ARC FLASH STUDIES - Murdoch University · 2016. 4. 18. · arc flash calculations were conducted...

ARC FLASH STUDIES An Internship with Fortescue Metals Group

Limited

SCHOOL OF ENGINEERING AND INFORMATION TECHNOLOGY

CHRISTIAN BARABONA BACHELOR OF ENGINEERING

(ELECTRICAL POWER AND INDUSTRIAL COMPUTER SYSTEMS)

JANUARY 2016

Disclaimer

I declare the following work to be my own, unless otherwise referenced, as defined by Murdoch University’s Plagiarism and Collusion Assessment Policy.

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Abstract

A significant safety risk to electrical personnel working on an energised switchboard is the hazard

of exposure to arc flash, which has gained increasing attention over the past decade. Although

reported arc flash injuries are infrequent compared to other electrical injuries, especially electric

shock, the very high costs associated with these arc flash injuries make them one of the most

important categories to avoid in an industrial workplace.

The main objective of this project is to conduct arc flash studies for switchboards installed at

Fortescue’s Solomon Hub to quantify the existing arc flash hazard posed by this type of equipment.

The aim of the study is to find feasible solutions to reduce arc flash incident energy to less than 8

cal/cm2 and to provide appropriate arc flash PPE recommendations.

Switchboards with voltage levels of 0.4kV, 0.69kV, 6.6kV, 11kV and 33kV were investigated. The

arc flash calculations were conducted using the IEEE 1584-2002 Standard, IEEE Guide for

Performing Arc-Flash Hazard Calculations. The study found that many switchboards have dangerous

incident energy levels that must be reduced, in order to allow energised work on the equipment. To

mitigate the hazard, three simple solutions were proposed: optimise protection settings, install

maintenance switches and remote operation.

Firstly, optimising protection settings is the least expensive solution to reduce the operating time of

protection devices, and hence limit arc flash incident energy exposure. Secondly, where a permanent

setting will violate the grading requirement of the system, then installing maintenance switches is

proposed. Thirdly, where the first two strategies cannot be implemented because they will violate

the grading requirement of the system, then remote operation is proposed. This will eliminate the arc

flash hazard because personnel will operate the equipment outside the arc flash boundary.

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If the recommendations of this study are implemented, the arc flash incident energy of the

switchboards will significantly reduce to not greater than 8 cal/cm2. The implications are improved

safety for personnel, given that energy levels on many switchboards currently pose a significantly

higher arc flash hazard.

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Acknowledgements

Firstly, I would like to thank FMG’s engineering team especially my industry supervisors; Lead

Electrical Engineer Brad Mcleod and Principal Electrical Engineer Cobus Strauss for giving me the

opportunity to undertake an engineering internship as part of their team. The support and guidance

that you have provided is much appreciated and the knowledge I have gained from all of you is

invaluable.

I would also like to express my gratitude to my academic supervisors; Dr Sujeewa Hettiwatte and

Dr Gregory Crebbin for their academic assistance, not only for the internship project but also for the

support they have provided throughout my degree at Murdoch University. I would also like to

acknowledge the rest of the staff at the School of Engineering for facilitating our learning and guiding

us throughout our university studies.

Furthermore, I would like to thank my fellow students for making my time at university enjoyable

and for contributing to my academic and professional development.

Most importantly, I would like to thank my family for their unwavering support and encouragement.

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Table of Contents Abstract ............................................................................................................................................iii

Acknowledgements .......................................................................................................................... v

List of Figures ................................................................................................................................. viii

List of Tables .................................................................................................................................... ix

Definitions, Acronyms and Terms Used in this Thesis Report .......................................................... xi

List of symbols ................................................................................................................................. xii

1 Introduction ............................................................................................................................. 1

2 Background .............................................................................................................................. 3

2.1 Engineering Internship ..................................................................................................... 3

2.2 Fortescue Metals Group ................................................................................................... 3

2.2.1 Solomon Hub ............................................................................................................ 4

2.3 Project Background .......................................................................................................... 5

2.4 Arc flash ............................................................................................................................ 7

2.5 Arc flash reported incidents and statistics ........................................................................ 9

2.5.1 Standards and WHS Requirements ......................................................................... 10

2.6 Arc Flash Studies............................................................................................................. 13

2.6.1 NFPA 70E ................................................................................................................ 14

2.6.2 IEEE Std 1584 – 2002 .............................................................................................. 15

2.7 Assumptions and Clarifications ...................................................................................... 16

2.8 PowerFactory ................................................................................................................. 16

3 Methodology .......................................................................................................................... 17

3.1 System audit, data collection and power system modelling .......................................... 17

3.2 Short-Circuit Study ......................................................................................................... 18

3.2.1 Effect of motor contributions in the calculations ................................................... 19

3.3 Arc current calculations .................................................................................................. 21

3.4 Coordination studies ...................................................................................................... 23

3.5 Incident energy and arc flash boundary calculations ..................................................... 24

3.6 PPE selection .................................................................................................................. 26

3.7 Process flowchart ........................................................................................................... 27

4 Results .................................................................................................................................... 28

4.1 Stockyard ........................................................................................................................ 28

4.2 Firetail ............................................................................................................................ 29

4.3 Kings Valley..................................................................................................................... 30

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4.4 RMUs + other attached switchboards ............................................................................ 31

5 Discussion ............................................................................................................................... 32

5.1 Elimination ..................................................................................................................... 36

5.2 Substitution .................................................................................................................... 36

5.3 Engineering Controls ...................................................................................................... 37

5.3.1 Optimise protection settings .................................................................................. 37

5.3.2 Installing a maintenance switch ............................................................................. 37

5.3.3 Zone Selective Interlocking Scheme ....................................................................... 38

5.3.4 Remote Operation .................................................................................................. 39

5.4 Administrative control .................................................................................................... 40

5.5 PPE ................................................................................................................................. 40

6 Recommendations ................................................................................................................. 41

7 Conclusion .............................................................................................................................. 44

8 References.............................................................................................................................. 46

9 Appendices ............................................................................................................................. 49

9.1 Appendix A – Solomon Interconnection diagram ........................................................... 49

9.2 Appendix B – LV incomers Settings................................................................................. 50

9.3 Appendix C – Arc flash study results for the Stockyard .................................................. 53

9.4 Appendix D – Arc flash study results for Firetail OPF...................................................... 54

9.5 Appendix E – Arc flash study results for Kings Valley OPF .............................................. 56

9.6 Appendix F – Arc flash study results for RMUs and switchboards downstream ............. 59

9.7 Appendix G – GE LV circuit breaker curve ...................................................................... 61

9.8 Appendix H – Maintenance mode protection settings ................................................... 62

9.9 Appendix I – Arc flash study results for Stockyard based on the proposed solutions ..... 63

9.10 Appendix J – Arc flash study results for the Firetail OPF based on the proposed solutions

65

9.11 Appendix K – Arc flash study results for the Firetail OPF based on the proposed

solutions ..................................................................................................................................... 67

9.12 Appendix L – Arc flash study results for RMUs based on proposed solutions ................ 69

9.13 Appendix M – Proposed protection settings to resolve grading problems found .......... 71

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List of Figures Figure 1: Fortescue Metals Group Limited Operations Map [1]....................................................... 4

Figure 2: Switchboard installed in Substation 2 ............................................................................... 6

Figure 3: Locations within a switchboard where arc faults can occur: a) outgoing terminal of the

feeder, b) feeder, c) distribution bus, d) main busbar and e) incomer or incoming cable termination.

(Redrawn from [23]) ...................................................................................................................... 12

Figure 4: Fault simulation showing motor contributions ................................................................ 21

Figure 5: TCC illustrating the significant increase in incident energy for a 10% arc current

reduction ........................................................................................................................................ 22

Figure 6: TCC illustrating the effect of the clearing characteristics of a protection relay on the

incident energy ............................................................................................................................... 24

Figure 7: Flow chart which illustrate the steps conducted to achieve the goals of the arc flash

studies ............................................................................................................................................ 27

Figure 8: Fault simulation showing the faulted switchboard .......................................................... 32

Figure 9: Hierarchy of controls (redrawn from [40]) ...................................................................... 36

Figure 10: Zone selective interlocking ........................................................................................... 39

Figure 11: GE LV circuit breaker curve (approval pending [39] .................................................... 61

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List of Tables Table 1: Definitions, acronyms and terms used in this report ........................................................... xi

Table 2: Limitations of equations from IEEE 1584 ........................................................................ 15

Table 3: Distance factors and typical conductor gaps used for the arc flash calculations [30] ....... 22

Table 4: PPE requirements based on incident energy exposure [26] .............................................. 26

Table 5: Arc flash study results for switchboards installed at the Stockyard .................................. 28

Table 6: Arc flash study results for switchboards installed at Firetail OPF .................................... 29

Table 7: Arc flash study results for switchboards installed at Kings Valley OPF........................... 30

Table 8: Arc flash study results for RMUs and loads fed from the RMUs ..................................... 31

Table 9: Existing Stockyard .4 kV MCC protection settings .......................................................... 50

Table 10: Existing Firetail .4 kV MCC protection settings............................................................. 50

Table 11: Existing KV .4 kV MCC protection settings .................................................................. 51

Table 12: 0.4kV MCCs fed from RMUs ........................................................................................ 51

Table 13: Exising incomer protection settings for VSDs ................................................................ 52

Table 14: Arc flash study results for 0.4kV switchboards installed at the Stockyard based on the

existing protection settings ............................................................................................................. 53

Table 15: Arc flash study results for 11kV switchboards installed at the Stockyard based on the


Table 16: Arc flash study results for 0.4kV switchboards installed at Firetail OPF based on the


Table 17: Arc flash study results for 6.6kV switchboards installed at Firetail OPF based on the


Table 18: Arc flash study results for 33kV switchboards installed at Firetail OPF based on the


Table 19: Arc flash study results for 0.4kV switchboards installed at KV OPF based on the existing

protection settings .......................................................................................................................... 56

Table 20: Arc flash study results for the 6.6kV switchboards installed at KV OPF based on the


Table 21: Arc flash study results for 33kV switchboards installed at KV OPF based on the existing


Table 22: Arc flash study results for the RMUs based on the existing settings .............................. 59

Table 23: Arc flash study results for the sizer drives switchboards based on the existing protection

settings ........................................................................................................................................... 59

Table 24: Arc flash study results for the VSDs based on the existing protection settings .............. 59

Table 25: Arc flash study results for 0.4kV switchboards based on the existing protection settings

....................................................................................................................................................... 60

Table 26: Settings and location of the three maintenance switches ................................................ 62

Table 27: Arc flash study results for 0.4kV switchboards installed at the Stockyard based on the

proposed protection settings ........................................................................................................... 63

Table 28: Proposed protection settings for the Stockyard 0.4kV switchboards incomers ............... 63

Table 29: Arc flash study results for the Stockyard 11kV switchboards based on the proposed


Table 30: Proposed protection settings for Stockpile 11kV switchboards incomers....................... 64

Table 31: Arc flash study results for Firetail 0.4kV switchboards based on the proposed protection

settings ........................................................................................................................................... 65

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Table 32: Proposed protection settings for Firetail 0.4kV switchboards incomers ......................... 65

Table 33: Arc flash study results for Firetail 33kV switchboards based on the proposed

maintenance mode protection settings ............................................................................................ 66

Table 34: Arc flash study results for KV 0.4kV switchboards based on the proposed protection

settings ........................................................................................................................................... 67

Table 35: Proposed protection settings for KV 0.4kV incomer ...................................................... 68

Table 36: Arc flash study results for KV 33kV switchboards based on the proposed maintenance

mode protection settings................................................................................................................. 68

Table 37: Arc flash study results for the RMUs based on the proposed maintenance mode


Table 38: Arc flash study results for 0.4kV switchboards based on the proposed protection settings

....................................................................................................................................................... 69

Table 39: Proposed protection settings for LV incomers ................................................................ 70

Table 40: Proposed settings for protection devices for the main Firetail 33kV switchboard (2000-

SR001) ........................................................................................................................................... 71

Table 41: Proposed settings for protection devices for the main KV 33kV switchboard (2000-

SR001) ........................................................................................................................................... 71

Table 42: Proposed settings for feeders to RMUs for correct coordination between protection

devices ........................................................................................................................................... 71

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Definitions, Acronyms and Terms Used in this Thesis Report

Table 1: Definitions, acronyms and terms used in this report

A Amperes

AC Alternating Current

Arc fault

current A fault current flowing through ionized air during an arc flash event

Bolted fault

current

A short-circuit or electrical contact between conductors at different voltages in

which the impedance between the conductors is close to zero

Cal Calories

CB Circuit Breaker

cm Centimetre

DOL Direct On Line

Feeder The first downstream protection device relative to the main busbar

FLA Full Load Amps

Grading Correct coordination between protection devices

HV High Voltage (greater than or equal 1kV)

IAC Internal Arc Classification

Instantaneous

function Protection element of low voltage circuit breakers that has no intentional delay

Incomer First upstream protection device relative to the main busbar

kA Kilo Amperes

kV Kilo Volts

KV Kings Valley

Long time

function Inverse-time overcurrent element of low voltage circuit breakers

LV Low Voltage (less than 1kV)

MCC Motor Control Centre

MS Maintenance Switch

MPU Mobile Power Unit

Operating time Total time taken by a protection device to initiate trips or alarms exclusive of any time

delays inherent in the tripping circuit after a trip is initiated

OPF Ore Processing Facility

PIMS Project Information Management System

PPE Personal Protective Equipment

Racking Process of disconnecting a circuit breaker from the bus

RMU Ring Main Unit

SCADA Supervisory Control and Data Acquisition

Short time

function Protection element of low voltage circuit breakers that has intentional delay

SLD Single Line Diagram

TCC Time-Current Curve

Total Clearing

Time Sum of the protection device operating time and the opening time of the circuit breaker

Upstream

protection

device

Feeder from the first upstream switchboard

V Voltage

WHS Workplace Health and Safety

Working

distance Distance between the worker and the potential arc source inside the equipment

50P Protection element of protection relays that has no intentional delay

51P Inverse-time overcurrent element of protection relays

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List of symbols

𝐶𝑓 Calculation factor

𝐷 distance from the possible arc point to person (mm)

𝐷𝐵 distance of the boundary from the arcing point (mm)

𝐸 is incident energy (J/cm2)

𝐸𝐵 incident energy at the boundary distance (J/cm2)

𝐸𝑛 normalized incident energy

𝐼𝑎 arcing current (kA)

𝐼𝑎,𝐿𝑉 arc current reflected in the LV side of the transformer (A)

𝐼𝑎/𝐻𝑉 arc current reflected in the HV side of the transformer (A)

𝐼𝑝𝑢 pickup setting of the protection relay (A)

𝐼𝑏𝑓 bolted fault current (kA)

𝑙𝑔 log10

𝑡 time (seconds)

𝑡𝑜 opening time of the circuit breaker (seconds)

𝑡𝑝 operating time of the protection device (seconds)

𝑡𝑡𝑜𝑡𝑎𝑙 total clearing time of the protection device (seconds)

𝑇𝐷 Time dial

𝑉 voltage (kV)

1

1 Introduction

Aside from the risk of electric shock, the principal safety risk to electrical personnel operating and

maintaining high voltage (HV) and low voltage (LV) switchboards is exposure to arc flash from live

bare power terminals or conductors within switchboards. In the past decade, many industrial

companies across the globe have recognised the significance of understanding and mitigating the

hazards posed by arc flash events occurring in their facilities. While reported injuries caused by an

arc flash are rare, the cost related to these injuries can be very high, making them one of the most

important categories of injuries to avoid in an industrial workplace.

