb

SP Z Z F

I Z

F

I V ++=

or

( )csssb

SLSP Z Z F

I V V ++=

........................................................ (Eq. 18)

Ib


1

Prospective step voltage limits can be calculated by substituting the relevant body currents, body impedances and soil resistivities as detailed in section A3 for touch voltages. The loaded step voltage curves are given in Figure 20 for water-wet conditions and large contact surface areas (10,000 mm2).

Figure 20: Loaded Permissible Step Voltages

The calculation of a tolerable step voltage limit for a fault duration is shown in the following example. The criteria for the example are:

(a) The fault duration is 1 s;


(c) Bare feet is considered;

(d) The tolerable body current for 1 s is read from curve c2 in Figure 15. This value is 0.08 A;

(e) The loaded step voltage is determined as approximately 1,500 V from Figure 20.

Based on the above criteria, the following are calculated:

Ib = 0.08 A From Figure 15 using curve c2 and 1 s.

Ifoot to foot = 0.8 A Dividing by the heart-current factor, F = 0.1.

VSL = 640 V From Figure 20 for 1 s.

Zst = 0 Ω Bare feet.

6 s = 3,000 Ω From equation 15.

The prospective tolerable step voltage limit from equation 18 is then:

VSP = 640 + 0.8(0 + 3,000) = 3,040 V

A similar value can be read from Figure 10.

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APPEnDIx B

CASE STUDIES

(Informative)

B1 CASE STUDY 1 – DISTRIBUTIOn EARTHInGThis case study, which involves an existing 11 kV transformer mounted on a concrete pole located at a bus stop, illustrates the principles presented in this guide (see Figure 21). For the purposes of this case study, transferred EPR issues have been ignored.

This pole was identified as possibly carrying an EPR risk for people using the bus stop. The bus stop is typically used by people travelling to work and it can therefore be assumed that footwear is worn around the pole.

People would typically be standing on a concrete footpath when touching the pole.

Figure 21: Location of pole mounted transformer


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This case study follows the risk management method as detailed in the flowchart from section .4 and in the steps in section 3A.

Step 1: Basic data

• The prospective earth fault current at the source substation is 7 kA.• The resistance to earth of the 11 kV transformer (including the associated MEN system) was

estimated as 5 Ω.• The resistivity of wet concrete is assumed to be 50 Ω-m. • The earth fault clearing time is 0.5 s.• The earth fault frequency for the line is 5 per year.• The line consists of 200 poles and does not have an overhead earth wire.

Step : Functional requirement

The pole meets the functional requirements.

• All exposed metalwork is bonded.

• The prospective earth fault current is more than twice the feeder pickup setting to ensure the protection will operate.

• No nearby telecommunication asset.

Step : Pole EPR

Using parameters associated with the earth fault current path for an earth fault at the pole, the EPR on the pole was calculated as approximately 4 kV.

The parameters are:

• 2.5 km Dog ACSR between site and source substation.

• 7 kA earth fault level at source substation.

• 2 Ω source substation earth grid resistance.

• 5 Ω site grid resistance.

Step : Prospective tolerable step and touch voltage limits

The touch voltage limit was determined from Figure 9 for a fault clearing time of 0.5 s and for a wet concrete resistivity of 50 Ω-m (footwear included).

The step voltage limit was determined from Figure 10 for a fault clearing time of 0.5 s and for a wet concrete resistivity of 50 Ω-m (footwear excluded).

VT (limit) = 410 V

VS (limit) = 2,150 V

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Step 5: Is EPR ≤ VT(limit) and Vs(limit)?

The EPR on the pole is greater than the step and touch voltage limits.

EPR = 4,000 V > VT (limit) = 410 V

VS (limit) = 2,150 V

Step 6: Calculate actual touch and step voltages

For this case study, the actual step and touch voltage limits were calculated using modelling software.

A plot of touch voltages on the pole is shown in Figure 22.The plot shows that the maximum touch voltage on the pole is calculated to be 2,023 V.

Figure 22: Touch Voltages on the Pole

A plot of step voltages around the pole is shown in Figure 23. The plot shows that the maximum step voltage around the pole is calculated to be approximately 1,900 V.


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Figure 23: Step Voltages Around the Pole

Step7:Areactualtouchandstepvoltages≤V T (limit) and VS (limit)?

Actual touch voltage exceeds the touch voltage limit but the actual maximum step voltage is less than the step voltage limit. Therefore, only touch voltage hazards exist.

Step : Risk assessment

The risk assessment consists of:

(a) Identify the risk by identifying all hazards and extent of hazard zones;

(b) This is achieved by comparing voltage limits with calculated or measured voltages;

(c) Estimate people exposure to the hazards. Carry out sensitivity analysis where required.

The only hazardous components at the pole are the touch voltages onto the concrete pole. The risk can be assessed by calculating the coincidence probability, Pc.

Pc = EFFF

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Where:

yeara in hours of Number

hours) (in yearper exposure of durationTotalE

F=

FF = Average number of hazardous EPR events per year on a pole

The frequency of earth faults for the line with 200 poles is 5 faults per year. Therefore:

0.0252005

FF ==

If, for the purpose of this case study, we assume that the pole is being touched once a day for 5 minutes (i.e. someone leaning against the pole) for five days of the week (i.e. λE = 260 days per year), the total duration of exposure per year will be:

Total duration of exposure = 5 minutes per day × 260 days per year

€

Total duration of exposure per year (in hours) = 5 minutes a day × 260 days per year

60 minutes per hour

= 21.7 hours per year

As there are 8,760 hours in a year, the exposure factor will be:

The coincidence probability is therefore:

Pc = 2.5×10-2 × 2.5×10-3 = 6 × 10-5

Since only one person is typically affected, N = 1 and the equivalent probability is:

Pe = NPc = 1 x 6 × 10-5 = 6 x 10-5

The risk is therefore ‘intermediate’ and should be minimised unless the risk reduction is impractical and the costs are grossly disproportionate to safety gained. A cost benefit analysis should be carried out to determine whether the costs of risk treatment options are disproportionate to the safety gained.

