NEC Design Compliance, System Protection, and Arc Flash Hazard

1928 IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 49, NO. 4, JULY/AUGUST 2013

NEC Design Compliance, System Protection,and Arc Flash Hazard

Ronald H. Simpson, Senior Member, IEEE

Abstract—The National Electric Code (NEC) specifies limits onsettings of transformer overcurrent protective devices that directlyaffect system protection. However, compliance with NEC designguidelines does not assure adequate system protection. The resultcan be zones of poor or nonexistent protection and “ExtremeDanger” arc flash hazard (AFH) ratings. This paper discusses theexisting system protection in a large paper mill and makes rec-ommendations for improving that protection and lowering AFHratings.

Index Terms—Arc flash hazard (AFH), National Electric Code(NEC) design guidelines, system protection.

I. INTRODUCTION

AN ARC FLASH hazard (AFH) study was implemented fora newspaper mill. The mill has no in-house generation and

receives all of its electrical power from five utility transformers.Simplified single-line diagrams of Substations 1 and 2 from thissystem are shown in Figs. 1 and 2.

Utility Substation #1 (see Fig. 1) has a 13.8-kV switchgearlineup with one main and four feeder circuit breakers. UtilitySubstation #2 (see Fig. 2) has a 13.8-kV switchgear lineup withone main and three feeder circuit breakers. The seven feedersare serving a total of 49 unit substation transformers ranging insize from 1000 to 8400 kVA. Each feeder has a different numberof transformers.

Substations 3, 4, and 5 are dedicated to one 13.8-kVswitchgear lineup each. These switchgear lineups have fourfeeders, each serving a 12 000-hp synchronous motor refiner.

II. NEC DESIGN GUIDELINES

The National Electric Code (NEC) limits the number of unitsubstations that can be fed by one overcurrent protective deviceby limiting the maximum pickup of that device. NEC Article450 Table 450.3 [1] specifies transformer protection and isshown in Fig. 3.

For transformers with no more than 6% impedance, this tablelimits the pickup of the primary overcurrent protective relay to amaximum of 6X full load amperes (FLA). For optimum systemdesign as per this guideline, the number of transformers on afeeder should be limited to six, and they should all have the

Manuscript received April 16, 2012; accepted July 16, 2012. Date of publica-tion April 4, 2013; date of current version July 15, 2013. Paper 2012-PPIC-127,presented at the 2012 IEEE Pulp and Paper Industry Conference, Portland, OR,USA, June 17–21, and approved for publication in the IEEE TRANSACTIONS

ON INDUSTRY APPLICATIONS by the Pulp and Paper Industry Committee ofthe IEEE Industry Applications Society.

The author, deceased, was with GE Energy, Alpharetta, GA 30005 USA.Color versions of one or more of the figures in this paper are available online

at http://ieeexplore.ieee.org.Digital Object Identifier 10.1109/TIA.2013.2256768

Fig. 1. Utility Substation #1.

Fig. 2. Utility Substation #2.

0093-9994/$31.00 © 2013 IEEE

SIMPSON: NEC DESIGN COMPLIANCE, SYSTEM PROTECTION, AND ARC FLASH HAZARD 1929

Fig. 3. NEC Table 450.3.

same kilovoltampere rating if they are protected by a commonprimary relay.

For transformers with more than 6% but less than 10%impedance, this table limits the pickup of the primary overcur-rent protective device to a maximum of 4X FLA. For optimumsystem design as per this guideline, the number of transformerson a feeder should be limited to four, and they should allhave the same kilovoltampere rating if they are protected bya common primary relay.

The aforementioned limits are often interpreted to specify themaximum load that can be served with acceptable protectionprovided by the primary protective device. However, this maynot be the case. If there are six or less transformers with Z <6% on a feeder but the transformers vary in size by a significantamount, the protection afforded by the primary overcurrentrelay could be poor or nonexistent for some. Even when alltransformers are of the same size, the protection afforded bya common upstream feeder relay is poor if the relay is set to themaximum 6X FLA of the transformers.