An arc flash will primarily occur when personnel are undertaking switching functions or

maintenance work that require switchboard doors to be opened or covers to be removed. In order to

quantify the amount of energy released during such an event, arc flash studies must be performed.

The purpose of this project is to determine the existing arc flash incident energy levels of HV and

LV switchboards installed in the Solomon Hub, which is owned by Fortescue Metals Group Limited

(“Fortescue”). The term “switchboard” will also include ring main units (RMUs) and motor control

centres (MCCs) for the rest of this document. The principal aims of the project are to reduce the

incident energy to less than 8 cal/cm2 where possible, and to determine the appropriate arc flash

personal protective equipment (PPE) where it is not feasible to reduce the incident energy to less

than 8 cal/cm2. To achieve these aims, the following tasks were conducted:

Verification of existing power network models and expanding the models where required;

Short circuit studies to determine maximum and minimum three-phase fault currents at the

switchboards;

Maximum and minimum arc current calculations;

Coordination studies to determine the clearing times of the protection devices for the

corresponding arc fault currents; and

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Incident energy and arc flash boundary calculations.

This thesis discusses how the study was conducted, the results of the studies based on the existing

state of the system, the proposed solutions as well as the arc flash studies results based on these

solutions. In addition, a section detailing different solutions that were investigated to mitigate the arc

flash hazard is included.

This report begins with a background section that will provide sufficient information about the

internship project and will give comprehensive facts in regards to the arc flash study.

3

2 Background

2.1 Engineering Internship

Murdoch University engineering students must complete the unit ENG470-Engineering Honours

Thesis as one of the requirements for Bachelor of Engineering at Murdoch University. The internship

is one of two types of projects that engineering students at Murdoch University can undertake. The

internship placement provides students with exposure to their prospective industry while gaining

practical problem-solving experience. The aim of the unit is to develop the following graduate

attributes: communication, critical and creative thinking, social interaction, independent learning,

ethics and in-depth knowledge of the project topic.

The internship project took place at Fortescue’s corporate office in Perth under the direct supervision

of a senior Electrical Engineer. The placement was a full time position for 18 weeks where the main

task undertaken was the arc flash studies for the Solomon Hub. As part of the electrical engineering

team, the intern also undertook minor tasks such as power network modelling and simulations. These

tasks provided opportunities to turn theory learned from formal studies into practice, while gaining

invaluable skills and knowledge of how to become a successful engineer.

2.2 Fortescue Metals Group

Since the company’s inception in 2003, Fortescue Metals Group (FMG) has managed to acquire

several tenements in the Pilbara region of Western Australia where significant iron ore deposits have

been discovered. The company owns port facilities and a 620 km rail infrastructure that is used to

transport iron ore from the company’s two operating hubs, which include Cloudbreak, Christmas

Creek, Firetail and Kings Valley mines, as shown in Figure 1. The mining operation was built on an

existing mine lease and is now producing 165 million tonnes of iron ore per year, making Fortescue

the fourth largest iron ore producer in the world.

4

Figure 1: Fortescue Metals Group Limited Operations Map [1]

2.2.1 Solomon Hub

Solomon Hub is located 120 km west of Chichester Hub and includes Firetail and Kings Valley

mines. Solomon Hub has almost twice the resource of Chichester Hub and produces more than 70

metric tonnes of iron ore per year [1]. The arc flash studies were conducted for switchboards installed

in the Solomon Hub, and hence this report will only focus on Solomon Hub’s electrical system.

2.2.1.1 Solomon Hub power system arrangement

Power for Solomon Hub is supplied by four 15MVA Solar Titan 130 (“MPU”) [2] and two GE

LM6000PF Dual Fuel Gas Turbine Generators with maximum individual capacity of 63.5MVA [3].

The power plant is owned by TransAlta and operated as an islanded electrical system. The plant

supplies power to the mining, crushing, screening, overland conveying, stock-piling and train load

out facilities, workshops, administration services buildings and an accommodation village.

Power from the LM6000 generators and MPUs is generated at 11kV. The MPUs are used to supply

power to the Primary Diesel Facility, Stockyard and RMU 10 at 11kV; while some of the generated

power is fed to Substation 1 for transmission at 132kV. Likewise, power from the LM6000

generators is stepped-up to 132kV by two transformers installed in Substation 1 for transmission.

5

From Substation 1, power is transmitted to Substation 2 and Substation 3. In Substation 2, a 50MVA

transformer is used to step-down the voltage to 33kV and feed to a 33kV switchboard where

electricity is distributed to RMU 11, RMU 14 and Firetail ore processing facility (OPF) main 33kV

switchboard via two feeders. The power network set-up for Substation 3 is the same, although power

is distributed to RMU 29, RMU 12 and Kings Valley OPF.

The main 33kV switchboards in Firetail OPF and Kings Valley OPF have a number of outgoing

feeders that supply power to various plant switchrooms. From each switchroom, power is reticulated

to 6.6kV and 400V switchboards to provide power for motors and other electrical equipment

installed at the OPFs. The power network interconnection diagram for the Solomon Hub is shown in

Appendix A.

2.3 Project Background

Electricity is a widely used energy resource as it provides an efficient source of power for

applications such as lighting, heating and many others. Well maintained and operated electrical

equipment will offer a very high level of service and safety. One of the major pieces of electrical

equipment installed in an industrial facility is a switchboard. A switchboard is an assembly of panels

containing busbars, protection devices and auxiliary equipment that are critical to the safe and

continuous operation of electrical equipment. Electricity is transmitted to a switchboard from a

power supply, where it is distributed to downstream equipment. Shown in Figure 2 is a switchboard

installed in Substation 2 at the Solomon Hub that is used to distribute electricity to RMU 11, RMU

14 and Firetail OPF.

6

Figure 2: Switchboard installed in Substation 2

A switchboard is the main point of isolation if downstream equipment is being tested or requires

maintenance and needs to be de-energised. However, electrical personnel working with, or in close

proximity to a switchboard must be aware that, under certain conditions, electrical switchboards

present a serious hazard. Industrial power networks operate at higher energy levels and higher

voltage levels than domestic systems and therefore an awareness of these additional hazards is

essential. When personnel are working on a switchboard, they are exposed not only to electric shock

but also to an arc flash hazard.

An arc flash hazard is a dangerous condition caused by an electric arc as a result of electrical faults

[4]. Because of the significant and even catastrophic nature of these events, elimination and

mitigation strategies continue to receive attention. An arc flash will primarily occur when personnel

are switching or racking a circuit breaker or maintenance work is being performed in the

switchboard. In order to determine the hazard posed by an arc flash event, arc flash studies must be

performed.

In August 2014, Fortescue’s Perth Engineering team initiated arc flash investigations as a critical

safety initiative. The goal of the overall study was to determine the arc flash hazard posed by

switchboards installed in the Solomon Hub and to find solutions to mitigate the hazard. The arc flash

7

hazard assessment was limited to switchboards with voltage levels of at least 400V. Switchboards

that have a lower rating have a relatively low fault current associated with them, hence a low risk of

an arc fault developing with sufficient energy to cause a severe injury.

There is no regulatory requirement for the company to perform an arc flash study. However, to fulfil

the Workplace Health and Safety (WHS) requirement of the company, all measures must be

undertaken to ensure safety of personnel, and hence arc flash studies are recommended.

2.4 Arc flash

An arc flash is the release of heat and light energy when an insulator between energised conductors

fails and current flows through a normally nonconductive medium, such as air [5]. The arc flash

caused by dielectric breakdown is identical to the arc flash emitted by an arc welder. Some of the

causes of arc flash are:

Rats and snakes entering the equipment;

Using an item of under-rated measuring equipment;

Loose joints;

Tools left behind after maintenance; and

Tools accidentally touched two energised conductors.

When objects touch energised conductors, it can result in a short circuit fault. The large fault current

will result in a strong magnetic field, which in turn will propel the object away. As the object moves

away, the current continues to flow and forms very hot arcs which vaporise conductors and ionize

gases. An arc flash can also occur for the same reason when switching or racking a circuit breaker.

In systems with high voltage, tracking can also initiate an arc flash event. This occurs naturally due

to the dielectric breakdown value of air, making it possible for an arc flash to occur over a much

greater air gap, and also due to the tendency of partial discharge to occur over time across insulation,

8

eventually leading to insulation breakdown and an arc fault developing. The arc formation in a

cubicle occurs across different phases [6]:

1. Compression phase: the air where the arc develops is overheated. Then, through

convection and radiation, the remaining volume of air inside the cubicle also increase in

temperature.

2. Expansion phase: as soon as the internal pressure increases, a hole in the cubicle is

formed where the superheated air begins to escape. The pressure increases until it

reaches its maximum value.

3. Emission phase: the superheated air is forced out by an almost constant overpressure

which is the result of the continued contribution of energy by the arc.

4. Thermal phase: after the discharge of air, the temperature inside the cubicle is close to

the arc’s temperature. The final phase lasts until the arc is extinguished, where the

materials inside the cubicle coming into contact, experience erosion with production of

gas, molten material and fumes.

The electric arc between metals is four times as hot as the surface of the sun, which is the hottest

temperature reached on earth [7]. In a bolted fault, such as phase-phase and phase-to-ground faults,

the fault current stays within the conductors where resistance is very low, therefore, little heat is

generated. For an arc fault, there is an appreciable resistance between conductors because a current

is flowing through the air. The heat generated is significant due to the higher resistance path between

conductors. The arc flash may blow equipment doors open and propel parts including molten metals.

The arc flash may continue until the generated voltage has been consumed or a protection device

clears the fault. The potential hazards caused by an arc flash event may include [8]:

9

Burns – an electric arc produces heat energy where exposure experienced by personnel can

cause survivors to suffer debilitating and horrific burn trauma or death.

Projectiles hazard – arc faults result in rapid increase of pressure inside equipment causing

the ejection of loose items or metallic particles.

Intense light – an arc flash event emits high intensity light which can damage the eyes.

Sound waves – an arc flash event may cause permanent hearing loss due to sound generated

from the explosion.

Respiratory trauma – hazardous toxic gases are produced from molten metals or burnt

insulation which are harmful if inhaled.

2.5 Arc flash reported incidents and statistics

The potential for electrical injuries due to arc flash is a serious workplace health and safety problem.

The Department of Mines and Petroleum in Western Australia recorded four arc flash incidents from

2013 - 2015 that can be found in the Department’s Safety Publications Library [9]. All incidents

resulted in irreparable damage to equipment and, fortunately, only resulted in minor injuries to

personnel. The author of this report is aware that the number of arc flash incidents is many times

more than what was reported to the Department of Mines and Petroleum, although normally these

incidents are not reported to the relevant authority, and hence not viewable from public records. On

the 3rd of February 2015, two electricians died due to an arc flash event in a mall in Perth [10]. The

electricians were conducting routine maintenance on a switchboard when the incident happened. The

incident is still under investigation but it is believed that it was caused by human error. This event

highlights that even though arc flash events are uncommon compared to other electrical faults, they

can be very costly and even lethal.

In the USA, a report published by the NFPA states that electrical burns from arc flashes are the cause

of many work-related burns treated at burns centres [11]. Research conducted at a Texas burn centre

over a 20-year period found that 40% of burns were caused by electrical arc injuries and the length

of hospital stay for treatment was 11.3 days [11]. In addition, data from the Bureau of Labor Statistics

10

shows that for a seven-year period starting in 1992, 2287 U.S. workers died and 32,807 workers

sustained lost time injuries because of electrical shock and burn injuries [12]. Of the 32,807 injuries,

38% were classified as electrical burns [12], which is the category that would include arc flash burns.

Furthermore, a research report by the National Institute for Occupational Safety and Health into arc

flash injuries in the mining industry noted that between 1990 and 2001, there were 836 arc flash

incidents on mine sites [13]. The majority of these incidents occurred during electrical work activities

including: installation (2%), maintenance (5%), repair and troubleshooting (42%), unspecified

electrical work (22%), during normal operation (19%) and unspecified cause (10%) [13]. Although

reported arc flash injuries are infrequent compared to other electrical injuries, the very high costs

associated with these injuries make them one of the most important categories of injuries in an

industrial workplace.

Extended hospitalisation and rehabilitation costs for personnel, coupled with litigation fees, fines,

investigation costs and increased insurance premiums, are often expensive. In addition, an arc flash

event can also cause irreparable damage to equipment which can lead to extensive downtime and

costly replacement and repair. The combined costs of the damage of one incident have been

estimated to potentially reach a total value of over USD 12 million [14]. As such, the potential

impacts highlight the importance of having mitigation strategies to reduce or eliminate arc flash

hazards.

2.5.1 Standards and WHS Requirements

Over the last decade, increasing attention has been placed on the arc flash hazards associated with

electrical switchboards. This has driven manufacturers to design and build safer switchboards that

specifically address arc flash risk. Electrical switchboards in Australia with a nominal supply current

of 800A or more shall be protected from arc faults while the equipment is in service or is undergoing

maintenance as per AS/NZS 3000:2007 [15].

11

The Fortescue specification for LV switchboards 100-SP-EL-0001 is currently being revised and

will outline arc fault protection for LV switchboards that have nominal current of 400A and above,

which is in conformity with the enhanced PPE recommended for such switchboards as per AS/NZS

4836 [16] [17] [18]. For HV switchboards, the Fortescue specification 100-SP-EL-0016 states that

HV switchboards must have an arc fault containment rating, which is now becoming an industry

standard worldwide [19].

2.5.1.1 Internal Arc Fault Containment

Fortescue switchboards have Internal Arc Classification (IAC) certification, as specified in Section

8.3 and Annex A of AS/NZS 62271.200 – 2005, which is an adaptation of IEC 62271.200 modified

for Australian conditions. The arc fault containment is intended to offer a tested level of protection

in the event of internal arc fault for personnel in the vicinity of switchgear with rated voltage from

1kV up to and including 52kV [20]. Likewise, AS/NZS 3439.1:2002 provides guidelines for Internal

Arc Fault Containment testing with the intention of protecting personnel standing in front of an LV

switchboard from an internal arcing fault [21].

The IAC testing is subject to agreement between the switchboard manufacturer and the customer.

There are two types of test performed for IAC certification: the “special” test and the “standard” test.

The “special” test is conducted if additional security is required. For this test, arc faults are simulated

in different locations within a switchboard where it is possible for an arc fault to occur [22]. Due to

the additional cost of testing, when IAC certification is requested, the test that is normally conducted

is a “standard” test only. When conducting a “standard” test, the arc is initiated on the outgoing

terminal of the feeder, which is normally cleared instantaneously, and hence the arc flash energy is

reduced [22]. However, faults in other locations within a switchboard are possible. Nonetheless, the

probability of these faults is low, therefore IAC testing for faults at these locations is not generally

required [21]. Figure 3 shows locations within a switchboard where the initiation of an arc fault is

possible.

