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• dipenkhandhediya

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Citation preview

Substation Earthing Guide

Committee Draft Under Revision

Table of Contents

i

Table Of Contents 1

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.1 Functions Of An Earthing System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1.1.1 1.1.2 1.1.3

1.2 1.3 1.4 1.5

Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Equipment Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 System Operating Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Constraints Facing Earthing System Designers . . . . . . . . . . . . . . . . . . The Engineered Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purpose And Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Format of Guides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.5.1

2 3 4 5

Earthing Guides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2

Co-ordinated Design Technique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

3

Information Gathering And Hazard Appraisal . . . . . . . . . . . . . . . . . . . . . 9 3.1 Hazard Appraisal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 3.2 Information Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 3.2.1 3.2.2 3.2.3 3.2.4

4

4.3 4.4

Power Safety Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Transient Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Effect of Electric Current on The Human Body . . . . . . . . . . . . . . . . 15 Development Of Realistic Safety Criteria . . . . . . . . . . . . . . . . . . . . . 15 4.4.1 4.4.2 4.4.3

Definition of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 The Shock Circuit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Safety Criteria Applicable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Soil Resistivity Testing, Interpretation And Modelling . . . . . . . . . . . . . . 25 5.1 Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 5.2 Soil Resistivity Testing Procedure Guidelines . . . . . . . . . . . . . . . . . 25 5.2.1 5.2.2 5.2.3

6

10 10 11 11

Allowable Voltage Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 4.1 Conditions For Danger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 4.2 Causes Of Undesirable Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 4.2.1 4.2.2

5

Electrical System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Site Layout And Locality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Locality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geological Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Initial Data Gathering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Resistivity Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Result Interpretation And Modelling . . . . . . . . . . . . . . . . . . . . . . 29

Current Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 6.1 Calculation Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 6.1.1 6.1.2 6.1.3 6.1.4

6.2

Prospective Source Impedances . . . . . . . . . . . . . . . . . . . . . . . . . . . Conductor Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Personnel Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Incoming Equipment Rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

36 36 36 37

Worst Case Prospective Fault Current . . . . . . . . . . . . . . . . . . . . . . . . 38

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Faults Within Substation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 6.3.1 6.3.2

6.4

7

Calculating Induced Current Flows . . . . . . . . . . . . . . . . . . . . . . . . 41 Small Industrial Substation Example . . . . . . . . . . . . . . . . . . . . . . . 41

Faults Outside The Substation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 6.4.1 6.4.2

6.5

ii

General Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Fault Duration With Stepped Faults . . . . . . . . . . . . . . . . . . . . . . . . 44

Fault Current Asymmetry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Power Frequency Voltage Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 7.1 Earthing System Impedances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 7.1.1 7.1.2 7.1.3 7.1.4 7.1.5 7.1.6

7.2 7.3

Voltages Inside the Substation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Voltages External to the Substation . . . . . . . . . . . . . . . . . . . . . . . . 66

Transfer Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 Voltage Gradients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 7.5.1 7.5.2

7.6 7.7

48 56 57 59 59 60

Earthgrid Potential Rise . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Touch And Mesh Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 7.3.1 7.3.2

7.4 7.5

Primary Earthing System Impedances . . . . . . . . . . . . . . . . . . . . . . Auxiliary Earthing System Impedances . . . . . . . . . . . . . . . . . . . . . Aerial Conductors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Buried Conductors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Combination of Primary and Auxiliary Earthing Systems . . . . . . Proximity Effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Within and Close to the Substation Grid Area . . . . . . . . . . . . . . . . 72 External to Substation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Empirical And Analytical Calculation Comparison . . . . . . . . . . . . . 81 Voltage Mitigation Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 7.7.1 7.7.2

Primary Source Hazard Prevention . . . . . . . . . . . . . . . . . . . . . . . . . 87 Secondary Effect Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

8

Transient Voltage Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 8.1 Transient Sources And Interference Mechanisms . . . . . . . . . . . . . . . 89 8.2 Mitigating The Effects Of Transients In Substations . . . . . . . . . . . . 91

9

Direct Current Power System Earthing . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1 HVDC Converter Station Earthing . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2 HVDC Cable Terminal Station Earthing . . . . . . . . . . . . . . . . . . . . . 9.3 Electrodes For Earth Return Working . . . . . . . . . . . . . . . . . . . . . . . .

10

Installation Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96 10.1 Principles Behind Installation Of Earthing Equipment . . . . . . . . . . 96

93 93 94 94

10.1.1 H.V. Electrical Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96 10.1.2 Non Electrical Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 10.1.3 Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

10.2

Equipment Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 10.2.1 Rating of Earthing Conductors . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 10.2.2 Conductor Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102 10.2.3 Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

10.3

Designing The Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106 10.3.1 Horizontal Mesh Layout . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 10.3.2 Driven Rod Placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 10.3.3 Structural Members . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110

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10.3.4 External Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110 10.3.5 Auxiliary Test Electrodes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

11

Testing Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112 11.1 Impedance Measurements Using Portable Meters . . . . . . . . . . . . . . 112 11.2 Earth System Injection Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 11.2.1 11.2.2 11.2.3 11.2.4 11.2.5

12

Testing Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Testing Principle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Difficulties in Measuring Low Impedances . . . . . . . . . . . . . . . . . Comparison of Injection Methods . . . . . . . . . . . . . . . . . . . . . . . . Measurement of Touch and Step Voltages . . . . . . . . . . . . . . . . . .

114 115 118 119 120

Maintenance And Refurbishment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122 12.1 Initial Commissioning Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122 12.1.1 Physical Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122 12.1.2 Electrical Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

12.2

Periodic Integrity Checks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124 12.2.1 Physical Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125 12.2.2 Electrical Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

12.3

Major Review And Refurbishment . . . . . . . . . . . . . . . . . . . . . . . . . 126 12.3.1 12.3.2 12.3.3 12.3.4 12.3.5 12.3.6 12.3.7

Investigation and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . Initial Field Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Design Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Initial Injection Test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . New Design Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Remedial Measure Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . Design Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

128 128 129 129 129 129 129

Case Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130 Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161

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Chapter 1

Introduction

1

1 Introduction An earthing system design based upon minimising earth resistance will not guarantee safety, there is no simple relation between the resistance of the earthing system and the maximum shock current to which a person might be exposed. Therefore, the performance of an earthing system as a whole must be analysed. The design methodology introduced aims to integrate the various phenomena affecting the performance of earthing systems with appropriate analytical procedures.

1.1

Functions Of An Earthing System

1.1.1 Safety To ensure that: !

Accessible non-current-carrying metallic structures and equipment are maintained at the same potential.

!

Hazardous step, touch and transfer voltages do not exist during fault conditions (50Hz or transient)

!

A common earthing point is provided to reduce or eliminate static buildup.

!

The design criteria are maintained over the design life of the installation despite additions or modifications.

1.1.2 Equipment Protection To limit the level of transient voltages on equipment by safely providing a low impedance path for lightning discharges, switching surges, fault currents and other system disturbances. These disturbances may cause extensive damage to equipment including associated equipment such as communications cables. Equipment damage might include: insulation breakdown; thermal or mechanical damage, and may result in fires and electrically ignited explosions.

1.1.3 System Operating Requirements !

To ensure proper operation of protective devices such as protection relays and surge arresters. Power-system overvoltages and fault current levels are influenced by the earthing system.

!

The design must be co-ordinated to achieve the desired reliability levels. System outage rates are effectively reduced by the use of earthing systems which minimise phase to earth back flashover and inductive interference (eg. protection pilot cables).

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Chapter 1 !

1.2

Introduction

2

The continuous metallic earth grid provides a connection to earth for lightning and switching surges and 50Hz earth fault current. Therefore, every component of an earthing installation should be capable of carrying the design maximum earth fault current which may flow through the component without causing hazardous potentials, interference to other systems, or damage until the fault is cleared.

Constraints Facing Earthing System Designers The design of safe economical earthing systems is difficult to achieve. Existing installations are exposed to changes requiring a review of safety and equipment rating performance. A number of these constraints are outlined as follows: !

Interaction between Power Systems and Industrial Installations. Because of the increasing area of industrial installations, and the increasing density of power generating, transmission and distribution equipment, the effect of power equipment on industrial equipment must be assessed, controlled and coordinated, in the interest of personnel and equipment safety, in a cost-effective manner. Influences such as voltage rises from power generating and transmission plant have to be considered to avoid the transfer to, or induction in, equipment for both surface and underground installations.

!

Fault Level Increases. The increase in fault levels has increased inductive interference/hazard conditions.

!

Reduction in Substation Areas. Due to new technology in the power industry (eg. SF6 insulated equipment) and space constraints in city and urban environments, substation areas are being drastically reduced. Thus earthgrid impedances, which are inversely proportional to the square root of the area, increase. The combination of increased earth fault current and earth grid impedances leads to an increase in earthgrid potential rise. Consequently earth system design and installation costs are increasing to off-set these effects.

!

Widespread Use of Conductive Structures. The introduction of concrete and steel poles to the sub-transmission and distribution systems is presenting a new range of problems involving earthing system requirements.

!

Large Interconnected Systems. Whilst earthing design practices for substations of relatively small dimensions have been quite well established, earthing systems for large industrial installations (eg. power stations and coal processing plants) require more sophisticated calculations to achieve safe cost-effective designs.

!

Existing Earthing Systems. Many older substations present the possibility of hazardous situations existing during fault conditions, for the following reasons:-

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Chapter 1

!

1.3

Introduction

3

•

Earth grids were designed in a haphazard manner, consisting only of conductors run to bond metallic structures. Such substation earth grid designs often do not comply with the currently accepted international standards.

•

Uncertainty concerning both the condition and effectiveness of the existing earthing systems.

•

In many instances the electrical hardware has become inadequate to handle the increasing fault currents with the required degree of safety. Many installations are over 50 years old and during that time fault levels have, in some cases, more than tripled. Therefore, the old design may not be electrically safe or sufficiently robust to withstand the increased fault levels.

•

Alterations or additions to earthing systems have often been undertaken in an ad-hoc manner. This has left earth systems poorly documented, with many unrecorded or ‘inadvertent’ connections.

Professional Liability and Financial Constraints. The cost of designing, installing and testing a new or refurbished earthing system is quite high. Some problems are not only difficult but also costly to resolve. However, if an accident occurs, the legal costs associated may be very high. Such litigation is cause for concern, as we are bound by professional and economic constraints to implement a system which meets appropriate safety criteria.

The Engineered Response The experience of the power supply industry has shown that only a small proportion of electric shock incidents involve high voltage power equipment. It is proposed that the relative infrequency of incidents involving protective earthing systems is not predominantly related to adequate earthing system design, but rather is fortuitously a consequence of a very low probability of human exposure to hazardous situations. Not only must the requirements for a shock situation coincide but their degree is also involved. The fault current magnitude and time of exposure, coincidental with a persons hand contact and possibly barefoot, and being present in the location coinciding with the fault. It is impossible, short of abandoning entirely the distribution of electric power, to prevent, at all times, in all places, and under all conditions, the presence of dangerous voltages. However, this fact does not relieve the engineer of the responsibility of seeking to lower this probability as much as he reasonably can. Thankfully in most cases it can be reduced to an acceptable value by internationally recognised design procedures. It is necessary to plan ahead to prevent problems arising in the future. Whatever the affected equipment, an assessment and control of problems will have to be planned before they occur. Planning and design co-ordination is necessary to ensure safety for personnel and avoidance of equipment failures. Careful design can

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Chapter 1

Introduction

4

achieve an acceptable solution.

1.4

Purpose And Scope The purpose of this guide is to provide guidelines for the design, installation, testing and maintenance of earthing systems associated with electrical substations. Earthing systems that are covered in this guide include those associated with: generating plants, industrial installations, transmission and distribution stations. Internal wiring and equipment/appliance earthing details are not addressed in this document. Rather AS3000 - ‘Wiring Rules’ should be followed or other governing regulations. The following section outlines the structure of this Guide and its relationship to other ESAA Guides. The topics covered in this Substation Earthing Guide are shown in Figure 1-1 following.

SUBSTATION EARTHING GUIDE 1. Introduction

2. Co-ordinated Design Technique 3. Information Gathering and Hazard Appraisal 4. Allowable Voltage Criteria 5. Earth Resistivity, Interpretation And Modelling

.

6. Current Distribution

7. Power Frequency Voltage Design

8. Transient Voltage Design

9. Direct Current Power System Earthing

10. Installation Techniques.

11. Testing Methods 12. Earthing System Maintenance and Refurbishment

.

Figure 1-1

Substation Earthing Guide - Overview

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Chapter 1

1.5

Introduction

5

Format of Guides The ESAA Earthing Guides are structured as follows:

1.5.1 Earthing Guides Four guides have been issued, covering earthing systems in each of the following components of the electrical system: ! ! ! !

Power stations and industries : large interconnected systems Transmission systems : Power lines and cable earthing Substations : Design of any substation earthing system Distribution Systems : Substations and line/cables involved with LV distribution.

These documents are intended to provide directions to earthing system designers in the form of: definitions, design guidelines, basic formulae, appropriate standards (ie, safety criteria, equipment sizing), with cross-references to details provided within the Earthing Reference Manual. These Guides address the following areas: ! ! ! ! ! ! ! ! !

Safety criteria applicable. Hazard appraisal and mitigation method identification. Provide co-ordinated planning and design strategies. Analysis methods with worked examples. 50Hz, direct current and transient performance of earthing systems. Analysis of the conductive and inductive interaction with nearby metalwork such as: railway lines, metallic pipelines, telecommunications networks, underground power cables and fences. Installation techniques. Testing methods: Initial investigations and final verification. Maintenance and refurbishment philosophies and procedures.

The four guides are intended to ‘stand alone’ and, therefore, deliberately overlap to a certain extent. The Power Station and Industries Earthing Guide provides more detailed information on problems specific to such installations, whilst leaving the substation earthing system design to the Substation Earthing Guide.

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Chapter 2

Co-ordinated Design Technique

6

2 Co-ordinated Design Technique The summary of a design methodology is illustrated below in Figure 2-1 [1]. The major steps in the process (numbered above the process box) are discussed in subsequent sections (located (i.e. (3)) above the process boxes).

Figure 2-1: Coordinated Design Technique

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Chapter 2

Co-ordinated Design Technique

7

The first step in the process is information gathering to determine: ! ! ! ! !

The design fault currents and ground return currents. Soil conditions (resistivity, moisture content seasonal variations geology corrosive properties). Site area restrictions, alternative site possibilities. Services and facilities nearby (or further away) that may be affected by ground currents/voltage rises, or by induced voltage or currents due to fault currents flowing in lines. Site testing requirements.

This step is critical, in that the significant factors must be appraised before simplifying assumptions can be made with confidence. To ignore parameters, such as soil resistivity or voltage transfer paths, can lead to either unsafe conditions or over expenditure. Once the information is gathered, the design procedure is structured to minimise complicated analysis. For example, detailed analytical modelling is only recommended in order to: ! ! !

Find appropriate designs if simple empirical formulae cannot be acceptably applied to the particular installation. Investigate a range of remedial measures. Minimise manpower and material costs by more accurate modelling when appropriate.

Decisions on whether complex modelling will be necessary may be judged from the results of the investigations and preliminary calculations, and with guidance from Figure 2.1 Markers are placed in the margins throughout the Guide to indicate the major Design Steps.

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Chapter 3

Information Gathering And Hazard Appraisal

8

3 Information Gathering And Hazard Appraisal A preliminary investigation is required to determine the earthing system requirements. Section 3.2 provides a checklist of details required under the following categories:

Design Step 1

! !

Design Step 1

Electrical power system configuration, site layout and locality Geological survey and soil resistivity measurements.

A thorough investigation will reveal possible hazardous situations and provide more accurate data for the design process. When reviewing the safety performance and checking the sizing and condition of existing systems additional procedures are recommended (see Chapter 12).

3.1

Hazard Appraisal Too often this investigation stage in the process is effectively ignored under the excuses of “too little time”, “inadequate documentation available”, or “it can be proven by testing”. On many occasions taking a little extra time at this initial stage has proved well worthwhile, resulting in: !

Better planning of resistivity test program (ie. in certain difficult cases the substation position has been moved when adequate time and land was available).

!

Locating previously unknown/unexpected hazards (eg. fences, pipelines).

!

Gathering better location specific information resulting in significant cost savings (eg. special constraints, lower resistivity locations, additional availability of secondary earthing systems).

!

Better planning for the commissioning injection test program as more hazards are known before hand. Otherwise, neither the design nor test may allow one to identify and quantify the real hazards. It is better to plan for such contingencies earlier rather than once the system is installed (eg. retrofitting can be hazardous and costs are significantly higher than at the initial stage).

Patience and persistence at the preliminary stage will yield cost savings and/or safety insurance in the majority of cases.

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Chapter 3

3.2

Information Gathering And Hazard Appraisal

9

Information Required

3.2.1 Electrical System A)

Single Line Diagram

i)

Transformer/Protection Details

! ! !

Protection relays: types, settings, fault clearing times Current transformer ratios. Transformers: size, impedance, voltages, connections. (eg. earth fault limitation), configuration (eg. star/delta).

ii)

Overhead and Underground Reticulation

! ! !

Conductor: Size, length, type, spacings. Overhead earthwires: size, length, earthing details, shielding factor. Underground cables: @ Type, laying configuration. @ Cable sheath: size and material, Earthing and cross-bonding details, shielding factor. @ Cable box earthing details. LV reticulation details: neutral connections and earth leakage protection details.

! iii)

Earth fault Details

For each voltage level indicate: !

!

Maximum earth fault currents @ Components flowing in: transformer neutrals, overhead shieldwires, and cable sheaths. @ Details concerning lines being; active or passive (i.e. for each fault case which lines supply earthfault current). Maximum fault duration for the earth fault currents: @ Without failure of a relay or circuit breaker. @ With failure of first level of protection.

3.2.2 Site Layout And Locality A)

Earthing Details

! ! !

Conductor sizes, connections, types. Earth electrode sizes, depths and locations. Interconnections between earthing systems.

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Equipment Locations

Earthing details and locations are also required for the following equipment: !

Lightning spires, surge diverters.

In the case of equipment to be extended, determine the impedance to earth of the existing electrical equipment. Also determine the earth electrode material used in the existing equipment.

3.2.3 Locality Earthing details and locations are required for metalwork in the vicinity, including: ! ! ! ! ! ! ! !

Pipelines (eg. water, gas, oil) stating the method of installation in the soil (insulated or not insulated, on pipe supports/bridges). Fences (eg. bare metal fences, bare wires or insulated-wire, or fences consisting of insulated-wire with insulated fence posts without bare metal parts). Building construction details (eg. steel, or reinforced concrete). Railway tracks, stating the foundation (eg. ballast, or directly embedded in paved soil) and insolation details. Poles and other steel structures in immediate contact with the soil or water, or connected with the soil or water through concrete. Rivers, streams, lakes, headwaters and soil water ponds of hydro-electric power stations or pumped storage stations. Communications lines. Disused buried metalwork.

Determine where these conductors are accessible so as to allow contact at the nearest point outside the earthing system.

3.2.4 Geological Survey A)

Geological Data

Topography, nature of soil material, presence of various layers, water table, previous test data, and civil earthworks (eg. cut and fill). B)

Seasonal Variations

Recent weather patterns, moisture relative to maximum and minimum, and the magnitude of effect of seasonal variations. While difficult to quantify such information does provide a useful context in which the resistivity test results may be interpreted and a set of design data determined.

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Earth Resistivity

Results of a resistivity survey over the area under consideration, using spacings at least equal to the size of the site. D)

Corrosion Properties of the Soil

Determine corrosion properties of the soil. Ascertain performance of any existing earth electrode by inspection.

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4 Allowable Voltage Criteria Ensuring safety for both power authority personnel and the public in the event of an earth fault is one of the primary purposes of an earthing system. The factors involved in developing safety criteria in the context of power system operating conditions and physiological safety constraints are introduced to provide for safety evaluations. Without such an understanding, the application of electric shock safety criteria to practical problems may be misinterpreted [2, 5, 8, 22] (eg difference between the prospective (i.e. open circuit) and ‘loaded’ touch voltage calculations of body currents). This section addresses aspects pertinent to the goal of providing safe earthing systems, the causes and conditions for danger, and factors involved in applying realistic safety criteria: 1. 2. 3. 4.

4.1

Conditions for danger Causes of undesirable voltages Effect of electric current on the human body Safety criteria

Conditions For Danger The first step involved in defining the shock hazard, is to determine the circumstances which make electric shock accidents possible. A ‘shock’ situation requires the evaluation of the following factors: !

The magnitude of the fault current to ground in relation to size of the earthing system and soil resistivity.

!

Soil resistivity and distribution of earth fault current flow such that high-potential gradients are possible at one or more locations.

!

Presence of an individual at such a location, at a time, and in a position that their body bridges at least two points of high potential difference.

!

Duration of the fault of sufficient time to cause harm at the given location.

The relevant infrequency of accidents of the type being studied, compared to accidents of other kinds, is due to the low probability of coincidence of the conditions required. Nevertheless, fatalities due to voltage gradients associated with earthing systems can be expected to occur unless design action is taken to reduce the risk.

4.2

Causes Of Undesirable Voltages Hazardous earth potentials can be produced by power frequency and transient earth currents as a result of power system earthfaults and switching and lightning overvoltages.

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4.2.1 Power Safety Voltages a)

Conduction of Fault Currents

The majority of safety problems are associated with voltage rises resulting from the conduction of power frequency earth fault currents into the ground. All metalwork forming the earthing system will conduct current, either directly into the ground, or to another part of the system and thence to ground. The three basic hazard situations are due to step, touch and transfer voltages. b)

Induced Voltages

!

Electromagnetic Induction Voltages may be electromagnetically induced in fences, pipelines, conveyors, railway lines, telecommunication cables, trailing cables whether above or underground due to the flow of fault current in high voltage power lines. Problems have been experienced at depths of up to 100m. Kovats in reference [20] cites a voltage of 2kV induced along an underground conveyor 1.14km in length, 50m below a double circuit 500kV and single circuit 330kV transmission line.

!

Electrostatic Induction If an item of equipment runs parallel to a transmission line for any distance, tests should be undertaken to determine the voltages existing in the steady state. Although rare, problems have been experienced with fences, lines and conveyors near to transmission lines.

4.2.2 Transient Voltages Transient voltages are either of atmospheric or man-made origin. a)

Atmospheric Origin

Potentials due to lightning strikes to ground, or discharges between clouds, can affect any part of the surface, but can also be transferred conductively to distant parts of installations (even underground). Following lightning strike to a line or substation the initial lightning surge to earth may be of short duration, however, a power frequency ‘follow-through’ current may occur. This secondary effect, due to insulation ‘flashover’ may present a greater safety hazard than the initial transient surge.