Calculate the present value (PV) of the liability:

VoSL = $10,000,000

Liability per year = 10,000,000 x 6 x 10-5 = $600

PV = $13,000 (assuming an asset lifespan of 50 years and a discount rate of 4%)


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Step 9: Risk treatment options

A number of risk treatment options can be considered. Examples of risk treatment options are:

– Installing an underslung earth wire on the line.– Installing a gradient control conductor and an asphalt layer around the pole.– Installing an insulating barrier around the pole to prevent people from touching the pole.– Replace the concrete pole with a wood pole.

A few of the above risk treatment options are detailed below to illustrate the principles.

Installing an underslung earth wire on the line

A study has shown that an underslung earth wire would reduce the EPR on the pole to 600 V. The resulting touch voltage on the pole would then reduce to approximately 300 V which is below the tolerable touch voltage limit. The cost of this risk treatment option has been determined to be approximately $100 k. Comparing the cost of risk treatment to the present value of the liability indicates that the cost of this risk treatment option is grossly disproportionate to the safety gained.

Installing a gradient control conductor and an asphalt layer around the pole

With a gradient control conductor installed at a distance of one metre around the pole, the touch voltage reduces to 900 V. This touch voltage exceeds the touch voltage limit. However, if asphalt is also installed around the pole, the touch voltage limit increases to 2,000 V with the result that the touch voltage is lower than the limit. The cost of this risk treatment option is $5,000 and is below the present value of the liability. There may be some additional ongoing costs associated with maintenance of the asphalt that should also be considered.

Installing an insulating barrier around the pole to prevent people from touching the pole

An insulating barrier could be installed around the pole to prevent people from being able to touch the pole. Such an insulating barrier could take the form of a wooden enclosure or a fibreglass jacket. The cost of this risk treatment option is $2,000 and is significantly below the present value of the liability. There may be some additional ongoing costs associated with maintenance of the insulating barrier.

Replacement of the concrete pole with a wood pole

By replacing the concrete pole with a wood pole, touch voltage hazards on the pole can be eliminated. If the transformer earthing conductor is insulated from touch, touch voltage hazards associated with the transformer and pole can be completely eliminated. The cost of this risk treatment option is $,500 and is significantly below the present value of the liability.

Additional risk treatment options may be considered as required.

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Clearly, economically viable risk treatment options exist for this case and one of the options should be implemented. The cheapest risk treatment option may not be the best option. Other considerations may dictate which risk treatment option is selected. For example, an underslung earth wire may be the best option if a number of EPR issues exist along the line. Other mitigation options such as the use of Neutral Earthing Resistors (NERs) or Petersen Coils (Ground Fault Neutralisers) may also be considered where additional EPR issues are expected along the line.

The exposure corresponding to the transition from low to intermediate and from intermediate to high may also be calculated as a sensitivity/sanity check. The calculations below show that the exposure would have to be in excess of 40 minutes per week on average for the risk to become high. In this case, it is unlikely that someone would be exposed for so long every week.

€

Maximum exposure for intermediate risk = 8,7601×10−4

2.5 ×10−2

= 35.04 hours per year

= 2,425 seconds per week (40 minutes per week)

For the risk to fall within the low risk category, the exposure for a person would need to be less than 24 seconds per week as shown below. In this case, it appears that the exposure is likely to exceed 24 seconds per week.

€

Maximum exposure for low risk = 8,7601×10-6

2.5 ×10−2

= 21 mintues per year

= 24 seconds per week

The above sensitivity check confirms that an intermediate risk level may be adopted for this case.

The costs and practicality of the selected risk treatment option may be such that there is some residual risk after treatment is applied. This residual risk may be low and therefore acceptable. Alternatively, the residual risk may be in the intermediate category and would require further cost benefit analysis. The cost benefit analysis may be applied using the amount by which the probability of fatality has been reduced to determine whether further risk treatment is required.

Once the design has been completed, the remaining steps in section 3A can be completed.


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B CASE STUDY – HV A.C. SUBSTATIOn

A zone substation is proposed in a commercial/industrial area in a town. The substation will contain two 33/11 kV transformers. The substation is approximately 50 m x 25 m.

The substation will be connected to two 33 kV incomers and three 11 kV feeders. All the lines are overhead.

To manage the risk from EPR events, this guide allows for the use of either the probabilistic approach or the deterministic approach.

The deterministic approach is typically used for fenced substations such as HV transmission substations and distribution zone substations where it is considered that any exposure to calculated body currents above appropriate levels selected from international standards such as IEEE Standard 80, or the IEC 60479-1 is unacceptable.

For this case study, the substation earth grid design has been carried out following the deterministic approach as detailed in the flowchart of Figure 7. However, for transferred voltage issues, both the deterministic and probabilistic approaches have been considered.

Since the substation is located in an urban commercial/industrial area with significant foot traffic in the vicinity of the substation, it was decided to classify the substation as a special location. This is a prudent approach that, for a substation, should not result in significant additional costs for the earth grid.

Basic data

- The 33 kV earth fault current is 3 kA.

- The 11 kV prospective earth fault current is 10 kA.

- The 11 kV lines have Weka conductors.

- The 33 kV and the 11 kV lines do not have overhead earth wires (OHEWs).

- The fault clearing time for an 11 kV off-site earth fault is 0.5 s.

- The fault clearing time for a 33 kV bus earth fault is 0.5 s.

Other basic data have been determined as detailed below.

(a) Soil resistivity

Soil resistivity tests were conducted at the site. When the tests were carried out the soil was very wet. The soil resistivity model shown below was derived from the following measured data:

Layer Resistivity Thickness

1 300 Ω-m 0.0 – 1.0 m

2 80 Ω-m 1.0 m+

Since the soil was wet when the soil resistivity measurements were taken, it can be assumed that the resistivity of the top soil layer is at its minimum value. If the soil had been dry, a sensitivity analysis would be required to investigate effects resulting for a drop in soil resistivity if it were wet. Therefore, a top soil layer of 300 Ω-m has been used to calculate tolerable touch and step voltages on natural ground.

