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CONSIDERATIONS IN UNIT SUBSTATION DESIGN TO OPTIMIZERELIABILITY AND ELECTRICAL WORKPLACE SAFETY

ByDavid B. Durocher

Senior Member, IEEEIndustry ManagerEaton Corporation

ABSTRACT

Many legacy low and medium-voltage unit substations installed today are based upon older designs thattook advantage of reduced first cost opportunities allowed by existing installation codes and standards.Fast-forward to how these substation designs fair in safety and reliability today, particularly in industrialprocess applications found in cement, pulp and paper, petroleum & chemical and others, some of theexercised opportunities applied in the past begin to look more like liabilities than assets. Legacyengineering decisions once thought to be prudent take on new meanings today, particularly when thesedecisions are viewed through the lens of emerging new workplace safety standards. The critical issue of

addressing destructive arc-flash hazards associated with persons working on or around energizedelectrical equipment must now be considered.

Because traditional substation designs often appeared to involve some compromise regarding both safetyand reliability, a design team of a major process industry user took a fresh look at unit substation design.The design review took place in conjunction with construction of a Greenfield plant built in the spring of2009 in the USA. This paper will review the design limitations of traditional unit substation configurations,offer an overview of the alternatives considered by the Greenfield site project team, and discuss technicaland safety validation of the design that was ultimately selected and installed. Economic comparisons totraditional designs, changes in the owner operating and safety procedures for plant personnel as a resultof the engineering design changes, and overall design acceptance by operations will also be reviewed inthis paper.

Index Terms Process Industries, Power Distribution, Unit Substations, Design for Safety, ElectricalWorkplace Safety.

INTRODUCTION

Low and medium voltage unit substations are applied universally across most every industry. At the tree-top level, unit substations are used simply to transform medium-voltage, typically 15 to 25kV, to a lowerdistribution voltage, typically 0.48 to 4.16kV, for application in supporting a host of various motor andprocess equipment loads. Fig. 1 shows a typical low-voltage unit substation. In this case, the primaryassembly at the left is a medium-voltage fused load break switch. For this example, we will assume theprimary voltage is 13.8kV. For assemblies in North American industry, this assembly is typically designedto metal-enclosed switchgear standard ANSI/IEEE Standard C37.20.3 [1]. This assembly includes a load-break isolation switch with ratings of 600 or 1200 amperes and a medium-voltage current-limiting fuse,appropriately sized to protect the transformer. The primary switchgear is close-coupled to a substationtransformer, either dry-type or liquid filled. The substation transformer is designed to ANSI/IEEE StandardC.57.12 with wall-mounted primary and secondary bushings. There are many different substationtransformer design alternatives to choose from, beyond the scope of this paper. Good information on thealternatives can be found in other technical papers, including [3]. In this case, the transformer rating isshown at 2000kVA. With a secondary distribution voltage at 480Y/277 volts, the low-voltage bushings areshown close-coupled to metal enclosed low-voltage switchgear. In Fig. 1, the low-voltage switchgearconsists of a 3200 ampere secondary main bus and secondary metering, with no secondary main circuitbreaker, connected to four 1200 ampere feeder circuit breakers. There are again variations on low-

978-1-4244-6409-8/10/$26.00 2010 IEEE

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Fig. 1: Typical Unit Substation today: Primary metal enclosed load interrupterswitchgear, fused load-break switch. Transformer close-coupled liquid filled ordry/cast resin. Secondary switchgear metal enclosed with low-voltage powercircuit breakers shown here with four feeders and no main breaker.

3200A

125E

13.8kV

480Y/277V

2000kVA

5.75%Z

1200A

1200A

1200A

1200A

voltage switchgear designs. For process industry applications, most frequently these assemblies aremanufactured to UL1558 Standards [4].

This unit substationassembly, installed indoor oroutdoors, remains thestalwart of power distributionsystems of today. In someapplications, the primarymetal-enclosed switchgearand transformer may bemounted outdoors and asecondary air terminalchamber at the transformerwill cable-feed to indoor low-voltage switchgear. Withouta doubt, the integrateddesign shown here hasbeen low cost and reliableperformer and in thisconfiguration, continues tobe applied in many industrialsystems to this day.

DESIGN CONSIDERATIONS

In anticipation of the upcoming project, the design team for the Greenfield site took on the task ofinvestigating existing unit substation configurations carefully to identify where there may be some inherenthidden flaws in the design. It is important to note that prevailing codes and standards regardinginstallation of this equipment had an impact on the unit substation design. In the US, the prevailinginstallation document that applies is the National Electrical Code (NEC) [5]. Lets investigate two areas ofthis code that impact the design and installation of the unit substation presented here.