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Man-made Origin

Transient currents enter the earthing system, due to arcing between isolator/disconnector contacts during switching operations or breakdown of insulation. The short rise times of the wave combined with the high speed of travel creates high voltage differences over short distances in the earthing system. Whilst this does not present a great safety hazard to personnel, the overall reliability of substations may be reduced. Therefore, special measures should be taken to avoid disturbances due to high frequency earth potential rises, especially when designing the earthing of gas-insulated substations (G.I.S.) which can create extremely high frequency voltages that may be accessible to staff or transferred to secondary systems. The integration of the physiological data into the context of the electrical power system is required to enable design engineers to allocate limited resources in a manner consistent with realistic risk management philosophies. Safety criteria are required which are both technically feasible within realistic operating conditions and provide economical solutions.

4.3

Effect of Electric Current on The Human Body The starting point for the derivation of the safety criteria is the fundamental research into the effect of electric current upon the human body. Thresholds have been defined for perception, let-go and ventricular fibrillation (VF). Although asphyxia and cardiac arrest do cause a number of fatalities, ventricular fibrillation is considered to be the main cause of death by electrical shock [11]. The fibrillating current threshold is affected by the following inter-related factors, and is internationally accepted as the threshold to be used when designing substation earthing. ! ! ! ! ! !

Current magnitude Current path Duration and time occurrence Sensitivity of the individual Frequency Body impedance

The Earthing for Safety chapter in the ESAA Earthing Reference Manual provides details regarding each of these factors.

4.4

Development Of Realistic Safety Criteria In order to relate the physiological data to ‘real-life’ power system applications, actual hazard situations must be identified and the relevant parameters defined. This process is described in the following sections; 1. 2. 3.

Definition of terms The shock circuit Derivation of safety criteria

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4.4.1 Definition of Terms The distinction between ‘prospective touch voltage’ and ‘touch voltage’ is defined as follows: Prospective Touch Voltage (Vpt). The voltage difference between an earthed metallic structure (within 2.4m of the ground), and a point on the earth’s surface separated by a distance equal to a man’s normal maximum horizontal reach (approximately one metre) [18], [22]. This voltage is defined as an open circuit voltage, measured using a high impedance voltmeter. Touch Voltage (Vt). The voltage across a body, under fault conditions, in a position described as for the prospective touch voltage but allowing for the voltage drop caused by a current in the body. [22] Thus the touch voltage may also be termed a ‘loaded’ voltage which is ‘loaded’ by the human body impedance. The touch voltage may be reduced by additional impedance in series with the human body. This situation is reflected in the safety criteria by varying assumptions concerning the human body resistance and foot contact resistance. The foot contact is simulated either using a driven rod, or 300cm² copper disc. The former method provides a conservative estimate for touch voltages as it negates the current limiting effect of a high impedance surface layer, if present. This guide follows the American practice, based upon IEEE Std 80 [18], which utilises 1000Ω body impedance and calculated value of foot contact resistance in its safety criteria derivation. Therefore, this guide recommends a value of allowable prospective ‘touch voltage’ (see Section 4.4.3). Step voltage definitions are similar to those given above for open circuit and loaded touch voltage cases, as follows: Prospective Step Voltage (Vps). The voltage difference between two points on the earth’s surface separated by a distance equal to a man’s normal maximum step (approximately one metre). Step Voltage (Vs). The voltage across a body, under fault conditions, in a position described as for the prospective step voltage but allowing for the voltage drop caused by a current in the body. [22]. The measurement of prospective (or open-circuit) step voltage and step voltage is based on similar principles to those given above for the touch voltages. The main difference being one hand contact being replaced by an electrode representing the human feet.

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It is important that these distinctions be clarified during the design stage and in the testing procedures as considerable hazards may arise through mismatch of design safety criteria and measurement technique. Refer to Section 11.2.5 of the Testing chapter for further detail on measurement procedures.

4.4.2 The Shock Circuit For the step and touch voltage shock situations, the significant circuit parameters are identified, defined and combined to form ‘electrocution equations’ in the following sections: a) Parameter identification and definition. b) Equation derivation. a)

Parameter Identification and Definition

The following Figure 4-1 identifies the parameters involved in step and touch voltage shock situations.

Figure 4-1:

Electric Shock Circuit Parameters.

Two of the parameters involved in the shock circuit are discussed in the following sections; i) ii) i)

Resistance of insulating materials Foot-to-ground contact resistance

Resistance of Insulating Materials

According to an extensive survey conducted by an IEC WG2 [27] and another by

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Electricite de France, the resistance of dry new shoes varies between 6 and 20 megohms. If wet and new the range is from 350 ohms to low kilohms. For older wet shoes the resistance drops below 500 ohms in many cases. To date studies have considered it prudent to neglect the effect of shoe and glove impedance, especially at locations such as recreational or camping areas. It is recommended [6], [7] that boots or gloves be taken into consideration in switchyards when public access is not possible, provided conservative values are used, and provided property inspection procedures are applied as a matter of routine. ii)

Foot-to-Ground Contact Resistance

The resistance of the ground just beneath the feet may appreciably increase the circuit resistance. The general case will be discussed firstly, then the case where a thin layer of high resistance material exists on the earth surface. !

General Case

The shock circuit may be simplified as shown in the following Figure 4-2.

Figure 4-2:

Touch and step voltage circuits

Rbt RF Rbs RMF

Hand to feet body resistance Self resistance of each foot to remote earth Foot-to-foot body resistance Mutual resistance beneath feet

= = = =

For Vpt, Vt, Vps and Vs see definitions in Section 4.4.1. The voltage gradients can be depicted as shown in the following Figure 4-3.

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Figure 4-3: Potentials associated with step and touch voltage shocks. From Figure 4-2 the two cases may be expressed as follows [18 ]; = = .

Step voltages case with two feet in series (1m apart) 2 (RF - RMF) 6 ρs

(4-1)

= = .

Touch voltage cases with 2 feet in parallel. 0.5 (RF + RMF) 1.5 ρs

(4-2)

RF

=

Resistance of a standard foot having resistance equal to a plate electrode on the surface with a radius of 0.08m

RMF

=

Mutual coupling between feet

ρs

=

Surface homogeneous soil resistivity

!

Effect of a Thin Layer of Crushed Rock

R2fs

R2fp

Where

The contact resistance of the foot with normal soil is generally neglected. However, if a layer of crushed rock (5 to 15cm) or bitumen is spread on the surface of the ground, it will provide additional series resistance, thereby reducing the body current. IEEE80 [18] utilises the new surface layer resistivity value in equations derated by a factor (Cs) to account for layer depth and resistivity magnitude differences. The thickness of the high resistance layer must be greater than the flashover distance for the prospective voltage for the material. Heppe [51] calculated the derating factor to be used in accordance with the following formulae: Cs

=

Reduction factor for derating the nominal value of surface layer resistivity.

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  1  Kn 1 2 Cs  0.96  n 1 1  2n h / 0.08 2  s

   

19

(4-3)

Cs = 1 if ρs = ρ Where K = Reflection factor

K  ρs ρ hs

  s   s = = =

(4-4)

Crushed rock resistivity (Ω.m) Soil resistivity (Ω.m) Thickness of crushed rock layer (m)

An alternative simplified formulae (4-5) from Sverak [69 ] gives the reduction factor as follows:

   1   s   Cs  1  0106 .  .   2hs  0106     Cs

=

1

(4-5)

if ρ = ρs

Figure 4-4 from IEEE80(86) [18], provides a graphical representation of Cs.

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Figure 4-4:

eg.

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Reduction Factor Cs As a Function of Reflection Factor K and Crushed Rock Layer Thickness hs

A typical case of 3000Ωm crushed rock over 100Ωm homogeneous earth increases parallel foot contact resistance from 150 to 2565 Ω.

The surface layer resistivity must be significantly higher than the soil resistivity (5 times or more) for any benefit to be gained. It is important to ensure that the crushed rock selected is of adequate size and resistivity. Problems have been found with aggregates containing fine and round river gravels. It is important that the layer be coarse crushed rock and maintained in clean condition to ensure system safety compliance (eg. industrial substations where fine dust is generated must be maintained clear of fines or have the crushed rock layer ignored in calculations). b)

Equation Derivation

The shock circuit equations are summarised as follows. From Figure 4-2 it can be seen that the actual prospective touch and step voltages across the human body, as a function of allowable body current, body resistance and foot to ground contact resistance, are:

V pt  ibt Rbt  R2 fp





(4-6)





(4-7)

V ps  ibs Rbs  R2 fs Where ibt = = ibs

Permissible body current (hand-to-feet) Permissible body current (foot-to-foot)

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Note: Additional series resistance due to gloves and footwear may also be included in Equations (4-6) and (4-7), if its application can be justified.

4.4.3 Safety Criteria Applicable Design Step 5

It is recommended until further international standardisation occurs that the American IEEE Std 80[18] approach be used for substations under ESAA Guidelines.

Design Step 5

While IEEE Std 80 [18] discusses several of the biological shock factors, such as the heart current factor, it does not quantify them in producing a simplified set of safety criteria. The standard is based upon the 99.5% ventricular fibrillation (VF) current threshold, proposed by Dalziel and provides guidance for body weights of 50 to 70 kg. ! !

50kg case recommended for locations where children may be present (eg. outside substations). 70kg case is recommended (eg, inside substations) where access is limited.

The IEEE Std 80 Standard does not take into account the dependence of body impedance (Rb) on applied voltage or path, but uses a single value of 1000Ω. It does, however, recognise the effect of a surface layer of high resistivity (as described previously in Section 4.4.2 a) ii) upon RF. The recommended limits to touch and step voltages occurring during earth fault conditions are determined using the following Equation 4-8 and 4-9 for 70kg persons. The case of allowable prospective touch voltages inside substations is illustrated as follows:



V pt  ibt Rbt  R2 fp



 0157 .  . Cs  s     1000  15  t 

(4.8)

 157  0.236Cs  s   V pt    volts t   For allowable step voltages the result is:

V ps 

157  0.942 Cs  s

(4-9)

volts

t

Therefore, to determine the prospective touch and step voltages open circuit test measurements are made using driven rods and a high impedance voltmeter, as foot-to-ground contact resistance is incorporated in Equations 4-2 and 4-8. The formulae for allowable prospective touch and step voltages are shown in the following Table 4.1 for 50kg to 70kg persons.

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Table 4.1 Allowable Prospective Voltage Criteria

50kg body weight

Prospective Touch Voltages (Vpt)

Prospective Step Voltages (Vps)

116  0174 . Cs  s

116  0.696 Cs  s

(To be used in areas with public access) 70kg body weight (May be used in restricted areas within a substation)

t

t

157  0.236 Cs  s t

157  0.924 Cs  s t

Where Cs

=

Derating factor relating to surface layer thickness and resistivity (see Section 4.4.2 b) Figure 4-4 and Equations 4-3 and 4-4).

=

1 when crushed rock resistivity is equal to soil resistivity.

ρs

=

Resistivity of surface material (Ωm) (eg. crushed stone or bitumen) (provided layer depth/thickness (hs) hs > flashover/puncture distance for the prospective voltage).

t

=

Duration of shock current (seconds).

The following points should also be considered when determining allowable voltages: !

Hand-to-hand Conditions

For hand-to-hand touch conditions (eg. opening gates) it is considered appropriate to use the touch voltage criteria without the additional series impedance factor, as follows: Allowable prospective hand-to-hand voltage (50kg) =

116//t volts

(4-10)

For areas only accessible to electrical staff (say within the substation) the 70kg equation may be used. !

GIS Transient Earth Potential Rise Conditions

It is often the case that in GIS installations the shock circuit contains no additional series impedance. It is, therefore, recommended that the same voltage criteria as for hand-to-hand conditions be applied. The Chapter on Transient Phenomena in the

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Earthing Reference Manual provides additional details on safety criteria based upon the energy rating. !

Fault Duration

Primary or backup protection - In larger transmission system substations with very fast duplicated protection systems it is considered reasonable to use the primary system fault clearance times. In older subtransmission system substations there is a case for considering the effect of the failure of a single primary protection. In public locations with high exposure to people and possibly slower clearing times, it is considered prudent to attempt to comply with backup protection clearing times. Reclosing - On overhead lines with fast auto reclosing systems the sum of the two fault clearing times is used. If manual or time delayed auto.-reclosing is used (eg. cable systems) it is acceptable to only use the first trip clearance time. Stepped faults - The non simultaneous operation of circuit breakers causes a ‘step’ in the fault current as discussed in Section 6.4.2. !

Calculation of Expected Touch and Step Voltages

The following chapters provide the means to calculate the expected prospective touch and step voltages. Several points are worth clarifying at this stage: !

Fault Current

Grid Current The fault current giving rise to the touch or step voltage hazards is that current being conducted to earth by the primary and secondary earthing system (ie. grid to remote earth current); not the prospective maximum earth fault current. Chapter 6 provides some guidelines for calculation of the zero sequence current distribution. Direct Current Offset The presence of a D.C. component in the fault current is also incorporated via a correction factor (see Section 6.5). The effective fault current is increased by a factor depending upon the fault clearing time and the specific X/R ratio for the location. !

Fault Impedance

It is reasonable to include a certain amount of fault impedance, according to the system configuration at the fault point (eg. timber poles with timber cross arms compared to metallic or reinforced concrete transmission towers). Arcing faults should be assumed to have zero resistance.

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Fault Locations

Fault locations on the primary and secondary sides, both inside and outside the substation should be investigated.

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5 Soil Resistivity Testing, Interpretation And Modelling When designing an earthing system to meet safety and reliability criteria, an accurate resistivity model of the soil is required. The following sections outline the major practical aspects of the measurement procedure and result interpretation.

5.1

Principles Soil resistivity values in the Australian continent are widely varying depending on the type of terrain, eg, silt on a river bank may have resistivity value in the order of 1.5Ωm, whereas dry sand or granite in mountainous country areas may have values higher than 10,000Ωm. Factors that affect resistivity may be summarised as;! ! ! ! ! !

Type of earth (eg, clay, loam, sandstone, granite) Moisture content; resistivity may fall rapidly as the moisture content is increased, however, after a value of about 20% the rate of decrease is much less. Soil with content greater than 40% do not occur very often. Temperature; above freezing point, the effect on earth resistivity is practically negligible. Chemical composition and concentration of dissolved salt. Presence of metal and concrete pipes, tanks, large slabs, cable ducts, rail tracks, metal pipes and fences, etc. Topography; rugged topography has a similar effect on resistivity measurement as local surface resistivity variation caused by weathering and moisture.

When defining the electrical properties of a portion of the Earth, a distinction between the geoelectric and geologic model is required. In the geoelectric model the boundaries between layers are determined by changes in resistivity, being primarily dependent upon water and chemical content, as well as texture. The geologic model, based upon such criteria as fossils and texture, may contain several geoelectric sections. The converse is also common. As earthing systems are installed near the surface of the Earth, the top soil layers being subject to higher current densities are the most significant and require the most accurate modelling. The Wenner [34] and Schlumberger [35] test methods are both recommended, with testing and interpretation techniques detailed in the Earthing Reference Manual, and summarised in the following sections.

5.2

Soil Resistivity Testing Procedure Guidelines The purpose of resistivity testing is to obtain a set of measurements which may be interpreted to yield an equivalent model for the electrical performance of the earth, as

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seen by the particular earthing system. However, the results may be incorrect or misleading if adequate investigation is not made prior to the test, or the test is not correctly undertaken. To overcome these problems the following data gathering and testing guidelines are suggested:

5.2.1 Initial Data Gathering An initial research phase is required to provide adequate background, upon which to determine the testing program, and against which the results may be interpreted. Data related to nearby metallic structures, as well as the geological, geographical and meteorological nature of the area is very useful [3], [19]. For instance the geological data regarding strata types and thicknesses will give an indication of the water retention properties of the upper layers and also the variation in resistivity to be expected due to water content. By comparing recent rainfall data, against the seasonal average, maxima and minima for the area it may be ascertained whether the results are realistic or not. For small installations the resistivity fluctuations may significantly affect the earth system impedance.

5.2.2 Resistivity Testing A number of guidelines associated with the preparation and implementation of a testing program are summarised as follows: !

Test Method

Factors such as maximum probe depths, lengths of cables required, efficiency of the measuring technique, cost (determined by the time and the size of the survey crew) and ease of interpretation of the data need to be considered, when selecting the test type. Three common test types are shown in Figure 5-1. The Schlumberger array [3] is considered more accurate and economic, than the Wenner or Driven Rod methods, provided a current source of sufficient power is used.

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Figure 5-1:

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Resistivity Test Probe Configurations

In the Wenner method all four electrodes are moved for each test with the spacing between each adjacent pair remaining the same. With the Schlumberger array the potential electrodes remain stationary while the current electrodes are moved for a series of measurements. In each method the depth penetration of the electrodes is less than 5% of the separation to ensure that the approximation of point sources, required by the simplified formulae (Section 5.2.3), remains valid. !

Selection of Test Method Type

When planning a soil resistivity survey factors such as: maximal probing depth, length of cables required, efficiency of the measuring technique, cost determined by the size of the survey crew and ease of interpretation of the data need to be considered. Each electrode array has specific advantages as explained below:

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Wenner Array If the test apparatus is underpowered or has limited ability to detect low voltage, then the Wenner array [34] is most effective as it is the most efficient in terms of the ratio of received voltage per unit of transmitted current. However, the Wenner array is the least efficient from an operational perspective. It requires the longest cable layout, largest electrode spreads and for large spacings one person per electrode is necessary to complete the survey in a reasonable time. Also, because all four electrodes are moved after each reading the Wenner array is most susceptible to lateral variation effects. Where unfavourable conditions such as very dry or frozen soil exist, considerable time may be spent trying to improve the contact resistance between the electrode and the soil. Schlumberger Array Economy of manpower is gained with the Schlumberger array [35] since the outer electrodes are moved four or five times for each move of the inner electrodes. The reduction in the number of electrode moves also reduces the effect of lateral variation on test results. Considerable time saving can be achieved using the reciprocity theorem with the Schlumberger array when contact resistance is a problem. Since contact resistance normally affects the current electrodes more than the potential electrodes, the inner fixed pair may be used as the current electrodes, a configuration called the ‘Inverse Schlumberger Array’. Use of the inverse Schlumberger array increases personal safety when a large current is injected. Heavier current cables may be needed if the current is of large magnitude. The inverse Schlumberger reduces the heavier cable lengths and time spent moving electrodes. The minimum spacing accessible is in the order of 10m (for a 0.5m inner spacing), thereby, necessitating the use of the Wenner configuration for smaller spacings. Lower voltage readings are obtained when using Schlumberger arrays. This may be a critical problem where the depth required to be tested is beyond the capability of the test equipment or the voltage readings are too small to be considered. Driven Rod Method The driven rod method (or Three Pin or Fall-of-Potential Method) [23] is normally suitable for use in circumstances such as transmission line structure earths, or areas of difficult terrain, because of: the shallow penetration that can be achieved in practical situations, the very localised measurement area, and the inaccuracies encountered in two layer soil conditions [19]. !

Traverse Locations

A resistivity test traverse consists of taking measurements for a series of probe

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spacings located in a straight line (co-linear array) to comply with the assumptions upon which the simplified Formulae are based. The traverse locations are designed to provide data on the vertical and horizontal resistivity variations over an area several times larger than the proposed earthing system. It is usual to use orthogonal traverses as a check, and to indicate the presence of vertical layering. Larger earthing systems require a greater number of traverses ($4). It is also useful to include a ‘check’ traverse near to, yet beyond the influence of the grid. Measurements are re-made on this traverse when undertaking an injection test on the installed grid, to correlate the test results with the initial measured conditions at the time of design. !

Spacing Range

The range of spacings recommended includes accurate close probe spacings ($1m), which are required to determine the upper layer resistivity, used in calculating the step and touch voltages, to spacings larger than the radius or diagonal dimension of the proposed earth grid. The larger spacings are used in the calculation of remote voltage gradients and grid impedance. Measurements at very large spacings often present considerable problems (eg inductive coupling, insufficient resolution on test set, physical barriers) they are important if the lower layer is of higher resistivity (ρ2 > ρ1). In such cases considerable error is introduced if a realistic value of ρ2 is not measured due to insufficient spacing. !

Practical Testing Recommendations

It has been found that special care is required when testing to: •

• • • •

Eliminate mutual coupling or interference due to leads parallel to power lines. Cable reels with parallel axes for current injection and voltage measurements, and small cable separation for large spacings (>100m)) can result in errors. Ensure the instrumentation and setup is adequate (ie equipment selection criteria, power levels, interference and filtering), Undertake operational checks for accuracy (ie, a field calibration check), Reduce contact resistance (use salt water, stakes and/or the reverse Schlumberger), Instruct staff to use finer test spacings in areas showing sharp changes (ie to identify the effect of local inhomogeneities and give increased data for interpretation). Plot test results immediately during testing to identify such problem areas.

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5.2.3 Result Interpretation And Modelling ! Design Step 2

Apparent Resistivity Calculation

In homogeneous isotropic earth the resistivity will be constant. However, if the earth is non homogeneous and the electrode spacing varied, a different value of resistivity (ρa) will be found for each measurement. This measured value of resistivity is known as the apparent resistivity. The apparent resistivity is a function of the array geometry, measured voltage (Δv), and injected current (I). For the arrays described in the previous section the apparent resistivity is found from the field measurements using the following formulae. Wenner array

aw

v I  2 a R

= = = = =

apparent resistivity (Ωm) probe spacing (m) voltage measured (volts) injected current (Amps) measured resistance (Ω)

aw  2a

(5-1)

Where ρaw a Δv I R

Schlumberger array

as 

 L2 R 2l

(5-2)

Where ρas l L R

= = = =

apparent resistivity (Ωm) distance from centre line to inner probes (m) distance from centre line to outer probes (m) measured resistance (Ω)

Driven Rod

ad 

2lR  8l  ln    d

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(5-3)

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Chapter 5

Soil Resistivity

31

Where ρad l d R

= = = =

Apparent resistivity (Ωm) Length of driven rod in contact with earth (m) Driven rod diameter (m) Measured value of resistance (Ω)

!

