Electrical Engineering Workplace Safety

8/12/2019 Electrical Engineering Workplace Safety

1/14

November2010

Vol: 1

LEC

TRICA

LENG

INEER

CONSIDERATIONS

IN UNIT

SUBSTATIONDESIGN TO

OPTIMIZE

RELIABILITYAND ELECTRICAL

WORKPLACE

SAFETY

Abstract

i. introduction

ii. design considerations

iii. application wake-up calls

iv. a path forward via

product technology

V. The genesis of a new

substation design

vi. the greenfield site design

selection

vii. the next generation of unit

substation design

Viii. conclusion.

INDEX

LINKED


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page 2 Electrical Engineer - Vol 1: November 2010

Session 9 - Considerations in Unit Substation Design to Optimize Reliability & Electrical Workplace Safety

The paper was edited, design and publishedby Electrical Engineera division of ElectricalWorldmagazine which is published by Roger

Scott, 30/1 Waterside Crescent, Carramar,NSW 2163. If you have a paper you thinkshould be published contact Des Dugan.

([email protected]) Tel: 0418211 404. for consulation and costings.

The contents are subject to EW copyright

except where previous copyright takesprecident. Electrical World is Australian

National Library certifed. ISSN 1838-448X.

CONSIDERATIONS IN UNIT

SUBSTATION DESIGN TO

OPTIMIZE RELIABILITY ANDELECTRICAL WORKPLACE

SAFETYDavid B. Durocher

Senior Member IEEEIndustry Manager

Eaton Corporation

26850 SW Kinsman RoadWilsonville, OR 97070 [email protected]

(c) 2010 IEEE. Reprinted, with permission, from 2010 IEEE IAS Electrical Safety Workshop

ABSTRACT

Many legacy low and medium-voltage unit substations installed today are based upon older designsthat took advantage of reduced first cost "opportunities" allowed by existing installation codesand standards. Fast-forward to how these substation designs fair in safety and reliability today,

particularly in industrial process applications found in cement, pulp and paper, petroleum & chemical andothers, some of the exercised "opportunities" applied in the past begin to look more like liabilities thanassets.

Legacy engineering decisions once thought to be prudent take on new meanings today, particularlywhen these decisions are viewed through the lens of emerging new workplace safety standards. The criticalissue 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. Thedesign review took place in conjunction with construction of a Greenfield plant built in the spr ing of 2009in the USA.

This paper will review the design limitations of traditional unit substation configurations, offer anoverview of the alternatives considered by the Greenfield site project team, and discuss commercial,operational, technical and safety validation of the design that was ultimately selected and installed.

Index Terms - Process Industries, Power Distribution, Unit Substations, Safety by Design, ElectricalWorkplace Safety

I. INTRODUCTION

Low and medium voltage unit substations are applied universally across most every industry. At thetree-top level, unit substations are used simply to transform medium-voltage, typically 15 to 25kV, toa lower distribution voltage, typically 0.48 to 4.16kV, for application in supporting a host of various

motor and process equipment loads.Fig. 1shows a typical low-voltage unit substation.In this case, the primary assembly at the left is a medium-voltage fused load break switch. For this

example, we will assume the primary voltage is 13.8kV. For assemblies in North American industry, thisassembly is typically designed to 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 amedium-voltage current-limiting fuse, appropriately sized to protect the transformer.

The primary switchgear is close-coupled to a substation transformer, either dry-type or liquid filled.The substation transformer is designed to ANSI/IEEE Standard C.57.12 [2]with wall-mounted primary

and secondary bushings. There are many different substation transformer design alternatives to choose from,


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Electrical Engineer - Vol 1: November 2010 page 3


beyond the scope of this paper.Good information on the alternatives can be found in other technical papers, including [3]. In this case, the

transformer rating is shown at 2000kVA. With a secondary distr ibution voltage at 480Y/277 volts, the

low-voltage bushings are shown close-coupled to metal enclosed low-voltage switchgear.In Fig. 1 (above), the low-voltage switchgear consists of a 3200 ampere secondary main bus and secondary

metering, with no secondary main circuit breaker, connected to four 1200 ampere feeder circuit breakers.There are again variations on low-voltage switchgear designs. For process industry applications, mostfrequently these assemblies are manufactured to UL1558 Standard [4].

