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Alberta Power Industry Consortium & University of Alberta

Professional Development Course

Power System Grounding – Industry Experiences

Organized By

Alberta Power Industry Consortium & University of Alberta AESO AltaLink ATCO Enmax Epcor FortisAlberta

Instructed By

Joseph Kuffar & Dennis Peters, Enmax Nerkez Lalic, Epcor

Dennis Rasmusson, AltaLink Wilsun Xu, University of Alberta

May 28 & 30, 2013

Calgary & Edmonton, Alberta, Canada

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Abstract

Power system grounding is probably one of the most confusing subjects in the field of

power engineering. It covers a wide range of topics, such as short‐circuit responses of

power networks, electric field distributions of grounding structures, and implications to

safe work practice. This course is a continuation of the 2012 APIC course on power

system grounding. Building on the fundamental theories taught last year, the current

course will share actual industry practices, experiences, investigations of the APIC

companies. Relevant technical concepts and theories behind the practices will also be

explained to facilitate learning. This course will mainly focus on grounding related

electrical safety issues. A few cases involving the grounding performance of power

systems will also be discussed.

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Confidentiality Requirement

This course material was prepared by the University of Alberta for the ultimate benefit of the Alberta Power Industry Consortium members (hereinafter called “SPONSORS”). It may contain confidential research findings, trade secrets, proprietary materials (collectively called “Proprietary Information”). The term Proprietary Information includes, but is not limited to, plans, drawings, designs, specifications, new teaching materials, trade secrets, processes, systems, manufacturing techniques, model and mock-ups, and financial or cost data.

The document is made available to the sponsors only. The Sponsors will use all reasonable efforts to treat and keep confidential, and cause its officers, members, directors, employees, agents, contractors and students, if any, (“Representatives”) to treat and keep confidential, and Proprietary Information in the document and the document itself. This course material shall not be disclosed to any third party without the consent of the Alberta Power Industry Consortium.

Disclaimer

This document may contain reports, guidelines, practices that are developed by the University of Alberta and the members of the Alberta Power Industry Consortium (APIC).

Neither the APIC members, the University of Alberta, nor any of other person acting on his/her behalf makes any warranty or implied, or assumes any legal responsibility for the accuracy of any information or for the completeness or usefulness of any apparatus, product or process disclosed, or accept liability for the use, or damages resulting from the use, thereof. Neither do they represent that their use would not infringe upon privately owned rights.

Furthermore, the APIC companies and the University of Alberta hereby disclaim any and all warranties, expressed or implied, including the warranties of merchantability and fitness for a particular purpose, whether arising by law, custom, or conduct, with respect to any of the information contained in this document. In no event shall the APIC companies and the University of Alberta be liable for incidental or consequential damages because of use or any information contained in this document.

Any reference in this document to any specific commercial product, process or service by trade name, trademark, manufacture, or otherwise does not necessarily constitute or imply its endorsement or recommendation by the University of Alberta and/or the APIC companies.

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About the Alberta Power Industry Consortium:

The Alberta Power Industry Consortium consists of six Alberta utility companies (AESO,

AltaLink, ATCO, Enmax, Epcor and FortisAlberta) and the University of Alberta. Established in

the fall of 2007, its goal is to bring Alberta power companies together, with the University of

Alberta as the coordinating organization, to solve technical problems of common interest, to

produce more power engineering graduates, to support the professional development of

current employees, and to promote technical cooperation and exchange in Alberta’s power

utility community.

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About the instructors:

Mr. Joseph Kuffar is a 2004 graduate of Electrical Engineering from the University of Saskatchewan.

Joseph has 9 years technical engineering experience. His work experience includes system planning,

distribution system design, material standards and QC, and asset management (distribution &

network). He is currently holds a position with ENMAX as Supervising Engineer, T&D Asset

Management. Joseph is a registered professional engineer in the province of Alberta.

Mr. Nerkez Lalic is a 1972 graduate of Electric Power Engineering Faculty from the University of

Sarajevo, Bosnia & Herzegovina. He worked for international equipment manufacturing,

engineering and consulting companies on the design, construction, testing, commissioning and EPC

management of high voltage substation and overhead/underground transmission line projects. He

has been with EPCOR for nine years and currently holds the position of Senior Manager,

Transmission Projects. Mr. Lalic has a special interest in improving EPC processes of complex

engineering projects, focusing on implementation of COAA standardized engineering contracts in

practice and safety standards improvement, coordination and implementation during execution of

complex construction works. Mr. Lalic is a registered professional engineer in the province of

Alberta.

Mr. Dennis Peters is a 2008 graduate of Electrical Engineering from the University of Saskatchewan.

Dennis worked for ENMAX upon graduation and has 5 years of engineering experience. His work

experience includes network secondary distribution customer and system design and recently

network and distribution asset management. He has special interest in network secondary

distribution material specifications and material QC and QA. Dennis currently holds a position with

ENMAX as T&D Asset Management Engineer. Dennis is a registered professional engineer in the

province of Alberta.

Mr. Dennis Rasmusson is a 1972 graduate of Electrical Engineering Technology from NAIT in

Edmonton. Upon graduation Dennis spent the first 10 year of his career in the field in the area of

protection and control. He spent the next 17 years in various positions in management in both

transmission and distribution. During this time his roles included Manager of Substation

Construction and Operations, Regional Transmission Maintenance Manager, Area Manager of

Sherwood Park, and Director of Asset Management. During the last 15 years his main focus was on

safety and held roles of Safety Manager and Director of EH&S. He has been working in the

electrical utility industry for 42 years. In 2010 Dennis started his retirement by working as a safety

specialist on a reduced work week and plans on retiring late 2013.

Dr. Wilsun Xu obtained a B.Sc. degree from China in 1982 and PhD from UBC in 1989. He worked

in BC Hydro from 1989 to 1996. He joined the University of Alberta as a faculty member in 1996 and

is currently a research chair professor at the U of A. Dr. Xu has extensive engineering and research

experiences in the area of power quality. His research work on multiphase power system analysis

has helped him to formulate a methodology to analyze faulted power systems with complex

grounding configurations. In recent years, Dr. Xu has used the methodology to investigate several

issues related to power system grounding. Dr. Xu is a registered professional engineer in the

province of Alberta.

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Course Outline

1. Review: Basic concepts of power system grounding

Performance grounding versus safety grounding

Basics of safety grounding

Basics of performance grounding

2. Grounding and safe work practice

Theory: Equipotential bonding and grounding transmission lines

Case: Working on isolated transmission facilities – Altalink practice

Case: Deep grounding‐well method for improving Epcor substation

grounding

Theory: Characteristics of GPR as affected by grounding

arrangements

3. Grounding performance of power systems

Theory: measurement of grounding resistances

Case: Distribution grounding system assessment and replacement

program of Enmax

Case: Bonding feeder and substation neutrals – pros, cons, and ATCO

practice

Case: Does improving grounding help to reduce telephone

interference?

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Alberta Power Industry Consortium & University of Alberta

Professional Development Course

by Wilsun Xu, Professor

[email protected] Department of Electrical & Computer Engineering

University of Alberta

May 2013

Power System Grounding - Industry Experiences

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Background of this course

• The 2012 APIC course covered various concepts & theories of power system grounding;

• The course feedback indicates that there is an interest to learn actual cases and industry experiences on grounding;

• This course is developed as a continuation of the last year’s course, with a focus on industry applications and experiences;

• Key theories will also be reviewed to enhance learning;

• Industry speakers are invited to share their experiences

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Background of this course Industry instructors & cases

Joseph Kuffar, Supervising Engineer, T&D Asset Management, Enmax Dennis Peters, Engineer, T&D Asset Management, Enmax Nerkez Lalic, Senior Manager - Transmission Projects, Epcor Dennis Rasmusson, Safety Specialist, AltaLink

•Theory: Equipotential bonding and grounding transmission lines •Case: Working on isolated transmission facilities – Altalink practice

• Case: Deep grounding-well method for improving Epcor substation grounding

• Case: Distribution grounding system assessment and replacement program of Enmax

Case: Bonding feeder and substation neutrals – ATCO practice Case: Grounding and telephone interference – U of A findings

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Course Outline

Part I - Review: basic concepts of power system grounding • Performance grounding versus safety grounding • Performances of networks versus grounding structures

Part II - Grounding and safe work practice

• Theory: Equipotential bonding and grounding transmission lines • Case: Working on isolated transmission facilities – Altalink practice • Case: Deep grounding-well method for improving Epcor substation grounding • Theory: Characteristics of GPR as affected by grounding devices

Part III - Grounding performance of power systems

• Theory: measurement of grounding resistances • Case: Distribution grounding system assessment and replacement program of Enmax • Case: Bonding feeder and substation neutrals – pros, cons, and ATCO practice • Case: Does improving grounding help to reduce telephone interference?

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Part I

Quick Review of Last Year’s Material

• When performing short-circuit analysis, you encounter If-1ph>If-3ph. What does it mean? If this is a concern, what can you do?

• What is temporary overvoltage (TOV)? What is the impact of grounding on TOV?

• What is GPR and what is the profile or distribution of GPR?

• What is the step voltage?

• Why grounding through a feeder neutral is better than grounding through a temporary grounding rod?

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1. Introduction

Transformer: Generator: Line neutral:

G

Load:

G

a b c N

Grounding means connecting a network point (node) to the ground directly or through an impedance. It also means connecting unenergized elements of equipment to ground.

Enclosure

De-energized line

11

We classify grounding practices into two broad types:

1. Safety (protective) grounding

2. Performance grounding

• Grounding is made primarily for safety reasons • The grounding element is normally unenergized • Example: trip grounding for workers

• Grounding is used to improve power system performance • The grounding element is normally energized • Example: grounding of transformer neutral point • Performance considerations include reducing equipment insulation requirements, improving service reliability, mitigating interference etc.

1. Introduction Why ground?

12

Example of safety (protective) grounding:

1. Introduction Why ground?

Example of performance grounding:

b

c

a

b

c

N

a

Solidly grounded system Multi-grounded neutral (MGN) system

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Mesh (grid) Rod Buried wire Buried plate

1. Introduction How to ground?

From the system perspective, grounding is just a node connected to ground ( ). In reality, it is realized using ground structures/devices

Sample grounding devices

Main concerns for grounding devices: • Effectiveness to provide a ground: grounding resistance

• Voltage rise and distribution when a current flows into it

Performance issue

Safety issue

Ground surface

Ground potential rise (GPR) Surface potential

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1. Introduction

Issues of concern for performance grounding:

1. Temporary overvoltage (TOV)

2. Fault current

3. Protection

4. Reliability

5. Power quality

6. Signal interference

7. …

These are the most important concerns affecting the selection of grounding schemes. Economic issue.

Under perfect balanced system condition, the grounding points have zero voltage, so grounding does not affect normal system operation. It affects a system when the system becomes unbalanced due to faults or loads.

System performance

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1. Introduction Summary

IEEE C62.92 - Guide for the Application of Neutral Grounding in Electrical Utility Systems Part I – Introduction Part II - Grounding of Synchronous Generator Systems Part III- Generator Auxiliary Systems Part IV- Distribution Part V- Transmission Systems and Subtransmission Systems

IEEE Std. 80 - Guide for Safety in AC Substation Grounding IEEE Std. 81 - Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System

There are, therefore, two aspects on grounding practices

Aspect 1: Network performance consideration Aspect 2: Safety considerations

Aspect 1:

Aspect 2:

This course mainly deals with safety grounding issues 16

2. Review – Safety (Protective) Grounding

Worksite Safety Measures:

Barricade - reduce electric contact Insulation (mat, glove, boots) – reduce current flow to workers Grounding – reduce hazard duration and GPR Equipotential zone – reduce voltage differences in the site

May also related to grounding

Each measure shall work independently

17

The hemispherical electrode at the surface of earth

Iground Network Perspective

(grounding resistance)

Safety perspective

(GPR)


x

VGPR

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Grounding device

I

V1=I*R1

V2=I*R2

Grounding resistance (R1 or R2) determines V1 or V2 (i.e. GPR at the grounding spot)

However, the distribution of ground potential depends on the type of electrodes

Different type of electrodes

Similar type of electrodes


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If the electrodes are close to each other, the total grounding resistance is greater than the parallel of the two electrodes, i.e. Ra ≠ 0

Vtotal


a) Interfering Electrode

20

1. Touch and step voltages 2. Electrical model of human body 3. Human response to electricity


Other important concepts:

These concepts will be reviewed in more detail in the next presentation

21

Two key performance concerns: 1. Fault current carrying capability of power equipment

It is desirable for all types of fault currents (1φ, 2φ faults etc.) to be less than the three-phase fault current. If3φ generally defines the equipment fault current carrying capability.

