Short T.A. Electric Power Distribution Handbook

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Short-Circuit Protection

377

• Fault resistance: Assume a maximum value of fault resistance when

calculating the current for a single line-to-ground fault. Common

values of fault resistance used are 1 to 2, 20, 30, and 40

. Rural

Electriﬁcation Administration (REA) standards use 40

Other options for determining the reach are

• Point based on a maximum operating time of a device: Deﬁne the

reach as the point giving the current necessary to operate a protective

device in a given time (with or without assuming any fault imped-

ance). Example: The REA has recommended taking the reach of a

fuse as the point where the fuse will just melt for a single line-to-

ground fault in 20 sec with a fault resistance of 30 or 40

• Point based on a multiplier of the device setting: Choose the point

where the fault current is some multiple of the device rating or

setting. Example: The reach of a fuse is the point where the bolted

fault current is six times the fuse rating.

None of these methods are exact. Some faults will always remain unde-

tectable (high-impedance faults). The trick is to try to clear all high-current

faults without being overly conservative.

Assuming a high value of fault resistance (20 to 40

) is overly conserva-

tive, so avoid it. For a 12.47-kV system (7.2 kV line to ground), the fault

current with a 40

fault impedance is less than 180 A (this ignores the

system impedance — additional system impedance reduces the calculated

current even more). Using typical relay/recloser setting philosophies, which

say that the rating of the recloser must be less than half of the minimum

fault current, a recloser must be less than 90 A, which effectively limits the

load current to an unreasonably low value. In many (even most, for some

utilities) situations this is unworkable. As discussed in Chapter 7, faults with

arc impedances greater than 2

are not common, so take the approach that

the minimum fault is close to the bolted fault current. On the other hand,

high-impedance faults (common during downed conductors) generally

draw less than 50 A and have impedances of over 100

. The 40

rule does

not guarantee that a protective device will clear high-impedance faults, and

in most cases would not improve high-impedance fault detection.

8.1.2 Inrush and Cold-Load Pickup

When an electrical distribution system energizes, components draw a high,

short-lived inrush; the largest component magnetizes the magnetic material

in distribution transformers (in most cases, it is more accurate to say

remag-

netizes

since the core is likely magnetized in a different polarity if the circuit

is energized following a short-duration interruption). The transformer inrush

characteristics important for protection are:

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• At a distribution transformer, inrush can reach peak magnitudes of

30 times the transformer’s full-load rating.

• Relative to the transformer rating, inrush has higher peak magni-

tudes for smaller transformers, but the time constant is longer for

larger transformers. Of course, on an absolute basis (amperes), a

larger transformer draws more inrush.

• Sometimes inrush occurs, and sometimes it does not, depending on

the point on the voltage waveform at which the reclosing occurs.

• System impedance limits the peak inrush.

The system impedance relative to the transformer size is an important

concept since it limits the peak inrush for larger transformers and larger

numbers of transformers. If one distribution transformer is energized by

itself, the transformer is small relative to the source impedance, so the peak

inrush maximizes. If a tap with several transformers is energized, the equiv-

alent connected transformer is larger relative to the system impedance, so

the peak inrush is lower (but the duration is extended). Several transformers

energizing at once pull the system voltage down. This reduction in voltage

causes less inrush current to be drawn from each transformer. For a whole

feeder, the equivalent transformer is even larger, so less inrush is observed.

Some guidelines for estimating inrush are:

•

One distribution transformer

— 30 times the crest of the full-load

current.

•

One lateral tap

— 12 times the crest of the full-load current of the

total connected kVA.

•

Feeder

— 5 times the connected kVA up to about half of the crest of

the system available fault current.

At the feeder level, inrush was only reported to cause tripping by 15% of

responders to an IEEE survey (IEEE Working Group on Distribution Protec-

tion, 1995). When a three-phase circuit is reclosed, the ground relay is most

likely to operate since the inrush seen by a ground relay can be as high as

the peak inrush on the phases (and it is usually set lower than the phase

settings). An instantaneous relay element is most sensitive to inrush, but the

instantaneous element is almost always disabled for the ﬁrst reclose attempt.

The ground instantaneous element could operate if a signiﬁcant single-phase

lateral is reconnected.

