Short T.A. Electric Power Distribution Handbook

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Short-Circuit Protection 407

8.4 Lateral Tap Fusing and Fuse Coordination

Utilities use two main philosophies to apply tap fuses: fusing based on load

and standardized fusing schedules. With fusing based on load, we pick a

fuse based on some multiplier of peak load current. The fuse should not

operate for cold-load pickup or inrush to prevent nuisance operations. As

an example, one utility sizes fuses based on 1.5 times the current from the

phase with the highest connected kVA. With standardized fuse sizes, a typ-

ical strategy is to apply 100K links at all taps off of the mains (even if a tap

only has one 15-kVA transformer). If using second-level fusing, use 65K links

for these and 40K fuses for the third level. There is no clear winner; each

has advantages and disadvantages:

• Fusing based on load — This tends to fuse more tightly. High-imped-

ance faults are somewhat more likely to be detected. Nuisance fuse

operations are more likely, especially with utilities that tightly fuse

laterals. We are more likely to have load growth cause branch load-

ings to increase to the point of causing nuisance fuse operations.

Fusing based on load helps on circuits that have covered wire

because a smaller fuse helps protect against conductor burndown

(taps that are more heavily loaded usually have a larger wire, which

resists burndown).

• Standardized fuse sizes — It is simple: we spend less time coordinating

fuses, we do not constantly check loadings, and utilities have less

inventory. There is also less chance that the wrong fuse is installed

at a location. A disadvantage of this approach is that larger fuses

than needed are used at many locations, resulting in higher fault

damage at the arc location, longer voltage sags, and more stress on

in-line equipment.

Coordinating lateral tap fuses is generally straightforward. The fuse must

coordinate with the station recloser or circuit breaker relays. Station ground

relays are usually set to coordinate with the largest tap fuse. On the down-

stream side, a tap fuse should coordinate with the largest transformer fuse.

This usually is not a problem.

In addition to sizing a fuse to avoid nuisance operations and coordinating

with upstream and downstream protectors, we size fuses to ensure that the

fuses provide protection to the line section that they are protecting. The reach

of the fuse must exceed the length of the line section. Several methods are

used to quantify the reach of a fuse:

• Where the fuse will clear a bolted single line-to-ground fault in 3 sec

• Where the bolted single line-to-ground fault current is six times the

fuse rating

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408 Electric Power Distribution Handbook

• Where the fuse will clear a single line-to-ground fault with a 30 W

resistance in 5 sec

In most situations, typical fuse sizes provide sufﬁcient reach by any of

these methods. The ﬁrst two methods are the best; the 30 W resistance is

overly conservative and difﬁcult to apply.

Reliability needs dictate the number of fuses used. The most common

application for line fuses is at tap points. Occasionally, utilities fuse three-

phase mains, but a recloser is more commonly used for this purpose. In the

southwest U.S., in areas with few trees and little lightning, fuses may be

rarely used. This is the exception, not the rule. Most utilities fuse most taps

off the main line. Some go further and provide several levels of fusing,

especially utilities with heavy tree coverage. Returns diminish: too many

fuses leads to situations where fuses do not coordinate, and the extra fusing

does not increase reliability signiﬁcantly. Cutouts themselves contribute to

causing faults by providing an easy location where animals, trees, and light-

ning cause faults, especially if they are poorly installed.

8.5 Station Relay and Recloser Settings

The main feeder circuit breaker relays (or recloser) must be set so that the

circuit breaker coordinates with downstream devices, coordinates with

upstream devices, and does not have trips from inrush or cold-load pickup.

Station relays almost always use phase and ground time-overcurrent relays.

Table 8.9 shows typical settings used by several utilities. Many utilities try

to use standardized relay settings at all distribution stations. This has the

TABLE 8.9

Time-Overcurrent and Instantaneous Station Relay Pickup Settings in Amperes

on the Primary at Several Utilities

Utility

Phase Ground

NotesTOC Inst. TOC Inst.