2. Over-voltage withstand capability of power equipment

It is desirable that the fault-caused voltage rise is not excessive due to the concerns on equipment insulation cost

Index: Φ

Φ=3

1

f

f

II

raioCurrent

Index: faultpre

faultduring

VV

ratioVoltage−

−=Which is also called “earth fault factor”

60Hz-component

3. Review – Performance Grounding

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3.1 Impact of grounding

Impedance Ratio

The degree of grounding of a network point can be characterized approximately using the following impedance ratio K

Define performance indices

1

0

ZZKratioImpedance =

Look into the system from here (Z1 & Z0)

This ratio varies with locations in a system 23

Consider cases of R0=R1=0, i.e. Z0&Z1 have reactive parts only: If K=0 (i.e. Z0=0, this is an unrealistic case): Iratio= 1.5, Vratio=61% (V drop) If K=1 (i.e. Z0=Z1, ZN=0, fully grounded): Iratio=1.0, Vratio=100% If K=3 (i.e. Z0=3Z1, boundary case): Iratio=0.6, Vratio=125% If K=∞ (i.e. Z0 = ∞, ungrounded): Iratio=0.0, Vratio=173%

Conclusions:

1) If and TOV can be changed by changing K, i.e. the degree of grounding 2) Reducing If will always lead to increasing TOV or vice versa. The two indices can not be reduced simultaneously

Various grounding schemes are used to achieve a different level of compromise between If and TOV


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IEEE Definition

Coefficient of grounding (COG)

3)(3)(

)()( ratio

linetoline

groundtolinemax VfaultPreVfaultDuringV

faultPreVfaultDuringV

COG ===−−

−−−

If COG does not exceed 80%, i.e. the phase-to-ground voltage rise is less than 80% of rated line voltage, the location is called effectively grounded (This is equivalent to less than 138% voltage swell or voltage increase < 38%)

If any location in a particular part of a system satisfies the above condition, that part is called effectively grounded

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0 ≤XX 1

1

0 ≤XR

COG<80% is approximately equivalent to the following condition

& |K|<3 roughly


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Effective Grounding Non-effective Grounding

Ground every neutral

- Some neutrals - Ground with small R

Ungrounded Resonant ground

Ground with large R

If Very large

large Small (arcing current)

≈ zero 10 ~ 200A

TOV Low Low(<125%) High Mild Mild

Line trip (reliability)

Yes Yes No No No

Fault detection

easy easy hard hard Okay

Application UHV (≥220kV)

EHV [110 ~ 220kV]

MV (industrial)

MV MV

MGN

3.2 Performance of typical grounding schemes Comparison

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Equipotential Bonding and Grounding Transmission Lines

May, 2013 27

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Welcome To Worker Protective Grounding Basics 28

AGENDA 1. Why do we bond and ground? 2. Hazards:

• Induction and line energization • Touch and Step potential • Ground Potential Rise (GPR)

3. Methods of grounding • Bracket grounding • Equipotential Bonding and Grounding (EBG)

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1. Why do we bond and ground? 1) To protect linemen and substation workers from

harmful voltages and currents that exit on power system

2) Isolating power lines or equipment to work on them is not sufficient to protect workers from harmful voltages and currents

3) Bonds and grounds are applied to reduce voltages and currents to a safe level

4 30

2. The Hazards

5 31

Range of Tolerable Current

Effects of an electric current passing through the vital parts of a human body depend on:

• Duration of the current flow, • Magnitude of the current flow, and • Frequency of this current

Ventricular fibrillation = immediate arrest of blood

circulation

6 32

Effects of Current Magnitude on the Body

• < 1 mA

• 1 – 8 mA

• 8 – 15 mA

• 15 – 20 mA

• 20 – 50 mA

• 50 – 200 mA

• > 200 mA

No sensation

Sensation of shock, but not painful

Painful shock, “let go value”

Painful shock, loss of muscle control

Severe muscle contractions

Heart failure possible

Severe burns and heart failure

7 IEEE 80 Reference 33

Relationship of Electrical Current and Shock Duration

8 34

Sources of Harmful Currents: Primary sources of currents on isolated lines:

1. Accidental energization • Switching error, failed isolation switch, human error • Lightning • Wildlife • Back feed – customer generators, testing • Potential rise on ground grids, neutral or shield wire

from a fault on an adjacent circuit.

2. Induction

9 35

Induction • Induction comes from two sources:

• Voltage source – capacitive coupling

• Current source – magnetic induction Together these form Electromagnetic

Induction

10 36

Electric Field Induction - first type Electric field from an energized line will charge a conductive object

• Adjacent power line • Fence • Vehicle • Ungrounded line hardware • Person

11 37

C1

C2

12 38

13 39

14 40

Magnetic Induction – second type • When there is a current flow in a conductor there will be

a magnetic field developed around that conductor • This magnetic field will expand and collapse at the

same frequency as the AC power system feeding the conductor

• When magnetic lines of force cut a conductor there will be a voltage produced in the isolated conductor Transformer action

15 41

Magnetic Induction (cont’d)

16 42

Magnetic Induction (cont’d)

• Magnetic induction on power lines can be considered an air core transformer

• The amount of magnetic induced voltage and current will be directly proportional to the current on the energized line, the separation between the lines and the length of the two parallel lines

17 43

There will be no current flow if the isolated line remains isolated and ungrounded (open circuit)

18 44

If there is only one ground on the secondary of a transformer there will not be any magnetic induced current flow

19 45

20 46

Magnetic Induction (cont’d) • The magnetic induced voltage on a power line will

increase as you move away from the portable protective grounds

• This is called open-end voltage

21 47

22 48

Magnetic Induction Summary • When you install a 2nd set of personal protective

grounds there will be a current flow between the 2 sets of grounds

• The amount of current that will flow in this circuit will depend on the current flowing on the energized line, the separation between the lines, the distance between the grounds and the total impedance of the circuit

• This includes the impedance of the line and the resistance of the grounds

• This circulating current is normally much higher than the steady state current flow from capacitive induction

23 49

24 50

Static Induction – third type

25 51

Hazards of Step & Touch Potentials • When there is a voltage difference between your hands

and your feet, it is called touch potential

• When there is a voltage difference between your feet, it is called step potential

26 52

Touch Voltage

27 53

Step Potential

28 54

29

Step Potential

55

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Step Potential

56

3. Grounding and Bonding • Bracket grounding • Equipotential Grounding and Bonding

31 57

No Grounds Installed

32 58

Equipotential Bonding

33 But no grounding

59

• Trip ground • It is connected with sole

purpose of tripping an accidentally energized circuit

• Should measure no more than 10 Ω to ground • Can be located anywhere on isolated line

34 60

Equipotential Bonding and Grounding

35 61

Voltage = 80kv phase-to-ground RW = 1000 ohms RP1= RP2 = RP3 = 2200ohms RC1 = RC2 = RC3 = RC4 = 0.01 ohms RJ1 = RJ2 = _ 0.0025 ohms Rr1 = Rr2 = 3 ohms Rg1 = Rg2 = Rg3 = Rg4 = Rg5 = 7 ohms

Bracket Grounding

36 62

To mitigate the hazard around the base of the pole: Open the downlead on the structure at the work site

OR Use bond mats and an insulated platform, maintain a safe

distance away from the area, or enter and exit the area quickly

37

63

To mitigate the hazard around the base of the pole: Open the downlead on the structure at the work site

OR Use bond mats and an insulated platform, maintain a safe

distance away from the area, or enter and exit the area quickly

38

64

Overhead Shield Wire (OHSW) • Include OHSW in EB&G • Ground resistance of trip ground is reduced

because multiple parallel down leads

39 65

In a complex grounding situation where human error may increase the likelihood of a hazard being created through an error in applying or removing grounds in wrong sequence:

Addition of: • Two bleed grounds will lower hazard of induction and • Grounds should not be more than 1 to 1 1/2 spans

from worksite

40 66

Optional protection from induction • Two bleed grounds will lower hazard of induction • Grounds should not be more than 1 to 1 1/2 spans from worksite

41 67

Questions

42 68

Question 1 • What are the two primary hazards safety

grounding is addressing? Line energization Induction

69

Question 2 • The effect of current passing through the

body depend on what factors? • Duration of the current flow, • Magnitude of the current flow, and • Frequency of this current

70

Question 3 • What the primary purpose of a trip

ground? To provide a low ohms circuit to ground to

cause the protection to clear the fault as fast as possible.

71

Question 4 • What is the primary purpose of bonds?

To protect a worker by creating a

equipotential zone and limiting the voltage across a workers body.

72

Question 5 • What is bracket grounding and what is it

main limitation? It placing grounds on all sources of energy

and the worker works between the grounds. Bracket grounding does not protect the

worker from line energization. Bracket grounding does trip the circuit and

clears the fault.

73

Working on Isolated Transmission Facilities May, 2013

74

AGENDA 1. AltaLink Work Methods:

• EBG - Lines and Substations • No Bond Zone • Live Line Methods • Modified No Bond Zone Method

2. Grounding Process • Eliminating human error during

grounding

2

75

Why do we bond and ground? 1) To protect linemen and substation workers from

harmful voltages and currents that exit on power system

2) Isolating power lines or equipment to work on them is not sufficient to protect workers from harmful voltages and currents

3) Bonds are applied to reduce voltages and currents to a safe level

4) Grounds are applied to result in faster fault clearing

3 76

Working Safely on Isolated Transmission Lines

There are 4 ways that we can safely work on lines: 1. Equipotential Bonding and Grounding 2. No Bond Zone 3. Modified No Bond Zone 4. Live Line Method

4 77

1. Equipotential Bonding and Grounding Applying Bonding • Equipotential bonding methods must be used

when the equipment being worked on can become energized

• Only the application of bonds in a EB&G zone can protect a worker from harmful currents

5 78

Applying Bonds (cont’d): • All conductive paths must be bonded together to

form an equipotential zone. To ensure you maintain equipotential zones the phases, neutrals, shield wires, guy wires and steel winch lines etc. must be bonded together.