Transformers are not the only elements that draw inrush; others include

resistive lighting and heating elements and motors. Incandescent ﬁlaments

can draw eight times normal load current. The time constant for the incan-

descent ﬁlaments is usually very short; the inrush is usually ﬁnished after

a half cycle. Motor starting peak currents are on the order of six times the

motor rating. The duration is longer than transformer inrush with durations

typically from 3 to 10 sec.

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Cold-load pickup is the extra load following an extended interruption due

to loss of the normal diversity between customers. Following an interruption,

the water in water heaters cools down and refrigerators warm up. When the

power is restored, all appliances that need to catch up energize at once. In

cold weather, following an extended interruption, heaters all come on at

once (so it is especially bad with high concentrations of resistance heating).

In hot weather, houses warm up, so all air conditioners start following an

interruption.

Cold-load pickup can be over three times the load prior to the interruption.

As diversity is regained, the load slowly drops back to normal. This time

constant varies depending on the types of loads and the duration of the

interruption. Cold-load pickup is often divided into transformer inrush

which last a few cycles, motor starting and accelerating currents which last

a few seconds, and ﬁnally just the load due to loss of diversity which can

last many minutes. Figure 8.1 shows the middle-range time-frame with

motor starting and accelerating currents.

It is important to select relay settings and fuse sizes high enough to avoid

operations due to cold-load pickup. Even so, cold-load pickup problems are

hard to avoid in some situations. A survey of utilities reported 75% having

experienced cold-load pickup problems (IEEE Working Group on Distribu-

tion Protection, 1995). When a cold-load pickup problem occurs at the sub-

station level, the most common way to reconnect is to sectionalize and pick

the load up in smaller pieces. For this reason, cold-load pickup problems

are not widespread — after a long interruption, utilities usually sectionalize

anyway to get customers back on more quickly. Two other ways that are

sometimes used to energize a circuit are to raise relay settings or even to

block tripping (not recommended unless as a very last resort).

FIGURE 8.1

Ranges of cold-load pickup current from tests by six utilities. (Data from [Smithley, 1959].)

1: Upper limit of currents measured by six utilities

2: Lower limit of currents measured by six utilities

0 1 2 3 4 5

Time, seconds

Load in multiples of normal peak current

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In order to pick relays, recloser settings, and fuses, we often plot a cold-load

pickup curve on a time-current coordination graph along with the protection

equipment characteristics. Points can be taken from the curves in Figure 8.1.

It is also common to choose one or two points to represent cold-load pickup.

Three-hundred percent of full-load current at 5 sec is a common point.

Distribution protective devices tend to have steep time-overcurrent char-

acteristics, meaning that they operate much faster for higher currents. K-link

fuses and extremely-inverse relays are most commonly used, and these

happen to have the steepest characteristics. This is no coincidence; a distri-

bution protective device must operate fast for high currents (most faults)

and slow for lower currents. This characteristic gives a protective device a

better chance to ride through inrush and cold-load pickup.

8.2 Protection Equipment

8.2.1 Circuit Interrupters

All circuit interrupters — including circuit breakers, fuses, and reclosers —

operate on some basic principles. All devices interrupt fault current during

a zero-crossing. To do this, the interrupter creates an arc. In a fuse, an arc is

created when the fuse element melts, and in a circuit breaker or recloser, an

arc is created when the contacts mechanically separate. An arc conducts by

ionizing gasses, which leads to a relatively low-impedance path.

After the arc is created, the trick is to increase the dielectric strength across

the arc so that the arc clears at a current zero. Each half cycle, the ac current

momentarily stops as the current is reversing directions. During this period

when the current is reversing, the arc is not conducting and is starting to

de-ionize, and in a sense, the circuit is interrupted (at least temporarily). Just

after the arc is interrupted, the voltage across the now-interrupted arc path

builds up. This is the

recovery voltage

. If the dielectric strength builds up

faster than the recovery voltage, then the circuit stays interrupted. If the

recovery voltage builds up faster than the dielectric strength, the arc breaks

down again. Several methods used to increase the dielectric strength of the

arc are discussed in the following paragraphs. The general methods are:

•

Cooling the arc

— The ionization rate decreases with lower

temperature.

•

Pressurizing the arc

— Dielectric strength increases with pressure.

•

Stretching the arc

— The ionized-particle density is reduced by

stretching the arc stream.

