Tripping with the Speed of Light:Arc Flash Protection

Robert A. Wilson (ABB Inc.), Rainer Harju (ABB Oy, Finland),Juha Keisala (ABB Oy, Finland), Sethuraman Ganesan (ABB Ltd., India)

Abstract - Reducing clearing time is a criticalcomponent in reducing arc flash incidentenergy levels. Additional benefits includereduced collateral damage, lower productiondowntime and potentially lower personalprotective equipment (PPE) requirements. Anovel method of fast arc flash detectionutilizes long fiber optic light sensors to detectand initiate tripping faster than conventionalrelaying techniques. This paper discussesapplication examples as well as twodocumented arc flash events where thisprotection was implemented.

Keywords - Arc flash, arc flash hazards,incident energy, personal protective equipment

I. Introduction

Arc flash is not a new phenomenon butinterest and concern about the dangersassociated with arc flash events has increaseddramatically in recent years. This increasedawareness and concern is largely due to newguidelines and standards put forth by IEEE(Institute of Electrical and ElectronicEngineers), NFPA (National Fire ProtectionAssociation), NEC (National Electric Code)and OSHA (Occupational Safety and HealthAdministration).

IEEE Standard 1584TM, "Guide forPerforming Arc-Flash Hazard Calculations",contains step-by-step procedures forcalculating the available incident energy whereworkers might be exposed to energizedelectrical equipment.

NFPA 70E, "Standard for Electrical Safetyin the Workplace", adopts the IEEE Standard1 584TM calculation procedures and assignshazard levels ranging from 0 through 4 toincident energies up to and including 40cal/cm2. It also lists typical PPE (PersonalProtective Equipment) suit levels appropriatefor working near energized electricalequipment at each of the defined hazard levels.

Beginning in 2002, the NEC has included asection requiring the labeling of panels witharc flash hazard warnings. The 2005 NECadded meter-socket locations to the list oflocations that need to be marked.

OSHA regulations represent the fourthmajor impetus behind the increased interest inarc flash hazards. The primary OSHAregulations are in 29CFR 1910 Subparts I andS. These regulations are primarily concernedwith hazard assessment and documentation aswell as training workers in the proper use ofPPE.

II. Arc Flash Calculations IEEE Standard1 584TM-2002

IEEE Standard 1584TM contains step-by-step procedures for calculating the availableincident energy to which a worker might beexposed. Factors used in the calculationsinclude available (bolted) fault current,voltage, equipment type and construction andgrounding method. In addition, there a severalconstants whose values can be determined orapproximated based on tables that are includedwithin the standard.

1-4244-0995-0/07/$25.00 C2007 IEEE 226 Protective Relay 2007

The incident energy calculation is basicallya three-step process consisting of thefollowing:

a. Calculation of two arcing currents fromavailable bolted fault currents

b. Calculation of the normalized incidentenergy at each arcing current

c. Conversion from normalized to actualincident energy based on actual factors(clearing time, equipment factors, etc.)

The final step listed above consists ofconverting the previously calculatednormalized incident energy to the actualincident energy. This process takes intoconsideration actual equipment factors andactual fault clearing times based on theprotection that is in place. It also assumes thatall devices including relays, fuses and breakersoperate properly. Two equations are useddepending on system voltage.

For applications up to 15 kV [1]:

(1)

TABLE 1 - Typical working distances [1]

Classes of Equipment Typical WorkingDistance

15 kV switchgear 910 mm5 kV switchgear 910 mm

Low-voltage switchgear 610 mmLow-voltage MCCs & 455 mm

panelboardsCable 455 mmOther Determined in the field

TABLE 2 - Equipment factors and voltage classes [1]

System Equipmen Typical Distance xVoltage t Type conductor Factor(kV) gap (mm)

Open Air 10-40 2.000Switchgear 32 1.473

0.208 - 1 MCC and 25 1.641panelsCable 13 2.000

Open Air 102 2.000>1-5 Switchgear 13-102 0.973

Cable 13 2.000Open Air 13-153 2.000

>5-15 Switchgear 153 0.973Cable 13 2.000

For applications above 15 kV:

E = 5.12xl 0 VIbf (D2 (2)

where:

En is the incident energy (cal/cm2) normalized for aspecific time and specific distance from the arc