6 79

Trip Ground Locations • Permanent trip ground structures locations

Engineered to be used in high fault zones Typically have a resistance less than 10Ω

• Steel Structures Attach a ground to the grounding lug at the bottom of the

tower

• Concrete Structures A downlead runs the length of the structure; this is same for

wooden structures

• Heath probes must not be used as a trip ground Heath probes can be used as a marshalling point for ground

chains. However, they must be barricaded because they create serious step and touch potential hazards

7 80

OHSW as a Trip Ground • Generally has a resistance in the range of 3-6Ω in

good soils

• Downleads (#2 ACSR or larger) must be electrically connected to the 5/16” or larger OHSW

• OHSW may be used as trip grounds inside single fault level zones

• Only use the OHSW as a trip ground in a double fault zone when there is an engineering study that confirms it can be used safely

8

81

Location for Trip Ground for Lines with Distance Protection

9 82

Bonding Guy Wire and Anchors • Guy wires are not to be used in tripping circuits

Preforms could fail under fault conditions

• Guy wires are to be bonded into zone if required

• Anchors may be use in a tripping circuit if they have been meggered to less than 10 ohms

10 83

Problems With The Placement of Grounds

Substation 1 Substation 2

11 84

12 85

Housekeeping Hazards • Do not coil grounds

Creates a high impedance

• Use correct grounds

Must be equal lengths and as short as possible

• Secure and place grounds properly

Place out of the way for work to occur

May be tied down but not coiled

13 86

Installing Parallel Grounds • Ensure both sets are of exact length

Share fault current equally

• Install both grounds on one phase before moving to next phase

When only one ground is on, it is at risk of failure under fault condition

14 87

Mobile equipment without a boom • If a vehicle must be parked in the ground potential rise

zone and is not likely to contact the primary:

Vehicle should not be bonded into the zone

Workers are still at risk of touch potential but to a lesser degree

• Use of a bond mat attached to the vehicle mitigates the touch potential problem

15 88

Mobile Equipment - with an Aerial Device

• Non-insulated boom Bond the bucket (mandatory) Bond the chassis Maintain safe distance, use mat

and platform, or enter/exit quickly

• Insulated boom Bond bucket into EB&G Do not bond or ground

at ground level Freely contact truck

16 89

Protecting People on the Ground General Practices

• Apply trip grounds or ground rods away from work site

• Install grounds or bonds with an insulated stick • Flag/barrier equipment and work sites in urban

areas

17 90

Protecting Workers around Mobile Vehicles • Remove items you need from the vehicle • Use bond mats or insulated platforms • Stay 5 meters (16’ 5”) away from vehicles or

equipment that is tied into EB&G zone • To access a bucket truck, either move boom

out harms way and remove truck chassis ground, or enter/exit quickly

18 91

Protecting Workers around Mobile Vehicles • To access a truck hoisting a load, either

remove grounds and move load, or enter/exit quickly

• Disconnect the truck when the truck is no longer needed in EB&G zone

• Remove ground-rod end first and then remove ground from truck chassis

19 92

Bond Mats • Bond mats are to be used to bond a person to an

EB&G zone

• Must not be used as a grounding mat

Bond mats are not designed for fault current Only use a bond mat when there is a trip grounding

on the circuit

20 93

Using Bond Mats • Mitigate step and touch potential

• Stand on mat and then connect the mat to equipment with an insulated stick

21 94

Using Bond Mats To step off bond mats, do one of the following:

• Use an insulated platform between mat and area outside GPR Zone

Or • Move quickly in and out of the area

22 95

Bond mats in parallel Preferred Method

Bond Mats in Series

Connecting Bond Mats

23 96

Grounding in a substation • Substations are different from lines in two

ways: Substation ground grid along with all

permanent conductive objects in the substation are grounds to the grid. This creates basically an EBG zone

Insulating gravel and ground grid protects workers on the ground

24 97

Substation Ground Grid Typical Substation Grid Substation Grid In Poor Soil

Conditions

25 98

Substation Ground Grid

Ideal ground grid Practical substation grid

26 99

Touch and Step Potential Hazards

27 100

Typical Grounding in a Substation

trip ground

Ground the truck is in case boom contacts primary buss

Insulating gravel protects workers on the ground

Bucket bond is part of the EBG zone for the worker in the bucket

28 101


Grounds are required to be isolated from the station

equipment for most maintenance equipment

tests

29 102


‘Method A’ has less movement of the ground leads under fault conditions (during a balance fault)

30 103

2. No Bond Zone Method • When it not practical to use EBG method • Often used after a storm when significant

amount of conductor is on the ground • A No Bond Zone is defined as a zone where

there is an additional separation point in addition to the Guarantee of Isolation (GOI) point and there is NO possible way that section of line can become energized

31 104

No bond zone requirements: • Second set of barriers in addition to ACC GOI isolation

points • Conductor must be physically isolated • Bleed ground

Bleeds off static induction Install within sight of the work whenever practical

• No induction In induction corridors, all parallel circuits must be de-

energized Line crossings must be near perpendicular to ensure

magnitude of induction is not harmful Second barrier must be created at the crossing to

protect against accidental energization 32

105

No Bond Zone

33 106

Second barriers at line crossings: Install splash ropes when fallen conductor could

encroach on MAD

34 107

3. Live Line Method

• The line is isolated and grounded (trip ground) • Workers treat it as a live line and use live line

tools and techniques • Assume line voltage to be line nominal voltage

rating

35 108

4. Modified No Bond Zone • Is a method that combines elements of no bond zone

and live line method

• Often used when ‘no bond zone’ cannot be used due to the presence of induction

The line is isolated with second open points (open spans) [This eliminates re-energization of the line]

Induction is managed live line techniques at a reduce voltage level (permits the use of Class 4 rubber gloves)

36 109

Grounding Practices Process 1. Is grounding complex or non-complex?

Complex grounding occurs at more than one work site or involves more than one work crew

2. Create a project grounding plan Outlines hazards and mitigations for all sites Required for complex grounding only Signed by project grounding leader

3. Review the project grounding plan Signed by competent second set of eyes

37

110

Grounding Practices Process cont’d 4. Communicate the project grounding plan

At start-up meeting Participants sign attendance sheet

5. Create a site grounding plan Outlines electrical hazards and mitigations for

one site Required for complex and non-complex

grounding Use Safe Work form in Safety and Health

Library Signed by site grounding leader

38 111

Grounding Practices Process cont’d

6. Review the site grounding plan Signed by competent second set of eyes

7. Communicate the site grounding plan At tail-board meeting On-site workers sign Safe Work Plan

39 112

Grounding Practices Process cont’d

8. Execute grounding according to the site grounding plan

Minimum two workers Third person as safety observer (optional) Before each step, read out and repeat If changes required, stop work, revise,

communicate 9. Submit all grounding plans for review

External contractor crews return to AltaLink project manager

AltaLink crews return to your manager

40 113

Questions

41 114

Question 1 • What are the four methods used by

AltaLink to work on isolated transmission lines?

EBG No Bond Zone Live Line Methods Modified No Bond Zone

115

Question 2 • If the center section of a line is the ideal

location for a trip ground, when would you place the trip ground in a substation?

If you can not find a good low ohms ground location. i.e. in mountains

116

Question 3 • Why would you ground a truck chassis?

To protect the truck. It does not protect the

workers on the ground.

117

Question 4 • How do you protect workers on the

ground?

Keep them away from the GPR zone (ribbon off area)

Bond mats or insulated platform Remove fault current injection point (if

possible)

118

Question 5 • What are two primary difference affecting

grounding in a substation versus transmission line?

Substation ground grid – all non energized conductive objects are connected to ground grid. Basically a EGB zone

Insulating gravel.

119

1

Deep-ground-well method used for improving

the grounding resistance of HV substation grounding system

Alberta Power Industry Consortium (APIC) Grounding Seminar

Calgary, May 28th, 2013; Edmonton, May 30th, 2013, Presenter: Nerkez Lalic, P.Eng.

Senior Manager Transmission Projects, EPCOR DTI

120

2

1. Introduction Achieving low resistive earth grounding of a substation grounding system (electrode) is primarily in function of:

• Resistivity of earth the grounding electrode is placed in • Relative size of the grounding system itself.

In most cases, we as engineers have no control over the available size of the substation, and we certainly have no control of the soil / earth conditions at the site. As such, we need to evaluate the most effective method of achieving low resistive earth grounding of a substation grounding system in order to control Earth Potential Rise / Ground Potential Rise outside substation area.

121

3

Earth Potential Rise (EPR) also called Ground Potential Rise (GPR) occurs when a large current flows to earth through grounding system resistance / impendence. Ground Potential Rise or Earth Potential Rise (as

defined by IEEE Standard 80-2000) is the maximum electrical potential that a (substation) grounding grid may reach with reference to a distant grounding point - potential of remote earth.

This voltage - GPR, is equal to the maximum grid current times the grid resistance.

2. Earth Potential Rise (EPR) / Ground Potential Rise (GPR)

122

4


The change in voltage over distance (potential

gradient) may be so high that a person could be injured due to the voltage developed between two feet, or between the ground on which the person is standing and a grounded metal object. Probably the most commonly noted Ground

Potential Rise or Earth Potential Rise event involves the death of cows in a field during a lightning strike.

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5


124

6

• Transferred potential through any conducting object connected to the substation earth ground is a hazard to people and equipment outside the substation.

• Earth potential rise (EPR) is caused by electrical faults

that occur at electrical substations, generating stations, or high-voltage transmission lines.


125

7

• The potential rise can cause hazardous voltage, many hundreds meters away from the actual fault location.


126

8

Number of factors determine the level of potential rise, including: Magnitude of fault current, Earth type, Earth moisture, Ambient and earth temperature, Underlying rock layers Clearing time to interrupt a fault.


127

9

Earth potential rise is a SAFETY ISSUE. An EPR event at a site such as an electrical transmission and distribution substation may expose personnel, users, public and properties to dangerous voltages.


128

10


129

11

Comment on figure “Potential Gradient Area”:

• If the potential gradient area, having diameter A-B, is within substation fence dangerous potentials can be controlled by creating equipotential zones, insulating equipment (PPE), and restricted work areas as described below.

• If potential gradient area, having diameter A-B, is outside substation fence dangerous potentials are in the public zone and that can be mitigated by improving grounding resistance (impedance). i.e. reducing EPR (Ue) and reducing diameter of potential gradient area to within substation fence.


130

12

• "Step potential" is already discussed and there is no need to repeat. • "Touch potential" is already discussed and there is no need to repeat. • "Ground Potential Difference (GPD)" is a factor calculated when a grid of grounding conductors is installed. GPD potential is the difference between the metallic object connected to the grid, and the potential of the soil within the grid. This can be a problem if equipotential zone is poorly designed and installed.

3. Step, Touch Potential and Ground Potential Difference (GPD)

131

13

The grounding grid is one of the most challenging aspects in design of new and safe operation of in-service substations. An engineering analysis of the power system under fault conditions can be used to determine whether or not hazardous step and touch voltages will develop. The result of this analysis can show the need for protective measures and can guide the selection of appropriate precautions.

4. MITIGATION

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14

Several methods may be used to protect employees from hazardous ground-potential gradients: •The creation of an equipotential zone will protect a worker standing within it from hazardous step and touch potentials. Equipotential zones will not, however, protect employees who are either wholly or partially outside the protected area. •Bonding conductive objects in the immediate work area can also be used to minimize the potential between the objects and between each object and ground.

4. MITIGATION

133

15

•The use of insulating Personal Protective Equipment (PPE), such as rubber gloves, can protect employees handling grounded equipment and conductors from hazardous touch potentials. •Restricting employees from areas where hazardous step or touch potentials could arise can protect employees not directly involved in the operation being performed.

4. MITIGATION

134

16

•It is common practice to cover the surface with a high-resistivity layer of crushed stone or asphalt. The surface layer provides a high resistance between feet and ground grid and is an effective method to reduce the step and touch potential hazard. •Improve grounding resistance/impedance – by increasing ground grid (substation) size and / or application of low resistive earth grounding, considering that magnitude of fault current is determined with fixed number of amperes. The only variable that can be changed is earth resistance (impedance) of grounding system.

4. MITIGATION

135

17

A well designed grounding grid can eliminate Step and Touch potential hazards regardless of how high the Ground Potential Rise voltage is. Just like how a bird can land on a power line without being electrocuted properly designed equipotential zones inside substation can do the same thing.

4. MITIGATION

136

18

Background: In the middle of eighties a number of studies were done to determine the most effective method of installing low resistive earth grounding. Various grounding methods and materials were evaluated. The majority of the standard methods were rejected for practicality or cost reasons. New methods of using chemical rods and soil conductivity improvement materials looked promising but left unanswered questions as to environmental impact and liabilities. There is concern about ground water contamination from the chemicals.