•

Introducing fresh air

— Introducing de-ionized gas into the arc stream

helps the dielectric strength to recover.

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381

An air blast breaker blasts the arc stream into chutes that quickly lengthen

and cool the arc. Blowout coils can move the arc by magnetically inducing

motion. Compressed air blasts can blow the arc away from the contacts.

The arc in the interrupter has enough resistance to make it very hot. This

can wear contact terminals, which have to be replaced after a given number

of operations. If the interrupter fails to clear with the contacts open, the heat

from the arc builds high pressure that can breach the enclosure, possibly in

an explosive manner.

In an oil device, the heat of an arc decomposes the oil and creates gasses

that are then ionized. This process takes heat and energy out of the arc. To

enhance the chances of arc extinction in oil, fresh oil can be forced across

the path of the arc. Lengthening the arc also helps improve the dielectric

recovery. In an oil circuit breaker, the contact parting time is long enough

that there may be several restrikes before the dielectric strength builds up

enough to interrupt the circuit.

Vacuum devices work because the dielectric strength increases rapidly at

very low pressures (because there are very few gas molecules to ionize).

Normally, when approaching atmospheric pressures, the dielectric break-

down of air decreases as pressure decreases, but for very low pressures, the

dielectric breakdown goes back up. The pressure in vacuum bottles is 10

to 10

torr. A vacuum device only needs a very short separation distance

(about 8 to 10 mm for a 15-kV circuit breaker). Interruption is quick since

the mechanical travel time is small. The separating contacts draw an arc (it

still takes a current zero to clear). Sometimes, vacuum circuit breakers chop

the current, causing voltage spikes. The arc is a metal vapor consisting of

particles melted from each side. Contact erosion is low, so vacuum devices

are low maintenance and have a long life. Restrikes are uncommon.

is a gas that is a very good electrical insulator, so it has rapid dielectric

recovery. At atmospheric pressures, the dielectric strength is 2.5 times that

of air, and at higher pressures, the performance is even better. SF

is very

stable, does not react with other elements, and has good temperature char-

acteristics. One type of device blows compressed SF

across the arc stream

to increase the dielectric strength. Another type of SF

interrupter used in

circuit breakers and reclosers has an arc spinner which is a setup that uses

the magnetic ﬁeld from a coil to cause the arc to spin rapidly (bringing it in

contact with un-ionized gas). SF

can be used as the insulating medium as

well as the interrupting medium. SF

devices are low maintenance, have

short opening times, and most do not have restrikes.

Since interrupters work on the principle of the dielectric strength increas-

ing faster than the recovery voltage, the

X/R

ratio can make a signiﬁcant

difference in the clearing capability of a device. In an inductive circuit, the

recovery voltage rises very quickly since the system voltage is near its peak

when the current crosses through zero. Asymmetry increases the peak mag-

nitude of the fault current. For this reason, the capability of most interrupters

decreases with higher

X/R

ratios. Some interrupting equipment is rated

based on a symmetrical current basis while other equipment is based on

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asymmetrical current. Whether based on a symmetrical or asymmetrical

basis, the interrupter has asymmetric interrupting capability.

8.2.2 Circuit Breakers

Circuit breakers are often used in the substation on the bus and on each feeder.

Circuit breakers are available with very high interrupting and continuous

current ratings. The interrupting medium in circuit breakers can be any of

vacuum, oil, air, or SF

. Oil and vacuum breakers are most common on

distribution stations with newer units being mainly vacuum with some SF

Circuit breakers are tripped with external relays. The relays provide the

brains to control the opening of the circuit breaker, so the breaker coordinates

with other devices. The relays also perform reclosing functions.

Circuit breakers are historically rated as constant MVA devices. A sym-

metrical short-circuit rating is speciﬁed at the maximum rated voltage [for

more ratings information, see (ANSI C37.06-1997; IEEE Std. C37.04-1999;

IEEE Std. C37.010-1999)]. Below the maximum rated voltage (down to a

speciﬁed minimum value), the circuit breaker has more interrupting capa-

bility. The minimum value where the circuit breaker is a constant-MVA

device is speciﬁed by the constant

where

= Rated symmetrical rms short-circuit current operating at

= Maximum rms line-to-line rated voltage

= Operating voltage (also rms line-to-line)

=Voltage range factor = ratio of the maximum rated voltage to the

lower limit in which the circuit breaker is a constant MVA device.