12

Figure 3: Locations within a switchboard where arc faults can occur: a) outgoing terminal of the feeder, b) feeder, c)

distribution bus, d) main busbar and e) incomer or incoming cable termination. (Redrawn from [23])

If the arc fault occurs at locations other than the outgoing terminal of the feeder, the first upstream

protection device will clear the arc fault. For example, if the fault is at the feeder or at the main

busbar, the first upstream protection device is the incomer. If the fault is at the incomer, the clearing

device is the feeder from the first upstream switchboard (upstream protection device), which is

normally located in another switchroom. Due to protection grading requirements, these protection

devices normally have longer operating times than the incomer protection device. As a result of

longer operating times, the arc flash energy is higher, and the switchboard arc fault containment

certified using the “standard” test might not be able to withstand the energy released under this

scenario.

Support from IAC test reports are needed before personnel can conduct normal operating duties

while the equipment is energised (with all panel doors closed) without requiring an arc flash PPE. In

order to verify that the whole switchboard is capable of withstanding internal arc faults, the test

13

report must specify that the test was conducted for all compartments within the switchboard, rather

than just on the outgoing terminal of the feeder.

The Fortescue’s records do not clearly show if switchboards installed in the Solomon Hub were IAC

certified using the “standard” test or the “special” test. It was known that all HV switchboards and

some LV switchboards have an IAC, however, without the certification to confirm this, personnel’s

safety could not be guaranteed when working on energised switchboards (with all panel doors

closed).

In addition, it is important to realise that even if the switchboards have been IAC tested, this can

only provide protection if covers and doors are closed and properly fixed in place. When the door or

cover of an arc resistant switchboard is open, the arc resistant properties of the equipment are

nullified. Hence, protection cannot be guaranteed if personnel are conducting normal operating

duties or maintenance work while doors are open. Hence, it is necessary that arc resistant

switchboards shall be included in the arc flash study.

2.6 Arc Flash Studies

An arc flash study is used to quantify the arc flash hazard by calculating the arc flash energy. An arc

flash study is considered a continuation of short-circuit and coordination studies because the results

of each of these studies are required for the arc flash hazard analysis. The arc flash hazard assessment

is used to identify and implement controls to reduce the likelihood and severity of an arc flash

accident. After conducting an arc flash assessment, the calculated energy will determine the required

PPE for personnel working on or near electrical equipment. In addition, the result of the assessment

can be used to establish the limits of approach to energised electrical equipment, identify hazard

management, and identify mitigation actions. When performing an arc flash hazard assessment, a

good knowledge of the electrical network in a facility and the electrical protection system is required.

14

Globally, two North American standards have dominated arc flash hazard assessment [24]: The

NFPA 70E, Standard for Electrical Safety in the Workplace; and the IEEE Std 1584-2002, IEEE

Guide for Performing Arc Flash Hazard Calculations. Prior to the Australian Standard, ENA NENS

09 – 2014 [25] for arc hazard quantification coming into place in 2014, and even currently, the USA

standards IEEE 1584 and NFPA 70E were widely adopted by the Australian Engineering

Community.

2.6.1 NFPA 70E

The National Fire Protection Association (NFPA) 70E standard [26] provides guidelines for

electrical safety in the workplace and selection of arc flash PPE. NFPA 70E is a safety standard that

describes work practices that can help protect electrical personnel from electrical hazards including

electrocution, electric shock, arc blast and arc flash. Section 130 of the NFPA 70E provides task and

equipment based tables that can be used in determining arc flash PPE requirements, hence known as

the “table” method. These tables give pre-defined levels of PPE based on the tasks that are to be

performed, the magnitude of the fault current and the associated clearing time of the protection

device. The “table” method takes a three-step approach:

1. Conduct a risk assessment to determine if the condition of the equipment and the task

that is to be performed warrants the used of arc flash PPE. If PPE is not required, no

further action is necessary, otherwise, proceed to step 2.

2. Determine the working distance and calculate the magnitude of the prospective fault

current and the associated clearing time of the protection device.

3. Determine the arc flash PPE category requirement for the task specified in step 1.

The arc flash energy depends on complex relationships between system voltage, bolted and arcing

fault current, arc impedance, clearing time of protection devices, conductor spacing, confinement in

an enclosure, and system grounding [27]. Some of these variables are not considered in the selection

of arc flash PPE based on the “table” method outlined in the NFPA 70E standard. For this reason,

15

the “table” method is of limited practical use and this could explain why there is a general preference

for using the other method outlined in the IEEE Std 1584 - 2002.

2.6.2 IEEE Std 1584 – 2002

The IEEE Std 1584 – 2002: IEEE Guide for Performing Arc-Flash Hazard Calculations, outlines the

methodology, including providing relevant equations, to determine the arc flash boundary and the

incident energy to which employees could be exposed during their work on or near electrical

equipment [28]. The arc flash boundary is the distance from the arc source where personnel are

exposed to 1.2 cal/cm2 of energy that can lead to a second degree burn [29]. Personnel not wearing

arc flash PPE must not go within the arc flash boundary to avoid exposure to high levels of arc flash

energy. The incident energy is the amount of energy that can reach a person’s face or torso standing

at a specific distance relative to the origin of the arc [30]. The incident energy calculation is not

based on exposure on the hands or arms which will be closer to the arc source if conducting energised

work, because injury to these areas is less life threatening. The equations within the IEEE 1584

standard was developed from statistical analyses using data from a large number of laboratory tests

conducted by the IEEE 1584 working group. Table 2 shows the parameter range for electrical

systems where the empirically derived equations are valid [30]. For equipment with voltage levels

above 15kV, equations based on a theoretical model developed by Ralph Lee [7], which are included

in the IEEE 1584 standard, can be applied.

Table 2: Limitations of equations from IEEE 1584

Parameter Applicable Range

System voltage 0.208kV – 15kV

Frequency 50/60 Hz

Bolted fault current 0.7kA – 106kA

Gap between electrodes 13 – 152 mm

Equipment enclosure type Open air, box, MCC, panel, switchgear and cables

Grounding type All types of grounding and ungrounded

Faults Three phase

The IEEE 1584 standard does not consider the risk of an arc flash occurring nor the effect of arc

fault containment. Instead, the standard is limited to the hazard posed by thermal energy, and the

effects of molten metals, projectiles and toxic by-products are not considered. Nonetheless, industrial

16

companies still have an obligation to complete Arc Flash Hazard assessment to mitigate arc flash

hazards. IEEE 1584 is based on the most comprehensive laboratory experiments and calculations

available; therefore, where arc flash hazard quantification is needed, the IEEE 1584 is generally

used.

2.7 Assumptions and Clarifications

The random nature of arcs makes them very difficult to model precisely. The equations in

the IEEE 1584 standard that are used for the analyses are developed based on average values.

Parameters used are selected to achieve what are considered to be the worst case results.

Calculations are based on three-phase faults.

The inrush currents of transformers are assumed to equal 12 times the transformer rating.

The inrush current of DOL motors are assumed to equal 6 times the motor rating.

Other assumptions are stated in the relevant sections where these assumptions are implemented.

2.8 PowerFactory

The software that was used for all the simulations is DIgSILENT PowerFactory. PowerFactory is an

engineering tool used for the analysis of electrical transmission and distribution systems. The

software was developed by programmers and engineers with extensive experience in computer

programming and electrical systems analysis [31]. The equations used and the results of the

simulations have been confirmed in a large number of implementations of power systems throughout

the world.

17

3 Methodology

3.1 System audit, data collection and power system modelling

A system audit was conducted to determine the state of the power network electrical model. During

the system audit, the network model was compared to the latest single line diagrams (SLDs). The

model was found to require a significant amount of work to bring it to a state where it would

accurately represent the complete Solomon Hub power network. It was found that many equipment

parameters used in the PowerFactory model were incorrect. In order to provide accurate incident

energy calculations, the network model needs to be as accurate as possible. Some parameters, like

the cable impedances, can have a significant effect on the fault levels. However, it was found that

many cables were not modelled, and some had incorrect lengths entered, which resulted in incorrect

impedance values. Moreover, some transformers were modelled using typical impedance values

instead of actual nameplate impedance values. Whilst impedance values may differ only slightly, a

small variation of available fault current may significantly affect the calculated magnitude of the

incident energy for a switchboard [32]. As a result, it was necessary to obtain accurate and complete

data pertaining to the cable and transformer specifications. Those data were then used to update the

PowerFactory model. This task identified an unexpected number of existing errors, and therefore

was time-consuming, taking approximately one month of full time investigation by the intern.

Another problem encountered during the project was that many electrical loads and switchboards

that are included in the present arc flash study had not previously been modelled into the simulation

software. Hence, the respective SLDs for these types of equipment were obtained and used to update

the model in the simulation software. The switchboards were modelled using “busbar” blocks while

all the loads were modelled using “general load” blocks in the PowerFactory software. There are

numerous electrical loads connected at each switchboard, however, they were modelled as a single

load. This is because modelling each load separately will give no additional information about the

power network compared with modelling a single composite load [33]. The power ratings of the

loads were taken from the Solomon electrical load list 224632-SL-2000-LL-EL-0002 [34] and the

18

load factors were assumed to equal 100% of the rated capacity. The load factor will not affect the

fault simulations; but in load flow simulations, it will result in maximum current demand, which is

considered to be the worst-case scenario.

Finally, it was found that all LV circuit breakers were not modelled into the simulation software and

the protection settings were not available. The protection devices need to be modelled in the software

so that a Time-Current Curve (TCC) can be generated, which will be used to determine the operating

time of these devices when a fault is simulated. As a result, the intern travelled to Solomon hub to

obtain the settings of the LV circuit breakers, which can be found in Appendix B. Most of the

protection settings were collected except for the settings of a few protection devices that were not

accessible or were not operational during the visit. Consequently, site personnel at Solomon Hub

were requested to gather the remaining protection settings after they became operational.

One more methodological problem encountered in the project is that, unfortunately, even though

most of the required protection settings were obtained, the LV circuit breakers cannot be modelled

into PowerFactory software because Fortescue did not have this included in the PowerFactory

protection devices library. As a result, all the operating times calculations for all LV circuit breakers

were performed manually.

3.2 Short-Circuit Study

Short-circuit simulations were conducted to determine the fault levels at each switchboard. It was

assumed that any unbalanced arc fault will immediately escalate to three-phase faults because air is

ionized around the conductors [30]. Hence, only faults involving three phases were simulated. The

fault currents that flow as a result of three-phase short-circuit faults at each switchboard were

determined using the “complete” method. With this method, fault currents are determined by

superimposing a healthy load-flow condition before the fault initiation, resulting in more realistic

and more accurate fault calculations [31].

19

Unlike in protection studies where the maximum fault current is assumed to provide worst-case

conditions, for an arc flash study, the worst-case short-circuit current assumptions do not always

produce the most severe arc flash incident energy results, as will be explained in the next section.

For simple radial systems similar to the Solomon hub’s electrical network, IEEE 1584 suggested that

two sets of calculations are required [30]. The first calculation is for the minimum short-circuit

current conditions and the second is for maximum short-circuit current conditions.

Both the maximum and minimum short-circuit conditions should be evaluated to determine the effect

on the protective device clearing times and the incident energy exposures. The variations between

the results of these two calculations can have a significant effect on the accuracy of the evaluations

for the arc flash hazard and the PPE requirements for each switchboard. There are different operating

modes that can significantly change the fault levels at the switchboards, which were identified. The

first operating mode was the basis of the maximum short-circuit calculations and included motor

contributions, while the second and third operating modes were the basis of the minimum short-

circuit calculations and excluded motor contributions. The operating modes were:

1. One LM6000 generator and all MPUs are in service (126MVA of generation) for maximum

fault simulations.

2. One LM6000 generator and one MPU are in service (79MVA of generation) for Stockyard

and RMU10 minimum fault simulations.

3. Three MPUs are in service (47MVA of generation) for minimum fault simulations for the

OPFs.

3.2.1 Effect of motor contributions in the calculations

Another variable that can affect the fault levels are current contributions from induction motors.

When a fault occurs, induction motors momentarily contribute current to the fault. The Solomon

Hub’s electrical system includes many induction motors, although around half of the major induction

20

motors are driven by variable speed drives (VSDs). A VSD effectively separates the motors from

the rest of the system, and hence a VSD-driven motor does not contribute to the fault current. The

fault contribution from a single motor is not significant, however, the individual contributions adds

up, which can result in a significant increase in the fault level. Unlike the contribution from the

generators, contributions from motors decay rapidly and may not be present for the whole duration

of an arc flash event [35].

Neither IEEE 1584 nor NFPA 70E provides guidance on how to calculate motor contributions,

however, PowerFactory can calculate motor contributions and include them in fault simulations. For

minimum fault simulations, it was assumed that there are no contributions from the motors, whereas,

for the maximum fault simulations, PowerFactory was set to include contributions from motors, to

obtain the highest fault current magnitude. When calculating the clearing time of protection devices

manually (as was the case for the LV circuit breakers), it is important that contributions from motors

downstream of the faulted bus are excluded because these currents are not passing through the

incoming and upstream protection devices that are used to interrupt the fault current.

To illustrate this, Figure 4 shows a PowerFactory fault simulation analysis where a fault was

introduced in Switchboard 2. It can be seen that Motor M2 is located downstream of Switchboard 2

and contributed 5kA to the fault. The rest of the network, including other motors, supplied a total of

31.835kA of current to the fault. Motor M2’s contribution does not flow through the incomer and

the upstream protection device. Consequently, this can have a significant effect on the incident

energy calculation because it will affect the clearing time of the protection devices. The importance

of using a correct value for the fault magnitude in clearing time calculations is further explained in

Sections 3.3 and 3.4.

21

Figure 4: Fault simulation showing motor contributions

3.3 Arc current calculations

The bolted fault currents found in the short-circuit study were used to calculate the arcing current

using either equation (1) or equation (2), depending on the voltage level.

For switchboards with a voltage under 1000V [29, p.10]:

𝐼𝑎 = 10K+0.662(𝑙𝑔𝐼𝑏𝑓)+0.0966V+0.000526G+0.5588V(𝑙𝑔𝐼𝑏𝑓)−0.00304G(𝑙𝑔𝐼𝑏𝑓) (1)

For switchboards with a voltage of 1000V or higher [29, p.10]:

𝐼𝑎 = 100.00402+0.983(𝑙𝑔𝐼𝑏𝑓) (2)

where

𝐼𝑎 is the arcing current (kA)

K is a constant which has a value of -.097

𝑙𝑔 is the log10 function

𝐼𝑏𝑓 is the bolted fault current (kA)

G is the gap between conductors seen in Table 3 (mm)

V is the system voltage (kV)

22

Table 3: Distance factors and typical conductor gaps used for the arc flash calculations [30]

Voltage (kV) Typical conductor gaps x (distance factor)

0.208 - 1 32 1.473

>1 - 5 13-102 0.973

>5 - 15 153 0.973

The minimum arc current values were further reduced by 15% as recommended in Section 9.10.4 of

IEEE 1584. This was done because it is very difficult to accurately predict the arcing current and a

small change in current could result in a significant change in clearing time. To illustrate this, the

time current curve (TCC) of a protection relay protecting a 33kV switchboard is shown in Figure 5.