NEC Article 240.21(C)2 Overcurrent Protection

Article 240.21(C) of the NEC addresses required overcurrent protection, specifically related to transformersecondary conductors. The article states that a set of conductors feeding a single load shall bepermitted to be connected to a transformer secondary, without overcurrent protection of thesecondary. The article defines six conditions, specified in 240.21(C)(1) through 240.21(C)(6), underwhich secondary overcurrent protection is not required. Sorting through the six options for our close-coupled unit substation example, points us to the condition outlined in 240.21(C)(2) which most closelyapplies. This condition gets fairly involved, with four different sub-conditions, all which must apply in orderto satisfy the exception of no secondary protection. Relevant language in these sub-conditions includes:

240.21(C)(2): Transformer Secondary Conductors Not over 3 m (10 ft) Long.

(1) The ampacity of the secondary conductors isa). Not less than the combined calculated loads on the circuits supplied by the secondaryconductors

b). Not less than the rating of the device supplied by the secondary conductors or not less than therating of the overcurrent-protective device at the termination of the secondary conductors.

The first item (1) a) above requires that the engineer perform calculations to determine the total conductorload and then specify a conductor size to support the calculated load. Referring back to the Fig. 1example, note that the secondary conductor is specified at 3200A. So, although the total connected ratedload of the secondary feeder breakers is 4800A (four breakers rated at 1200A each), the NEC allows the

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designer to assume a load diversity and size the secondary bus as some lower value. The second item(1) b. in essence states that the secondary conductor ampacity be either greater than the overcurrentdevice at which the conductors terminate (in this configuration, there is no such device) or greater thanconductor or bus rating in the equipment where the conductors terminate. From this language, it seemsclear that secondary bus protection for the unit substation is not required. There is ongoing debate insome circles regarding the word device in this article, as some see the term device to mean somethingother then the switchgear. Interestingly, the NEC Code Making Panel supporting this Article is reviewingthis language and considering future revision to clarify the meaning. This aside, note also that Article240.21(C) includes a Fine Print Note stating For overcurrent protection requirements for transformers,see 450.3.

NEC Article 450.3 Equipment Transformers

Article 450.3 of the NEC addresses secondary overcurrent protection of transformers. Note 2 for Table450.3(A) states: Where secondary overcurrent protection is required, the secondary overcurrent deviceshall be permitted to consist of not more then six circuit breakers or six sets of fuses grouped in onelocation. Traditionally referred to as the six disconnect or six handle rule, this provision allows the userto forego secondary overcurrent protection in a unit substation, provided there are no more than sixfeeder devices in the assembly. For the example shown in Fig. 1, this is clearly the case, so this assemblycould be installed without concern that the design would violate the applicable installation code.

APPLICATION WAKE-UP CALL

Although the six feeders no main unit substation passes all requirements outlined in the applicablestandards, the unit substation equipment manufacturer and the project team investigating designalternatives were not satisfied this was the best approach. Earlier experiences in industrial plants wherearc-flash studies have been performed as outlined in NFPA-70E [6] using calculation methods inIEEE1584 [7] yielded some very revealing and disturbing results. In the event of a secondary bus fault,the NFPA-70E standard requires that the upstream overcurrent protective device be used in determiningthe available arcing current. In this case, the current-limiting fuse on the primary of the substation is thedevice used in the calculation. Specifically, Fig. 2 below shows calculations revealing arc flash energiesat the secondary switchgear in excess of 700 calories/cm 2. These levels are defined in IEEE1584 asUNAPPROACHABLE, where effectively no Personal Protective Equipment (PPE) would be adequate in

safeguarding personnel should a bus fault occur while persons were working on the energized substation.In many existing facilities, unit substation feeder devices were used as a lockout/tagout point whiledownstream equipment was being serviced or maintained. The elevated arc flash energies effectivelymade it unsafe to rack-out a secondary feeder breaker while the secondary bus was energized. Inprocess industry applications where electrical workplace safety is paramount and energizedlockout/tagout is common, the six feeders no main unit substation design was simply no longer apractical option. A number of vintage unit substations that employed the configuration shown in Fig. 2,have effectively been upgraded to improve reliability and electrical safety. Although beyond the scope ofthis paper, one such upgrade is presented in the case study outlined in [8].

Returning to the primary current-limiting fuse in the unit substation shown in Fig. 2, selecting the rating ofthis fuse to account for transformer inrush results in a melting time requirement up to 12X the transformerrated primary current for 0.1 seconds. In the 2000kVA substation shown in Fig. 2, a 125E fuse is applied.

A bolted secondary fault would result in a primary current of less than 1000 amps, resulting in a fuseclearing time of over 2 seconds. The example calculation assumes an arcing fault of 10,000 amperes onthe secondary bus, resulting in a fuse clearing time of 160 seconds. In either the case of a bolted fault oran arcing fault, the secondary arc flash energy on the secondary bus of this unit substation design isUNAPPROACHABLE. In addition, should a bus fault occur while this assembly was energized, the likelyresult beyond extremely high arc flash energies would be extensive equipment damage caused by theheat energy developed before the primary fuse would clear. In a process industry environment, thistranslates to hours or perhaps days of downtime. In the end, the primary fuse in the 13.8kV fused load-break switch shown in Fig. 2, is intended to protect the transformer, not the secondary bus. Adding asecondary main circuit breaker would resolve this issue of protection in some applications. This would in

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effect protect the secondary bus downstream of the main breaker. However, the bus from the transformersecondary terminals up to the main is still not adequately protected.