Newer circuit breakers are rated as constant current devices (

= 1).

Consider a 15-kV class breaker application on a 12.47-kV system where

the maximum voltage will be assumed to be 13.1 kV (105%). For an ANSI-

rated 500-MVA class breaker with

15 kV,

= 1.3, and

18 kA, the

symmetrical interrupting capability would be 20.6 kA (15/13.1

18). Circuit

breakers are often referred to by their MVA class designation (1000-MVA

class for example). Typical circuit breaker ratings are shown in Table 8.1.

Circuit breakers must also be derated if the reclose cycle could cause more

than two operations and if the operations occur within less than 15 sec. The

percent reduction is given by

Symmetrical interrupting capability

for

◊<£

◊£

KI V

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383

(

– 2) +

(15 –

)/15 +

(15 –

)/15 + · · ·

where

= Total reduction factor, %

= Calculating factor, %

= Total number of openings

th time interval less than 15 sec

The interrupting rating is then

(

100

–D)I

. The permissible tripping delay

is also a standard. For the given delay period, the circuit breaker must

withstand

times the rated short-circuit current between closing and inter-

rupting. A typical delay is 2 sec.

Continuous current ratings are independent of interrupting ratings

(although higher continuous ratings usually go along with higher interrupt-

ing ratings). Standard continuous ratings include 600, 1200, 2000, and 3000

A (the 600 and 1200-A circuit breakers are most common for distribution

substations).

A circuit breaker also has a

momentary

close and latch

short-circuit rating

(also called the ﬁrst-cycle capability). During the ﬁrst cycle of fault current,

a circuit breaker must be able to withstand any current up to a multiple of

the short-circuit rating. The rms current should not exceed 1.6

and the

peak (crest) current should not exceed 2.7

The circuit breaker interrupting time is deﬁned as the interval between

energizing the trip circuit and the interruption of all phases. Most distri-

bution circuit breakers are ﬁve-cycle breakers. Older breakers interrupt in

eight cycles.

Distribution circuit breakers are three-phase devices. When the trip signal

is received, all three phases are tripped. All three will not clear simulta-

neously because the phase current zero crossings are separated. The degree

of separation between phases is usually one-half to one cycle.

TABLE 8.1

15-kV Class Circuit Breaker Short-Circuit Ratings

500

MVA

750

MVA

1000

MVA

Rated voltage, kV 15 15 15

K, voltage range factor 1.3 1.3 1.3

Short circuit at max voltage rating 18 28 37

Maximum symmetrical interrupting, kA 23 36 48

Close and latch rating

1.6 K

rated short-circuit current, kA (asym) 37 58 77

2.7 K

rated short-circuit current, kA (peak) 62 97 130

for kV

for kA

318

% I

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8.2.3 Circuit Breaker Relays

Several types of relays are used to control distribution circuit breakers.

Distribution circuits are almost always protected by overcurrent relays that

use inverse time overcurrent characteristics. An inverse time-current char-

acteristic means that the relay will operate faster with increased current.

The main types of relays are

•

Electromechanical relays

— The induction disk relay has long been the

main relay used for distribution overcurrent protection. The relay is

like an induction motor with contacts. Current through the CT leads

induces ﬂux in the relay magnetic circuit. These ﬂux linkages cause

the relay disk to turn. A larger current turns the disk faster. When

the disk travels a certain distance, the contacts on the disk meet

stationary contacts to complete the relay trip circuit. An instanta-

neous relay functionality can be provided: a plunger surrounded by

a coil or a disk cup design operates quickly if the current is above

the relay pickup. Most electromechanical relays are single phase.

•

Static relays

— Analog electronic circuitry (like op-amps) provide the

means to perform a time-current characteristic that approximates

that of the electromechanical relay.

•

Digital relays

— The most modern relay technology is fully digital

based on microprocessor components.

Electromechanical relays have reliably served their function and will con-

tinue to be used for many years. The main characteristics that should be

noted as it affects coordination are overtravel and reset time.

Overtravel

occurs because of the inertia in the disk. The disk will keep turning for a

short distance even after the short circuit is interrupted. A typical overtravel

of 0.1 sec is assumed when applying induction relays. An induction disk

cannot instantly turn back to the neutral position. This

reset time

should be

considered when applying reclosing sequences. It is not desirable to reclose

before the relay resets or

ratcheting

to a trip

can occur.