Notice the change in relay clearing time when transitioning from the “definite-time” region of the

TCC to the “inverse” region of the TCC. As illustrated in Figure 5, when the arc fault current is

reduced by 10%, the clearing time is increased from 0.02 s to 0.5 s, which resulted in a significant

increase in incident energy.

Figure 5: TCC illustrating the significant increase in incident energy for a 10% arc current reduction

23

3.4 Coordination studies

The objective of coordination studies is to ensure that protection devices are properly designed and

coordinated [36]. Coordination studies are used to determine the operating time of protection devices

and to ensure that these devices will detect faults and isolate the faulted part of the system without

compromising reliability. Conventionally, coordination studies were targeted at reliability, with all

protection settings adjusted towards clearing bolted faults. However, as there are new arc flash safety

requirements, this means that from now on all coordination studies (including the present study) used

to determine the appropriate settings for the protection devices must not only clear bolted faults but

they must also clear arc faults.

The operating times of protection devices were determined based on the minimum and maximum

arc current values calculated using the equations presented in Section 3.3. The accuracy of the

operating time is important because this is the most dominant factor influencing incident energy [37].

For each switchboard, out of two calculations, the arc fault current magnitude that resulted in

protection device operating time that led to worst-case scenario was used. For switchboards that are

protected by a fuse, the minimum arcing fault currents are the basis of the worst-case calculations

for the incident energy [38]. For switchboards that are protected by circuit breakers or protection

relays, the worst-case calculations vary according to the regions of the TCC. If the arc fault current

magnitude falls completely within any region of the TCC where the time remains constant, the

maximum arc fault current will result in the calculation of the worst-case incident energy. However,

if the arc fault current falls within the “inverse” region of the TCC, depending on the steepness of

the curve, the lower arcing fault values can sometimes result in the worst-case scenario calculations,

because it will correspond to longer clearing times (illustrated in Figure 6). Incident energy is a

function of several parameters including the arc current and the clearing time of the protection

device, where a lower fault current can sometimes be counteracted by an associated increase in fault

clearing time, thereby leading to higher incident energy. Therefore, in order to determine the worst-

case incident energy for instances when the arc current value falls within the “inverse” region of the

24

TCC, two calculations were conducted. The first calculation used the maximum arc current value

and the associated clearing time of the protection device while the second calculation used the

minimum arc current value and the associated clearing time of the protection device.

Figure 6: TCC illustrating the effect of the clearing characteristics of a protection relay on the incident energy

Note that the opening times of the circuit breakers were added to the operating time of protection

devices. The opening time has a value range of 0.03 s – 0.06 s depending on the type and model of

the circuit breaker.

3.5 Incident energy and arc flash boundary calculations

After the coordination study, arc flash boundary and incident energy calculations were performed

using equations from IEEE 1584. Incident energy is the amount of energy that can reach a person’s

face or torso if an arc flash occurs. The incident energy was calculated using equation 3 and equation

4 for switchboards that have a voltage of less than 15kV [29, p.11].

25

𝐸𝑛 = 10𝐾1 + 𝐾2 + 1.081𝑙𝑔𝑙𝑎 +0.0022G (3)

where

𝐸𝑛 is the incident energy (J/cm2) normalised for time and distance

𝐾1 is a constant that has a value of -0.555 for switchboard incident energy calculations

𝐾2 is a constant that has a value of -0.113 if the system is solidly grounded, otherwise it has a

value of 0

𝐸 = 4.184𝐶𝑓𝐸𝑛 (𝑡

0.2) (

610𝑥

𝐷𝑥 ) (4)

where

𝐸 is the incident energy (J/cm2)

𝐶𝑓 is a calculation factor that has a value of 1.5 for a switchboard that has a voltage level of

1kV and below, otherwise, it has a value of 1

𝑡 is arcing time (seconds)

𝐷 is a person’s distance relative to the origin of the arc (mm)

𝑥 is a distance exponent from Table 3

For switchboards where the voltage level is 15kV or above, the theoretically derived equation by

Ralph Lee was used [29, p.12]:

𝐸 = 2.142 𝑥 106𝑉𝐼𝑏𝑓(𝑡

𝐷2) (5)

The possible working distances for the switchboards were determined from the equipment manuals

by inspecting the switchboard dimensions. However, these distances will vary depending on the task

that is being performed. To cater for worst-case scenario, the working distance for the LV

switchboards was assumed to be equal to 610 mm while the working distance for HV switchboards

was assumed to be equal to 910 mm. The assumptions were based on the advice of the supervising

electrical engineer at Fortescue who has a good knowledge of switchboard construction.

26

In addition, the arc flash boundary, which is the distance from the arc source at which a person can

receive a second degree burn, was calculated. Any person crossing the arc flash boundary is required

to wear the appropriate arc flash PPE. If the switchboard has a voltage of less than 15kV, equation 6

is used; otherwise, equation 7 is used [29, p.12].

𝐷𝐵 = [4.184𝐶𝑓𝐸𝑛 (𝑡

0.2) (

610𝑥

𝐸𝐵)]

1

𝑥 (6)

𝐷𝐵 = √2.142𝑥106𝑉𝐼𝑏𝑓 (𝑡

𝐸𝐵) (7)

where 𝐷𝐵 is the incident energy (J/cm2) and x the distance exponent from Table 3.

3.6 PPE selection

The required PPE if personnel are exposed to arc hazards is shown in Table 4. The PPE category

was chosen based on the magnitude of the incident energy which was calculated in the previous step.

This is the minimum level of PPE recommended from NFPA 70E standard with the intent to protect

personnel from the thermal effects of the arc flash at working distance.

Table 4: PPE requirements based on incident energy exposure [26]

Min Incident

Energy (cal/cm2)

Max Incident Energy

(cal/cm2) PPE Category

Required PPE Rating

(cal/cm2)

0 1.2 0

1.21 4 1 4

4.1 8 2 8

8.1 25 3 25

25.1 40 4 40

40.1 And above X Specialised PPE

required

27

3.7 Process flowchart

The arc flash studies performed for this project were made up of several tasks that were explained in

the previous sections. The aim of the studies is not just to quantify the arc flash hazards and

recommend PPE, but also to find solutions to mitigate the hazard. Figure 7 shows the process flow

chart illustrating the steps conducted to achieve the goals of the arc flash studies.

Figure 7: Flow chart which illustrate the steps conducted to achieve the goals of the arc flash studies

28

4 Results

Switchboards were evaluated to determine if either the incomer or the upstream protection device

should be used for the calculation of the incident energy. In this study, it was assumed that an arc

fault can occur at the load side of the incomer or at the incomer itself. An incoming protection device

can only detect faults at its load side, which is normally in a separate compartment. If this happens,

the incomer will clear the fault, and hence its operating time will be used for the incident energy

calculations. If the fault is at the incoming protection device itself, then the upstream protection

device will provide the protection. The identification of the correct protection device is very

important because the clearing times will vary, depending on which device trips. The arc flash studies

results were categorised based on the location of the fault within switchboards.

4.1 Stockyard

The summary of the arc flash study results for switchboards installed in the Stockyard area is shown

in Table 5. The complete arc flash study results for the Stockyard area can be found in Appendix C.

These results are based on the existing settings of the protection devices. As previously mentioned,

two incident energy calculations were conducted for each switchboard: one is when the fault is at

the load side of the incomer (a “switchboard”) and another is when the fault is at the incomer itself

where the upstream protection device will clear the fault. An arc fault at the incomer can occur when

personnel are switching or racking the incoming protection device. It can be seen that some

switchboards have very high arc flash incident energy that is well above the desired limit of 8

cal/cm2.

Table 5: Arc flash study results for switchboards installed at the Stockyard

Equipment Clearing Device

Location

Maximum

Arc Current (kA)

0.85 x

Minimum

Arc Current (kA)

Total

Clearing Time (s)

Incident

Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash

Boundary (mm)

0.4kV Incomer

Upstream 8.03-13.89 6.81-11.58 0.75- 2.28 14.66-55.72 3336-8259

0.4kV Switchboards

Incomer 8.03-13.89 6.81-11.58 0.06-0.43 1.00-12.92 538-3061

11kV

Incomer Upstream 5.37-18.49 3.75-9.21 0.42-0.67 3.59-8.40 2809-6725

11kV Switchboards

Incomer/Upstream 5.37-18.49 3.75-9.21 0.08-0.67 1.58-21.82 1204-17934

29

The incomers possess the greatest arc flash hazard, with SUB-801-SWB01 incomer CB and

SUB901-MCC01 incomer CB having 54.93 cal/cm2 and 55.72 cal/cm2 potential incident energy,

respectively (see Appendix C). These energy levels are higher than the withstand rating of PPE’s

available at the Stockyard area and, therefore, a mitigation strategy must be implemented as soon as

possible.

4.2 Firetail

The results of the arc flash study for switchboards installed at Firetail OPF are summarised in Table

6. The complete arc flash study results for the Stockyard area can be found in Appendix D. It can

be seen that all 6.6kV switchboards have a calculated incident energy of less than 8 cal/cm2, which

is the ideal result. However, people working in 0.4kV and 33kV switchboards are exposed to very

high arc flash incident energy. For the 0.4kV switchboards, it can be seen that the highest potential

incident energy exposure is 43.82 cal/cm2 if an arc fault occurs at SR102-MCC01 incomer. In

addition, it can be seen that the incident energy of 33kV switchboards are well above the desired

limit of 8 cal/cm2.

Table 6: Arc flash study results for switchboards installed at Firetail OPF

Moreover, Table 6 shows that the feeder from Substation 2 will clear faults in all 33kV switchboards.

The incomer and the upstream protection devices for the 33kV switchboards will detect the fault but

the feeder from Substation 2 will operate first. The protection devices do not have the correct

coordination, and hence a three-phase fault in any of the 33kV switchboards installed at Firetail OPF

Equipment

Clearing

Device

Location

Maximum

Arc Current

(kA)

0.85 x Minimum

Arc Current

(kA)

Total

Clearing

Time (s)

Incident

Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash

Boundary

(mm)

0.4kV Incomer Upstream 16.38-18.04 13.24-13.28 1.07-1.10 38.43-43.82 6418-7016

0.4kV

Switchboards Incomer 16.38-18.04 13.24-13.28 1.25 37.62-41.77 6326-6791


6.6kV

Switchboards Incomer 3.90-5.26 2.93-3.02 0.41-0.42 2.54-4.93 1967-3888

33kV Incomer

/Switchboards

Substation 2

Feeder to

Firetail OPF

4.52-4.59 2.06-2.10 0.39-0.41 35.41-37.58 4944-5086

30

has the potential to result in unnecessary power outages in Firetail OPF. The latter problem will be

considered when recommending the proposed solutions.

4.3 Kings Valley

The results of the arc flash studies for switchboards installed in Kings Valley OPF is summarised in

Table 7. The complete arc flash study results for Kings Valley OPF can be found in Appendix E.

The incident energy of 6.6kV switchboards remain below the desired limit of 8 cal/cm2. However,

the 0.4kV switchboards remain a serious risk, many 0.4kV switchboards have an incident energy

greater than 40 cal/cm2 where there is no available PPE to protect personnel. As such, energised

maintenance work at these switchboards should not be allowed unless steps to mitigate the risk are

taken. This is especially the case for switchboards 2500-SR509-MCC02 where the potential incident

energy is 92.27 cal/cm2.

A further finding is that the incident energy of all 33kV switchboards are below the maximum

incident energy limit of 8 cal/cm2. However, the 33kV protection system has no fault grading from

Substation 3 feeders. Substation 3 feeders to Kings Valley OPF will trip instantaneously for a fault

in any of the 33kV switchboards installed at Kings Valley OPF, including faults at the HV terminal

of the transformers. As a consequence, power will be unnecessarily taken out at the Kings Valley

OPF if a three-phase fault occurs in the 33kV system. This problem will be considered when

recommending the proposed solutions.

Table 7: Arc flash study results for switchboards installed at Kings Valley OPF

Equipment

Clearing

Device Location

Maximum

Arc Current (kA)

0.85 x

Minimum Arc Current

(kA)

Total

Clearing Time (s)

Incident

Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash

Boundary (mm)


0.4kV Switchboards

Incomer 14.98-18.39 12.30-13.40 0.45-3.00 13.17-92.27 3102-11631

6.6kV Incomer Upstream 3.96-5.36 3.00-3.02 0.66 4.07-5.66 3195-4480

6.6kV

Switchboards Incomer 3.96-5.36 3.00-3.02 0.42-0.84 2.57-6.67 1990-5302

33kV Incomer CBs/Switchboards

Substation 3

Feeder to Kings

Valley OPF

4.68-4.86 2.01-2.05 0.08 7.64-7.87 2296-2330

31

4.4 RMUs + other attached switchboards

The results of the arc flash study for the RMUs and other switchboards that are fed from the RMUs

are summarised in Table 8. The complete arc flash studies result for these switchboards can be found

in Appendix F. The 0.4kV switchboards’ arc flash incident energy levels are dangerously high. In

particular, the SR701-MCC01 switchboard has a calculated incident energy of 116.54 cal/cm2 and

there is no commercially available PPE that can withstand this energy exposure. Hence, energised

work on this switchboard should not be allowed until mitigating steps have been taken.

The calculated incident energy for the 6.6kV switchboards remain below 8 cal/cm2. This is also the

case for most tasks on the 0.69kV switchboard. However, it is not the case when personnel are

switching or racking the 0.69kV switchboard incomers where personnel are exposed to high incident

energy levels reaching 52.08 cal/cm2 for the CV763-VSD02 switchboard incomer. Moreover, it can

be seen that the arc flash incident energy of the 33kV switchboards are below 8 cal/cm2, which is

desirable. However, these results are based on the existing settings of the protection devices which

do not have correct coordination. The protection settings of these devices will be adjusted to ensure

the reliability of the protection system. However, as a consequence of changing these settings, the

arc flash incident energy at these switchboards will increase. The proposed protection settings to

ensure selectivity and for reduced arc flash incident energy are discussed in Section 7 of this report.

Table 8: Arc flash study results for RMUs and loads fed from the RMUs

Equipment

Clearing

Device Location

Maximum

Arc Current (kA)

0.85 x

Minimum Arc Current

(kA)

Total

Clearing Time (s)

Incident

Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash

Boundary (mm)


0.4kV Switchboards

Incomer 7.26-19.04 6.12-15.33 0.09-6.5 3.13-116.54 1168-13629


0.69kV



6.6kV


33kV Incomer

/Switchboards

Substations

1 and 2 4.36-4.86 2.01-2.09 0.08 7.11-7.93 2216-2340

32

5 Discussion

From the results of the arc flash studies, it is evident that many switchboards have unacceptably high

incident energy values that need to be improved. Contrary to what was believed by many electrical

personnel, the arc flash hazard posed by LV switchboards has been found to actually be more

significant than the arc flash hazard posed by HV switchboards. This is due to the higher available

fault current for LV systems. When the voltage is stepped down by a transformer, the current is

increased. Electrical personnel interact with LV switchboards more often than HV switchboards.