In applications where the primary assembly and transformer are outdoors and cable connected to thesecondary switchgear, the secondary bus protection issue becomes more problematic. Clearly, anopportunity existed for the project design team to consider design alternatives that would offer betterperformance, both in reliability and workplace safety.

A PATH FORWARD VIA PRODUCT TECHNOLOGY

Recognizing the limitations of the legacy unit substation design, the project team worked with the powerdistribution equipment supplier to review alternative designs that might offer improved performance.Because of the extreme hazard and potential for extended outage time, the group quickly dismissed theage-old approach of installing unit substations based on the six feeders - no main design. The strategywas to look at designs that included a secondary main overcurrent protective device (in this case, a low-voltage power circuit breaker) and then investigate design alternatives that might offer advantages to thisdesign approach. The group recognized that adding a secondary main device would add cost and wasinterested in alternatives that might perform as well, or better, than the secondary main design.

The group considered several emerging technologies that might offer improved performance. Three

technologies were considered and ultimately applied. These are discussed below:15kV Vacuum Primary Circuit Breaker

One technology that appeared promising was in the area of medium-voltage vacuum circuit breakers. Thegroup believed that application of a low-cost circuit breaker in the primary of the unit substation, providingboth primary and secondary current protection, would be a desirable alternative to the traditional fusedload-break switch. Although vacuum circuit breakers have traditionally involved higher space and costthan a fused switch, some manufacturers had developed newer vacuum breakers that looked promising.Fig. 3 shows and example of one such design available. In the North American markets, vacuum circuitbreakers are manufactured to ANSI Standard C37.20 [9]. Inspired in part by a trend toward global design

Fig. 2: Limitations of existing unit substation designs have been identified for existing plants after arc-flash hazardassessments in accordance with IEEE1584 have been performed. In this example, an arcing fault at the unitsubstation secondary bus results in a calculated incident energy of 702.4 cal/cm 2 .

NFPA70E: Fault at 480V Switchgear Bus 31.8kA Symmetrical Fault current 1167 AF Boundary 702.4 cal/cm 2 @ 18 UNAPPROACHABLE

NFPA70E-2009: Category 4 ishighest category @ 40 cal/cm 2

3200A

125E

Bus Fault at 480V Switchgear 10kA Secondary Arcing Fault At 13.8kV = 348A primary fault125E fuse clearing time = 160 seconds

Arc Flash & PPE

2000kVA

5.75%Z

13.8kV

480Y/277V

1200A

1200A

1200A

1200A

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standards, traditional designs have given way to newer offerings that are smaller, lighter, and haveimproved functionality. As is shown in Fig. 3, although the newer design vacuum breakers are onlyavailable in limited ratings, most offer a smaller size with fewer parts. Notably different from traditionalvacuum circuit breakers,the new design includesan integral trip unit withlinear trip actuator. Thisactually offers improvedperformance with reducedclearing times, in part dueto the smaller sizedcomponent. Wheretraditional vacuum circuitbreakers require 5 cyclestotal clearing time, thenewer vacuum breakercan in some applications,clear a fault within 3cycles. In unit substationapplications where higherratings are not asimportant as in medium-voltage switchgear line-ups, the newer designbreaker offers a viablealternative.

Zone Selective Interlocking

Zone selective interlocking for low and medium-voltage circuit breakers has been an available technologyfor many years and most all manufacturers offer this feature as a standard offering for low-voltage powercircuit breakers. The application is reviewed here and discussed relative to Fig. 4 below. Fig. 4 shows theconfiguration of a typical low-voltage switchgear assembly in a low-voltage substation with a main power

circuit breaker and three feeder circuit breakers. Zone selective interlocking is a functionality of the circuitbreaker tripping system. Inthis example, all fourbreakers (the main andthee feeders) areconnected together with acommon zone controlcircuit. The main andfeeders are selectivelycoordinated so that thebreaker nearest the faultclears first. A slightlylonger short time delaysetting for the mainbreaker is used to assurethe system is selectivelycoordinated. In the eventof a downstream faultshown at (1) on Fig. 4, thefeeder breaker nearest thefault would trip, followingthe short-time delay settingof 0.2 seconds or 12.5

15kV Vacuum Circuit Breaker 25H X 20W X 18 D, 330 lbs

ANSI C37.20 Rated at 25 and 40kA

600, 1200,2000 and 2500A ratings

Integral trip unit with linear trip actuator

2-step stored energy mechanism

15kV Vacuum Circuit Breaker 31H X 29.5W X 25D, 460 lbs

ANSI C37.20 Rated at 25, 40 and 50kA

1200, 2000, 3000 and 5000A ratings

External relay required

2-step stored energy m echanism

Fig. 3: Newer design 15kV class vacuum circuit breakers are manufactured tothe same standards as previous versions, but are smaller, lighter, and haveincreased functionality. Shown above is a comparison of the newer design atleft and traditional design at right. The new design shown includes an integralmultifunction trip unit.