This unit substation assembly, installed indoor or outdoors, remains the stalwart of power distributionsystems of today. In some applications, the primary metal-enclosed switchgear and transformer may bemounted outdoors and a secondary air terminal chamber at the transformer will cable-feed to indoorlow-voltage switchgear.

Without a doubt, the integrated design shown here has been low cost and reliable performer and in thisconfiguration, continues to be applied in many industrial systems to this day.

II. 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 someinherent hidden flaws in the design. It is important to note that prevailing codes and standards regarding

installation 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]. Let's investigate two areas of thiscode that impact the design and installation of the unit substation presented here.

A. NEC Article 240.21(C)2 Overcurrent ProtectionArticle 240.21(C) of the NEC addresses required overcurrent protection, specifically related to transformer

secondary conductors. The article states that "a set of conductors feeding a single load ... shall be permitted tobe connected to a transformer secondary, without overcurrent protection of the secondary ...".

The article defines six conditions, specified in 240.21(C)(1) through 240.21(C)(6), under which secondaryovercurrent protection is not required. Sorting through the six options for our close-coupled unit substationexample, points us to the condition outlined in 240.21(C)(2) which most closely applies.

This condition gets fairly involved, with four different sub-conditions, all which must apply in order to satisfythe exception of no secondary protection. Relevant language in these sub-conditions includes:

240.21(C)(2): Transformer Secondary Conductors Not over 3m (10 ft) Long.(1) The ampacity of the secondary conductors is a). Not less than the combined calculated loads on the circuits supplied by the secondary conductors b). Not less than the rating of the device supplied by the secondary conductors or not less than the rating

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 totalconductor load and then specify a conductor size to support the calculated load. Referring back to the Fig. 1example above, note that the secondary conductor is specified at 3200A.

So, although the total connected rated load of the secondary feeder breakers is 4800A (four breakers rated

Fig. 1: Typical Unit Substation today: Primary metal enclosed load interrupter switchgear,fused load-break switch. Transformer close-coupled liquid filled or dry/cast resin. Secondaryswitchgear metal enclosed with low-voltage power circuit breakers, shown here with fourfeeders and no main breaker.

3200A

125E

13.8kV

480Y/277V

2000kVA

5.75%Z

1200A

1200A

1200A

1200A

Figure 1


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at 1200A each), the NEC allows the designer to assume a load diversity and size the secondary bus as somelower value. The second item (1) b. in essence states that the secondary conductor ampacity be either greaterthan the overcurrent device at which the conductors terminate (in this configuration, there is no such device)or greater than conductor or bus rating in the equipment where the conductors terminate.

From this language, it seems clear that secondary bus protection for the unit substation is not required.There is ongoing debate in some circles regarding the word "device" in this article, as some see the termdevice to mean something other then the switchgear. Interestingly, the NEC Code Making Panel supportingthis Article is reviewing this language and considering future revision to clarify the meaning. This aside, note

also that Article 240.21(C) includes a Fine Pr int Note stating "For overcurrent protection requirements fortransformers, see 450.3.

B. NEC Article 450.3 Equipment - TransformersArticle 450.3 of the NEC addresses secondary overcurrent protection of transformers. Note 2 for Table

450.3(A) states: "Where secondary overcurrent protection is required, the secondary overcurrent device shallbe permitted to consist of not more then six circuit breakers or six sets of fuses grouped in one location".Traditionally referred to as the "six disconnect" or "six handle" rule, this provision allows the user to foregosecondary overcurrent protection in a unit substation, provided there are no more than six feeder devices inthe assembly.

For the example shown in Fig. 1, this is clearly the case, so this assembly could be installed without concernthat the design would violate the applicable installation code.

III. 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 where arc-flash studies have been performed as outlined in NFPA-70E [6]using calculation methods in IEEE1584 [7]yielded some very revealing and disturbing results. Inthe event of a secondary bus fault, the NFPA-70E standard requires that the upstream overcurrent protectivedevice be used in determining the available arcing current.

In this case, the current-limiting fuse on the primary of the substation is the device used in the calculation.Specifically, Fig. 2 (below) shows calculations revealing arc flash energies at the secondary switchgear in excessof 700 calories/cm2. These levels are defined in IEEE1584 as UNAPPROACHABLE, where effectively noPersonal Protective Equipment (PPE) would be adequate in safeguarding personnel should a bus fault occurwhile persons were working on the energized substation.

