CIRCUIT BREAKER AND SWITCHGEAR HANDBOOK VOLUME 4.pdf

8/17/2019 CIRCUIT BREAKER AND SWITCHGEAR HANDBOOK VOLUME 4.pdf

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Circuit Breakers andSwitchgear Handbook

Volume 4

Published by The Electricity Forum

The Electricity Forum215 -1885 Clements Road

Pickering, Ontario L1W 3V4Tel: (905) 686-1040 Fax: (905) 686 1078

E-mail: [email protected]

The Electricity Forum Inc.One Franklin Square, Suite 402

Geneva, New York 14456Tel: (315) 789-8323 Fax: (315) 789 8940

E-mail: [email protected]

Visit our website at

www.electr i c i tyforum.com


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2 ircuit Breaker and Switchgear Handbook - Vol. 4

The Electricity ForumA Division of the Hurst Communications Group Inc.

All rights reserved. No part of this book may be reproduced without

the written permission of the publisher.ISBN-978-1-897474-10-5

The Electricity Forum

215 - 1885 Clements Road, Pickering, ON L1W 3V4

© The Electricity Forum 2008

P r i n t e d i n C a n a d a

CIRCUIT BREAKER AND

SWITCHGEAR HANDBOOKVOLUME 4

Publisher & Executive Editor

Randolph W. Hurst

Editor

Don Horne

Cover Design

Alla Krutous

Layout

Cara Perrier

Handbook Sales

Nicola Jones

Advertising Sales

Carol Gardner

Tammy Williams


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4 Circuit Breaker and Switchgear Handbook - Vol. 4


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Circuit Breaker and Switchgear Handbook - Vol. 4 5

ABSTRACT

In today’s infrared community, we talk a great deal about“What is safe?” when it comes to electrical equipment and inter-nal-arc flash. Thermographers generally assume that with thecovers and doors closed, the switchgear is in a totally safe work condition. This paper explores the differences in switchgearwith respect to internal-arc flash and how this affects the safetyof the thermographer. The presentation incorporates a workedexample of an internal-arc flash test on a piece of 15kVswitchgear incorporating infrared windows, including actual

video footage of an arc-flash test occurring.

INTRODUCTION

Infrared thermography of electrical switchgear is a well-known and accepted predictive mainte-nance technique. Working with any kind of live, electrical equipment incorporates anelement of risk, but how does this risk manifest itself in relation to arc flash andinfrared thermography? Is our electricalswitchgear totally safe?

RECOGNIZING THE FAULT TYPE: BOLT-ED FAULTS OR ARCING FAULTS?

Today, the infrared community talksa great deal about “arc fault” or “arc flash”,but to understand what an arc fault actuallyis and how it affects switchgear, one mustfirst appreciate the difference between an arc fault and another,albeit less common, occurrence known as a “bolted fault”.

A bolted fault is basically a dead short via a highly con-ductive medium between two different phases or between aphase and Earth conductor. Figure 1 shows a diagrammaticexample of a bolted fault situation.

Since the fault current is confined to the relevant conduc-tor, there is usually no energy release outside of the system’s

conductive path.As is commonly known, an arcing fault is very dangerous

and, as we shall see, quite different from a bolted fault. An arc-ing fault is also a short circuit between phases or between phaseand Earth, but this time the short circuit current flows throughthe air, rather than through an actual conducting material such,as copper.

When an arc fault occurs, temperatures at the fault loca-tion increase instantly to over 5,000ºF (the melting point of cop-per is 1,983ºF). Vaporization of internal components resultingfrom this massive temperature increase, along with the super-

heated ball of gas, causes an explosive blast that bombards theswitchgear with high intensity pressure waves.

Under arc fault conditions, a huge amount of damage iscaused to the equipment, and a significant injury hazard is posedto any personnel in the vicinity at the time of the fault.

Arc faults are usually caused by one of the followingdynamic interventions into an otherwise static system:

Dropped toolsInduced airflowDielectric breakdown of insulationMechanical failure

So, now that we understand the dif-ference between the two fault occurrences,we can look at the switchgear design in rela-tion to them.

HOW DOES THIS AFFECT THESWITCHGEAR?

Traditionally, switchgear wasdesigned, tested, and rated to withstand thebolted fault current level that could occur, asthis is always higher than the arc fault level,

due to the lower current impedance of the cross phase conduc-tor in comparison to air. The switchgear was designed to such an

IS ELECTRICAL SWITCHGEAR SAFE?

Tony Holliday, Hawk IR International Ltd.

Figure 1. Diagrammatic representation of a bolted fault

Figure 2. Diagrammatic representation of an arc fault


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extent that the bolted fault current did not exceed the maximumcurrent-carrying capacity of the conductors and, as such, theequipment was not damaged due to the fault.

This current level is called AIC, which stands for “AmpsInterrupt Capacity” and can be found on a metal plate on theswitchgear that has been type tested against this type of faultoccurrence. The designation will show the bolted fault leveltested (xxkA) for a time period commensurate with the antici-pated cycle time of the upstream interrupter, be it a fuse or a

breaker.However, as we have seen, there is a vast difference

between the effects of a bolted fault and an arc fault, and a suc-cessful bolted fault type test does not mean that the switchgearcan subsequently withstand an arc fault - even at a lower shortcircuit current level - which is much more violent.

Today, arc-resistant switchgear undergo arc fault typetests in order to satisfy the market that the equipment is indeedsafe, should either fault occur at the tested ENERGY LEVEL orless.

It is not correct to associate arc flash danger solely withvoltage. Energy = Voltage x Current x Time. So, it is quite pos-sible for the arc flash energy level on 480V equipment to be as

high as or higher than on 4160V or 15kV equipment.See Figure 3 for a fault-tested piece of medium voltage

equipment.

It is important to realize that arc-resistant switchgear isdesigned to contain the arc by-products and vent the gases in asafe manner. Protection should include against flying objects,flash burn, escaped hot gases, and glowing particles whether theperson is outside the enclosure or inside the adjacent live com-partment during maintenance. In order to maintain the arc-resistant protection of the switchgear during operation, all doors

and covers must be closed and latched or bolted, while ener-gized.

IS OUR INSTALLED SWITCHGEAR ARC-RESISTANT?

The straight answer is most probably no. Arc-resistantswitchgear is expensive due to its construction and certificationrequirements, and as such, this type of equipment is in theminority in today’s workplace. It is a recognized fact that shoulda fault occur in a non-arc-resistant switchgear, then not only willthe equipment be destroyed beyond repair, but it is normal forsuch explosions to cause covers/doors to become forciblydetached from the equipment.

What this means is that, regardless of whether you

remove the covers to perform an infrared survey, should an arcfault occur, the cover will be ejected from the cubicle, and theoperator will be exposed to the residual fault condition plus theimpact from the flying cover.

Figure 4 shows the result of an arc fault explosion in a4kV starter cubicle.

This panel is not arc-resistant and as can be seen, the rearpanel was blown completely off. This is the image that everyelectrical thermographer must have in their mind BEFOREentering a live, operating switch room. Just because the coversare closed does NOT mean you are safe.

WHERE DO WE GO FROM HERE?

There are a number of points the infrared thermographerneeds to remember when dealing with potential arc fault occur-rences:

1. Arc faults do not simply happen. They are the result of a change in the static nature of the switchgear.

2. If possible, check the operating schedule of the equip-ment you will be surveying. If a fault is to occur other than fromhuman intervention, then it is likely to happen when a circuitcloses and/or load increases.

3. Ensure that predictive maintenance is carried out reg-ularly to reduce the potential for mechanical failure.

4. Do NOT remove covers or doors to perform theinfrared inspection, as this is more likely to cause an arc faultthan prevent one.

SUMMARY

With run-to-failure being an unacceptable option, electri-

cal infrared thermography must continue. However, it must beexecuted in a manner that is as safe as possible, and operatorsperforming the inspections must be trained to understand thedangers and risks associated with the work.

Ultimately, live electrical equipment is extremely danger-ous, regardless of whether the covers are removed or not, and itis important that the infrared community not become blaséabout the safety requirements needed to carry out infrared ther-mography on such equipment. The recent high-profile coveragerelating to arc fault incidents can only serve us well; however,we need to be careful that we do not fall into the trap of “a littleknowledge is a dangerous thing”. There are standards such asNFPA70E in the workplace today to assist not only the thermo-

Figure 3. Arc-ResistantSwitchgear, GEPower/VAC.

Figure 4. 4kV starter cellExplosion caused due to a failure of the leads feeding the motor.


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INTRODUCTION

As more and more emphasis is placed on personnel safe-ty in the workplace, the need for safer system planning, proce-dures, tools, and products continually increases. Although theprobability of an arcing fault inside metal-clad switchgear islow, the cost in terms of personnel safety and equipment dam-age is high when an arcing fault occurs. OSHA, NFPA, andIEEE have recognized the hazards associated with arcing faultsin electrical systems by specifically addressing measures tominimize the possibility of an arcing fault, and to mitigate itseffects on personnel. This paper discusses these issues, empha-sizing the role that arc resistant switchgear plays in providing asafer work environment.