Similar limits for maximum load are specified for transform-ers with 6% < Z < 10%. If there are four or less transformerswith 6% < Z < 10% on a feeder but the transformers varyin size by a significant amount, the protection afforded by theprimary overcurrent relay could be compromised or nonexis-tent. In effect, what this table is saying is that, if the number oftransformers on a feeder exceeds the number allowed, there willnot be sufficient short circuit current available in the secondarycircuit to effectively operate the primary overcurrent relay forsecondary phase overcurrent faults when the relay is set to carrythe full load current of all the transformers.

This table in the NEC also allows for the fuse protectionof the transformer. Fuse protection is also limited in terms ofmaximum ratings just as the relays are limited in terms ofmaximum pickup. Note that, if the transformer has impedanceless than 6%, the maximum rating of the fuse is 3X, whichis only half the maximum pickup of the relay. The reason forthis is that the “E” rated fuses that are commonly used fortransformer protection have a minimum pickup current thatis 2X the rated current of the fuse. In effect, this makes the

maximum pickup current of the fuse 6X the transformer rating,which is the same as that for a relay.

This maximum pickup is clearly outside the range of over-load protection for an individual transformer. Note also that,even when transformer primary fuses are dedicated to a singletransformer, they cannot provide overload protection. Thesefuses do not even protect themselves from overload due to theminimum pickup of the “E” rated fuse being 2X the continuousrating of the fuse. Fuses that are commonly used to protecttransformers from through-fault currents are intended to beapplied in combination with other devices to provide overloadprotection.

However, overload protection is rarely applied on the primaryof the unit substation transformer along with the fuse. Thisprotection is commonly provided by secondary main devices ifprovided at all. Many systems such as the one under discussiondo not employ secondary main circuit breakers in the 480-Vunit substations and have no overload protection.

III. ANALYSIS OF SYSTEM DESIGN

Some of the transformers fed by the seven medium-voltagefeeders have dedicated primary protection in the form of a fuseor relay. When you consider that the fuse must carry the max-imum forced cooled rating of the transformer and then factorin the pickup of 2X FLA for the fuse, the protection providedis marginal. Most fuses will at best protect the transformerfrom mechanical damage due to severe through-fault currentsthat result from maximum three-phase bolted secondary faultconditions.

Reduced fault currents such as those resulting from arcingfaults or ground faults may not melt the primary fuse at all orwill melt the fuse in the range of seconds. The result is thatthe protection zone from the primary fuse down to and possiblyincluding the secondary gear for most substation transformersprovides in excess of 40 calories per square centimeter andhence is classified as an “Extreme Danger” AFH category andshould not be accessed while energized.


Fig. 4. CB 201 transformer UT1.

Fig. 5. ANSI C57.12 overload ratings.

The table in Fig. 4 shows that CB 201 has less than sixtransformers, but the transformers vary in size by a considerableamount. In addition, two of the transformers have dedicatedprimary protection in the form of fuses, but one has no ded-icated primary protection. As a result, the transformer forSubstation E42379 must be protected by the upstream relaywith the pickup set to carry three transformers plus overloadcapacity. The total connected kilovoltampere on this feeder is10 680 kVA.

ANSI C57.12 [5] for liquid immersed transformers specifiesstandard overload ratings for power transformers. Table 2 fromthat standard is shown in Fig. 5.

This table shows that standard forced cooled ratings are133.3% and 166.7% of the rated kilovoltampere. In addition,most system engineers will set the overload protection of thetransformer to something greater than the rated current in theabsence of the Stage 1 and Stage 2 forced cooled ratings toallow short-term overloads.

While this may shorten the life of the transformer over thelong term, in the near term, it allows for short-duration over-loads that may only happen on the days of highest load withoutinterrupting service. This is a reliability-versus-protection com-promise to prevent the interruption of service when it is mostneeded.

In the aforementioned example for CB 201, the minimumpickup of relay R-17 required to carry the full load of all thetransformers on the feeder compared to the full load rating ofthe unprotected transformer is

PU =10680kV A

7500kV A= 1.42 pu.

The relay pickup must be set to 42% overload or 1.42 per unitfor the unprotected transformer just to carry the base load ratingof all the transformers. However, the existing setting of relayR-17 compared to the FLA of all the transformers on thefeeder is

PU =720A

447A= 1.61pu.