Therefore, statistically, the risk of having an arc flash incident in LV switchboards is actually higher.

In addition, normally, coordination studies are performed to select the appropriate settings of

protection devices to clear bolted faults. However, for LV systems, the magnitude of the arc current

is much lower than the bolted fault current and therefore, a protection device might take longer to

clear the arc fault or maybe it will not detect it at all. To illustrate this further, a numerical calculation

is shown below to calculate the incident energy of switchboard 2500-SR509-MCC02 installed at

Kings Valley, using the arc current values that were found to result in the worst-case incident energy.

Figure 8 shows the single line diagram that depicts the fault and shows the clearing devices.

Figure 8: Fault simulation showing the faulted switchboard

33

For the protection of the incomer protection device, the maximum arc current of 16.71kA was used

because it would result in worst-case incident energy:

𝐼𝑎/𝐻𝑉 = 16710 𝑥 0.417

33= 211𝐴 (7)

Where 𝐼𝑎/𝐻𝑉 is the arc current referred to the HV side of the transformer. Using the protection

settings of the upstream protection device, the operating time of the upstream protection device was

calculated using Equation 8 [38, p.108]. The protection device’s 50P element with pickup setting of

700A would not detect the arc fault current of 211 A, hence, the 51P element was used in order to

calculate the result for the hypothetical worst-case incident energy level. The protection device has

a time dial (TD) setting of 0.21, pickup setting of 50 A and the curve type was set to C1.

𝑡𝑝 = 𝑇𝐷 (0.14

(𝐼𝑎/𝐻𝑉

𝐼𝑝𝑢)

0.02

−1

) (8)

𝑡𝑝 = 0.21 (0.14

(211

50)

0.02−1

) = 1.01 𝑠

𝑡𝑡𝑜𝑡𝑎𝑙 = 𝑡𝑝 + 𝑡𝑜 (9)

𝑡𝑡𝑜𝑡𝑎𝑙 = 1.01 + 0.05 = 1.06 𝑠

where

TD is the time dial setting of the protection relay

𝐼𝑝𝑢 is the pickup setting of the protection relay

𝑡𝑝 is the operating time of the protection device

𝑡𝑜 opening time of the circuit breaker

𝑡𝑡𝑜𝑡𝑎𝑙 is the total clearing time of the protection device

Then, using equation 3 and 4, the incident energy was calculated to be equal to 38.86 𝑐𝑎𝑙

𝑐𝑚2.

34

For the protection of the remaining sections of the switchboard, the incomer, which is an LV circuit

breaker, would clear the fault. Hence, the incomer’s operating time was used for the calculation

which can be found in Appendix B. The minimum arc current of 13.25kA was used in order to

calculate the result for the hypothetical worst-case incident energy level. The protection device’s

short-time and instantaneous time elements have pickup settings of 21.6kA and 26.4kA respectively

which are above the arc current of 13.25kA. Hence, these elements will not detect the fault and

therefore, the long-time element was used for the incident energy calculations. The protection device

has a pickup setting of 2400 and the curve type was set to C-04. The total clearing time of the device

can be approximated from the curve shown in Appendix G, but first, it must be scaled [39]:

𝑆𝑐𝑎𝑙𝑖𝑛𝑔 = 𝐼𝑎,𝐿𝑉

𝐼𝑝𝑢 (10)

𝑆𝑐𝑎𝑙𝑖𝑛𝑔 = 13250

2400= 5.5

Where 𝐼𝑎,𝐿𝑉 is the arc current in the LV side of the transformer. Approximating from the curve, 5.5

equates to 3 seconds total clearing time as seen from the curve in Appendix G. Then, using equation

3 and 4, the incident energy was calculated to be equal to 92.27 𝑐𝑎𝑙

𝑐𝑚2.

When considering the results of the above calculations, it is evident that the arc flash incident energy

levels are very high. This is because the protection devices were set without consideration for arc

faults. The value of the arc current is a lot lower compared to the bolted fault current in LV systems.

And in this instance, the magnitude of the arc fault falls within the “inverse” region of the TCCs of

the devices, which in turn has led to longer operating times and higher incident energy.

On the other hand, all 6.6kV switchboards were found to have very low arc flash incident energy

levels with potential incident energy exposure not exceeding 8 cal/cm2. Therefore, the existing PPEs

that are currently used in Solomon Hub which are rated at 12 cal/cm2 are appropriate for continued

usage.

35

In addition, the 0.69kV switchboards were found to have low arc flash incident energy levels with

potential incident exposure not exceeding 8 cal/cm2, except when the arc fault occurs at the incomer

where personnel are exposed to incident energy of up to 52.08 cal/cm2, and therefore energised work

should not be conducted until mitigating procedures have taken place.

Currently, most of the 33kV switchboards have manageable arc hazard levels with arc flash incident

energy having been found to be less than 8 cal/cm2. An exception was the 33kV switchboards

installed at Firetail where the incident energy levels were found to be 23.37 cal/cm2 – 37.58 cal/cm2.

Although the arc flash hazard levels for switchboards other than those installed at Firetail were at

safe levels, the 33kV system has no grading from protection devices installed at Substation 2 and

Substation 3. A three-phase fault anywhere in the 33kV system will result in unnecessary power

outage to other healthy equipment. For example, if there is a fault at the HV terminal of a transformer

in Kings Valley OPF, the protection device installed at Substation 3 will clear the fault which will

result in unnecessary power outages to other equipment operating at Kings Valley. It will be

recommended that the protection settings of these devices be adjusted to ensure the reliability of the

protection system. However, as a consequence of changing these settings, the arc flash incident

energy levels at these switchboards will increase. This is a major problem that needs to be resolved

and this will be considered when recommending solutions for the arc flash studies.

It would seem then that using arc flash studies solely as a means to determine the required PPE

requirements is not the most effective control method for minimizing potential danger to personnel.

Engineers must conduct risk assessments and identify possible risk mitigation strategies by

identifying which controls are feasible for mitigation of arc flash hazards. A hierarchy of controls is

a system used in the industry to help prevent or reduce hazards [40]. Numerous safety organizations

have promoted this method and it is widely accepted in the industry. As depicted by the triangle in

Figure 9, the methods considered to be least effective are at the bottom whilst the methods considered

the most effective are at the top:

36

Figure 9: Hierarchy of controls (redrawn from [40])

A preferred approach is to use solutions higher in the pyramid, that is, elimination, substitution and

engineering; although these alternatives are not always feasible. The different controls to reduce the

arc flash hazard were investigated.

5.1 Elimination

Elimination is the most ideal control method to protect personnel from arc flash hazards. The

elimination of arc flash hazards can be achieved if electrical work is performed only while equipment

is not energised. However, it is not feasible to switch off equipment every time testing or

maintenance functions are performed. This is especially true for the switchboards installed at the

Solomon Hub as the cost of a few hours of de-energised work can result in millions of dollars of lost

revenues. Furthermore, if equipment de-energisation was to become the chosen option, it involves

circuit breaker switching, racking and isolation verification which would also have associated arc

flash hazards that would need to be controlled.

5.2 Substitution

Substituting equipment like switchboards and protection devices for faster arc fault clearing is

impractical. The cost associated with the procurement and installation of this type of equipment

makes this control method infeasible. As a result, this control method was not considered.

37

5.3 Engineering Controls

5.3.1 Optimise protection settings

It has been determined from engineering research that the arc time has a linear effect in the incident

energy [30], whereby reducing the protection device’s clearing time proportionately reduces arc flash

incident energy. Therefore, the most effective solution to mitigate the arc flash hazard is to reduce

the operating time of the protection devices to clear arc faults as rapidly as possible. Protection

settings must be chosen to ensure high levels of protection for equipment while still allowing normal

operating currents and inrush currents to flow without causing equipment to trip. In addition, grading

between protection devices must not be compromised, and therefore the protection device closest to

the fault must be the only one that trips so that service will only be interrupted to a minimal portion

of the power network. Proper coordination between protection devices will result in protection

devices closer to the power source having longer clearing times and higher pickup levels compared

to protection devices further downstream. This means that protection devices downstream can clear

faults faster than the upstream protection devices, thereby avoiding an unnecessary power outage to

a larger portion of the power network. Consequently, optimising protection settings may not always

be a feasible solution for arc flash mitigation due to protection grading requirements.

5.3.2 Installing a maintenance switch

An alternative and simple method for the reduction of incident energy is to install a maintenance

switch. A maintenance switch is an external switch that is wired into a protection device to allow

personnel to activate maintenance mode protection settings. A maintenance mode protection setting

is a pre-set setting which allows fast clearing of arc faults (in most cases, instantaneously) [41].

For protection relays, the 50P element is activated, and for LV circuit breakers, the instantaneous

element is used. Both elements are used to detect faults without unintentional delay. If the

maintenance mode is activated, the grading between the protection devices will be compromised.

However, the maintenance switch will only be engaged when personnel are working on a

switchboard, and it must be deactivated as soon as switching/maintenance work at the switchboard

38

is completed. Switching to maintenance mode can be included in permit conditions to ensure it is a

mandatory step.

5.3.3 Zone Selective Interlocking Scheme

The Zone Selective Interlocking (ZSI) scheme is a method recognised in the engineering field used

to speed up the operating time of protection devices without sacrificing protection devices

coordination and introducing nuisance tripping into the system [42]. This concept allows protection

devices to communicate across the distribution zones. The information is transmitted from the

feeders to the incomers through wires or using communication infrastructure like supervisory control

and data acquisition (SCADA).

The concept of ZSI is best explained in a visual format, as shown in Figure 10. If a fault occurs

downstream of feeder F3, where the magnitude of the fault exceeds the pick-up settings of both

feeder F3 and the incomer, both protection devices will detect the fault. However, feeder F3 will

send a restraint signal to the incomer which will activate the pre-set time delay for the incomer’s

operating time allowing feeder F3 to clear the fault. The ZSI scheme allows the incomer to clear the

fault with little intentional delay. The incomer cannot be set to trip instantaneously because it needs

to allow the feeder to send the restraint signal where there is an inherent time delay. However, the

incomer time delay can still be set for a faster operating time because the incomer does not need to

grade with downstream protection devices. As a result, proper coordination and selectivity is

maintained while still providing back-up protection for feeder F3.

39

Figure 10: Zone selective interlocking

5.3.4 Remote Operation

Increasing the working distance between the possible origin of an arc flash and the personnel is also

an effective method to reduce exposure to an arc flash hazard. Therefore, another known effective

method to mitigate the arc flash hazard when switching or racking the circuit breakers is to perform

these tasks remotely. The remote operation of the circuit breakers can be achieved by installing a

remote switching and racking panel outside the arc flash boundary or using the SCADA

infrastructure where personnel can operate the equipment in front of a human machine interface

(HMI) panel or a personal computer (PC).

40

5.4 Administrative control

There are administrative controls that are already employed to mitigate arc flash hazards when

working at energised switchboards at the Solomon Hub. These include risk assessments, safety

related working procedures and safety training. Arc flash labels are currently not available, however

Fortescue intends to implement these based on the arc flash study results that were calculated in the

present project. This method of labelling equipment showing the level of arc flash hazard exposure

and the appropriate PPE will assist personnel in making informed choices about how to safely

perform their work.

5.5 PPE

There are PPE clothing options rated at 12 cal/cm2 and 40 cal/cm2 available at Solomon electrical

rooms. However, the use of PPE must be the last line of defence applied and all other means must

be investigated to reduce the arc flash hazard to an acceptable level. PPE clothing options with higher

category ratings are known to be heavy and uncomfortable, and capable of restricting vision and

movement. These drawbacks can make it difficult to complete many tasks, which means that this

protection equipment is also creating a hazard. The requirement set by FMG is the reduction of arc

flash incident energy to not greater than 8 cal/cm2 if feasible, so that the lighter PPEs rated at 12

cal/cm2 available at Solomon Hub can be used.

41

6 Recommendations

From Section 5, it can be seen that numerous arc flash hazard mitigation strategies exist. The

challenge is to find the optimal strategy that can be implemented on an existing facility like the

Solomon Hub. Implementing many of these strategies are difficult for engineers due to excessive

capitals costs and retrofitting costs that limit their feasibility. Incorporating the findings of the present

project, and following thorough research of the engineering literature and discussions with senior

engineers, it was decided that Fortescue would implement three engineering controls at the Solomon

Hub mines: protection settings optimisation, installing maintenance switches and remote operation.

Based on the results of the arc flash hazard studies, optimising the 50P element of protection relays

and the instantaneous protection settings of LV circuit breakers appeared to be the superior option

due to the very low costs associated with this strategy. Therefore, the settings of all LV incomers

and some HV incomers were optimised so that arc faults can be cleared fast, thereby reducing

incident energy exposure. These protection settings will give consideration to the inrush current from

motors and transformers during the energisation stage. Hence, the proposed protection settings will

clear arc faults fast, reducing the incident energy significantly while maintaining protection system

reliability. However, this method is not always feasible due to protection grading requirements, and

hence it can only be applied to some protection devices.

Where grading requirements do not allow for the mitigation of the arc flash hazard by optimising

protection settings, installing maintenance switches is proposed. Switching to maintenance mode

when working on the switchboard will be included in permit conditions to ensure it is a mandatory

step. A physical switch will be wired to the protection device, which will be used to activate the

maintenance mode protection settings. Initially, it was proposed to install 52 maintenance switches.

The majority were to be installed on the upstream protection devices, which are normally located in

another switch room. It was also noted that the existing SCADA infrastructure has the capability of

also being used to remotely activate the maintenance mode settings from upstream protection

42

devices. However, further investigation needs to be conducted to determine the feasibility of using

SCADA to activate the settings.

Arc flash calculations were performed based on the proposed optimised protection settings and

maintenance mode protection settings for the 52 protection devices. It was found that the potential

incident energy exposure from all switchboards would be reduced to less than 8 cal/cm2, which is a

significant improvement on the existing incident energy exposures. However, the number of

maintenance switches that would need to be installed is not practical due to the high cost of

installation and due to large distances, varying from a few hundred metres to just over 1 km, that

would limit accessibility. Ultimately, it was decided to use remote operation to mitigate the arc flash

hazard when switching or racking the LV incomers, which resulted in the reduction in the number

of maintenance switches that needed to be installed to just three, (the settings and locations can be

found in Appendix H). A remote switching and racking panel would be installed inside the

switchroom where the incomers are located. The switches that would be used to remotely switch or

rack the incomers would be wired to the protection devices. This method could eliminate the arc

flash hazard because the remote switching and racking panel would be installed outside the arc flash

boundary, and hence personnels’ safety could be assured.

