Analysis of Distribution System Reliability and Outage Rates

7/28/2019 Analysis of Distribution System Reliability and Outage Rates

1/6December 1987 q Supersedes 10/86

Analysis ofDistribution System Reliability and Outage Rates

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R280-90-7Reference Data

Reclosers

Table 1

Typical Utility Outage Rate Goals

RELIABILITY ANALYSISReference Data R280-90-7 provides information on methods tomeasure and improve distribution system reliability and outagerates. Standard indices are described that are used to measuredistribution system reliability and calculate improvements.Outage rates goals are discussed and examples of varioustypes of distribution systems are provided, showing logicalswitchgear applications that will reduce outage rates andimprove overall system operation.

Transient and permanent faults are defined and discussed.Transient fault protection schemes including reclosers and fusesfor sectionalizing feeder lines and taps are discussed. The differ-ence in fault protection philosophy for overhead versus under-ground systems is examined. Additional reliability improvementsare discussed that can be obtained through system automation

by remote identification of faulted sections, coupled with remoteswitching to isolate the fault and restore service to the rest of theline.

PERFORMANCE INDICESFor discussion of outage rates, performance indices arefrequenly used as described in the EPRI report EL-2081,Volume 2, Project 1356-1, pages 3-3 and 3-4. Use of thesestandard indices will permit meaningful comparison betweenutilities or between different divisions of a given utility, and per-haps most importantly; allow evaluation of system changes by adirect comparison of past and future performance of a feeder orsystem as changes are made. These standard indices aredefined as follows:

System Average Interruption FrequencyIndex (SAIFI)Defines the average number of times that a customers serviceis interrupted during a year. A customer interruption is definedas one interruption to one customer.

total number of customer interruptionsSAIFI =total number of customers served

System Average Interruption DurationIndex (SAIDI)Defines the average interruption duration per customer servedper year.

sum of customer interruption durationsSAIDI =total number of customers

Customer Average Interruption Frequency

Index (CAIFI)Defines the average number of interruptions per customer inter-rupted per year.

CAIFI = total number of customer interruptions totalnumber of customers affected

Customer Average Interruption DurationIndex (CAIDI)Defines the average interruption duration for those customersinterrupted during a year.

sum of customer interruption durationsCAIDI =total number of customer interruptions

Average Service Availability Index (ASAI)Defines the ratio of the total number of customer hours that service was available during year, to the total customer hoursdemanded. (customer hours demanded = 24 hours/day x 365days = 8760 hours)

ASAI = 8760 - SAIDI8760

For example, a SAIDI of 1.0 hours per year.

ASAI = 8760 - 1.0 = 99.989%8760

OUTAGE RATE GOALSFor the purposes of this discussion an outage is defined as anyloss of service for more than a normal reclosing interval. Manyutilities define an outage as loss of service for more than two

minutes.

Urban and Rural SystemsOutage rate goals will vary depending upon the nature of thedistribution system. Urban systems typically have less line exposure than rural systems. As a result, urban systems experiencefewer outages per year than rural systems.

Typical outage rate goals for urban and rural distribution systems are to limit outages to an average of 1.0 (urban) and 1.5(rural) outages per year (SAIFI). With each outage lasting anaverage duration of 1 hour (CAIDI), the average annual interruption is 1.0 hours for urban systems and 1.5 hours for rural distri-bution systems.

Many utilities have found that their service reliability deterio-rated significantly when they converted to a higher distributionvoltage (for example; 4kV to 13kV). The higher distribution volt

age allowed them to service longer feeder lengths and morecustomers with a given feeder. However, each outage thaoccurred affected more customers and the longer feedersrequired more patrol time to locate the fault.

To restore service reliability, the first step is to sectionalizeeach feeder into smaller sections, limiting the number of cus-tomers affected by a given outage and reducing the patrol timeneeded to locate and repair the fault. Operating experience of anumber of utilities that have adopted this sectionalizing practicehas suggested that an optimum feeder segment is 3 to 5 MVA.As the load of a line segment approaches 8 to 10 MVA, outagerates increase to unsatisfactory levels.

SystemIndex Type Operating Goal

SAIFI Urban 1.0 Outages Per YearSAIFI Rural 1.5 Outages Per YearCAIDI Rural/Urban 1.0 Hours Per OutageSAIDI Urban 1.0 Outage Hours Per YearSAIDI Rural 1.5 Outage Hours Per YearASAI Urban 99.989% Annual Service AvailabilityASAI Rural 99.983% Annual Service Availability


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Figure 1.