5. Deep well grounding – effective method of improving grounding resistance (impedance):

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19

Based on the studies it was determined that deep driven ground rods would offer the best solution for low resistive earth grounding if full rod contact with surrounding earth could be achieved and maintained. In achieving full rod contact with surrounding earth use of hydrated sodium bentonite of specific electric conductance and sealing characteristics has given excellent results.


138

20

As substation space is limited, realistically the only remaining way to improve earth resistance and reduce GPR to the acceptable values is to drive deep electrodes. It is not uncommon to see 100-meter (300+ ft) deep electrodes at some sites. The advantages of deep driven electrodes are:


139

21

• economical to install, • maintain low resistance over time, • maintenance free, • no environmental concerns.

With new technologies a new processes are developed for installing deep driven ground rods. This processes overcomes the problems associated with installing deep ground rods.


140

22


141

23


142

24


Construction of ground well with modern equipment: two 60m deep wells per day

143

25

A good ground system design demands computer modeling that can simulate the effects of an electrical fault on a 3D model of substation, taking into account such factors as conductor spacing and depth, X/R, soil resistivity, human

fibrillation currents, ground coverings, etc.

6. Ground System Design

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26

EPCOR Poundmaker POD 240/25kV, 3x75MVA substation grounding grid design installation testing

and commissioning utilizing deep well grounding (nine wells 60 meters - 200 feet each) to improve

substation grounding system resistance

7. CASE STUDY

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27

7. CASE STUDY- Poundmaker substation

Poundmaker, 189St-105Av, Edmonton: Energized in September 2012

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28

Energized in September 2012

147

29

Title

Substation site, August 2010

148

30

Soil Investigation Report

149

31

Soil Resistivity Test Report

150

32

First excavations: Soil Layers

August 2011 151

33

The EPCOR Poundmaker substation grounding grid was designed by: CANA High Voltage Ltd

#31, 4511 Glenmore Trail SE Calgary, AB T2C 2R9

Phone: 403-451-6408 Fax: 403-247-4729

The soil resistivity test and fall of potential data were used to develop SES - CDEGS Software Package (Current Distribution, Electromagnetic Fields, Grounding and Soil Structure Analysis) model of the substation site. The substation grounding configuration, insulating gravel, seasonal soil models, touch and step voltages were reviewed to evaluate safety at the site.

Grounding Study & Detailed Design

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34

It was clear that challenging soil electrical characteristics and limited fenced area of substation will require more extensive than usual grounding system.

Grounding Study & Detailed Design

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35

• Fault Level = 15.3kA + 5kA(safety margin) = 20.3kA • Clearing Time = 0.35 sec • Safety Threshold Evaluation = IEEE 80 criteria • Insulating Gravel = or > 5000 Ohm – m • Calculated GPR values were 6,977V in the summer; 7,518V in the spring and 8,026V in the winter • This GPR values exceeds the recommended 3000V limit as in AEUC – Division B, Cl 6-008)

Grounding Study – Design Criteria & Results of Safety Analyses

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36

• For calculated GPR values corresponding ground resistance values are: 0,345 Ohm in the summer; 0,370 Ohm in the spring and 0,395 Ohm in the winter • For AEUC allowed GPR value calculated ground resistance value is 0.147 Ohms • To achieve required safety threshold limits combination of ground grid, ground rods and ground wells were required. • Calculated well resistance needs to be less than 3.25 Ohm if the well is tested without the rest of the grid in place

Grounding Study – Design Criteria &

Results of Safety Analyses

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37

Grounding Study – Soil Model

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38

Ground Grid Detail Design Model Top View Sketch

157

39

Ground Grid Detail Design Model 3D Sketch

158

40

Ground grid detailed design - layout

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41

Fall of Potential calculated-expected results Ground Well Testing

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42

Fall of Potential test results Single Ground Well – Tested May 6, 2013

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43

Overall Ground Grid Soil Resistance Test Results Tested August 18, 2012

162

44

Substation Ground Grid Resistance Vs Single Grounding Well Resistance Comparison

163

45

Grounding Well Construction Photo

164

46

Grounding Well Construction Photo

165

47

Grounding well construction photo – ground electrode 4/0 Cu conductor + grounding rod

166

48

Questions to you!

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49

• Inspecting and maintaining grounding system at your substations? • When required, improving resistance of substations grounding system ? • Controlling GPR in public areas outside fence of your substations? • Having experience in installing deep grounding wells on your substations ?

Are you:

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50

ALBERTA Electrical Utility Code, 3rd Edition 2007: Section 12, Clause 7.7 Maintenance of Grounding System: “Grounding system shall be periodically tested for resistance and periodically inspected and maintained to ensure that the grounding system comply with the requirements of this Code”

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51

Paper: DEEP EARTH GROUNDING vs SHALLOW EARTH GROUNDING by Martin D. Conroy and Paul G. Richard, Computer Power Corporation, Omaha, Nebraska Westinghouse: Electrical Transmission and Distribution Reference Book IEEE- 80, Guide for Safety in AC Substation Grounding IEEE – 81, Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System IEEE – 81.2, Guide for Measurement of Impendance and Safety Characteristics of Large, Extended or Interconnected Grounding System IEEE – 367, Recommended Practice for Determining the Electric Power Station Ground Potential Rise and Induced Voltage From Power Fault AEUC – Alberta Electrical Utility Code Fluke 1625 and Megger DET-2-2 tester’s manuals CANA – HTI : EPCOR Poundmaker Substation Grounding Study Report

References:

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Thank you !

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1

Case Study

Characteristics of GPR as Affected by Grounding Structures


by Wilsun Xu

University of Alberta May 2013

Problems to clarify

1. What are the roles of each grounding element in a substation? • Grounding mesh, • Ground rod, and • Gravel

3. Exercise and discussion: analyzing a portable grid

2. What are the true benefits of grounding a worksite?

• Reduce ground potential rise? • Shorten the duration of energization?

1. Substation grounding grid

Mesh Rod Substation Grounding grid

Substation grounding grid consists of three components: mesh, rod and gravel.

GPR (surface potential) Gravel (insulating layer)

What are the roles played by the mesh and the rod structures?

Case C (lower step V, high GPR)

Case B (higher step V, lower GPR)

Vstep

Vtouch

Max surface potential

Zsystem Vs

Rg

Three cases are used to find the role of each element:

1. “Mesh+Rod”, which corresponds to the actual substation grid 2. “Mesh Only”, which corresponds to a mesh (horizontal) structure 3. “Rod Only”, a hypothetical case corresponding to a vertical rod structure


The following factors are also studied: 1) The depth of the structure 2) The soil resistivity


0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 20

10

20

30

40

50

60

70

80

90

100

Distance [m]

Vol

tage

Pot

entia

l

t=0mt=0.5mt=1mt=1.5mt=2m

t=0m

t=2m

t=1mt=1.5m

t=0.5m

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 20

10

20

30

40

50

60

70

80

90

100

Distance [m]

Vol

tage

Pro

tent

ial

t=0.01mt=0.5mt=1mt=1.5mt=2m

t=0.01m

t=0.5m

t=1.0m

t=1.5m

t=2m

Y

Z

X Vx (x,0,0)x

L

L/2

t

(0,0,-t)

YZ

X

dz

L

Vx (x,0,0)

(0,0,-L/2-t)

(0,0,z)

d

t

Vertical Rod

Horizontal Rod

1) GPR profiles are comparable, 2) close to surface will result in higher GPR and Vstep

Comparing single vertical and horizontal rods

1. Substation grounding grid Compare grounding structures

I=100A ρ=100Ω∙m Grid size: 100mx100m, Mesh size=10x10m Rod size:11x11, L_rod=5m Conductor sizes d=19.1mm

-60 -40 -20 0 20 40 6030

32

34

36

38

40

42

44

46

48

50

Length [m]Su

rfac

e Po

tent

ial [

V]

Mesh&RodMeshRod

-60 -40 -20 0 20 40 6030

32

34

36

38

40

42

44

46

48

50

Length [m]

Surf

ace

Pote

ntia

l [V

]

Mesh&RodMeshRod

Ground potential distributions due to different structures

Depth=1.0m

Depth=0.1m

Main conclusions: 1) The difference among the 3 structures is small

2) They shall be buried deep to achieve better performance

3) Mesh and rod structures interfere with each other a lot

-60 -40 -20 0 20 40 600

10

20

30

40

50

60

70

80

90

100

Length [m]

Surf

ace

Pote

ntia

l [V

]

Mesh&RodMeshRod

-60 -40 -20 0 20 40 600

10

20

30

40

50

60

70

80

90

100

Length [m]Su

rface

Pot

entia

l [V

]

Mesh&RodMeshRod

1. Substation grounding grid Impact of soil

I=100A Grid size: 100mx100m, Mesh size=10x10m Rod size:11x11, L_rod=5m Conductor sizes d=19.1mm Structure depth=0.5m

Uniform soil resistivity

Impact of soil resistivity

Two layers of resistivity

Top layer: Depth=2 meter, ρ=200Ω∙m Second layer: ρ=20Ω∙m

Main conclusions: Rod helps the grounding grid to access low resistivity soil, • Flatten the GPR profile • Lower the GPR due to smaller grounding R

ρ=200Ω∙m

-60 -40 -20 0 20 40 6030

35

40

45

50

55

60

Length [m]

Surf

ace

Pote

ntia

l [V

]

Mesh&RodMeshRod

Depth=0.5m Uniform soil resistivity

1. Substation grounding grid Lay mesh on surface

Main conclusions:

Bring the structures (mesh, rod or combined) to surface will lead to higher step voltages & GPR

-60 -40 -20 0 20 40 60 30

35

40

45

50

55

60

Length [m]

Surf

ace

Pote

ntia

l [V

]

MeshRodMesh&Rod

Depth~0m Top thin layer has high resistivity to represent surface

Mesh laid on surface

I=100A ρ=100Ω∙m Grid size: 100mx100m, Mesh size=10x10m Rod size:11x11, L_rod=5m Conductor sizes d=19.1mm Structure depth=0.5m

1. Substation grounding grid Summary of findings

Main findings:

The vertical (rod) and horizontal (mesh) structures are almost equally effective. However, the rod structure can reach deep soil with lower resistivity, leading to more significant reduction on GPR and step voltages;

The depth of grounding structure has a significant impact on the surface potential, in the form of GPR and step voltage. If the structure is closer to the surface, higher GPR and step voltage will result;

The vertical (rod) and horizontal (mesh) structures interfere with each other heavily. Combined use of the two structures does not double the performance. They act more like backups to each other;

2. The benefits of grounding a structure

If a working object is grounded through Rg, can the touch voltage be lowered?

25kV

Zsystem=R+jX

If

3

Rmat Rg

Additional

grounding

IFmat IFrod

P h a se L in e

N e u tr a l

U n g r o u n d

R g

5 0ΩV s te p

V to u ch

S tif fle g s

Phase Line

Neutral

Grounding to Temp. Rod

Rg

15ΩVstep

V touch

(a) Ungrounded scheme (b) Grounding to temporary rod

Phase Line

Neutral

Rg

15Ω

Grounding to Perm. Rod

Vstep

V touch

Phase Line

Neutral

Rg

15Ω

Grounding to Neutral

Vstep

V touch

(c) Grounding to system rod (d) Grounding to system neutral

Vtouch

Case 1 Case 2

X X

This is equivalent to asking: can we lower the ground potential at point X?


25kV

Zsystem=R+jX

If

3

Rmat Rg

Additional

grounding

IFmat IFrod

E

Vsys

Vmat

The supply voltage E is divided between Vsys and Vmat. We want to lower Vmat by using Rg

Zsys=1.5 ohm Rmat=10 ~ 200 ohm, Rg=5 ~ 30 ohm, Rmat//Rg= 4 ~ 30 ohm

One can easily see that most of the supply voltage E will be “consumed” by Vmat. So Vmat≈E and it cannot be lowered significantly with Rg.