COMMON CAUSES OF ARC FAULTS IN SWITCHGEAR

Arc faults within switchgear can be caused by a numberof factors, including:

a. Loss of insulating properties resulting from elevatedtemperatures. This can be caused by applying the equipment

above its continuous rating and from improperly torqued oraligned contact joints. Thermographic monitoring may be usedto monitor temperature rises so that preventive measures can betaken.

b. The presence of dust, contamination, or moisture oninsulating surfaces. These conditions lead to tracking acrossinsulating surfaces, providing a path for conduction betweentwo different potentials. Heaters can be effective in minimizingcondensation on internal conductors. The condition of the insu-lation should be monitored as part of an effective maintenanceprogram, especially in harsher environments.

c. Voids in insulation, which eventually lead to failure of the insulation when stressed at high voltages. Epoxy bus insula-

tion has demonstrated a greatly improved life expectancy basedon its homogeneous composition.d. Human error. The implementation of disciplined work

procedures, effective personnel training, and proper tools canminimize the possibility of human error causing an arc faultincident.

SUMMARY OF ARC FAULT CHARACTERISTICS

An arc fault within an arc-resistant switchgear enclosureis typically characterized by the following four phases:

a. Compression phase: The compression phase starts att=0 when the arc starts to burn and continues until the pressurecan no longer increase.

b. Expansion phase: The expansion phase starts when themaximum pressure has been reached and the pressure relief flaps have opened. This phase lasts approximately 5 to 10 mil-liseconds.

c. Emission phase: The emission phase occurs when allthe necessary pressure relief flaps have opened so that inside air,

where the arc burns, is exhausted outside the cell. This contin-ues until the gas in the cubicle reaches the arc temperature. Thisphase typically lasts 50 to 100 milliseconds in small cubicles,and in larger cubicles it can be considerably longer.

d. Thermal phase: The thermal phase lasts until the arc isextinguished. An arc emits radiation because of its extremelyhigh temperature (10,000 to 20,000 degrees K in the center).The thermal energy emitted during this phase heats, melts, andvaporizes parts of the cubicles and the components mounted inthem. The greatest damage typically occurs during this phase,when the thermal stress caused by the radiated heat is responsi-ble for severe burns and ignition of clothing.

INDUSTRY RECOGNITION OF ARC FLASH HAZARDS

The pertinent documents governing arc flash hazards are:• OSHA 29 Code of Federal Regulations (CFR) Part

1910, Subpart S• NFPA 70E-2000, “Standard for Electrical Safety

Requirements for Employee Workplaces”• IEEE 1584-2002, “Guide for Arc Flash Hazard

Analysis”• IEEE C37.20.7-2001, “IEEE Guide for Testing

Medium-Voltage Metal-Enclosed Switchgear for InternalArcing Faults”

OSHA 29 CFR 1910, Subpart S mandates that safe prac-tices be implemented to prevent shock or injuries due to direct

or indirect contact with energized conductors. It also addressesthe fact that workers who may be exposed to electrical hazardsmust be qualified and that provisions for the appropriate person-nel protective equipment must be made.

NFPA 70E details the steps needed to comply with theOSHA requirements. Specifically, NFPA 70E addresses:

• Worker training• Appropriate and safe tools• Safety program with responsibilities clearly identified• Arc flash hazard calculations• Personal protective equipment (PPE)• Equipment warning labels

MEDIUM VOLTAGE, METAL-CLAD ARC RESISTANTSWITCHGEAR:

ENHANCING WORKPLACE SAFETYThomas P. McNamara, P.E., Manager, Development Engineering, ABB Inc., Power Technologies Medium

Voltage


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IEEE Standard 1584-2002 provides a means to calculatethe incident energy resulting from an arc flash.

Per NFPA 70E, incident energy is “the amount of energyimpressed on a surface, a certain distance from the source, gen-erated during an electrical arc event”.

It is not considered safe to work around energized equip-ment generally. However, if and when this is deemed necessaryby the owner, the use of the properly rated PPE by properlytrained personnel is required.

The incident energy level is used to determine the flashprotection boundary (the surrounding area where the incidentenergy is equal to or greater than 1.2 calories/cm2). This inci-dent energy level exposes personnel to potential second-degreeburns.

The incident energy also is used to determine the appro-priate PPE required for the application. The incident energylevel is dependent on various factors, including system operat-ing configurations, voltage, length of the arc, arcing current,protective device settings, time to clear, and distance from arcfault to workers. In a given work environment, the calculationneeds to be performed at various locations where any of thesevariables will change. Note that the highest level of arcing cur-

rent does not always result in the highest incident energy level.A lower level of current that results in a longer arcing durationmay cause higher incident energy levels at the workers’ location.Care must be exercised to prescribe the appropriate PPE for theapplication. Overly conservative requirements can restrict work-er movement, vision, hearing, and comfort level unnecessarily.This in itself can be the cause of an unsafe situation.

An incident energy level above 40 cal/cm2 is consideredunsafe, even with the prescribed PPE.

Regardless of the incident energy level, additional practi-cal steps can be taken to improve the safety level of the work environment. These include the use of arc resistant switchgear,provisions for closed door or remote circuit breaker racking andoperation, and special protective schemes to minimize arc faultdurations and magnitudes.

OVERVIEW - EVOLUTION OF ARC RESISTANTSWITCHGEAR STANDARDS

Interest in arc resistant switchgear designs and ratingswas evident thirty years ago in Europe, where medium voltageswitchgear typically included uninsulated bus, which increasedthe likelihood of an arc fault occurrence. As a result, a draftAnnex AA to IEC 298 (currently IEC60298), “A.C. Metal-Enclosed Switchgear and Controlgear for Rated Voltages Above1 kV and Up to and Including 52 kV”, was created in 1976 andwas eventually approved by the IEC in 1981.

As a result of the interest in improving safety in the

workplace in North America, Annex AA was used as a guidelinein the preparation of the EEMAC G14-1-1987, “Procedure forTesting the Resistance of Metal-Clad Switchgear UnderConditions of Arcing Due to an Internal Fault”. Refinementswere made in EEMAC G14-1 based on “lessons learned” in thepreceding years of applying Annex AA. EEMAC G14-1-1987defines three accessibility types:

Type A: “switchgear with arc resistant construction at thefront only”

Type B: “switchgear with arc resistant construction at thefront, back and sides”

Type C: “switchgear with arc resistant construction at thefront, back and sides, and between compartments within the

same cell or adjacent cells” (exception: adjacent main bus com-partments)

IEEE C37.20.7-2001, “IEEE Guide for Testing Medium-Voltage Metal-Enclosed Switchgear for Internal Arcing Faults”,is based on these two predecessor documents, but also includesimprovements as deemed appropriate. This document is current-ly being reviewed by the working group and will be refined fur-ther in the next revision. Part of this revision process willinclude an attempt to harmonize the requirements with the cur-

rent IEC practices. IEEE C37.20.7 also defines three accessibil-ity types:

Type 1: “switchgear with arc resistant designs or featuresat the freely accessible front of the equipment only”.

Type 2: “switchgear with arc resistant designs or featuresat the freely accessible exterior (front, back, and sides) of theequipment only”.

Annex A to IEEE C37.20.7-2001 addresses a third acces-sibility type that addresses arc-resistance designs or featuresbetween adjacent compartments within the same cell or adjacentcells (with the exception of the main bus compartments). Theseare identified by the use of suffix “C” as follows:

Type 1C: “switchgear with arc resistant designs or fea-

tures at the freely accessible front of the equipment only”, alongwith arc-resistance designs or features between adjacent com-partments within the same cell or adjacent cells (with the excep-tion of the main bus compartments)

Type 2C: “switchgear with arc-resistant designs or fea-tures at the freely accessible exterior (front, back, and sides) of the equipment only”, along with arc-resistance designs or fea-tures between adjacent compartments within the same cell oradjacent cells (with the exception of the main bus compart-ments)

The testing associated with each of these documents isbased on all covers and doors being properly secured, and allvents and vent flaps set to their correct operating positions.Therefore, the ratings assigned based on testing to these stan-dards apply only under these conditions.

Testing is performed at the prescribed voltage and currentlevels with the specified flammable cotton indicators strategi-cally positioned to detect the escape of hazardous gases.Assessment criteria include:

1. Door, covers, etc. do not open. Bowing or other distor-tion is permitted except on those which are to be used to mountrelays, meters, etc.