This relay setting presently allows for the approximate maxi-mum forced cooled rating of all the transformers on the feedercombined. Setting the pickup of the upstream relay high enoughto allow the maximum forced cooled rating of all of thetransformers results in no overload protection of the unfusedtransformer.

Due to the fact that transformer E42379 is a significantpercentage of the total connected load and it is high resistancegrounded (R-20 does not operate), this transformer hasrelatively good through-fault current protection (no line–groundthrough-fault damage curve). However, for the arcing currentshown on the single line in Fig. 6, the relay will take at least 0.6 sto operate. This results in incident ratings above 8 calories persquare centimeter for the motor starter.

In addition, the arc flash boundary for a fault in the 4160-Vmotor starter is 309 in. This is 25.75 ft. The cable connectingthe secondary main relay and circuit breaker to the motor starteris only 30 ft long, placing the main circuit breaker within thearc flash boundary for the motor starter when conduit routes areconsidered. This means that the secondary main circuit breakercannot be approached while the motor starter has been accessedunless service personnel wear arc-rated personal protectiveequipment (PPE) with 8 or more calories of protection, oftendetermined as Category 3 PPE with 25 or more calorie rating.

In addition, the incident energy calculation for the secondarymain breaker section is above 25 calories, requiring Category 4PPE due to the reliance on the upstream relay R-17 to clear anarcing fault. A comparison of the personal protective equipmentrequired for the calculated incident energy is described intable H.3(b) (see Fig. 8) in informative annex H within NFPA70E-2012. The PPE associated with the hazard risk categories(HRCs) of table 130.7(C)15(a) is shown in Fig. 7.1

Generally, the standard uniform for service personnel inmost industrial plants is rated for 8 calories or more andcompatible with Category 2 HRC. Category 3 and Category 4PPE or exposure in excess of 12 calories should be avoidedwhen possible due to the limitations on activities resultingfrom the arc flash suit. Under some working conditions, itis not possible to stay in the arc flash suit for more thana few minutes, and dexterity and visibility are limited. Dueto the lack of comfort, there is always risk that a workermay choose not to wear such cumbersome PPE when he/sheneeds it.

1It should be noted that the industry often associates calculated incidentenergy with HRC categories using the minimum arc-rating requirements forPPE in table 130.7(C)(16). Although this is common practice, it is not correct asthis table is only to be associated with the activity HRC classifications of table130(C)(15)(a) and (b). Calculated incident energy should be used to referencethe table in informative annex H within the same standard, NFPA 70E-2012.


Fig. 6. (a) One line for 4160-V Substation E42379 showing incident energylevels at specific working distances. (b) TCC for 4160-V Substation E42379[see Fig. 6(a)] showing important overcurrent protection devices.

Note also that, despite the fact that the upstream relay R-17meets the NEC requirements for maximum pickup of 6X FLAfor transformer E42379, the secondary circuit experiences arcflash energies resulting in the range of 25–40 calories, com-

Fig. 7. PPE associated with NFPA 70E hazard risk categories.

Fig. 8. PPE guidance in NFPA 70E, informative Annex H.

Fig. 9. CTIs from IEEE 242.

monly referred to as Hazard Risk Category 4. This is partly dueto the fact that R-17, as well as R-41, is an electromechanicalrelay with limited adjustment and functional flexibility.

IEEE Standard 242 Table 15-3 [3] in Fig. 9 lists the minimumcoordination time intervals (CTIs) for protective devices. The


Fig. 10. (a) One line for low-voltage substation with dedicated primary fuse.(b) TCC for low-voltage substation [see Fig. 10(a)] with dedicated primary fuse.

recommended time interval between two electromechanicalrelays is 0.3 s. When the upstream relay is set to be selectivewith the downstream relay at the maximum three-phase boltedfault current, it tends to be very slow in operating at arc flashcurrent levels. At 480 V, arc flash currents are typically abouthalf the maximum value.

The smaller transformers on this feeder that have dedicatedprimary fuses do not fare any better than the transformerprotected by the upstream relay R-17 as far as protection of thesecondary circuit is concerned. Fig. 10 is a time–current curvefor transformer E51135, showing the dedicated primary fusecompared to the downstream low-voltage breaker trip units andthe upstream relay.