The proposed optimised protection settings and the results of the arc flash studies based on these

settings can be found in Appendices, I, J, K and L. The findings regarding the proposed solutions of

optimising protection settings, installing maintenance switches and utilising remote operation, if

implemented, will meet the principal aim of this project, which was to reduce the incident energy to

less than 8 cal/cm2. As a result, by applying the three solutions in the appropriate situations, the

existing PPEs rated at 12 cal/cm2 can be used for energised work in the switchboards installed at the

Solomon Hub mines.

43

Finally, it was found that the 33kV system does not have correct protection grading for three-phase

faults. While it is not part of the project, it is a major problem that need to be resolved. Therefore,

protection settings to resolve this problem were proposed which can be found in Appendix M. The

proposed protection settings will ensure the reliability of the protection system while giving

consideration to clearing time for arc flash.

44

7 Conclusion

The main purpose of this project is to conduct arc flash studies for switchboards installed at

Fortescue’s Solomon Hub. The aim of the studies is to find feasible solutions to reduce arc flash

incident energies to less than 8 cal/cm2 and to provide appropriate arc flash PPE recommendations.

The arc flash studies were conducted based on IEEE 1584-2002 Standard, the IEEE Guide for

Performing Arc-Flash Hazard Calculations. PowerFactory was used to perform short-circuit analyses

and coordination studies and the results were used to provide the information that is required for the

completion of an arc flash hazard analyses for each switchboard.

The arc flash study results summarised in Section 4 indicate that the existing arc flash incident energy

of some switchboards installed at the Solomon Hub are significantly above the desired level of 8

cal/cm2. Contrary to what was believed at the start of the studies, the LV switchboards represent the

most significant hazards, where many have incident energy greater than 40 cal/cm2, which is above

the withstand rating of PPEs available at Solomon Hub. In addition, it was found that the potential

incident energies of 0.69kV switchboards will depend on the task that is being performed. Switching

or racking the incomer create a significant arc flash hazard with many have incident energies greater

than 8 cal/cm2. Other switchboards that have voltages of 6.6kV and 11kV have low potential incident

energies except for SUB801-SWB01 switchboard, which has a potential incident energy of 21.82

cal/cm2.

Moreover, the 33kV switchboards have manageable arc flash hazards (with arc flash incident

energies less than 8 cal/cm2), with the exception of the 33kV switchboards installed at Firetail OPF,

where the incident energy levels are 23.37 cal/cm2 – 37.58 cal/cm2. However, the 33kV protection

system has no protection grading, if the correct protection settings are implemented, the incident

energies will increase.

45

While the main objective of this project was to conduct arc flash studies for switchboards installed

in the Solomon Hub, insufficient protection grading was found in a number of areas. As a result, the

recommendations for this project also included protection setting changes to ensure the reliability

and selectivity of the protection system. The main grading problems (for three-phase faults) that

were found were:

The 33kV system at Firetail has no three-phase fault grading. Faults in any of the 33kV

switchboards installed at Firetail will take out the whole Firetail OPF.

The 33kV system at KV has no three-phase fault grading. Fault in any of the 33kV

switchboards installed at KV will take out the whole KV OPF.

The feeders from RMUs have no three-phase fault grading with upstream protection

devices at Substation 2 and Substation 3.

The recommended solutions to reduce the arc flash hazard and to resolve the grading problems are

discussed in Section 6. To mitigate the arc flash hazard, three simple solutions were proposed:

1. Optimise protection settings

2. Maintenance switches

3. Remote operation

The proposed engineering controls will significantly reduce the arc flash incident energy for all

switchboards to less than 8 cal/cm2 which is the principal aim of this project. As a result, the existing

PPEs rated at 12 cal/cm2 can be used for energised work in the switchboards installed at the Solomon

Hub mines without compromising personnel safety. These results represent a significant

achievement and the project is considered to have been a resounding success.

46

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Calculations, New York: Institute of Electrical and Electronics Engineers, 2002.

48

[31] DigSILENT GmbH, PowerFactory 15 User Manual, Gomaringen: DigSILENT GmbH, 2014.

[32] W. Tinsley and M. Hodder, “A Practical Approach to Arc Flash Hazard Analysis and

Reduction,” in IEEE IAS Pulp and Paper Industry Conference, Victoria, 2004.

[33] International Electrotechnical Commision, IEC 60909-0:2001 - Short-circuit currents in three-

phase a.c. systems - Part 0: Calculation of Currents, Geneva: International Electrotechnical

Commision, 2001.

[34] Aurecon, FMG T155 Solomon Project Ore Processing Facilities, Perth: Fortescue Metals

Group Ltd., 2012.

[35] W. Tinsley, M. Hodder and A. Graham, “ARC FLASH HAZARD CALCULATIONS: MYTHS, FACTS

AND SOLUTIONS,” in IEEE IAS Pulp and Paper Industry Technical Conference, Appleton,

2006.

[36] M. Holt, “What is Arc Flash?,” Mike Holt Enterprises, Inc., 2004. [Online]. Available:

https://www.mikeholt.com/mojonewsarchive/NEC-HTML/HTML/What-is-Arc-

Flash~20040512.php. [Accessed 11 January 2016].

[37] P. Willis, “Arc Flash Standards - Australian Developments,” in Electrical Arc Flash Forum ,

Melbourne, 2010.

[38] W. Tinsley and M. Hodder, A Practical Approach to Arc Flash Hazard Analysis and Reduction,

Moon Township: Eaton Corporation, 2006.

[39] GE Consumer & Industrial GmbH, Installation, Operation and Maintenance Manual, Berlin:

GE Consumer & Industrial GmbH, 2010.

[40] Environmental & Safety Professionals, “Risk Assessment & Risk Management,”

Environmental & Safety Professionals, 2009. [Online]. Available:

http://www.environet.com.au/services.asp?id=20&cid=16. [Accessed 14 01 2016].

[41] N. Thompson, Arc Faults - Safety Measures and Detection, Auckland: NHP, 2013.

[42] C. G. Walker, “Arc flash energy reduction techniques zone selective interlocking & energy-

reducing maintenance switching,” in Pulp and Paper Industry Technical Conference (PPIC),

Nashville, 2011.

49

9 Appendices

9.1 Appendix A – Solomon Interconnection diagram

50

9.2 Appendix B – LV incomers Settings

It is important to inspect the relevant manuals to understand the interpretation of values in the

following tables.

Table 9: Existing Stockyard .4 kV MCC protection settings

Table 10: Existing Firetail .4 kV MCC protection settings

Existing Stockyard .4 kV MCC protection settings

Location Descriptor Protection device I rating In(xICT) LT PU LTD (s) ST PU trip time (s) INS PU

SUB801 SUB801

Incomer Terasaki 2500 1 0.9 10 3 0.4 16

SUB801 SK802

Incomer Terasaki 1250 0.63 0.8 20 8 0.2 10

SUB801 RC901

Incomer Terasaki 800 0.5 0.8 2.5 6 0.2 12

SUB901 SUB901

Incomer Terasaki 2500 1 0.9 10 3 0.4 6

Existing Firetail .4 kV MCC protection settings

Location Descriptor Protection

device

I

rating Ir LT PU

LT

Band

ST

PU

ST

Band

Inst

PU

SR203 Firetail SR203 Incomer GE

MPD32W32 3200 2400

0.75 x

rating C2

6 x

Ir 5

10 x

rating


MPD32W32 3200 2400

0.75 x

rating C2

6 x

Ir 5

10 x

rating


MPD32W32 3200 2400

0.75 x

rating C2

6 x

Ir 5

10 x

rating


MPD32W32 3200 2400

0.75 x

rating C2

6 x

Ir 5

10 x

rating


MPD32W32 3200 2400

0.75 x

rating C2

6 x

Ir 5

10 x

rating

SR303 Firetail SR303-MCC02 Incomer GE

MPD32W32 3200 2400

0.75 x

rating C2

6 x

Ir 5

10 x

rating

SR303 Firetail SR303-MCC01 Incomer GE

MPD32W32 3200 2400

0.75 x

rating C2

6 x

Ir 5

10 x

rating

51

Table 11: Existing KV .4 kV MCC protection settings

Table 12: 0.4kV MCCs fed from RMUs

Existing KV .4 kV MCC protection settings

Location Descriptor Protection

device

I

rating Ir LT PU

LT

Band

ST

PU

ST

Band Inst PU

SR303 Kings Valley SR303-MCC03 incomer GE

MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

2 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating

SR402Kings Valley SR402-MCC01 incomer GE

MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating


MPD32W32 3200 2400

0.75 x

rating C4

9 x

Ir 10

2 x

rating


MPD32W32 3200 2400

0.75 x

rating C4

9 x

Ir 10

11 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

2 x

rating


MPD32W32 3200 2400

0.75 x

rating

C

MIN

9 x

Ir 10

10 x

rating

0.4kV MCCs fed from RMUs

Location Descriptor Protection device I

rating In(xICT)

LT

PU

LTD

(s) ST PU

trip time

(s)

INS

PU

SR706 SR706-MCC01

INCOMER Terasaki 1250 0.8 1 10 6 0.4 16

SR705 SR705-MCC01

INCOMER Terasaki 1600 1 0.8 10 1 0.4 off

SR703 SR703-MCC01

INCOMER Terasaki 1250 0.8 1 10 6 0.4 16

SR701 SR701-MCC01

INCOMER Terasaki 1600 1 1 10 6 0.4 16

SR707 SR707-MCC01

INCOMER Terasaki 1600 1 0.85 10 1 0.4 2

52

Table 13: Exising incomer protection settings for VSDs

Protection

device In LT PU (x In) t ST Inst PU (x In)

CV763-VSD02 incomer ABB 1600 0.975 3

no ST

protection

4

CV125-VSD01 incomer ABB 1600 1.025 3 4

CV704-VSD03 incomer ABB 2500 1 144 4










53

9.3 Appendix C – Arc flash study results for the Stockyard

Table 14: Arc flash study results for 0.4kV switchboards installed at the Stockyard based on the existing protection settings

Equipment

Clearing

Device

Location

Maximum

Bolted Fault

Current (kA)

Maximum

Arc

Current

(kA)

Minimum

Bolted Fault

Current

(kA)

0.85 x

Minimum

Arc Current

(kA)

Total

Clearing

Time (s)

Working

Distance

(mm)

Incident

Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash

Boundary

(mm)

PPE

SUB801-SWB01 Incomer

Upstream 30.54 13.89 29.80 11.58 2.18 610 53.78 8062 X

SUB801-SWB01

Switchboard Incomer 30.54 13.89 29.80 11.58 0.43 610 12.92 3061 3

SK801-MCC01 Incomer

Upstream 28.42 13.12 27.07 10.73 0.91 610 20.67 4213 3

SK801-MCC01

Switchboard Incomer(1) 28.42 13.12 27.07 10.73 610

SK802-MCC01 Incomer

Upstream 22.74 10.98 21.94 9.08 0.75 610 14.22 3268 3

SK802-MCC01


RC901-MCC01 Incomer

Upstream 15.35 8.03 15.31 6.81 1.15 610 15.98 3537 3

RC901-MCC01


SUB901-MCC01 Incomer

Upstream 29.48 13.51 28.61 11.21 2.28 610 54.30 8116 X

SUB901-MCC01


(1) Protection settings not available.

Table 15: Arc flash study results for 11kV switchboards installed at the Stockyard based on the existing protection settings


Location

Maximum Bolted Fault Current (kA)

Maximum Arc

Current (kA)

Minimum Bolted Fault Current (kA)

0.85 x Minimum Arc Current (kA)

Total Clearing Time (s)

Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

CV801-VSD01 Switchboard Upstream 19.04 18.28 11.09 9.13 0.08 910 2.57 1993 1

CV801-VSD02 Switchboard

Upstream 19.15 18.38 11.14 9.17 0.08 910 2.59 2005 1


Upstream 19.16 18.39 11.14 9.17 0.08 910 2.59 2007 1


Upstream 12.09 11.70 7.87 6.52 0.08 910 1.59 1214 1


Upstream 12.07 11.68 7.87 6.52 0.08 910 1.58 1204 1


Upstream 12.13 11.73 7.87 6.52 0.08 910 1.59 1218 1


Upstream 12.10 11.71 7.87 6.52 0.08 910 1.59 1215 1


Upstream 12.08 11.69 7.87 6.52 0.08 910 1.59 1213 1


Upstream 12.10 11.71 7.87 6.52 0.08 910 1.59 1215 1


Upstream 12.11 11.71 7.87 6.52 0.08 910 1.59 1216 1

SUB901-SWB01 Switchboard

Upstream 12.18 11.78 7.92 6.56 0.42 910 8.40 6725 3

SUB901-SWB01 Incomer CB

Incomer 12.18 11.78 7.92 6.56 0.37 910 7.40 5903 2

SUB801-SWB01 Switchboard

Upstream 19.26 18.49 11.18 9.21 0.67 910 21.82 17934 3

SUB801-SWB01 Incomer

Incomer 19.26 18.49 11.18 9.21 0.67 910 21.82 17934 3

RC901-SWB01 Switchboard

Upstream 5.48 5.37 4.48 3.75 0.42 910 3.59 2809 1

RC901-SWB01 Incomer

Incomer 5.48 5.37 4.48 3.75 0.40 910 3.42 2672 1

54

9.4 Appendix D – Arc flash study results for Firetail OPF

Table 16: Arc flash study results for 0.4kV switchboards installed at Firetail OPF based on the existing protection settings

Table 17: Arc flash study results for 6.6kV switchboards installed at Firetail OPF based on the existing protection settings


Location

Maximum Bolted Fault

Current (kA)

Maximum Arc Current

(kA)

Minimum Bolted Fault

Current (kA)



Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

2200-SR201-MCC02 Incomer

Upstream(1) 4.03 3.97 3.56 2.99 910

2200-SR201-MCC02 Switchboard

Incomer 4.03 3.97 3.56 2.99 0.41 910 2.54 1967 1


Upstream(1) 4.05 3.99 3.59 3.02 910


Incomer 4.05 3.99 3.59 3.02 0.41 910 2.55 1977 1

SR103-MCC01 Incomer

Upstream 4.01 3.96 3.55 2.98 0.66 910 4.07 3195 2

SR103-MCC01 Switchboard

Incomer 4.01 3.96 3.55 2.98 0.42 910 2.57 1992 1

SR101-MCC01 Incomer

Upstream 4.02 3.97 3.56 2.99 0.66 910 4.08 3204 2


Incomer 4.02 3.97 3.56 2.99 0.42 910 2.58 1998 1

SR501-MCC01 Incomer

Upstream 4.02 3.97 3.55 2.98 0.66 910 4.08 3198 2


Incomer 4.02 3.97 3.55 2.98 0.42 910 2.58 1997 1

SR401-MCC01 Incomer

Upstream 3.96 3.90 3.49 2.93 0.67 910 4.04 3166 2


Incomer 3.96 3.90 3.49 2.93 0.42 910 2.55 1971 1

SR301-MCC01 Incomer

Upstream 5.36 5.26 3.55 2.98 0.66 910 5.55 4390 2


Incomer 5.36 5.26 3.55 2.98 0.59 910 4.93 3888 2

SR301-MCC02 Incomer

Upstream 4.39 4.33 3.55 2.98 0.66 910 4.48 3527 2


Incomer 4.39 4.33 3.55 2.98 0.42 910 2.83 2199 1



Location


Maximum Arc Current (kA)