Interpretation of Resistivity Measurement

The result of each resistivity test traverse is a value of apparent resistivity for each spacing/configuration used. The interpretation task is the determination of presence of layers of material of common resistivity. Both curve matching and analytical procedures may be used to identify the presence of resistivity layering (e.g. vertical, horizontal or dipping beds). Figure 5-2 shows several typical apparent resistivity curves. C

C C C

Graphical curve matching [33] is useful for field staff to detect anomalies and identify areas requiring closer examination and testing. However, the use of graphical curve matching is limited to soils of 3 layers or less. Computer based techniques are best used to identify two or more soil resistivity layers. Bad data is best eliminated or checked in the field, as statistical screening is only useful if a large number of traverses are made and the resistivity layering over the area is uniform . The use of weighted averaging techniques to determine an equivalent homogeneous soil model or average apparent resistivity values for each probe spacing is not mathematically sound. It is best to first obtain a resistivity model for each traverse and then make a decision upon which information to base the earthing system design.

It is recommended that a multi-layer model for apparent resistivity be generated. A two layer model yields significant benefits in both economy, accuracy and safety (see Chapter 7.6), these should identify the surface layer to about 1m and the average deep layer to the grid diagonal dimension. The multi-layer model is useful in providing more accurate information regarding the presence of lower resistivity layers, and hence optimising rod driving depths. However, the two layer model is considered sufficiently accurate for modelling the behaviour of grids in the majority of cases [4]. If more than two layers are identified, the lower layers are usually combined to form a two layer equivalent model. This is done because the surface potentials are closely related to the upper layer resistivity, whilst the grid impedance, which is primarily effected by the deeper layers, is not usually adversely affected by this simplification.

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Soil Resistivity

Figure 5-2:

Typical Resistivity Curves

Curve (A) Curve (B) Curve (C) Curve (D) Curve (E)

-

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32

Homogenous resistivity Low resistivity layer overlaying higher resistivity layer High resistivity layer between two low resistivity layers High resistivity layer overlaying a lower resistivity layer Low resistivity layer over high resistivity layer with a vertical discontinuity (typically a fault line).

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Current Distribution

33

6 Current Distribution Any earth fault situation may be seen to comprise three main components: the power system supplying fault energy, the earthing systems between which the fault energy flows, and the ‘ground’ as shown in Figure 6-1. In the Soil Resistivity Testing, Interpretation and Modelling Chapter (5) the methods for testing and modelling the electrical properties of the ‘ground’ are discussed. The resistivity analysis is the basis for determining the distribution of currents, and the voltages created. This chapter addresses issues associated with the power system supplying the earthfault fault energy to the point of fault. The fault current flow “in the ground” may be considered in two parts. The Power Frequency Voltage Design Chapter [7] addresses the conduction of fault energy in the vicinity of the faulted and return electrodes, while this chapter addresses the flow of zero-sequence current in the long path between electrodes. The magnitude of the fault current and its distribution in the earth and metallic return conductors is of prime importance for the following reasons: !

When designing safe earthing installations (eg. substations, transmission structures), the shock hazard is proportional to the magnitude of earth fault currents and time of exposure.

!

Calculating the electromagnetic induction into neighbouring “circuits” (eg. lines, cables, telecommunication circuits, pipelines, fences, railway lines, conveyors) to ensure safety for people and equipment [37], [38]. This problem is particularly significant in areas of high soil resistivity.

!

Making the correct choice for earth wires (size, type) in the light of fault energy magnitude and duration [36].

!

Determining optimal transmission structure configurations to: reduce losses, reduce surge impedance, balance line voltages and currents, reduce electric and magnetic fields, and reduce the amount of current returning through the soil [39].

While the latter three points mainly relate to transmission systems, it is impossible (and unwise) to ignore the interrelationship between the effects of fault currents in each of the fault current paths. Figure 6-1 illustrates the major fault energy transfer paths.

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Phase Conductors

Neutral Conductors Metallic Paths Soil Point of Fault Contact with 'Earth' Figure 6-1:

Fault Current Transfer Path

Fault Current Source(s)

Fault Current Transfer Systems

It is important to determine the earth fault current contributing to the maximum earthgrid potential rise (EPR) at a substation. A range of fault cases must be addressed and the fact that only a part of the total fault current usually flows between the earthing system and the surrounding earth has implications on both personnel safety and equipment requirements. The smaller value of the grid current results in a reduced earth potential rise, as opposed to using the total fault current. This means that the touch and step voltages are correspondingly lower. Because the EPR is lower, incoming communication circuits require less or lower rated protective or isolation equipment. This may result in cost savings on leased telephone lines, isolation neutralising transformers. The factors involved in calculating the maximum earthgrid current and, hence potential rise are addressed in the following sections: C C C C C

Calculation overview Worst case prospective fault current Faults inside the substation Faults outside the substation Fault current asymmetry

Figure 6-2 provides an overview of the topics covered in the chapter.

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Substation Earthfault Analysis

2.1 Calculation Overview

2.2 Worst Case Prospective

2.4 Faults Outside a Substation

2.3 Faults Within a Substation 1 2 3 4

Figure 6-2:

6.1

2.5 Fault Current Asymmetry

General Considerations Station Passive Station Active Stepped Fault Duration

Substation Earth fault Analysis Overview

Calculation Overview The analysis of maximum earth fault currents for substations needs to be co-ordinated with the overall design process. In this regard the earth fault currents are required for three main reasons: conductor sizing, personal hazard determination, and communication equipment rating under transfer and induction hazard conditions. The steps involved are summarised in the following Figure 6-3, showing calculations required and outcomes. Prospective Source Impedance (future maximum for known system augmentation)

Maximum Substation Fault Level

Fault Location Causing Maximum Current Grid-Earth

Inductive Energy Transfer

Transient Decrement Factor Calculations

Conductor Sizing

Figure 6-3:

Personnel Safety

Incoming Equipment Rating

Outcomes

Substation Earth fault Calculation Overview

Each of the steps shown in Figure 6-3 are briefly introduced below then developed in Sections 6.2 - 6.5 following.

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6.1.1 Prospective Source Impedances Section 6.2 establishes the procedures to determine the worst case ground current to be considered. The worst case prospective fault current is based on future maximum fault duties for the prospective future system augmentation.

6.1.2 Conductor Size Due to the large cost involved in replacing grid conductors, compared to the small incremental cost for material charges during installation, it is wise to take a “conservative” approach when sizing grid conductors. Therefore, the maximum prospective future fault level which allows for future additional transformer capacity and possible additional circuits is used to determine the maximum fault current the conductors must carry for each bus/voltage. The Installation Chapter (10) provides further details regarding sizing philosophies and conductor thermal withstand calculations. For most cases the highest current results from a bus fault on the primary or secondary of the substation. While this current may not create significant EPR, it will flow through the grid risers thus making it the significant dimensioning current. It is usual to ignore both the earth grid and local fault impedance (i.e arc impedance) in the calculation of this current.

6.1.3 Personnel Safety The safety of personnel and the public is a vital part of any earthing system design procedure. The voltages that may be experienced under fault conditions, are discussed in the Power Frequency Voltage Design Chapter (7). It is generally true that the maximum touch voltage that may be experienced, is the value of the grid EPR under transfer voltage conditions. Therefore, calculation of the maximum EPR is seen as the first step in determining the safety hazard levels. The current that contributes to creating the maximum EPR may come from a fault inside or outside the substation. Sections 6.2, 6.3 and 6.4 address the calculation methods which include the following issues: !

Faults Within Substations C C C C

!

Primary Faults Transformer infeed Primary earthing system impedance (See Section 7.1.1) Secondary earthing system impedance (See Section 7.1.2)

Faults Outside Substation C C C C

Primary or secondary side Fault impedance - conductive coupling Transformer infeed Inductive coupling

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At the inception of a fault the D.C. offset increases the effective current with values given for the effective increase for a range of system X/R ratios in Section 6.5.

6.1.4 Incoming Equipment Rating Equipment terminating within the substation, (such as telecommunications cables), are subject to the full earth potential rise during earth fault conditions and, therefore, require the same calculations as those undertaken for personnel safety [77], [103], [104]. Suitably rated protective devices are sometimes required for personnel safety, and for the protection and continuity of service of wireline telecommunication facilities. Three points are made concerning the calculations regarding the necessity for, and specification, of isolation equipment: !

Inductive Energy Transfer

Under certain fault conditions and equipment (eg. cable) configurations, the fault energy can inductively couple a voltage onto the equipment. This voltage may add to the EPR, giving rise to the possibility of the transfer of voltages higher than the EPR to remote locations. !

Transient Decrement Factor

Most modern telecommunications equipment is susceptible to transient voltages and, therefore, requires adequate protection. Thus, the peak transient voltage is required to be calculated or taken into account as shown in Section 6.5, or by using conservative assumptions, such as assuming the peak voltage to be 2p2 times the symmetrical component. !

Equipment Operation

Some equipment (eg. pilot protection circuits) is required to continue to operate during system faults. In such critical cases the isolation/protection design should be given special attention. The foregoing comments point to the need for special isolation and the difficulty in accurately calculating the interference parameters. In many instances a standard design based upon one common purchase specification will meet requirements. If the standard design margins are exceeded following simple calculations, then detailed calculations may be necessary to produce a cost effective design. The ESAA CJC ‘Earth Potential Rise’ Code of Practise [77] is used within Australia.

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Chapter 6

6.2 DESIGN STEP 4

Current Distribution

38

Worst Case Prospective Fault Current The simplest estimation of fault current is that of the total line-ground or line-line-ground fault current at the fault point (ie. ignoring the effect of alternative current paths). Thus, normal equations concerning symmetrical components, may be used and the grid/fault impedance is often assumed to be zero (see Earthing Reference Manual - Current Distribution Chapter). The EPR for this current is then calculated using simple formulae (Design Step 8). If this ‘conservative’ estimate yields acceptable EPR results, then there is little point in making further current distribution calculations (apart from OHEW dimensioning or inductive interference calculations). Loadflow or fault calculation programs are often used to provide a maximum current value. This value is used in calculating a maximum EPR, for telecommunications coordination (also apply a D.C. offset), or as an initial approximation in the design process. The following guidelines are commonly adopted when calculating the initial Maximum Grid Current: !

Substation Primary Faults ! ! !

!

Ignore grid impedance Use future ultimate fault current levels, only for conductor sizing calculations, or as an initial ‘first pass’ estimate EPR. Use realistic future (staged development) calculations for personnel safety hazard determination.

Substation Secondary Faults ! !

Use ultimate fault current levels only for conductor sizing. Consider likely fault impedance scenarios when determining personnel hazard levels. Thus, the assessment of fault impedance to cable fed or overhead lines is important (eg. cable fed, kiosk substation - Rfault # 5Ω). Section 6.4 following addresses this question in a general way, with the Current Distribution Chapter of the Earthing Reference Manual providing a detailed discussion of the issues and equations.

The next two sections provide information to assist in ascertaining the values of fault currents for faults inside and outside the substation, taking alternative source and return paths into account. To determine the actual component of fault current entering the earth via the earthgrid depends upon the following factors: i)

Whether the fault occurs inside or outside the station;

ii)

Whether the station, as seen from the fault location, is active or passive; that is, whether or not the station transformers represent voltage sources in the system where the fault occurs.

Since each of i) and ii) may have two outcomes, there are four possible combinations

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Chapter 6

Current Distribution

39

to be considered. However, the two that involve a fault located inside the station do not differ with respect to determination of Igmax. Three cases remain, therefore, that require consideration, and these will now be addressed.

6.3

Faults Within Substation In the case of an earth fault at a station the total earth-fault current IFO (i.e. the current in the earth conductor of the failure point) is divided along the grid earthing electrode of the station with parts flowing through the neutral of the earthed transformer(s), the earth wires (or cable sheath) of the line, and the earth, as shown in Figure 6-4 following, from Fortin [10]. !

The current (IFO) circulating through the neutral of the transformer is determined according to the impedance of the transformer and the neutral earthing reactor, if any.

!

The current (IRO) flowing along the phase of the line mutually induces a current in the earth wire(s).

!

At the station a part (ΣIp) of the total ‘conductive’ current flowing to the earth (νIRO) flows through the earth wires and towers of the line. This effect of the near towers is included in the measured earth impedance (Zt) of the station. The ‘input impedance’ (seen from the station) of the chain composed by the earth wires and tower earthing is in parallel with the earth impedance of the grid earthing electrode (and other auxiliary electrodes, if any).

Figure 6-4 presents the simplest case. Fault current (IFO) is formed by a current coming from the network (IRO) and current coming from the transformer (ITO). An index ‘x’ maybe added to indicate the distance between the substation under study and the point where the fault occurs. In the present case, x = 0 (ie. inside substation) and the fault current is written:

I FO  I RO  I TO

(6-1)

Current ITO circulates in the grid conductors and does not cause any earthgrid potential rise. This current , however, must be included when sizing grid conductors. In a similar way, a portion of current, Iin, returns to the source by induction on the neutral conductors of the line (ie, OHEW or cable sheath) as follows:

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Chapter 6

Current Distribution

Figure 6-4: IFO ITO IRO Ipi It μIRO υIRO Ip1

= = = = = = = =

40

Fault Energy Distribution: Fault Inside the Substation Fault Current Current fed by the transformer Current fed by the network Current in one of the towers Current circulating through the grid to remote sources Induced current Current responsible for the potential rise Conducted current through the first tower.

I in  I RO

(6-2)

The current (Iept) responsible for the potential rise, going through the earthing system impedance includes the effect of all conductive currents flowing to earth (ie, include OHEW effect).

I ept

   

It 

 I pi

1   I RO

(6-3)

vI RO v I RO  I TO 

If many lines contribute to the fault, the current responsible for the potential rise, going through the earthing system impedance is:

I ept



 vi

I ROi

(6-4)

If there is more than one line coming to the station, the right half of Figure 6-4 applies to each line feeding earth-fault current (i.e. active lines). The earth wires of the lines

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not feeding earth-fault current passive lines) have effect only by reducing the earth impedance of the station. Thus, the ‘impedance’ seen by this ‘conductive’ current (Iept) is formed by the parallel combination of all impedances connected to the main grid as discussed in Section 7.1.5. Section 3 on Transmission System Earth fault Analysis in the Current Distribution Chapter of the Earthing Reference Manual provides details regarding the current distribution in lines. The following section provides an overview of calculation methods used.

6.3.1 Calculating Induced Current Flows DESIGN STEP 9

In many cases analysis of fault current distributions in overhead earth wires (OHEW) and cable sheaths is required to determine the real potential rise at substations and power line structures, also to calculate the induced voltages in other circuits (eg. communications lines, conveyors or pipelines), and to determine errors and correction factors in injection testing result interpretation. A technique known as the decoupled method, from Sobral et al [44], [45] and Dick [48] may be utilised, which separates the fault current in the overhead earthwire (OHEW) or cable sheath into two components, one induced by the magnetic field generated by the fault current in the line, and another conductive component which will seek the path of least resistance to the imaginary earth return conductor. The induced component is constant and calculated using mutual couplings from Carson [46] and Wedepohl [49]. Current sources may be used at both ends of each ‘uniform line section’ to model the induced current component. This approach requires a greatly reduced matrix, yet yields accurate results. Couplings to buried structures such as pipelines, railway lines, conveyors and fences are handled in a similar manner to insulated telecommunications lines, except for the addition of voltage sources which model the conductive couplings through the soil. Hazard mitigation by the installation of earths of adjacent shielding circuits may also be modelled in this manner. Typical cases yield current injected into the primary earthing system of between 10-30% of total fault current (IFO), as underground cables or continuous overhead earthwires (OHEW) often carry the majority of the return current. The Earthing Reference Manual Current Distribution chapter provides the formulae required.

6.3.2 Small Industrial Substation Example A small area substation in a congested area of an industrial installation was designed using the foregoing analysis techniques. The inductive and conductively coupled currents returning via the OHEW and cable sheath of the supply feeder reduced the current to be dissipated in the grid by 72% Figure 6-5 provides an overview of the most significant currents measured. One particular direct buried pipeline running near the substation created a transfer hazard, with a touch voltage of 44% of EPR, was only able to be reduced to within the allowable safety criteria by specially designing the line to maximise the inductive current flow returning to the source in the OHEW.

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DESIGN STEP 9

Chapter 6

Current Distribution

Figure 6-5:

6.4

42

Industrial Substation Fault Current Distribution

Faults Outside The Substation The determination of fault current contributing to an earth potential rise for faults outside the substation is covered in the following sections: 1. 2.

General Considerations Fault duration with stepped faults.

6.4.1 General Considerations For faults outside the substation the current supplied by the earthed transformer(s) of the station should be taken into account, and also the fault currents from behind the station, in case the screening factors deviate from each other. The earth-fault current IFX has its maximum in the case of an earth fault in the immediate proximity of the station, however, this is rarely the fault point causing maximum EPR. When the fault occurs a few spans outside the station and the line is equipped with overhead earthwires, the current through the substation earth grid may be smaller than during faults within the station, depending on the relative significance of the contribution from the transformers at the station and the contribution from elsewhere in the system. i)

A greater part of the zero sequence current supplied by the system will flow through the tower footings, due to the higher voltages developed at towers near the fault.

ii)

A part of the zero sequence current supplied by the station transformers will return through the station earth grid.

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Current Distribution

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In this case more current than the share (1 - νa)Iea corresponding to the shield-wire screening-factor effect returns along the shield wires. With a fault point farther away the current Iea itself remains lower.

There is a line fault point implying highest rise of transmission station earth potential. In practice, it can be conservatively assumed that this point is located at a distance 1.5 < i < 5km from the station. Thus, the current flowing through the station earthing impedance may be calculated in the presence of many lines, as illustrated in Figure 6-6. And for a fault at a distance ‘x’ outside the substation, the following equations can be written:

I FX



I Ra  I Rb

(6-5)

I Ra



I R1  R R 2  I Tx

(6-6)

I ept



I Tx  a I Ra  1 I R1  2 I R 2 va I Ra   vi I Ri

(6-7)



Figure 6-6:

Fault Outside the Substation

Where x μiIi υiIi

= = =

Distance between the substation and the point of fault Induced current Conducted current

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Details of the calculation methods for passive and active transformer cases are provided in the Earthing Reference Manual Current Distribution Chapter.

6.4.2 Fault Duration With Stepped Faults While the previous sections addressed the issue of the magnitude of the EPR created, the duration is just as critical when determining safety criteria for people as the permissible voltage depends on duration of the fault. However, the current magnitude may change during the fault duration (eg. because of the opening of a circuit-breaker at the opposite end). For the highest current its real duration should be used, and for the total fault time the equivalent r.m.s. value of the current may be taken as suggested in [40]:

3I 0eq 

3I 01 2 t1  3I 02 2 t 2   t1  t 2  

(6-8)

Where t1 is the duration of 3I01, t2 the duration of 3I02, etc. An earth fault may be repeated after high-speed reclosing in the event of a permanent fault. Permanent line faults often have a high resistance and a lower fault current. Reclosing is often prevented when closing a circuit-breaker against a fault. If the statistics show that more than 20% of the earth-fault incidents are repeated after high-speed reclosing in the power system concerned, the sum of the times may be considered as the total time.

6.5

Fault Current Asymmetry The asymmetrical nature of earth fault currents was introduced in Section 6.1. The following sections address the effect and application of this asymmetrical nature in practice. All of the preceding discussion on determination of the maximum current creating an EPR has dealt specifically with rms symmetrical fault current. Actually, the fault current has decaying A.C. and D.C. components, resulting in the asymmetrical current waveshape shown in Figure 6-7, from Garrett in [43], where If and IF are the initial fault current and the ‘effective’ rms symmetrical current respectively.

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Current Distribution

Figure 6-7:

45

Relationship between actual values of fault current and values of IF, If and Df for fault duration tf.

The work by Dalziel and others was based on rms symmetrical current in determining the tolerable body current. Thus, a calculation is needed to convert the actual asymmetrical fault current to the rms symmetrical fault current upon which the shock equations are based. IEEE 80(86)[18] recommends that the following ‘decrement factor’ be used to scale the fault current to derive an equivalent ‘energy’ when determining a value of EPR for human safety hazard assessment. This equation allows for the D.C. offset but no allowance for reduction of the A.C. value due to machine characteristics. Df = Symmetrical decrement factor

Df

   1  Ta t f 



1



  1  e  

 t f     Ta 

2    

(6-9)

where Ta

=

Ta  tf ω

Equivalent system subtransient time constant

X secs) R = =

Fault duration (secs) Angular rotation - 2πf

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Current Distribution = =

46

Frequency in Hz System subtransient impedances

This equation conservatively assumes; maximum D.C. offset, subtransient impedances only contribute, and that the ac component of the fault current does not decay. Table 6.1 provides decrement factor results for 50Hz earth fault conditions and a range of X/R ratios: Table 6.1 Decrement Factor Df for Various X/R Ratios at 50Hz Decrement Factor Df

Fault Duration tf(sec)

X/R = 10

X/R = 20

X/R = 30

X/R = 40

1.37

1.392

1.399

1.403

.05

1.226

1.301

1.334

1.352

.10

1.142

1.226

1.273

1.301

.20

1.076

1.142

1.191

1.226

.30

1.052

1.100

1.142

1.176

.40

1.039

1.076

1.111

1.142

.50

1.031

1.062

1.091

1.118

.75

1.021

1.042

1.062

1.081

1.00

1.016

1.031

1.047

1.062

.00833

The fault current has an initial asymmetry or D.C. offset determined by the initial point on wave. Higher fault currents near generation or rotating machines may have a reducing rms value due to the machine characteristics. It is normal to ignore the reduction in the initial rms value for earthing design. When the fault duration is less than 0.5 seconds, and particularly with high X/R system impedance ratios, the rms value of current used in determining EPR safety criteria and telecommunications coordination should be increased. From Table 6.1 it can be seen that for very fast clearing times (# 0.1 secs) a factor of 40% is calculated with X/R = 40.

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Power Frequency Voltage Design

47

7 Power Frequency Voltage Design When designing earthing systems it is necessary to determine the power frequency performance of the system with respect to earthgrid impedance, EPR, step, touch, and transfer potentials. In the pursuing sections, situations associated with large substations are identified and problem mitigation methods introduced, as shown in the following Figure 7-1: 7 Power Frequency Voltage Design

7.2 Earthgrid Potential Rise

7.1 Earthing System Impedances

1 Primary Earthing System Impedances 2 Auxiliary Earthing System Impedances 3 Aerial Conductors 4 Buried Conductors 5 Combination of Earthing Systems 6 Proximity Effect

Figure 7-1:

7.1

7.4 Transfer Voltages

7.3 Touch and Mesh Voltages

1 Voltages Inside Substation 2 Voltages External

7.6 Empirical/Analytical Calculation Comparison

7.5 Voltage Gradients

7.7 Voltage Mitigation Methods

1 Within and Close to Substation 2 External to the Substation

1 Primary Source Hazard Prevention 2 Secondary Effect Mitigation

Power Frequency Voltage Design - Overview

Earthing System Impedances Simplified empirical expressions and more accurate analytical modelling techniques for determining the impedance of earthing systems are included in the following section. Various forms of electrodes are used for earthing electrical power system plant. Electrodes may be divided into two main categories as defined below [18]. Primary earth electrode. An earth electrode specifically designed or adapted for discharging the earth fault current into the ground, often in a specific discharge pattern, as required (or implicitly called for) by the earthing system design. Earth grids, counterpoise conductors and earth rods are typical primary electrodes.