The time current curve (TCC) of the dedicated primary fuseis completely to the right of the transformer thermal and me-chanical damage curve for secondary line–ground faults (solid

line). It is also completely to the right of the mechanical damagecurve for secondary three-phase faults (bottom dotted line). Itbarely grazes the thermal damage curve for secondary three-phase faults (top dotted line), giving essentially no protectionfor the secondary circuit.

Note that the AFH for the low-voltage switchgear is “Ex-treme Danger.” This switchgear cannot be accessed from thefront while energized. Note that one of the feeder breakers alsohas an AFH of “Extreme Danger” and cannot be accessed fromthe rear while energized as well.

The dedicated primary fuse is rated 100 E and has a contin-uous current rating of 100 A. The transformer is rated for a fullload current of

FLA =1680kV A

13.8kV ∗√3= 70A.

The ratio of fuse rated current to transformer FLA is

FLA =100E

70A= 1.43 pu.

However, because the fuse pickup is 2X the continuous rating,the pickup is

PU =200A

70A= 2.86 pu.

The result is no transformer protection for through-fault cur-rents and very poor AFH ratings in the secondary circuit.Fig. 10 shows what the time–current characteristics look likewhen plotted for a secondary arcing fault on the switchgear bus.Note that, for arcing faults in the switchgear bus, the primaryfuse takes 3 s to clear the fault.

Similar issues exist for the other transformer on this feederfor which the time–current curve and arc flash ratings wouldbe nearly identical to the low-voltage substation discussed.Despite the fact that the feeder discussed meets the letter of theNEC for protective device ratings and settings, it provides nothrough-fault current protection for one transformer and poorAFH ratings for all substations. Similar problems appear on theremaining feeders as well.

IV. SYSTEM PROTECTION EXCEEDING THE

NEC MINIMUM REQUIREMENTS

An effective solution to improve system protection and lowerAFH is a dedicated primary multifunction digital relay withmultiple set point groups for each substation primary. The relaycan be set to allow selectivity with secondary protective devicesduring normal operation. During maintenance operations, lowersettings can be activated to lower arc flash ratings when the gearmust be accessed by maintenance personnel while energized.

Fig. 11 shows a feeder with a dedicated primary digital relay,R-24, in maintenance mode. The maintenance set point groupinstantaneous setting has been lowered below the low-voltagearcing current to lower the AFH at the low-voltage substation.The switchgear now has incident energy below 8 calories(18 in). The feeders would also have incident energy below8 calories, contrary to the calculated value shown on the singleline which bases the calculation on the feeder setting and notthe primary relay. A maintenance mode switch can be installed


Fig. 11. (a) One line for low-voltage substation with dedicated primary relayin maintenance mode. (b) TCC for low-voltage substation [see Fig. 11(a)] withdedicated primary relay in maintenance mode.

in the switchgear to input a contact to the digital relay on theprimary, signaling the relay to go to set point group 2 with thelower instantaneous setting. Many modern digital relays offer avariation on this capability.

The relay could trip the upstream circuit breaker for thefeeder, but this would also interrupt service to two other substa-tions. A better solution would be to install a dedicated circuitbreaker at the primary of this substation at the same location asthe relay. Several manufacturers now have offerings that requirea footprint similar to that of a medium-voltage fused switch.

The expense for purchasing and installing relays and circuitbreakers dedicated to individual transformers must be weighedagainst the need to access the secondary switchgear while ener-gized. Additionally, the improvement in system reliability mustbe considered for both normal and maintenance operations.The potential harm to personnel and the cost of downtime andexpense of replacing equipment in poorly protected circuits canoften justify the cost of upgrading the substation protection.

It should be noted that it is not good engineering practiceto put maintenance mode incident energy ratings on arc flashlabels due to the requirement for human action to achieve therating. The label should have normal mode ratings, and thetemporary ratings requiring the maintenance mode switch tobe “on” should appear on the written work permit required forwork on energized circuits by NFPA 70E Article 130 B.1 [2].