There is a larger fault current since the total circuit Z is reduced with Rg; Some of the current originally going through Rmat could be diverted to Rg

E

Zsystem

Rmat

X

Rg Vmat


P h a se L in e

N e u tr a l

U n g r o u n d

R g

5 0ΩV s te p

V to u ch

S tif fle g s

Phase Line

Neutral

Grounding to Temp. Rod

Rg

15ΩVstep

V touch

(a) Ungrounded scheme (b) Grounding to temporary rod

Phase Line

Neutral

Rg

15Ω

Grounding to Perm. Rod

Vstep

V touch

Phase Line

Neutral

Rg

15Ω

Grounding to Neutral

Vstep

V touch

(c) Grounding to system rod (d) Grounding to system neutral

X

E

Zsystem

Rg

X

Similarly, the voltage at point X cannot be lowered significantly since the

system impedance is generally much smaller than the grounding resistance

Cases of very small Rg may exist if the grounding is created through a neutral or shield wire.

Also, the substation ground has very small Rg


Main findings:

Grounding, however, can result in a larger fault current, leading to fast fault clearing and reduced GPR duration; Grounding can divert some fault currents from a structure, making the structure experience reduced fault current;

Grounding does not guarantee a significant reduction on the GPR, since the grounding resistance is often higher than the system impedance. A large portion of the system voltage will impose on the grounding resistance; The energizing source behaves as a voltage source. Grounding can help to reduce GPR if the grounding resistance approaches the level of system impedance, examples are ground to system neutral or substation; The energizing source behaves as a current source.

3. Exercise & discussion: portable grid

Vtouch

Vstep

Bonding cable

Cable for trip grounding (a separate practice)

Like the substation grid, a portable grid (mat) is used to create an equipotential zone.

Portable grid

( )( )

touch touch safety limit

step step safety limit

V V Duration

V V Duration

Requirement on portable grid:

Discussion items: Q1: Will grounding connection lower the touch and step voltages? Q2: Are we likely encounter unacceptable touch and step voltages using the mesh?

Vtouch

Vstep

Bonding cable

Cable for trip grounding Ideal grid (Metal plate) (a separate practice)


Ideal case

Actual case

(a). Two feet stand on ground surface

(Touch potential concern). (b). One foot stands on ground surface

(Touch or step potential concern).

Vtouch

Vstep

1.5 meters

Analyze Q2

Condition: Vs=14.4kV, If=8kA, Overall grid 1.4mX1.4m, mesh size 0.2m, rod length 0.5m

3. Exercise & discussion: portable grid Analyze Q2

• The mesh structure works well when buried deep inside soil But it cannot perform when laid on ground surface

Main findings:

• Rods are needed to “flatten” the surface potential

If the grid is covered by a layer of (insulating) fabric, Should the fabric layer be placed on top or bottom?

Fabric on top Fabric on bottom

3. Exercise & discussion: portable grid Q3

Question 3:

Mat Conductors

Grounding rod

(a) With mesh-conductor-based mat

(Vstep=7.7 kV)

Grounding rod

1m 1m

(b) Without mesh-conductor-based mat (Vstep= 952V)

Compare two other work scenarios

Fabric layer on top

Increases the body resistance, helps to reduce body current. Useful to improve safety

Fabric layer on bottom

IF IF

IF

IF

The bottom insulation layer will concentrate IF current to the weakest spot to the ground. As result, having an bottom insulation layer is not helpful.


E

Zsystem

Rg

Rfabric

Rbody

Equal- potential zone

Analyze Q3

Theory

Measurement of Grounding Conditions


by Wilsun Xu


190

Outline

• Measurement of grounding resistance

• Measurement of soil resistivity

• Measurement of touch and step voltages

• Factors affecting grounding resistance and GPR

• Online monitoring of substation grounding grid

191

1. Measurement of grounding resistance

VRI

=V & I

Earth surface

Main challenges

1. How to determine V, a voltage referred to remote earth?

Rg

2. The current I must pass through a remote point to be valid

Invalid I Valid I

Temporary rod

192

Neutral and shield wires can affect the measurement results

Impact of neutral and shield wires

1. Measurement of grounding resistance

Additional challenge for substation Rg measurement

193

“Fall-of-Potential” method (for all grounding structures) S

urfa

ce p

oten

tial

Distance V

~61.8% of XE-C

For substation grid: XEC > 1.5~5 times of the diameter of the grid

1. Measurement of grounding resistance Basic method

194

1. Measurement of grounding resistance Other methods

• Using a transmission line as a current injection line • Measure substation voltage to a remote ground

Direct measurement by simulating a fault condition

195


Potential difference method

Voltage sensors

Potential difference

Distance

Potential

Potential difference Use multiple potential

difference data to estimate this curve

196

Practical methods

a) Measure Rg of MGN neutral

b) Use other structure as the remote ground


197

9

1. Measurement of grounding resistance ATCO results

Statistics of grounding resistances of permanent grounding structures

Histogram

Cumulative distribution

Rg

Rg

Mea

sure

men

t eve

nts

% M

easu

rem

ent e

vent

s

0.8 means 80%

198

2. Measurement of soil resistivity

V

source

meter

I

d d d

Total potential (V1+V2)

1 2

Wenner method

199

3. Measurement of step/touch voltages

1) Up to 100A, several hours, dedicated source 2) Several kA, 0.1 to 0.2 sec, short circuit

Step voltage sensor

RF RF

RB

IB

RF RF

RB IB

Touch voltage sensor Step voltage sensor

200

4. Factors affecting Rg Factors affecting Rg

2. Moisture and salt content

3. Temperature

4. Seasonal change

1. Characteristics of the soil

201

5. On-line monitoring technique

1) Active current injection 2) Step/touch sensor network

3) Trend monitoring 202

6. Summary

• Grounding condition measurement is still difficult to perform, due to 1) the need for multiple independent electrodes, 2) the impact of various natural factors

• The existing measurement methods just provide a snapshot of the grounding condition. Interpretation of the grounding performance under other conditions is needed

• On-line, continuous monitoring approaches seem to be the future for ground condition monitoring

203

Distribution Grounding System Program –

Assessment and Replacement

Simon Chan Joseph Kuffar

204

Outline

Background Drivers Ground Testing Program Grounding Replacement Program

205

Background

In 2004, UMS Group reviewed EPC Proactive Asset Replacement Program.

Study compared EPC to North American utility industry as well as global best practices.

Recommended EPC to initiate a Ground Integrity Testing program

206

Background..

Practice of the time….. Initial Installation test Maintenance test

– Proactive – In conjunction with Pole Testing and Treatment Program (O/H system only)

– Reactive – abnormal report (both O/H and U/G) Grounding replacement

– Reactive replacement - abnormal report – Pole replacement program

Paper records

207

Drivers

Equipment Protection To provides a low resistance path ground as well as

discharge path for lightning energy To allow proper operation of protective equipment during

the fault

Personnel Safety To Maintains equipment and other grounded structures at

the potential of earth To Minimize the risks of step and touch potential

Regulatory compliance

208

Drivers..

Regulatory Requirements: the 2003 Alberta Electric Utilities Act (Section 105 (1)):

– The owner of an electric distribution system has the following duties: – “(c) to operate and maintain the electric distribution system in a safe and reliable

manner”.

the 2007 Alberta Electrical and Utility Code Section 12 Grounding : Clause 7.6 Corrosion of Grounding System

(2) If the cross section area or mass of the grounding system equipment has been reduced by corrosion to less than 80% of the amount required by this Code the equipment shall be replaced.

– Clause 7.7 Maintenance of Grounding System Grounding systems shall be periodically tested for resistance and periodically inspected

and maintained to ensure that the grounding systems comply with the requirements of this Code.

209

Drivers…

CSA – C22.3 No.1 Overhead System 9.1.2.1 Multi-grounded Systems Where a single electrode resistance exceeds 25 ohms, up to two additional

electrodes connected in parallel or up to two deep-driven electrodes shall be used unless it is clear that additional electrodes will not significantly reduce the resistance.

210

2006 Grounding Testing Program

EPC initiated a 3 year grounding test program Work performed by consultant Purpose

– Establish an accurate overall ground rod condition for both O/H and U/G system

– Create a centralized database for record keeping – Implement a structured maintenance program

211

Fall 2006 Testing

Tested the grounding systems for 39 distribution feeders (randomly selected).

Sample selection as per ANSI/ASQ Z1.4 Standard Test limited to O/H and U/G dead-front equipment Pass/Failure Value of 25 ohms was used Started late Sept 2006 and completed Nov 2006 Data captured and stored in CMMS

212

Fall 2006 Testing - Tool

Ground Tester (AEMC 3731)

213

Fall 2006 Testing - Results

1099 of 7351 Distribution Ground Rods Tested 332 Failed (30%) 30% Pass/Fail Criteria – 17 Feeders failed Most failures were on old installations - 20 years plus

214

Fall 2006 Testing - Results ..

Questions 1. What is our typical Soil Condition? 2. How bad (severity of Deterioration)? 3. Should we change the approach? 4. What is the mode of failure (connectors or rods)? 5. Should we established a pass/fail criteria based on

the actual soil condition?

215

Fall 2006 Testing -Recommendation

Collect Soil Conditions/Resistivity Data with each ground rod resistance measurement

Determine the mode of failure - field Verification Test the remaining ground rods on feeders that failed

216

Outcome

Revised approach 2007 -2008 Testing based on age Work issued by city section Test area selected covered most areas of the city Measurements included Soil resistivity and grounding

resistance Test sites selected as per ANSI/ASQ Z1.4 Standard

217

Soil Resistivity Measurement

Wenner’s Method Tool -Fluke 1625 GEO Earth Ground Tester

218

2007-2008 Results

Soil in Calgary area generally has low resistivity. Certain areas have Corrosive soil condition A single ground rod can achieve a ground resistance of

25 ohms or less Estimated 25% of sites have deteriorated beyond the

limit set in the AEUC Systems installed prior to 1990 are particularly in poor

condition. Replacement of all existing deficient ground systems

could be over $30 Million.

219

2007-2008 Results -Key Understanding

- Understand typical soil conditions in Calgary - Identify areas with corrosive soil - Establish a pass/failure based on soil condition - Project the level of deterioration for field verification - Prioritize the replacement program

220

0%

10%

20%

30%

40%

50%

60%

70%

Unknown 1950's 1960's 1970's 1980's 1990's 2000's

Failu

re R

ate

Vintage

2006-2008 Sampling Test Results

2007-2008 Results

221

Field Trial 2009-2011

Objectives: – Small scale project to assess and determine the course

of addressing the entire EPC grounding system. – Further refine the number of deficient sites – Assess the replacement costs per site – Verify the projected level of deterioration – Identify any resource or other concerns likely to occur

in a full scale replacement program

222

Field trials – Projected deterioration

% Length Electrode Length (ft)

Soil Resistivity (Ohm-m)

Rod Diameter

Calculated Resistance

Value (single rod)

10% Length 8 47 0.75 143

20% Length 8 47 0.75 82

30% Length 8 47 0.75 59

40% Length 8 47 0.75 47

50% Length 8 47 0.75 39

60% Length 8 47 0.75 33

70% Length 8 47 0.75 29

80% Length 8 47 0.75 26

100% Length

8 47 0.75 21

Calculated grounding resistance and projected levels of deterioration based measured soil resistivity

223

Field Trial - Results

Field Verification Showed more deterioration than initially projected No issues with the connector Most Ground rod penciled at approx 4ft below ground

224

Results- Field Trial …

225

Grounding Replacement Program

In 2012, ENMAX Initiated grounding replacement program.

– Targeting areas with high failure rate – Priority given to areas with UJKT Cables – Installation based on current standard – Hydrovac excavation

226

Overhead Grounding Standard

227

Padmount Grounding Standard

TOP VIEW 228

Padmount Grounding Standard

FRONT VIEW

229

Current Practice..

Current Maintenance practice Initial Installation test Maintenance test

– O/H- In conjunction with Pole Testing and Treatment Program (10-year Cycle)

– UG – in conjunction with Line inspection

Maintenance record captured in CMMS system

230

Current Practice….