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Auxiliary earth electrode. Various metallic structures installed for purposes other than earthing. Such electrodes often have special operating constraints, such as limited current carrying capability. Underground metallic structures, overhead earthwires, underground cable sheaths and reinforcing bars encased in concrete, if connected to the grounding grid, may also form auxiliary electrodes. An alternative name is that of secondary earthing electrode or system. The earth resistances of individual electrode types and combinations are discussed in the following sections.

7.1.1 Primary Earthing System Impedances The three main types of electrodes used as primary earthing systems for substations are as follows: 1. 2. 3.

Driven rods Buried conductors Combination of rods and buried conductors.

Buried cast iron plates, iron bars and ‘coke’ beds were used in certain situations in the past. However, due to high installation costs and maintenance expenses, they are now rarely used. Coke beds are still used in conjunction with d.c. earthing electrodes as outlined in Chapter 9. Simplified formulae for use in the initial investigation suggested in Design Step 3 are given in Section 7.1.1.2.

7.1.1.1 A)

Driven Rods

Single Rod or Earth Stake

Derivation of the impedance of a single earth rod driven vertically into homogeneous soil is included in [29], [33], [63], [64]. RR = Resistance of driven rod (Ω)

RR 

 2l

 8l  ln d  1

(7-1) (7-2)

where ρ l d

= = =

Soil resistivity (Ωm) Rod length (m) Rod diameter (m)

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Power Frequency Voltage Design

B)

Multiple Driven Rods

!

Effect of Mutual Resistance

49

As the current paths associated with multiple rods are not independent of each other, the resultant impedance is not the simple parallel combination of individual resistances. Proximity affects the mutual resistance between electrodes affecting the performance, as the nomogram in Figure 7-2 illustrates [106]. The nomogram provides an estimate of the resistance of systems where the rods are driven, in line, around the perimeter of a square, or forming a solid square with spacing equal to rod depth. The electrode spacing should not be less than the electrode length.

Figure 7-2:

Earth Resistance of Multiple Driven Rods

The nomogram may be used for rectangular sites, with the same number of rods, if the narrower site dimension is greater than three rod lengths. Example 1. For two 5m rods, each 10 Ω individual resistance, spaced 5m apart, the combined earth resistance from Figure 17 is, Rc = 6 Ω, ie. 83% utilisation. According to [24] for 10m spacing the value of combined resistance is, Rc = 5.4 Ω, ie, 92% utilisation is achieved. Therefore, rods should always be driven with spacings at least equal to the driven

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depth to obtain best performance in homogeneous soils. If the soil resistivity is subject to seasonal variations special care should be taken to ensure adequate contact with a conductive soil. Example 2. The effect of using electrodes in a ‘solid square’ compared to a ‘hollow square’ configuration is illustrated for 5m rods in a 45 x 45m area. The use of a ‘solid square’ of 100 electrodes against 36 rods placed around the perimeter, only gives a resistance reduction factor of 1.24 from 0.62Ω to 0.5 Ω. A negligible resistance improvement compared to the expense involved in increasing the rod number by a factor of 2.8. Therefore, the number, depth and placement of rods should be carefully considered if optimum cost effectiveness is to be achieved. !

Single Layer Conditions

The following formula derived by Schwarz [66] for uniform soil resistivity conditions, relates to equally spaced rods.

 2nl

2l  8l K1 1 ln    d A 

ρ A n K1

= = = =

l d

= =

Soil resistivity (Ωm) Area covered by rod bed (m2 ) Number of rods Constant related to geometry of system (see Figure 7-3, where h = depth of top of rods). Rod length (m) Rod diameter (m)

RR 



2 n1  



(7-3)

where

(Note: A linear approximation to the K1 (curves from [18]) is also given in Figure 7-3.) The difficulty in adapting the graphical form of the K1 co-efficient for computer use was met by Kercel [56] who applied Equation 39 of Dwight [63], relating the rectangular plate resistance, to develop: K1 

 ln  a  ab 184 .    2 a 

a 2  b 2  ln  b   b b  



a 2  b2 a 2  b 2  a b     3b 2 3a 2 a 3a 2 b 2 



 a 2  b 2  (7-4)  

where a b

= =

Length of short side of grid (m). Length of long side of grid (m).

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Curve A - for depth h = 0 γA = -0.04 x +1.41 Curve B - for depth h =

1 10

A rea

γB = -0.05 x +1.20 Curve C - for depth h =

1 6

A re a

γC = -0.05 x +1.13

Figure 7-3: !

Coefficient K1 of Schwarz’s Formula

Two-Layer Earth Conditions

The following formula, from Sverak [69], further approximates the rodbed resistance (RR) when the rods penetrate the lower layer, providing the following assumptions are complied with: ρ2 $0.2ρ1 H $ b/10

(i.e. layer resistivity differences not extreme and lower layer more conductive.) (i.e. first layer of substantial thickness but less than the rod length.)

a 2n

RR 

l   8l   ln  d   1  2 K1 A 



2 n1  



(7-5)

This formula is the same as for single layer conditions, however, the apparent resistivity ρa is calculated as follows. ρa ρa

= =

Apparent soil resistivity seen by one earth stake (Ω.m) (l ρ1ρ2) /(ρ2 H + ρ1(l - H))

l ρ1 ρ2 H

= = = =

Length of rod (m) Upper layer resistivity (Ωm) Lower layer resistivity (Ωm) Thickness of uppermost resistivity layer (m)

(7-6)

where

for rod top burial = 0m

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If the rod top is buried a distance (L), the expression for apparent resistivity becomes:

l12  / 2  H  h  1  l  h  H 

a  Where

h

(7-7)

= Rod top burial depth.

The use of driven rods is of limited value in substations covering large areas of low resistivity soil, as the station ‘area’ provides sufficient ‘earth contact’ to dissipate the fault current. However, for substations of small area located on high resistivity soil, rods which penetrate to a lower resistivity layer often provide an economical system design. Such rods ensure consistent low resistance in areas where the top layer resistivity experiences seasonal variations. In such areas the top layer may freeze or be effected by drought, therefore, the horizontal mesh conductors will dissipate little current compared to the driven rods. To gain maximum benefit from any driven rod it is recommended that an accurate earth resistivity test be undertaken and a multilayer model derived (where applicable).

7.1.1.2

Horizontal Grid Electrodes

Buried bare conductors in a mesh configuration are used to: ! ! !

provide surface gradient control, bond substation equipment, provide the primary substation earthing system,

Approximate resistance equations are introduced in the following sections for both single and double earth resistivity layer conditions. A)

Single Layer Conditions

Minimum and maximum estimates as well as approximate guidelines regarding the effect of the number of meshes upon grid resistance and discussed as follows; ! DESIGN STEP 3

Minimum Resistance Value

A minimum value is useful when estimating the maximum component of fault current that will enter the earth grid. This value is based upon the resistance of a solid plate on the earth surface [29]. RG

=

Earthgrid impedance (Ω)

 

RG 

4

(7-8)

A

where ρ

=

Average soil resistivity (Ωm) (at depth approximately equal to

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equivalent radius for the area of the site). Area covered by the grid (m2)

=

This minimum value is useful when estimating the maximum component of fault current that will enter the earth grid i.e. Il-g (max) = Vfault / Rg (min) Maximum Resistance Estimate

! DESIGN STEP 3

(7-9)

Methods are proposed by Nehmann and Laurent, and used in [62], [69], to account for the fact that a meshed earthing system impedance is higher than that of a solid plate, as a function of conductor length. The additional term is an ‘empirical factor’ with no analytical derivation. As ‘L’ goes to infinity the equation reverts to that for the solid plate.

    4 A L

RG 

(7-10)

where L

=

Total length of buried earthing conductor (m)

Sverak [69] introduced resistance approximations for horizontal grids buried between 0.25m and 2.5m (based upon a more detailed formula for the solid plate derived by Laurent [70]).

1 RG     L

1  1   1  20 A  h 20 / A  

(7-11)

where h !

=

depth of grid buried (m)

Conductor Length

The total length of horizontal mesh conductors and driven rods are used in Equations (7-10) and (7-11). As driven rods provide more effective earth contact, on a per unit basis [18], this calculation will yield a slightly conservative estimate of total conductor length. Equations (7-10) and (7-11) provide a simple technique for making a reasonable estimate of the grid resistance. !

Schwarz’s Formula

The equation developed by Schwarz [66], for horizontal buried conductors is as

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follows:

 1  RG     L 

  2 L  K1 L   K2   ln h    A  

(7-12)

where ρ1 d h

= = =

h’ L A K1

= = = = =

K2

=

Resistivity of the soil layer in which the grid buried (Ω-m) Grid conductor diameter (m). Depth of burial (m).

d . h - for conductors buried at depth h. 0.5d - for conductors on the earth’s surface. Total length of grid conductor (m). Grid area (m2) Grid geometry related constant - Section 7.1.1.1 B - Figure 7-3 and Equation 7 - 4). Grid geometry related constant (see Figure 7-4 and Equation 7-13 following).

The estimate by Kercel [56] of K2 (see Equation (7-13)), for computer rather than graphical applications, is based on work by Gross et.al [73]. !

Guidelines Regarding Number of Meshes

As Equations (7-11) and (7-12) indicate, if conductor length is increased to a maximum value of infinity, the minimum grid impedance of Equation (7-8) is achieved. However, the benefit gained in grid impedance reduction by increasing the number of meshes is very limited when compared to other methods. B)

Two-Layer Earth Conditions

Equation (7-8) provided an estimate of the minimum grid impedance for uniform soil conditions, based upon the resistance of a solid metallic plate. In two layer soils the resistance, at large distances, is predominantly affected by the lower layer, due to its larger volume compared to the upper layer volume. Therefore, as a first approximation Equation (7-10) may be used in conjunction with the lower layer soil resistivity (ρ2).

RG 2 layer   ρ2 ρ1 L A

= = = =

2



4

A



1 L

(7-13)

Lower layer soil resistivity (Ωm) Soil resistivity near conductors (ie 1m) (Ωm) Total buried length of conductors (m) Grid area (m2)

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Curve A - for depth h = 0 γA = 0.15 x +5.50 Curve B - for depth 1 Area h= 10 γB = 0.10 x +4.68 Curve C- for depth h = 1 6

Area

γC = 0.05 x + 4.40

Figure 7-4:

Coefficient K2 of Schwarz’s formula

Equations by Schwartz are simpler to use, however, they are limited in application to certain soil conditions, as described in Section 7.1.1.B). In exceptions to these cases, and as a useful check, other equations have been proposed by Nahman and Salamon and are included in the Earthing Reference Manual. K2  ln

a  a  b 4 a  b  2 K1  ln  b ab 

7.1.1.3

a 2   b / 2 2  1   b / 2  a 2   b / 2 2   ln  2    (7-14)  b / 2    b / 2  a 2   b / 2 2 

Combined Mesh And Rod Earthing System Resistance

Both simplified and detailed empirical formula have been developed to model the resistance of an earthing system consisting of both horizontal conductors and driven rods. Both cases have been discussed with reference to certain (limited) two-layer soil conditions. The effective resistance is greater than the sum of the rods and conductors if considered as resistances in parallel because of their mutual coupling. Schwarz established the following approximate formulae to determine all grid resistance.

RC

2 RG x RR  RGR  RG  RR  2 RGR

(7-15)

where RC RG RR

= = =

Total combined earth system resistance (Ω) Resistance of horizontal grid (Ω) Resistance of driven rods (evenly spaced over same area as grid) (Ω)

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Mutual resistance between the grid and rod (Ω)

Equations for RG and RR have been provided in the proceeding Sections 7.1.1.1 and 7.1.1.2. The following section provides an equation for determining the mutual resistance between grid conductors and driven rods. The following formula derived by Schwarz [60] has been modified by Sverak [69] for two-layer conditions using an apparent soil resistivity (ρa) as defined in Section 7.1.1.1 B) Equations (7-6) and (7-7).

RGR 

a L

  2 L  K1 L   K2  1  ln l   A  

(7-16)

Where ρa

=

K2

=

K1

=

L l A

= = =

Apparent soil resistivity (see Section 7.1.1.1 B) Equations (7-6) and (7-7)) (Ωm) Grid geometry related constant (see Figure 7-5 and Section 7.1.1.2 B) Equation (7-13)) Grid geometry related constant (see Figure 7-3 and Section 7.1.1.1 B)) Total horizontal conductor length (m) Average driven rod length (m) Grid area (m²)

7.1.2 Auxiliary Earthing System Impedances DESIGN STEP 11

The primary grid is not the only system affecting the apparent impedance of the earthing installation, even unconnected metalwork can affect the grid impedance. Auxiliary or secondary earthing systems provide additional paths for the conduction of fault current to remote earth, and hence lower the apparent impedance as seen by the fault. The fault current which the earthing system must dissipate will follow any path of low impedance. Hence, any additional metalwork bonded to the primary earthing system, will carry some of the fault current. These auxiliary earthing systems will then dissipate their proportion of fault current in areas where the current densities are not as high as in the vicinity of the primary installation. Design Step 11 consists of the calculation of grid impedance taking auxiliary earthing systems into account. An obvious example of auxiliary earthing systems are overhead earthwires, (or shield wires) which if bonded to the primary earth grid, provide a low impedance connection to each of the line support structure earths along the line. Each of the structure earths can dissipate a proportion of the fault current. Similarly, underground cables, usually have their metallic sheaths bonded to the primary grid. Hence, the sheaths of underground cables can also conduct fault current increasing the field of influence of the primary installation. The sheath and

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armouring may be effectively insulated or not. If insulated and not earthed at remote places the transferred voltage will not cause current to flow to ground. The auxiliary earthing system may include any of the following components: !

Aerial conductors; overhead shield wires, distribution system neutrals.

!

Buried conductors; underground power cable sheaths, counterpoise (direct buried) conductors.

!

Other components; pipelines (water, gas), metallic fences, concrete encased electrodes, and building foundations.

The first two components are common to most substations. The third component is usually associated with larger interconnected earthing systems, such as industrial installations or power stations. Such components need not be solidly bonded to the grid, to affect the grid performance as fault current is often coupled conductively through the soil into conductors running adjacent to substations. The aerial earthwires and buried conductors may have currents flowing due to; a) b)

Conductive currents due to ground voltage differences. Induced by mutual coupling.

In this section only the conductive current is considered as being relevant in reducing the station earth resistance.

7.1.3 Aerial Conductors Overhead shield wires and distribution neutrals are often bonded to the primary earthing system in a substation and, therefore, present parallel paths for earth fault currents. The question of whether or not to isolate such conductors should be addressed when developing Transmission Earthing and Distribution System Earthing policies. The sizing of such conductors, if bonded to the substation earthing system, must be considered in conjunction with the study of the fault current magnitude in both the power supply and earth return systems. The following section provides empirical formulae for the input impedance of an overhead shieldwire system. !

‘Infinite’ Line Length

The input impedance (Zia) of a ‘long’ aerial earthwire, pipeline or cable may be calculated quite reliably using the following formula, for a ladder network.

Zia



Zs

=



Zs 2  Zs

2

4  Z s Rt



1

2

(7-17)

Where Self impedance of 1 span of OHEW (Ω) (or Ω/m for pipeline,

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etc) =

Rt

Tower footing resistance (Ω) (or earth impedance Ω/m for pipeline, etc).

For transmission lines this approximation [67], [74] assumes an average value of tower footing resistance. =

Zs

=

Zero - sequence self impedance of N earth wires with earth return. (Ω/km/phase) (3rc/N + 0.1482) + j 0.1885 ln(De/G.M.R.) (7-18)

= =

Resistance of one ground wire conductor (Ω/km) Equivalent depth of current return (m)

Where rc De

De 

658 ρ f



(7-19)

f = =

G.M.R. =

Soil resistivity (Ω.m) Frequency (Hz) Geometric mean radius of the N identical earth wires as a group in metres.







  d  d g lg n d g 2 g1d g 2 g 3 d g 2 gn   d N  g lg 2 g lg 3   GMR   GMRconductor     d  gNg1d gNg 2  d gNgN 1    





1 N2

(7-20)

Where GMRconductor dg1g2

= =

Geometric mean radius of ground wire conductor (m). Distance between earth wires 1 and 2 (m).

The earthing impedance of the line does not increase linearly with any increase in soil resistivity. This phenomena is due to the fact that, concurrently with the increase of the tower earthing resistance, due to the increase in soil resistivity, there is an increase of the impedance (Zia), which increases the number of towers that participate in dissipating the fault current. Therefore, as earth resistivity increases, the ‘effective length’ of an overhead earthwire will increase. This same situation exists with all long earthing conductors such as cable sheaths and counterpoise conductors. It is usually assumed, in calculations, that the tower footings are located outside the sphere of influence of the earthgrid voltage gradient. Ignoring the ‘proximity effect’

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is considered valid, as at most it is only the first tower or two that could be significantly effected.

7.1.4 Buried Conductors !

Underground Cable Sheath Input Impedance

Approximation for the input impedance of an insulated underground cable sheath can be determined as for overhead shieldwires. The following parameters are substituted in Equation (7-17): • • • •

Cable Sheath impedance (Zs), for the line self impedance, and/or Cable armouring impedance Pothead or jointing bay earth impedance, for the tower footing resistance (Rt) and/or Cable armouring to earth impedance when not insulated.

For single short cable lengths the total sheath impedance is usually negligible compared to the termination impedance. Unfortunately, this analysis produces non conservative (ie. lower) impedance values if the ‘proximity effect’ is present (see Section 7.1.6). !

Buried Counterpoise Conductor Impedance

In addition to underground cable sheaths, ‘counterpoise’ conductors are sometimes buried directly into the earth to help improve grid impedance. Long electrodes buried radially from a substation will significantly reduce the overall system impedance. The Reference Manual provides calculation methods and guidelines, and shows the value of counterpoise conductors in high resistivity soils. Ongoing supervision and maintenance issues tend to limit the value of direct burial, unless the counterpoise conductor is laid in the same trench as a power cable.

7.1.5 Combination of Primary and Auxiliary Earthing Systems The total grid impedance (Zgrid) is often calculated as the parallel combination of all connected earth system impedances [67], [74]:

Z grid

1 Rc  1 Zia    1 Zicable  1



(7-21)

where Rc Zia Zicable

= = =

Primary electrode resistance (Ω) Aerial conductor input impedance (Ω) Buried conductor input impedance (Ω)

This expression is approximate in that it: !

Ignores the mutual coupling resistance effects between individual auxiliary

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earth components, such as adjacent cable sheaths, which will increase the total impedance. !

Ignores the fact that more current will return via conductors which lie in the direction of fault current source.

!

Ignores the effect of conductive structures such as pipelines which, although not bonded directly to the grid, will reduce the return current path impedance.

In many instances the total grid impedance is primarily determined by the auxiliary earthing system. This calculation is especially vital in urban or city indoor substations where grid area is severely limited. To overcome these limitations analytical calculations are required as discussed in Sections 7.1.6 and 7.6.

7.1.6 Proximity Effect The interaction between electrodes and the earthgrid is called the ‘proximity effect’. It is significant in that it demonstrates an increase in effective resistance compared with the values calculated assuming independent parallel impedances. The effect is modelled empirically by Popovic [59], [60], [61] for the case of an ‘infinite’ length cable and a finite length cable. To demonstrate this phenomenon, consider a simple 30m by 30m square grid, with 10m mesh in uniform soil of 100Ωm resistivity. To this grid is attached a 100m long conductor, simulating an uninsulated armoured underground cable. Similarly, attach a second cable of the same length, running parallel and very close to the first, to simulate two cables buried in the same trench. The model is described in Figure 7-5 below.

Figure 7-5: Grid and Bonded Cables The resistance of the grid on its own, a cable on its own, and the two cables bonded together were calculated using a computer program which analyses individual grid elements. The result compared to the results from simple parallel combination results are summarised in Table 7.1 following.

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Table 7.1 Calculated Resistances for Grid and Bonded Cables Computer Calculated Value (Ω)

Parallel Combination (Ω)

Grid Only

1.70

-

Single Cable Only

2.10

-

Two Cables Only (Bonded)

1.80

1.05

Grid & One Cable (Bonded)

1.10

0.94

Grid & Two Cables (Bonded)

1.04

0.60

Situation Considered

The first point to note is that if the grid and cable are bonded together, their combined apparent resistance of 1.1 ohms, is higher than that expected by simple parallel combination of their individual resistances, which gives only 0.94 ohms. Parallel combination gives a result 15% low. This is because now they are together, or within proximity of one and other, the leakage current from one, raises the voltage on the other, which manifests itself as a rise in apparent resistance. This effect is made worse when the individual earths are brought closer together. For example, the two underground cables buried in the same trench and bonded together have much more than half their individual resistance, as would be expected from a simple parallel combination. The parallel combination gives a result 42% low. In fact the two cables have an equivalent resistance of 1.8 ohms, almost the same as the resistance of one cable only, being 2.1 ohms. That the proximity effect increases the value of EPR indicates that special consideration should be provided when including auxiliary electrodes in the earthing design. Aspects such as who owns and has control of the electrode, can it be unexpectedly removed or disconnected need to be taken into account in safety calculations. A computer analysis is advised in cases of adjacent cables and non-radial cable routes.

7.2

Earthgrid Potential Rise Earthgrid Potential Rise: The earthgrid potential rise (EPR) is the maximum potential rise of an earthing installation, with respect to remote earth, produced by the portion of fault current that flows through the earthing installation. The earthgrid potential rise (Vgrid) is calculated as the product of the grid impedance (Zgrid) and ultimate earth fault current (Ig).

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62

Ig . Zgrid

(7-22)

The parameters are determined as follows: !

Fault Current (Ig)

The fault current (Ig) is that component of L-G or L-L-G fault current which enters the conductive network which comprises the earthing system to produce a potential rise. Chapter 6 discusses methods for determining this value taking into account the shielding or screening factor of the overhead earthwires or cable sheath on lines feeding fault current. !