Alternatively, if a substation is a low-voltage switchgear withan existing secondary main circuit breaker, it can be retrofitwith trip units that have maintenance mode setting capability.This feature can lower the short time and/or instantaneous tripsof the main circuit breaker to lower the AFH at the feeders.While this solution eliminates the disadvantage of trippingother substations, it has its own disadvantage of not loweringthe AFH of the incoming bus or the main circuit breaker itself.The AFH ratings at these locations are still determined by theprimary feeder relay or transformer fuse protection which hasbeen previously shown to result in very high AFH ratings,including above 40 calories, normally considered as ExtremeDanger.

In addition, the maintenance mode switch operation of themain low-voltage circuit breaker trip has the same disadvan-tages as the primary relay alternative setting switch describedearlier. The setting of the maintenance mode switch requireshuman action, and the maintenance mode’s resultant ratingshould not appear on the AFH label. The maintenance modereduced AFH should be reflected on the required written workorder as stated previously.

The requirement for maintenance mode switches to lowerAFH can be eliminated or minimized by retrofitting the mainand feeder circuit breakers with modern trip units that havezone-selective interlock (ZSI) capability. These trip devicescan provide faster tripping and lower incident energy ratingswithout operator engagement. At the same time, they can befully selective to high prospective fault values. Recent advancesin protective device technology from multiple manufacturersallow ZSI systems to include dedicated primary relays andcircuit breakers within schemes that start at secondary low-voltage trips and circuit breakers.

The difference between maintenance mode and ZSI is thatthe dependence on maintenance mode requires the system tobe set to be less protective to achieve selectivity and thenrequires operator engagement to shift the protective device tomaximum protection/minimum arc flash settings temporarily.ZSI is normally set for maximum protection/minimum arc flashand shifts automatically to selective settings when faults areseen by downstream devices. With ZSI, the resultant incidentenergy number rating can appear on the AFH label since nohuman action is required and the system is fully automatic.In the case of a failure of the ZSI system, the system failsin the safer mode of protection. ZSI systems normally relyon simple voltage signals and do not require complex serialcommunications. A ZSI implementation can be expected to bevery reliable due to its simplicity.

The lowest AFH ratings will be obtained by ZSI schemes thatallow shifting of instantaneous trips (I-ZSI) [6]. The fastest tripwill result in the least AF energy being released. In addition,current technology also allows the analysis of fault current


Fig. 12. Simplified system with ZSI interlocking from feeders to LV main toMV relay protecting the substation transformer, including secondary bus.

waveforms by feeder trip devices to determine if current-limiting devices downstream of the feeder circuit breakers areoperating to interrupt a fault and delay tripping for the feederas required to maintain selectivity with downstream devices[6]. However, multiple manufacturers have improved short timeprotection speeds in later generation trip units, and schemesfaster than those available a decade ago can be created fromseveral manufacturers’ products.

V. IMPLEMENTATION OF AN INSTANTANEOUS

ZONE SELECTIVE SYSTEM (I-ZSI) USING AN

INSTANTANEOUSLY SELECTIVE ALGORITHM

A simplified sample system implementing waveform recog-nition capable trips in the low-voltage trips as well as I-ZSIbetween the low-voltage trips and up to the first medium-voltage relay is shown in Fig. 12. The relay employs twoprotective elements, one with instantaneous trip connected to aset of current transformers (CTs) at the transformer secondaryand the other connected to CTs on the medium-voltage sidethat may be placed on the medium-voltage circuit breaker’sline or load side. The simplified one line assumes the useof a secondary main circuit breaker. Other configurations arepossible, such as that without a secondary main circuit breakerwhere the zone interlocking would be connected directly fromthe feeders to the medium-voltage protective relay. That specificconfiguration is shown in Fig. 13. A configuration such asthis, using low-voltage (LV) CTs at the transformer secondarywith a multielement relay, allows the use of one relay for

Fig. 13. System of Fig. 12 with ZSI interlocking from feeders directly to MVrelay protecting the substation transformer and low-voltage main bus.

multiple transformers and can employ lower class CTs than anequivalent transformer differential implementation.