In many existing facilities, unit substation feeder devices were used as a lockout/tagout point while

downstream equipment was being serviced or maintained.The elevated arc flash energies effectively made it unsafe to rack-out a secondary feeder breaker while thesecondary bus was energized. In process industry applications where electrical workplace safety is paramountand energized lockout/tagout is common, the "six feeders - no main" unit substation design was simply nolonger a practical option.

A number of vintage unit substations that employed the configuration shown in Fig. 2, have effectivelybeen upgraded to improve reliability and electrical safety. Although beyond the scope of this paper, one such

NFPA70E: Fault at 480V Switchgear Bus

31.8kA Symmetrical Fault current

1167 AF Boundary

702.4 cal/cm2 @ 18

UNAPPROACHABLE

NFPA70E-2009: Category 4 ishighest category @ 40 cal/cm2

3200A

125E

Bus Fault at 480V Switchgear

10kA Secondary Arcing Fault

At 13.8kV = 348A primary fault

125E fuse clearing time = 160 seconds

Arc Flash & PPE

2000kVA

5.75%Z

13.8kV

480Y/277V

1200A

1200A

1200A

1200A

= Fault Free Zone!

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

2.

Figure 2


5/14



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

of this 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 faultor an arcing fault, the secondary arc flash energy on the secondary bus of this unit substation design is

UNAPPROACHABLE.In addition, should a bus fault occur while this assembly was energized, the likely result beyond extremely

high arc flash energies would be extensive equipment damage caused by the heat energy developed beforethe primary fuse would clear. In a process industry environment, this translates to hours or perhaps days ofdowntime. In the end, the primary fuse in the 13.8kV fused load-break switch shown in Fig. 2, is intendedto protect the transformer, not the secondary bus. Adding a secondary main circuit breaker would resolve thisissue of protection in some applications.

This would in effect protect the secondary bus downstream of the main breaker. However, the bus fromthe transformer secondary terminals up to the main is still not adequately protected. This area of the bus issometimes referred to as the "fault free zone" as shown in Fig. 2. The author cannot explain the reason for thislabel, save perhaps that in this area, there is a strong desire that a fault will never occur!

In applications where the primary assembly and transformer are outdoors and cable connected tothe secondary switchgear, the secondary bus protection issue becomes more problematic. The secondary

conductors could be installed in accordance with the NEC if they were 10 feet or less, but still not beprotected from either short circuit or overload. Clearly, an opportunity existed for the project design team toconsider design alternatives that would offer better performance, both in reliability and workplace safety.

IV. A PATH FORWARD VIA PRODUCT TECHNOLOGY

Recognizing the limitations of the legacy unit substation design, the project team worked with thepower distr ibution equipment supplier to review alternative designs that might offer improvedperformance. Because of the extreme hazard and potential for extended outage time, the group

quickly dismissed the age-old approach of installing unit substations based on the "six feeders - no main"design. The strategy was 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 offeradvantages to this design approach. The group recognized that adding a secondary main device would addcost and was interested 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:

A. 15kV Vacuum Primary Circuit BreakerOne technology that appeared promising was in the area of medium-voltage vacuum circuit breakers. The

group 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 fused load-break switch. Although vacuum circuit breakers have traditionally involved higher space and cost than a fused

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 mechanism

Fig. 3: Newer design 15kV class vacuum circuit breakers are manufactured to the same standards asprevious versions, but are smaller, lighter, and have increased functionality. Shown above is acomparison of the newer design at left and traditional design at right. The new design shown includesan inte ral multifunction tri unit.

Figure 3


6/14



switch, some manufacturers had developed newer vacuum breakers that looked promising. Fig. 3(previouspage) shows and example of one such design available. In the North American markets, vacuum circuitbreakers are manufactured to ANSI Standard C37.06 [9]. Inspired in part by a trend toward global designstandards, traditional designs have given way to newer offerings that are smaller, lighter, and have improvedfunctionality. As is shown in Fig. 3 (previous page), although the newer design vacuum breakers are onlyavailable in limited ratings, most offer a smaller size with fewer parts.