Grid Impedance (Zgrid)

The earthing system impedance (Zgrid) is composed of the combination of all connected earth impedances which may carry fault currents returning to the sources. The value of Zgrid may be calculated using the empirical approximations given in Sections 7.1.1 - 7.1.4, or the more accurate computer modelled result discussed in Section 7.6. The empirical approximations provide sufficient accuracy for calculations, for smaller installations, provided the parameter ‘boundary’ conditions are met. Care should be taken to match the calculations to actual system configurations, especially when the system is being implemented in stages. The maximum voltage rise on an installation is usually used when specifying isolation requirements for communications circuits or other services entering a substation, as discussed in Section 7.4 on Transfer Voltages. The transient D.C. offset current will give a peak EPR for use in co-ordination of protection of equipment terminating at the substation (eg. pilot or telecommunication cables) (see Chapter 6). DESIGN STEPS 8,10 & 12

7.3 DESIGN STEPS 10-15

The value of EPR may also be used as an initial conservative estimate of step and touch voltages Design Steps 8, 10, 12. If the calculated value of EPR is higher than the safety criteria for step and touch voltages further calculations and investigations should be undertaken as described in the following sections.

DESIGN STEPS 8, 10 & 12

Touch And Mesh Voltages Touch voltages, may be associated with all metal work directly or indirectly connected to the earthing system. Once it is ascertained that the EPR exceeds the maximum allowable touch voltage criteria, special attention is required to ensure safety for personnel under fault conditions. Figure 7-6 illustrates several typical hazard situations associated with an earthing system under fault conditions.

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63

Typical Shock Situations

Shock situations within and outside a substation are usually identified and analysed separately. Inside the Substation. The mesh voltage is the ‘touch’ voltage within a mesh, and the maximum value is used for design purposes. All metallic structures in contact with the earth, or an earthed conductor, present touch voltage hazards within a substation. Step voltages within the substation earthgrid are always less dangerous than touch voltages so need not be considered as a special topic. Voltages External to a Substation. Touch voltages may be transferred beyond the substation perimeter by auxiliary electrodes and are often associated with fencing. Substation fence design requires special care if the outside of the fence is accessible to the public. Surface voltage gradients used to assess step voltages are highest at the periphery of a grid, where fences are often located. The two shock situations are identified and analysed separately in the following sections: C C

Inside the substation, and those External to the substation.

7.3.1 Voltages Inside the Substation It is common practise to design the inside of a substation area using a mesh voltage less than or equal to the allowable touch voltage. Mesh Voltage is the potential between the surface of the earth in the centre of a grid mesh and the grid voltage.

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This technique simplifies the design and installation as individual ‘grading’ conductors are not required around any structure within the ‘meshed’ area. The worst case mesh potential usually occurs near the outside corners of a grid. The mesh potential could be encountered when carrying metallic equipment in the yard (eg. ladder on shoulder (s)). A)

Mesh Voltage Calculations

A simplified empirical formula presented in IEEE80-1986 [18] based upon Sverak [69], for calculating mesh voltages within the substation earthing system is: Vm

=

ρKmKiIg/L

Ig ρ Ki

= = = = = = = = =

Fault current flowing into the meshed grid (A) Upper layer soil resistivity (Ωm) Correction factor for grid geometry. 0.656 + 0.172n. Grid Conductor length (m) Lc+ 1.15 for rods at the perimeter of the grid Lc + Lr for rods at the middles Total length of horizontal conductor Total length of rod electrodes

(7-23)

Where

L L Lc Lr

(7-24) (7-25) (7-26)

Note: 1.15 reflects the higher current density at the ends of rods.

Km  

Geometrical spacing factor    D  2h2 h  Kii 1   D 2 8    ln ln    2n  1  2   16dh 8 Dd 4d  Kh  

(7-27)

Where Kii

=

Kii

=

1 for grids with earth rods along the perimeter, or for grids with earth rods in the grid corners, as well as both along the perimeters and throughout the grid area For grids with no earth rods or grids with only a few earth rods, none located in the corners or on the perimeter

=

(2n)-2/n

Kh

=

(1+(h/ho))

ho D h d

= = = =

1 m (reference depth of grid) Spacing between parallel conductors (m) Depth of grid conductors (m) Diameter of grid conductors (m)

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Number of parallel conductors in one direction.

The boundary conditions of the simplified equations for mesh and step voltages are as follows: !

Square Grids (or rectangular) with same number of conductors in each direction. C C C C

n # 25 0.25m # h # 2.5m d < 0.25h D > 2.5m

Equation (7-23) is often reworked, to calculate a first approximation for the minimum length of conductor required. Care should be taken with such an approach as in many cases it provides a misleading result. B)

Hazard Locations

Exposed Metalwork All metallic structures in contact with the earth, or an earth conductor, could present touch voltage hazards. Safety for personnel should be guaranteed by: !

The bonding of all such metalwork, which includes; internal fences, water, gas, and air service lines;

!

The use of grid mesh design to limit voltages to below safety levels.

!

Use of a thick layer of clean high resistivity crushed rock to increase foot-to-ground contact impedance.

!

Use of equipotential mats at working areas, such as at operating points, to protect operators.

Operating Handles Operating handles of switches may constitute a hazard to operators, if not adequately earthed. A number of factors may cause fault current to flow through the operating linkage to earth whilst an operator is in a critical position. ! ! !

Mechanical failure of the switch, Electrical breakdown of an insulator that forms part of the switch, Attempting to break a line current greater than the switch rating.

The danger may be reduced by equipotential mats, insulated handles and additional earthing of the linkage between the handle and the switch bases and supporting insulators.

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‘Close Fault’ Effects

When a fault occurs at a location close to a substation (eg first tower) the touch potentials may be higher in the area of the grid closest to the fault [53], due to the higher current density created in that region caused by the small current loop. Although the installation of an OHEW will return the majority of the fault current, the surface potentials in the peripheral meshes closest to the fault location may require special attention. !

Soil Model Effects

As illustrated in the examples in the preceding Soil Resistivity Chapter, the existence of a multi-layer soil not only affects the EPR, it also affects the touch and step voltages. The soil resistivity in the upper layer between the grid and four (4) times the grid depth has the main influence on the step and mesh voltages. Section 7.6 provides examples and guidelines for the use of empirical and analytical methods. *

*

*

Discussion of methods for limiting each type of fault voltage are discussed in the Voltage Mitigation Section 7.7.

7.3.2 Voltages External to the Substation Touch voltages beyond the substation perimeter may be associated with either: !

Substation fencing, or

!

Potentials transferred to other metalwork. Touch voltages external to substations are usually defined as ‘transfer voltages’. Voltages are either transferred directly by metalwork or indirectly by conduction through the earth to metallic objects remote from the substation. Transfer voltages are examined separately in Section 7.4 following.

!

Substation Fencing

Substation fence earthing is important for a number of reasons including: !

The outside of the fence is usually accessible to the general public.

!

The surface voltage gradients are highest at the periphery of the grid, where fences are often located.

!

In the event of a powerline conductor falling onto the fence it must allow sufficient current to flow to ensure protection system operation.

!

In higher voltage substations, unearthed fences may become electrostatically charged thereby posing a hazard to staff or the public.

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Substation fence earthing is usually either: A) B)

Included within, and bonded to, the earth grid, Separated from the main earthgrid and earth earthed independently.

The following sections briefly discuss each design option, with the Earthing Reference Manual Installation and Power Frequency Sections discussing the background and physical implementation of each scheme. A)

Fence Bonded to the Main Grid

Reasons for adopting the bonded design are as follows; !

Reduction of earth potential, and hence touch voltage, due to the reduction in grid resistance, which is closely related to the grid area.

!

Station fence lies close to station equipment.

!

A railway siding or metallic pipeline enters the fenced area effectively eliminating any isolation between the fence and main grid.

!

Eliminate hazards, cost or inconvenience, due to inadvertent or unforeseen bonding subsequent to initial installation.

Usually, the perimeter grading or ‘touch’ earth conductor is run 1m beyond the fence (. 1m distant) at a depth of 0.3 - 0.5m. The peripheral conductor may be run directly under the fence when space is a premium, at the expense of higher external touch voltages. Multiple horizontal conductors at increasing depth horizontally or vertically may be installed for step voltage control, alternatively driven vertical rods may be helpful. The value of touch voltage experienced near the fence under fault conditions may be assumed initially to be equal to the mesh voltage. However, in marginal cases where compliance with the safety criteria is not assured computer modelling of all surface voltage gradients, and/or a rigorous testing program undertaken following the system installation is recommended. Such testing is described in the substation testing procedures chapter. B)

Fence Independent of Main Grid

The independent earthing of a substation fence may be preferred provided the fence is located at a sufficient distance from the earthgrid to effectively reduce its earthing EPR. The advantages of independently earthing the fence are: !

The magnitude of touch voltages presented to the public will be reduced, relative to the EPR.

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Reduction of transfer of potential to external metalwork is more easily achieved with isolating sections along fences, particularly when radial to the site when the remainder of the fence is earthed independently to the main grid.

In the case of the station fence earthed separately but not connected to the substation main grid, the touch voltage for a person standing outside the fence can be approximated from the following equation [18], [26], [75].

x  x   x    1  1  1   D   D  D  D  2 D  1 I g    ln V f  Ki     lt x  1        D    n  1 D   

(7-30)

Where D = Spacing between parallel mesh conductors (m) DN = Distance between fence and earthgrid (m) x = Distance between fence and conductor and foot contact point Ki, Ig, L, ρ are as defined for Mesh Voltage in Equation (7-23) in Section 7.3.1 A).

7.4

Transfer Voltages

DESIGN STEP 19

During earth fault conditions voltages may be transferred from the substation earthgrid to remote locations (and vice versa). Design Step 19, investigating transfer potentials, is addressed in this section. The hazard presented is usually from contact of the touch type, being either hand-to-hand or hand-to-feet. A transferred potential problem generally occurs when a person standing at a remote location touches a conductor connected directly or indirectly through the earth to the substation earth grid. If no buried metallic structures are located near to the earth grid the equipotential contours follow the shape of the electrode and tend to become spherical at large distances from it. If a metallic object is located near the electrode, the equipotential contours are distorted and the potentials and potential gradients instead of decreasing with increased distance from the earth grid, may stay constant or, in the case of gradients, may increase to unexpected levels. Such structures in general will seldom follow exactly the initial undistorted equipotential lines. Current will enter the structures at the high potential areas and will leave it at the low potential areas. Since the highest gradients exist where the current enters or leaves the earth the region in the vicinity of the structure becomes hazardous if the magnitudes of these current are large enough. If in addition, the fault occurs in an area close to the main earthgrid and the buried structure, the gradients and potentials may be completely different from the values

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corresponding to the case where the main earthgrid is alone. A further possible consequence of buried metalwork in the vicinity of the earthgrid is the usually small reduction in earth grid resistance and hence EPR of the main grid. The following parameters are effective in determining the magnitude of transfer potentials which may occur. ! ! !

Relative dimensions, form and positions of the active electrode system and the passive system of metalwork. Earth structure and resistivity. Position of the point of return of earth currents.

High surface voltage gradients and hence step potentials are created by voltages transferred by buried metalwork (see Section 7.5 following). Examples of typical surface equipotential contours are illustrated in Figure 7-7 for bare buried metalwork.

Figure 7-7:

Typical Voltage Gradients Associated with Buried Metalwork

The importance of the problem results from the very high magnitude of potential difference which is often possible. This potential difference may equal or exceed

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(due to induced voltages on unshielded communication circuits and pipes) the EPR of the substation during a fault condition. The basic shock situation for transferred potential is shown in Figure 7-6 of the preceding section. An investigation into possible transferred potential hazards is essential in the design of a safe substation earthing network. An initial check procedure is introduced followed by a discussion of details relating to the transfer of potential through various typical metallic structures. An initial check that can be made to determine the possible magnitude of the transfer potential hazard, is outlined as follows: Conservative Approximations !

EPR : If the EPR of the system, being the highest possible value of transfer potential, is below the safe touch potential criteria no further checks are required.

!

Voltage Gradient : Calculate the difference in potential (Va - Vb), along the undisturbed voltage gradient of the earthing system (see Section 7.5), between the start and finish of the metallic structure under investigation. The resultant touch potential associated with the metallic structure should be less than this value. Typically, actual values may be near (Va - Vb) for insulated metalwork earthed at one end and 0.25 (Va - Vb) for metalwork in contact with the earth [80]. See Figure 7-8 following.

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Initial assessment of transfer potential hazards

Care should be taken in exercising these initial approximations. Two factors which will tend to increase the values of touch voltages are: ! ! !

Induced voltages Perturbations in the voltage gradient.

Induced Voltages

Voltage is induced in metalwork by fault current flowing in an adjacent power line. Figure 7-9 following illustrates the effect of the combination of inductive coupling to a power line and resistive coupling to an earthing system. The Earthing Reference Manual Chapter or Current Distribution evaluates the induced voltages as functions of fault current, physical relationship and length of exposure. The voltage must be calculated for insulated pipelines or communications lines close to transmission lines.

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72

Combined Inductive and Resistive Coupling Effects

Perturbations in Voltage Gradient due to Transfer Potential

The actual voltage gradient profile may be different to the estimated value obtained from the initial check. One case which will increase hazard is the presence of another metallic structure which transfers the remote earth near to the substation. Pipelines and fences often contribute to this problem (see Figure 7.7). !

Transfer Potential Cases

The following metallic structures or systems are those which often contribute to a transfer potential situation [78], [79], [80]; C C C C C C C C C C

Pipelines (eg. water, gas, fuel) Fences Railway lines Underground power cables Overhead earthwires Low voltage neutral wires Communications circuits Roadside ‘crash barriers’ External electrical services and structures. Conveyors

The Earthing Reference Manual, Power Frequency Voltage Chapter addresses each of these systems in detail.

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Voltage Gradients Two situations are examined: 1. 2.

Within the substation grid area External to substation earth grid

7.5.1 Within and Close to the Substation Grid Area Within an evenly spaced earth grid the maximum voltage gradient is usually associated with the corner mesh. However, this value is always less than the mesh voltage. The more onerous situation exists immediately adjacent to the substation earth electrode area where the potential gradient in the ground is greatest. Accordingly, the maximum ‘step potential’, at a time of substation potential rise will be experienced by a person who has one foot on the point of maximum potential rise and the other foot one step towards true earth. For purposes of assessment the step distance is taken as one metre as defined in the Safety Criteria Chapter. ! DESIGN STEP 14

Calculation of Step Potential Close to Grid

IEEE 80-1986 [18] has adopted an empirical formula for estimating step potential Vstep based upon work by Sverak [69], where it is assumed that the maximum step voltage occurs at a distance equal to the grid depth, (h), just outside the perimeter conductor. For the usual burial depth of 0.25m < h < 2.5m. Vstep

=

Step voltage

=

ρIGKsKi/L

L

=

Lc + Lr for grids with no earth rods or only a few rods in the centre away from the grid (m).

L

=

Lc Lr

= =

Lc + 1.15Lr for grids with earth rods predominantly around the perimeter (m). Total horizontal grid conductor length (m) Total rod length (m)

Where

(7-31)

or

and

Ks 





1  1 1    1  0.5n 2     2h D  h 

(7-32)

and for depths smaller than 0.25m,

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

1  1 1    1  0.5n 2     2h D  h 

Ks 

(7-33)

where

W 

1 1 1 1     2 3 4 n1

or for the case where n > 6

W  1 / 2 n  1  ln n  1  0.423 The use of a different equation for Ki, depending on the grid depth h, reflects the fact that the step voltage decreases rapidly with increased depth.

!

Ki

=

n

=

Grid irregularity factor as defined in Section 7.3.1 A) Equation (7-24) Number of parallel grid conductors in one direction

For Rectangular Grids (with square meshes) the value of ‘n’ when calculating Km, Ki, Ks is; n = n =

(nAnB)½ for mesh voltage calculations max(nA, nB) for step voltage calculations

(7-34) (7-35)

Where, nA and nB are the number of conductors in each direction. In deriving his equation for the step voltage factor, Ks, Sverak [69] first attempts to find the point above the grid that has maximum potential gradient. In all of his remaining assumptions, he relies on the fact that “step voltages are inherently less dangerous than the touch or mesh voltages...”, hence allowing a certain margin for error. The original model has assumed infinitely long conductors, hence the point of maximum voltage gradient, according to Sverak, is at a distance ‘h’ from the side of any particular grid. The infinite conductor model does not take into consideration the ‘end effect’, which is apparent for finite length conductors. The consequence of the ‘end effect’ is that, as computer modelling shows, the point of maximum voltage gradient is in fact diagonally out from the corner of any given grid, not the side. Hence the model used here inherently underestimates the magnitude of step voltages around any grid. Also caution should be exercised due to homogeneous soil resistivity assumption. In multilayer soils the step voltages will vary markedly from the value calculated in Equation 7-31. As explained in Section 7.6 following, this equation should only be used as an indicative value of Vstep.

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In addition to step voltages usually being smaller than mesh voltages, the allowable step voltage withstand level is higher than that of touch voltage. Therefore, step voltage safety levels are usually met, especially if a high impedance surface layer is used to limit body current flow.

7.5.2 External to Substation When a substation earth electrode is subjected to a potential rise, potential gradients develop in the surrounding ground area which are highest adjacent to the substation earth electrode. The actual ground potential reduces to zero or ‘true earth’ potential at some distance from the substation earth electrode, as illustrated in Figure 7-10 following.

Figure 7-10: Potential distribution for a circular metal plate in the earth’s surface as a function of distance This distance, varies from hundreds to thousands of metres, and forms a physical separation which, if it is not bridged by a metallic connection, renders any person in the high potential area immune from the possibility of simultaneous contact with zero potential. Although the total potential rise distributes over a substantial distance, potential differences between two points of ‘human step distance’ appearing in the immediate vicinity of the earthing system may present a shock hazard. Communication line and cable facilities entering such areas and extending to terminal points remote from the station may be exposed to the total potential rise of the mat as described in Section

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7.4 on Transfer Potentials, therefore, an EPR assessment is critical to these installations. The shape of the voltage curve around an earth electrode is independent of the earth resistivity (if homogeneous). A high earth resistivity often gives a high station potential which implies that the potential difference between two points could be dangerous. For the other extreme case, with low earth resistivity, the lower station potential would appear to constitute a smaller hazard. In practice a high earth resistivity gives not only a high value of grid impedance but also a greater relative increase of the area with raised potential. Although at first glance the higher resistivity appears to have compounded the problem, closer examination will show that the actual body current is also limited (refer to Chapter 4 on Safety Criteria) thereby possibly reducing the safety hazard. The analysis of the voltage profile extending from a substation is especially necessary in an urban environment. Often substations are constructed in such a manner that no external touch potential hazards are presented through the use of say brick external walls. However, these substations often of small area, may present high external step potentials, especially if external metalwork distorts the voltage gradients. The following sections discuss the analysis of voltage gradients beyond a substation earth grid area. A) B) A)

Undistorted voltage gradients Distorted voltage gradients.

Undistorted Voltage Gradients

The potential distribution around an earth electrode can be conveniently presented in the form of a curve, normalised so that the gradient is expressed as a percentage of the total voltages appearing at various distances from the edge of the electrode. The shape of such a distribution curve is exclusively a function of the geometry of the earthing system. Although the absolute magnitude may vary with other factors such as soil resistivity and fault current magnitude the percentage change in potential with distance remains the same. A number of empirical methods have been used to ascertain the external voltage gradient based upon various models for the grid, as discussed in detail in the Reference Manual. The Equivalent Hemisphere model is discussed in the following section. !

Equivalent Hemisphere Model

Bodle [82] proposed first converting the earthing system geometry to an equivalent hemisphere, then calculating earth potential away from the edge of the hemisphere. The voltage on the earth’s surface can be given by:

Vx 

I 2rg

for rg  0

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(7-36)

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Where ρ I rg Vx

= = = =

Earth resistivity Ωm Current flowing into the earth Amps Distance from the centre of the earth grid (m) Voltage at that position Volts

For most practical situations, the value of resistivity ρ is not known with sufficient accuracy, or the earth grid is not uniform. Often, however, the earth grid resistance and dimensions may be known, along with the maximum fault current which enables the maximum earth potential rise for the earth to be calculated. A rearrangement of the above formula yields the more useful result of:

Vx  Vgrid

re x  re

 7  6

(7-37)

Where re = Vgrid = x =

Radius of an equivalent hemispherical earth (m) Earth potential rise of the earth grid (V) Distance from the edge/corner of the earth grid (m)

This formula also shifts the profile so that the surface voltage equals the EPR at the edge of the grid. It should be kept in mind that this will slightly affect the accuracy (increased voltage) far from the grid, and that the surface voltage should be close to the EPR inside the grid. Where re

re 

=

Is the radius of a hemispherical electrode of equivalent resistance.

 2Re Re

 7  7 =

(7-38)

Resistance of the electrode (Ω)

For general electrode structures the following values of equivalent radius (re) can be used: Surface Plate:

re  0.3592 A

(7-39)

Where A

=

Area of the earth grid (m2)

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Driven Rod:

re 

l 8l ln  1 d

(7-40)

Where l d

= =

Depth (length) of the earth rod (m) Diameter of the earth rod (m)

With more complicated structures, such as large substations, it is better to measure the resistance of the earth and the soil resistivity, and then calculate equivalent radius (re) directly using Equation (7-38). This is because Equations (7-39) and (7-40) are derived from simplified resistance formulae for the relevant structures. If the resistance of the earth grid is not known, half of the largest dimension of the earth grid may be used for the equivalent radius (re), however, this will probably give very conservative values for voltage gradient. !

Limits for Application of Simplified Calculations

The above simplified calculations are based on an ideal situation in which a hemispherical earth is installed into an even and continuous soil (homogeneous resistivity). If an earth has a non-hemispherical shape, Equation (7-36) will become less accurate closer to the earth grid. A degree of accuracy is obtained after the point x is further away from the grid than the largest dimension of the grid (ie. the length of the rod or the diagonal measurement of a rectangular grid). Note also that distance (x) is measured from the centre of the grid, thus the size of the grid should be measured if measurements are to be taken from the end of an array or edge of a large grid. In Equation (7-36), the voltage gradient and values away from the edge of the grid may be inaccurate, however, this equation is conservative and is suitable for safety calculations. An example of voltage gradients for a grid in different soils is shown in Figure 7-11 following. Note that the values are normalised to the actual EPR existing. The empirical equations are often unable to calculate EPR accurately in multilayer soils.