By definition, a current-limiting device must limit the energyallowed to flow during a fault event below what the prospectivefault current would otherwise deliver. Usually, the device isexpected to clear in less than half a cycle, but even if it takeslonger than that, the peak energy allowed to flow throughany one half cycle period is much less than the prospectiveone. Modern digital trip units are fast enough to implementalgorithms to detect the change in the fault current wave shapecreated by the operation of downstream current-limiting de-vices (waveform analysis). If downstream motor control centers(MCCs) have current-limiting fuses, the complete selectivityof current-limiting motor circuit protectors or current-limitingcircuit breakers from the MCC feeder to the primary relaycan be achieved with simultaneous instantaneous protectionfrom in-zone faults over a broad range of prospective currents.This slightly longer instantaneous algorithm coupled with fastsignal transfer and processing allows the low-voltage trips toissue a process and a zone blocking signal fast enough toaccomplish zone selective interlocking within the instantaneousoperating range. The corresponding algorithms and capabilitiesin medium-voltage relays allow blocking within relays in sim-ilar time frames. In this specific case, the addition of a 10-msdefinite time delay to the medium-voltage feeder relay allowssufficient delay to accomplish the required interlocking whilekeeping protection very quick for the complete low-voltagesubstation up to the secondary bushings of the transformer. Thepossible TCC for the system of Fig. 12 is shown in Fig. 14. Thepossible TCC for the system of Fig. 13 is shown in Fig 15.BothTCCs show the clearing time for a three-cycle medium-voltage(MV) circuit breaker with no additional relaying delays and


Fig. 14. Four-circuit-breaker system from Fig. 12 showing 250-A LV current-limiting molded case circuit breaker (MCCB), with 600-A upstream LVswitchgear feeder and 2400-A LV switchgear main, plus dual-element 50/51relay with two sets of CTs, the first one at LV with IOC and the second at MVwithout IOC.

Fig. 15. System of Fig. 13 with no secondary main circuit breaker and MVrelay IOC adjusted downward closer to low-voltage feeder’s short time pickup.

with only the instantaneous overcurrent (IOC) detection tim-ing, relay timing including mechanical output contacts, andan additional 10-ms definite time delay in the IOC logic toensure proper IOC blocking operation. A faster operation (few

Fig. 16. System of Figs. 12 and 14 in restraint mode (ZSI blocking signalfrom LV feeder). The fault is under the LV feeder, above the current-limitingMCCB, i.e., the fault is on the MCC bus.

milliseconds) may be obtained with most relays using solid-state output contacts. A five-cycle circuit breaker would add33 ms to the clearing time. If a maintenance switch mode ofoperation was used to control the low-voltage circuit break-ers and/or the medium-voltage relays for temporary improvedprotection, the circuit breakers should be able to implementeven more sensitive instantaneous trips as well as reduce in-stantaneous clearing time by approximately half a cycle. In thecase of the medium-voltage relay, the 10-ms IOC definite timedelay could be reduced to zero, and the IOC blocking schemecould be bypassed, so the IOC protection is fixed while themaintenance switch is enabled.

Fig. 16 shows how the device time–current curves changewhen a zone selective interlocking signal is present. In the caseof Fig. 16, if the feeder detects a short time or instantaneousblocking signal, it will issue a blocking signal. The low-voltagemain circuit breaker curves to slower backup protection po-sitions for both instantaneous and short time trips. The dual-element medium-voltage relay turns off the element operatedfrom the low-voltage CTs and relies on the element operatedfrom the medium-voltage CTs for backup protection. The endresult is that selectivity and backup protection are providedsimultaneously at all system levels. The system of Figs. 13 and15 would simply show the same feeder circuit breaker curvewith the medium-voltage relay’s lower protection curve thatincludes the IOC protection removed.

In both cases, selectivity between the feeder circuit breakerand the overcurrent devices in the MCC is achieved via theinstantaneous algorithm’s inherent capability to discriminatebetween a fault condition within the feeder’s zone of protec-tion and the let-through current temporarily allowed to flowby a current-limiting device in the MCC. This requires the


Fig. 17. Instantaneous and short time portion of TCC shown in Fig. 14 with15–13-kA arcing current superimposed on overcurrent protection device TCC.The curve is stretched vertically to facilitate reading clearing times.

feeder to be set based on the MCC branch’s known let-throughcharacteristics.