A 720 4000 480 4000 Assumes peak

current = 400 A

B 720 1200 360 1200 Full load =

300 to 400 A

C 600 none 300 530

D 960 1300 480 600

E 800 none 340 none

F 960 2880 240 1920

G ≥2.25 ¥

current rating

same

as TOC

≥ 0.6 ¥

current rating

same

as TOC

600 600 160 160 Typical settings

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Short-Circuit Protection 409

advantage that relays are less likely to be set wrong, and there is less engi-

neering effort in a coordination study. Some other utilities set each relay

based on a coordination study.

Differences exist about the meaning of “peak load.” Some utilities base it

on the maximum design emergency load (which is typically something like

600 A). Others use the designed normal load (typically 400 A). Others may

base it on some percentage of the total connected distribution transformer kVA.

Instantaneous relay settings vary more than phase relay settings. Several

utilities also either disable or do not use an instantaneous relay setting. The

instantaneous relay pickup ranges from one to almost ten times the phase

relay pickup.

One reasonable set of base pickup settings is:

• Phase TOC (time-overcurrent) relay — Use two times the normal

designed peak load on the circuit.

• Ground TOC relay — Use 0.75 times the normal designed peak load

on the circuit.

• Instantaneous phase and ground relays — Use two times the TOC relay

pickups.

Settings any less than this are prone to false trips from cold-load pickup

and inrush.

In addition to avoiding nuisance trips, the relays (or recloser) must provide

protection to its line section (to the end of the line or to the next protective

device in series). Ensure that the relay has sufﬁcient reach at the minimum

operating current of the relay.

For a phase relay, sufﬁcient reach is achieved by ensuring that 75% of the

bolted line-to-line fault current at the end of the circuit is greater than the

relay’s pickup (its minimum operating current). So, if the line-to-line fault

current at the end of the circuit is 1000 A, the pickup of the relay should

be no more than 750 A. We use the line-to-line fault current because the

two types of faults not seen by the ground relay are the three phase and

the line to line. Of these, the line-to-line fault has the lower magnitude. The

75% factor provides a safety margin and allows some fault impedance.

Another approach is to ensure that the line-to-ground fault current at the

end of the circuit is less than the minimum operating current. The line-to-

ground fault current is less than the line-to-line fault current, which pro-

vides the safety margin.

For a ground relay, ensure that the relay pickup is less than 75% of the

line-to-ground fault current at the end of the line or to the next protective

device. The ground relay must also coordinate with the largest lateral fuse.

Feeders dedicated to supplying secondary networks, either grid or spot

networks, have similar settings as feeders supplying radial loads. Two main

differences are related to loading and the ground relay setting. The pickup

settings of station circuit breakers may have to account for higher peak loads.

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410 Electric Power Distribution Handbook

Some utilities have phase relay pickups that are similar to radial circuits,

from 600 to 800 A, but some have settings above 900 A with one utility

having a 1680-A setting (Smith, 1999). Also, if feeders are supplying only

network load, and all network transformers are connected delta – grounded

wye, the unbalanced current seen by the ground relay is small. Utilities can

set a low ground relay setting; some have settings ranging from 40 to 80 A

(Smith, 1999). The main limitation on lowering the setting further is that

during line-to-ground faults, the unfaulted circuits will backfeed the fault

through the zero-sequence capacitance of that circuit. Lower ground-relay

settings also help detect turn-to-turn or layer-to-layer faults within the pri-

mary windings of network transformers.

8.6 Coordinating Devices

Several details often arise when coordinating speciﬁc devices. Normally, we

want to ensure that the downstream device clears before the upstream device

operates over the range fault currents available at the downstream device.

Time-current characteristics of both device normally show us how well two

devices coordinate. Because of device differences, some combinations require

slightly different approaches. We discuss some of the common combinations

in the sections that follow.

8.6.1 Expulsion Fuse–Expulsion Fuse Coordination

When coordinating two fuses, the downstream fuse (referred to as the pro-

tecting fuse) should operate before the upstream fuse (the protected fuse). To

achieve this goal, ensure that the total clear time of the protecting fuse is

less than the damage time of the protected fuse. The damage time is 75% of

the minimum melt time. An example for coordinating a 100K link with a

65K link is shown in Figure 8.12. Above a certain current, the two fuses do

not coordinate; the protected fuse could suffer damage or melt before the

protecting fuse can clear. For high fault currents, coordination is impossible

because both fuses can open. The example shows that above 2310 A, the

total clear curve of the 65K is above the damage curve of the 100K link.