Notably different from traditional vacuum circuit breakers, the new design includes an integral tr ip unitwith linear trip actuator. This actually offers improved performance with reduced clearing times, in part due

to the smaller sized component. Where traditional vacuum circuit breakers require 5 cycles total clear ingtime, the newer vacuum breaker can in some applications, clear a fault within 3 cycles. In unit substationapplications where higher ratings are not as important as in medium-voltage switchgear line-ups, the newerdesign breaker offers a viable alternative.

B. Zone Selective InterlockingZone selective interlocking for low and medium-voltage circuit breakers has been an available technology

for 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).

This figure shows the configuration of a typical low-voltage switchgear assembly in a low-voltagesubstation with a main power circuit breaker and three feeder circuit breakers. Zone selective interlockingis a functionality of the circuit breaker tripping system. In this example, all four breakers (the main and theefeeders) are connected together with a common zone control circuit.

The main and feeders are selectively coordinated so that the breaker nearest the fault clears first. A slightlylonger short time delay setting for the main breaker is used to assure the system is selectively coordinated.In the event of a downstream fault shown at (1) on Fig. 4, the feeder breaker nearest the fault would trip,

following the short-time delay setting of 0.2 seconds or 12.5 cycles on a 60 hertz system.If however a bus fault shown at (2) on Fig. 4 occurred, the main circuit breaker would be called upon to

clear the fault. Without zone selective interlocking, the breaker short-time delay trip setting of 0.5 seconds or30 cycles would dictate the clearing time. A zone selective interlocking (ZSI) control connection between allcircuit breakers adds intelligence to this system.

When a bus fault occurs, ZSI allows the main breaker to interrogate the feeder breakers in the zone todetermine if they "see" a fault as well. If all report back that there is now downstream fault, then the mainbreaker will trip with no intentional delay.

The ZSI feature is simple to enable and can offer significant advantages in reducing potential arcflash hazards 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/cm2 to 7.0 calories/cm2.

The NFPA70E defines the first condition above as UNAPPROACHABLE where no level of PPE wouldbe safe and the second where PPE rated at 8 calories/cm2 would offer adequate protection, a significantdifference.

C. Multiple Settings GroupsOne final technology applied in today's power distribution systems is a newer capability offering multiple

settings group capability for protective relays used with circuit breakers. Although this capability has been

SD=

0.5S

SD=0.2S

SD=0.2S

SD=0.2S

SD=0.2S

SD=0.2S

SD=0.2S

M1

F1 F2 F3

X(2) Bus Fault

X (1) Downstream Fault

ZSI

Control

wires

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, theZSI controls will trip the main breaker with no intentional delay.

Figure 4


7/14



a feature for several years on a few higher-end protective relays used in medium-voltage systems, severaltripping systems applied in integral trip units of low-voltage power circuit breakers now also include thisfeature. In a similar concept described above in ZSI applications, use of multiple settings groups for circuitbreaker tripping enables the tripping system to respond differently for different system conditions. Again,referring to Fig. 4, if a downstream fault condition existed, the feeder circuit breaker setting would dictatethat the 0.20 second short-time delay setting time out before the breaker trips.

The power systems engineer determines this setting to assure coordination with downstream overcurrentprotective devices and system loads so that the device nearest the fault tr ips first. In some cases for instance,

large downstream motors may have high inrush currents or long acceleration times that will affect theshort-time setting of the feeder breakers in the unit substation.

As discussed previously, adding an intentional delay to a breaker clearing time comes at the cost of higherincident energy and arc-flash hazards. When personnel are working in downstream equipment, such as alow-voltage motor control center, the opportunity for a dropped tool or accidental contact of a tool orprobe between an energized conductor and ground is increased. As this could lead to a higher incident ofshort circuits or arc-flash incidents, it is often prudent to reduce trip settings to enable the upstream circuitbreaker 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 used whilepersonnel are working in downstream equipment. Fig. 5 (below) illustrates application of the multiple settinggroup technology.

At the left of Fig. 5, the integral Long-time, Short-time, Instantaneous & Ground (LSIG) integral tr ip unit

mounted in the low-voltage power circuit breaker is equipped with an on-off switch that enables a second"group" of settings. In the normal mode, the power systems engineer settings are based on a selectivelycoordinated system, while in the maintenance mode, the LSIG settings are replaced with an instantaneousonly setting, effectively disabling the normal short-time settings.