Fig. 4: A block diagram example of unit substation low-voltage switchgear isshown with zone selective interlocking applied. In the event of a bus fault,the ZSI controls will trip the main breaker with no intentional delay.

SD=0.5S

SD=0.2SSD=0.2SSD=0.2S SD=0.2SSD=0.2SSD=0.2S

M1

F1 F2 F3X(2) Bus Fault

X (1) Downstream Fault

ZSIControl

wires

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cycles on a 60 hertz system. If however a bus fault shown at (2) on Fig. 4 occurred, the main circuitbreaker would be called upon to clear the fault. Without zone selective interlocking, the breaker short-timedelay trip setting of 0.5 seconds or 30 cycles would dictate the clearing time. A zone selective interlocking(ZSI) control connection between all circuit breakers adds intelligence to this system. When a bus faultoccurs, ZSI allows the main breaker to interrogate the feeder breakers in the zone to determine if theysee a fault as well. If all report back that there is now downstream fault, then the main breaker will tripwith no intentional delay.

The ZSI feature is simple to enable and can offer significant advantages in reducing potential arc flashhazards described previously. For a typical low-voltage system capable of delivering 35,000 amperessymmetrical fault current, calculations in accordance with IEEE1584 show that adding ZSI can reduce theincident energy from 43.7 calories/cm 2 to 7.0 calories/cm 2. The NFPA70E Standard for Electrical Safety inthe workplace defines the first condition above as UNAPPROACHABLE and the second as Hazard RiskCategory 2, a significant difference.

Multiple Settings Groups

One final technology applied in todays power distribution systems is a newer capability offering multiplesettings group capability for protective relays used with circuit breakers. Although this capability has beena feature for several years on a few higher-end protective relays used in medium-voltage systems,several tripping systems applied in integral trip units of low-voltage power circuit breakers now alsoinclude this feature. In a similar concept described above in ZSI applications, use of multiple settingsgroups for circuit breaker tripping enables the tripping system to respond differently for different systemconditions. Again, referring to Fig. 4, if a downstream fault condition existed, the feeder circuit breakersetting would dictate that the 0.20 second short-time delay setting time out before the breaker trips. Thepower systems engineer determines this setting to assure coordination with downstream overcurrentprotective devices and system loads so that the device nearest the fault trips first. In some cases forinstance, large downstream motors may have high inrush currents or long acceleration times that willaffect the short-time setting of the feeder breakers in the unit substation. As discussed previously, addingan intentional delay to a breaker clearing time comes at the cost of higher incident energy and arc-flashhazards. When personnel are working in downstream equipment, such as a low-voltage motor controlcenter, the opportunity for a dropped tool or accidental contact of a tool or probe between an energizedconductor and ground is increased. As this could lead to a higher incident of short circuits or arc-flash

incidents, it is often prudent to reduce trip settings to enable the upstream circuit breaker to trip faster.

Multiple settings groups effectively allow for the power systems engineer to establish one group ofprotective settings during normal operations and another maintenance mode setting that can be usedwhile personnel are working in downstream equipment. Fig. 5 illustrates application of the multiple settinggroup technology. At the left of Fig. 5, the integral Long-time, Short-time, Instantaneous & Ground (LSIG)integral trip unit mounted in the low-voltage power circuit breaker is equipped with an on-off switch thatenables a second group of settings. In the normal mode, the power systems engineer settings arebased on a selectively coordinated system, while in the maintenance mode, the LSIG settings arereplaced with an instantaneous only setting, effectively disabling the normal short-time settings. Theresult is a faster clearing time of the circuit breaker should a downstream fault occur. At the right of Fig. 5,note that the before and after coordination curves are shown to demonstrate the impact of themaintenance setting. The selectively coordinated curves set at the left shows the main and feeder circuitbreaker curves and plots a short-circuit current of 5,600 amperes. Note that due to the short-time delaysetting for the feeder circuit breaker, the time to clear this lower level fault is extended. The curve set onthe far right shows the maintenance mode enabled, which effectively shifts the instantaneous setting ofthe feeder breaker to the left. The result in this example is a reduction in arc-flash energy from 11calories/cm 2 to less than 4 calories/cm 2. This demonstrates the advantage of the multiple setting groupfeature.

The maintenance (or instantaneous only) mode actually allows for faster clearing times than the normalinstantaneous settings, in part because the tripping system responds to peak currents as opposed to thenormal RMS or root mean squared currents. Since the tripping system is not burdened with the additional

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RMS calculation before sending a signal to the circuit breaker to trip on overcurrent, the time to actuallyopen the breaker contacts during a fault is reduced. Typically, instantaneous clearing times can occur in 3cycles rather than the standard 5-cyle trip for this class of circuit breaker. Although clearing in anadditional 2 cycles (32 milliseconds) seems insignificant, this actually can mean a difference in theHazard Risk Category, typically reducing the hazard from HRC2 to HRC1.