Utilities live with this common miscoordination. Table 8.10 lists the maxi-

mum coordination currents between K links. In cases where fuses do not

coordinate, why have the second fuse? The second fuse still has some value;

it adds another sectionalizing point (for a fuse in a cutout), and for a down-

stream fault, it identiﬁes the fault location to a smaller area. Also, the down-

stream fuse may operate without damaging the upstream fuse. The amount

of damage to the upstream fuse depends on the point of the waveform where

the fault occurs (the extra 1/2 + cycle waiting for a current zero causes the

extra heating to the protected fuse).

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Short-Circuit Protection 411

FIGURE 8.12

Example of fuse coordination between a 100-K (the protected fuse) and a 65-K link (the pro-

tecting link).

TABLE 8.10

Maximum Fault Currents for Coordination between the Given K Fuse Links

10K 12K 15K 20K 25K 30K 40K 50K 65K 80K 100K 140K 200K

6K 170 310 460 640 840 1060 1410 1800 2230 2930 3670 5890 9190

8K 20 230 410 610 810 1040 1400 1790 2230 2930 3670 5890 9190

10K 40 300 550 780 1000 1370 1770 2220 2930 3670 5890 9190

12K 80 420 690 950 1330 1730 2190 2910 3650 5880 9190

15K 90 530 840 1250 1670 2120 2870 3640 5870 9190

20K 100 610 1120 1570 2040 2800 3590 5870 9190

25K 120 840 1380 1920 2710 3510 5830 9150

30K 240 1090 1690 2570 3380 5740 9110

40K 300 1240 2260 3210 5630 9010

50K 240 1750 2800 5500 8910

65K 970 2310 5210 8740

80K 420 4460 8430

100K 3550 7950

140K 4210

1 2 3 4 5

65 K

100 K

Maximum

coordination

current

255

0.01

0.1

0.02

0.05

1: 65K minimum melt

2: 65K total clearing

3: 100K damage time

4: 100K minimum melt

5: 100K total clearing

Current, amps

Time, seconds

Fault

"Protected" Fuse "Protecting" Fuse

Source

100 K 65 K

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412 Electric Power Distribution Handbook

8.6.2 Current-Limiting Fuse Coordination

Coordinating two current-limiting fuses is similar to coordinating two expul-

sion links. Plot the time-current characteristics and ensure that the maximum

clearing time of the load-side fuse is less than 75% of the minimum-melting

time of the source-side fuse over the range of fault currents available at the

load-side fuse. The 75% factor accounts for damage to the source-side fuse.

Unlike expulsion links, current-limiting fuses can coordinate to very high

currents. For coordination at higher currents than are shown on published

time-current characteristics (operations faster than 0.01 sec), ensure that the

maximum clearing I

t of the load-side fuse is less than 75% of the minimum-

melt I

t of the source-side fuse. Manufacturers provide both of these I

t values

for current-limiting fuses.

Coordinating an expulsion link with a current-limiting fuse follows similar

principles. Because the melting and clearing characteristics of current-limit-

ing fuses are so much steeper than those of expulsion links, coordination is

sometimes difﬁcult; the operating characteristic curves are more likely to

cross over. A load-side current-limiting fuse coordinates over a wide range

of fault current. For a source-side current-limiting fuse, the clearing-time

limitations of expulsion links (to about 0.8 cycles) prevent coordination at

high currents. For currents above this value, either both will operate, or just

the current-limiting fuse will operate.

Backup current-limiting fuse coordination requires special attention. To

ensure that the CLF does not try to operate for currents below its minimum

interrupting rating, the intersection of the expulsion fuse’s total-clearing

curve and the backup fuse’s minimum-melting curve must be greater than

the maximum interrupting rating of the backup fuse. Normally, we select

backup current-limiting fuses for use with expulsion links based on matched-

melt coordination. Select a backup current-limiting fuse that has a maximum

melting I

t below the maximum clear I

t of the expulsion element. Also, check

the time-current curves of the devices. The expulsion link should always

clear for fault currents in the low-current operating region, especially below

the minimum interrupting current of the current-limiting fuse.

