Short T.A. Electric Power Distribution Handbook

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Short-Circuit Protection 437

as discussed in the next section). Single-phase protective devices do have

some drawbacks. The main concerns are

• Ferroresonance

• Single-phasing of motors

• Backfeeds

Ferroresonance usually occurs during manual switching of single-pole

switching devices (where the load is usually an unloaded transformer). It is

less common for ferroresonance to occur downstream of a single-phase pro-

tective device that is operating due to a fault. The reason for this is that if

there is a fault on the opened phase, the fault prevents an overvoltage on

the opened phase. Also, any load on the opened section helps prevent fer-

roresonant overvoltages. Because ferroresonance will be uncommon with

single-phase protective devices, it is usually not a major factor in protective

device selection. Still, caution is warranted on small three-phase transform-

ers that may be switched unloaded (especially at 24.94 or 34.5 kV).

With single-phase protective devices, backfeeds can create hazards. During

a line-to-ground fault where a single-phase device opens, backfeed through

a three-phase load can cause voltage on the load side of an opened protective

device. Backfeeds can happen with most types of three-phase distribution

transformer connections (even with a grounded-wye – grounded-wye con-

nection). The important points to note are that

• The backfeed voltage is enough to be a safety hazard to workers or

the public (for example in a wire down situation).

• The available backfeed is a stiff enough source to maintain an arc of

signiﬁcant length. The arc can continue causing damage at the fault

location during a backfeed condition. It may also be a low-level

sparking and sputtering fault.

Based on these points, single-phasing can cause problems from backfeed-

ing. Whether this constrains use of single-phase protective devices is debat-

able. Most utilities do use single-phase protective devices, usually with fuses,

on three-phase circuits.

Under single-phasing, motors can overheat and fail. Motors have relatively

low impedance to negative-sequence voltage; therefore, a small negative-

sequence component of the voltage produces a relatively large negative-

sequence current. Consequently the effect magniﬁes; a small negative-

sequence voltage appears as a signiﬁcantly larger percentage of unbalanced

current than the percentage of unbalanced voltage.

Loss of one or two phases is a large unbalance. For one phase open, the

phase-to-phase voltages become 0.57, 1.0, 0.57 for a wye – wye transformer

and 0.88, 0.88, 0.33 for a delta – wye transformer. In either case, the negative-

sequence voltage is 0.66 per unit. With such high unbalance, a motor over-

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438 Electric Power Distribution Handbook

heats quickly. The negative-sequence impedance of a motor is roughly 15%,

so for a 66% negative-sequence voltage, the motor draws a negative-

sequence current of 440%.

Most utility service agreements with customers state that it is the cus-

tomer’s responsibility to protect their equipment against single phasing. The

best way to protect motors is with a phase-loss relay. Nevertheless, some

utilities take measures to reduce the possibility of single-phasing customers’

motors, and one way to do that is to limit the use of single-phase protective

devices. Other utilities are more aggressive in their use of single-phase pro-

tective equipment and leave it up to customers to protect their equipment.

8.10.1 Single-Phase Reclosers with Three-Phase Lockout

Many single-phase reclosers and recloser controls come with a controller

option for a single-phase trip and three-phase lockout. Three-phase reclosers

that can operate each phase independently are also available. For single-

phase faults, only the faulted phase opens. For temporary faults, the recloser

successfully clears the fault and closes back in, so there will only be a

momentary interruption on the faulted phase. If the fault is still present after

the ﬁnal reclose attempt (a permanent fault), the recloser trips all three phases

and will not attempt additional reclosing operations.

Problems of single-phasing motors, backfeeds, and ferroresonance disap-

pear. Single-phasing motors and ferroresonance cause heating, and heating

usually takes many minutes for damage to occur. Short-duration single-

phasing occurring during a typical reclose cycle does not cause enough heat

to do damage. If the fault is permanent, all three phases trip and lock out,

so there is no long-term single phasing. A three-phase lockout also reduces

the chance of backfeed to a downed wire for a prolonged period.

Single-phase reclosers are available that have high enough continuous and

interrupting ratings that utilities can use them in almost all feeder applica-

tions and many substation applications.