Current (kA)



Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

SR203-MCC01 Incomer

Upstream 37.59 16.39 35.38 13.28 1.07 610 38.43 6418 4


Incomer 37.59 16.39 35.38 13.28 1.25 610 35.76 6330 4

SR104-MCC01 Incomer

Upstream 37.54 16.38 35.27 13.24 1.1 610 39.46 6535 4


Incomer 37.54 16.38 35.27 13.24 1.25 610 35.64 6326 4

SR102-MCC01 Incomer

Upstream 42.39 18.04 35.34 13.27 1.1 610 43.82 7016 x


Incomer 42.39 18.04 35.34 13.27 1.25 610 35.73 6791 X

SR502-MCC01 Incomer

Upstream 39.80 17.16 35.34 13.27 1.1 610 41.5 6762 X


Incomer 39.80 17.16 35.34 13.27 1.25 610 35.73 6545 4

SR402-MCC01 Incomer

Upstream 40.93 17.54 35.37 13.28 1.09 610 42.13 6831 X


Incomer 40.93 17.54 35.37 13.28 1.25 610 37.47 6653 4

SR303-MCC02 Incomer

Upstream 38.95 16.86 35.32 13.26 1.1 610 40.73 6677 X


Incomer 38.95 16.86 35.32 13.26 1.25 610 35.70 6463 4

SR303-MCC01 Incomer

Upstream 41.07 17.59 35.33 13.26 1.1 610 42.64 6887 X


Incomer 41.07 17.59 35.33 13.26 1.25 610 40.65 6667 X

55

Table 18: Arc flash study results for 33kV switchboards installed at Firetail OPF based on the existing protection settings


Location


Maximum Arc Current

(kA)


Current (kA)

0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

2200-SR201-SWB01 Switchboard/Incomer

SUB002 Feeder to

Firetail 4.57 4.57 2.47 2.10 0.39 910 36.32 5006 4


SUB002 Feeder to

Firetail 4.45 4.45 2.42 2.06 0.39 910 35.41 4944 4


SUB002 Feeder to

Firetail 4.53 4.53 2.45 2.08 0.39 910 36.02 4986 4


SUB002 Feeder to

Firetail 4.54 4.54 2.45 2.08 0.41 910 37.58 5092 4


SUB002 Feeder to

Firetail 4.56 4.56 2.46 2.09 0.41 910 37.58 5092 4


SUB002 Feeder to

Firetail 4.52 4.52 2.44 2.07 0.41 910 37.48 5086 4


SUB002 Feeder to

Firetail 4.59 4.59 2.47 2.10 0.39 910 36.43 5014 4

56

9.5 Appendix E – Arc flash study results for Kings Valley OPF

Table 19: Arc flash study results for 0.4kV switchboards installed at KV OPF based on the existing protection settings



Location


Maximum Arc Current

(kA)


Current (kA)

0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE


Upstream 36.34 15.96 34.88 13.12 1.12 610 39.07 6490 4


Incomer 36.34 15.96 34.88 13.12 0.45 610 13.17 3102 3


Upstream 39.57 17.08 35.23 13.23 1.11 610 41.67 6780 X


Incomer 39.57 17.08 35.23 13.23 0.45 610 13.17 3260 3


Upstream 38.92 16.85 32.10 12.29 1.17 610 43.3 6959 X


Incomer 38.92 16.85 32.10 12.29 0.45 610 13.97 3229 3


Upstream 36.81 16.12 35.22 13.23 1.11 610 39.15 6500 4


Incomer 36.81 16.12 35.22 13.23 0.45 610 13.17 3260 3


Upstream 43.42 18.39 35.26 13.24 1.11 610 45.14 7159 X


Incomer 43.42 18.39 35.26 13.24 0.45 610 13.17 3260 3


Upstream 39.19 16.95 35.05 13.18 1.11 610 41.33 6743 X


Incomer 39.19 16.95 35.05 13.18 0.45 610 14.05 3242 3


Upstream 40.49 17.39 34.49 13.01 1.12 610 42.88 6914 X


Incomer 40.49 17.39 34.49 13.01 0.45 610 14.45 3304 3


Upstream 37.37 16.32 35.78 13.40 1.10 610 39.31 6517 4


Incomer 37.37 16.32 35.78 13.40 0.45 610 13.49 3153 3


Upstream 39.91 17.19 34.81 13.11 1.12 610 42.35 6856 X


Incomer 39.91 17.19 34.81 13.11 0.45 610 14.27 3276 3


Upstream 33.56 14.98 32.13 12.30 1.17 610 38.11 6382 4


Incomer 33.56 14.98 32.13 12.30 2.5 610 91.66 11579 X


Upstream 38.50 16.71 35.28 13.25 1.06 610 38.86 6467 4


Incomer 38.50 16.71 35.28 13.25 3 610 92.27 11631 X


Upstream 37.94 16.51 35.26 13.24 1.11 610 40.18 6615 X


Incomer(1) 37.94 16.51 35.26 13.24 610


Upstream 37.18 16.25 35.16 13.21 1.11 610 39.5 6538 4


Incomer 37.18 16.25 35.16 13.21 0.45 610 13.43 3144 3


Upstream 39.40 17.02 35.31 13.26 1.11 610 41.52 6763 X


Incomer 39.40 17.02 35.31 13.26 0.45 610 14.12 3252 3

57

Table 20: Arc flash study results for the 6.6kV switchboards installed at KV OPF based on the existing protection settings


Location


Current (kA)

Maximum Arc

Current (kA)


Current (kA)



Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

2300-SR302-MCC01

Incomer Upstream 4.02 3.96 3.57 3.00 0.66 910 4.08 3197 2

2300-SR302-MCC01


2300-SR301-MCC02


2300-SR301-MCC02


2300-SR301-MCC01


2300-SR301-MCC01


2100-SR103-MCC01


2100-SR103-MCC01


2100-SR101-MCC01


2100-SR101-MCC01


2200-SR201-MCC03


2200-SR201-MCC03


2200-SR201-MCC02


2200-SR201-MCC02


2200-SR201-MCC01


2200-SR201-MCC01


2700-SR701-MCC01


2700-SR701-MCC01


2400-SR401-MCC01


2400-SR401-MCC01


2500-SR508-MCC01


2500-SR508-MCC01


2570-SR504-MCC02


2570-SR504-MCC02


2570-SR504-MCC01


2570-SR504-MCC01


2550-SR501-MCC02


2550-SR501-MCC02


58


Table 21: Arc flash study results for 33kV switchboards installed at KV OPF based on the existing protection settings

2550-SR501-MCC01


2550-SR501-MCC01

Switchboard Incomer(1) 4.02 3.97 3.59 3.02 910


Location


Current (kA)

Maximum Arc Current

(kA)


0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE


SUB003 Feeder to

KV 4.75 4.75 2.37 2.01 0.08 910 7.74 2312 2


SUB003 Feeder to

KV 4.72 4.72 2.37 2.01 0.08 910 7.70 2305 2


SUB003 Feeder to

KV 4.73 4.73 2.38 2.02 0.08 910 7.72 2308 2


SUB003 Feeder to

KV 4.75 4.75 2.38 2.02 0.08 910 7.75 2312 2


SUB003 Feeder to

KV 4.68 4.68 2.36 2.01 0.08 910 7.64 2296 2


SUB003 Feeder to

KV 4.73 4.73 2.36 2.01 0.08 910 7.71 2307 2


SUB003 Feeder to

KV 4.71 4.71 2.38 2.02 0.08 910 7.69 2303 2


SUB003 Feeder to

KV 4.74 4.74 2.39 2.03 0.08 910 7.73 2309 2


SUB003 Feeder to

KV 4.78 4.78 2.40 2.04 0.08 910 7.79 2319 2


SUB003 Feeder to

KV 4.86 4.86 2.41 2.05 0.08 910 7.87 2330 2

59

9.6 Appendix F – Arc flash study results for RMUs and switchboards

downstream

Table 22: Arc flash study results for the RMUs based on the existing settings

Table 23: Arc flash study results for the sizer drives switchboards based on the existing protection settings

Table 24: Arc flash study results for the VSDs based on the existing protection settings


Location


Current (kA)

Maximum Arc

Current (kA)




Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

RMU12 Upstream (SUB003)

4.86 4.86 2.42 2.06 0.08 910 7.93 2340 2


4.81 4.81 2.40 2.04 0.08 910 7.85 2327 2


4.78 4.78 2.39 2.03 0.08 910 7.80 2320 2


4.72 4.72 2.37 2.01 0.08 910 7.70 2305 2


4.58 4.58 2.46 2.09 0.08 910 7.47 2270 2


4.50 4.50 2.43 2.07 0.08 910 7.35 2252 2


4.45 4.45 2.41 2.05 0.08 910 7.26 2238 2


4.36 4.36 2.36 2.01 0.08 910 7.11 2216 2


Location


Current (kA)

Maximum Arc

Current (kA)




Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

SR152-SWB01 Incomer

Upstream 3.43 3.39 2.55 2.15 0.92 910 4.79 3775 2

SR152-SWB01 Switchboard

Incomer 3.43 3.39 2.55 2.15 0.52 910 2.71 2100 1

SR122-SWB01 Incomer

Upstream 3.58 3.53 2.67 2.25 0.77 910 4.21 3304 2


Incomer 3.58 3.53 2.67 2.25 0.52 910 2.83 2198 1

SR112-SWB01 Incomer

Upstream 3.57 3.53 2.67 2.25 0.77 910 4.21 3306 2


Incomer 3.57 3.53 2.67 2.25 0.52 910 2.82 2194 1


Location


Current (kA)

Maximum Arc Current

(kA)


Current (kA)



Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

CV113-VSD01 Incomer

Upstream 25.68 21.18 24.23 17.04 1.05 610 49.75 7647 X


Incomer 25.68 21.18 24.23 17.04 0.09 610 4.26 1443 2

CV123-VSD01 Incomer

Upstream 25.70 21.20 24.25 17.04 1.05 610 49.79 7652 X


Incomer 25.70 21.20 24.25 17.04 0.09 610 4.27 1444 2

CV763-VSD02 Incomer

Upstream 25.43 20.10 23.58 16.60 1.11 610 52.08 7888 X


Incomer 25.43 20.10 23.58 16.60 0.09 610 4.22 1433 2

CV125-VSD01 Incomer

Upstream 25.30 20.89 23.48 16.54 1.05 610 49 7569 X


Incomer 25.30 20.89 23.48 16.54 0.09 610 4.20 1428 2

CV705-VSD03 Incomer

Upstream 25.47 21.02 23.62 16.63 1.05 610 49.34 7604 X


Incomer 25.47 21.02 23.62 16.63 0.09 610 4.23 1435 2

CV704-VSD01 Incomer

Upstream 25.65 21.16 23.82 16.76 1.05 610 49.71 7643 X


Incomer 25.65 21.16 23.82 16.76 0.09 610 4.26 1442 2

CV704-VSD02 Incomer

Upstream 25.66 21.17 23.82 16.76 1.05 610 49.72 7644 X


Incomer 25.66 21.17 23.82 16.76 0.09 610 4.26 1442 2

60

Table 25: Arc flash study results for 0.4kV switchboards based on the existing protection settings


CV704-VSD03 Incomer

Upstream 25.54 21.07 23.82 16.76 1.05 610 49.48 7619 X


Incomer 25.54 21.07 23.82 16.76 0.09 610 4.26 1442 2

CV153-VSD01 Incomer

Upstream 25.00 20.65 23.21 16.35 1.05 610 48.41 7506 X


Incomer 25.00 20.65 23.21 16.35 0.09 610 4.15 1416 2

CV763-VSD01 Incomer

Upstream 17.92 15.05 17.49 12.50 0.89 610 29.14 5319 4


Incomer 17.92 15.05 17.49 12.50 0.09 610 2.95 1123 1

CV705-VSD02 Incomer

Upstream 18.83 15.78 18.32 13.06 0.84 610 29.01 5303 4


Incomer 18.83 15.78 18.32 13.06 0.09 610 3.10 1162 1

CV705-VSD01 Incomer

Upstream 18.80 15.75 18.28 13.04 0.84 610 29.03 5305 4


Incomer 18.80 15.75 18.28 13.04 0.09 610 3.10 1161 1


Location


Current (kA)

Maximum Arc

Current (kA)


0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE

SR701-MCC01 Incomer

Upstream 20.57 10.14 20.48 8.59 1.16 610 24.79 4766 3


Incomer 20.57 10.14 20.48 8.59 6.5 610 116.54 13629 X

SR029-MCC01 Incomer

Upstream 29.72 13.60 29.07 11.36 1.37 610 40.19 6616 X


Incomer(1) 29.72 13.60 29.07 11.36 610

SR706-MCC01 Incomer

Upstream 13.55 7.27 13.42 6.14 1.07 610 15.96 3535 3


Incomer 13.55 7.27 13.42 6.14 0.46 610 6.86 1993 2

SR705-MCC01 Incomer

Upstream 20.40 10.07 19.78 8.36 4.45 610 94.42 11815 X


Incomer 20.40 10.07 19.78 8.36 0.43 610 9.12 2418 3

SR703-MCC01 Incomer

Upstream 13.53 7.26 13.38 6.12 1.07 610 15.94 3531 3


Incomer 13.53 7.26 13.38 6.12 0.43 610 6.40 1901 2

SR151-MCC01 Incomer

Upstream 36.17 15.90 33.63 12.75 2 610 69.84 9627 X


Incomer(1) 36.17 15.90 33.63 12.75 610

SR121-MCC01 Incomer

Upstream 36.2 15.91 34.36 12.97 2.01 610 69.89 9632 X


Incomer 36.2 15.91 34.36 12.97 0.09 610 3.13 1169 1

SR111-MCC01 Incomer

Upstream 36.15 15.89 34.29 12.95 2 610 69.80 9624 X


Incomer 36.15 15.89 34.29 12.95 0.09 610 3.13 1168 1

SR707-MCC01 Incomer

Upstream 45.36 19.04 42.39 15.33 0.60 610 25.33 4836 4


Incomer 45.36 19.04 42.39 15.33 0.43 610 18.16 3858 3

61

9.7 Appendix G – GE LV circuit breaker curve

Refer to the relevant section from the “Operation and Maintenance Manual” for the MPRO 50 trip

unit to understand how to determine the total clearing time from the curve seen in Figure 11.

Figure 11: GE LV circuit breaker curve (approval pending [39]

62

9.8 Appendix H – Maintenance mode protection settings

Table 26: Settings and location of the three maintenance switches

MS at SUB801 11kV Switchboard incomer

50P2 pickup 2550A

Time setting 0

MS at SUB002 33kV switchboard incomer

50P1 pickup 1600 A

Time setting 0

MS at SUB003 33kV switchboard incomer

50P1 pickup 1600 A

Time setting 0

63

9.9 Appendix I – Arc flash study results for Stockyard based on the

proposed solutions

Table 27: Arc flash study results for 0.4kV switchboards installed at the Stockyard based on the proposed protection settings

Highlighted in red are the protection settings changes that need to be implemented to reduce the arc

flash incident energy.