The result is a faster clearing time of the circuit breaker should a downstream fault occur. At the rightof 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 on the far r ight shows the maintenance mode enabled, which effectively shifts theinstantaneous setting of the feeder breaker to the left. The result in this example is a reduction in arc-flashenergy from 11 calories/cm2to less than 4 calories/cm2. This demonstrates the advantage of the multiple

setting group feature.The maintenance (or instantaneous only) mode actually allows for faster clearing times than the normal

instantaneous settings, in part because the tr ipping system responds to peak currents as opposed to the

normal RMS or root mean squared currents. Since the tripping system is not burdened with the additionalRMS 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 3 cycles rather than the standard 5-cyle trip for thisclass of circuit breaker. Although clearing in an additional 2 cycles (32 milliseconds) seems insignificant,

Fig. 5: Newer designs of stand-alone and integral circuit breaker trip units include capabilities formultiple settings groups. Selectively coordinated settings can be overridden by an instantaneous onlysetting while downstream maintenance is being performed. At the center are the selectively coordinatedcurves. At the right, the feeder breaker instantaneous setting maintenance setting is shown shifted tothe left, enabling the breaker to clear the fault faster should a lower level arcing fault occur.

LSIG Trip Unit

AF Hazard < 4 cal/cm2AF Current = 5.6kAAF Current = 5.6kA

AF Hazard 11 cal/cm2

Figure 5


8/14



this actually can mean a difference in the reducing incident energy from 8 calories/cm2to 4 calories/cm2,a significant improvement. It is important to understand that the multiple settings group capability doesrepresent a trade-off on two different fronts.

First, depending on the instantaneous setting selected, selective coordination of the system may becompromised. In the Fig. 5example, note that the curve to the far left of the plot (brown in color) representsan across-the-line start of the largest motor fed by this substation feeder breaker. In the selectively coordinatedsetting, starting this motor would assure this motor could be started without a feeder breaker trip. However, inthe maintenance mode, note from the curve set at the right that the feeder breaker would indeed trip. Second,

application of multiple settings group functionality dictates that facility maintenance practices be revised andthen adhered to.

Maintenance persons will need to adopt a process where the maintenance mode could be safely engagedwhile downstream energized work is being performed, and also be assured that the protective settings werereturned to normal after maintenance is completed. It would be typical for the maintenance mode settings tobe enabled with a lockable switch and door-mounted light so this alternative maintenance setting could beincluded in the facility 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) [10]requires that live parts be deenergized before an employee works on or near them. Thereis simply no argument that turning the power off results in the safest working condition. However, in someprocess industry environments, deenergizing the power system is simply not practical and at times can resultin an even greater hazard.

V. THE GENESIS OF A NEW SUBSTATION DESIGN

Application of the various technologies discussed in the previous section came to fruition inupgrading several existing unit substations at an integrated pulp and paper mill in the WesternUnited States. Following a facility wide effort to update power systems studies to achieve

compliance with NFPA70E, the site engineer ing team discovered that most of the areas of very high orUNAPPROACHABLE incident energies as calculated by the system study were at the secondary bus oflow-voltage unit substations.

In fact, 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-voltage circuitbreaker was not practical. There simply was no room to add new assemblies. Fig. 6 (below) shows what wasultimately installed. The existing unit substation was upgraded by removing the medium-voltages fuses in the

existing fused load-break switch, and replacing them with a new fixed-mount vacuum circuit breaker.The new 15kV vacuum breaker with an integral overcurrent trip unit at the substation pr imary, connectedto secondary current sensors at the transformer secondary spade terminations, offered secondary busovercurrent protection. In addition to the integral trip unit, a second overcurrent protective relay along withprimary current transformers were added to protect the transformer, a necessary addition after the primary

15kV Vacuum Breaker

Before After

Arc Flash Study Results

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

AF Boundary 1167 18

Cal/cm2 702.4 1.4

NFPA70E HRC Unapproachable 1

Improved Unit Substation DesignLV Substation with Retrofit Vacuum Primary Breaker

86

ST

Integral

50/51 Relay

50/51

Relay

Fig. 6: Unit substation retrofit included a vacuum breaker installed at the primary. Both primary andsecondary overcurrent protection was installed, reducing incident energy at the secondary switchgearmain bus from 702.4 cal/cm

2to 1.4 cal/cm

2.