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Surface Voltage (% EGVR)

100

10 Case I Case II Case III Case IV 1 0

10

20

30

40

50

60

70

80

90

100

110

Distance from Corner of Grid (m)

Figure 7-11: Soil Resistivity Effect on Surface Gradients The profiles given in Figure 7-11 have been calculated analytically, however, the results are intended to be indicative only. Case I Case II Case III Case IV

Equation (7-36) ρ = 100Ωm, R = 2.04Ω ρ1 = 10Ωm (5m depth) ρ2 = 100Ωm, R = 0.641Ω ρ1 = 100Ωm (5m depth) ρ2 = 10Ωm, R = 0.41Ω

For Cases I and II, the soil resistivity value used is 100Ωm. For Cases III and IV the grid is located in two layer soil resistivity, where ρ1 is the top layer resistivity of depth 5m, and ρ2 is the lower layer resistivity of infinite thickness. The grid is comprised of four 10m meshes (i.e. 20m side length) with a 10m stake at each of the four outside corners. Any metalwork connected to the grid and extending beyond the grid perimeter will transfer potentials to the soil nearby. Pipelines and counterpoise electrodes, whilst assisting in reducing the value of Rgrid and hence EPR, may create hazardous step potentials at a remote location. Such high potential gradients are difficult to ‘supervise’, as they usually occur outside controlled areas. The following section discusses cases where the voltage gradient external to an earthing system is distorted. B)

Distorted Voltage Gradients

Three factors contributing to distortions in voltage gradients are discussed in this section: external metalwork, natural phenomena, and soil resistivity anomalies.

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External Metalwork

External metallic structures may import a ‘remote earth’ potential to a location near a substation as shown in Figure 7-12.

Figure 7-12: Equipotential ‘crowding’ by external metalwork As shown the equipotential contours become ‘crowded’ between the pipeline and the substation fence, giving rise to high step voltages. In an urban location, where much metalwork is found, such effects should be examined closely. !

Natural Phenomena

A watercourse may, in certain high resistivity situations, conduct current to remote earth. This may result in higher voltage gradients, in the direction of the watercourse, in a similar manner to the preceding example. !

Soil Resistivity Anomalies

Soil resistivity anomalies, such as vertical faults, may give rise to variations in the voltage gradients. Work by Kavorsky et.al. [84] illustrated a method for estimating the voltage gradients across a vertical fault. The example they cited gave surface equipotential contours as shown in Figure 7-13.

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Figure 7-13: Equipotential contours across a vertical fault The foregoing empirical approximations are a useful guide in determining the voltage gradients surrounding an earthing system in undisturbed single layer earth conditions. The analysis of voltage gradients in ‘disturbed earth’ is a rather difficult task. In such cases, field measurements (which are usually made after construction of the electrode) are required to evaluate analytical predictions. Scale model test are sometimes made using an ‘electrolytic tank’, which is a vessel containing a liquid compounded to simulate the conductivity of soil. Analysis, by computer, in which each element of the grid and external metalwork is included, can provide accurate solutions for situations outside the constraints of the empirical formulae. Section 7.6 following discusses empirical and computer analysis techniques. The Earthing Reference Manual provides greater depth in describing the analytical procedures.

7.6 DESIGN STEP 16 & 20

Empirical And Analytical Calculation Comparison Numerous computer based analytical procedures have been proposed to enable the exact location and effect on impedance of grid elements to be calculated [4], [50], [51], [52], [72]. The benefits of such methods are that they; ! Model complex grid configurations and multi-layer soil resistivities, with flexibility ! Provide accurate values of resistance, and voltage values.

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Many have the following limitations: ! Difficulty in accurately entering the information regarding system configuration. !

The voltage on the electrodes is considered constant. This is acceptable for many typical primary electrodes, however, it can be inaccurate (even up to 200%) for longer buried conductors. Therefore, the auxiliary earthing system is usually considered separately. As the final resistance value is usually primarily dependent upon the auxiliary earthing system extreme accuracy in calculating the primary electrode resistance may not be justified. Refer to Section 7.1.4 for examples of analytical proximity effect calculations which highlight the deficiencies of the simple ‘parallel’ impedance approach.

!

Most of the programs available work exclusively in the real domain. That is, they only consider a purely resistive system. There are a few programs, however, that calculate the effect the admittance of the earthing conductor has on grid behaviour. Such effects become significant in larger interconnected systems.

!

Few of the programs allow for the inclusion of input impedances to the grid ( such as over-head earth wires, or cable sheaths bonded to the earth grid). Others allow for fences, pipes, and other buried metalwork, thus calculating the extent of the transfer potential hazard.

!

A homogeneous soil layer model is usually too limited in its modelling ability, therefore a more detailed soil structure is required.

!

The program should also be able to take any size, shape or form of earthing grid. There should be no restraints in the symmetry or complexity of the grid. This requirement should also enable the inclusion of non-connected earthing systems in the area of the grid.

!

Fault currents should be accepted at any node or multiple nodes in the system to enable modelling of multipath faults (e.g. extensive steel structures, test configurations modelling (i.e. inductive current flow, remote probe/grid effects)).

The use of such detailed analytical procedures may not be necessary when calculating earth system resistances for use in calculating maximum earthgrid voltage rise (EPR). The simplified resistance calculations of the previous section usually provide a value of Rgrid, for use in calculating EPR, of sufficient accuracy. However, care must be taken to ensure that the boundary conditions of the empirical equations are complied with, otherwise the results will be in error. The following section provides a detailed comparison and application guidelines for empirical calculation methods. The main use of computerised analysis lies in analysing the values of step and touch voltages associated with the primary grid and nearby installations. In certain critical situations considerable expense may be saved by the use of accurate modelling

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techniques. !

Application of Analytical Methods

The application of programs based upon analytical procedures, such as those discussed in the proceeding section provide significant advantages over the empirical formulae. Examples which highlight the value of such methods and a number of application guidelines are included in the following section. Computer programs allow detailed analysis to be performed on any earthing system existing in the ‘ideal’ world. By using a program it is possible to perform indepth parametric analysis, studying the affects which various parameters, such as resistivity, grid layout and unconnected metalwork, have on the earthing system characteristics [4], [52]. Such analysis also highlights certain pitfalls and hazards that can arise, if careful thought is not given to earthing design. It is valuable to compare the results of the computer analysis with similar results produced from the empirical set of equations (Section 7.1) highlights the pitfalls of using empirical equations blindly. This section presents an analysis of a relatively simple earthing system, using an analytical computer program, and the empirical equations. The case that will be considered here deals with the effects that seemingly comparable soil structures have on the characteristics of a simple grid. As the equations for step and mesh voltage presented in Section 7.3.1 and 7.3.2 only apply to homogeneous soils, application of the equations to non-homogeneous soils can present a problem. If resistivity tests indicate a two layer soil structure, a common (yet erroneous) practice would be to take the numerical average of the readings as a homogeneous approximation. To demonstrate the possible hazard of using the numerical average, consider a simple 30m square grid with 10m mesh. The grid is buried in a two layer soil structure with a top layer depth of 2m. We will consider two distinct soil structures. The first case has a 100 Ωm upper layer on a 10 Ωm lower layer, while the second case has a 10 Ωm over a 47 Ωm lower layer. These two soil structures have been chosen as they produce the same numerical average resistivity of 30 Ωm for a typical range of resistivity readings. The calculated values for grid resistance using the empirical equations and a computer program are shown in Table 7.2 following.

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Table 7.2 Calculated Grid Resistance for Different Soil Structures Calculated Grid Resistance Rg (Ω)

Method of Calculation

ρ= 100 on 10 (Ω.m)

ρ = 10 on 47 (Ω.m)

Analytical Computer Modelling

0.662

0.474

Empirical Equations Solid Plate: Eq(7-8) Laurent: Eq(7-10) Sverak: Eq(7-11) Schwarz: Eq(7-12)

0.443 0.568 0.557 1.706

0.443 0.568 0.557 0.171

The first thing to note about the results is that Equation (7-12) has produced results in both cases, significantly different to all the others, even though it is the only one of the empirical equations that can deal with two layer soils. This is because both cases violate the restrictions imposed on the use of Equation (7-12). For the 100 on 10 Ωm case, the difference in top and bottom layer resistivities is greater than 5 times, while in the 10 on 47 Ωm case, the top layer is of lower resistivity than the bottom (see Section 7.1.1.2). The results produced by Equation (7-12) should be ignored. Considering the 10 on 47 Ωm case first, we see that the empirical results have produced the expected spread, with the computer value fitting in as expected (i.e. Equation (7-12) lower, Equation (7-10) and (7-11) higher than the computer value). From these results, the 30 Ωm approximation for the two layer soil structure would seem quite adequate. The computer calculated value for the 100 on 10 Ωm case is slightly higher than the empirical values, yet still within the same order of magnitude of the other results. It would still appear that the 30 Ωm approximation is acceptable (if not, then only slightly low). If we now look at the calculated values of step and mesh voltage for the two soil structures, greater discrepancies emerge. The results of the calculations are given in Table 7.3 below. Table 7.3 Calculated Mesh and Step Voltages for Different Soil Structures

Method of Calculation

Calculated Mesh Voltage Vmesh (Volts)

Calculated Step Voltage Vstep (Volts)

100 on 10 Ωm

10 on 47 Ωm

100 on 10 Ωm

10 on 47 Ωm

Analytical Computer

516

47

174

43

Empirical

165

165

63

63

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Considering the 10 on 47 Ωm case first we see that the empirical of Sections 7.3.1 and 7.3.2 equations have calculated step and mesh voltages significantly higher than the computer model. This is as would be hoped, providing a margin of safety in the calculations. However, if a mesh voltage of 165 volts was within the required safety limits for this grid design, the question must be asked as to whether the given design is too conservative. If the ‘true’ value is in fact 47 volts, could we have designed the grid with larger mesh spacing and still satisfied the safety requirements. Larger mesh spacing would mean less copper in the ground and lower labour costs, hence producing a much cheaper design. This highlights the fact that in some cases, application of traditional design methods can produce unnecessarily expensive grids, where simpler, cheaper grids could still satisfy the given safety criteria. If we now consider the 100 on 10 Ωm case, the results are by no means conservative. The computer method has calculated step and mesh voltages well in excess of the values calculated by the empirical equations, the difference being approximately 300%. This highlights the fact that in some cases, application of traditional design methods can produce grids that do not satisfy the given safety criteria (i.e. unsafe). The reason for the unexpectedly high values for step and mesh voltage is the difference between the upper and lower layer resistivities. The current leaking from the grid segments sees the lower layer as a far better (lower resistance) path back to the return electrode. Hence, all the current leaves the grid and goes down, into the lower layer. Practically none of the current stays in the upper layer. As it is the leakage current that creates the voltage on the surface of the earth, if the current is going down, (rather than up or across) the voltages above the grid decrease very rapidly away from the grid conductors. This phenomenon is best highlighted by a 3 dimensional view of the voltage profiles above the grid for the two cases, shown in Figures 7-14 and 7-15 following.

Figure 7-14: 3-D Soil Voltage Profile Above Grid for 10 on 47 Ωm Case

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Figure 7-15: 3-D Soil Voltage Profile Above Grid for 100 on Ωm Case As can be seen from the above 3-D plots, the voltage gradients around the 100 on 10 Ωm case are much steeper than those for the 10 on 47 Ωm case. While the overall voltage level directly above the grid conductors for the two cases is approximately the same (due to similar EPR), the absolute voltage (with respect to remote earth) within the meshes is much lower for the 100 on 10 Ωm case, giving rise to the higher mesh voltage values. Similarly the step voltages are much higher for the 100 on 10 Ωm case due to the rapid ‘drop-off’ in voltage away from the grid. A 3-D voltage profile for a 30 Ωm homogeneous soil would lie somewhere between the two plots shown above, slightly steeper than the 10 on 47 Ωm case, yet not as steep as the 100 on 10 Ωm case. The preceding section comparing the results of several empirical formula for grid resistance and mesh and step voltages with the results of detailed analytical computations, is based largely upon a paper by Hughes and Carman [4]. A more thorough analysis is provided in the Reference Manual. Until most recent times, empirical formulae were used for the majority of analysis performed on earthing systems. Such equations offer a quick and sometimes satisfactory appraisal of earthing system behaviour. However, these simplified equations have many limitations and do not always depict a ‘worse case’ scenario. With the increasing availability of powerful personal computers, more detailed analysis methods have been developed. The benefits of these computer programs as design tools are obvious. Yet in some earthing situations, such a detailed, and hence time consuming, computer analysis is unnecessary and the simple empirical formulae would suffice. Hence, the question must be asked: “Under what conditions can the empirical formulae be used, and when should a more detailed analytical analysis be

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performed?” !

Recommendations

The following section provides several recommendations [4] regarding the application of the empirical equations for symmetrical earthgrids: Apparent Grid Resistance C

When calculating resistance of grids without earth stakes and buried in a homogeneous soil, the empirical method suggested in Section 7.1.5 is satisfactory (ie, Equation. (7-11)).

C

For grids with stakes in homogeneous soil, it is necessary to go to a more detailed equation such as Equation (7-3) to get results that better approximate the ‘actual’ values. Yet all design must be made knowing such calculated grid resistance is on the high side of ‘actual’ values.

C

For grids in two layer soils Equation (7-5) can be used, provided the restrictions imposed in Section 7.1.1.1 are not exceeded.

C

For other cases in two layer earth, no simple equation (eg, Equations 7-12, 7-13, 7-16) can be accurately used unless the top layer is extremely deep, or the higher resistivity top layer is above the buried grid, in which case homogeneous approximations will suffice.

Mesh Voltage C

When calculating mesh voltages for grids buried in homogeneous earth, Equation (7-23) can be used confidently, knowing a factor of safety exists in the calculated results.

C

For grids in two layer soils, the mesh voltage can be approximated by Equation (7-23) using the value of resistivity of the layer in which the grid is wholly buried.

C

Where the earth stakes penetrate both layers, particularly for lower resistivity bottom layers, more extensive computer analysis is suggested.

Step Voltage C

When calculating step voltage for grids buried in homogeneous soil, great care must be taken in applying Equation (7-31) as it produces results ‘near’, yet lower than the maximum analytical value. Hence any design based on Equation (7-31) must also incorporate significant margins of safety.

C

For grids in two or more layer earth, no approximate equations are valid, hence more extensive computer analysis is suggested.

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The wide range of parameters of earthing grids (such as grid size, shape and area; conductor type and size; earth stake configuration; soil resistivity and layering) make the range of possible earthing scenarios enormous. The empirical equations presented are limited to only a small subset of possible earthing grids. For this subset, a set of recommendations for the use of the empirical equations has been described above. Computer based calculation of the empirical equations is useful as more accurate methods of calculating constants (such as K1 and K2) are possible, and violations of the boundary conditions can be automatically identified, preventing the user from inadvertently applying the equations ‘out-of-bounds’. For the remaining earthing systems (such as asymmetrical grids, large interconnected systems, multilayer soils, earthing grids with many projections) the only tool available that facilities accurate analysis is the computer based analytical approach. Not only do accurate modelling tools give the engineer confidence in his design, they also allow for more efficient and cost effective design solutions. Savings (labour and material) in the order of 40-60% are often obtained using analytical calculation techniques.

7.7 DESIGN STEP 18 & 21

Voltage Mitigation Methods There are two approaches to limiting the shock obtained through indirect contact: primary source hazard prevention, and secondary effect mitigation.

7.7.1 Primary Source Hazard Prevention This protective measure involves configuring the primary system to minimise hazards associated with protectively earthed equipment under fault conditions. Four of the parameters involved in the primary fault circuit which can be utilised are introduced below: !

Earth Fault Current Restriction. The earth fault current entering the earthing system may be reduced by either: directly limiting the current (eg. neutral earthing resistors or reactors), or by diversion of current, by inductive and resistive coupling, into auxiliary earthing systems (eg. cable sheaths or OHEW’s).

!

Impedance Reduction. Earthing system impedance is related to the size of grid, amount of copper in the ground and earth resistivity. A number of alternatives suggested for reducing the impedance include: increasing grid area, OHEW (size increase, tower footing impedance reduction, burial of continuous counterpoise conductors between towers), underground cable sheath bonding, deep driven earthstakes, direct burial of radial counterpoise conductors to increase grid area, chemical treatment of the soil (to increase ‘effective’ area of grid conductor), bonding to structural members (eg. foundations), and bonding to a low resistivity area (eg. river, dam, geological fault of conductive material).

!

Fault Clearing Time Reduction. The use of fast discriminate protection capitalises on the ability of the human body to withstand higher currents if the

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fault duration is reduced. Special protection schemes may be used to overcome the long fault clearance times often found in distribution systems. One such scheme involves an instantaneous first trip, followed by a time graded IDMT characteristic on reclosure. The very fast first trip will provide safety and allow the person time to release contact prior to a longer duration reclosure attempt. !

Site Selection. Sometimes it is necessary to relocate a substation to: avoid interference with other installations (eg. mines), minimise hazards to the public, achieve a sufficiently low grid impedance, or minimise costs.

7.7.2 Secondary Effect Mitigation Secondary effect mitigation methods involve minimising the proportion of the total voltage rise with which a person may come in contact during fault conditions. Such measures take into account the physical conditions encountered in a particular installation, and seek to affect the shock circuit by: !

Local potential control, (eg. closer mesh spacing, operator earth mats, driven rods).

!

Increased series impedance, (eg. insulated footwear and gloves, bitumen or crushed rock).

!

Access prevention, (eg. use of fences and warning signs).

!

Isolation or bonding of equipment. Within a substation, equipment is always bonded (eg. internal fences, water, gas and air service lines). Outside the substation periphery one may choose to isolate or bond to the full earthing system. A bonded design is usually advised for the following reasons: C

Reduction of earth potential rise, and hence touch voltage. This is due to the reduction in grid resistance, which is caused by the increase in the grid area.

C

The elimination of hazards and cost of inconvenience associated with inadvertent or unforeseen bonding subsequent to initial installation. Isolation is sometimes used for discrete metallic structures, which radiate from the substation, and which can be effectively supervised (eg. fences, pipelines).

The design of effective, economical earthing systems involves applying the appropriate combination of protective measures for each situation and type of installation. The Earthing Reference Manual examines the application of each of these hazard mitigation options.

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8 Transient Voltage Design 8.1 DESIGN STEP 22

Transient Sources And Interference Mechanisms Mechanisms which create transients include; switching surges on power lines and in gas insulated substation (GIS) equipment, lightning surges, earth faults, radio transmitter operation, as well as electrostatic discharges. An effectively integrated earthing system is required to enable the primary and secondary power system components to withstand both 50Hz and transient phenomena, whilst maintaining personnel safety, equipment integrity and operational security. The various sources of transient voltages and currents in substations are summarised as follows: !

Atmospheric Events

A lightning stroke generates travelling waves on the HV line. These waves can be produced by a stroke to the conductor, to the earth shield wire or the tower. The shape of the travelling waves depends on the amplitude and the shape of the lightning current. A flash-over of the insulation can be caused by a lightning stroke to the insulator contamination. The flash-over will produce electromagnetic waves which affect the secondary circuits and the lightning current fed directly, or via an arc, into the earthing system may result in high potential differences within the earthing system. !

Switching in High Voltage Circuits

Switching of isolators or circuit breakers is a frequent source of noise in HV substations. The guided waves are transmitted by the current transformer (CT) and the voltage transformer (VT) to the measuring and protection circuits. Current flow on cable screens, produced by guided waves and magnetic fields, and currents fed into the earthing system through CT and VT generate common mode voltages which may also influence the secondary circuits. !

Earth Faults

Earth faults caused by lightning, switching over-voltages, conductor galloping or faulty switching are to be regarded mainly with respect to the electromagnetic waves radiated. !

Switching in Secondary Circuits

De-energising of inductive loads generate transient high frequency overvoltages in secondary circuits. !

Radio Transmitter Operation

The high frequency field generated by radio transmitters, including those which are used by maintenance staff, can influence sensitive electronic equipment.

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These disturbances affect personnel and equipment as summarised in Figure 8-1 (adapted from [85]).

Figure 8-1:

Transient Phenomena in Substations

Transient earthing design is required to provide safety and integrity for the following sub system elements: C C C C C

Primary electrical system equipment (eg. transformers), Personnel (eg, operators, maintenance staff), Secondary circuits and equipment (eg. SCADA and protection systems), Buildings (eg. control building), External services (eg. pipelines and communications lines).

The transient phenomena cause hazardous voltages and currents to flow in these ‘exposed’ metallic paths by inductive, conductive and radiated interference mechanisms (eg. secondary wiring interference causing maloperation of circuitry at critical times. Surge or transient phenomena may be considered to be sources of noise, (or interference) which affect equipment in the following ways [87], [88], [89]: C

Direct or conductive interference - voltage differences in the earthing system causing current flow in cable screens.

C

Guided interference - inductive and capacitive coupling from currents and voltages in phase conductors and earth conductors.

C

Radiated interference - caused by switch arcing, arc gap operation or insulation breakdown, are picked up by secondary circuits operating as antennae.

The Reference Manual provides detailed descriptions of the interference mechanisms

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associated with each transient source for both air and gas insulated substations.

