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IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 45, NO. 2, MARCH/APRIL 2009 569

Arc Flash and Coordination Study Conflictin an Older Industrial Plant

Peter E. Sutherland, Fellow, IEEE

AbstractOnce arc flash hazard analysis became a requirementfor many industrial power system studies, the reduction of arcflash hazards has become an important concern. Inevitably, thefactors that lead to reductions in arc flash hazards do not alwayslead to an improvement in other areas, i.e., in particular, protectivedevice coordination. This paper will examine several particularcases where an arc flash hazard analysis of an older industrialplant yielded several cases of buses where the hazard level wasextreme danger above category 4. By changing protective devicesettings and, if necessary, the devices themselves, the hazard levelcan be reduced. Methods to maintain coordination, if possible, arediscussed.

Index TermsArc flash hazard analysis, protective devicecoordination.

I. INTRODUCTION

AN ARC FLASH hazard analysis usually begins with a

study of a facility based upon the procedures and method-

ology of the National Fire Protection Association (NFPA) 70E

[1] and IEEE 1584 [2]. However, an arc flash hazard analysis

is usually performed in conjunction with a suite of other power

system studies [3], such as the following:

1) load flow;

2) short circuit;3) protective device coordination.

The results of an arc flash hazard analysis are labels to

be placed on equipment, which give, among other things, the

following:

a) the flash protection boundary, the distance within which a

person must wear personal protective equipment (PPE);

b) the hazard/risk category, a number from 0 to 4 indicating

which classification of PPE that the person must wear.

The arc flash protection boundary must be reasonable, such

that people who are not working on the equipment can still

perform their functions. For example, it should not extend

outside the fence of an outdoor substation or prohibit opening

the door of an indoor substation. If the hazard/risk category

is above level 4 (40 cal/cm2), no approach is possible with-

out deenergization of the equipment. This is usually called

Paper ICPSD-MT09-5, presented at the 2007 Industry Applications SocietyAnnual Meeting, New Orleans, LA, September 2327, and approved forpublication in the IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS bythe Power Systems Engineering Committee of the IEEE Industry ApplicationsSociety. Manuscript submitted for review October 31, 2007 and released forpublication September 2, 2008. Current version published March 18, 2009.

The author is with GE Energy Services, Schenectady, NY 12306 USA(e-mail: peter.sutherland@ieee.org).

Color versions of one or more of the figures in this paper are available onlineat http://ieeexplore.ieee.org.

Digital Object Identifier 10.1109/TIA.2009.2013597

danger or extreme danger on arc flash labels. It is de-

sirable that the risk category be standardized so that all per-

sonnel working on a single project, or piece of equipment,

can wear the same gear. Table 130.7(C)(9)(a) in NFPA 70E

gives recommended clothing for various tasks on different

equipment if a study has not been performed. For example, in

600-V class Switchgear, there are tasks at levels 03. Many

plants, however, standardize on level-2 and level-4 PPE. A

typical hazard/risk reduction task would be to reduce a cal-

culated extreme danger to level 3, or a level 4 to a level 2.

Thus, a reduction to a level 3 would mean that the personnelwould wear level-4 PPE.

Arc flash hazard levels depend upon fault current magnitude

and duration, I2t. The power going into the arc resistance

is a function of I2R, where R is the arc resistance. This

is multiplied by time, which is the arc duration. Since arcs,

currents, and resistances are in constant variation, this is really a

time-varying integral whose units are energy (calories). When

this energy is radiated to a persons skin, they experience an

incident energy (in calories per square centimeter), which is

what causes the burn.

The factors that can be controlled are in the timecurrent

characteristics of the system protective devices, reducing I2t

by reducing t for any given I. These factors include thefollowing.

1) Pickup: The minimum current at which a device actuates.

Lower pickup provides arc fault protection for a greater

range of fault currents.

2) Time delay: Shorter time delay reduces time to trip and

lowers I2t.

3) Instantaneous pickup: Operating time is typically the

minimum possible for the circuit breaker being used.

Lower instantaneous pickup settings reduce arc flash

hazard.

A more extensive list of six design changes and six overcur-rent upgrades is given in [4].

Protective devices in a power system are coordinated in

time and in current pickup in order to provide for an orderly

shutdown in case of a fault and to prevent blackouts. Changes

in protective device settings to solely reduce arc flash hazards

will inevitably result in a loss of coordination, resulting in

misoperation during faults and unnecessary blackouts.