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(b) Realistic 11 kV earth return fault current

The closest equipment where an earth fault could result in significant earth return current is an 11 kV transformer located 200 m from the substation. The transformer is connected to the local MEN system, which is not very large. A simple evaluation of the MEN system has indicated that the impedance of the MEN system is likely to be in the region of 1 Ω or more. Therefore, the impedance at the ‘faulted’ site is ZFaulted site = 1 Ω.

The 11 kV bus impedance at the substation is:

ZSource j(11,000 V/)/10,000 Ω = j0.64 Ω

The impedance of the 11 kV line between the substation and the 11 kV transformer is:

ZLine = (0.24 + j0.4 Ω/km) x 0.2 km = 0.05 + j0.08 Ω

To determine the likely earth grid impedance at the substation, a preliminary earth grid has been set up and the impedance of the preliminary earth grid has been calculated as 1.53 Ω. It is likely that the earth grid will be improved and for the purposes of the earth fault current calculations, an earth grid impedance (ZSource grid) of 1 Ω has been selected since in this case it is a reasonably conservative estimate. The earth fault current calculation may have to be reviewed, if the earth grid impedance changes significantly from 1.0 Ω.

ZSource grid = 1.0 Ω (assumed)

The total fault loop impedance is:

ZTotal = ZSource + ZSource grid + ZLine + ZFaulted site = j0.64 + 1.0 + 0.05 + j0.08 + 1.0 Ω

= 2.05 + j0.72 Ω

|ZTotal| = 2.2 Ω

The 11 kV off-site earth fault current is:

IF-tower (11,000 V/)/2.2 A = 2,890 A

The earth fault currents for the site are summarised as:

Fault Earth Fault LocationProspective Fault

Current (A)

Actual Earth Grid Return

Current (A)

Earth Fault Clearing Time (s)

F1 33 kV bus 3,000 3,000 0.5

F2 11 kV bus 10,000 01 NA

F3 Off-site 11 kV 10,000 2,890 0.5

NOTE 1: Fault current circulates within the earth grid.


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Since the earth fault clearing time is the same for the 33 kV bus earth fault and the 11 kV off-site earth fault, the 33 kV bus earth fault represents the worst case fault for assessing EPR safety issues.

Functional requirements

The substation earthing system will be designed to meet all the functional requirements. This includes the following:

(a) An earth grid will be provided to ensure that the protection operates effectively.

(b) All components that could become live will be bonded to the earth grid.

(c) The reinforcing of the control room floor and transformers pads will be bonded to the earth grid.

(d) The security fence will be bonded to the earth grid.

Prospective tolerable step and touch voltage limits

The EPR safety aspects of this design are based on tolerable step and touch voltage limits for a special location as given in Figure 8 and Figure 10.

The tolerable step and touch voltage limits are calculated as:

Tolerable Limits Touch Voltage (V)

0. sStep Voltage (V)

0. s

300 Ω-m surface (natural ground typical) 284 5,165

5,000 Ω-m surface (100 mm crushed rock layer over natural) 1,260 44,197

15,000 Ω-m surface (50 mm asphalt layer over natural) 2,614 5,1651

NOTE 1: Additional impedance for asphalt over natural ground is not included for step voltage limits because of the relatively low breakdown voltage of asphalt.

Earth grid design process

A basic earth grid was designed by positioning earthing conductors that surround the area covered by the substation equipment and structures. The earthing conductors enclose as much area as practical to help avoid high current densities. The earthing conductors are also laid in a mesh configuration to control step and touch voltages within the switchyard.

For the purpose of this case study, the design of the earth grid was carried out using modelling software. However, earth grids may also be designed using hand calculations. IEEE Standard 80 contains examples of earth grid designs carried out using the equations, tables and graphs presented in the standard. Other publications such as ENA, EG1 and BS 7354 also contain the information to enable hand calculations to be performed. Hand calculations are only recommended for smaller sites with homogeneous soils and without significant nearby underground services. For more complicated sites, computer analysis should be carried out.

The EGVR associated with the basic earth grid was modelled for the worst case earth fault current. The worst case EGVR for the substation was calculated to be approximately 4,600 V. This EGVR

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exceeds the touch voltage limit, but not the step voltage limit. Step voltages are not an issue in this case.

The actual touch voltage associated with the basic earth grid was calculated as shown in Figure 24. As a first check, the EPR safety issues were assessed assuming that the substation is covered in natural soil. The colours represent areas where touch voltages exceed the limit of 284 V on natural soil. The security fence is the outside perimeter line as indicated in Figure 24. To mitigate the touch voltage hazards inside the substation, crushed rock can be used.

Figure 24: Touch Voltages for Basic Earth Grid

Note that in the plot of Figure 24, the touch voltages represented by the colours within the mesh are also an indication of the mesh voltages.

With crushed rock, the touch voltage limit increases to 1,260 V. Figure 25 shows that crushed rock has the effect of mitigating most of the touch voltage inside the switchyard.


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Figure 25: Touch Voltages around Basic Earth Grid with Crushed Rock

To mitigate the remaining touch voltage hazards, the size of the earth grid mesh can be reduced. However, touch voltage hazards will remain onto the outside of the substation security fence.

A risk assessment could be carried out to determine whether the risk associated with the touch voltage hazards onto the outside of the fence is acceptable. If this risk were deemed acceptable then mitigation of these touch voltage hazards would not be required. In this case, the decision was made to apply the deterministic approach to the substation and to classify the substation as a special location. Therefore, the mitigation of all touch voltage hazards is desired.

Mitigation measures are discussed in detail in section 4. In this case, since the substation fence will not be located on the property boundary, it was decided to mitigate the touch voltage hazards onto the outside of the fence by installing a gradient control conductor. The touch voltages are again plotted for a touch voltage limit of 284 V (natural ground) to show the touch voltages on the security fence, outside the switchyard.

Figure 26 shows that touch voltage hazards still exist onto the outside of the substation fence even with the gradient control conductor. Crushed rock or asphalt is required along a one metre wide strip around the substation. In this case, the decision was made to use crushed rock since crushed rock will be used inside the switchyard also.

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Figure 26: Touch Voltages around Earth Grid with a Gradient Control Conductor Outside the

Perimeter Fence

Figure 27 shows that with crushed rock and gradient control conductors inside and outside the security fence, touch voltage hazards on the fence are completely eliminated. Two areas of touch voltage hazards remain inside the substation. These areas of hazards should be eliminated.