E is the incident energy (cal/cm2)Cf is a calculation factor

1.0 for voltages above 1kV1.5 for voltages at or below 1kV

t is the arcing time (seconds)D is the distance from the possible arc point to the

person (mm). See Table 1 for typical workingdistances.

x is the distance exponent from Table 2lbf is the bolted fault current for three-phase faults

(symmetrical RMS)(kA)V is the system voltage

III. Hazard Levels

NFPA 70E assigns relative hazard risklevels depending on the calculated incidentenergy levels. NFPA 70E also lists anexample of typical PPE (Personal ProtectiveEquipment) clothing appropriate to eachhazard category. For actual applications, thecalculated incident energy must be comparedto specific PPE combinations used at thefacility being evaluated. The example given inNFPA is shown below in Table 3:

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E=C E610'c

f n .2 D x

TABLE 3 - PPE Characteristics [2]

Note that the highest defined hazardcategory is level 4 having an upper limit of 40cal/cm2. While PPE is certainly available inratings well above 40 cal/cm2, working near

exposed energized equipment above 40cal/cm2 is discouraged. NFPA 70E notes that"greater than normal emphasis should beplaced on de-energizing the equipment"(Annex D.8 FPN) at such high incident energy

levels [2]. One possible reason is that PPE isprimarily intended for thermal protection.Other factors including physical trauma are

very dangerous above 40 cal/cm2.

IV. Mitigating Strategies

The three most obvious arc flashmitigating strategies are:

a. Reduce the fault current (If)b. Increase the working distance (D)c. Reduce the clearing time (t)

Some protective devices are currentlimiting by design. Current limiting fuses, forexample, are capable of both limiting themagnitude of fault current and durationprovided the fault current is within theircurrent limiting range (typically 10-15 timesthe device rating) [3]. Fault currents belowthis range must be analyzed like non-currentlimiting devices (based on the time-currentcharacteristics). Lower level arcing currentscan easily result in higher incident energy

because the clearing time maybe longer.Current limiting reactors (CLR) may also

be used to limit the available fault current.The disadvantage of a CLR is that it alsointroduces impedance in the circuit and itsassociated undesirable voltage drop [4]. Insome cases, the cost of a pyrotechnic-operatedhigh-current fault limiter with interruptingratings exceeding 200kA can be justified [5].

B. Increasing the working distance

Increasing the working distance has a

dramatic effect on the incident energy. Fromequations (1) and (2), it is also apparent thatthe incident energy level decreasesexponentially with increasing workingdistance. Examples of this strategy includeremote racking and the use of extension tools(i.e. hotsticks). However, many tasks may notbe able to be accomplished remotely andremote racking devices may not operate as

desired.

C. Reducing the clearing time

Referring to equations (1) and (2), it is alsoevident that the incident energy is directlyproportional to the arcing time. The arcingtime represents the total fault clearing time.Where a circuit breaker is involved, this timeconsists of the relay operating time plus thebreaker opening time.

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Hazard ~~~~~RequiredHazard Typical Protective Minimum PPERisk Clothing Systems Arc Rating

Category (cal/cm2)

Non-melting,flammable materials

0 (natural or treated N/A (1.2)materials with atleast 4.5 oz/yd2)

1 FR pants and FRshirt, or FR coverallCotton Underwear,

2 plus FR shirt and FR 8pants

Cotton Underwear,3 plus FR shirt and FR 25

pants and FRcoverall

Cotton Underwear,4 plus FR shirt and FR 40

pants and multi-layer flash suit

A. Reducing thefault current

According to IEEE Standard 1584T,breaker operating times vary from 1.5 cyclesto 8 cycles depending on the class of breakerinvolved. Table 4 lists the typical operatingtimes referenced in this standard.

TABLE 4 - Power circuit breaker operating times [1]

Relay operating times depend heavily on

the type of protection being used.Instantaneous over-current (ANSI device 50)and bus differential (ANSI device 87) are

relatively fast with typical operating times of2-3 cycles. On the other hand, operating timesfor time over-current elements (ANSI device51) are very dependent on the currentmagnitude and can vary from a few cycles toover a second. Time over-current relays are

especially slow where coordination withdownstream protection requires delayedtripping of upstream relays.