It is important to understand that the multiple settings group capability does represent a trade-off on twodifferent fronts. First, depending on the instantaneous setting selected, selective coordination of thesystem may be compromised. In the Fig. 5 example, note that the curve to the far left of the plot (brown incolor) represents an across-the-line start of the largest motor fed by this substation feeder breaker. In theselectively coordinated setting, starting this motor would assure this motor could be started without afeeder breaker trip. However, in the maintenance mode, note from the curve set at the right that thefeeder breaker would indeed trip. Second, application of multiple settings group functionality dictates thatfacility maintenance practices be revised and then adhered to. Maintenance persons will need to adopt aprocess where the maintenance mode could be safely engaged while downstream energized work isbeing performed, and also be assured that the protective settings were returned to normal aftermaintenance is completed. It would be typical for the maintenance mode settings to be enabled with alockable switch and door-mounted light so this alternative maintenance setting could be included in thefacility lockout/tagout procedure.

Finally, it is important to note that the Occupational Safety and Health Administration (OSHA) clearlyprohibits work on energized equipment. Specifically, OSHA 29 Code of Federal Regulations (CFR) Part1910.333 (a)(1) [9] requires that live parts be deenergized before an employee works on or near them .There is simply no argument that turning the power off results in the safest working condition. However, insome process industry environments, deenergizing the power system is simply not practical and at timescan result in an even greater hazard.

LSIG Trip Unit

HRC = 1 (< 4 cal/cm2)

AF Current = 5.6kA AF Current = 5.6kAHRC = 3 (11 cal/cm

2

)Fig. 5: Newer designs of stand-alone and integral circuit breaker trip units include capabilities for multiple settingsgroups. Selectively coordinated settings can be overridden by an instantaneous only setting while downstreammaintenance is being performed. At the center are the selectively coordinated coordination curves. At the right, thefeeder breaker instantaneous setting is shifted, enabling the breaker to clear the fault faster during a lower levelarcing fault.

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THE GENESIS OF A NEW SUBSTATION DESIGN

Application of the various technologies discussed in the previous section came to fruition in upgradingseveral existing unit substations at an integrated pulp and paper mill in the Western United States.Following a facility wide effort to update power systems studies to achieve compliance with NFPA70E, thesite engineering team discovered that most of the areas of very high or UNAPPROACHABLE incidentenergies as calculated by the system study were at the secondary bus of low-voltage unit substations. Infact, the results of the study include actual calculated incident energy values for one of the 2000kVAsubstations reviewed previously with the results as shown in Fig. 2. In this facility, since most existing unitsubstations were already installed, adding new protective devices such as a secondary main low-voltagecircuit breaker was not practical. There simply was no room to add new assemblies. Fig. 6 shows whatwas ultimately installed. The existing unit substation was upgraded by removing the medium-voltagesfuses in the existing fused load-break switch, and replacing them with a new fixed-mount vacuum circuitbreaker. Adding a vacuum breaker with an integral overcurrent trip unit at the primary allowed the abilityto add secondary current sensors at the transformer secondary spade connections, resulting insecondary bus overcurrent protection. In addition to the integral trip unit, a second overcurrent protectiverelay along with primary current transformers was added to protect the transformer, a necessary additionafter the primary fuses were removed to make room for the vacuum breaker. In this application, the siteengineering team elected to add multiple settings group functionality to the vacuum breaker integral tripunit. This allowed for an additional maintenance setting that could be used when necessary. In this case,

the maintenance setting was used primarily when the existing secondary draw-out power circuit breakerswere being racked onto or off of the energized secondary bus. The site routinely used the secondaryfeeder breakers as a convenient systems location to perform lockout/tagout of downstream loads. In acontinuous process environment, it was not practical to deenergize the unit substation to perform thiswork. Before the substation upgrade, the extremely high incident energies at the secondary buseffectively prohibited removal of secondary feeder breakers. Further details outlining this unique solution

Fig. 6: Unit substation retrofit included a vacuum breaker installed at the primary. Both primary and secondary

overcurrent protection was installed, reducing incident energy at the secondary switchgear main bus from 702.4cal/cm 2 to 1.4 cal/cm 2 .

15kV Vacuum Breaker

Before AfterArc Flash Study Results

Sym. Fault at 480V Switchgear Bus 31.8kA 31.8kA

AF Boundary 1167 18

Cal/cm 2 702.4 1.4

NFPA70E HRC Unapproachable 1

Improved Unit Substation DesignLV Substation with Retrofit Vacuum Primary Breaker

86

ST

Integral50/51 Relay

50/51Relay

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that improved both the safety and reliability of unit substations at this mill site are explained in the awardwinning paper referenced previously [8].

THE GREENFIELD SITE DESIGN SELECTION

Drawing upon new technologies and unit substation retrofit experiences described previously, the designteam for the Greenfield industrial plant drove toward the optimum design. The group determined early-onthat secondary bus protection, either via a secondary main circuit breaker, or from a vacuum primarybreaker with secondary current sensors was required. Past experience proved that selection andapplication of a primary fuse to protect the transformer and expect this device would also adequatelyprotect the secondary bus, was a poor design approach.