This is slightly different than the problem of the design of

limited arc energy distribution systems [5], although many of

the same principles can be used.

It is the purpose of this paper to give some examples of these

coordination problems and how they may be resolved.

0093-9994/$25.00 2009 IEEE

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570 IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 45, NO. 2, MARCH/APRIL 2009

Fig. 1. Example 600-V substation.

Fig. 2. Coordination curves for substation of Fig. 1 (before).

II. EXAMPLES OF ARC FLASH VERSUS COORDINATION

A. Correcting an Arc Flash Problem When a Coordination

Problem Requires Trip-Unit Replacement

In this older substation (Fig. 1), the low-voltage circuit break-

ers use electromechanical dashpot-type trip units with wide

characteristics (Fig. 2). The main breaker has an instantaneous-

only characteristic (vertical bar on the timecurrent curve). The

transformer protection is from an older inverse-time overcurrent

relay, with nearly definite time characteristics. The relay and

low-voltage circuit breakers do not coordinate in this situation,

such that the only practical solution is an upgrade to modernelectronic equipment. The 600-V transformer secondary and

Fig. 3. Coordination curves for substation of Fig. 1 (after). Relay IAC 11 timedial reduced from 1.5 to 0.5.

TABLE IARC FLASH RESULTS AT BUS-4 VERSUS TIM E DIA L

SETTING FOR RELAY 50/51-1 FO R FIG. 1

bus both have high levels of incident energy, exceeding level 4.

Arc flash hazard risks can be reduced to level 3 on the trans-

former secondary and 600-V bus by reducing the time dial

of the relay from 1.5 to 0.5, as shown in Fig. 3 and Table I.

This does not change the coordination, or lack thereof, signif-

icantly, because the actual tie breaker characteristics, defined

by a dashpot-type trip unit, are probably not very close to the

published curve. Dashpots of these old-type circuit breakers

tend to suffer from drying out of oil and lack of the correctdashpot oil for maintenance. The main breaker is instanta-

neous only.

The main breaker is set at the same value as the instantaneous

unit of the tie breaker. Therefore, no changes of primary relay

setting or relay curve shape will alleviate the coordination

problem.

The only practical solution is to update the low-voltage

circuit breakers with solid-state trip units. However, the arc

flash problem needs to be corrected now, while the circuit

breakers might not be updated or replaced for some time. The

arc flash hazard can be reduced, while the coordination problem

should be addressed separately. When this occurs, the fact that

the relay setting has been lowered to reduce arc flash hazardshould not be forgotten.

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SUTHERLAND: ARC FLASH AND COORDINATION STUDY CONFLICT IN AN OLDER INDUSTRIAL PLANT 571

Fig. 4. Original configuration of 600-V substations on a 13.8-kV feeder withnormal inverse relays.

TABLE IIARC FLASH RESULTS AT BUS-16 VERSUS TIM E DIA L

SETTING FOR RELAY R1

B. Correcting a Coordination Problem Without

Introducing an Arc Flash Problem

In the existing configuration of this feeder (Fig. 4), there

is initially a severe arc flash problem, as shown in line 1 of

Table II, as well as a coordination problem (Fig. 5). This relay

does not protect the 500-kVA transformer because the pickup is

too high. It also does not coordinate with the main breakers on

the 1500-kVA substation.

It was decided to upgrade the feeder with a relay having a

very inverse timecurrent curve for better coordination char-

acteristics (Fig. 6). If the relay is set to protect the 500-kVA

transformer (Fig. 7 and line 2 of Table II), there is a coordina-

tion problem, in that the relay no longer coordinates with the

protection for the 1500-kVA transformer (Fig. 8).

The other alternative of setting the relay for the 1500-kVA(Figs. 9 and 10 and line 3 of Table II) transformer leaves the

Fig. 5. Original coordination of 600-V substations on a 13.8-kV feeder.

Fig. 6. Two 600-V substations on a 13.8-kV feeder with very inverse relays(protection of 500-kVA transformer).

500-kVA unit unprotected (Fig. 11) and raises the incident

energy to unacceptable levels.

One solution to this dilemma is the use of a transformerprimary fuse on the 500-kVA transformer, such that the incident

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572 IEEE TRANSACTIONS ON INDUSTRY APPLICATIONS, VOL. 45, NO. 2, MARCH/APRIL 2009

Fig. 7. Protection of 500-kVA transformer.