Common methods to reduce the relayoperating time include those listed below.Along with each method are listed some

advantages (+) and disadvantages (-) of each.

a. Lowered device settings (temporary)(+) Inexpensive to implement(+) Fairly fast (typically 2-3 cycles)(-) Activation requires operator action(-) Full selectivity of protection may belost(-) Failure to deactivate could result in

undesired tripping

b. Install high impedance bus differentialprotection

(+) Fairly fast (typically 2-3 cycles)(-) Requires CTs on all circuits(-) Prone to CT saturation concerns

c. Install zone interlocking scheme(+) Fairly fast (typically 5-10 cycles)(+) Inexpensive to implement(-) Requires communication betweendevices

d. Install dedicated arc flash protection(+) Very fast (0.15 cycles)(+) Fairly inexpensive to implement(+) Immune to CT saturation(+) Supports arc flash breaker failure

protection

V. Dedicated Arc Flash Protection

Arc flash protection is specificallydesigned to detect and trip for an arc flashevent. Arcing time is a critical factor inlimiting the damage and risk of personal injuryresulting from an arc flash. Consequently, arc

flash detection relays must be very fast andtypically operate in a few milliseconds. Thisspeed is achieved by detecting the light froman arc flash and by initiating tripping actionvia solid-state tripping elements.

A. Background ofarcflash relaying

An arcing fault instantaneously releaseslarge amounts of radiant energy. The radiantenergy includes both light and thermal energy.

Light intensities can be thousands of timeshigher than normal ambient light. Thisphenomenon is used in arc flash detectionrelays to achieve faster operating times than ispossible with conventional relaying.

Optical sensors detect the sudden increasein light intensity. Instantaneous over-currentelements are used as fault detectors tosupervise the optical system for security. Onlysource-connected current transformers

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Circuit breaker rating, type Opening time at 60HzLow voltage (molded case)(<1OOOV) (integral trip) 1.5 cycles

Low voltage (insulated case)(<1 OOOV) (power circuit bkr) 3.0 cycles

(integral trip or relayoperated)

Medium voltage(1-35 kV) 5.0 cycles

Some high voltage(>35 kV) 8.0 cycles

(typically at the main breakers) need to beconnected. Tripping occurs only if both lightand fault current are simultaneously detected.For additional speed, these relays are equippedwith high-speed solid state tripping outputs.Total operating time is typically less than 2.5ms [6].

Arc flash detection systems are stand-aloneprotection systems. They do not need to becoordinated with existing protection systems.Therefore, it is not necessary to delay trippingfor coordination with other protection.

B. First generation arcflash detection relays

Although new to North America, arc flashrelays have been around since the early1990's. Early arc flash protection used onlysingle-point light receptors called "lenssensors". In this system, one or more lenssensors are located in each high voltagecompartment where a potential arc flash mightoccur. Each lens sensor is radially connectedto electronics via a clad fiber. Because of theopaque fiber cladding, only the extreme endsof these radial fibers are light sensitive. Eachsensor is individually targeted, for moreprecise location of the arc flash fault. Alimited number of sensors may be attached to acommon electronic package. Multipleelectronic packages are then interconnected toachieve the complete switchgear coverage.

C. Second generation arcflash detectionrelays

During the year 2000, a second generationof arc flash detection relays was introduced.In addition to the traditional lens sensorsmentioned previously, the second generationproduct also accommodated a radicallydifferent type of light sensor, a long un-cladfiber optic sensor that can absorb lightthroughout its length.

There are several advantages to the longfiber sensor technology. First, it dramatically

reduces the cost of installation. A singleoptical fiber sensor can be as long as 200 feet,typically covering the same protection zoneassociated with conventional bus differentialprotection but at much lower cost than lenssensors. Second, any concerns about shadowsfrom internal structures that might block thedirect exposure to an arc flash are eliminated.Third, if the fiber sensor is configured in aloop, it can provide regular self-checking ofthe sensor's integrity and continuity, alarmingif a problem is detected.

Visible light consists of the light spectrumranging from 400nm to 700nm wavelengthswhereas arc flash test results show that mostof the radiated energy is in the range of200nm to 600nm. Consequently, optical arcflash relays are designed to operate in thelower end of the visible spectrum and slightlylower including ultraviolet light [7].

The optical sensor fiber is available invarious lengths up to a maximum of 60m (200ft). Unlike optical communication fiber, thisfiber has no opaque cladding. The lack ofopaque fiber cladding allows some of the lightto enter through the exposed exteriorcylindrical surface, where it propagates backto the electronics. The entire fiber is a sensor,not just the ends of the fiber. Thischaracteristic allows more complete coverageof switchgear cubicles without concern forshadows and without interconnecting amultitude of radial single point light (lens)sensors.