Because the new site required both low-voltage (480Y/277V secondary) and medium-voltage(4160Y/2400V secondary) unit substations, the design team decided to move to application of a primaryload-break switch over a fixed mounted vacuum circuit breaker at the primary as a standard platform forboth low and medium-voltage unit substations. A product was commercially available that was configuredas shown in Fig. 7. Note from the section-view at the right that the incoming power enters at the top-rearof the assembly. The incoming cable termination is designed to accommodate a typical drip loop and alsohas room so that medium-voltage cables can be looped in and out of the assembly to feed an adjacentunit substation. Above the load-break switch is a distribution class lightning arrestor to protect theincoming of each substation. Bus runbacks on the load-side of the switch include current transformers,connected at the vacuum breakers to support primary overcurrent protection of the transformer. Thevacuum breaker in the lower compartment includes an integral trip unit. Note also at the lower rear of theassembly is a snubber network, the purpose for which is described below.

Vacuum Interrupters and Chop Currents

One phenomenon which is not widely discussed or understood is the potential for voltage transients thatoccur when the vacuum interrupter in a vacuum circuit breaker opens an inductive load. One of thephysical characteristics of all vacuum interrupters (VI) is a phenomenon called chop current. When thecontacts of a VI open, current continues to flow through the arc drawn across the contacts within thevacuum bottle. In an ac sine-wave, as the current approaches zero, the energy across the arc cannot besustained within the vacuum. When the arc energy reaches a low current level, the arc is immediately

Line

Load

Snubber

LA

Vac Bkr

LBSwitch

Fig. 7: Greenfield site included 11 low and medium-voltage unit substations, each with a primary load-breakswitch over a fixed mounted vacuum circuit breaker configured as shown. This replaced previous fused load-

break switch designs, adding secondary bus overcurrent protection.

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quenched and the current is driven to zero nearly instantaneously. The current value where the energycollapses to zero for a VI is known as the chop current. All VIs have this chop current characteristic andthis value will typically be published by the VI manufacturer. Often on the order of 6 to 10 amperes, chopcurrent is a function of the VI design itself, including geometry, material composition, hardness of thecontact surface and other physical characteristic. Because energy cannot be created or destroyedinstantaneously, driving current to zero with very high di/dt results in corresponding voltage transientdv/dt, when switched into an inductive load. Although VIs are typically applied in medium-voltageswitchgear and motor controllers where hundreds of feet of cable connect the vacuum breaker element tothe supported load, in this unit substation application the vacuum circuit breaker is often within 10 feet ofthe transformer primary winding.

Transient studies performed by the equipment manufacturers power systems engineering group provedthat voltage transients caused failure of the primary winding of a number of substation transformers. Fig.8 shows one such transformer, a vacuum pressure impregnated (VPI) dry-type design that failed turn-to-turn at the first primary winding. In this application, voltage transients caused due to VI current chopexceeded the Basic Impulse Level (BIL) of the transformer design. Fig. 9 shows the results of a transientstudy with the VI opening as a chop current of 6 amperes as shown at the left, resulted in acorresponding voltage transient as shown at the right. Note from Fig. 9 that the negative peak voltagetransient is nearly 150kV, exceeding the 95kV BIL rating of most 15kV class substation transformers.

To curtail the severe voltage transients caused due to the VI in close proximity to the transformerinductive load, the equipment manufacturer designed a simple Resistor-Capacitor AC snubber network.This snubber, comprised of three single-phase 15kV class capacitors and series connected resistor

Transformer Failure On VI De-Energization

Flash/Burn Marks

Coil to Coil Failure

Fig. 8: Unit substation dry-type transformer field failure likely caused by VI switching transients.

Fig. 9: Chop current of the vacuum interrupter shown at left result in very high voltage transients shown at right.

-150kV!

Voltage Waveforms Without Snubbers

0

50

100

150

- 50

- 100

- 150

Current Waveforms Without Snubbers

Ichop

+6 amps

0

20

40

60

- 20

- 40

- 60

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elements, was connected on the load terminals of the vacuum breaker assembly. The snubber assemblywas mounted as a component in the substation primary medium-voltage load break switch and fixedvacuum breaker assembly. Fig. 10 shows a photo of one of the three-phase snubbers at the center andthree single-phase assemblies at the far right. At the left, the resulting impact from adding the R-Csnubber as calculated from the transient study shows that the peak voltage transients have beensignificantly reduced in this example to a level below 30kV.