Figure 27: Touch Voltages for Substation with Crushed Rock and Gradient Control Conductors

Inside and Outside the Perimeter Fence


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The installation of a gradient control conductor and crushed rock outside the security fence can only be achieved if the land purchased for the substation is sufficiently large. If because of size restriction, it is required to install the security fence on the boundary of the land, mitigation of touch voltages onto the outside of the security fence has to be considered. Touch voltage hazards will then exist on neighbours’ properties. Often, the only practical mitigation option is to use a wooden security fence rather than a wire mesh fence.

So far, the earth grid has consisted only of buried horizontal conductors. Since the conductors are buried relatively shallow (0.5 m) the impedance of the earth grid can vary with seasonal variation in the soil moisture content. Also, the soil resistivity shows that deeper soil layers have a significantly lower resistivity than the top soil layer. Therefore, in this case, it would be advantageous to add some driven rods to the earth grid. Three metre deep driven rods have been added to the corners and to the mid point of each side. The rods are installed inside the substation along the perimeter earthing conductor running one metre inside the security fence.

Figure 28 shows that with the addition of the driven rods, the touch voltage hazards inside the switchyard are eliminated. The final impedance of the earth grid is 1. Ω.

Figure 28: Touch Voltages for Earth Grid with Additional Driven Rods

Touch voltage hazards onto the substation gates also need consideration. If the gates open to the outside, the use of additional gradient control conductors together with surface treatment materials such as crushed rock or asphalt can be considered. Alternatively, the gates could be allowed to open inward only.

The highest earth fault current seen by the earthing conductors will be 10 kA for an 11 kV bus fault. The equipment earthing conductors must be sized for the earth fault current of 10 kA while the buried earth grid conductors can be sized for 70% of 10 kA, i.e. 7 kA.

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The sizes of the earthing conductors can be based on the worst case backup earth fault clearing time. However, a factor of safety is required to take into account the long duration these conductors are expected to be in service and relied upon, potential increase in the prospective earth fault current and the corrosive nature of the ground soil in which they are installed. Historically, earthing conductors have been rated for an earth fault clearing time of 3 s. For this substation the decision was made to size the earthing conductors for an earth fault duration of 3 s.

From Figure 3 and Figure 4 of section 2, the minimum sizes for the earthing conductors are:

(a) For buried conductors, the minimum size should be 70 mm2 or 20 x 4 copper strap;

(b) For the equipment earthing conductors, the minimum size should be 95 mm2 or 30 x 4 mm copper strap.

EPR TRAnSFER ISSUES

The EPR contours around the substation have been plotted as shown in Figure 29 for the worst case earth fault current. The 650 V EPR contour has been overlaid on an aerial picture as shown in Figure 30. Google Earth can also be used for this purpose. The EPR contour plot on the aerial picture indicate that EPR voltages could potentially be transferred onto surrounding conductive fences, metallic water pipes, buildings, third party assets, etc. All transferred voltages should be assessed but in this case study the following transferred EPR issues are considered applicable.

Conductive fences and pipes

For conductive fences, one of the first mitigating measures required is to ensure that third party fences are isolated from the substation security fence. Typically, 2 m long wooden sections of fence are used for this purpose. Mitigation of hazardous transferred voltages beyond the 2 m isolation sections would then have to be further investigated. This would require a detailed knowledge of third party fences around the substation. A risk assessment can also be carried out to determine the risk associated with touch voltage hazards on the fences. If the risk is low, then further mitigation would not be required.

Transferred voltages onto metallic water pipes should be assessed in a similar fashion to the conductive fences. If a water pipe enters the substation, plastic piping should be used. To mitigate the transfer voltages onto metallic pipes, it may be necessary to insert some plastic sections at specific locations. This requires a detailed knowledge of the pipes around the substation. Note that the EPR transfer onto pipes may be a temporary issue since metallic pipes are regularly being replaced with plastic pipes. A risk assessment of touch voltage hazards onto external taps connected to metallic pipes may be carried out to access whether mitigation is applicable, and the degree of mitigation required.

Buildings

EPR transfer voltages may cause touch voltage hazards to appear on external metal and concrete surfaces on surrounding buildings. As can be seen from Figure 30, some of the buildings around the substation are surrounded by asphalt. There will be no transferred touch voltage issues on those buildings. On other buildings where plants and/or grass exist along the walls, a risk assessment may be carried out to determine what degree of mitigation should be applied.


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Telecom

Discussions with Telecom have revealed that the Telecom cables in the area have an insulation rating of 2,500 V, and Telecom access points have an insulation rating of 1,500 V. The 2,500 V contour extends only a few metres out from the substation, and the 1,500 V contour extends about 10 m out from the substation. In this case, there are no Telecom cables within the 2,500 V contour, and no cross-connect cabinets or access points within the 1,500 V contour. Hence, for these EPR contours, there will be no EPR transfer issues for Telecom cables, cross-connect cabinets or access points.

Since the earth fault clearing time is 0.5 s, the other EPR contour of interest is the 650 V contour. This 650 V limit (for 0.5 s duration) is both a personnel safety voltage limit, and a default plant damage voltage limit for telecommunications plant that doesn’t have a higher insulation rating. The 650 V EPR contour is shown to be approximately 45 m out from the security fence.

Figure 29: EPR Contours around Substation

Telecom cables and access points can also be plotted on the aerial photograph as shown in Figure 30 to indicate which Telecom assets may be affected by the EPR contours.

There is one Telecom cross-connect cabinet located inside the 650 V EPR contours.