2. That no parts are ejected into the vertical plane definedby the accessibility type

3. There are no openings caused by direct contact with anarc

4. That no indicators ignite as a result of escaping gases

or particles5. That all grounding connections remain effective

CHARACTERISTICS OF ARC RESISTANT SWITCHGEARDESIGNS

Arc resistant switchgear is characterized by some specialdesign features necessary to achieve the required ratings.Typically, these include:

a. Robust construction to contain the internal arc pressureand direct it to the exhaust chambers designed for the purposeof safely venting the gases

b. Movable vent flaps that open due to the arc fault pres-sure, increasing the volume containing the arc products


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c. Special ventilation designs with flaps that are openunder normal operating conditions, but slam shut when an arcfault occurs

d. Closed door circuit breaker racking and operationABB’s SafeGear utilizes a patented series of vent flaps in

conjunction with an arc chamber to safely vent the arc gasesaway from personnel. This design makes it possible to stack thecircuit breakers two-high within one cell.

Front doors, rear and side panels are designed, secured,and tested to ensure that they withstand the potentially highpressures until the relief flaps open and pressure subsides, with-out being blown from the cubicle or allowing dangerous hotgases to be released to the front, rear, or sides of the switchgear.

Doors are reinforced with channel steel, and secured withspecial hinges and hardware. Interlocking flanges and gasketmaterial are used to seal in flames and keep hot gases fromigniting flammable materials near the switchgear.

The use of a double wall construction between cells hasbeen demonstrated to be very effective in withstanding the heatand pressure created by the arc fault. The heat dissipation andresistance to burnthrough is enhanced considerably by the use of double 14 gauge side sheets separated by an air gap of approxi-mately 3/16 inch.

The integrity of the low-voltage control and protectivedevice circuitry is critical. Low-voltage compartments, whichcontain the protective relays, meters, devices, and wiring,

should be separate reinforced modules. This protects not onlythe devices themselves, but the control bus and wiring whichmay otherwise be destroyed as a result of the arc fault. This isextremely important as the protective scheme is being relied onto limit the duration of the arc fault.

Consideration must also be given to provide sufficientclearance above the switchgear to allow the gases to be dis-persed properly and not to be reflected back into the area thatcould be occupied by personnel.

Where appropriate clearances are not possible due to thedesign of the building, an exhaust plenum can be provided tosafely vent the gases outside the building to an area that is notaccessible to personnel.

The plenum design must be tested to verify that thepotential back pressure does not cause a failure of the arc resist-ant integrity of the equipment.

Figure 1. Internal horizontal and vertical arc chamber vents arc gases safely away frompersonnel.

Figure 2. Typical pressure vs. time relationship for switchgear internal arc fault.

Figure 3. Successful arc test on 15 kV metal-clad switchgear.


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SYSTEM PROTECTION APPROACHES

The system protection scheme should be designed tolimit the total energy that results from internal arc faults, andspecifically, to limit the current magnitude and duration to val-ues that are within the arc-resistant ratings of the switchgear.Various approaches can be used to achieve this, including:

1. Arc detection system: Very fast identification of an arc-ing fault can be achieved by sensing a combination of light,sound, pressure, and current rate of rise. Using these parame-ters, an arcing fault can be identified in 2 to 4 milliseconds, atwhich time a trip signal is sent to the circuit breakers supplyingpower to the fault. In this situation, the equipment is subjectedto the peak pressure because of the tripping time of the circuitbreaker, but the duration of the fault, and therefore, the overallenergy level, is reduced. Peak pressure occurs within approxi-

mately 20 milliseconds. Total clearing time with this approachwill be approximately 70 to 100 milliseconds.

2. High-speed fault making devices: Using sensors simi-lar to those described above for the arc detection system, uponsensing an arcing fault, a very high speed fault making devicecan be activated to apply a three-phase fault on the power sys-tem. The energy is diverted from the arcing fault to the three-phase bus circuit, which is designed to withstand this energy.This effectively removes the source of energy to the destructive

arcing fault. Simultaneously, a trip signal is sent to the circuitbreakers supplying power to the faulted area. As in the arcdetection system above, the total clearing time will be approxi-

mately 70 to 100 milliseconds.However, the energy is now contained in the bus bars.

The arcing fault energy was diverted within 4 to 5 milliseconds.Therefore, the danger and destruction caused by the arcing faultis limited significantly. The three-phase fault is applied beforethe switchgear is subjected to the peak pressure of the arcingfault. The resulting display and equipment damage is negligible.

3. Differential relaying scheme: By monitoring and sum-ming the currents flowing in and out of the defined protectivezone, the differential scheme can be set up to be very sensitiveand to operate very quickly. When the sum of the currents in andout of the protective zone do not equal zero, the high speed dif-ferential relay picks up and trips the appropriate circuit breakersthat are supplying power to the zone. With high speed differen-tial relaying, the total interruption time will be less than 100milliseconds. Although this scheme is typically fast, sensitive,and limits energy by reducing the fault duration, it only protectsthe defined differential zone.

4. Grounding schemes and ground fault protection:i. Solidly grounded system: Ground fault protection can

be used to sense and interrupt ground fault currents. With nointentional impedance in the ground return circuit, ground cur-

Figure 4. Exhaust plenum mounted on roof of two-high switchgear in PDC building.

Figure 5. High-speed fault-making device limits destructive energy significantly

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rents can be high. Settings dictated by coordination withupstream and downstream devices can cause tripping to bedelayed. Additional protection, e.g., differential zone protection,is advisable.

ii. Low-resistance grounded system: The low-resistancegrounding system reduces the probability of a single phase-to-ground arcing fault. If one occurs, it may evolve into a multi-phase arcing fault. Ground fault relaying should be set to quick-ly identify this condition and remove all power sources supply-

ing the fault.iii. High resistance grounded system: With the ground

current limited by the high resistance, system operation can con-tinue after the first phase-to-ground fault occurs. However, theground fault should be located and removed quickly to avoidovervoltage stresses, which increase the probability of a secondphase to ground fault.

iv. Ungrounded system: Since the ground current is lim-ited by the phase-to-ground capacitive reactance, system opera-tion can continue after the first phase-to-ground fault occurs.Similar to the high resistance grounded system, the ground faultshould be located and removed quickly to avoid overvoltagestresses, which increase the probability of a second phase-to-

ground fault.

5. Partial discharge monitoring: A method of predictingpotential failures is to monitor switchgear insulation for partialdischarge levels while in service. The data obtained can be usedto identify trends over time, which enables the user to correctthe problem before catastrophic failure occurs.

SUMMARY

Metal-clad switchgear, with fully Insulated primary con-ductors, major parts of primary circuits isolated in groundedmetal, and primary circuits isolated from secondary circuits bygrounded metal, is designed to minimize the potential for inter-nal arc faults. However, if and when they occur, arc faults can becatastrophic in terms of danger to personnel and destruction of equipment. Proper application, maintenance, and operation byqualified personnel can further reduce the probability of internalarc faults.

With ever increasing interest in workplace safety, theneed to address the hazards of arcing faults and arc flash is rec-ognized throughout the electrical industry. OSHA, NFPA, andIEEE have each published documents that cover the require-ments and guidelines associated with these potential issues.OSHA 29 CFR 1910, Subpart S mandates the requirements,NFPA 70E defines the steps necessary to meet the OSHArequirements, and IEEE 1584 provides a means to calculate theincident energies, which enable the user to prescribe the appro-

priate personnel protective equipment. In selecting the properpersonnel protective equipment, note that the highest arc faultcurrents do not always result in the highest incident energy. Alower arc fault current for a longer duration may result in a high-er incident energy level than a high arc fault current for a shortduration.

Arc-resistant switchgear can provide an additional levelof safety over conventional switchgear, by directing the arcgases, in the event of an internal arc fault, away from the areawhere workers may be present (in front of, beside, or behind theswitchgear). The industry standards governing the arc testing of arc resistant switchgear have evolved from IEC in the 1970s, toEEMAC in the late 1980s, to IEEE in 2001.

Protective devices and schemes can also be used toreduce incident energy levels by quickly identifying arc faultsand minimizing the associated destructive energy. This can bedone by reducing the arc fault current magnitude and/or timeduration. If the protective scheme is dependent on controlpower, it is important to ensure that the low voltage control busis designed in such a way that it will not be destroyed in theevent of an internal arc fault.