Putting it all Together

Since the site would apply cast resin coil design transformers, the entire unit substation assembly wasdesigned for close-coupled indoor application. A rigorous analysis of several alternative unit substationconfigurations was completed as a part of the process. Particular focus on the unit substation first cost forvarious alternatives was reviewed to assure the improved design alternatives were not addingsignificantly to the cost. Table I shows the first cost of several alternative designs considered. Note thatthe values shown are estimates, as the relative magnitude comparing one design versus another is therelevant issue. Because the economic modeling suggested that applying a primary load-break switch over

a fixed mounted vacuum circuit breaker with an integral trip unit was the best overall selection, the designteam elected to establish this approach as the Greenfield site standard for both low-voltage and medium-voltage unit substations. The team selected a metal-enclosed assembly at the primary of each unitsubstation, built to the ANSI Standard C37.20.3 [10]. As shown in Table I, a metal-clad assembly, built tothe ANSI Standard C37.20.2 [11] was also considered. This design included a draw-out vacuum breakerand no visible load-break switch. Ultimately, the metal-clad draw-out design was dismissed, as it provedmore costly and lacked the feature of a visible blade incoming disconnect device, a valuable featurewhich was used as a part of the company lockout/tagout safety procedure.

TABLE ISUBSTATION ALTERNATIVES PRIMARY

SWGRSUBSTATIONXFMR

SECONDARYSWGR

TOTALS

2000kVA: 13.8kV TO 480Y/277V, 600A LB SW &FUSE, LIQ TRX, 3200A MCB, 4-800A FCBS

$19,000 $90,000 $88,000 $197,000

2000kVA: 13.8kV TO 480Y/277V, 600A LB SW &VAC BKR, LIQ TRX, 3200A BUS, 4-800A FCBS

$31,000 $90,000 $72,000 $193,000

2000kVA: 13.8kV TO 480Y/277V, 600A LB SW &FUSE, CAST TRX, 3200A MCB, 4-800A FCBS

$17,000 $165,000 $86,000 $268,000

2000kVA: 13.8kV TO 480Y/277V, 600A LB SW &VAC BKR, CAST TRX, 3200A BUS, 4-800A FCBS

$29,000 $165,000 $70,000 $264,000

5000kVA: 13.8kV TO 4160Y/2400V, 600A LB SW& FUSE, LIQ TRX, 1200A MCB, 2-1200A FCBS

$19,000 $175,000 $118,000 $312,000

5000kVA: 13.8kV TO 4160Y/2400V, 600A LB SW& VAC BKR, LIQ TRX, 3200A MCB, 4-800A FCBS

$31,000 $175,000 $85,000 $291,000

Volt age Waveforms With Snubbers

0

10

20

30

- 10

- 20

- 30 -30kV

Fig. 10: Addition of an R-C snubber assembly installed in the primary metal-enclosed switchgear to attenuatevoltage transients. A single-phase resistor capacitor snubber shown at center and three of these assembliesmounted in the switchgear at right.

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THE NEXT GENERATION OF UNIT SUBSTATION DESIGN

The design team selected the new unit substation design based on leveraging power distributionequipment technologies to improve system safety and reliability. The selected design was applied to 11new unit substations installed at the plant site; two medium-voltage unit substations (10MVA and 5MVAwith a secondary voltage of 4160V) and nine low-voltage substations (all at 2000kVA with a secondaryvoltage of 480Y/277V. Both medium-voltage and low-voltage substations were installed with highresistance grounding systems, application described in [12] and [13], which eliminated the possibility of aphase to ground fault, further enhancing system safety and reliability. A typical low-voltage substationone-line diagram is shown in Fig. 11. In this application, the project team applied the smaller, low-costvacuum circuit breaker technology and also zone selective interlocking as described in Section IV above.From Fig. 11, note that the 15kV class vacuum breaker is connected to primary bus current sensors, anda separate overcurrent relay with current transformers mounted at the secondary bus is set-up to shunttrip the primary vacuum breaker in the event of a secondary bus fault. In this configuration, the multiplesettings group capability of the vacuum breaker integral trip unit was not used. Instead, the team electedto opt for a zone selective interlocking scheme, with control connections between the separateovercurrent relay and the secondary low-voltage power circuit breaker trip units. In this scheme, a busfault would result in the primary vacuum breaker tripping with no intentional short-time delay. The designteam made the choice to not take advantage of the faster clearing times available with the multiple settinggroup capability discussed previously, primarily because the company felt that revising their establishedsafety procedures for lockout/tagout could potentially cause confusion for plant operators. By definition,the multiple setting group approach required that the system studies be run in two different protection

Fig. 11: Greenfield site installed unit substation design. Metal enclosed primary switchgear; 15kV load-break switch overa fixed mounted vacuum circuit breaker. Integral breaker trip unit used for primary transformer protection, separateovercurrent relay mounted in the secondary switchgear with 86 lockout relay and shunt-trip used for secondary bus

protection. ZSI connection between secondary overcurrent relay and all 480V low-voltage power circuit breakers.

Substation One-LineAs-Installed Primary Protection

ZSI

ZSIZSIZSIZSI

50

51

50

51

50515051

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

(3) 200:1 CURRENT SENSORS

(3) 3200:5 CT

(3) 3200:5 CT

OC Relay

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

MVVCBL,S,I600AF200AT

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modes and required that operators would engage the instantaneous only mode during maintenance andalso remember to switch things back to the normal settings after maintenance was performed.