In this case, the Telecom cross-connect cabinet is located close to the edge of the 650 V EPR contour. Discussions with Telecom should be carried out to determine a cost-effective solution. The solution may consist of one of the following:

(a) The Telecom cross-connect cabinet can be moved to a new location outside the 650 V EPR contour;

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(b) The substation earth grid impedance can be reduced so that the size of the 650 V EPR contours is reduced although this may have the opposite effect and push the EPR contours further out. A reduction in the earth grid impedance may require a significant amount of additional copper conductors or significantly deeper rods. Another option that may be considered to reduce the earth grid impedance is the bonding of the substation earth grid to the surrounding MEN system. However, the hazards associated with the transfer of the EPR to the surrounding MEN system needs to be carefully considered. Bonding of the substation earth grid to the MEN system is discussed at the end of this case study;

(c) Asphalt may be installed around the Telecom cross-connect cabinet;

(d) Telecom could place a sign on the cross-connect cabinet to alert their staff of the risk and require them to use precautions such as adequate personal protective equipment (PPE). This may be an effective solution since only one cross-connect cabinet is involved.

There may be other mitigating options that may be considered.

A risk assessment has been carried out to evaluate the risk to Telecom staff at the cross-connect cabinet and whether mitigation is required.

Figure 30: 650 V EPR Contours around Substation


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Risk assessment for Telecom cross-connect cabinet

Telecom staff may visit the cabinet once a month on average. This is a conservative estimate. During each visit, the Telecom technicians may spend up to 15 minutes at the cross-connect cabinet, but they are likely to be touching the metallic parts of the telecommunications cables for a total of only 4 minutes. It is unlikely that more than one person will touch the conductors at a time, i.e. N = 1.

The exposure factor is therefore calculated as:

5F 10x1.9

365x24x60

48

yearainutesminofNo

yearperutesmin48E −===

Since the 11 kV off-site earth fault and the 33 kV bus earth fault result in a similar earth fault current, both earth faults should be considered when assessing the frequency of earth faults.

Earth fault statistics from other similar substations in the network have indicated that a 33 kV bus earth fault may occur on average once every 30 years. The 11 kV transformer is mounted on a pole. Earth fault statistics for 11 kV pole mounted transformers in this area indicate that a transformer earth fault may occur on average once every 500 years.

A more detailed study of off-site 11 kV earth faults has indicated that earth faults at only two 11 kV distribution transformers will create 650 V EPR contours that enclose the Telecom cross-connect cabinet. The earth fault frequency for both 11 kV transformers should be included in the calculations. The earth fault currents at other 11 kV transformers (located further from the substation) would be too low to create 650 V EPR contours that enclose the Telecom cabinet. Earth fault frequencies associated with conductive poles on the 11 kV feeders can also be ignored since the earth fault currents are significantly lower and, consequently, the extent of the EPR contours from the substation are limited.

The total earth fault frequency, FF, is therefore calculated as:

0.035 500

1

500

1

30

1 FF =++=

The equivalent probability of a Telecom technician being in contact with the metal conductors during a worst case fault can be calculated:

Pe = NEFFF = 1 x 9.1 x 10-5 x 0.035 = 3.2 x 10-6

This is considered an intermediate risk according to the risk matrix. However, this risk is relatively low since it falls in the low end of the intermediate range. A cost benefit analysis is carried out as detailed below.

The risk calculated indicates that the VoSL per year is:

VoSL per year = $10,000,000 x 3.2 x 10-6 = $32 per year

Over the period of the next 50 years, if the discount rate is 4%, then the present value, PV, can be calculated as:

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The cost benefit analysis indicates that not much money should be spent on mitigating the risk associated with the Telecom cross-connect cabinet. Telecom should be made aware of the calculated risk and of the results of the cost benefit analysis when discussing with them a viable solution to the EPR issue. The results of the risk assessment though indicate that option (d) above may be the most cost-effective solution in this case.

Mains powered telecommunications equipment

The transferred EPR from the substation onto the nearby MEN system may cause the failure of mains powered telecommunications equipment at the surrounding businesses. However, this is unlikely to be an issue if the EPR transferred onto the LV MEN is less than the applicable telecommunications limit voltage. In this example, only a small proportion of the LV earths in the local LV MEN system are inside the 650 V EPR contour, so the EPR transferred onto the LV MEN should be well under 650 V. Hence nothing more needs to be done.

Normally, there would only be a possible issue if the majority of the LV earths in the local LV MEN system are inside the 650 V EPR contour. If this were the case, the power utility may consider the failure of these third party telecommunications items of equipment as an acceptable financial risk for the power utility, since the risk of failure is relatively low (one 33 kV bus earth fault every 30 years on average).

OTHER MITIGATIOn COnSIDERATIOnS

Touch voltage hazards and the extent of the EPR contours can be mitigated by reducing the worst case EGVR of the substation. This can be achieved by either reducing the impedance of the substation earth grid and/or by installing NERs on the 33 kV system at the source.

The impedance of the substation earthing system may also be reduced by bonding to the local MEN system. This will effectively remove the 11 kV off-site earth fault as a significant source of touch voltage hazards. However, touch voltage hazards and the EPR transfer issues resulting from a 33 kV bus earth fault may then be spread over a larger area. This aspect would need to be considered in more detail.

NERs can be used to limit the 33 kV earth fault current and thereby reduce the EGVR of the substation. NERs can also be used in conjunction with a reduced earthing system impedance to further reduce the EGVR. For example, bonding of the substation earth grid to the MEN system may result in an earthing system impedance as low as 0.8Ω. If the 33 kV NERs limit the earth fault current to a maximum of 500 A, the worst case EGVR for the substation may be as low as:

EGVR = 0.8Ω x 500 A = 400 V

With this low EGVR, the transferred EPR issues will generally be eliminated and touch voltage hazards onto the outside of the substation fence are unlikely to exist. A gradient control conductor and crushed rock outside the fence are unlikely to be required.

A reduction in the 33 kV bus earth fault current can also be achieved by installing OHEWs over the whole length of the 33 kV lines. The OHEWs are likely to reduce 33 kV earth grid return current to approximately 20% of the prospective 3 kA earth fault current.


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B CASE STUDY – kV DISTRIBUTIOn TOWER LOCATED nEAR CHILDREn’S PLAYGROUnD

This case study involves an existing 66 kV distribution tower located in a park close to a children’s playground. This tower was identified as carrying a potential EPR risk for children using the playground. The tower is very close to the playground and children have been observed to use the tower as a jungle gym at times. Since a significant proportion of children will not be wearing shoes, footwear impedance is excluded from the assessment.