Another consideration with single-phase reclosers vs. three-phase devices

is that a ground relay is often not available on single-phase reclosers. A

ground relay provides extra sensitivity for line-to-ground faults. Not having

the ground relay is a tradeoff to using single-phase devices. Even if a ground

relay is available on a unit with single-phase tripping, if the ground relay

operates, it trips all three phases (which defeats the purpose of single-phase

tripping).

References

Amundson, R. H., “High Voltage Fuse Protection Theory & Considerations,” IEEE

Tutorial Course on Application and Coordination of Reclosers, Sectionalizers,

and Fuses, 1980. Publication 80 EHO157–8-PWR.

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Short-Circuit Protection 439

ANSI C37.06-1997, AC High-Voltage Circuit Breakers Rated on a Symmetrical Current

Basis — Preferred Ratings and Related Required Capabilities.

ANSI C37.42-1989, American National Standard Speciﬁcations for Distribution Cutouts

and Fuse Links.

ANSI C57.12.20-1988, American National Standard Requirements for Overhead-Type Dis-

tribution Transformers, 500 kVA and Smaller: High-Voltage, 67 000 Volts and Below;

Low-Voltage, 15 000 Volts and Below, American National Standards Institute.

ANSI/IEEE C37.60-1981, IEEE Standard Requirements for Overhead, Pad Mounted, Dry

Vault, and Submersible Automatic Circuit Reclosers and Fault Interrupters for AC

Systems.

Benmouyal, G. and Zocholl, S. E., “Time-Current Coordination Concepts,” Western

Protective Relay Conference, 1994.

Bottrell, G. W., “Hazards and Beneﬁts of Utility Reclosing,” Proceedings, Power

Quality ’93, 1993.

Burke, J. J., “Philosophies of Distribution System Overcurrent Protection,” IEEE/PES

Transmission and Distribution Conference, 1996.

CEA 288 D 747, Application Guide for Distribution Fusing, Canadian Electrical Associ-

ation, 1998.

Cook, C. J. and Niemira, J. K., “Overcurrent Protection of Transformers—Traditional

and New Philosophies for Small and Large Transformers,” IEEE/PES Trans-

mission & Distribution Conference and Exposition, 1996. Presented at the train-

ing session on “Distribution Overcurrent Protection Philosophies.”

Cooper Power Systems, Electrical Distribution — System Protection, 3rd ed., 1990.

Cooper Power Systems, “Comparison of Recloser and Breaker Standards,” Reference

data R280-90-5, February 1994.

Drouet, M. G. and Nadeau, F., “Pressure Waves Due to Arcing Faults in a Substation,”

IEEE Transactions on Power Apparatus and Systems, vol. PAS-98, no. 5, pp. 1632–5,

1979.

Dugan, R. C., Ray, L. A., Sabin, D. D., Baker, G., Gilker, C., and Sundaram, A., “Impact

of Fast Tripping of Utility Breakers on Industrial Load Interruptions,” IEEE

Industry Applications Magazine, vol. 2, no. 3, pp. 55–64, May/June 1996.

Engelman, N. G., “Relaying Changes Improve Distribution Power Quality,” Trans-

mission and Distribution, pp. 72–6, May 1990.

EPRI 1001665, Power Quality Improvement Methodology for Wire Companies, Electric

Power Research Institute, Palo Alto, CA, 2003.

EPRI TR-106294-V2, An Assessment of Distribution System Power Quality: Volume 2:

Statistical Summary Report, Electric Power Research Institute, Palo Alto, CA, 1996.

Gabrois, G. L., Huber, W. J., and Stoelting, H. O., “Blowing of Distribution Trans-

former Fuses by Lightning,” in IEEE/PES Summer Meeting, Vancouver, Canada,

1973. Paper C73-421-5.

Hamel, A., Dastous, J. B., and Foata, M., “Estimating Overpressures in Pole-Type

Distribution Transformers Part I: Tank Withstand Evaluation,” IEEE Transac-

tions on Power Delivery, vol. 18, no. 1, pp. 113–9, 2003.

Hamel, A., St. Jean, G., and Paquette, M., “Nuisance Fuse Operation on MV Trans-

formers During Storms,” IEEE Transactions on Power Delivery, vol. 5, no. 4, pp.

1866–74, October 1990.