BIBLIOGRAPHYOSHA 29 Code of Federal Regulations Part 1910,

Subpart S“Standard for Electrical Safety Requirements for

Employee Workplaces”, NFPA 70 E-2000“IEEE Guide for Testing Medium-Voltage Metal-

Enclosed Switchgear for Internal Arcing Faults” IEEE StdC37.20.7-2001

“Procedure for Testing the Resistance of Metal-CladSwitchgear Under Conditions of Arcing Due to an InternalFault”, EEMAC G14-1-1987

“Guide for Performing Arc-Flash Hazard Calculations”,IEEE Std 1584 - 2002

“Performing Arc-flash Hazard Calculations”, C. M.Wellman and L. B. McClung, Electrical Contracting &Engineering News (March 2003)

”Electric Arc Hazards and Clothing”, Hugh Hoagland,Dr. Tom Neal, Dr. Stephen Cress, Electric Energy (Fall, 2001)

“Improved Switchgear Safety Through Arc ResistantConstruction”, Paul Thompson, E. John Saleeby”, 1994 ElectricUtility Conference

“Draft Guide for Application of Equipment Qualified asMedium-Voltage Metal-Enclosed Arc Resistant Switchgear”,IEEE PC37.20.7a/D1 (September 17, 2002)


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INTRODUCTION

In today’s ever changing environment of electrical powerdistribution equipment and systems, safety and reliability arebecoming the focal point of utility and industrial switchgearusers. Many of these locations have upgraded their systems byconverting older air circuit breakers to vacuum or by orderingnew systems that are “Arc Resistant”. However, many are notaware of the opportunity to upgrade existing switchgear cubi-cles to arc resistant retrofits achieving optimum safety for oper-ating personnel and reliability of installed systems. Arc Proof

retrofits of existing metal clad and metal enclosed switchgear isavailable for lineups of most manufacturers and vintages.

Members of governing bodies (such as the NFPA 70E)are becoming more concerned about an increasing number of accidents and injuries from electric arcing faults. Extreme tem-peratures and pressures as well as electromagnetic radiation areall effects that need to be dealt with to provide optimum safetyfor plant operations personnel. Incident energy and arc flashboundary are becoming increasingly important in the everydayoperation of power distribution systems.

New switchgear installations require a more stringentstandard than older vintages. Associations such as EEMAC(Electrical Equipment Manufacturers Association of Canada),IEEE (Industrial Electrical & Electronics Engineering Society),IEC (International Electrotechnical Commission) are specifyingthe requirements for new safety features in switchgear. Throughthe door racking of circuit breakers, separate instrument sec-tions and various other features are now standard on new equip-ment to provide additional safety for operators. New switchgearcan also be ordered as arc resistant, providing the highest levelof safety to operating personnel by reflecting internal arc

byproducts in a safe direction.

The following article discusses the options available forupgrading previously installed medium-voltage switchgear to anarc resistant design. The designs discussed in this article havebeen tested to EEMAC G14 -1 and meet IEEE standard C37-20-7. This process can apply to commonly found utility and indus-trial installations throughout North America.

ARC RESISTANT SWITCHGEAR RETROFITS

Magna Electric


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ELECTRICAL FAULTS & ARCS

There are a variety of circumstances that result in inter-nal arcs in electrical switchgear. Often times this failure occurswhen the breaker fails during routine switching or when clear-ing a through fault. A dangerous situation also exists when abreaker fails to properly open prior to removal or insertion.Other causes of internal failure are due to partial dischargeactivity that weakens the insulation over time. Normally, any

line surges on equipment with weakened insulation are subjectto internal failure. Operational mishaps can occur to cause inter-nal faults such as tools, jumpers or other equipment left in acubicle during routine maintenance checks.

INTERNAL FAULTS IN SWITCHGEAR

The extent of protection againstoccurrence of internal faults varies

depending upon the type of switchgearinstalled. The lowest

level is plain Metal-Enclosed switchgear.

Mid-level protectionis found in the vari-ous forms of

“Hybrid” Metal-Enclosed and the high-

est-level protection isMetal-Clad. Should, how-

ever, an internal fault occur, none of the above is designed towithstand its effects. There is much confusion with the throughfault interrupting capability of the switchgear as also applyingto an internal fault withstand capability. This is not the case.

INTERNAL CONSEQUENCES

When an internal arc occurs in a switchgear cubicle,there are a variety of phenomena that occur. Depending on the

amount of available fault current and its duration, a certainquantity of hot gases, hot glowing particles and super heated airare produced. There are also potentially toxic components (frominsulation and other materials) and vaporized metal particles(plasma). Another major occurrence in this situation is a suddenlarge internal pressure rise.

EXTERNAL CONSEQUENCES

There are a number of external consequences that occurduring a switchgear arc and fail-ure. Pressure will force particlesand gases out of holes, coolingvents and any gaps. With nodesigned controlled escape point,

the weakest part of a gear willfail. Pressure at the front doorcan be between 50,000 and100,000 pounds static. Front orrear doors are most likely pointsof failure leading to personnelinjury. All of the above occurs inless than 10 cycles.

This normally is notenough time for a protectionrelay and upstream breaker toreact.

There are up to 4 stages of events during an internal fault.

Stage 1 is the compressionstage and starts at “Arc Event”time zero and continues to apoint of maximum internal pres-sure. (less than 10 cycles)

Stage 2 is the expansionstage and starts when the pres-sure relief vent begins to open,ending gas flow. This stage ischaracterized by wave motionand possible under-pressure witha duration of 5 to 10 millisec-onds.

Stage 3, the emissionstage, starts when the pressurerelief vent has opened and endswhen the gas in the cubiclereaches arc temperature.Duration of stage 3 is typically50 to 100 milliseconds.

The thermal stage in thisprocess is stage 4 and lasts untilthe arc is extinguished and allcombustible material has beenconsumed. The greatest damageto the equipment occurs duringthis last stage.

ARC RESISTANT SWITCHGEAR TYPES

Based on the EEMAC standards, there are 3 types of arcresistant switchgear. Type A requires protection from the effectsof an internal arc in the front of cubicle to a height of 2 meters.Type B provides protection in the front, rear & exposed side of cubicle to a height of 2 meters. Non exposed sides are excludedin type B. The last type is type C which is the same as type Bwith the additional provision of inter-compartmental protectionwith the exception of the main bus compartment. EEMAC alsorequires that the building housing the switchgear be consideredin the overall design by the end user. IEEE is similar but con-tains some variations.


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RETROFITTING EXISTING SWITCHGEAR TO ARC PROOF

Switchgear retrofits toarc resistant design are avail-able for most manufacturersand also for most vintages of switchgear. Tested designsmeet all EEMAC and IEEEstandards for protection.

Switchgear cubicleswith newly installed vacuum

breakers are prime candidates for cubicle upgrades to arc resist-ant. Vacuum retrofits have already extended the life of theswitchgear by adding a new breaker. The circuit breaker is thedevice that normally shortens the overall life due to characteris-tically having numerous moving parts. The switchgear cubiclesthemselves will last for a very long time due to the fact that theyhave limited moving components.

Modern switchgear arc resistant retrofits allow for sys-tem switchgear to be upgraded to include the cubicle front doorand steel framework and associated protection or metering if sodesired. The doors are a heavy duty design with multiple hinges

and locking devices to guarantee that arc blast does not escapethrough the front door of the switchgear. The extra strengthlocking devices on the handles work in conjunction with thecubicle modification to ensure the door cannot open under theextreme force. In order to mount such a door a heavy duty steelframe is also installed.

One of the major exposures that operating personnelexperience when operating metal clad switchgear is during theracking in and racking out of circuit breakers. Anyone that hasperformed this operation recognizes a distinct sound that occurswhen the breaker is just making or breaking the primary connec-tion of the power stabs from the finger clusters to the main busstabs. That distinct sound is air ionizing and this ionized air can

compromise the insulation value of the phase to phase dielectricinside the cubicle.

Through the door racking is a requirement of allswitchgear arc resistance retrofits. This upgrade means that theoperator will rack the circuit breaker in and out with the doorclosed. The possibility of exposure during failure is extremelylimited during this process.

One of the major factors in releasing energy containedinside switchgear cubicles is to provide an intricate venting sys-tem. It is common when a switchgear cubicle fails that the dam-age cascades to other cubicles or to other equipment located inthe same room. A cubicle failure can destroy overhead cabletray or adjacent control system mimic panels or control sectionsresulting in weeks or months of downtime for equipment andsystems outside the immediate cubicle area.

The venting system employed in arc resistant retrofits isa key to releasing the energy in a controlled manner. Optimumsafety of the personnel, as well as decreased damage to equip-ment in the surrounding area, is the key to each individualdesign. All this means a higher degree of safety for site person-nel and limiting the degree of downtime suffered.

Outdoor houses are particularly susceptible to majordamage when a breaker cubicle or cable entry section fails. It iscommon that smoke, heat and flash damage can virtually immo-bilize entire outdoor switchgear and control houses. Venting tooutdoor is a key to limiting the damage.


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TESTING DETAILS

Retrofit designs are tested at acertified laboratory on typicalswitchgear cubicles to meet the stan-dards as discussed in this article. Aninternal short circuit is established totest the retrofit’s capability to with-stand the sudden temperature andpressure rise. Indicators are located atnumerous points within 10 centime-ters of the switchgear. The internalfault is set up to establish the maxi-mum stress on the design and estab-lish the capability of the arc resistantretrofit. Typically, test currentsexceeded 30,000 Amps RMS with apeak of 75,000 Amps for a full 60cycles.