Since the line is not being upgraded in any way, transferred EPR issues were not considered.

This case study follows the risk method as detailed in the flowchart from section .4.

Step 1: Basic data

– The prospective earth fault current at the source substation is 20 kA. The earth fault current is sourced from one side only.

– The earth grid impedance at the source substation is ZSource grid = 0.1 Ω.

– The resistance to earth of the 66 kV tower was calculated as ZTower = 12.0 Ω.

– The tower leg foundations are grillages and have a depth of h = 2.5 m.

– The resistivity of the top soil layer was measured as = 220 Ω-m.

– The earth fault clearing time is 0.2 s.

– The earth fault frequency data is not available for this line. Therefore the default earth fault frequency from the EEA ‘Guide to risk based earthing system design’ will be used. The default value is 2.2 earth faults per 100 circuit-km per year.

– The double circuit line is 30 km long and consists of 120 towers.

– The tower is located approximately 6 km from the source substation.

– An overhead earth wire is not fitted to this section of line.

– The conductor on the line is Hyena. The impedance of the line is approximately 0.28 + j0.6 Ω per km.

Step : Functional requirement

The tower already meets the functional requirements.

Step : Tower EGVR

The 66 kV bus impedance at the source substation is:

ZSource (66,000 V/)/20,000 A = j1.9 Ω

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The tower footing resistance is:

ZTower = 12 Ω

The line impedance is:

ZLine = (0.28 + j0.6 Ω/km) x 6 km = 1.68 + j3.6 Ω

The earth grid impedance at the source substation is:

ZSource grid = 0.1 Ω

The total fault loop impedance is:

ZFault = ZSource + ZSource grid + ZLine + ZTower = j1.9 + 0.1 + 1.68 + j3.6 + 12.0 Ω = 13.8 + j5.5 Ω|ZFault| = 14.9 Ω

The earth fault current at the tower is:

IF-tower (66,000 V/)/14.9 A = 2,560 A

The EGVR on the tower is:

EGVR = 2,560 A x 12.0 Ω = 30,725 V

This means that during an earth fault at the tower, the voltage rise on the tower is expected to reach approximately 31 kV.

Step : Prospective tolerable step and touch voltage limits

The step and touch voltage limits were calculated for a fault clearing time of 0.2 s and for a soil resistivity of 220 Ω-m (footwear excluded).

VStep (limit) = 12,500 VVTouch (limit) = 615 V

Step5:IsEGVR≤V Step and VTouch limits?

The tower EGVR is significantly higher than the step and touch voltage limits.

Step : Calculate actual step and touch voltages

The actual touch voltage on the tower is typically between 40% and 70% of the EGVR. This means that the actual touch voltages are expected to be between 12 kV and 22 kV. The touch voltages on


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the tower were modelled as shown in Figure 31. From the plot, it can be seen that the maximum touch voltage on the steel structure is 14.8 kV.

Figure 31: Touch Voltages on 66 kV Tower

The step voltages around the tower were modelled as shown in Figure 32. From the model, it can be seen that the step voltages that exceed the limit of 12.5 kV only exist over a very small area. A person’s foot would have to be against the tower leg and the other foot in a coloured area 1 m from the tower leg for the person to experience a hazardous step voltage.

Figure 32: Step Voltages around 66 kV Tower

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Since it is not known what the water content of the soil was when the soil resistivity was measured, the step voltage hazards were also assessed with a lower top soil resistivity of 100 Ω-m which would result in a lower step voltage limit. Such a lower resistivity of the top soil can result from an increase in the soil moisture content. The step voltage limit corresponding to a soil resistivity of 100 Ω-m is 8.2 kV. Figure shows areas where the step voltage exceeds the 8.2 kV limit. In this case, the hazardous step voltage areas are within a radius of approximately 1 m around each tower leg.

Figure 33: Step Voltages around 66 kV Tower for Lower Limit

The touch and step voltages can also be estimated using the formulae shown below. These formulae are approximate and contain simplifications. They can be used to obtain a reasonable indication of the extent of the hazards and are useful for assessing risks.

Step voltages may be calculated at varying distances from a tower leg. The maximum step voltage is typically found close to the tower leg or foundation. The closest distance to the centre of a tower leg that a foot can be placed on the ground is approximately 0.2 m. In this case, the step voltage will be calculated for a foot at a distance r = 0.2 m from a tower leg and another foot at a distance r + 1 = 1.2 m.

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towerFrstep

Vstep-r = 11 kV

The above step voltage is lower than the maximum step voltage calculated by the modelling software.


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Step7:Areactualtouchandstepvoltages≤V T (limit) and VS (limit)?

The actual touch voltages on the tower significantly exceed the touch voltage limit.

The actual step voltages exceed the step voltage limit around the tower, but the areas of step voltage hazards are limited.

Step : Risk analysis

The significant hazards on the tower are the touch voltage hazards. The step voltage hazards cover a small area and are expected to carry a much reduced risk. Therefore, as a first estimation of risk, the step voltage hazards will be ignored. The risk is assessed by calculating the coincidence probability, Pc.

Pc = EFFF

Where:

€

EF

= Total duration of exposure per year (in hours)

Number of hours in a year

FF = Average number of hazardous EPR events per year on a tower

The frequency of earth faults for the line with 120 poles is 2.2 faults per 100 circuit-km per year.

Total circuit length = 2 x 30 km = 60 km (because there are two circuits)

The earth fault frequency factor is:

0.01120 x 10060 x 2.2

FF ==

On average, children visit the playground on three days of the week (the playground may be visited everyday of the week when the weather is good and not at all when the weather is bad). It is estimated that children may spend 2 hours on average at the playground during each visit. During these two hours, it is estimated that on average three children will be spending approximately 10 minutes each in contact with the tower while standing on the ground.