For additional security, the arc flash relayincludes a set of conventional 5A currenttransformer inputs. These are typicallyconnected to the current transformers locatedon the source side of the main breakers and areused to drive instantaneous phase and groundover-current elements. These over-currentelements act as fault detectors, supervising theoptical flash detector. They utilize peak-to-peak waveform detectors in order to eliminatedelays associated with conventional root-mean-square (RMS) calculations.

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In normal operation, both light and over-current must be present simultaneously fortripping to occur. Detection of an intense lightalone will not result in a trip unless the systemis intentionally set to operate that way (notrecommended).

Over-current settings allow differentcurrent threshold levels for phase and groundfault currents. High-speed insulated gatebipolar transistors (IGBT) are used to providetwo fully trip-rated outputs rather thanrelatively slow conventional dry contacts. Theoverall tripping time is a miniscule 2.5ms.

Figure 1 shows a suggested fiber routingpath in a single-high main-tie-main switchgearconfiguration. This illustration only shows themain fiber routing for the right half of the

lineup. The fiber route forms a loop travelingfrom the electronics, through the breakercompartments, returning through the buscompartment with a slight detour through theVT compartment. A second fiber would berouted in a similar path in the left half of theswitchgear lineup. The two fibers wouldoverlap in the tie breaker compartment. Aflash anywhere along the right-hand fiberroute would result in high-speed tripping ofthe breakers at Main-2 and Tie positions.Similarly, a flash anywhere along the left-handfiber route would result in high-speed trippingof the breakers at Main-I and Tie positions.

Front View

B9 Right half fiber sensor loop zone

HE Left halffiber sensor loop zone

K Overlap zone (tie breaker)

i - - -- Main fiber optic sensor path (one side only :shown)

B_s Fiber loop runs frm the relay through the breaker, bus andVT compartment and returns to the relay.

GaLileThe second fiber loop (not shown) overlaps the fitt in the

View be breaker compartmnent

Fig. 1. Suggested fiber sensor routing in single-high switchgear [8]

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VT?

-mm

Sid a

I

The routing paths of each fiber shouldtake into account which breaker(s) should betripped. Each fiber represents a commontripping action or protection zone.Regardless of where the flash occurs alongthe fiber, the same breakers will be tripped.In order to achieve the desired selectivity,separate fibers should be used for eachprotective zone along with the appropriateextension units for selectivity in tripping.

Note that the main fiber loop shown inFigure 1 does not enter any of the cablecompartments. An arc flash in one of thesecompartments should only cause theappropriate feeder breaker to be tripped, notthe entire bus since a fault in this zone isdownstream from the feeder breaker.

There are two ways to handle thissituation. One solution is to installindividual fiber sensors and theirappropriate electronics (extension unit) ineach of the cable compartments. Thiseffectively makes each cable compartment aseparate arc flash zone. Alternatively, onecould use a feeder relay that combinesconventional over-current protection with

optical arc flash protection using lenssensors mounted in the cable compartment[9].

VI. Reducing Incident Energy With ArcFlash Protection

Incident energy is directly proportionalto the total clearing time. Table 5 showsthis relationship and lists examples ofpotential incident energies that might bepresent in 13.8 kV grounded metal-cladswitchgear under worst-case assumptions.In this chart, incident energies are shown asa function of total clearing time andavailable bolted fault current per the IEEEStandard 1 584TM. Each interior cell showsthe calculated incident energy level incal/cm2. The column marked "Arc FlashRelay" is based on a total clearing time of0.9 seconds. This clearing time consists of2.5ms (arc flash detection) plus 84ms (5cycles) for the breaker operating time. Cellshading indicates the hazard level as definedby NFPA 70E and listed earlier in Table 3.

n y

ClearlngI Tiem )

1020

I

3040.so.

6070 180

goocurrent kA-)

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Table 5 illustrates the relationshipbetween total clearing time and incidentenergy. It also illustrates the potentialreduction in hazard levels and associatedPPE (Personal Protective Equipment) levelswhen an ultra high-speed arc flash detectionsystem is installed.