8.2

Mitigating The Effects Of Transients In Substations The design of substation earthing systems to mitigate the effects of transients, requires the coordination of a large number of factors. The 50Hz design criteria are primarily related to personnel step, touch and transfer hazards. The transient phenomena described in the preceding section, cause hazardous voltages and currents to flow in ‘exposed’ metallic paths by inductive, conductive and radiated interference mechanisms. At the higher frequencies the interference coupling mechanisms cause hazards over a greater area. Thus, both personnel safety and secondary wiring and equipment are placed at risk due to these transient phenomena. Through the years, substation design has been largely free to ignore the problem of transient voltages because power system devices have been built with a substantial margin of safety, and because the magnitude of the transients has been within that margin. As power systems have grown new levels of performance have been expected, along with the handling of increasing amounts of energy. The pressure of economics to reduce the margin of safety, along with the use of more sophisticated control and instrumentation equipment, has begun forcing the power system designers into a difficult position. For instance, on one hand there is a trend to favour PVC coated control cables (instead of lead-sheathed cable) for economic reasons, while new components (such as solid-state devices) with less tolerance to overvoltages are being connected to these same control circuits. If it were not for the measure of conservatism in the power field, problems would have been experienced with much greater severity previously. The use of voltages of 330kV and above has seen a large increase in the number of problems, due to the compounding of contributing factors (ie, high voltage, higher power, larger cable runs, and more sensitive equipment). While the problems are magnified for voltages above 132kV (especially above 330kV) care should be taken at the lower voltages, as the hazards may still exist. The most effective (and usually economic) solution to each problem usually lies in the adoption of several mitigation measures. It is difficult to clearly define a ‘best solution’, as the contributing factors are interrelated in a complex manner, and individual applications are often complicated by a number of utility or location dependent ‘special’ constraints (eg. cost and special equipment availability). A computer based assessment of the propagation of the electromagnetic transients can give realistic solutions. However, it is time consuming and not always necessary. A simplified assessment is usually appropriate which combines guidelines, based upon experimental research, with a number of empirical formulae. It is difficult to clearly define a ‘best solution’, as the contributing factors are interrelated in a complex manner, and individual applications are often complicated by a number of utility or location dependent ‘special’ constraints (eg. cost and special equipment availability). Therefore, the most affective, and often economic, solution to each problem usually lies in the adoption of several mitigation measures, when considered in conjunction with the power frequency design criteria. Such a co-ordinated design approach achieves adequate safety levels through a combination of measures (eg. insulation co-ordination, grid layout, control cable layout, screening, termination, and equipment

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protection). The Transient Phenomena chapter of the Earthing Reference Manual outlines a number of measures which have been adopted by power authorities to reduce the hazardous effects of power system transients. The mitigation measures have been divided into two broad categories: primary source prevention and secondary effect mitigation. The design aims are discussed for air insulated substations and gas insulated substations separately, followed by a brief introduction to testing methods associated with proving the transient performance of the system.

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9 Direct Current Power System Earthing Earthing design for a D.C. system is similar to A.C. system earthing design but has some particular requirements not normally required for A.C. systems. The major differences apply to electrode-earthing systems for earth return operation of High Voltage Direct Current (HVDC) systems. This section provides an introductory overview of the main factors involved in the design and operation of HVDC earthing systems. High voltage D.C. transmission systems are designed either with two poles, (cable or overhead lines) both being either isolated from earth, or able to operate the same as single-pole systems with one conductor isolated from earth, and with earth (soil or water) used as the second (return) conductor. The utilisation of earth as a conductor for the transmission current leads to a substantial reduction in the transmission line cost for a given power availability. In existing projects the line costs have varied from a few million dollars up to a hundred million dollars. Reducing these costs can thus be of considerable economic advantage. In the two-pole transmission systems the midpoint in each station is normally connected to earth enabling the power to be maintained on one pole during interruptions in the other pole or during maintenance of the same. Thus, even in two-pole systems the connections to ground will be made through electrodes that are designed to carry the full load current. Existing transmission current ratings range from 200 to 2400 A. Metal structures buried near the electrodes may be exposed to corrosion. The risk of corrosion will be more pronounced for single-pole systems which continuously pass large load currents via the electrodes. For large metal structures such as long cables and pipe lines the risks occur, more particularly, near the cathode electrode. The electrodes in a two-pole system carry full load current only occasionally and, at other times any current due to unbalance in the two-pole operation is small. However, the corrosion risk must also be considered for such systems.

9.1

HVDC Converter Station Earthing It is common practice for A.C./D.C. converter stations to be sited so that all the high voltage D.C. equipment, such as the D.C. transmission line terminations, D.C. line switchgear, D.C. side surge arresters, D.C. smoothing reactors, D.C. measuring devices, D.C. filter circuits, and the low voltage D.C. neutral/electrode line switchgear and measuring devices etc, are located in one switchyard adjacent to the building housing the converter valve groups. All the A.C. side equipment, such as converter transformers, surge arresters, power

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line carrier filters, harmonic filter banks etc, are located in a common A.C. switchyard on the opposite side of the converter building. The D.C. side earthing design follows the same principle as for an A.C. switchyard. Fault currents within the valve groups are determined by the converter transformer impedances and the tripping times of the converter transformer circuit breakers. For faults beyond the D.C. smoothing reactor the fault currents will be reduced by the inductance of the reactor and will be reduced to zero by converter control action in much shorter times than occur in A.C. system faults. The A.C. side earthing design is the same as for a conventional A.C. station. However, it should be noted that A.C. harmonic filter banks often of very large MVAR values comprise several series tuned or parallel/series tuned circuits to provide low impedance paths for the various harmonic currents produced in the conversion process. Close-in A.C. system faults have the effect of creating a discharge path for the stored energy in the filter circuits at new resonant frequencies. The modern approach of using copper mesh in A.C. switchyards to help control step and touch potentials is particularly valuable in providing low impedance - high frequency earth mat and helps avoid high frequency voltages occurring which may otherwise cause damage such as arc-punctures in air blast breaker air-supply lines. The D.C. and A.C. side earthing systems are bonded together to ensure a low impedance return path for the A.C. filters to the HVDC system which is the source of the harmonics.

9.2

HVDC Cable Terminal Station Earthing Where a portion of the D.C. transmission system requires land or submarine power cable, it is usual for some switching equipment and surge protection equipment to be located at the cable terminal sites. For these switchyards, the same design approach as for an A.C. switchyard is followed. However, the crest value and duration of any fault current will be determined mainly by the energy stored in the capacitances of the cables, and this may be very large for long cables, perhaps of the order of 20μF for a single cable. The crest value of the fault currents may be 3-4 times the continuous full load current, although the action of the converter station control system will ensure very short discharge times of only 20 to 30 msec. A much simpler earth mat will therefore be necessary. The cable armouring also assists in achieving a low overall resistance to ground.

9.3

Electrodes For Earth Return Working D.C. electrode installations are a special case of earthing design. For monopolar D.C. schemes they are required to operate continuously at rated current, while for bipolar schemes they are required to operate in both directions for relatively long periods whenever one or the other pole is out of service for maintenance or repair. !

Land Electrodes

For land electrodes, step and touch potentials have to be chosen to suit the nature of

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any ongoing activity on the surface of the site, and the rate of heat production must be controlled to ensure the final steady state temperature is within acceptable values. The associated time constant may be of the order of months. The selection of materials and the drainage of the site are important to ensure reliable operation over a long period of time usually many years. !

Shore or Sea Electrodes

For shore or sea electrodes, the potential gradients in the shallow water near the beach are probably the most important as these can affect marine life, and people may often wade in the shallow water (eg. collecting shell fish). The step and touch potential limits would probably be chosen to ensure they are below the threshold of annoyance for people wading in the shallow water as this avoids the difficulties of otherwise having to control or constrain access to the site. It should be noted that operation as an anode attracts fish! The selection of materials is more difficult than for a land electrode because of the additional corrosiveness of sea water. The life of the electrode material is much shorter than for a land electrode, but suitable design of the installation can allow easy access to the electrode elements for periodic maintenance or replacement, and the cost of replacements can be reasonably low. A major advantage of a sea or shore electrode is that the electrode resistance to ‘ground’ can be much lower than for a land electrode. !

‘Stray’ D.C. Currents

Because electrode return systems operate continuously at high currents static D.C. voltage gradients are established across the countryside. Relatively low gradients may be sufficient to cause some of the HVDC ground return current to flow between widely separated earthed A.C. transformer neutrals via the AC system, and cause saturation in the AC transformers. Modification to transformer earthing circuits may be necessary to avoid this. The effect of D.C. on corrosion (eg. D.C. traction systems) is discussed in detail in the Corrosion Chapter of the Earthing Reference Manual. The Reference Manual provides a detailed analysis of the design procedure for HVDC earthing systems.

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10 Installation Techniques This chapter discusses the physical implementation of earthing systems in four sections is depicted in Figure 10-1 following:

10 Installation Techniques

10.1 Principles

10.2 Equipment Selection 1 Conductor Rating 2 Conductor Sizing 3 Connections

10.3 Installation Layout 1 Horizontal Meshes 2 Driven Rods 3 Structural Members 4 External Connections 5 Auxiliary Test Electrodes

Figure 10-1: General Installation Techniques - Outline The Earthing Reference Manual, Installation Techniques chapter provides greater detail on these topics as well as specific methods for earthing equipment and the practicalities of installing earthing systems.

10.1 Principles Behind Installation Of Earthing Equipment The following guidelines may be used when earthing of metalwork associated with H.V. installations.

DESIGN STEP 23

10.1.1

H.V. Electrical Equipment Metallic components of all H.V. electrical equipment which do not form part of the operating circuit must be included in the protective earthing scheme. Such components include; i)

All above-ground conductive metal parts that might accidentally become energised, such as metal structures, machine frames, metal housings of conventional or gas-insulated switchgear, transformer tanks and guards;

ii)

All fault current sources such as surge arresters, capacitor banks or coupling capacitors and transformers.

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Non Electrical Equipment Earthing of metallic components which do not form part of the electrical equipment is required in cases where these components may, under fault conditions, come into contact (by direct contact or by arcing) with live components. Such components include fences and pipelines (e.g. water, oil). These components may be earthed separately to the main earthing system under certain circumstances.

10.1.3

Connections All connecting conductors are to be of adequate mechanical strength and current carrying capacity. If a metallic structure (e.g. transformer tank, steel or aluminium support structure) forms part of the conductive path special attention should be given to joints or transition points (e.g. provision of bonding conductors). The connection of metalwork associated with probable fault current sources (e.g. arresters, transformer tanks, earthing switches) is often made with additional security, ie: !

By means of two conductors, both of which separately withstand the total earth-fault current. Usually placed on different sides of the equipment and foundation to avoid simultaneous damage to both conductors;

!

The connection to the earth grid conductors is made in at least two directions, such that the breaking of one earth grid conductor does not render the bonding ineffective.

10.2 Equipment Selection The factors governing the selection of equipment types and sizes are discussed in the following section depicted in Figure 10-1 following: Figure 10-2 shows a section overview:

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10.2 Equipment Selection

10.2.1 Conductor Rating

1 Electrical Rating 2 Mechanical Rating

10.2.2 Conductor Sizing

1 Material Selection 2 Conductor Cross Section 3 Connections

10.2.3 Connections

1 Underground 2 Aboveground 3 Protecting Connections 4 Qualifying Tests

Figure 10-2: Equipment Selection - Overview

10.2.1 DESIGN STEP 7

Rating of Earthing Conductors The rating of earthing conductors comprises two basic components: 1. 2.

10.2.1.1

DESIGN STEP 7

Electrical rating. Mechanical rating.

Electrical Rating

The dimensioning of the earth conductors, to be undertaken for each application, is governed by the following factors: A) B) C) D) A)

Fault current magnitude. Fault current duration. Conductor conductivity. Thermal breakdown limitation.

Fault Current Magnitude

The conductor should be of sufficient current carrying capacity to withstand the maximum earth fault currents expected under: i) ii) iii)

Normal fault conditions, Resistively earthed conditions, and Transient fault conditions.

i)

Normal Fault Conditions

!

Fault level increases - Care should be taken to account for the projected increases in fault levels. If the fault level increase is associated with the installation of a new transmission line(s), the new OHEW is likely to carry a

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proportion of the fault current, thus reducing the expected current increase. !

Current Splits - Bonds (or tails) between equipment and the earth system should be given a full fault rating as mentioned previously (even if a duplicate bond is installed). It may be assumed that the fault current will travel in two directions at the point where the bond (tail) connects to the main earth system. However, rather than assuming equal current split, a value of 70/30 is usually used (ie. Rate the bond for 70% of the Fault current). Note that bonds between single pole earth switch contacts must be rated for the maximum of either the full three phase earth Fault or the single phase earth Fault 8.

!

‘Stepped’ Fault Currents - In instances where the fault current magnitude changes, as protection schemes isolate the faulted section, the individual magnitudes and times are summated.

!

Additional ‘safety’ factor - In most cases an additional ‘safety’ factor is applied by specifying a next largest standard conductor size. This often occurs for economical reasons where a standard size is used to minimise multiple stock holdings of cable, joints and tools.

ii)

Resistively Earthed Conditions

For stations in a network with the neutral earthed over a high resistance, there are scarcely any difficulties in mastering earthing problems if only consideration to earth-fault currents flowing for a single-phase earth-fault is taken. When a poly-phase fault occurs in a network earthed over a high resistance, in certain cases depending on the actual network impedances, short-circuit currents of the same order of magnitude as those for a single-phase earth-fault in a solidly-earthed network can occur. A polyphase earthfault means that two or three different phases in the same system have an earth-fault. The fault can occur in geographically separate places. Such faults within the substation or generator yard will cause the greatest flow. Therefore, conductor size is chosen to meet the maximum expected current (and a direct path to minimise impedances) flowing until cleared by the primary protection scheme (the use of the secondary (or ‘backup’) scheme clearing time is considered an unnecessary contingency). iii)

Transient Fault Conditions

Transient or high frequency fault currents are associated with; lightning spires, lightning arresters, GIS installations. !

Lightning Spires

Lightning spire downleads, and overhead shieldwires acting as lightning protection over substations, will usually only conduct lightning surge currents. As these are of

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very short duration the following minimum areas are typically used: 35mm² 50mm² 107mm²

-

copper steel aluminium

Care should be taken to ensure that power frequency fault currents may not flow in such conductors if minimum areas are chosen. !

Lightning Arresters

Although the minimum conductor areas suggested above apply to the high frequency surge current, the power frequency ‘follow-through’ current is of full fault rating (unless the arrestor has special current limiting characteristics). Therefore, arrester earths are usually fully fault rated to cover insulation failure and flashover conditions. !

GIS Installations

In addition to the normal fault current rated bonds (to earth), GIS switchgear is susceptible to high frequency longitudinal induced current flow creating high voltages between parts of the GIS and the system earthgrid. The Transient Phenomena chapter of the Reference Manual discusses the additional bonding required to mitigate the operational and safety hazards of such surge currents. B)

Fault Current Duration

The fault current duration is often specified to correspond to the total clearing time defined as the greater of either the: !

Clearing time assuming that one primary protection system or associated operational equipment (i.e. circuit breaker, tripping coil) fails to operate. In this instance reclosure time is not usually applicable.

!

Total clearing time of the primary protection system and subsequent reclosures.

C)

Conductor Conductivity

The earth conductors and connections should be of sufficient conductivity to keep voltage drops to a low level. This requirement is usually fulfilled when conductors meet other electrical and mechanical constraints. D)

Thermal Breakdown Limitation

An earthing system must be designed to withstand energy dissipation in both the electrodes and the soil immediately surrounding the electrodes. The thermal characteristics of the conductors are discussed in Section 2.2 of the Reference Manual Installation Techniques Chapter

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Problems are possible in systems with limited amounts of conductor installed in high resistivity and/or areas susceptible to drying out. In these cases it is suggested that additional driven electrodes be installed to ensure that the current dissipating from each electrode is within limits and/or deep enough to contact low resistivity or moist earth.

10.2.1.2

Mechanical Rating

The mechanical rating of earth conductors is contingent upon the following factors: ! ! !

Externally applied forces; Force produced by the flow of earth fault current through the conductor; Corrosivity of surrounding media, and (galvanically) connected materials.

These subjects are discussed in the following three sections: A)

Minimum Conductor Size

The mechanical ‘strength’ requirement should determine the minimum conductor size. A conductor size, with the mechanical strength and rigidity to minimise the possibility of mechanical damage that is commonly used for unprotected conductor is 70mm² copper. B)

Electromagnetic Forces

Although electromagnetic forces on conductors are great, they do not dictate the minimum conductor size. Rather they specify the method and frequency of fastening of conductors to structures. Thus, where conductors are used as downleads from mounted equipment they should be fastened to the structure as often as necessary to withstand the short circuit dynamic forces. C)

Environmental Factors

Two environmental factors that effect conductor sizing, choice of material and installation location and methods are: i) ii) i)

Corrosion Physical Protection and Location

Corrosion

The corrosion of earth system conductors occurs due to the electrochemical reaction between dissimilar metals. The current which flows causes loss of material on the anodic surface. Corrosion problems are exacerbated when the anodic action is restricted to a small area (eg hole in pipeline covering). In this case the full current density is focussed on the small area, possibly removing material at a hazardous rate. The solution to such problems lies in a combination of the following corrective measures:

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Correct choice of materials; Careful installation procedures; Calculation of hazard magnitude; Installation of special protection (eg active or passive cathodic protection system).

The latter two steps are required if a hazard is still suspected, once the former two steps have been considered. The corrosion rate calculations and cathodic protection installation design is discussed further in the ESAA Earthing Reference Manual chapters on Direct Current Phenomena, Installation Techniques, and corrosion. !

Main Grid Material

The choice of main grid earthing materials to minimise corrosive activity has resulted in mostly copper conductors (wire and strip, or copper covered steel) being used. In less corrosive areas steel conductors may be used, whilst in corrosive areas stainless steel conductors are sometimes used. Aluminium conductors are not acceptable. ii)

Physical Protection and Location

The earthing conductors are required to withstand a number of physical stresses, including: direct impact, soil movement, vandalism. !

Direct Impact

The use of at least the minimum conductor size, (Section 10.2.1i)), and double or redundant connections (Section 10.2.3) on important equipment, should ensure reliable operation. !

Soil Movement

In certain areas where the ground is known to expand and contract (e.g. cold climates, areas with clay soil and alternating long and wet periods), it is considered prudent to install ‘loops’ or flexible ‘z’ sections to prevent undue stress being placed upon connections. !

Vandalism

The increase in vandalism and theft is resulting in a number of special design considerations: !

Above ground connections

Galvanised steel wire or strip is sometimes used for above ground connections on isolated installations. If copper is used underground, care should be taken to ensure the electrolytic action does not deteriorate the steel section.

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Fences

Conductors bonding to fences, and external ‘touch earth’ conductors, are sometimes used as a connection point by thieves. To prevent excessive conductor being ‘dragged’ from the grid, concrete blocks have been used to anchor the conductor. !

Anti-Climbing Precautions along the Tops of Walls

Where barbed wire or other metallic anti-climbing devices are erected along the top of brick walls and fences. These should be connected to earth using the same procedure as with fencing.

10.2.2

Conductor Sizing 10.2.2.1

Material Selection

Consistent with the preceding discussion regarding environmental factors, buried earthing systems are usually constructed of hard drawn stranded copper conductor, copper strip or hot-dip galvanised steel strip. Stranded aluminium conductors or aluminium strip may be used in covered cable ducts or as above ground connecting leads to framework and apparatus. However, aluminium conductors are not to be laid in the ground and should not come into contact with the soil.

10.2.2.2

Conductor Cross Section Selection

A minimum conductor size is specified by the mechanical considerations discussed in Section 10.2.1.2. The thermal considerations of conductor rating under fault conditions are also to be examined. The selection of an appropriate conductor size to withstand fault current without exceeding maximum temperature criteria may be based upon the Onderdonk formula [92], [93] following: A

=

conductor area (mm²)’ 1 2

 T   x 10 4 / TCAP c r r  A  I  ln 1  Tm  Ta  /  Ko  Ta    





(10-1)

where I Tm Ta Tr

= = = =

αo αr ρr

= = =

Rms current (kA) Maximum allowable temperature (EC) Ambient temperature (EC) Reference temperature for material constants (EC) (Table 10-1 uses 20EC as reference) Thermal coefficient of resistivity at 0EC Thermal coefficient of resistivity at reference temperature Tr. Resistivity of the earth conductor at reference temperature Tr (μΩ/cm3)

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Installation Techniques = = = =

1/αo (1/αr) - Tr Fault clearing time (s) Thermal capacity factor (J/cm3/EC)

=

4.184 . SH . SW

= =

Specific heat (cal/gm/EC Specific weight (gm/cm3)

105

(10-2)

where SH SW

Equation 10-1 is dependent upon two assumptions: !

All heat remains in the conductor - reasonable due to short clearing time (tc).

!

TCAP is approximately constant - reasonable as SH and SW vary in opposite directions at approximately the same rate for short values of tc.

Material constants required by Equation 10-2 are given for commonly used earthing conductors in Table 10-1 following [18]. Table 10-1 Earth Conductor Material Constants pr (at 20NC-μΩ/cm)

1053

1.7241

242

1084

1.7774

.00378

245

1084/1300

4.397

30

.00378

245

1084/1300

5.862

61

.00403

228

657

2.862

2.556

.00320

293

419/1300

20.1

3.931

.00130

749

1400

72

4.032

(at 20NC)

Standard Annealed Soft Copper Wire

100

.00393

Commercial Hard Drawn Copper Wire

97

.00381

40

Copper Clad Steel Core Wire Commercial EC Aluminium Wire Zinc-Coated Steel Core Wire Stainless Steel No. 304

Ko (1/αo-at 0NC)

Fusing Temp. (NC)

Conductivit y (%)

Conductor

8.5

2.4

αr

234

TCAP (J/cm3/NC)

3.422

3.422 3.846 3.846

Minimum conductor size calculation results for a range of conductor types are given

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in Table 10-2 and Figure 10-2 as an example. The temperature range used in Table 10-2 and Figure 10-3 are as follows: Ta Tm

= =

Ambient temperature Maximum allowable temperature

= =

40°C 450°C

Guidelines for maximum conductor temperatures are usually limited by jointing/connection methods as follows: C C C

Soft soldered joints: Tm Brazed joints: Tm Fully rated (ie. Temperature): Tm (copper)

# # #

240°C 450°C 1050°

Table 10-2 Minimum Conductor Size Minimum Conductor Size (mm²/kA) Fault clearing time tc (s)

(100%)

(97%)

0.1

1.866

0.2

Aluminium Cable

Zinc Coated Steel

Stainless Steel (No. 304)

1.886

2.793

5.785

9.918

2.638

2.667

3.949

8.181

14.026

0.5

4.171

4.216

6.244

12.935

22.178

0.75

5.109

5.164

7.648

15.842

27.162

1.0

5.899

5.963

8.831

18.293

31.364

1.5

7.225

7.303

10.816

22.404

38.413

2.0

8.343

8.433

12.489

25.87

44.355

3.0

10.218

10.328

15.296

31.684

54.324

Copper

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60 Copper Aluminium Mild Steel Stainless Steel

50 40 30 20 10 0 0

0.5

1

1.5

2

2.5

3

3.5

Fault Clearing Time (Secs)

Figure 10-3: Minimum Conductor Size Several further factors to be considered when determining the final conductor cross sectional area are: !

Current Splitting

If the earth fault current, upon entering the buried section of the earth grid, travels in two directions, it is assumed that the current divides on a 70/30 basis (some standards suggest 80/20 or 50/50 distribution). Thus, such buried conductors do not require full fault rating. !

Fault Clearing Time

The malfunction of protection relays or other equipment will cause the fault current to persist until the backup protection operates. As the failure of protection, control or operating equipment may remain unnoticed until requested to operate, it is considered that the use of backup clearing times is prudent and not introducing unwarranted contingencies. !