Exposure per day = 10 minutes = 0.17 hours

Total number of exposures per year = 3 days per week x 52 weeks per year = 156

Total duration of exposure per year = 0.17 x 156 = 26.5 hours

As there are 8,760 hours in a year, the exposure factor is:

3-F 10 x 0.3

760,8

5.26E ==

The coincidence probability is therefore:

Pc = 0.01 x 3.0 x 10-3 = 3.0 x 10-5

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Since approximately three children are assumed to be contacting the tower at the same time, N = 3 and the equivalent probability is:

Pe = NPc = 3 x 3.0 x 10-5 = 9.0 x 10-5

The risk is ‘intermediate’ and should be minimised unless the risk reduction is impractical and the costs are grossly disproportionate to safety gained. It should be observed that the calculated equivalent probability is relatively close to a ‘high’ risk and even though a cost benefit analysis can be carried out, this closeness to the ‘high’ risk level should be considered when assessing the results.

A cost benefit analysis can be carried out to determine whether the costs of risk treatments are disproportionate to the safety gained.

Calculate the present value (PV) of the liability:

VoSL = $10,000,000

Liability per year = 10,000,000 x 9.0 x 10-5 = $900

PV = $19,300 (assuming an asset lifespan of 50 years and a discount rate of 4%)

Step 9: Risk treatment options

A number of risk treatment options can be considered. Examples of risk treatment options are:

– Installing gradient control conductors and an asphalt layer around the pole.

– Installing a wooden fence around the pole to deter children from climbing the tower.

– Installing an equipotential reinforced concrete pad around the tower.

The risk treatment options are assessed and evaluated below:

Installing gradient control conductors and an asphalt layer around the pole

With gradient control conductors it will only be possible to reduce the touch voltage to approximately 4 kV. This touch voltage still significantly exceeds the touch voltage limit. If asphalt is also installed around the tower, the touch voltage limit increases significantly; however, the touch voltages are such that asphalt must be specified of a type that will withstand the maximum touch voltage. In this case, there is no specific information on the withstand voltage of asphalt and a value of 4 kV as specified in this guide should be used. The touch voltage will be approximately the same as the withstand voltage of asphalt and therefore, there is a risk that asphalt may be ineffective. There is not enough confidence in the effectiveness of this option to proceed with it.


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Installing an insulating barrier around the tower to prevent children touching the tower

A wooden fence can be installed around the tower to deter children from climbing the tower. The cost of this risk treatment option is $,000 and is significantly below the present value of the liability. There may be some additional ongoing costs associated with maintenance of the wooden fence.

Installing an equipotential reinforced concrete pad around the tower

A reinforced concrete pad may be installed around the tower up to a distance of one metre from the structural steel. The reinforcing must be bonded to the tower. The reinforced concrete pad will create an equipotential surface around the tower. The cost for the concrete pad is approximately $15,000. The concrete pad will cause step voltage hazards to remain when stepping between the pad and the surrounding soil. For a top soil resistivity of 220 Ω-m, the step voltage hazard areas will be negligible and the concrete pad is an acceptable solution. However, if the top soil resistivity drops to 100 Ω-m, for example when the top soil is wet, then modelling has shown that step voltage hazards will exist when stepping onto and off the concrete pad. In this case, the concrete pad may not be an acceptable solution.

All the above risk treatment options are cost-effective and are below the calculated PV for the risk. However, the best solution appears to be the wooden fence around the tower.

Alternative risk treatment such as reducing the earth fault current, reducing the earth fault clearing time, the EGVR, the occupancy rate or the earth fault frequency may also be considered and evaluated. Examples of these include improving the tower footing resistance, the installation of an overhead earth wire, or the relocation of the playground may also be considered and evaluated.

Once the design has been completed, the remaining steps in section 3A can be completed.

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B CASE STUDY – 0 kV TRAnSMISSIOn TOWER A 220 kV transmission tower is located on a roadside verge. A 15 m long section of fence runs within 6 m of the tower.

The example calculates the earth grid voltage rise, and step and touch voltages. The safety issues associated with EPR are also assessed.

Earth grid voltage rise calculation

Abbreviations and data used in the earth grid voltage rise calculation:

System voltage Vsource 220 kV

Prospective source 1 bus fault level Ibus 1 (25∠ -85o) or (2.2 – j25) kA

Prospective source 2 bus fault level Ibus 2 (25∠ -85o) or (2.2 – j25) kA

Line impedance Zline (0.1 + j0.7) Ω/km

Tower footing resistance ZTFR 7 Ω

Distance from source 1 Lsource 1 50 km

Distance from source 2 Lsource 2 150 km

Source impedance Zsource

Equivalent impedance of sources and lines Zequivalent

Tower fault current Itower

Impedances that are in parallel //

Zsource_1 = Vsource 1

=220 kV

= (0.44 + j5.04) Ω√3 Ibus 1 √3 x (2.2 – j25) kA

Zsource_2 = Vsource 2

=220 kV

= (0.44 + j5.04) Ω√3 Ibus 2 √3 x (2.2 – j25) kA

Zline_1 = Zline x Lsource 1 = (0.1 + j0.7) Ω/km x 50 = (5 + j35) Ω

Zline_2 = Zline x Lsource 2 = (0.1 + j0.7) Ω/km x 150 = (15 + j105) Ω

Zequivalent = (Zsource 1 + Zline 1) // (Zsource 2 + Zline 2)

Zequivalent = (0.44 + j5.04 + 5 + j35) Ω // (0.44 + j5.04 + 15 + j105) Ω

Zequivalent = (3.31 + j29.4) Ω

Itower = 220 kV=

220 kV kA√3 (Zequivalent + ZTFR) √3 x (3.31+ j29.4 + 7) Ω

Itower = 220 kV = 4.08 kA54 ∠ 71o) Ω

Earth grid voltage rise = ZTFR x Itower = 7 Ω x 4.08 kA

EGVR = 29 kV

NOTE: In this example the transmission line has no overhead earth wire (OHEW) installed. Where an OHEW is installed, the calculations are more complex and generally require a computer model to simulate the fault current distribution. Typically only 10% to 20% will flow down through the tower.


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Earth potential rise calculation

Abbreviations and data used in the EPR step and touch calculation:

Depth of foundation h 5 m

Soil resistivity 200 Ω-m

Greatest distance between the fence and the tower amax 15 m

Smallest distance between the fence and the tower bmin 6 m

Distance from the electrode r

EPR at r metres from the foundation Vr

Touch voltage Vtouch

Step voltage Vstep

Transfer voltage Vtransfer

General EPR formula

As a reasonable approximation, the following formula can be used to calculate Vr, the voltage at the surface r metres from an electrode h metres deep. This general formula applies to soil with uniform soil resistivity.