Figure 6


9/14



fuses were removed to make room for the vacuum breaker. In this application, the site engineering teamelected to add multiple settings group functionality to the vacuum breaker integral tr ip unit. This allowed foran additional maintenance setting that could be used when necessary. In this case, the maintenance setting wasused primar ily when the existing secondary draw-out power circuit breakers were being racked onto or off ofthe energized secondary bus.

The site routinely used the secondary feeder breakers as a convenient systems location to perform lockout/tagout of downstream loads. In a continuous process environment, it was not practical to deenergize the unit

substation to perform this work. Before the substation upgrade, the extremely high incident energies at thesecondary bus effectively prohibited removal of secondary feeder breakers.

Further details outlining this unique solution that improved both the safety and reliability of unitsubstations at this mill site are explained in the award winning paper referenced previously [8].

VI. THE GREENFIELD SITE DESIGN SELECTION

Drawing upon new technologies and unit substation retrofit experiences described previously, thedesign team for the Greenfield industrial plant drove toward the optimum design. The groupdetermined early-on that secondary bus protection, either via a secondary main circuit breaker, or

from a vacuum primary breaker with secondary current sensors was required. Past experience proved thatselection and application of a primary fuse to protect the transformer and expect this device would alsoadequately protect 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 pr imary as a standard platform for both

low and medium-voltage unit substations.A product was commercially available that was configured as shown in Fig. 7 (above). Note from thesection-view at the right that the incoming power enters at the top-rear of the assembly. The incoming cabletermination is designed to accommodate a typical drip loop and also has room so that medium-voltage cablescan be looped in and out of the assembly to feed an adjacent unit substation. Above the load-break switch is adistribution class lightning arrestor to protect the incoming of each substation.

Bus runbacks on the load-side of the switch include current transformers, connected at the vacuumbreakers to support primary overcurrent protection of the transformer. The vacuum breaker in the lowercompartment includes an integral trip unit.

Note also at the lower rear of the assembly is a snubber network, the purpose for which is described below.

A. Vacuum Interrupters and Voltage TransientsOne phenomenon which is not widely discussed or understood is the potential for voltage transients that

occur when the vacuum interrupter in a vacuum circuit breaker opens an inductive load. One of the physical

characteristics of all vacuum interrupters (VI) is a phenomenon called chop current.When the contacts of a VI open, current continues to flow through the arc drawn across the contacts

within the vacuum bottle. In an ac sine-wave, as the current approaches zero, the energy across the arc cannotbe sustained within the vacuum. When the arc energy reaches a low current level, the arc is immediatelyquenched and the current is driven to zero nearly instantaneously. The current value where the energy

Figure 7

Line

Load

Snubber

LA

Vac Bkr

LB

Switch

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.


10/14



collapses to zero for a VI is known as the chop current. All VI's have this chop current characteristic and thisvalue will typically be published by the VI manufacturer. Often on the order of 3 to 10 amperes, chop currentis a function of the VI design itself, including geometry, material composition, hardness of the contact surfaceand other physical characteristics.

Because energy cannot be created or destroyed instantaneously, driving current to zero with very high di/dt results in corresponding voltage transient, when switched into an inductive load (V = L * di/dt). AlthoughVIs are typically applied in medium-voltage switchgear and motor controllers where hundreds of feet of cableconnect the vacuum breaker element to the supported load, in this unit substation application the vacuum

circuit breaker is often within 10 feet of the transformer primary winding.Transient studies performed by the equipment manufacturer's power systems engineering group proved

that 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 pr imary 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 transient study with the VI opening as a chop current of 6 amperes as shown

at the left, resulted in a corresponding voltage transient as shown at the right. Note from Fig. 9 that thenegative peak voltage transient is nearly 150kV, exceeding the 95kV BIL rating of most 15kV class substationtransformers.