With matched-melt coordination, the expulsion fuse always operates,

including when the backup current-limiting fuse operates. In overhead

applications with an expulsion fuse in a cutout, the dropout of the expulsion

fuse provides a visible indication when the fuse(s) operate. Also, the backup

fuse is unlikely to have full voltage across it.

The maximum melting I

t of expulsion links is not provided from curves

or data. To estimate this, take the minimum melting I

t calculated from the

minimum-melt curve at 0.0125 sec, and multiply by 1.2 for tin links or 1.1

for silver links. The multiplier allows for conservatism in minimum-melt

curves and for manufacturing tolerances.

Somewhat less conservatively, experience has shown that fuses coordinate

well if the maximum melt I

t of the expulsion link does not exceed twice the

minimum melt I

t of the backup fuse (IEEE Std. C37.48-1997). We can tighten

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Short-Circuit Protection 413

up the backup fuse because, under most practical situations, the backup fuse

lets through signiﬁcantly more I

t than its minimum-melt value.

Manufacturers of backup current-limiting fuses normally provide coordi-

nation recommendations for their fuses, but review of the coordination

approach is sometimes appropriate. Backup fuses often use a “K” nomen-

clature signifying the K link that it coordinates with. For example, a “25 K”

backup link coordinates with a K link rated at 25 A or less. Figure 8.13 shows

the time-current curves of a 40K expulsion link and the curves of one man-

ufacturer’s 40K backup current-limiting fuse. This graph extends below the

normal cutoff time of 0.01 sec to show how the fuses coordinate at high

currents. This example shows that the backup fuse does not coordinate using

the strict matched-melt criteria (the maximum melting time of the expulsion

link is more than the minimum melting time of the backup fuse). The min-

imum-melt I

t of the backup fuse is 1.6 times the minimum melt I

t of the

backup fuse, so it meets the relaxed matched-melt criteria since this ratio is

less than two.

The time-current curve crossover coordination allows a smaller backup cur-

rent-limiting fuse. As before, the intersection of the expulsion fuse’s total-

clearing curve and the backup fuse’s minimum-melting curve must be

greater than the maximum interrupting rating of the backup fuse. We do not

try to ensure that the backup fuse always melts. We can use a smaller fuse,

which reduces the I

t let through and reduces energy to faults. The backup

CLF operates for a wider range of short-circuit currents. With a smaller fuse,

the backup fuse can operate before the expulsion link melts for high fault

currents. Utilities often use time-current curve crossover coordination for

under-oil backup current-limiting fuses. In addition to lowering energy to

faults, crossover coordination extends the range of current-limiting fuse

protection to larger transformers.

For transformer protection, overload and secondary faults are also consid-

erations for backup current-limiting fuses. Secondary faults at the terminals

of the transformer should not damage or melt the backup CLF. One way to

do this is to ensure that at the total clearing time of the expulsion link with

the bolted secondary fault, the backup fuse’s minimum melting current is

at least 125% of the secondary fault current (Hi-Tech Fuses, 2002). Also,

overload should not damage or melt the backup CLF.

8.6.3 Recloser–Expulsion Fuse Coordination

Normally, we want the recloser’s fast curve (A curve) to clear before down-

stream fuses operate. This saves the fuse for temporary faults (we discuss

fuse saving in more detail later in this chapter). Select the delayed curve (B,

C, … ) to be above the clearing time of downstream fuses. A permanent fault

downstream of a fuse should blow the fuse, not lockout the recloser.

To open the recloser before the fuse blows, Cooper (1990) recommends

adjusting the A curve by multiplying the time by a factor of 1.25 for one fast

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414 Electric Power Distribution Handbook

operation, a factor of 1.35 for two fast operations with a reclosing time greater

than or equal to 1 sec, and a factor of 1.8 for two fast operations with a

reclosing time from 25 to 30 cycles. For applications with two or more

delayed operations, the fast curve coordinates for fault currents up to the

point where the adjusted A curve crosses the expulsion fuse’s minimum-

melting curve.