How much improvement is realizeddepends on the speed of the existingprotection. The direct and indirect damagesassociated with an actual arc flash explosionwould be smaller and production downtimewould likely be shorter as well.

VII. Arc flash relaying in air magneticswitchgear

Optical arc flash relaying is ideallysuited to equipment with vacuum or SF6interrupters, the predominant form ofmedium voltage circuit technology duringrecent years. These interrupters are sealedand normal fault interruption is containedwithin the sealed interrupters. Therefore,any light flash is cause for concern. Asimultaneous light flash and fault currentdetection represents an arc flash event.

Older air magnetic breakers operatedifferently. In this type of breaker, an arc isdrawn in air during normal faultinterruption. The arc is extinguished byblow-out coils that create magnetic forcescausing the arc to be elongated andsegmented. Most of the light is containedwithin the arc chutes but these chutes are notcompletely sealed. Concerns have beenraised about whether optical arc flashrelaying is appropriate for air magneticcircuit breakers. In other words, willsufficient light escape the arc chutes tocause undesired tripping during normal faultclearing?

To answer this question, high-currenttests were conducted on medium voltage airmagnetic switchgear breakers equipped withoptical arc flash relaying [10]. Tworepresentative breakers were chosen fortesting, a 13.8-500-5H-1200 (15kV class,1200A, 500MVA) GE MagneblastTMbreaker and a Westinghouse 5ODHPTM-250-1200 (5kV class, 1200A, 250 MVA)breaker. Each was installed in a singleswitchgear frame and equipped with ten arc

flash relays utilizing long fiber and single-point lens sensor technologies.

The ten arc flash relays representeddifferent optical fiber paths, exposed fiberpaths, lens sensor locations and lightthreshold settings. Downstream three-phasefaults were staged at three different levelsand each test was run three times.

Tables 6 and 7 represent the results ofthe medium voltage testing on theWestinghouse DHPTm breaker. Tables 8and 9 represent the results of the GEMagneblastTm breaker tests.

Table 6Westinghouse DHPTm Trip Tests

Using Long Fiber Sensor Technology

Note 1: Some trips occurred with long fiberexposure.

No trips occurred for fibers placed 2 ft. below the topof the arc chutes.

Note 2: Circuit breaker failed during test. However,the arc flash relay correctly tripped for all settings.

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3 kA 10 kA 20 kAMinimum Light No Some(') NA(2)

SettingMedium Light No No NA(2)

SettingMaximum Light No No NA(2)

Setting

Table 7Westinghouse DHPTm Trip TestsUsing Lens Sensor Technology

3 kA 10 kA 20 kA

Minimum Light Yes Yes YesSetting

Medium Light Yes Yes YesSetting

Maximum Light Yes Yes YesSetting

Table 8GE MagneblastTm Trip Tests

Using Long Fiber Sensor Technology

3 kA 10 kA 20 kA

Minimum Light No No NoSetting

Medium Light No No NoSetting

Maximum Light No No NoSetting__

Table 9GE Magneblast Trip Tests

Using Lens Sensor Technology

3 kA 10 kA 20 kA

Minimum Light No No NoSetting

Medium Light No No NoSetting

Maximum Light No No NoSetting__

The GE MagneblastTm breaker testsindicate that optical arc flash relaying witheither technology may be applied. The GEbreaker's arc chutes allow relatively littlelight to escape during normal fault clearingand no arc flash trips occurred for any of thetest.

The Westinghouse DHPTm breaker arcchutes allow much more light to escape. In

this case, proper positioning of the fiber iscritical. Care should be taken to avoiddirect exposure of the fiber directly above ornear the top of the arc chutes. When thefiber was located two feet below the top ofthe arc chutes, no trips were recorded. Onthe other hand, false detection using lenssensors occurred at all fault current levels.

Unfortunately, the complete range oftests could not be completed on theWestinghouse DHPTm breaker because thebreaker under test had not been properlyreconditioned prior to the test. One phasefailed to interrupt during the 2OkA fault andthe upstream test facility breaker wasrequired to clear the fault. However, all ofthe arc flash relays did detect this event.

As a result of these tests on oldermedium voltage air magnetic breakers, it isthe generally recommended that any fibersensor be located well below the top of thearc chutes to minimize exposure to any"normal" light flash as a result of clearingdownstream faults. Also, a "straight-through" path is suggested since there isample light sensitivity built into the system.An uncontrolled arc flash will extend wellbeyond the arc chutes, greatly increasing theavailable light.