Fig. 8. Protection of 1500-kVA transformer with 500-kVA settings.

energy is within acceptable limits on the 600-V bus. This will

allow the primary relay R1 to be set to protect the 1500-kVAtransformer.

Fig. 9. Two 600-V substations on a 13.8-kV feeder with very inverse relays(protection of 1500-kVA transformer).

Fig. 10. Protection of 1500-kVA transformer with settings for arc flashreduction.

It is important to select the proper fuse when remediating

arc flash hazards. Two different fuses of the same rating andmanufacturer, even if both are current-limiting fuses, may have

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SUTHERLAND: ARC FLASH AND COORDINATION STUDY CONFLICT IN AN OLDER INDUSTRIAL PLANT 573

Fig. 11. Protection of 500-kVA transformer with 1500-kVA settings.

Fig. 12. Two 600-V substations on a 13.8-kV feeder, with fast fuses onsmaller substation.

TABLE IIIARC FLASH RESULTS AT BUS-16 VERSUS FUS E TYPE

(R1 AT 6.0 AT, 0.5 TD)

Fig. 13. Two 600-V substations on a 13.8-kV feeder, with slow fuses onsmaller substation.

completely different arc flash limitation characteristics. This is

shown in Fig. 12 and Table III, where, for this situation, the

fuse in line 1 has an incident energy of 6.6 cal/cm2, while that

in Fig. 13 and in Table III (line 2) has 44.9 cal/cm2

, which is inthe extreme danger category.

Looking at the timecurrent curves (Fig. 14), the fuse-1 curve

sweeps down and to the left, providing short clearing times

across the range of high available fault currents. However, the

fuse-2 curve is steep, providing long clearing times at all but the

highest fault currents. An example of changing a slow fuse for

a fast fuse can also be found in [6]. However, the fast fuse may

trip on transformer inrush, making that option unworkable.

III. CONCLUSION

Resolution of combined arc flash and coordination problems

requires evaluation of multiple options. Solution of one prob-lem may cause the other problem to reappear in another place.

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Fig. 14. Comparison of fuse timecurrent curves.

The presence of old equipment with unreliable characteristics

complicates the assessment. Published timecurrent curves

and breaker opening times should not always be relied upon.

Proposed solutions may not always be implemented, and the

engineer should be prepared for a long drawn-out process

before all problems are resolved. Proposed solutions which

reduce arc flash hazards may create other protection problems

which render the solution unusable.

REFERENCES

[1] Standard for Electrical Safety in the Workplace, NFPA 70E, 2004.[2] IEEE Guide for Performing Arc-Flash Hazard Calculations,

IEEE Std. 1584-2002.[3] IEEE Recommended Practice for Industrial and Commercial Power System

Analysis, IEEE Std. 399-1997.[4] M. Hodder, W. Vilcheck, F. Croyle, and D. McCue, Practical arc-flash

reduction, IEEE Ind. Appl. Mag., vol. 12, no. 3, pp. 2229, May/Jun. 2006.[5] J. C. Das, Design aspects of industrial distribution systems to limit arc

flash hazard, IEEE Trans. Ind. Appl., vol. 41, no. 6, pp. 14671475,Nov./Dec. 2005.

[6] R. Doan and R. Sweigart, A summary of arc-flash energy calculations,IEEE Trans. Ind. Appl., vol. 39, no. 4, pp. 12001204, Jul./Aug. 2003.

Peter E. Sutherland (M77F07) received the B.S.degree in electrical engineering from the University

of Maine, Orono, and the Ph.D. degree in elec-tric power engineering from Rensselaer PolytechnicInstitute, Troy, NY.

In 1987, he joined General Electric (GE)Company, Schenectady, NY, and held a variety of po-sitions, becoming a Senior Engineer in the GE PowerSystems Energy Consulting Department. In 2001,he joined SuperPower, Inc., Schenectady, where heworked on applications of superconductivity to elec-

tric power systems. He was then with EPRI PEAC Corporation (currentlyEPRI Solutions, Inc.), Schenectady, as a Consulting Engineer. He is currentlya Lead Consultant with GE Energy Services, Schenectady. He is the author ofnumerous technical papers.

Dr. Sutherland is a Registered Professional Engineer in the States ofPennsylvania, Maine, and New York. He is active in the IEEE IndustryApplications Society and in the IEEE Schenectady Section.