Hi-Tech Fuses, “Bulletin FS-10: Application of Trans-Guard EXT and OS Fuses,” Hi-

Tech Fuses, Hickory, NC, 2002.

IEEE Std. C37.04-1999, IEEE Standard Rating Structure for AC High-Voltage Circuit

Breakers.

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440 Electric Power Distribution Handbook

IEEE Std. C37.010-1999, IEEE Application Guide for AC High-Voltage Circuit Breakers

Rated on a Symmetrical Current Basis.

IEEE Std. C37.40-1993, IEEE Standard Service Conditions and Deﬁnitions for High-Voltage

Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches,

and Accessories.

IEEE Std. C37.48-1997, IEEE Guide for the Application, Operation, and Maintenance of

High-Voltage Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse Discon-

necting Switches, and Accessories.

IEEE Std. C37.112-1996, IEEE Standard Inverse-Time Characteristic Equations for Over-

current Relays.

IEEE Std. C62.22-1997, IEEE Guide for the Application of Metal-Oxide Surge Arresters for

Alternating-Current Systems.

IEEE Working Group on Distribution Protection, “Distribution Line Protection Prac-

tices — Industry Survey Results,” IEEE Transactions on Power Delivery, vol. 3,

no. 2, pp. 514–24, April 1988.

IEEE Working Group on Distribution Protection, “Distribution Line Protection Prac-

tices — Industry Survey Results,” IEEE Transactions on Power Delivery, vol. 10,

no. 1, pp. 176–86, January 1995.

Johnston, L., Tweed, N. B., Ward, D. J., and Burke, J. J., “An Analysis of Vepco’s 34.5

kV Distribution Feeder Faults as Related to Through Fault Failures of Substa-

tion Transformers,” IEEE Transactions on Power Apparatus and Systems, vol. PAS-

97, no. 5, pp. 1876–84, 1978.

Lunsford, J. M. and Tobin, T. J., “Detection of and Protection for Internal Low-Current

Winding Faults in Overhead Distribution Transformers,” IEEE Transactions on

Power Delivery, vol. 12, no. 3, pp. 1241–9, July 1997.

Plummer, C. W., Goedde, G. L., Pettit, E. L. J., Godbee, J. S., and Hennessey, M. G.,

“Reduction in Distribution Transformer Failure Rates and Nuisance Outages

Using Improved Lightning Protection Concepts,” IEEE Transactions on Power

Delivery, vol. 10, no. 2, pp. 768–77, April 1995.

Report to the IEEE working group on system performance, 2002.

Short, T. A., “Fuse Saving and Its Effect on Power Quality,” in EEI Distribution

Committee Meeting, 1999.

Short, T. A. and Ammon, R. A., “Instantaneous Trip Relay: Examining Its Role,”

Transmission and Distribution World, vol. 49, no. 2, February 1997.

Smith, D. R., “Network Primary Feeder Grounding and Protection,” in Draft 3 of

Chapter 10 of the IEEE Network Tutorial, 1999.

Smithley, R. S., “Normal Relay Settings Handle Cold Load,” Electrical World, pp. 52–4,

June 15, 1959.

Westinghouse Electric Corporation, Applied Protective Relaying, 1982.

I feel that there is not a single manager that respects the work of a lineman, until

they really need us. Hell ours could not even tell you what a shotgun stick is.

In response to: Do linemen feel they are respected by management and

coworkers for the jobs they are doing, do management and coworkers

understand what you do?

www.powerlineman.com

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Reliability

Power outages disrupt more businesses than any other factor (see Figure

9.1). I lose two hours of work on the computer; Jane Doe gets stuck in an

elevator; Intel loses a million dollars worth of computer chips; a reﬁnery

ﬂames out, stopping production and spewing pollution into the air. End

users expect good reliability, and expectations keep rising. Interruptions and

voltage sags cause most disruptions. In this chapter we study “sustained”

interruptions, long-duration interruptions generally deﬁned as lasting

longer than 1 to 5 min. We investigate momentary interruptions and voltage

sags in the next chapter. Reliability statistics, based on long-duration inter-

ruptions, are the primary benchmark used by utilities and regulators to

identify service quality. Faults on the distribution system cause most long-

duration interruptions; a fuse, breaker, recloser, or sectionalizer locks out the

faulted section.