VIII. Field Experience With Arc FlashRelays

Fortunately, arc flash events arerelatively rare although perhaps not as rareas one might think. At the 11th annualIEEE-IAS Electrical Safety Workshop,statistics presented from a National Institutefor Occupational Safety and Health studyshowed that during the period from 1992through 2001, there were 44,363 electrical-related injuries involving days away fromwork. The number of nonfatal electrical

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shock injuries was 27,262, while 17,101injuries were caused by electric arc flashburns and the amount of time away fromwork is significantly higher for arc flashburns than as a result of electrical shockinjuries [4] [11]. A large percentage ofthese accidents occur while workers aredirectly exposed to energized conductors,often during the process of racking breakersin or out.

Over 3,500 arc flash detection systemsutilizing long fiber optic sensor technologyhave been installed in 36 countriesworldwide over the past 6 years. There havebeen at least two documented cases to datewhere an arc flash accident occurred inmedium voltage switchgear protected by arcflash relays utilizing the long fiber sensortechnology. These two events are describedbelow.

A. Case #1: Detramovice Power Plant(612612002) [12]

During the morning shift at theDetramovice Power Plant in the CzechRepublic on June 26, 2002, two workerswere exercising a 6.3 kV breaker that hadbeen withdrawn to its test position.Unfortunately, they forgot that the breakerwas closed as they tried to push it into theoperation position. The mechanicalinterlocks were bypassed as they forced thebreaker into position. This, in turn, initiated

an arc that could have caused extremelyserious consequences.

Fortunately, the switchgear wasequipped with dedicated arc flash relaysutilizing long fiber sensor technology.Within 82 ms, the entire substation wasdisconnected and a major catastrophe wasaverted.

Eyewitnesses reported that the cubicleroom was full of white sticky smoke fromburned plastic but that was the extent of thedamage. Repairs consisted of cleaning thebreaker and cubicle as well as replacing thebreaker rosette and cubicle pins. Figure 2shows photos taken immediately followingthe incident. No permanent damage to theinstallation or surrounding equipment wasencountered and the plant was quicklyreturned to service thanks to the fastreaction time of the arc detection system.More importantly, however, both workersescaped injury and possible death.

Had the arc protection system not beeninstalled, the estimated direct cost of thephysical damages could have been as highas $1.6 million USD [13]. Indirect lossesincluding extended loss of production wouldprobably have been many times higher yet.

A similar accident at this same plantoccurred in 1979 well before the installationof dedicated arc flash relaying. Thatincident resulted in 3-day outage. Lostproduction and equipment damages totaledseveral million dollars for the event.

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Fig. 2. Detmarovice 6/26/02 event photos

B. Case #2. Kemira Grow How event [14]

Kemira Grow How has a fertilizer plantlocated in Uusikaupunki, Finland. Energyconsumption is 18 MVA and the plant alsohas 7 MVA of on-site generation. Primaryproducts are fertilizers for farms,greenhouses, gardens and forests.

In 2003, the Kemira Grow How plantnarrowly avoided a major catastrophe justone day after fiber optic based arc flashrelaying had been installed in 1965 vintagemedium voltage switchgear.

The arc flash event was initiated when adisconnect switch was opened but failed toextinguish the arc. The disconnect switchthat was being opened fed a longunderground cable, not normally energized.Due to the capacitive no-load current in thecable, the air disconnector switch could notextinguish the arc. Instead, the arcprogressed to the bus compartment, where itevolved into a three-phase bus fault.According to Jari Lintula, Electrical

Department Manager, the accident was theresult of human error.

Jari Lintula (Manager) and Pentti Laine(Technician) were working in the sameroom when the flash occurred. Neither wasinjured although both were a bit shaken.

The just-installed arc flash relayingsystem detected the arc flash and trippedbefore the switchgear could sustain anysignificant damage. The plant was restoredto service in a few hours. Had dedicated arcflash relaying not been installed, protectionwould have depended on conventional over-current relaying. The clearing time wouldhave doubled. The incident energy wouldhave doubled as well. It is difficult toestimate the damage that would haveoccurred but it would most likely have beenquite expensive. One day of lost productioncosts millions of dollars.

Arc flash relaying was originallyinstalled at this site as insurance to limit thedirect and indirect damages associated withan electrical accident. The investment waspaid back many times over in one day.