SUMMARY

Operations personnel areexposed to potential hazards duringnormal operation of power distributionswitchgear due to the extremely highlevels of energy that are involved whenswitchgear fails. Arc resistant retrofitsare a great option for life extension,improved productivity and, mostimportantly, operating personnel safety.These retrofits are available for mostmanufacturers and vintages of switchgear and should be consideredfor any application where the safety of personnel or the reliability of equip-ment is a major concern.


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INTRODUCTION

The design of modern high-voltage puffer-type SF6 gascircuit breakers is based on the switching of two parallel contactsets. First, the low-resistance silver-plated contacts or the maincontacts are specifically designed to carry the load current with-out any excessive temperature rise. Second, following the main

contact part, the tungsten-copper arcing contacts are finallyopened, thus initiating arc quenching and current interruption.

To assess the condition of the breaker contacts, the maincontact resistance measurement is usually performed. However,the static resistance measured when the breaker remains in aclosed position does not give any indication of the condition of the arcing contacts. To evaluate the latter’s condition, an inter-nal inspection can be done, but time-consuming and costlymaintenance procedures must be followed in order to securelyhandle the SF6 gas and arc by-products. It should be remem-bered that excessive arcing-contact wear and/or misalignmentmay result in a decrease of the circuit breaker’s breaking capac-ity.

The dynamic contact resistance measurement (DRM)was developed over 10 years ago to assess the condition of thearcing contacts without dismantling the breaker. This method isno longer widely used since the interpretation of the resistancecurve remains ambiguous. Previously published test resultsusually depicted several spikes [1-3] in the resistance curvewhich could be the result of a partial contact part during the con-tact movement.

The following paper presents a new dynamic-contact-resistance measurement method that has been validated by fieldtests which were performed on air-blast and SF6 gas circuitbreakers. The new method is based on the breaker contactresistance measurement during an opening operation at lowspeed. After reviewing the characteristics of the dynamic resist-

ance curve and the measuring system and parameters, the paperdeals with relevant values that can be extracted from the resist-ance curve for detecting contact anomalies wear and/or mis-alignment. Finally, case studies are presented and test resultsare discussed. The new method is available through zensol.comas an accessory of the CBA-32P family test instruments.

1. MEASURING SYSTEM AND SENSORS

For dynamic contact resistance measurements (DRMs),three signals must be recorded:

- the injected current (IDC) of at least 100 A in order tominimize relative noise level;

- the voltage drop (VD) across the breaker contacts;

- the breaker contact travel curve.

Since the new DRM method presented in this paper willbe performed during an opening operation at low contact speedwhen the breaker is off-line, some commercial acquisition unitswith the following features may be used:

- 3 analog inputs with at least 12-bit resolution andappropriate range of voltage inputs;

- a sampling frequency of W 10 kHz;- a total acquisition time of 30-100 s;- connection to a portable computer for calculation of

the instantaneous contact resistance (VD/IDC), data analysisand interpretation using dedicated software.

Finally, the following sensors are required:- Hall-effect current sensor allowing accurate measure-

ment of both the current amplitude and the abrupt current vari-ation at the arcing contact part that corresponds to the completebreaker contact opening;

- linear or rotary contact travel sensor depending uponthe breaker technology.

2. MEASURING PARAMETERS

2.1 CLOSING OPERATIONSDRMs during closing operations are not generally useful

since the measurement must be performed during a transientstate, i.e. from open to closed contacts. There are two main rea-sons why the measurement in this condition is impractical:

- the abrupt resistance variation from infinity (open con-tacts) to the arcing contact resistance is difficult to measure,making the resistance level of the arcing contact difficult todetect;

- the transient DC current at the moment of arcing con-tact touch generates undesired noise level and therefore jeopard-

izes the measurement.

2.2 OPENING OPERATIONS AT LOW CONTACT SPEEDDRM should be performed during opening operations at

low contact speed (ª 0.002-0.2 m/s). Figure 1a shows superim-posed typical resistance curves of two consecutive measure-ments at rated speed on break A (Table 1). The two traces havebeen synchronized by superimposing instants of the main con-tact part which is identified as tm in the Figure 1a graph. Notethat no filtering has been applied.

At the rated speed, it can be observed that the resistancecurves are not reproducible from one test to another. Moreover,this phenomenon is more marked in the vicinity of the arcing

A NEW MEASUREMENT METHOD OFTHE DYNAMIC CONTACT RESISTANCE

OF HV CIRCUIT BREAKERSM. Landry, A. Mercier, G. Ouellet, C. Rajotte, J. Caron, M. Roy, Hydro-Québec

Fouad Brikci, Zensol Automation Inc. (CANADA)


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ing an opening operation at low speed where t0 corresponds tothe beginning of the breaker contact motion. In most breakeroperating manuals, the procedure for performing such a lowspeed opening is given. It is always relevant to superimpose thetravel curve of the breaker contact in order to extract diagnosticparameters related to the position of both the main contacts andthe arcing contacts. These parameters are:

- Rp (mW): Average main contact resistance- Dp (mm): Main contact wipe- Da (mm): Arcing contact wipe- Pa (mm): Position of the breaker contacts at

the arcing contact part

3.3 GRAPH OF THE RESISTANCE CURVE AS A FUNCTION OF THE CONTACT TRAVELTo compensate for the fact that the dynamic resistance

curve is measured at a low contact speed that is not necessarilyconstant for the two test series (Fig. 1a), the contact resistancegraph must be plotted as a function of the contact travel (Fig.3b) in order to evaluate two additional parameters for diagnos-ing the arcing contact conditions:

- Ra (mW): Average arcing contact resistance = (SRi=1,N) / N (Fig. 3b), N= Number of samples in the interval Da

- Ra*Da (mW.mm): Area beneath the resistance curve as

a function of the contact travel (Fig. 3b)The latter parameter provides a criterion for evaluating

the global breaker contact wear and/or contact alignment status.Once the graph is plotted, all diagnostic parameters can bededuced, including those in section 3.2. Since this graph can beconsidered as complete for diagnosing the breaker contact con-dition, it will be given for each case study presented in the fol-lowing section.

4. CASE STUDIES

The new DRM method was validated in the field on SF6gas circuit breakers. Three case studies are presented in the fol-lowing section. Table I summarizes the measurement results for

which abnormal values are highlighted.

4.1 CASE STUDY NO. 1: ONE BREAK OF A 315-KV CAPACITOR-BANK SF6 GAS CIR-CUIT BREAKER

Figure 4 presents the DRM results on a break (Break A,Table I) of a 315-kV capacitor-bank SF6 gas circuit breakerwhich has performed 2492 operations. Based on this graph andthe results listed in Table I, it can be deduced that the arcingcontacts are in excellent condition. In fact, the Ra value of 185mW is almost constant throughout the contact motion. Theglobal criteria Ra*Da is also relatively low, i.e. 3.6 mW.mm. Inaddition, the main contact part can be easily detected.

Figure 3 - Parameters to be extracted from the dynamic contact resistance curvea) Contact resistance and contact motion as a function of time b) Contact resistance as a function of contact travel

Figure 4 - DRMs on break A


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4.2 CASE STUDY NO. 2: ONE BREAK OF A 120-KV CAPACITOR-BANK SF6 GAS CIR-CUIT BREAKER

Case study No. 2 (Fig. 5) presents the DRM results on abreak (Break B, Table 1) of a 120-kV capacitor-bank SF6 gascircuit breaker which has performed 687 operations.

In February2000, a major failureoccurred on this circuitbreaker which causedimportant damage tothe surrounding equip-ment. An investigationof the breaker failurerevealed that an arcingcontact tip appeared tohave broken off duringan opening operationand thus impaired thesubsequent closingoperation.

In the fall of 2002, the DRM wasperformed. Based onthe Figure 5a graph, theparameters defined in

section 3 were extractedand listed in the casestudy No. 2 row inTable I. The instanta-neous arcing contactresistance reaches anabnormal peak of 1 mWwhile the average value (Ra) of 420 mW could be interpreted asnormal. The most relevant factor is the product Ra*Da thatreaches 10.3 mW.mm, thus suggesting a contact anomaly. Asmentioned in section 3, this factor represents the cumulativearea beneath the resistance curve, thus summing the resistancevariations or the contact wear during arcing contact opening.

Photos of the moving and fixed arcing contacts of thetested break are shown in Figure 5c.

On the moving arcing contact, it can be observed that onearcing contact tip is off center. This abnormality caused dam-age to the fixed arcing contact (see right-hand side photo). It is

believed that this condition occurred dueto a misalignment of the arcing contacts atthe break assembly. After an arcing con-tact overhaul and careful contact align-ment, the DRM was performed one moretime. Figure 5b presents the measurementresults that showed that the arcing contact

condition was definitely restored. In fact,the Ra value of 173 mW is low.Furthermore, the low Ra*Da value of 3.4mW.mm indicates that the arcing contactis in excellent condition.