Future Growth

The ultimate value of fault current used should allow for the possibility of future growth of the system and attendant fault level increases. The provision of an added safety factor at the time of initial installation by selecting a larger sized conductor is usually economically justified considering the larger cost involved in future re-enforcement of the conductors. The use of limited standard conductor types reduces the amount of stock required for both conductors and connectors, and often simplifies installation.

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Connections The connection of earthing conductors to above ground equipment, driven stakes and other buried earthing conductors is discussed in detail in the ESAA Earthing Reference Manual, Installation Techniques Chapter. As mentioned in the section regarding ratings of the earthing conductors, the joints must meet the criteria for conductivity, thermal capacity, mechanical robustness and long term reliability [94]. The joints are usually the most vulnerable point in the earthing system, and must continue to withstand the electrical/thermal and mechanical stresses even in a corrosive environment.

DESIGN STEP 6

10.3 Designing The Installation Each installation is designed according to a number of factors: standard design methods, redundancy and security level requirements, (eg high fault level, high reliability criteria locations), financial constraints, physical constraints (eg high resistivity bedrock location) and safety criteria (eg urban installations). This section provides a brief overview of a number of approaches commonly adopted when designing the physical implementation of an earthing system. Guidelines for the earth grid layout, and connection of substation equipment to the earth grid is provided in the ESAA Earthing Reference Manual for a wide range of equipment including: open-type outdoor switchgear, transformers, cable sheaths, current busbars, indoor installations, substation service equipment, non-electrical constructions, gas-insulated switchgear. !

Guidelines for General Grid Layout

Guidelines for the overall layout and interconnection of earth system elements is briefly addressed in the following sections. 1. 2. 3. 4. 5.

10.3.1

Horizontal mesh layout. Driven rod placement. Structural members. External connections. Auxiliary test electrodes.

Horizontal Mesh Layout While many different mesh layout policies can be used, a number of basic principles may be identified. Figure 10-4 from [95] illustrates a typical mesh layout of one bay of a large outdoor air insulated switchyard.

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A typical grid earthing electrode in a 110 kV outdoor switchgear including one empty and one equipped bay. Annotation: 1 2 3 4 5 6 7 8 9 10 OK

Circuit breaker Disconnector Disconnector and earthing switch Current transformer Coupling capacitor Line trap Support insulator Termination gantry Cubicle for control devices Switchgear fence Earthing withstanding short circuit between poles to be temporarily earthed.

Figure 10-4: Mesh Layout for A Large Air Insulated Switchyard Section The horizontal mesh conductors are placed according to a number of requirements:

A)

Touch and Step Voltage Criteria

In both large and small installations, the horizontal meshes play an important role in maintaining local voltage gradients within safe limits. In most cases the current density is highest at the periphery of an earthing system, therefore, the addition of extra conductor in these regions tends to reduce the step and touch potentials. Several approaches are given as examples in Figure 10-5 following.

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Figure 10-5: Mesh Conductor Placement to Reduce Voltage Gradients Figure 10-5 a) style designs are often seen when touch voltages are so high that a ‘touch earth’ is installed 1m from the fence both outside the yard and inside. The decision of whether or not to bond the fence to the main grid is discussed in the Power Frequency Voltages Created Chapter, and further installation guidelines addressed in the Earthing Reference Manual. The provision of a touch earth inside the fence is not often made due to the effect of the crushed rock (and safety shoes) in limiting the body current that might flow under fault conditions. Local voltage gradient control mats or loops are often placed on the surface adjacent to operating mechanisms (eg isolator and earthing switch handles) to reduce the risk of operators receiving any shock.

B)

Fault Current Dissipation

The dissipation of large power frequency fault currents often requires that two or more paths be provided to minimise the heating effect on the conductors (eg. at surge arresters and earth switches). The full three phase fault current rating is required for earth conductors between single phase earth switches.

C)

Inductive Effect Reduction

Parallel coupling of transient currents with control cables may yield high induced voltages which may cause damage and/or malfunction of equipment. Therefore, current paths are multiplied from sources of such currents (eg. surge arresters) and coupled into the mesh network as quickly as possible. The Reference Manual

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Installation Techniques chapter discusses the practical aspects of installing control cables, while the mechanism of transient earth potential rise (TEPR) is investigated in detail in the Reference Manual Transient Voltages Chapter. Very high power frequency currents running parallel to control circuitry over ‘large’ distances (say $20m) may give the same effect as shorter high frequency parallel couplings.

D)

Impedance Reduction

A close surface mesh network does little to reduce the grid impedance. However, Kercel [25] illustrates the beneficial effect of a widely spaced mesh (placed on the natural surface prior to backfilling) on grid impedance reduction.

E)

Redundancy Level Required

In high fault level, high reliability/security substations duplication of bonds and mesh conductors is often considered prudent. Each bond is fully fault rated and installed in opposite directions to different mesh conductors. This ensures fast fault clearance even if one bond is broken, to minimise fault energy flowing through costly equipment (and thereby protect the faulted apparatus and also neighbouring equipment if tank or insulator rupture is prevented).

10.3.2

Driven Rod Placement Driven earth electrodes (either rods, stakes, pipes, cables, strip) are often installed for the following reasons: A) B) C) D)

A)

Grid Impedance Reduction. Stabilisation of Grid Impedance. Touch and Step Voltage Reduction. Transient Current Energy Dissipation

Grid Impedance Reduction

Vertically installed rods often have higher current dissipation than horizontally buried conductors due to the proximity effect (refer Section 7.1.6). If the driven rods penetrate a low resistivity soil layer their current dissipation increases greatly, resulting in a cost effective grid impedance reduction. Such effects are especially valuable for grids of small area. The large surface area of major transmission and generation stations reduces the need for deep driven earth electrodes. Such rods are more effective if placed around the perimeter of the earthing system. However, to maintain highest energy dissipation they should be separated by a distance equal to one or two times the rod depth (preferably two times).

B)

Stabilisation of Grid Impedance

In areas where the surface layer (top 1-2m) resistivity fluctuates widely with seasonal changes, driven rods play an important role. When the top layer dries out (or freezes)

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the horizontal mesh electrodes may contribute little to the fault energy dissipation, and driven rods are used to maintain contact with the lower resistivity earth. In some areas where the ground is frozen for over 6 months of the year grid designs are made on the basis of driven rods alone (eg Canada [24]). However for very large transmission and generation installations (in most of Australia) the large grid area is effective in maintaining impedance stability.

C)

Touch and Step Voltage Reduction

In addition to the reduction caused by a decrease in impedance (and hence EPR) some measure of local gradient control is achieved with driven rods. This factor is rarely considered significant or economical within substations, as judicious placement of horizontal mesh conductors and the use of crushed rock is usually more effective.

D)

Transient Current Energy Dissipation

The provision of an earth stake (2-4m) length) is considered useful in dissipating transient fault energy quickly, and containing it within a small area. Therefore, one or two earth stakes are normally driven at the foot of structures supporting lightning spires, surge arresters and CVT’s.

10.3.3

Structural Members For most transmission and distribution installations structural members are considered part of the secondary earthing system. They are connected to the system, but not usually considered necessary to meet safety criteria. However, for large interconnected earthing systems such as power stations and industrial complexes, structural members are often designed as necessary parts of the primary earthing system. Special care is required to ensure adequate bonding of reinforcement and current dissipation levels kept low to prevent concrete ‘spalling’ and corrosion.

10.3.4

External Connections Connections to external earthing conductors such as underground cables, OHEW’s, and the MEN system play a vital role in the earth system performance. These connections should be: !

Rated adequately to withstand expected fault currents (eg older jute served steel wire lead armoured 11kV cable sheaths often dissipate 40-70% of fault energy in urban locations).

!

Not creating transfer potential hazards.( eg HV fault energy impressed onto the LV MEN network, or inductively coupled current causing transfer of hazard to an underground/overhead transition point in HV system). In certain instances it is prudent to install isolation between the substation and the external connection. Telecommunications and pilot cables are usually installed with isolation transformers (refer EPR Code of Practice [77], and sometimes isolation transformers are used in conjunction with station backup

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supply from the local MV reticulation.

10.3.5

Auxiliary Test Electrodes It is sometimes considered necessary to segregate electrodes or earthing systems to check earth resistance fluctuations. However, once a main earth grid has been established in a substation, it is difficult to achieve segregation of independent sections of the grid for periodic testing. Where main earth grids on adjacent sites are connected together, it is usually practical to insert links in the tie connections to enable segregation of the sites. It is preferable to locate these links in a sunken concrete box, or mounted on walls, structures, posts, where they will be readily visible and can be suitably labelled. However, if installed a sunken box care should be taken to ensure that the bolted connection is kept clear of soil to minimise corrosion effects. Sometimes a test electrode is installed in the middle of a large mesh and bonded to the main grid by PVC covered cable to minimise coupling to the main grid during tests. Several warnings are associated with the use of such test electrodes: !

Safety precautions must be taken during routine testing to prevent operators coming into contact with high touch voltages (ie use of gloves and rubber mats).

!

Special precautions should be taken to prevent inadvertent disconnection of main earth connections.

!

Separate bolted links for each earth electrode of a group in close proximity are not required or recommended, as they are likely to reduce the reliability of the installation.

!

Routine tests using portable earth testers and “short” current/voltage lead lengths are considered of limited worth, unless the site is small and inductive coupling negligible. Maintenance and supervision of the earthing system is discussed further in Chapter 12.

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11 Testing Methods DESIGN STEP 23

Accurate test methods based on current injection from a remote point are required for the following reasons: !

Analytical design calculations can not prove installation safety, they can only act to guide the engineer to the most effective design. Therefore, the safety of an installation should be proven by test.

!

Errors in calculation of EPR may be quite large using traditional empirical formulae (up to a factor of 5 or 15, Fortin [101]). In such cases safety criteria of personnel and insulation levels on telecommunications equipment may be exceeded creating dangerous situations.

!

Portable test instruments are not sufficiently accurate for large installations in lower resistivity soil (ie. Rgrid n 0.5Ω).

!

Earth system impedance may be significantly greater than the resistance component for large grids in low resistivity soil, or for grids with many extended earthing conductors (eg. OHEW, or cable sheaths).

Test methods are required that enable accurate measurements to be made of: grid impedance, EPR, current distributions, as well as step, touch and transfer voltages. Accurate testing is difficult to achieve, yet necessary to validate design calculations and check installation safety and equipment operation, as the first step in the ongoing control process.

11.1 Impedance Measurements Using Portable Meters Determining the impedance to remote earth of a localised earth electrode is, in some cases, a straightforward measurement problem requiring nothing more sophisticated than a portable earth tester, some earth rods, and few hundred metres of wire to reach a remote current probe location. The use of portable earth resistance meters is useful in providing a fairly simple check of grid resistance, which may be used as part of the periodic grid integrity check. Unfortunately, the portable earth tester is inadequate in a large number of cases, as outlined in the following section. It has been shown that many ‘low power’ units are not appropriate for measuring impedances lower than 1Ω (some even 2Ω!!). The instructions provided with the portable resistance meters usually suggest that the voltage probe be located at a distance equal to 60% of the current lead length (based on work by Tagg [33]). This recommendation is acceptable for small localised earthing systems. However, when testing larger systems, additional guidelines are recommended as follows: • •

Use the ‘fall-of-potential’ method, outlined in Section 11.2.2. Use a current lead length at least equal to 5 times the largest grid/system

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diagonal dimension (both horizontally and vertically). Keep the test leads separated from metalwork external to the grid being tested, as it may ‘short-circuit’ the test current circuit giving very ‘satisfactory’, yet incorrect readings. Caution should be taken to ensure that conductive and inductive interference components are taken into account when making the initial measurements (see Section 11.2.3). Simplified methods are available for overcoming or determining the interference effects. It is recommended that the initial test lead configuration and results be documented for reference when doing future tests.

11.2 Earth System Injection Testing The validation of the adequacy of an earthing system, to meet design and safety criteria, can only be done through experimentation. Earthing systems for substations comprise many component types, covering a wide range of areas, from 25m2 to over 20 000m2. Components include the primary mesh conductors and driven earth electrodes coupled to other metalwork such as; L.V. neutrals, overhead earthwires (OHEW), underground cable sheaths, direct buried counterpoise conductors and tie conductors to other grids and pipelines. In addition the relation to and effect upon adjacent yet not directly bonded metalwork such as pipes, communications cables, tanks and buildings must be considered. Calculations of voltages and currents associated with the performance of such earthing systems are impaired by over simplification of the system, and inaccuracy or oversight of the necessary parameters. In a similar way measurements may also be affected by lack of information and therefore, inadequate planning. Measurements are also affected by other problems such as interference, non-linearity errors and practical obstacles. The testing of substation earthing systems to prove compliance with design and safety criteria requires careful examination of possible ways to reduce errors. It has been found that an appropriate instrumentation and test equipment configuration, combined with calculations, enables the operational difficulties to be overcome. !

Impedance Measurements by Full Injection Test

In many cases the measurement process is complicated by factors which may preclude the use of portable testers and necessitate a full injection test. These factors include high ambient electrical noise levels, large grid dimensions, interconnections of grids with other earthing systems, buried piping, very low soil resistivity values, and difficulty in obtaining a suitable remote current probe location. Very low soil resistivity values coupled with an extensive grid network may lead to significant longitudinal voltage gradients in the earth network conductors which cannot be neglected with respect to the potential at the current injection node of the earth network. Therefore, the earth potential rise of an earth network is no longer uniquely defined. To remove any ambiguity, a specific reference point must be defined. Systems with a large number of overhead earthwires may have a large reactive component which may not be measured by a basic resistance tester or underground

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cables connected. In certain cases, if the earth resistance is beneath a set value, it may be possible to conclude that the step, touch and transfer voltages are within safer limits. (Eg Design Step 9)However, if any hazard locations exist which have not been modelled, or which appear to be close to the safety limits, an injection test with full measurements of step, touch and transfer voltages should be undertaken. The following sections provide an overview of the testing methods presently used: 1. 2. 3. 4. 5.

11.2.1

Testing purpose Testing principle Difficulties in measuring low impedances Low current injection method benefits. Measurement of step and touch voltages

Testing Purpose An injection test is undertaken to determine the following factors: C

Earthgrid Potential Rise

The calculation of the earth potential rise (EPR) permits the optimum choice of protection equipment for communication cables. The accuracy of the earth impedance magnitude is a determining factor in this choice. In the past empirical calculation methods have yielded errors reaching factors of between 5 and 15 in some cases. Such a situation can create dangerous conditions among personnel working inside the substation, and distrust for installations outside the substation. Therefore, accurate analytical calculation methods and injection testing procedures are required. C

Current Distribution

The complexity of earthing systems has increased due to the higher short circuit levels and equipment density characteristic of modern installations. The design of earthing systems has become increasingly sophisticated and construction very expensive. It becomes necessary, therefore, to perform measurements to assure the efficiency of the main components that contribute to drain current into the earth. Alternative current paths include overhead earth wires and counterpoises in transmission lines, distribution circuit neutrals, cable sheaths and other metallic structures connected to a substation, as well as any other metallic pieces connected to the earthing system. The ratio of the current drained over the injected current, for each of the elements, enables an evaluation to be made of the efficiency of each earthing system component. Both current magnitude and phase measurements are required to enable the inductive and conductive components to be identified.

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Personnel Safety

Possible step, touch and transfer voltage hazard locations associated with metalwork in or adjacent to an earthing system, must been identified and measured to ensure safety for power authority personnel and the public.

11.2.2

Testing Principle The testing principle, based on the application of the fall-of-potential method [97] consists of injecting a current between the earthing system under test and a remote earth [99] - [100]. !

Fall-of-Potential Method

The test principle consists in circulating a current through the earthing system impedance under test and measuring the potential rise caused by this current. Figure 11-1 shows the basic circuit.

Figure 11-1: Fall-of-potential basic circuit To find the maximum value of Vm (used to determine the earthing system impedance) the potential of the earthing system would be measured with reference to a test potential electrode placed at increasing distances from the earth system until the difference between two or three successive voltage readings is negligible (assuming the test current is held constant). As a further check, the current probe distance may be increased significantly, and potential measuring procedures repeated. Even under ideal conditions, of perfectly homogeneous earth and no extended earth connections, current probe spacing extended to 50 times the maximum earthing system dimensions will give an expected measurement accuracy of only 98.5%. Eg. A typical case of a 50 x 70m substation, gave VM (500m) = 97% EPRmax (computed), in low resistivity soil conditions, with an injection point 5000m distant. At the point where the current and potential electrodes are at remote earth, and assuming that the measurements are not influenced by mutual coupling or other

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interference, the earth system impedance may be found by the following equation:

Zg 

Vs     Is

(11-1)

Further testing guidelines covering the following topics are covered in the pursuing sections: a) b) c) d) e)

a)

Current Probe Separation Potential Probe Separation Angle Between Current and Potential Leads Potential Measurement Details Impedance Weighting

Current Probe Separation

The current injection point should be far enough removed to be considered at ‘remote earth’ potential. Values of between 5 and 10 times the substation diagonal dimension (Dsub) are often used. IEEE80 [18] Section 5.1 recommends a 6.5 times factor, with external conductor lengths added to the grid diagonal to yield a total distance. Horizontal and vertical dimensions should both be considered in this assessment. Care should be taken with this approach, as the effective length of long buried conductors is dependent upon soil resistivity. In high resistivity soils greater length is active before the input impedance reaches a maximum or ‘characteristic’ value. Under such high resistivity conditions the distance between injection points should be quite large. (eg, in soils of resistivity over 1000 Ωm distances of 5-20 km may be required.) Figure 11-2 illustrates the effect of insufficient current probe spacing (point C1).

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Figure 11-2: Fall-of-potential method RA R C1

= = =

Apparent resistance (V/I against x) True resistance Current electrode too close

C2

=

P x(m)

= =

Current electrode sufficiently far away Potential electrode Distance to potential Electrode

The striped part of zero slope in curve C2 indicates the true resistance value, as the soil surface in this zone is not affected by the two electrodes. Curve C illustrates the effect of a probe spacing that is insufficient, thereby, negating the validity of the potential measurement.

b)

Potential Probe Separation

In practice measured potential increases with distance, until it appears to stabilise. The ratio, at a given distance, of the potential over the injected current gives the apparent impedance at such a distance. Figure 11-3 illustrates the shape of a typical apparent impedance curve.

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Figure 11-3: Apparent impedance ZA(Ω)

c)

=

Apparent impedance

x(m)

=

Distance to potential electrode

Angle Between Current and Potential Probe

It is preferable that the potential lead be extended at an angle of 90E with respect to the current injection line. When the angle is not 90E the mutual coupling will induce voltages in the potential leads that will give erroneous impedance values if not adequately corrected. Figures 11-4a and 11-4b illustrate typical variations in measured impedance due to A.C. mutual coupling.

11.2.3

Figure 11-4a: Apparent Impedance for Z > 0.5Ω

Figure 11-4b: Apparent impedance for Z < 0.5Ω

ZA x(m)

Θ

= =

Apparent Impedance Distance to potential electrode P

= Angle between current and potential cables

Difficulties in Measuring Low Impedances For a complex electrode, such as an earthing system of an substation, the earth resistance is very low. Many instruments cannot measure low resistances, and the great majority of them do not account for the reactive part. In addition to the required instrument capabilities, testing configuration and analytical calculations are required

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to handle errors due to power frequency standing voltages and injection current induced voltage errors.

A)

Power Frequency Standing Voltages

The large dimensions of the test circuits in the current injection method make them prone to the influence of interfering earth potential differences and magnetic fields. There may exist currents other than that injected, which flow through the station earthing impedance (but not necessarily through the ammeter), thereby giving rise to a corresponding earthing voltage. If a staged fault injection test is undertaken with currents in the order of 1000A or more, interference seldom has any significance. However, low voltage power frequency and off-power frequency tests are affected by such voltages. A number of methods for eliminating such effect have been used, including: phase reversal, interference compensation, beat frequency method, tunable voltmeter, and signal analyser [101], [105].

B)

Injection Current Induced Voltage Elimination

Interference also occurs in the measurements due to injected current flowing in the earth and the grid conductors causing mutual resistance and A.C. coupling effects respectively. These effects are discussed in the following sections: i) ii) i)

Earth mutual resistance effect mitigation A.C. mutual coupling effect mitigation

Earth Mutual Resistance Effect Mitigation

Measurement errors result from the mutual resistance between Grid and Potential Probe, the mutual resistance between Current Probe to Potential Probe, and the mutual resistance between Current Probe to Grid. The resistive coupling is a function of probe separation and soil resistivity [97]. Problems due to mutual effects between probes appear when the impedance to be measured is around 0.5 Ω, and the measurement error increases as the impedance and separations diminish. As any empirical equations are only valid for uniform earth grids, and at distances from greater than the diagonal dimension, an analytical approach is required for earthing systems that have extended conductors. ii)

A.C. Mutual Coupling Effect Mitigation

C

Effect of Injection Current Circuit

A second source of measurement error is the inductive coupling between the injected current and potential leads. This mutual coupling causes the ac test current in the current test lead to induce a voltage into the potential test lead that adds vectorially to the actual grid voltage. Mutual inductive impedance errors will be the largest when test conductors are

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parallelled, however, any angle apart from 90° will yield some error. When mutual impedance magnitude is equal to, or greater than, the earthing impedance, error in calculating mutual impedance components can result in large errors in earthing impedance determination. Therefore, inductive coupling calculations are required to determine the component of test current available for inducing an error in the remote voltage lead. C

Effect of Extended Grid Conductors

Large earthing systems may include buried neutrals, overhead neutrals, overhead earth wires, control and communication shields, buried bare grid tie conductors, water pipes, gas lines and railroad tracks. The extended nature of these components may introduce additional measurement error by induction into the voltage lead.

11.2.4

Comparison of Injection Methods While high power 50Hz injection has been the ‘traditional’ test method, low current injection methods have been used widely over the last ten years. To avoid background noise interference from the active power system or external sources, a non power frequency signal is injected. At these frequencies an amplifier with an output signal of between 1 and 10 amps will usually provide sufficient measurement accuracy. Due to the small current magnitudes, the injection cables may be of quite small cross-sectional area. Although still requiring careful test planning and result interpretation, the low power method yields accurate results with significant operational and economic benefits as outlined below. C Tests may be undertaken with substation in service. C No network reconfiguration required if using own injection cable (# 10 Amps). C No protection equipment alterations required. C No power frequency induction interference problems. C Time and cost reductions (typically