To curtail the severe voltage transients caused due to the VI in close proximity to the transformer inductiveload, 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 elements, was connected

on the load terminals of the vacuum breaker assembly. The snubber assembly was mounted as a component in

the substation primary medium-voltage load break switch and fixed vacuum breaker assembly.Fig. 10 shows a photo of one of the three-phase snubbers at the left and three single-phase assemblies at the

right. The waveform above shows the resulting impact from adding the R-C snubber as calculated from thetransient study. This shows that the peak voltage transients have been significantly reduced - in this example toa level below 30kV.

Transformer Failure On VI De-Energization

Flash/Burn Marks

Coil to Coil Failure

Fi . 8: Unit substation dr -t e transformer field failure likel caused b VI switchin transients.

-150kV!

Voltage Waveforms Without Snubbers

0

50

100

150

- 50

- 100

- 150

Current Waveforms Without Snubbers

Ichop

+6 amps0

20

40

60

- 20

- 40

- 60

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

Figure 8

Figure 9


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B. Putting it all TogetherSince the site would apply cast resin coil design transformers, the entire unit substation assembly was

designed 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 for

various alternatives was reviewed to assure the improved design alternatives were not adding significantly tothe cost.

Table I shows the first cost of several alternative designs considered. Note that the values shown areestimates, as the relative magnitude comparing one design versus another is the relevant issue. Because theeconomic modeling suggested that applying a pr imary load-break switch over a fixed mounted vacuumcircuit breaker with an integral tr ip unit was the best overall selection, the design team elected to establish thisapproach 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 unit substation, built to the ANSIStandard C37.20.3 [1]. As shown in Table I, a metal-clad assembly, built to the ANSI Standard C37.20.2[11]was also considered. This design included a draw-out vacuum breaker and no visible load-break switch.Ultimately, the metal-clad draw-out design was dismissed, as it proved more costly and lacked the visible bladeincoming disconnect device, which was considered an important functionality used as a part of the companylockout/tagout safety procedure.

TABLE I

SUBSTATION ALTERNATIVES PRIMARYS

SWGR

SUBSTATION

XFMR

SECONDARY

SWGR

TOTALS

2000kVA: 13.8kV TO 480Y/277V, 600A LB SW & FUSE, LIQ TRX,

3200A MCB, 4-800A FCB'S

$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 FCB'S

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

2000kVA: 13.8kV TO 480Y/277V, 600A LB SW & FUSE, CAST TRX,

3200A MCB, 4-800A FCB'S

$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 FCB'S

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

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

2000A MCB, 2-1200A FCB'S

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

5000kVA: 13.8kV TO 4160Y/2400V, 600A LB SW & VAC BKR, LIQ

TRX, 2000A BUS, 2-1200A FCB'S

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

VII. 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 to11 new unit substations installed at the plant site; two medium-voltage unit substations (10MVA and

5MVA with 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 high resistance grounding systems,application described in [12]and [13], which eliminated the possibility of a phase to ground fault, furtherenhancing system safety and reliability. A typical low-voltage substation one-line diagram is shown in Fig. 11.In this application, the project team applied the smaller, low-cost vacuum circuit breaker technology and also

zone selective interlocking as described in Section IV above.From Fig. 11, note that the 15kV class vacuum breaker integral overcurrent trip unit is connected to

primary bus current sensors, and a separate overcurrent relay with current transformers mounted at thesecondary bus is set-up to shunt trip the primary vacuum breaker in the event of a secondary bus fault. In thisconfiguration, the multiple settings group capability of the vacuum breaker integral tr ip unit was not used.

Voltage 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 assemblies

Figure 10


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Instead, the team elected to opt for a zone selective interlocking scheme, with control connections betweenthe separate overcurrent relay and the secondary low-voltage power circuit breaker tr ip units. In this scheme, abus fault would result in the pr imary vacuum breaker tripping with no intentional short-time delay.

The design team made the choice to not take advantage of the faster clearing times available with themultiple setting group capability discussed previously, primarily because the company felt that revising theirestablished safety 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 modes and required that operators would engage the instantaneous only mode during maintenanceand also 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 inFig. 12 (next page). In this case, secondary bus protection is supported by current sensors connected to thevacuum circuit breaker integral overcurrent trip unit, and primary protection is accomplished via a separateovercurrent relay connected to primary current transformers.

Using the vacuum circuit breaker integral trip unit to protect the substation secondary bus offers twoadvantages in system performance over the connection discussed in Fig. 12 (next page).