An alternate configuration that takes advantage of the multiple setting group capability is shown in Fig.12. In this case, secondary bus protection is supported by current sensors connected to the vacuumcircuit breaker integral trip unit, and primary protection is accomplished via a separate overcurrent relayconnected to primary current transformers. There is a slight advantage in applying this configuration asopposed to the selected configuration discussed above and shown in Fig. 12. Using the multiple settingsgroup capability in a maintenance mode improves the primary breaker clearing time from 5-7 cycles downto 3 cycles thus, reducing the downstream arc flash energy should a bus fault occur. The tradeoff hereis of course that maintenance and operations need to embrace this approach and be willing to adopt newlockout/tagout procedures to support this.

Results from this new approach were very significant. After the power systems design studies werecompleted and all settings were completed in the field, the facility was outfitted with arc flash and shockhazard labels. The studies confirmed that the entire electrical system, both low and medium-voltage,delivered arc flash hazards below 8 cal/cm2, or a Category 2 PPE requirement. This was very welcomenews to plant operations, since the facility PPE standards included company provided Category 2 PPE forall electrical maintenance personnel. So, no special PPE was necessary on the rare occasion that workbe required on energized equipment anywhere in the facility. The design team was very pleased withthese results.

Fig. 12: Alternate unit substation design. Metal enclosed primary switchgear; 15kV load-break switch over a fixedmounted vacuum circuit breaker. Integral breaker trip unit with multiple settings group maintenance feature used forsecondary bus protection, separate overcurrent relay mounted in the primary switchgear with 86 lockout relay andshunt-trip used for primary transformer protection. ZSI connection between integral overcurrent relay and all 480V low-voltage power circuit breakers.

Substation One-LineAlternate Primary Protection

ZSI

ZSIZSIZSIZSI

5051505150

515051

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

(3) 200:5 CT

(3) 3200:5 CT

(3) 3150:1 CURRENT SENSORS

OC Relay

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

LVPCBL,S,I800AF800AT

MVVCBL,S,I600AF3150AT

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CONCLUSIONS

As new challenges emerge in power distribution systems reliability and electrical workplace safety, it isthe responsibility of the systems designer to seek out new approaches and solutions that address them.Stepping back and looking at the big picture, the systems designer has an onerous responsibility inspecifying or selecting the best designs. Design decisions made today will impact cost, safety andserviceability of the installed systems for 40 or 50 years during the useful life for the owner. Studies haveshown that this cost is an order of magnitude of 7 to 10 times the installed cost of the power distributionequipment.

The work by the project design team in this effort is considered a significant step forward in innovation inunit substation design. In the current environment of emerging codes and standards such as NFPA70E,focused on improved electrical workplace safety, the obvious first choice for any power systems designeris to design the hazard out. Industry must continue to increase focus on Safety By Design as the mosteffective approach in minimizing electrical hazards while improving system reliability. Developments suchas those described in this paper are considered a driving force in establishing accomplishing thisobjective.

REFERENCES

[1] American National Standards Institute ANSI/IEEE Standard for Metal-Enclosed InterrupterSwitchgear, November 2001

[2] American National Standards Institute ANSI/IEEE Standard for Three Phase Power Transformers,March 2000 (?)

[3] Considerations in Application and Selection of Unit Substation Transformers, IEEE Transactions onIndustry Applications, Volume 38, May-June 2002, pgs 778-787.

[4] UL1558 Standard for Metal-Enclosed Low-Voltage Power Circuit Breaker Switchgear, February1999.

[5] National Fire Protection Agency NFPA70 National Electrical Code, 2008 Edition.[6] National Fire Protection Agency NFPA70E Standard for Electrical Safety in the Workplace, 2009

Edition[7] Standard 1584, IEEE Guide for Performing Arc-Flash Hazard Calculations. September 2002[8] Distribution Equipment Modernization to Reduce Arc Flash Hazards, Hopper, W.S, Etzel, B.L., IEEE

Transactions on Industry Applications, Volume 38, Volume 44, Issue 3, May-June 2008, pgs 940-948[9] 29CFR1919.301 to .399, OSHA Sub Part S, Electrical Installations, National Archives and Records Administration, Washington DC, 2007

[10] American National Standards Institute ANSI C37.20.3-2001, IEEE Standard for Metal-Enclosed LoadInterrupter Switchgear, November 2001.

[11] American National Standards Institute ANSI C37.20.2-1999, IEEE Standard for Metal-CladSwitchgear, October 1999.

[12] R. Beltz, I. Peacock, W. Vilcheck, Application Considerations For High Resistance GroundRetrofits, Conference Record, 2000 IEEE IAS PPIC, pgs X-XX.

[13] A.S. Locker, M.S. Scarborough, Advancements in Technology Create Safer & Smarter HRGSystems, Conference Record, 2008 IEEE IAS PPIC, Pgs X-XX