Many utilities use reliability indices to track the performance of the utility

or a region or a circuit. Regulators require most investor-owned utilities to

report their reliability indices. The regulatory trend is moving to perfor-

mance-based rates where performance is penalized or rewarded based on

quantiﬁcation by reliability indices. Some utilities also pay bonuses to man-

agers or others based in part on indices. Some commercial and industrial

customers ask utilities for their reliability indices when locating a facility.

9.1 Reliability Indices

9.1.1 Customer-Based Indices

Utilities most commonly use two indices, SAIFI and SAIDI, to benchmark

reliability. These characterize the frequency and duration of interruptions

during the reporting period (usually years) (IEEE Std. 1366-2000).

SAIFI, System average interruption frequency index

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Typically, a utility’s customers average between one and two sustained

interruptions per year. SAIFI is also the average failure rate, which is often

labeled

. Another useful measure is the mean time between failure (MTBF),

which is the reciprocal of the failure rate: MTBF in years = 1/

SAIDI, System average interruption duration frequency index

SAIDI quantiﬁes the average total duration of interruptions. SAIDI is cited

in units of hours or minutes per year. Other common names for SAIDI are

CMI and CMO, standing for customer minutes of interruption or outage.

SAIFI and SAIDI are the most-used pair out of many reliability indices,

which look like a wash of acronyms — most importantly,

for duration and

for frequency. Another related index is CAIDI:

CAIDI, Customer average interruption duration frequency index

CAIDI is the “apparent” repair time (from the customers’ perspective). It

is generally much shorter than the actual repair time because utilities nor-

FIGURE 9.1

Percent of U.S. businesses disrupted by the given problem. (Data from [Rodentis, 1999].)

Violence/bombing/terrorism

Earthquakes

Hurricanes

Fires/explosions

Floods

Lightning storms

Telecommunications problems

Computer hardware problems

Power outages

0204060

Percent of businesses disrupted

0204060

SAIFI

Total number of customer interruptions

Total number of customers served

SAIDI

Sum of all customer interruption durations

Total number of customers served

CAIDI

SAIDI

SAIFI

Sum of all customer interruption durations

Total number of customer interruptions

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Reliability

443

mally sectionalize circuits to reenergize as many customers as possible before

crews ﬁx the actual damage.

Also used in many other industries, the availability is quantiﬁed as

ASAI, Average service availability index

We can ﬁnd ASIFI from SAIDI speciﬁed in hours as

(Use 8784 h/year for a leap year.)

Survey results for SAIFI and SAIDI are shown in Table 9.1. Figure 9.2

shows the distribution of utility indices from the CEA survey. Much of this

reliability index data is from Short (2002). Utility indices vary widely because

of many differing factors, mainly

•Weather

• Physical environment (mainly the amount of tree coverage)

• Load density

• Distribution voltage

• Age

• Percent underground

• Methods of recording interruptions

Within a utility, performance of circuits varies widely for many of the same

reasons causing the spread in utility indices: circuits have different lengths

TABLE 9.1

Reliability Indices Found by Industry Surveys

SAIFI, No. of

Interruptions/Year

SAIDI, h of

Interruption/Year

25% 50% 75% 25% 50% 75%

IEEE Std. 1366-2000 0.90 1.10 1.45 0.89 1.50 2.30

EEI (1999) [excludes storms] 0.92 1.32 1.71 1.16 1.74 2.23

EEI (1999) [with storms] 1.11 1.33 2.15 1.36 3.00 4.38

CEA (2001) [with storms] 1.03 1.95 3.16 0.73 2.26 3.28

PA Consulting (2001) [with storms] 1.55 3.05 8.35

IP&L Large City Comparison

(Indianapolis Power & Light, 2000)

0.72 0.95 1.15 1.02 1.64 2.41

Note:

25%, 50%, and 75% represent the lower quartile, the median, and the upper

quartile of utilities surveyed.

ASAI

SAIDI

SAIFI

Customer hours service availability

Customer hours service demanded

ASAI

8760 SAIDI

8760

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444

Electric Power Distribution Handbook

necessary to feed different areas of load density, some are older than others,

and some areas may have less tree coverage. Figure 9.3 shows the spread of

reliability on individual feeders at two utilities for two years worth of data.