First, in clearing a fault, the inherent latency due to the 86 lockout relay and shunt trip are eliminated.Second, using the multiple settings group capability in a maintenance mode further improves the primarybreaker clearing time from 5-7 cycles down to 3 cycles. Both serve to reduce the downstream arc flash energyshould a bus fault occur. The tradeoff here is of course that maintenance and operations need to embrace thisapproach and be willing to adopt new lockout/tagout procedures to support this.

Results from this new design approach were impressive. After the power systems design studies werecompleted and all settings were made in the field, the facility was outfitted with arc flash and shock hazardlabels. The studies confirmed that the entire electrical system, both low and medium-voltage, delivered arcflash hazards below 8 cal/cm2.

This was very welcome news to plant operations, since the facility PPE standards included company

Figure 11

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


13/14



provided PPE rated at 8 cal/cm2for all electrical maintenance personnel.So, no special PPE was necessary on the rare occasion that work needed to be performed on energized

equipment anywhere in the facility.The design team was very pleased with these results.

VIII. CONCLUSIONAs new challenges emerge in power distribution systems reliability and electrical workplace safety, it is the

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 in

specifying or selecting the best designs.Design decisions made today will impact cost, safety and serviceability of the installed systems for 40 or 50

years during the useful life for the owner.Studies have shown that this cost is an order of magnitude of 7 to 10 times the installed cost of the power

distribution equipment.The work by the project design team in this effort is considered a significant step forward in innovation

in unit 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 designer is todesign the hazard out.

Industry must continue to increase focus on Safety By Design as the most effective approach in minimizingelectrical hazards while improving system reliability.Developments such as those described in this paper and efforts by a recently formed Working Group

within the IEEE [14]and discussed in [15]are considered driving forces in accomplishing this importantobjective.

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 480Vlow-voltage power circuit breakers.

Figure 12


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14 El i l E i V l 1 N b 2010


IX. ACKNOWLEDGEMENTSThe author wishes to thank Warren S. Hopper, Weyerhaeuser Company and David D. Shipp, Eaton

Corporation for their technical expertise and support in developing this paper. Without the help of theseindividuals, the concepts and applications outlined here would simply not have been possible.

REFERENCES[1] American National Standards Institute ANSI Standard C37.20.3-2001, IEEE Standard for Metal-

Enclosed Load Interrupter Switchgear, November 2001.[2] American National Standards Institute ANSI Standard C57.12 IEEE Standard for Three Phase Power

Transformers, 2005[3] Considerations in Application and Selection of Unit Substation Transformers, IEEE Transactions on

Industry Applications, Volume 38, May-June 2002, pgs 778-787.[4] Underwriters Laboratories UL1558 Standard for Metal-Enclosed Low-Voltage Power Circuit Breaker

Switchgear, February 1999.[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] W.S. Hopper, B.L. Etzel, "Distribution Equipment Modernization to Reduce Arc Flash Hazards", IEEE

Transactions on Industry Applications, Volume 38, Volume 44, Issue 3, May-June 2008, pgs 940-948[9] American National Standards Institute ANSI Standard C37.06, IEEE Standard for Medium Voltage

Circuit Breakers[10] Occupational Safety and Health Administration 29 CFR 1910.333, OSHA Sub Part S, Electrical

Installations, National Archives and Records Administration, Washington DC, 2007[11] American National Standards Institute ANSI C37.20.2-1999, IEEE Standard for Metal-Clad

Switchgear, October 1999.[12] R. Beltz, I. Peacock, W. Vilcheck, "Application Considerations For High Resistance Ground Retrofits",

Conference Record, 2000 IEEE IAS PPIC, pgs 33-40.[13] A.S. Locker, M.S. Scarborough, "Advancements in Technology Create Safer & Smarter HRG Systems",

Conference Record, 2009 IEEE IAS PPIC, Pgs 102-113.

[14] IEEE Working Group P1814 "Recommended Practice for Electr ical System Design Techniques toImprove Electrical Safety" Institute of Electrical and Electronics Engineers, IAS PCIC, 2009.

[15] L. Bruce McClung, Dennis J. Hill, "Electrical System Design Techniques to Improve Electrical Safety",Conference Record, 2010 IEEE IAS Electrical Safety Workshop, Pgs 147-152.

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