FIGURE 8.13

Coordination between a 40-K expulsion link and a 40-K backup current-limiting fuse using the

relaxed matched-melt criteria.

1: Backup total clearing I

2: Expulsion minimum-melting time

3: Expulsion maximum-melting time

4: Backup minimum-melt I

40K expulsion link

40K backup

current-limiting fuse

0.001

0.01

0.1

1.0

10.0

Current, amps

Time, seconds

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Short-Circuit Protection 415

On hydraulically controlled reclosers, the trip-coil rating determines the

recloser’s “pickup.” Beyond that, hydraulically controlled reclosers have

limited curve selections and no adjustments. Figure 8.14 shows average

clearing curves for a single-phase Cooper 4E hydraulically controlled

recloser overlayed on top of two K fuse links. For this example, only a

limited range of fuses coordinate for low and high fault currents. Fuses

larger than a 65K have signiﬁcant overlap in the low-current area, leaving

more chance that the recloser could lock out for a fault on a lateral tap. The

slower delayed curves, such as the C curve shown, reduce the chance of

miscoordination for lower fault currents. For the fast-trip A curve, the 40K

link only coordinates with the fast curve for fault currents up to 360 A;

smaller links are worse. Since K links are signiﬁcantly steeper than these

recloser curves, we must expect limited coordination for certain combina-

tions. In this instance, T links coordinate over a wider current range because

their time-current characteristics match the slope of the recloser character-

istics more accurately. Miscoordination is more problematic in the low-

current region. If the recloser locks out for faults downstream of a fuse,

FIGURE 8.14

Example of coordination between K links and a Cooper 4E single-phase hydraulic recloser with

a 100-A trip coil (A, B, and C curves shown).

40K

65K

100.0 1000.

0.01

0.1

1.0

10.0

C curve

B curve

1.25xA curve

Current, amps

Time, seconds

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416 Electric Power Distribution Handbook

more customers are interrupted, and crews have a harder time ﬁnding the

fault (more area to patrol).

Reclosers with electronic controls and relayed circuit breakers offer more

ﬂexibility. We can tailor tripping characteristics to coordinate over a wider

range of currents. Three-phase reclosers have a ground-trip element that can

increase the sensitivity of the recloser and also coordinate better with down-

stream fuses.

8.6.4 Recloser–Recloser Coordination

For coordinating two reclosers, the curve separation we need depends on

the type of recloser. For hydraulically-controlled reclosers that are series

coil operated, both operate if there is less than a 2-cycle separation; both

may operate for a separation of 2 to 12 cycles, and both coordinate properly

if there are more than 12 cycles of separation. For hydraulically-controlled

reclosers that use high-voltage solenoid closing (larger reclosers), we need

8 cycles of separation for coordination (if it is less than 2 cycles, both

devices operate). This data is for Cooper reclosers (Cooper Power Sys-

tems, 1990).

8.6.5 Coordinating Instantaneous Elements

Coordinating instantaneous relay elements or recloser fast curves is difﬁcult.

By the nature of an instantaneous element, two in series will both operate

if the short-circuit current is above the pickup of both relays.

The most common way to coordinate two instantaneous elements is to

raise the pickup of the upstream element. Find a setting where the instan-

taneous relay will not operate for faults downstream of the second protective

device. The upstream relay cannot operate if its pickup is above the available

fault current at the location of the downstream element. For this strategy,

the instantaneous pickup on the element must be higher than its time-

overcurrent pickup. This rules out hydraulic reclosers, which have the same

pickup for the fast (A) curve and the delayed curves (B & C), but is not a

concern with electronic reclosers because they have the same ﬂexibility as

relayed circuit breakers.

Rather than using an instantaneous relay element, we can perform the

“fast trip” function with a time-overcurrent relay with a fast characteristic.

Now, we might be able to coordinate the fast curve of a line recloser with

the substation circuit breaker or recloser.

As another way to coordinate two instantaneous elements, use a time delay

on the upstream instantaneous element. Choose enough time delay, 6 to 10

cycles, to allow the downstream device to clear before the station device

operates.

Even with coordinated fast curves (either using a delay or using a fast

TOC curve), nuisance momentary interruptions occur for faults cleared by

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