Replacement Upgrade the grounding when

– Section of cable is replaced – Old equipments are replaced – High resistance grounds are identified – Other system upgrades program

Sections with high failure rate are targeted for proactive replacement program

231

Challenges

Equipments on Private Property (backyard…) Equipment in less accessible areas Equipment on paved lanes Easement Encroachment - fences, garages & etc Resources Customer Complaints

232

233

234

235

Reference

Alberta Electrical Utility Code, 3rd Edition 2007 CSA – C22.3 No.1 Overhead System ANSI/ASQ Z1.4 Standard Fluke 1625 User manual

236

Questions

237

1

Theory & Case Study

Connecting Substation and Feeder Neutrals: Pros, Cons and ATCO Practice


by Wilsun Xu


238

1. The issue of concern

138 kV

Substation

MGN

25 kV Transmission side Distribution side Customer side

///

Equivalent circuit of Upstream ends

Should one connect the substation neutral to the feeder neutral?

Q1: If connecting the neutrals, the substation GPR may transfer to feeder neutral. How bad can it be?

Q2: If not connecting the neutrals, what are the negative consequences?

239

2. GPR transfer from substation to feeder

Distribution Substation

MGN

Distribution side-25 kV

Fault scenarios to consider

Neutral

Grounding grid

fI

fI

Neutral

Grounding grid

fIfI

Transmission fault Distribution fault

Outside sub Inside sub

TfsubfaultT IRGPR −− =

DfsubfaultD IRGPR −− =

240

Rsub

Z’geq A B C Substation

N

Zn Ig

Ineutral IN

X VN

faultsubNsubstation IRVGPR ≈=

Neutral

Zn X VN

Substation GPR: Propagation of GPR to outside:

substationgeqn

geqN

geqn

geqXmaxneutral GPR

ZZZ

VZZ

ZVGPR

''

''

+=

+==−

geqn

geqsubstationmaxneutral ZZ

ZGPRGPRk

''

/+

== −

Ratio of GPR transfer:

2. GPR transfer from substation to feeder Method to estimate

241

0

2

4

6

8

10

12

14

16

0 0.5 1 1.5 2Neutral length [km]

Equ

ivle

nt im

ped.

[ohm

]

Z’geq

ZN

Zgn

ZN

Zgn Zgn

ZN Z’geq

0.7

0.8

0.9

1

7 15( base case) 30

Grounding resisatnce [Ω]

[/

]

S=50m S=100m (base case) S=250m S=500m

Ratio of GPR transfer

K

2. GPR transfer from substation to feeder Sample results

242

2. GPR transfer from substation to feeder Sample results

Observation GPR transfer ratio k

Max NPR per kA (V/kA)

Corresponding system condition

High end value 0.95 129 m 50S, 30 =Ω=gnR

Typical value 0.91 124 m 001S, 15 =Ω=gnR

Low end value 0.76 108 m 500S, 7 =Ω=gnR NPR – neutral potential rise = GPRneutral

243

gnRgnRgnRgnR

nZ n nZnZ nZ nZ nZmaxNPR

GPRgnR

Customer #1 Customer #2

2NPR NNPR

Neutral voltage rise (NPR) at other points

1 maxNPR =NPR =k×GPR 2 1 1NPR =k ×NPR i+1 i iNPR =k ×NPR

nnNPR =k ×GPR

…..


Max NPR per kA

NPR per kA at 2 km (V/kA)

NPR per kA at 5 km (V/kA)

m 50S, 30 =Ω=gnR 129 24 3.4

m 001S, 15 =Ω=gnR 124 22 3.2

m 500S, 7 =Ω=gnR 108 46.4 12

2. GPR transfer from substation to feeder NPR at customer location

244

3. ATCO Practice

Ground potential

No. of grounding points from substation

Substation neutral

First grounding point outside fence (neutral connection point)

600V threshold

Hazard zone Should not happen in public area

i.e. if it happens in the public area, Neutrals shall not be connected

Decide if two neutrals shall be connected

245

3. ATCO Practice

Why use 600V as the threshold?

V0

0.5m

Step Voltage

V0

V0 is the NPR

0.116body

s

It

≤

0.1161000steps

Vt

< ×

IEEE Std.80 (t=0.5s) Simplified (t=0.5s)

50 kg 726.0 V 453.8 V

70 kg 982.6 V 614.1 V

Rod=1.5m

246

3. ATCO Practice

Is the feeder O/H or U/G?

O/H

Is there a M.G.N on the riser pole?

Does the O/H line have a neutral leaving the

substation?

Is the pole located in an area frequently travelled

by the public?

Connection from the concentric neutral to the

substation ground is approved

Please refer to isolation manual

No Concern

U/G

Next Slide

247

3. ATCO Practice

Connection from the concentric neutral to the

substation ground is approved

Enter your fault level (amps): 500000 Enter your sub ground resistance: 0.15 Select Cable Leaving Substation: 500 MCM Select System Neutral or U/G system Cable 1/0

Are the first 6 grounding points (Ground Rods, Pull Boxes, etc.) located in areas frequently travelled by the public?

Please refer to isolation manual

YES ….

User Input Data

Calculated by Excel

248

3. ATCO Practice

k - The maximum ratio of NPR to GPR PR = 1500 Ground Pt.k1 0.98355496 1 NPR1 = 1475 1k2 0.97131637 2 NPR2 = 1457 2k3 0.94345550 3 NPR3 = 1415 3

k4 0.89010828 4 NPR4 = 1335 4k5 0.79229275 5 NPR5 = 1188 5k6 0.62772780 6 NPR6 = 942 6k7 0.39404219 7 NPR7 = 591 7k8 0.15526925 8 NPR8 = 233 8K9 0.02410854 36 9K10 0.00058122 1 10K11 0.00000034 0 11K12 0.00000000 0 12

K13 0.00000000 Calculation for K1 0 13

K14 0.00000000 0 14U/G Cable Impedance per meter Z equivalent Distance from Sub to Riser or Pull Box Impedance of Neutral K1#1 AL 0.00066380 6 300 0.1991400 0.967876189350 MCM 0.00046000 0.1380000 0.977517107500 MCM 0.00033440 0.1003200 0.983554961750 MCM 0.00022000 0.0660000 0.9891196831/0 0.00063000 0.1890000 0.969461949266.8 0.00035800 0.1074000 0.982414776477 0.00029270 0.0878100 0.985576094

Calculation of neutral voltage rise at every neutral point. The NPR shall be < 600V

249

4. Not connecting the neutrals: negative consequence

X N totalGPR I Z=

|GPR|

Net GPR profile

Islanded neutral

I

I

Neutral V = Neutral GPR

Will the GPR close to the first pole become unacceptable if the neutral is not connected?

250

IF

znn

RgnRgn Rgn Rgn Rgn RgnRgn

znn znn znn znn znnen en en

+ - + - + -X YF

znn


znn znn znn znn znn

IN IN IN

X YF

a) Fault current IF causes induced voltage en at each grounding interval:

n mn Fe z I= ×

Phase-neutral Mutual (coupling) Z

b) Each induced voltage en can be converted into a current source IN:

mnN F

nn

zI Iz

=

Self Z of the neutral

Induced V


251

z n n

R g n R gn R g n R g n R g n R g n R g n

z n n z n n z n n z n n z n n X Y F

c) The current sources can be merged into one.

d) The series current source can be further represented using two shunt sources

A B

mnN F

nn

zI Iz

=

z n n V NX Y

I N R g n R gn I N R g n R g n R g n R g n R g n

z n n z n n z n n z n n z n n V NF

This model makes it much easier to analyze the GPR case


252

Parallel Zone

Neu

tral V

Caused by source B

Caused by source A

NX N totalAI ZV =

NF N totalB-up totalB-down N totalAI (Z //Z ) 0.5I ZV = ≈

e) The voltage profile along the neutral can be established using superposition

A B

z n n V NX Y



ZtotalA ZtotalB-up ZtotalB-down


253

Parallel Zone

Caused by source B

Caused by source A

Net GPR profile

2km (neutral) 1km (shield)

X F

Neu

tral V

N

eutra

l V

Mag

nitu

de

IF

znn


znn znn znn znn znnen en en

+ - + - + -X YF


254

A

V NX

I N

A B

z n n V NX Y



ZtotalA ZtotalB-up ZtotalB-down

ZtotalA totalA nn gnZ Z R≈

mnmax at-X nn gn F

nn

zGPR GPR z .R Iz transfer FZ I= = × =

Typical value of Ztransfer for Alberta distribution line is about 0.34 ohm. For example if a fault current is 1kA, the maximum GPR is 340 V.


255

maxGPR 0.34transfer F FZ I I= =

If neutrals are not connected:

If neutrals are connected:

Observation GPR transfer ratio k

Max NPR per kA (V/kA)




Low end value 0.76 108 m 500S, 7 =Ω=gnR

There may be a concern (Note that the IF’s are different)

GPRmax=0.124IF

Summary: more investigations are needed to find the best compromise


256

1

Case Study

Does improving grounding help to reduce telephone interference ?


by Wilsun Xu


257

1. A telephone interference problem

Summerside Sub.

East Industry Sub.12E

11SU21SU12SU

Telephone Line

Telephone Cabinet

41 Ave.

17 S

t.

66 S

t.

75 S

t.

101

St.

91 S

t.

127

St.

IT = 1000 (Dec. 2005)IT = 1800 (March 2006)IT = 2300 (Sept. 2009)

IT = 3500 (Nov.19th 2010) IT = 500 (Nov. 29th 2010)ACCEPTABLE IT LEVEL

IT = 5000 (Nov. 29th 2010)NOT ACCEPTABLE IT LEVEL

IT numbers shown here are probe-wire IT

258

The 9th harmonic voltage is the main contributor (around 70%) to telephone noise.


259

Telephone Cabinet

Summerside Sub.

East Industry Sub.

12E

21SU

41 Ave.

75 S

t.

101

St.

91 S

t.

127

St.

17 S

t.

66 S

t.

12E21SUTelephone Line


Source of telephone interference

Parallel zone of interference 260

B Power conductors

Neutral (N)

A C

M-field produced by A, B & C

M-field produced by N

2. Basics of telephone interference

Total M-field

Case 1: no neutral, Iabc in positive sequence Case 2: no neutral, Iabc in zero sequence Case 2: with neutral, Iabc in zero sequence

261


Power conductors

Sheath (S) Core (T) Phone conductors

Neutral (N)

A B

C A B C N

S T

Telephone cable core

Telephone cable sheath

Neutral

Phase conductors

∆V

ATATTTT IZIZV +=∆

A

T

Transformer analogy

TTTSTSNTNCTCBTBATAT IZIZIZIZIZIZV +++++=∆Self Z Mutual Z 262

A B C N

S T Telephone cable core

Telephone cable sheath

Neutral

Phase conductors

∆VT

( )( )( )

T TT T

TA A TB B TC C

TN N

TS S

V Z IZ I Z I Z IZ IZ I

∆ =+ + +−−

Impact of power current

Impact of neutral current

Impact of sheath current

)()( NTNCTCBTBATApowerT IZIZIZIZV −++=∆ −

Power influence on telephone:


0

0

( ) ( )

( )

TA A B C TN N

TA TN N

TA N

Z I I I Z IZ I Z IZ I I

≈ + + −= −≈ −

Zero sequence current causes interference

Neutral current reduces interference

The same concept is applicable to the analysis of induced voltages on pipelines

Harmonics dominated by zero sequence component: 3, 9, 15

Ideas to reduce telephone interference: reducing I0, increasing IN to I0. 263

3. Factors Effecting Telephone Interference Level a) Bad Grounding Rods

1) The rods connecting the neutral to ground are subject to corrosion (i.e., the neutral grounding resistance increases).

2) To determine the impact of above on telephone interference, the rods along the neutral circuit in parallel with the telephone line are gradually removed

3) Results show bad grounding rods do not affect the induced voltage.