4.3 CASE STUDY NO. 3: ONE BREAK OF A 230-KVREACTOR SF6 GAS CIRCUIT BREAKER

Figure 6a presents the DRM resultsfor break D (Table I) for which an internalbreakdown occurred without a major fail-ure. In this case, the Ra value is about 2mW, which indicates very severe damage

to the arcing contacts. The global valueRa*Da of 60 mW.mm is the highest valuethat was ever obtained during the valida-tion test program. The break was disman-tled and arcing traces on both the movingand fixed arcing contacts as well as on thesupporting tube of the main contacts were

observed.For comparison purposes, Figure 6b gives the DRM

results for a normal break (Break E, Table I) of the same circuitbreaker. Based on the curves and the extracted value in Table I,the arcing contacts of this break are clearly in excellent condi-tion. In fact, the Ra value of around 100 mW is almost constant

Break A: Break of a 315-kV capacitor-bank SF6 gas circuit-breaker Break B: Break of a 120-kV capacitor-bank SF6 gas circuit-breakerBreak C: Same as break B, except that arcing contacts were overhauled Break D: Break (with internal restrike) of a 230-kV SF6 gas reactor circuit-breakerBreak E: Same as break D, but without internal restrike

Figure 5 - Dynamic contact resistance measurements on one break of a 120-kV capaci-tor-bank SF6 gas circuit-breaker

a) Dynamic resistance curve before contact dismantlingb) Dynamic resistance curve after contact overhaulc) View of the damaged moving and fixed arcing contacts.


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from the main contact part up to the arcing contact part.

CONCLUSION

This paper presents a new dynamic contact resistancemeasurement method performed during opening operations atlow contact speed aimed at evaluating the breaker conditionwithout dismantling it. Compared to the DRM curves at therated contact speed, the new method allows reproducible curvesto be obtained which are easy to analyze and interpret.

Three signals must be measured: the injected DC currentthat must be produced by a stable source, the voltage dropacross the breaker contacts and the contact travel.

To extract the diagnostic parameters, a dedicated soft-ware program was developed in order to plot the dynamic resist-ance curve as a function of the contact travel, i.e. mW versusmm. Six vital diagnostic parameters values are therefore deter-mined:

- average main contact resistance;- average arcing contact resistance;- main contact wipe;- arcing contact wipe;- position of the breaker contact at thearcing contact part;- and the cumulative area beneath the resistance curve.The last parameter is the most relevant one since it allows

the overall contact wear and/or contact alignment status to beassessed. Moreover, values obtained from different breaker

technologies can be compared. For example, values of about 3mW.mm indicate healthy breaker contacts while values of about10 mW.mm indicate faulty contacts.

The three case studies presented in this paper prove thatthe new DRM method provides vital information about thebreaker contact condition. Without dismantling the breaker, themaintenance crew can thus plan maintenance work for specificbreakers for which the DRMs reveal contact anomalies.

Dr. Fouad Brikci is the President of Zensol Automation Inc.. He

was the first to introduce the concept of truly-computerized test

equipment in the field of circuit breaker analyzers. Dr. Brikci

has developed experience in the fields of electronics, automa-

tion and computer science.

REFERENCES

[1] Salamanca F., Borras F., Eggert H.,Steingräber W., Preventive Diagnosis on High-Voltage CircuitBreakers, Paper No. 120-02, CIGRE Symposium, Berlin, 1993.

[2] Kumar Tyagi R., Singh Sodha N., Condition-Based Maintenance Techniques for EHV-Class CircuitBreakers, 2001 Doble Client Conference.

[3] Ohlen M., Dueck B, Wernli H., DynamicResistance Measurements – A Tool for Circuit BreakerDiagnostics, Stockholm Power Tech International Symposiumon Electric Power Engineering, Vol. 6, p. 108-113, Sweden,June 18-22, 1995.

Figure 6 - DRM results on breaks of a 230-kV reactor SF6 gas circuit-breaker: a) Resistance curve following an internal restrike of the break D b) Normal break E


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ABSTRACT – The purpose of this paper is to examinethe application of low-voltage circuit breakers to control energyreleased during an arc flash occurrence. It contrasts arc-flashincident energy values obtained by calculation with valuesobtained by direct testing. It examines values at low fault cur-rent levels where long duration events may be expected. It alsoreviews the protection afforded by current-limiting circuitbreakers. The paper concludes with an overall discussion of cir-

cuit breaker applications for arc flash energy reduction.

I. INTRODUCTION

The 2004 edition of NFPA 70E, Standard for ElectricalSafety Requirements for Employee Workplaces [1] establishesrequirements associated with electrical arc flash hazards. TheIEEE Guide 1584, “Guide for Performing Arc-Flash HazardCalculations” [2], enumerates methods for numerically quanti-fying energy values associated with an overcurrent protectivedevice (OCPD). Actual values from tests with circuit breakershave not been available to the P1584 committee. The authors of this paper have conducted literally hundreds of tests to deter-mine the arc flash energy values associated with low-voltagecircuit breaker performance. This article will present the testingprotocol, introduce the expectation of values from manufactur-er’s tests and confirm that values from tests are lower than val-ues from IEEE 1584 calculation methods.

II. TESTING PROTOCOL

A major hurdle in determining arc flash energy valuesassociated with the performance of overcurrent protectivedevices has been the absence of a single industry-wide standarddescribing the testing protocol. While efforts are underway toestablish these common requirements, several IEEE publica-tions [3], [4], [5], [6] have established initial baseline testingparameters.

In order to simulate actual low-voltage electrical distribu-

tion equipment, all testing reported upon in this article was per-formed using the “arcs in a box” setup as follows. (See Fig. 1.)Three 3/4” round CU electrodes were mounted inside anunpainted carbon steel enclosure (no cover), 1” from the back.The round electrodes were spaced 1” apart (1.75” center to cen-ter). The 1”spacing is the required phase-to-phase clearancethrough air for low-voltage distribution equipment such as pan-elboards, switchboards, motor control centers and switchgearper low-voltage equipment standards.

A bare 18 AWG copper wire was used to initialize the arcat the bottom end of the round electrodes. Insulating supportblocks were positioned between adjacent electrodes as neededto prevent them from bending due to forces created by the arc

currents. Additionally, as needed, insulating sleeves were addedover the electrodes inside the enclosure, between the bottomsupport block and the inside top of the enclosure, to avoid arc-ing between electrodes, except along the intended exposedlength at the bottom, in the arc initiation area.

Calorimeters were used to obtain the actual arc energymeasurements. A calorimeter is essentially a thin slice of copperheld inside an insulating block. The copper’s exposed side is

painted black and one or more thermocouples are attached on itsopposite side. The exact construction details are contained in[6]. An array of 7 Calorimeters was used, all mounted in frontof the enclosure, 18” away from the centerline of the electrodes(horizontally). The 18” distance was chosen according to [5] asthe “Typical working distance… sum of the distance betweenthe worker standing in front of the equipment, and from thefront of the equipment to the potential arc source inside theequipment” representative of low-voltage motor control centersand panelboards. On the array, 3 calorimeters are mounted in ahorizontal row at the same height as the tip of the electrodes(vertically). A second set of three calorimeters is located in ahorizontal row 6” below the elevation of the electrode tips. Themiddle calorimeter of each set is aligned with the center elec-

trode (side to side). A single additional calorimeter is located 6in above the center electrode tip.

Low-voltage circuit breakers were inserted into the testcircuit electrically ahead of where the 3/4” round CU electrodesenter the enclosure (external & upstream from theenclosure/electrodes).

The OCPD was connected from the test station to its lineside using cables or bus bars sized in accordance with its con-tinuous current rating but not more than 250 KCMIL. The loadside of the OCPD was connected to the 3/4” copper electrodesusing cables or bus bars with the same size restrictions as thoseon the line side. Each set of conductors was as short as practicaland no longer than 4 feet in any case.

The electrical test circuit was calibrated in accordancewith UL 489, UL Standard for Safety for Molded-Case CircuitBreakers [7], Appendix C or American National StandardC37.50-1989, Low-Voltage AC Power Circuit Breakers Used inEnclosures – Test Procedures [8], Section 3.9.3 (which are con-sidered equivalent methods for this purpose).

The data acquisition system was calibrated and capableof recording voltage, current, and calorimeter outputs asrequired by the tests. The temperature acquisition system had aminimum resolution of 0.1°C, a minimum accuracy of 1.5°Cand acquired data for a duration long enough to capture themaximum temperature achieved. The maximum temperaturerise (actual temperature – pretest reading) obtained from any

APPLYING LOW-VOLTAGE CIRCUIT BREAKERS TOLIMIT ARC FLASH ENERGY

George Gregory Fellow Member, IEEE Schneider Electric / Square D Company;

Kevin J. Lippert, Senior Member, IEEE, Eaton Electrical


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calorimeter was multiplied by the constant 0.135 to obtain inci-dent energy in calories/cm 2. Current and voltage data was

acquired at a minimum rate of 10 kHz.The circuit breaker was placed in the closed (ON) posi-tion, and the test station was then closed to energize the circuit.At least 3 tests were conducted at each circuit level in order toconfirm repeatability. The highest temperature value recordedfrom any of these tests was used for the established value.