With the unrestrained settings shown in Fig. 14, the incidentenergy at the main low-voltage bus, including the rating at theprimary of the main circuit breaker and the feeder’s terminals,may be reduced below 4 calories. The switchgear bus, as wellas the feeder’s secondary terminal, may be below 4 calories.Fig. 17 shows the low-voltage arcing current (15–12.7 kA)superimposed on a portion of the TCC of Fig. 14 verticallystretched for easier interpretation. The medium-voltage relay’sIOC would trip between 80 and 90 ms (< 4 calories), thelow-voltage main at 80 ms (∼3 calories), and the low-voltageswitchgear feeder at less than 60 ms (< 3 calories). If themedium-voltage circuit breaker is a five-cycle circuit breakerinstead of a three-cycle one, the secondary main circuit breakerline side calories would increase to less than 5 calories due tothe low arcing current provided by the 1500-kVA transformer.

Note that the size of the substation transformer also affectsthe AFH ratings. AFH ratings are dependent on the amount ofcurrent as well as the time. Larger transformers will producemore fault current and produce higher AFH ratings per unittime. However, the instantaneous pickup settings are moredefined by the size of the MCC branch circuit breaker thatthe switchgear feeder is set to be selective with in this system.Hence, incident energy ratings may or may not increase signif-icantly at all buses, depending on the timing of the overcurrentdevice at the arcing current of interest. Generally, the low-voltage main circuit breaker and feeder protection in 480-Vsubstations rated 1500 to 2500 kVA can be reduced to under

8 calories as long as the branches in the MCC that drive theselective instantaneous pickup settings are not above 250 A forcircuit breakers or 400 A for fuses. The incoming terminals mayreach ∼10 calories for the highest fault currents when assuminga three-cycle circuit breaker clearing at 90 ms or ∼14 calorieswhen assuming a five-cycle circuit breaker with a clearing timeof 120 ms. In all cases, it is considerably better than a medium-voltage fuse that could take several seconds to clear a low-voltage arcing fault.

VI. CONCLUSION

Meeting the NEC minimum requirements for system designand transformer protection will not assure adequate transformerprotection from through-fault current damage or acceptable arcflash incident energy ratings in the secondary switchgear. How-ever, these goals can be achieved by exceeding the minimumrequirements of the NEC with dedicated primary relays thathave I-ZSI with secondary main and feeder circuit breakers. Pri-mary fuse disconnects can be replaced with dedicated primarycircuit breakers, improving protection and system reliabilitywhile reducing AFH.

Exact timing and setting capability may vary from manufac-turer to manufacturer and from the examples used in this paper;however, most modern low-voltage trips today have fast shorttime bands and zone selective interlocking, and most medium-voltage relays have instantaneous blocking capabilities evenif they do not have multiple protection elements. Althoughtiming and settings may vary somewhat, many different com-binations of these types of modern devices, in various con-figurations, should achieve significantly improved performanceover minimally designed substations that only achieve minimalNEC-compliant protection.

REFERENCES

[1] NFPA 70, National Electric Code, 2011, Article 450, page 70-343.[2] NFPA 70E, Standard for Electrical Safety in the Workplace, National Fire

Protection Association, 2012.[3] Recommended Practice for Protection and Coordination of Industrial and

Commercial Power Systems, 1986, Table 15-3, page 605.[4] NFPA 70, National Electric Code, 2011, Article 230-95.[5] Requirements for Liquid-Immersed Power Transformers, ANSI C57.12,

Table 2.[6] M. Valdes, P. Sutherland, and S. Hansen, “Optimizing circuit breaker in-

stantaneous trip settings for selectivity and arc flash performance simulta-neously,” in IEEE Elect. Safety Workshop Conf. Rec., 2010, pp. 112–118.

Ronald H. Simpson (M’83–SM’90) (1949–2012)graduated from the Georgia Institute of Technologyin 1977 with a degree in electrical engineering.

He spent 33 years in the field of power systemsengineering. He was with the GE Energy, Alpharetta,GA, USA. GE appointed him to the GE Field Ser-vice Engineers “Hall of Fame” in 2005. He au-thored several papers on power systems protectionand harmonics presented at PPIC and published inthe IEEE TRANSACTIONS ON INDUSTRY APPLI-CATIONS and IEEE Industry Applications Magazine.

Mr. Simpson was the Chair of the IEEE Pulp and Paper Industry Conferencein 2004.

Documents

NEC Design Compliance, System Protection, and Arc Flash Hazard