Tele

phon

e lin

e to

tal i

nduc

ed

volta

ge (V

)

Poor grounding (percentage of telephone line)264

Phone line

The return load current, IN, is bypassed by the grounding rods, When it reaches the parallel zone, its magnitude has become very small so IN does not help to reduce telephone interference. Improved grounding is actually not good in this case.

Neutral Load

Su

bst

atio

n

3I0 IN

Rgl

N

1) Neutral current due to load imbalance

Increased grounding resistance

Distance

IN

Conducted current


265

Neutral

Load

Su

bst

atio

n

3I0 IN

Rgl N + – + – + – + – + – + –

Loop current

Voltage induced by phase currents

Phone line

+ –

I1 I2

Since I1=I2=..=Ix due to similarities among the circuit segments, The currents entering the ground (through the rods) are almost zero in the parallel zone, so changing the grounding resistance of the rods has no impact on the neutral current, i.e. telephone interference.

Ix

2) Neutral current due to induction


Applicable for long neutral

266

21SU Feeder

Telephone Line

Summerside Sub.

Location 3

Location 2

Location 4

Location 1

Neutral current due to loads has “disappeared” when it reaches these points

In the parallel zone, the neutral only contains induced current


267

3. Factors Effecting Telephone Interference Level b) Broken Neutral

-0.50.51.52.53.54.55.56.57.58.59.5

Base Case (No Broken)

Broken at Location 1




Vol

tage

(V)

Cases

27% 22%8%

60%

Impact of Broken neutral on the Induced 9th Harmonic Voltage 21SU Feeder

Telephone Line

Summerside Sub.

Location 3

Location 2

Location 4

Location 1

• The broken neutral causes a decrease of the neutral current close to the broken point, which, in turn, increases the telephone inferences:

Broken neutral has a significant impact on telephone interference level. However, if the broken point is 1.5km or more away from the telephone line, the negative impact is negligible.

Neutral Broken

InInInInIn

Neutral Current Profile

In

268

Load balancing does not affect the flow of 3rd, 9th and 15th harmonic currents significantly, which are dominated by the zero sequence component

Since the telephone interference is mainly caused by these harmonics, load balancing is not very effective to reduce telephone interference Load balance can reduce the impact of 11th and 13th harmonics, which are not a major contributor to telephone interference (at least in this case)

3. Factors Effecting Telephone Interference Level c) Load balance

269

3. Factors Effecting Telephone Interference Level c) Load balance

Source

A

B

C

N

I0=IA+IB+IC

I0

Load balance cannot change I0, so it has no impact on telephone interference

3rd, 9th, and 15th harmonics behave as zero sequence current sources

270

• Improving grounding resistance rarely reduces telephone interference (depending on the length of the neutral);

• Improving load balancing will not help reducing telephone interference in general;

• Ensure neutral continuity in the parallel zone will help reducing telephone interference

3. Factors Effecting Telephone Interference Level Summary of findings

+ – + – + – + – + – + –

Loop current

+ –

I1 I2 Ix

Cannot be too large

Cannot be too large

271

4. Review exercise

Phase Neutral

1) Which case causes more interference?

Phase Neutral

Grounded overhead neutral Ungrounded overhead neutral

Telephone Telephone

Neutral Phase

Neutral

Telephone Telephone

Phase

2) Which case will benefit from improved grounding resistance?

Islanded neutral

272

Alberta Power Industry Consortium

Grounding Issues 2009-2010

Project #1.1

Draft Report

Substation GPR Transfer to Feeder Neutral Points

Project Leader

Wilsun Xu

Project Team Members

Khaled Alawasa Janak Acharya

Department of Electrical & Computer Engineering University of Alberta

Edmonton, AB, T6G 2V4

Phone: 780-492-5965 [email protected]

November, 2009

273

1

NOTICE This report was prepared by the University of Alberta for the ultimate benefit of the Alberta Power Industry Consortium members (hereinafter called “SPONSORS”), who do not necessarily agree with the opinions expressed herein. Neither the SPONSORS, the University of Alberta, nor any other person acting on their behalf makes any warranty, expressed or implied, or assumes any legal responsibility for the accuracy of any information or for the completeness or usefulness of any apparatus, product or process disclosed, or accept liability for the use, or damages resulting from the use, thereof. Neither do they represent that their use would not infringe upon privately owned rights. Furthermore, the SPONSORS and the University of Alberta HEREBY DISCLAIM ANY AND ALL WARRANTIES, EXPRESSED OR IMPLIED, INCLUDING THE WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, WHETHER ARISING BY LAW, CUSTOM, OR CONDUCT, WITH RESPECT TO ANY OF THE INFORMATION CONTAINED IN THIS REPORT. In no event shall the SPONSORS and the University of Alberta be liable for incidental or consequential damages because of use or any information contained in this report. Any reference in this report to any specific commercial product, process or service by tradename, trademark, manufacturer or otherwise does not necessarily constitute or imply its endorsement or recommendation by the University of Alberta or the SPONSORS.

274

i

Table of Contents

1. Introduction ................................................................................................................... 2

2. System Configurations and Parameters ................................................................... 2

3. Analytical Study............................................................................................................ 3

3.1 Substation GPR ........................................................................................................... 3

3.2 Neutral potential rise due to substation GPR ....................................................... 5

3.3 NPR transfer to customer .......................................................................................... 7

3.4 Representative values ................................................................................................ 8

3.5 Summary..................................................................................................................... 10

4. Case Study Results ..................................................................................................... 10

4.1 Effect of neutral grounding resistances ................................................................ 10

4.2 Effect of neutral grounding interval ..................................................................... 11

4.3 Effect of neutral length ............................................................................................ 12

4.5 Effect of customer grounding resistance .............................................................. 12

5. Summery and Conclusions ....................................................................................... 14

Appendix A: MGN configurations .................................................................................. 15

Appendix B : Equivalent impedance of MGN .............................................................. 15

275

2

1. Introduction

The objective of this project is to investigate the neutral potential rise (NPR) of the MGN feeders due to short-circuit within substation boundaries. When such a fault occurs, the substation neutral will experience a GPR. This GPR propagates to distribution feeders through their MGN neutral, resulting in the neutral voltage rise. The project has determined key factors affecting the GPR transfer and developed a practical NPR estimation method for APIC member companies. This project first employs analytical method to show the production of NPR and to establish simplified equations for its estimation. Case studies are then conducted to provide typical values expected in Alberta system. Finally, the case NPR transfer to the loads is studied. 2. System Configurations and Parameters Figure 2.1 illustrates the general layout of the system used in this project. A distribution feeder with a multi-grounded neutral (MGN) is supplied by a substation transformer. The upstream transmission system is represented by its equivalent circuit.

138 kV

Substation

MGN

25 kV Transmission side Distribution side Customer side

gnR

nZnZnZnZnZ

subRgnR gnRgnRgnR

///

Equivalent circuit of Upstream ends

fI

Figure 2.1 A distribution feeder with MGN and equivalent transmission system.

The interest of this study is to demonstrate how the GPR transfers to the neutral and to the customer load. The following cases have been identified and investigated:

Fault locations: T-side or D-side, inside the substation or just outside it. The connections of substation transformer windings (Delta or Y, grounded or ungrounded). The MGN configurations (full-neutral or islanded-neutral). The impedance of the substation transformer neutral.

The MGN that is islanded from the substation will not experience any GPR transfer through the neutral conductor (see Appendix A). Therefore, the study is restricted to the MGN that is essentially connected to the substation. The study presented in this report make the following assumptions:

The shield wire is assumed to be connected with the ground grid of substation under study and the upstream transmission substation.

276

3

The effect of induced voltages in the shield wire is ignored, which gives slightly conservative results.

The feeder loads are ignored. The fault currents are assumed to be known.

Table 2.1 shows the base case data and the sensitivity parameters considered in this study.

Table 2.1 Base case data and sensitivity parameters

Parameters Base case Value

Ranges and values

Substation fault current ( Line-to-ground)

5.0 kA @ T-side 2.0 kA @ D-side -

Substation grounding resistance ( subR ) 0.15 Ω - Substation transformer connection Wye(g)-Wye(g) Wye(g)-Wye(g) , Delta-Wye(g) MGN grounding interval 100 m 50, 100 , 250, 500 m Neutral grounding resistance ( gnR ) 15 Ω 7 , 15, 30 Ω Distribution line/neutral length 2 km 1, 2, 5 km Distribution neutral impedance( nZ ) 0.9114+j0.946 Ω /km -

3. Analytical Study Analytical studies are performed first to reveal the mechanism of the ground potential rise (GPR) and neutral potential rise (NPR) as result of ground-faults in the substation area. The effects of system parameters and arrangement on the behaviour of these phenomena are also demonstrated. 3.1 Substation GPR We first consider that the fault is at the transmission side (T-side) as shown in Figure 3.1. Since the source is at the upstream, the worst case occurs when a ground fault occurs inside the substation. According to this figure, the neutral and shield wires will divert a part of the fault current. However, since the substation ground resistance is significantly lower than the ground resistances of neutral and shield wires, we can assume that all the fault current flows into the substation ground. This produces the highest possible (i.e. conservative) GPR which is given by Equation (3.1).

TfsubfaultT IRGPR −− = ………………………………………………………….. (3.1) Where subR is the substation ground-grid resistance and TfI − is the T-side fault current.

277

4

subR


MGN

Distribution side-25 kV

gnRgnRgnR

fI

nZ nZ nZ

Figure 3.1 Fault current flow pattern for a T-line fault occurring in the substation. We then consider that the fault is at the distribution feeder side (D-side). In this case, the worst case involves a ground fault occurring just outside the substation. The fault current will return through grounding grid, leading to a high GPR. If the fault occurs within the substation, the fault current will be bypassed by the grounding grid, so the GPR is not as high as that of the first case. Both situations are shown in Figure 3.2. The resulting GPR for the fault just outside the substation is:

DfsubfaultD IRGPR −− = ………………………………………………………….. (3.2)

Where DfI − is the fault current for a fault on D-side. This equation is similar to Equation (3.1) except for the amount of fault current will be different.

(a) Fault outside substation (b) Fault inside substation Figure 3.2 Fault current flow pattern for D-line fault occurring inside and outside the substation The accuracy of the above equations is dependent on the winding configuration of the substation transformer as shown in Figure 3.3. In any case, the highest possible GPR is given by the equations (3.1) and (3.2). The highest GPR per kA of the fault current will be 150 V/kA, which is determined by the substation ground resistance (0.15 Ω in this example).

N eutra l

G round ing g rid

fI

fI

Neutral

Grounding grid

fI

fI

278

5

D/Yg transformer

Neutral

fI

Grounding grid

fI

Yg/Yg transformer

fI

Neutral

'fI

Grounding grid

fI

fsubIRGPR =

fsubffsub IRIIRGPR ≅−= )( '

Note: The Y/Yg case has no fault current.

Figure 3.3 The transformer winding configurations and corresponding GPR equations.

The neutral impedance of the transformer will affect the fault current (Figure 3.4). However, the above equations hold for the calculation of GPR.

Neutral

fI

fI

Neutral impedance

Grounding grid

Figure 3.4 Neutral impedance at secondary side of the substation transformer. 3.2 Neutral potential rise due to substation GPR Once we know the substation GPR, the neutral voltage rise due to this GPR can be understood from the circuit of Figure 3.5. In this case, we assume that the substation GPR is modeled as a voltage source. This assumption is valid since, as discussed earlier, the substation GPR will not be affected significantly by the D-line neutral configurations. The equivalent impedance of the MGN is shown in Appendix B.

279

6

(a) (b)

Figure 3.5 The equivalent voltage source of GPR and multi-grounded neutral. According to this model (Fig. 3.5), the highest NPR occurs at the first grounding point, one span away from the substation. It can be estimated by using the voltage divider principle as shown in Equation (3.3)

GPRZZ

ZNPR

nMGN

MGN

+=max ……………..…...................………………..………..(3.3)

GPRkNPR *max =

nMGN

MGN

ZZ

Zk

+= ……………..………....................………………….……..(3.4)

where nZ : The impedance of neutral wire per span.