III. METHODS OF DETERMINING ARC FLASH VALUESAt this time, there are three basic methods of determining

arc flash values for determination of flash protection boundaryand for selection of personal protective equipment (PPE):

1. NFPA 70E. Table 130.7(C)(9)(a) for hazard/risk cate-gory (HRC) and Section130.3(A) for flash protection boundary.HRC is developed by assumptions of the conditions of installa-

tion. Although useful for those who have to work on a systemfor which little information is available, the assumptions of thisapproach may not match the system.

2. IEEE 1584 full calculation procedure using OCPDtime-current curves. This is the most accurate method in gener-al use. It applies detailed information to calculate values uniqueto the installation.

3. IEEE 1584 shortcut method for circuit breakers. Thismethod bypasses the need for detailed information about the cir-cuit breaker. However, it is quite conservative in that it appliesthe full calculation procedure to the longest duration for the cir-cuit breaker having the longest published clearing time for thecategory.

Another method that this paper is intended to help bringforward is application of manufacturer published values from

arc flash tests performed with the OCPD directly in the circuit.This method avoids making assumptions about perform-ance of the OCPD and provides the most accurate informationavailable. The earliest version of this method was employed toestablish the shortcut method for fuses in IEEE 1584.

This method of testing with the OCPD in the circuitinvolves an enormous volume of testing, which is one reason thepublic has not seen published values earlier. By application of the laws of physics and information regarding the performanceof the OCPD, it may be possible to model the occurrence andoutput the incident energy value. This kind of modeling is atopic to look to for the future.

IV. TYPICAL OUTPUT OF CALCULATED VALUES

Fig. 2 illustrates typical output for 400-ampere molded-case circuit breakers (MCCBs). Results of the IEEE 1584 fullcalculation procedure for a standard thermal-magnetic circuitbreaker and for a current limiting (CL) circuit breaker areshown.

Curve A-B is typical of the characteristic anticipated forincident energy of a circuit breaker using time-current curvesand the calculation method of IEEE 1584. That is, as the boltedfault current increases the incident energy increases.

The total electrical energy is calculated using equation 1.

Fig. 1 – Sketch of Test Setup


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VI. COMPARISON OF RESULTSFig. 5 compares incident energy values for a typical 400A MCCB using three methods of determination, IEEE 1584 fullcalculation method, IEEE 1584 shortcut and direct test values.

As expected, shortcut values are highest because theyrepresent the longest duration MCCB for the industry. Valuesfrom direct tests are lowest.

Values from direct tests are lowest because they reflectthe actual performance of the circuit breaker as opposed to usingvalues from trip curves. There are two significant reasons for thedifference. First, time-current curves are generally drawn toassume a conservatively long clearing of the circuit breaker.Actual values are obtained by test and then frequently roundedup to the next normal current zero for determination of the pub-lished curves. For example, if the circuit breaker clears in 11 msduring its longest operation at 600 V, the curve will be drawn toshow clearing at 16.7 ms, a full cycle. The same circuit breaker

at 480 V may clear within 8 ms, but the time-current curve stillshows clearing in 16.7 ms. When trip curve values are used forcalculations, they will be conservative in duration.

The second difference relates to current. As the circuitbreaker is clearing, it develops an arc between its contacts.

The dynamic impedance of this arc will reduce the cur-rent flowing and will, in that way, reduce the incident energy.

The calculation methods assume full arc current as though thearc in the circuit breaker was not present.

Using Fig. 5 and hazard categories as outlined in Table130.7(C)(11) of NFPA 70E for a 480 V bolted fault level of 65kA, we would find that HRC 1 PPE would be required if calcu-lations using either the full or shortcut methods of IEEE 1584were applied. Category 0 PPE would be required for applicationof direct tested values. If we were to apply Table 130.7(C)(9)(a)of NFPA 70E, HRC 2 PPE would be required for voltage test-ing of equipment. The most accurate method is the use of directtested values and it is also the lowest in this case.

FIG. 4 – TEST VALUES USING 800 A LOW-VOLTAGE POWER CIRCUIT BREAKER

FIG.5 – COMPARISON OF INCIDENT ENERGY VALUES FOR THREE METHODS OF DETERMINING INCIDENT ENERGY


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Table 1 shows tested values in comparison with calculat-ed values for a number of MCCBs. By applying the lower andmore accurate values, often lighter rated PPE can be applied,which reduces the heat and encumbering effect on workers, andmay improve their ability to perform the work safely.

VII. APPLICATION RECOMMENDATIONSWhenever possible, trip units should be set for instanta-

neous operation. Operation with no intentional delay greatly

aids in reduction or arc flash energy when it can be implement-ed without reducing needed selective coordination.

Be aware of the fault current that would result in opera-tion below the instantaneous range. Below that value, durationof the fault can be long and calculated incident energy can behigh.

Adjust settings to the lowest level that will allow opera-tion of the facility.

TABLE 1

TESTED VALUES FOR MCCBS COMPARED WITH CALCULATED VALUES


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VIII. ZONE SELECTIVE INTERLOCKINGMany electronic trip units offer a communication feature

known as Zone Selective Interlocking (ZSI). Two or morebreakers connected in series are interconnected with a twistedpair of communication wires between their trip units.

With ZSI, upstream breakers receive a signal to delaytripping for a preset interval while the downstream circuitbreaker clears the fault. However, when no signal is received

from the downstream breaker, ZSI bypasses the preset shortdelay time and ground fault delay time (when available) on theupstream circuit breaker closest to the fault, which then tripswith no intentional delay. This enables instantaneous trippingover a much wider range of fault currents while still maintain-ing optimal system coordination.

IX. SUMMARYDirect testing with the OCPD in the circuit provides the

most accurate information related to application of the devicefor mitigation of arc flash injury. Test information is becomingavailable from manufacturers. The test method is that used fordevelopment of IEEE 1584 with the OCPD in the test circuit.

Personal Protective Equipment (PPE) for arc flash pro-tection should be utilized any time work is to be performed onor near energized equipment, or equipment that could becomeenergized!

Similarly, circuits protected by many low-voltage powercircuit breakers operating in their instantaneous mode result inHRC 2 or lower. PPE consisting of conventional cotton under-wear, in addition to the simple FR shirt and pants, typicallyresults in a minimum arc rating of 8 cal/cm2, HRC 2 and is ade-quate for these circuits. Engineers must be aware that operationin the instantaneous mode for power circuit breakers may resultin reduction of coordination.

Extensive testing confirms that low-voltage circuit break-ers provide an excellent method to reduce the energy during an

arc flash incident. Current-limiting circuit breakers especiallyreduce incident energy by reducing both duration and fault cur-rent during an event. The added protection is not shown by cal-culation methods, which only consider duration.

Note: All values expressed in this paper unless otherwisestated assume a working distance of 18 inches and the arcingfault in a motor control center unit. The tested values are forspecific circuit breakers that will not be identified other than bycurrent rating. They are presented to indicate typical results thatmay be published by the manufacturers. Values in the article arenot intended to be used for arc flash analysis. The authors rec-ommend contacting the manufacturer of the specific overcurrentprotective device for application information.

X. REFERENCES[1] NFPA 70E Standard for Electrical Safety in the

Workplace, 2004 Edition, National Fire Protection Association,Quincy, MA, USA.

[2] IEEE Std 1584-2002, IEEE Guide for Performing ArcFlash Hazard Calculations.

[3] Doughty, R. L., Neal, T. E., Macalady, T., Saporita, V.,and Borgwald, K., “The use of low voltage current limitingfuses to reduce arc flash energy, Petroleum and ChemicalIndustry Conference Record, San Diego, CA, pp. 371–380,Sept., 1999

[4] Doughty,R.L.,Neal,T.E.,and Floyd,H.L.,“Predictingincident energy to better manage the electric arc hazard on 600-

V power distribution systems, IEEE Transactions on IndustryApplications, vol.36, no. 1, pp.257 .269, Jan./Feb.2000.

[5] IEEE Guide 1584, “Guide for Performing Arc-FlashHazard Calculations”, September 2002

[6] ASTM F-1959/F1959M-99, Standard Test Methodfor Determining the Arc Thermal Performance Value of Materials for Clothing.

[7] Underwriter’s Laboratories, UL 489, UL Standard forSafety for Molded-Case Circuit Breakers,

[8] American National Standard, ANSI C37.50-1989,Low- Voltage AC Power Circuit Breakers Used inEnclosures–Test Procedures

XI. VITAGeorge D. Gregory graduated from the Illinois Institute

of Technology with BSEE (1970) and MSEE (1974) degrees.He serves as Manager, Industry Standards with SchneiderElectric / Square D Company in Cedar Rapids, Iowa. He is aFellow Member of IEEE and a frequent author in IASConferences. He is a registered PE in Illinois, Iowa and PuertoRico.