Vr = Itower

ln( 22 hr + + h)

16πh ( 22 hr + - h)

Based on the above general EPR formula Vtouch, Vstep and Vtransfer can be calculated.

Touch voltage on the tower is calculated as:

Vtouch = EGVR _ Itower

ln( 22 h1 + + h)

16πh ( 22 h1 + - h)

Step voltage at distance r from the tower foundation is calculated as:

Vstep r = Itower

ln( 22 hr + + h) _

Itowerln

( 22 h)1r( ++ + h)

16πh ( 22 hr + - h) 16πh ( 22 h)1r( ++ - h)

Transfer voltage where the conductor is a distance, a, from the tower foundation at its closest point and b, at its furthest point is calculated as shown below. This will calculate the maximum possible voltage that an individual could be exposed to through contact with the conductor. For a more accurate assessment a computer simulation is required.

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Vtransfer r = Itower

ln( 22 ha + + h) _ Itower

ln( 22 hb + + h)

16πh ( 22 ha + - h) 16πh ( 22 hb + - h)

Using the data above, the touch, step and transferred voltages are calculated as:

Touch voltage:

Vtouch = EGVR _ Itower

ln ( 22 h1 + + h)

16πh ( 22 h1 + - h)

Vtouch = 29kV _ x 4080

ln ( 22 51 + + 5)

16π x 5 ( 22 51 + - 5)

Vtouch = 14 kV

Step voltage:

Vstep r = Itower

ln( 22 hr + + h) _

Itowerln

( 22 h)1r( ++ + h)

16πh ( 22 hr + - h) 16πh ( 22 h)1r( ++ - h)

1.5 m from the tower, r = 1.5, and is used initially as it is the largest possible step voltage.

Vstep 1.5 = x 4080

( ln( 22 55.1 + + 5) _ ln

( 22 5)15.1( ++ + 5) )16π x 5 ( 22 55.1 + - 5) ( 22 5)15.1( ++ - 5)

Vstep 1.5 = 3.1 kV

Transferred voltage:

Vtransfer r = Itower

ln( 22 ha + + h) _

ρ Itowerln

( 22 hb + + h)

16πh ( 22 ha + - h) 16πh ( 22 hb + - h)

Vtransfer = x 4080

( ln( 22 56 + + 5) _ ln ( 22 515 + + 5) )

16π x 5 ( 22 56 + - 5) ( 22 515 + - 5)

Vtransfer = 2.8 kV


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EPR safety assessment

Abbreviations and data used in the EPR safety assessment:

Fault Clearance Time t 100 ms

Fault Rate 0.005 faults per year

Number of Towers 3 per km

Exposure Factor Vtouch Ef 1 15 seconds per day or 1.5 hr/year

Exposure Factor Vtransfer Ef 2 15 seconds per day or 1.5 hr/year

Number of persons exposed n 1

Equivalent number of people N

Equivalent probability Pe

By applying the fault duration t and the soil resistivity , the permissible prospective touch voltage limit can be derived from Figure 9.

Non hazardous touch voltage limit Vtouch limit 1.5 kV

The same limit applies for transfer voltage Vtransfer limit 1.5 kV

Similarly, applying t and the permissible prospective step voltage limit can be derived from Figure 10.

Non hazardous step voltage limit Vstep limit 15 kV

Vstep reduces with increased distance from the electrode. As the calculated Vstep was for a location adjacent to the tower and was below the Vstep limit, then a risk from Vstep can be ignored. If this were not the case, the Vstep would be calculated for a range of distances to establish the region where the Vstep limit was exceeded.

In this case an individual would, however, be at risk from Vtouch and Vtransfer were they to be exposed to a fault and the probabilistic method is used to assess this risk.

Probabilistic assessment

Pe = NEfFf

As n = 1 then N = 1

Pe = N x(Ef 1 + Ef 2) hrs/yr

x Ff faults/year24 x 365

17


Pe = 1 x (1.5 + 1.5)

x 0.0053 x 24 x 365

Pe = 1 x (1.5 + 1.5)

x 0.0053 x 24 x 365

Pe = 1.2 x 10-6

EPR mitigation

In this instance the risk would be considered to be effectively low and no mitigation is required.

If the risk were greater, then a typical approach would be to eliminate one of the contributory elements, for instance mitigation for Vtransfer. This could be undertaken by sectioning the fence with separate sections of fencing so that the conductor was not continuous and the voltage was not being transferred.

In this instance, the Vtransfer would probably not actually exceed the Vtransfer limit for several reasons. For instance, the Vtransfer calculation assumes the fence is connected to ground only at the two extremes, whereas a computer model is capable of calculating it from its multiple paths to earth along its length and the average voltage that the conductor would therefore reach. Secondly, the calculation reflects the voltage differential at either end of the conductor. The midsection of the conductor would have a voltage differential below Vtransfer.


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APPEnDIx C

ExAMPLES OF EARTHInG ARRAnGEMEnTS

(Informative)

Figures 34 to 40 inclusive provide illustrations of the application of the advice in this guide on earthing configurations for various substations and items of of network equipment.

Figure 34: Example of Earthing Arrangement in HV a.c. Station

19


Figure 35: Example of Earthing Arrangement for Earth Switches in HV a.c. Station


170

Figure 36: Example of Earthing Arrangement for Pole Mounted Transformer

171


Figure 37: Example of Earthing Arrangement for Air Break Isolator with other Equipment


17

Figure 38: Example of Earthing Arrangement for Lightning Surge Arresters

17


Figure 39: Example of Earthing Arrangement for HV Installations at Consumers’ Premises


17

Figure 40 : Example of Earthing Arrangement for Ground Mounted Kiosk

guide-to-power-system-earthing-practice-final(june2009)[1].pdf

Documents

eea guide

electricity act

new zealand committee

coordination of power

general earthing practices

new zealandguide

electricity network

industry representatives