Even though these two utilities are within the same state, SAIFI differs

dramatically.

Customer reliability is not normally distributed. A skewed distribution

such as the log-normal distribution is more appropriate and has been used

in several reliability applications (Brown and Burke, 2000; Christie, 2002). A

log-normal distribution is appropriate for data that is bounded on the lower

side by zero. The skewed distribution has several ramiﬁcations:

• The average is higher than the median. The median is a better

representation of the “typical” customer.

• Poor performing customers and circuits dominate the indices (which

are averages).

• Storms and other outliers easily skew the indices.

Realize that SAIFI and SAIDI are weighted performance indices. They

stress the performance of the worst-performing circuits and the performance

during storms. SAIFI and SAIDI are not necessarily good indicators of the

typical performance that customers have.

FIGURE 9.2

Distribution of utility indices in Canada (CEA survey, 36 utilities, two-year average). (Data from

[CEA, 2000].)

0 2 4 6 8

0 5 10 15

100

SAIFI, events/year

100

SAIDI, hours/year

Percent of utility indices

exceeding the x-axis value

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Reliability

445

9.1.2 Load-Based Indices

Residential customers dominate SAIFI and SAIDI since these indices treat

each customer the same. Even though residential customers make up 80%

of a typical utility’s customer count, they may only have 40% of the utility’s

load. To more fairly weight larger customers, load-based indices are available;

the equivalent of SAIFI and SAIDI, but scaled by load, are ASIFI and ASIDI:

ASIFI, Average system interruption frequency index

ASIDI, Average system interruption frequency index

FIGURE 9.3

Reliability indices by feeder for two utilities. Forced events only—major events, scheduled

events, and outside causes (substation or transmission) are excluded. The total SAIFI including

all events was 0.79 for Utility A and 3.4 for Utility B.

0 1 2 3 4

0 50 100 150

100

SAIFI, interruptions/year

Weighted percent of feeders

exceeding the x-axis value

100

CAIDI, minutes/interruption

Weighted percent of feeders

exceeding the x-axis value

ASIFI

Connected kVA interrupted

Total connected kVA served

Average number of interruptions= ()

ASIDI

Connected kVA interruption duration

Total connected kVA served

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Electric Power Distribution Handbook

Fewer than 8% of utilities track ASIFI and ASIDI, mainly since they are

hard to track (knowing load interrupted is more difﬁcult than knowing

number of customers interrupted). Utilities also feel that commercial and

industrial customers have enough clout that their problems are given due

attention.

9.2 Storms and Weather

Much of the reliability data reported to regulators excludes major storm or

major event interruptions. There are pros and cons to excluding storm inter-

ruptions. The argument for excluding storms is that storm interruptions

signiﬁcantly alter the duration indices to the extent that restoration perfor-

mance dominates the index. Further, a utility’s performance during storms

does not necessarily represent the true performance of the distribution sys-

tem. Including storms also adds considerable year-to-year variation in

results. On the other hand, from the customer point of view an interruption

is still an interruption. Also, the performance of a distribution system is

reﬂected in the storm performance; for example, if a utility does more tree

trimming and puts more circuits underground, their circuits will have fewer

interruptions when a storm hits.

If storms are not excluded, the numbers go up as shown in an EEI survey

in Figure 9.4. The interruption duration (CAIDI) and the average total inter-

ruption time (SAIDI) increase the most if storm data is included. Storms only

moderately impact SAIFI. During storms, crew resources are fully used.

Downed trees and wires plus trafﬁc makes even getting to faults difﬁcult.

Add difﬁcult working conditions, and it is easy to understand the great

increase in repair times.

During severe storms, foreign crews, crews from other service territories,

and general mayhem add large roadblocks preventing utilities from keeping

records needed for tracking indices. Expedience rules — should I get the

lights back on or do paperwork?

Utilities use various methods to classify storms. The two common catego-

ries are

•

Statistical method

— A common deﬁnition is 10% of customers

affected within an operating area.

•

Weather based deﬁnition

— Common deﬁnitions are “interruptions

caused by storms named by the national weather service” and “inter-

ruptions caused during storms that lead to a declaration of a state

of emergency.”

Some utilities exclude other interruptions including those scheduled or

those from other parts of the utility system (normally substation or trans-

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