Table 28: Proposed protection settings for the Stockyard 0.4kV switchboards incomers

SUB801 MCC Incomer SUB901 MCC Incomer SK801 MCC Incomer(1) SK802 MCC Incomer RC901 MCC Incomer

ICT 2500 2500 1250 800

In (xICT) 1 1 1 1

LT (x In) 0.9 0.9 0.85 0.8

LT s 10 10 20 2.5

ST 3 3 8kA 6 6

ST s 0.2 0.2 0.2 0.2 0.2

INST 8 6 10 12

(1) Protection settings to ensure incident energy is less than 8 cal/cm2.

Table 29: Arc flash study results for the Stockyard 11kV switchboards based on the proposed protection settings


Location


Maximum Arc Current

(kA)


Current (kA)

0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE MS

SUB801-SWB01

Incomer CB Remote operation will eliminate arc flash hazard.

SUB801-SWB01

Switchboard Incomer 30.54 13.89 29.80 11.58 0.23 610 6.91 2002 2 No

SK801-MCC01 Incomer CB

Remote operation will eliminate arc flash hazard.

SK801-MCC01 Switchboard

Incomer 28.42 13.12 27.07 10.73 0.23 610 5.36 1685 2 No

SK802-MCC01 Incomer CB


SK802-MCC01 Switchboard

Incomer 22.74 10.98 21.94 9.08 0.23 610 5.36 1685 2 No

RC901-MCC01 Incomer CB


RC901-MCC01 Switchboard

Incomer 15.35 8.03 15.31 6.81 0.23 610 3.82 1339 1 No

SUB901-MCC01


SUB901-MCC01



Location


Current (kA)

Maximum Arc

Current (kA)


0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE MS

SUB901-SWB01

Incomer CB Upstream 12.18 11.78 7.92 6.56 0.25 910 5.00 3946 2 No

SUB901-SWB01


SUB801-SWB01


SUB801-SWB01

Switchboard Incomer 19.26 18.49 11.18 9.21 0.08 910 2.61 2019 1 Yes

64

Table 30: Proposed protection settings for Stockpile 11kV switchboards incomers

Protection Device Location Relay CTR 51P 50P

Feeder to SUB901 11kV switchboard

SUB801 SEL751A 1000 CS – 0.52

C2 TD – 0.75

Pickup – 4 Time setting – 0.20 s

Incomer of main SUB901 11kV switchboard

SUB901 SEL751A 1000 CS-0.94

C2 TD – 0.69


65

9.10 Appendix J – Arc flash study results for the Firetail OPF based on the

proposed solutions

Table 31: Arc flash study results for Firetail 0.4kV switchboards based on the proposed protection settings



Table 32: Proposed protection settings for Firetail 0.4kV switchboards incomers


Location


Current (kA)

Maximum Arc

Current (kA)


Current (kA)

0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE MS

SR203-MCC01 Incomer



Incomer 37.59 16.39 35.38 13.28 0.18 610 6.46 1914 2 No

SR104-MCC01 Incomer



Incomer 37.54 16.38 35.27 13.24 0.18 610 6.46 1912 2 No

SR102-MCC01 Incomer



Incomer 42.39 18.04 35.34 13.27 0.18 610 7.17 2053 2 No

SR502-MCC01 Incomer



Incomer 39.80 17.16 35.34 13.27 0.18 610 6.79 1979 2 No

SR402-MCC01 Incomer



Incomer 40.93 17.54 35.37 13.28 0.18 610 6.96 2011 2 No

SR303-MCC02 Incomer



Incomer 38.95 16.86 35.32 13.26 0.18 610 6.67 1954 2 No

SR303-MCC01 Incomer



Incomer 41.07 17.59 35.33 13.26 0.18 610 6.98 2015 2 No

SR203-MCC01

Incomer SR104-MCC01

Incomer SR102-MCC01

Incomer SR502-MCC01

Incomer SR402-MCC01

Incomer SR303-MCC02

Incomer SR303-MCC01

Incomer

Rating 3200 3200 3200 3200 3200 3200 3200

LT pickup 0.75 x Ie 0.75 x Ie 0.75 x Ie 0.75 x Ie 0.75 x Ie 0.75 x Ie 0.75 x Ie

LT Band C2 C2 C2 C2 C2 C2 C2

Ir 2400 2400 2400 2400 2400 2400 2400

ST pickup 5 x Ir 5 x Ir 5 x Ir 5 x Ir 5 x Ir 5 x Ir 5 x Ir

ST Band 5 5 5 5 5 5 5

INST pickup 10 x Ie 10 x Ie 10 x Ie 10 x Ie 10 x Ie 10 x Ie 10 x Ie

66

Table 33: Arc flash study results for Firetail 33kV switchboards based on the proposed maintenance mode protection settings


location

Max Bolted Fault

Current (kA)

Max Arc

Current (kA)

Min Bolted Fault

Current (kA)

0.85 x Min Arc Current

(kA)

Total Clearing time (s)

Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE MS

2000-SUB001-RMU01 Switchboard/Incomer

SUB002 33kV switchboard

incomer 4.59 4.59 2.47 2.10 0.08 910 7.46 2269 2 Yes



incomer 4.57 4.57 2.47 2.10 0.08 910 7.43 2262 2 Yes



incomer 4.45 4.45 2.42 2.06 0.08 910 7.25 2236 2 Yes



incomer 4.53 4.53 2.45 2.08 0.08 910 7.37 2256 2 Yes



incomer 4.54 4.54 2.45 2.08 0.08 910 7.39 2258 2 Yes



incomer 4.52 4.52 2.46 2.09 0.08 910 7.42 2263 2 Yes



incomer 4.52 4.52 2.44 2.07 0.08 910 7.35 2252 2 Yes



incomer 4.59 4.59 2.47 2.10 0.08 910 7.48 2273 2 Yes

67

9.11 Appendix K – Arc flash study results for the Firetail OPF based on the

proposed solutions

Table 34: Arc flash study results for KV 0.4kV switchboards based on the proposed protection settings


Location


Maximum Arc

Current (kA)


Current (kA)

0.85 x Minimum

Arc Current

(kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE MS




Incomer 36.34 15.96 34.88 13.12 0.20 610 6.98 2015 2 No




Incomer 39.57 17.08 35.23 13.23 0.20 610 7.51 2118 2 No




Incomer 38.91 16.85 32.10 12.29 0.20 610 7.40 2098 2 No




Incomer 36.81 16.12 35.22 13.23 0.20 610 7.05 2030 2 No




Incomer 43.42 18.39 35.26 13.24 0.18 610 7.32 2082 2 No




Incomer 39.19 16.95 35.05 13.18 0.20 610 7.45 2106 2 No




Incomer 40.49 17.39 34.49 13.01 0.20 610 7.66 2147 2 No




Incomer 37.37 16.32 35.78 13.40 0.20 610 7.15 2049 2 No




Incomer 39.91 17.19 34.81 13.11 0.20 610 7.56 2129 2 No




Incomer 33.56 14.98 32.13 12.30 0.20 610 6.51 1924 2 No




Incomer 38.50 16.71 35.28 13.25 0.20 610 7.33 2085 2 No




Incomer 37.94 16.51 35.26 13.24 0.20 610 7.24 2067 2 No




Incomer 37.18 16.25 35.16 13.21 0.20 610 7.12 2043 2 No




Incomer 39.40 17.02 35.31 13.26 0.20 610 7.48 2113 2 No

68



Table 35: Proposed protection settings for KV 0.4kV incomer

SR303-MCC01 Incomer

SR303-MCC02 Incomer

SR303-MCC03 Incomer

SR104-MCC01 Incomer

SR102-MCC01 Incomer

SR203-MCC01 Incomer

SR203-MCC02 Incomer

Rating 3200 3200 3200 3200 3200 3200 3200

LT pickup 0.75 0.75 0.75 0.75 0.75 0.75 0.75

LT Band C-Min C-Min C-Min C-Min C-Min C-Min C-Min

Ir 2400 2400 2400 2400 2400 2400 2400


ST Band 6 6 6 6 5 6 6


SR702-MCC01 Incomer

SR402-MCC01 Incomer

SR509-MCC03 Incomer

SR509-MCC02 Incomer

SR509-MCC01 Incomer

SR505-MCC01 Incomer

SR503-MCC01 Incomer

Rating 3200 3200 3200 3200 3200 3200 3200

LT pickup 0.75 0.75 0.75 0.75 0.75 0.75 0.75

LT Band C-Min C-Min C4 C4 C4 C-Min C-Min

Ir 2400 2400 2400 2400 2400 2400 2400


ST Band 6 6 6 6 6 6 6


Table 36: Arc flash study results for KV 33kV switchboards based on the proposed maintenance mode protection settings


Location


Maximum Arc Current

(kA)


0.85 x Minimum

Arc Current (kA)

Total Clearing Time

(s)

Working Distance

(mm)

Incident

Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE MS



incomer

4.75 4.75 2.37 2.01 0.08 910 7.74 2312 2 Yes



incomer

4.72 4.72 2.37 2.01 0.08 910 7.70 2305 2 Yes



incomer

4.73 4.73 2.38 2.02 0.08 910 7.72 2308 2 Yes



incomer

4.75 4.75 2.38 2.02 0.08 910 7.75 2312 2 Yes



incomer

4.68 4.68 2.36 2.01 0.08 910 7.64 2296 2 Yes



incomer

4.73 4.73 2.36 2.01 0.08 910 7.71 2307 2 Yes



incomer

4.71 4.71 2.38 2.02 0.08 910 7.69 2303 2 Yes



incomer

4.74 4.74 2.39 2.03 0.08 910 7.73 2309 2 Yes



incomer

4.78 4.78 2.40 2.04 0.08 910 7.79 2319 2 Yes



incomer

4.86 4.86 2.41 2.05 0.08 910 7.87 2330 2 Yes

69

9.12 Appendix L – Arc flash study results for RMUs based on proposed

solutions

Table 37: Arc flash study results for the RMUs based on the proposed maintenance mode protection settings


Location


Current (kA)

Maximum Arc

Current (kA)


0.85 x Minimum

Arc Current (kA)


Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm)

PPE

MS

RMU12


incomer

4.86 4.86 2.42 2.06 0.08 910 7.93 2340 2 Yes

RMU29


incomer

4.81 4.81 2.40 2.04 0.08 910 7.85 2327 2 Yes

RMU13


incomer

4.78 4.78 2.39 2.03 0.08 910 7.80 2320 2 Yes

RMU17


incomer

4.72 4.72 2.37 2.01 0.08 910 7.70 2305 2 Yes

RMU11


incomer

4.58 4.58 2.46 2.09 0.08 910 7.47 2270 2 Yes

RMU14


incomer

4.50 4.50 2.43 2.07 0.08 910 7.35 2252 2 Yes

RMU15


incomer

4.45 4.45 2.41 2.05 0.08 910 7.26 2238 2 Yes

RMU16


incomer

4.36 4.36 2.36 2.01 0.08 910 7.11 2216 2 Yes

Table 38: Arc flash study results for 0.4kV switchboards based on the proposed protection settings


location

Max Bolted Fault

Current (kA)

Max Arc Current

(kA)

Min Bolted Fault

Current (kA)

0.85 x Min Arc Current

(kA)

Total Clearing time (s)

Working Distance

(mm)

Incident Energy

(𝒄𝒂𝒍

𝒄𝒎𝟐)

Arc Flash Boundary

(mm) PPE MS

SR701-MCC01 Incomer



Incomer 20.57 10.14 20.48 8.59 0.23 610 4.92 1589 2 No

SR029-MCC01 Incomer



Incomer 29.72 13.60 29.07 11.36 0.26 610 7.63 2141 2 No

SR706-MCC01 Incomer



Incomer 13.55 7.27 13.42 6.14 0.23 610 3.43 1245 1 No

SR705-MCC01 Incomer



Incomer 20.40 10.07 19.78 8.36 0.23 610 4.88 1581 2 No

SR703-MCC01 Incomer



Incomer 13.53 7.26 13.38 6.12 0.23 610 3.43 1243 1 No

SR151-MCC01 Incomer



Incomer 36.17 15.90 33.63 12.75 0.09 610 3.13 1169 1 No

SR121-MCC01 Incomer

Remote operation will eliminate arc flash hazard. SR111-MCC01

Incomer

SR707-MCC01 Incomer


Incomer 45.36 19.04 42.39 15.33 0.13 610 5.49 1712 2 No

RBS MCC Incomer 7.88 4.72 7.76 3.96 0.26 610 2.43 985 1 No

70



Table 39: Proposed protection settings for LV incomers

SR706-MCC01

Incomer SR705-MCC01

Incomer SR703-MCC01

Incomer SR701-MCC01

Incomer SR151-MCC01

Incomer(1)

SR029-MCC01

Incomer(1)

RBS Incomer(1)

SR707-MCC01 Incomer

ICT 1250 1600 1250 1600 3200 1600

In (xICT) 0.8 1 0.8 1 0.9 1

LT (x In) 1 0.8 1 1 C12 0.85

LT s 10 10 10 10 2880 10

ST 4 4 4 4 3 8kA 2kA 6

ST s 0.2 0.2 0.2 0.2 1 0.2 0.2 0.1

INST 12 10 12 10 5 16

71

9.13 Appendix M – Proposed protection settings to resolve grading

problems found



Table 40: Proposed settings for protection devices for the main Firetail 33kV switchboard (2000-SR001)

Location Relay CTR 51P CS Curve TD 50P

Feeders to main Firetail Switchboard

(2000-SR001) SUB002 GE F650 600 0.81 Curve A 0.23 Off

Incomer for main Firetail switchboard (2000-SR001)

Main Firetail switchboard

(2000-SR001) SEL751A 600 0.81 C1 0.23 Off

Table 41: Proposed settings for protection devices for the main KV 33kV switchboard (2000-SR001)

Table 42: Proposed settings for feeders to RMUs for correct coordination between protection devices

Location Relay CTR 51P CS Curve TD 50P

Feeders To main KV Switchboard

(2000-SR001) SUB003 GE F650 600 1.2 Curve A 0.19

De-activate

Incomers for main KV switchboard (2000-SR001)

KV SEL751A 1200 0.6 C1 0.19 off

Location Relay CTR 51P 50P

Feeder To RMU14

SUB002 (SWB05-CB07)

GE F650 300 CS – 1

Curve A TD – 0.1


Feeder To RMU11

SUB002 (SWB05-CB06)

GE F650 300 CS – 0.48 Curve A TD – 0.1

Pickup – 2.9 Time setting – 0.25 s

Feeder To RMU13

SUB003 (SWB06-CB06)

GE F650 300 CS – 1

Curve A TD – 0.1


Feeder To RMU12

SUB003 (SWB06-CB07)

GE F650 300 CS – 0.48 Curve A TD – 0.1

Pickup – 2.9 Time setting – 0.25 s

ARC FLASH STUDIES - Murdoch University · 2016. 4. 18. · arc flash calculations were conducted...

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