Digital relays are slowly replacing electromechanical relays. The main

advantages of digital relays are

•

More relay functions

— One relay performs the functions of several

electromechanical relays. One relay can provide both instantaneous

and time-overcurrent relay protection for three phases, plus the

ground, and perform reclosing functions. This can result in consid-

erable space and cost savings. Some backup is lost with this scheme

if a relay fails. One option to provide relay backup is to use two

digital relays, each with the same settings.

•

New protection schemes

— Advanced protection schemes are possible

that provide more sensitive protection and better coordination with

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385

other devices. Two good examples for distribution protection are

negative-sequence relaying and sequence coordination. Advanced

algorithms for high-impedance fault detection are also possible.

•

Other auxiliary functions

— Fault location algorithms, fault recording,

and power quality recording functions.

Digital relays have another advantage: internal diagnostics with ability to

self-test. With digital technology, the relay is less prone to drift over time

from mechanical movements or vibrations. Digital relays also avoid relay

overtravel and ratcheting that are constraints with electromechanical relays

(though some digital relays do reset like an electromagnetic relay).

Digital relays do have disadvantages. They are a relatively new technology.

Computer technology has a poor reputation as far as reliability. If digital

relays were as unreliable as a typical personal computer, we would have

many more interruptions and many ﬁres caused by uncleared faults. Given

that, most digital relays have proven to be reliable and are gaining more and

more acceptance by utilities.

Just as computer technology continues to advance rapidly, digital relays

are also advancing. While it is nice to have new features, technical evolution

can also mean that relay support becomes more difﬁcult. Each relay within

a certain family has to have its own supporting infrastructure for adjusting

the relay settings, uploading and downloading data, and testing the relay.

Each relay requires a certain amount of crew learning and training. As relays

evolve, it becomes more difﬁcult to maintain a variety of digital relays. The

physical form and connections of digital relays are not standardized. As a

contrast, electromechanical relays change very little and require a relatively

stable support infrastructure. Equipment standardization helps minimize the

support infrastructure required.

The time-current characteristics are based on the historically dominant

manufacturers of relays. Westinghouse relays have a CO family of relays,

and the General Electric relays are IAC (see Table 8.2). Most relays (digital

and electromechanical) follow the characteristics of the GE or Westinghouse

relays. For distribution overcurrent protection, the extremely inverse relays

are most often used (CO-11 or IAC-77).

The time-current curves for induction relays can be approximated by the

following equation (Benmouyal and Zocholl, 1994):

TABLE 8.2

Relay Designations

Westinghouse/ABB

Designation

General Electric

Designation

Moderately inverse CO-7

Inverse time CO-8 IAC-51

Very inverse CO-9 IAC-53

Extremely inverse CO-11 IAC-77

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where

= trip time, sec

= multiple of pickup current (

M >

= time dial setting

A, B, p

= curve shaping constants

With actual induction disk relays, the constants

and B change with the

time dial setting, but with digital relays, they stay constant.

Standardized characteristics of relays have been deﬁned by IEEE (IEEE

Std. C37.112-1996). This is an attempt to make relay characteristics consistent

(since the relay curve can be adjusted to almost anything in a digital relay).

The equations for the standardized inverse relay characteristics are shown

in Table 8.3. Figure 8.2 compares the shapes of these curves. The standard

allows relays to have tripping times within 15% of the curves. The standard

also speciﬁes the relay reset time for 0 < M < 1 as

where t

= reset time, sec for M = 0

8.2.4 Reclosers

A recloser is a specialty distribution protective device capable of interrupt-

ing fault current and automatically reclosing. The ofﬁcial deﬁnition of a

recloser is:

Automatic Circuit Recloser — A self-controlled device for automatically

interrupting and reclosing an alternating-current circuit, with a predeter-

mined sequence of opening and reclosing followed by resetting, hold closed,

or lockout.

TABLE 8.3

IEEE Standardized Relay Curve Equation Constants

ABp

Moderately inverse 0.0515 0.114 0.02

Very inverse 19.61 0.491 2.0

Extremely inverse 28.2 0.1217 2.0

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tTD

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