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IX. Conclusions

Ultra-fast clearing of arc flash faults isessential in controlling arc flash hazards.Reducing the arcing time through fasterdetection is the most practical means oflowering incident energy levels andimproving workplace safety.

Incident energy is directly proportionalto arcing time. Even a few millisecondsimprovement may shift hazard levels andPPE requirements to lower categories.

Optically based arc flash relaying is thefastest protection available with a typicaloperating time of less than 2.5ms. Thedevelopment of long fiber light sensorshave made this protection practical for bothnew and retrofit applications.

Optical arc flash protection technologyhas a proven track record with over 5 yearsexperience and over 3,500 installations.Optical arc flash relays are ideally suited tomodern vacuum and SF6 breakertechnologies where the fault interruptiontakes place inside a sealed container.However, with proper precautions, opticalrelay may also be applied to air magneticbreakers as well.

Beyond the installation of dedicated arcflash relaying, arc flash mitigation strategiesshould also consider replacing older airmagnetic breakers (typical operating time of5 cycles) with modern vacuum and SF6technology (typical operating time of 3cycles or less).

X. References

[2] NFPA 70E, Standard for ElectricalSafety in the Workplace, 2004 Edition

[3] "Arc Flash Hazard Analysis andMitigation", Chris Inshaw and RobertWilson, 2006 Texas A&M RelayConference

[4] "A Total Approach to Arc FlashCompliance", Alan C. Bast, Jeffry L.Bennett, Norman E. Reifsnyder, RichardMages, Preston Cooper, Power-GenInternational 2006 Conference

[5] "Is-Limiter", ABB Calor Emag MediumVoltage Products, ABB AG, All Rights,Reserved

[6] ABB Buyers Guide, REA 10 ArcProtection Relay, 1MRS750929-MBG,May 1999

[7] "Arc Protection Technical Aspects",ABB Powerpoint presentation, January,2005

[8] "REA lOX Optical Sensor FiberRouting", ABB Instruction Book1VAD266601, May, 2006

[9] "REF 610 Feeder Protection" ABBDescriptive Bulletin, February, 2005

[10] "KEMA Test Results Summary", ABBREA1OX tests, November 10, 2006

[11] "Preventing Arc Flash Injuries03/20/2006 by Jim White, OccupationalHazards, (C 2004 Penton Media, Inc.All Rights Reserved.

[12] "Electric Arc - The UnpredictablePhenomenon, ABB publication, 2006

[13] Letter of Reference, Ludvik Pavlik,Detmarovice Power Plant, July 4, 2002

[14] "REA 10_ Arc Protection SystemSaved Lives and Equipment", ABBpublication, 2006

[1] IEEE Guide for Arc-Flash HazardCalculations, IEEE StandardTM 1584-2002

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XI. BIOGRAPHIES

Robert A. Wilson is a Regional TechnicalManager for ABB Inc. in Houston, Texas.He received his BSEE degree from PurdueUniversity in 1974 and his MSEE degreefrom Carnegie Mellon University in 1976.He is a Senior Member of IEEE and aRegistered Professional Engineer in Texasand Pennsylvania.

for the Distribution Automation division ofABB Ltd, Bangladore, India. He is amember of IEEE. He teaches in ABB RelaySchools and has presented papers at variousprotection conferences.

Rainer Harju is a Product Manager forABB Oy, Distribution Automation in Vaasa,Finland. He received his MSEE degreefrom the University of Oulu, Finland in1989. His expertise areas are arc flashprotection systems as well as transformer,generator and motor protection and controlrelays for medium voltage powerdistribution.

Juha Keisala graduated from the VaasaInstitute of Technology in 1990. He hasbeen working as an Application Engineerresponsible for protection applications forABB Oy Distribution Automation'sCustomer Support in Vaasa, Finland since1990. Prior to this position, he worked as adesign and commissioning engineer forABB Oy Service.

Sethuraman Ganesan received his BEdegree with Honors in Electrical andElectronics Engineering from MadrasUniversity, India in 1982. He worked forTata Consulting, Areva, Deprocon and ABBin various countries in power plant electricaldesign and substation protection and controlsystems. In 2001, he joined ABB Inc. inAllentown, Pennsylvania, as a seniorapplications engineer and HV relays productmanager in the Substation Automation andProtection Division. Presently he is working

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