MGNZ : The equivalent impedance of multi grounded neutral. k : The ratio of maximum NPR to GPR.

Here, the ratio k is considered as an estimator for how much GPR will transfer to the first span of the MGN. It is only a function of MGN parameters (neutral wire impedance; grounding resistance and ground span length), and independent of the fault locations, MGS and substation resistance.

Figure 3.6 shows k values for different grounding intervals and grounding resistances of the MGN. This ratio increases with the grounding resistance, but decreases when the grounding span length increases.

MGNZsubR

Substation

maxNPRGPR

nZ

gnRgnRgnRgnR

nZ nnZ

subR

Substation

nZnZ nZ nZGPR

MGNZ

gnR

280

7

0.7

0.8

0.9

1

7 15( base case) 30

Grounding resisatnce [Ω]

Ratio

[GPR

/NPR

]

S=50m S=100m (base case) S=250m S=500m

Figure 3.6 Effect of MGN grounding resistance and span length on the value of k

3.3 NPR transfer to customer Figure 3.7 shows the schematic diagram of the single and 3-phase customer loads supplied from the distribution feeder. The MGN neutral network can be represented by Figure 3.8, irrespective of the single-phase or three-phase loads. The NPR transfer mechanism is essentially the same as GPR transfer to the first grounding point of the neutral.

A

B

C

N


GPR propagation

a

b

Three phase customer

cn

cn

Single phase customer

Figure 3.7 Three-phase and single-phase representation of MGN The NPR at the first grounded node of the neutral is given as:

1 maxNPR =NPR =k譍 PR ……………..…....................……………….…….…… (3.5)

281

8

Similarly, the NPR at the second grounded node is: 2 1 1NPR =k 譔 PR ……………………………………………..…………...………. (3.6) In this manner,

i+1 i iNPR =k 譔 PR

Where MGN-ii

MGN-i n

Zk =Z + Z

………………………………………………………………......... (3.7)

In Equation (3.7), the ZMGN-i is the equivalent impedance of the MGN seen downstream from the ith span of the neutral. The ZMGN-i are equal for a sufficiently long neutral (see Appendix B). Therefore, the voltage divider ratios will be the same. i.e. k1 = k2 = …= ki (= k). This is particularly true when there are about more than 10 ground spans downstream of the grounded node in question. From Equations (3.5) and (3.6), the NPR at the 2nd node will be:

2 1NPR =k k 譍 PR× ………………………………………………………….…… (3.8)

Since k1 = k,

22NPR =k 譍 PR

Now the NPR of the nth grounded node of the neutral can be expressed as:

nnNPR =k 譍 PR …………………………………………………………….…… ..(3.9)

As mentioned earlier, Equation (3.9) is valid until n = N-10, where N is the total number of grounding spans (or nodes) of the neutral. For the last 10 segments, the k ratios (Eq. 3.7) become nearly equal to 1 because ZMGN >>Zn. Therefore, the NPR will be approximately the same as that of the (N-10)th grounded node.

gnRgnRgnRgnR

nZ nnZnZ nZ nZ nZ

maxNPR

GPRgnR

Customer #1 Customer #2

2NPR NNPR

Figure 3.8 GPR transfer to customer 3.4 Representative values Figure 3.9 shows the typical results for the GPR and max NPR values. The fault current on D-side was (2 kA) and that for the T-side was (5 kA). As seen, GPR and NPR for the fault at T-side are significantly larger than fault at D-side. This is due to the fact that fault current at T-side is much higher than that at D-side.

282

9

0

100

200

300

400

500

600

T-side fault D-side fault

Volta

ge [V

]GPR max.NPR

Figure 3.9 Summary of GPR and NPR results for T-side fault and D-side fault.

The representative k-index values and NPR are shown in Table 3.2. To unify the results for the T-side faults and D-side faults, the GPR and NPR are presented in terms of per kA of fault current, i.e. the actual values of GPR and NPR are divided by the fault current. Table 3.3 shows the NPR of the neutral at different distances from the substation. It is noticed that the customer will experience higher NPR with span length 500 m.

Table 3.2 Representative values of the k-index and max NPR/kA. Observation GPR transfer

ratio k Max NPR

per kA (V/kA)




Low end value 0.76 108 m 500S, 7 =Ω=gnR

Table 3.3 Representative values of NPR in the neutral. Corresponding

system condition Max NPR

per kA NPR per kA at 2

km (V/kA) NPR per kA at 5 km

(V/kA) m 50S, 30 =Ω=gnR 129 24 3.4

m 001S, 15 =Ω=gnR 124 22 3.2

m 500S, 7 =Ω=gnR 108 46.4 12

283

10

3.5 Summary The GPR transfer to the distribution neutral involves a very simple phenomenon: the substation GPR is “shared” by a voltage divider formed by a ladder network consisting of neutral grounding resistances and neutral conductor impedances. The same principle applies to the NPR transfer to the customers. It is not important to know what type of faults causes the GPR since the fault type does not affect the highest GPR transfer ratio k. 4. Case Study Results In this section, several case study results are shown to illustrate the impact of the multi grounded neutral parameters including grounding interval, grounding resistance, length of the neutral, etc. The case studies assume that the customer grounding resistance is equal to the MGN grounding resistance, except for the case study for the effect of customer grounding resistance. 4.1 Effect of neutral grounding resistances Figure 4.1 shows the NPR as the percentage of GPR along the neutral length due to the substation GPR transfer for different grounding resistances. The max NPR (i.e. at the first grounding point) increases from 87% to 94% of GPR when Rgn increases from 7 Ω to 30 Ω. The increase in NPR at 2 km is larger (from 8% to 30%). However, the customers that are located farther will see the smaller effects of grounding resistances.

0

10

20

30

40

50

60

70

80

90

100

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5Distance from substation[km]

Per

cent

age

of s

ub.G

PR

Rgn=7Ω Rgn=15 Ω (base case) Rgn=30Ω

Figure 4.1 The GPR transfer to the MGN neutral for different grounding resistances.

Max. NPR

Customer

284

11

4.2 Effect of neutral grounding interval Figure 4.2 shows the GPR transfer to the MGN neutral for different lengths of grounding spans. It can be seen that the NPR increases with the grounding span. As moving away from the substation, the increase in NPR becomes larger. However, as we move further the increases become smaller.

0

10

20

30

40

50

60

70

80

90

100

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

Distance from substation[km]

Per

cent

age

of s

ub.G

PR

S= 50 mS= 100 m(base case)S= 250 mS= 500 m

Figure 4.2 The GPR transfer to the MGN neutral for different grounding spans.

Customer

max.NPR

285

12

4.3 Effect of neutral length The effect of neutral lengths was investigated for a 1 km, 2 km and 5 km neutral as illustrated in Figure 4.3. The shorter the neutral length, the higher will be the NPR at its end. However, the maximum NPR will be affected only slightly. A customer will experience high NPR (70% of GPR) as long as the distance between the customer and substation is about 1 km. Increasing the neutral length to 2km will reduce the customer NPR by 40% . In conclusion the neutral length has significant impact of the NPR profile.

0

10

20

30

40

50

60

70

80

90

100

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

Distance from substation[km]

Per

cent

age

of s

ub.G

PR

L=1 km

L=2 km(base case)

L=5 km

Figure 4.3 The NPR of the MGN neutral for different lengths of the neutral.

4.5 Effect of customer grounding resistance The customer grounding resistances are generally small because there are many parallel ground connections, such as groundings of multiple houses. Figure 4.4 shows the effect of the customer grounding resistance on the NPR at the customer location. In this case, the customer is located at the end of the neutral. The customer NPR will initially increase significantly when the grounding resistance increases from 0.1 Ω to 5 Ω. But the further increase in its grounding resistance will affect the NPR slightly. Figure 4.5 shows the NPR profile when the neutral is extended downstream of the customer. In this case, the effect of grounding resistance on the customer NPR is relatively small, and as it increases its impact is negligible.

286

13

0

10

20

30

40

50

60

70

80

90

100

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2Distance from substation[km]

Perc

enta

ge o

f sub

.GPR

R= 0.1Ω R= 1 Ω R=5 Ω R=10 Ω R=15 Ω (base case) R=30 Ω

Figure 4.4 Effect of customer grounding resistance (2 km neutral, customer at 2 km).

0

10

20

30

40

50

60

70

80

90

100

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5Distance from substation[km]

Perc

enta

ge o

f sub

.GPR

R= 0.1Ω

R= 1 Ω

R=5 Ω

R=10 Ω

R=15 Ω (base case)

R=30 Ω

Figure 4.5 Effect of customer grounding resistance (5 km neutral, customer at 2 km).

The distance of the customer from the substation is an important consideration. Customer with low grounding resistance (0.1 & 1 Ω) will affect the NPR profile slighty .However if the customer is connected at the distance more than 2 km from the substation; the effect of customer grounding resistance is dominated by the other MGN grounding resistances.

Customer

287

14

5. Summery and Conclusions The mechanisms involved in the GPR production are the same for the T-side faults and for the D-side faults. The mechanism of the GPR transfer to the MGN neutral is independent of the fault location in the substation. The following conclusions can be drawn:

• The maximum GPR at the substation is about 150 V/kA of fault current for the faults on either side of the transformer, assuming the substation grounding resistance of 0.15 Ω.

• The maximum NPR that occurs on the first grounding point is about 95% of the GPR. The NPR at the downstream customer loads at 2 km and 5 km are 35% and 8%, respectively.

• The NPR at the grounding points of MGN increases with the increase in neutral grounding resistances or grounding intervals.

• The customer grounding resistance will affect the NPR that transferred to a customer when the neutral is short (less than 2 km) and ends to the customer location.

In summary, general models for estimating the substation GPR and the maximum NPR have been established. This study is also applicable for the system where a multi-grounded conductor (shield, neutral, etc) is extended from the substation.

288

15

Appendix A: MGN configurations

The MGN arrangement determines whether or not the neutral will experience voltage rise with the fault occurrence in the substation. Figure A-1 presents different schemes of multi-grounded neutral in the distribution systems. These configurations are described below: Full-MGN: The neutral is terminated to substation grid and also connected at the load’s neutral. In this case, the substation GPR can propagate to the customer load points. MGN-L: In this arrangement, the neutral conductor is isolated from substation, but it is connected to the loads of the feeder. The GPR will not transfer in this arrangement. MGN-S: The neutral is connected to the substation grid, but it terminates before reaching the feeder load. The GPR will transfer to the neutral points, but does not create the NPR at customer load. MGN-I: The neutral is islanded from both sides, i.e. from substation and from the load. There will no GPR transfer in this case.

138 kV

Substation

Full MGN25 kV Distribution side

Substation

MGN-S25 kV Distribution side

Substation

MGN-I25 kV Distribution side

Substation

MGN-L25 kV Distribution side

Load sideLoad side

Load side Load side

Figure A-1 MGN arrangements in distribution systems.

In summary, the MGN that is islanded from the substation will not experience NPR through the neutral conductor. Appendix B: Equivalent impedance of MGN Figure B-1 shows the equivalent impedance of the multi-grounded neutral (MGN), i.e. ZMGN for the grounding resistance of 15 ohm and grounding span of 100 m. The equivalent impedance initially decreases with the increase in neutral length, but remains constant at about 1.5 ohm after exceeding a certain length (about 1.6 km in this case, i.e. 16 grounding spans).

289

16

0

2

4

6

8

10

12

14

16

0 0.5 1 1.5 2Neutral length [km]

Equi

vlen

t im

ped.

[ohm

]

Figure B-1 MGN arrangements in distribution systems.

gnRgnRgnRgnR

nZ nnZnZ nZ nZ nZ

gnR

MGNZ

290

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