Kevin J. Lippert is the Manager, Codes & Standards with

Eaton Electrical in Pittsburgh, PA. He began his career in 1986with Westinghouse Electric Corp., which was acquired by EatonCorp. (1994). He is heavily involved with the NationalElectrical Manufacturer’s Association and has heldChairmanships of several NEMA Low Voltage DistributionEquipment committees.


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SUMMARYAs scientists and citizens become more concerned with

global warming and the impact that “greenhouse gases” are saidto have, those companies involved in the transmission and dis-tribution of energy will be required to respond. This paper pres-ents an alternative to a greenhouse gas remediation policy,

which focuses solely on the detection of sulfur hexafluoride(SF6) emissions during the manufacturing and operating life of the power circuit breaker. By looking beyond the detection andfield resolution of the SF6 leaks to the total life cycle of thebreaker, we can have a much larger impact on the issue of glob-al warming. Remanufacturing is a solution that goes beyonddetection and provides substantial benefits environmentally,economically and systemically.

INTRODUCTIONCircuit breakers play a vital role in the protection and

operation of the electric transmission and distribution system.Circuit breakers interrupt the flow of electrical current in trans-

mission lines for normal switching of transmission circuits, andfor emergencies in the event of short circuits on the system.

SF6 has been used for insulation in electrical equipmentfor more than 40 years. SF6 provides the insulation medium forthousands of power circuit breakers, each having voltage ratingsof up to 800 kV, in the electricity supply systems around theworld today. In fact, the first high-voltage circuit breaker usingSF6 was put in service in 1956 at 115 kV. These first SF6-insu-lated circuit breakers were dual (or two-pressure) breakers thatwere derived from the air blast two-pressure circuit breakers.More recently, the single-pressure puffer circuit breaker hasevolved as the predominant configuration of high-voltage circuitbreaker equipment.

Sulfur hexafluoride’s main characteristics make it verysuitable for use in electrical equipment.

These desirable characteristics include:· High dielectric strength· Excellent arc-quenching properties· Good chemical stability· Nontoxic

SF6 AS A GREENHOUSE GASUnfortunately, some of the very characteristics that make

SF6 a desirable solution for arc interruption and insulation of electrical equipment also have been found to cause environmen-tal concerns. Sulfur hexaflouride has been characterized by theU.S. Environmental Protection Agency (EPA) as “a very power-

ful greenhouse gas” with a global warming potential of 23,900(EPA Global Warming Site, 2000). Many scientists are con-cerned about what is being characterized as a global warmingtrend. These scientists point to an increase in global mean sur-face temperatures since the late 19th century - and recent datashowing that the 20th century’s 10 warmest years all occurred in

the last 15 years - as evidence of a dangerous trend. Many areconcerned that the rising global temperatures will raise sea lev-els, change precipitation, and contribute to alteration of forests,crop yields and water supplies (EPA Global Warming Site,2000).

SF6 LEAKAGE DETECTION EFFORTSGiven the data supporting the assertion that SF6 has

some lasting presence in the Earth’s atmosphere and the poten-tial impact of greenhouse gases on the environment, the electricutility industry and those in the electric utility supply chain havetaken measures to reduce the escape of SF6. The ABB Group, aglobal technology company and supplier to the world’s utilities,has reported several measures taken by manufacturers to reducethe level of SF6 escaping into the atmosphere. Marchi, et al.present these measures in a paper titled “Design,Manufacturing, Practice and Information to Minimize SF6Release From Electric Power Equipment.” These measuresinclude:

· Design for minimizing leakage during operation· Gas emission monitoring during testing, manufacturing

and commissioning· Gas loss monitoring in service· Gas recovery and recycling procedures· Gas recovery from equipment· SF6 recyclingThese measures allow for improved detection of leakage

during the life cycle of electrical equipment. Other efforts leadto the elimination of leakage once detected.

REMANUFACTURING AND REMEDIATION OF EMISSIONSRemanufacturing is a process of rebuilding (and in some

cases upgrading) equipment that has previously been utilized inan electrical system. This process (as performed at ABB High-Voltage Switchgear Service) involves disassembly of the break-er to the basic components, comparing those components (andtheir parts) dimensionally with the original manufacturing spec-ifications, and rebuilding, replacing or machining any parts thatdemonstrate nonconformities. All components and vessels arecleaned and restored. The refurbished or replacement compo-

THE ENVIRONMENTAL BENEFITS OFREMANUFACTURING:

BEYOND SF6 EMISSION REMEDIATIONGeorge A. McCracken, Roger Christiansen and Mark Turpin, High-Voltage Switchgear Service, ABB

Power T&D


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nents are then reassembled and tested to original equipmentspecifications. Because the breaker is completely remanufac-tured, it returns to the customer with the same warranty as wasoriginally granted when the breaker was sold new.

A CASE STUDY: TWO-PRESSURE SF6 BREAKERSA two-pressure circuit breaker (produced up to 1985)

maintains an insulating pressure of 45 psig to 60 psig and aninternal arc extinguishing pressure of 240 psig to 280 psig. Thedevice-opening process directs the high-pressure gas across thecontacts into the low-pressure system, and a compressor systemtransfers this gas back into the high-pressure side. The SF6 vol-ume in the two-pressure breakers ranges from 760 lb. for a 242kV circuit breaker to more than 1,500 lb. For an 800 kV circuitbreaker.

There are several thousand two-pressure circuit breakersin service in the electric power transmission grid today, eachranging from 138 kV to 800 kV. One of the unique capabilitiesof the two-pressure SF6 breakers is the ability to interrupt veryhigh short-circuit currents in the network resulting from faults inthe system, such as lightning strikes, power line failure resultingfrom high wind and snow, and equipment failures. There are

more than 100 of these two-pressure breakers installed in criti-cal circuits with short-circuit current ratings of 90 kA through-out the United States. The present single-pressure puffer circuitbreakers cannot handle these large currents and, if designed forthis duty, would become extremely expensive. Thus, remanufac-turing of these circuit breakers is the only viable option.

The two-pressure SF6 breakers have been found to becontributors to SF6 emissions on some systems, leading someobservers to assume that the two-pressure design is inherentlyfaulty. In reality, all manufacturers of two-pressure SF6 break-ers recognized in the late 1970s that the gasket system in thelow-pressure portion of these breakers was resulting in leakageof low-pressure gas to the atmosphere. In time, this gasket mate-rial corroded the adjoining metal, resulting in leakage from thelow-pressure system. Following the recognition of this issue, allmanufacturers implemented the use of seal material with ademonstrated long-term performance.

The recognized corrective action for this early seal sys-tem problem involves the machining of all seal surfaces andreassembly using the corrected gasket material. This leak repairprocess entails the remanufacturing steps previously detailed. Inthe case of emissions remediation, the testing performed byABB in the factory of the remanufactured circuit breaker ismore stringent than the tests performed on new equipment. Theremanufactured equipment utilizes vessels fabricated from steelplates, as opposed to the use of aluminum castings. Therefore,the leak test technique can be more specialized because it needs

to be focused only on the flanged joints and welds. ABB’s fac-tory leak testing used in equipment remanufacturing is a processof isolating or ‘bagging’ each flange/seal joint for a prescribedtime period and then testing the ‘bagged’ volume with a devicethat will detect a leak rate of 1/60th of 1% per year (by weight).New equipment manufacturing cannot use that ‘bagging’ tech-nique due to the large surface areas that must be checked. Fieldexperience during many years has shown that the remanufacturetechniques are a viable solution to SF6 leakage.

OTHER ENVIRONMENTAL BENEFITS OFREMANUFACTURING

Manufacturing any complex product requires the use of a

tremendous amount of energy and material. When consideringthe supply chain and material requirements of power circuitbreakers, we find that they can contain more than 9,800 lb. of steel, 7,500 lb. of aluminum, 4,000 lb of porcelain and 200 lb.of copper. Each of these building blocks of the circuit breakerrequires raw material mined from the earth, and that those rawmaterials be processed into the finished material required tomanufacture the circuit breaker’s components. As stated earlier,the two-pressure SF6 breakers require as much as 1,500 lb. of

SF6 gas. In processing each of these materials, carbon dioxide(CO2), the most abundant greenhouse gas, is emitted.

Remanufacturing does not require the same materialinputs as original manufacturing, therefore eliminating the needfor the supply chain. In addition to using lower levels of energyand raw materials, remanufacturing allows for the recycling of the SF6 gas that is already in the circuit breaker. In fact, it is esti-mated that remanufactured goods conserve the equivalent of 400 trillion Btu of energy per year. Remanufacturing accom-plishes this conservation by saving 85% of the energy requiredto p

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