Reclosers and fuses provide protection against transientand permanent faults.

Figure 2.

Recloser/fuse link coordination.

When further relability improvement is desired, some utilitieshave utilized loop operation (figure 9) of adjacent feeders. Thisoperation not only sectionalizes the feeder into smaller seg-ments, it allows the utility to restore service to the customers atthe end of a feeder, minimizing any outage to the smallest pos-sible segment of the feeder. Two large eastern utilities that haveadopted this scheme have achieved the following service conti-nuity records:

Utility A0.715 outages per customer per year (SAIFI),1.056 hours peroutage (CAIDl ), resulting in 0.767 outage hours per customerper year (SAIDI).

Utility B0.475 outages per customer per year (SAIFI), 1.4 hours per out-age (CAIDI), resulting in 0.665 hours per outage per customerper year.

TYPES OF FAULTSTRANSIENT VS.PERMANENTMaximum service reliabiIity is achieved when the distributionsystem is designed and operated to minimize the effect of anyfault that may occur.

Two types of faults are encountered on an overhead distribu-tion system: transient and permanent. A transient fault is onewhose cause is transitory in nature. If the arc that results can becleared quickly, before it burns into a permanent fault, the causeof the fault is gone, no equipment damage has occurred, andthe circuit can be re-energized immediately, returning service tothe entire system. Since the open time between fault interrup-tion and re-energization is typically a few seconds in duration,this operation normally is not classified as an outage.

Examples of Transient Faults Include:Wind blowing two conductors together temporarily. A treebranch that falls across two conductors and then falls clear. Abird or small animal that briefly causes an arc from a live termi-nal to ground, and then falls clear.

On most distribution systems, the majority of faults (50 to90%) are transient in nature. With proper protection devices(fast tripping with fast reclosing), these faults can be clearedwithout a reportable outage.

Examples of Permanent FaultsA permanent fault is one in which permanent damage hasresulted from the cause of the fault. Examples would include abroken insulator, a broken conductor, an automobile knocking apole down, etc. With these permanent faults, the line must bede-energized, a line crew must be brought to the site andrepairs made. Outage times range from 30 minutes to manyhours and result in recorded outages.

For permanent faults, the extent of the outage can be mini-mized by limiting the size and length of the affected line. Theshorter line segment minimizes the number of customers affect-

ed and minimizes the time required to patrol the line and locatethe fault.

For faults on the main feeder line, a line sectionalizing device(recloser or sectionalizer) can be used to divide the feeder intosmaller line segments. All taps should have a protective device(fuses for small taps, a recloser or sectionalizer for larger taps)where they connect to the main feeder. Even on very small taps,a fuse should be used. The justification is that this type of tapfuse does not protect the tap, it protects the remainder of thedistribution feeder from a fault on the tap.

A combination of a recloser and fuses (shown in Figure 1) istypically used to provide protection against both transient andpermanent faults.

The fast trip curve of the recloser is used to clear all transientfaults on the main feeder and taps. For permanent faults on thetaps, the recloser time delay curve allows the tap fuse to clear,resulting in an outage on the tap only, as shown in Figure 2.

OUTAGE RATE REDUCTION METHODSThe following examples describe how outage rates can bereduced by various approaches to using main line sectionaliz-ing devices, recloser-fuse coordination and loop schemes.

ExampIe 1

Use of Main Line Sectionalizing Device

PROBLEMAll permanent faults on the main line result in an outage ofthe entire feeder.


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Figure 3.Calculating reliability.

Investigate outage rates for one fault at F1 and one fault at F2as shown in Figure 3.

Each outage = 1 hour in length (time required to locate faultand restore service).

Figure 4.

Substation breaker set on all delay operations to lockout.

With No Line Recloser:Fault at F1: 1000 customers x 1 hr. = 1000 cust. hrs.Fault at F2: 1000 customers x 1 hr. = 1000 cust. hrs.

Outage Total = 2000 cust. hrs.

OPTION TO IMPROVE SERVICE RELIABILITY1. Refer to Figure 3. Add a recloser at point A as a main line

sectionalizing device to reduce outage rates caused by faults

on the main feeder.With Recloser At A:

Fault at F1: 1000 customers x 1 hr. = 1000 cust. hrs.Fault at F2: 500 customers x 1 hr. = 500 cust. hrs.

Outage Total = 1500 cust. hrs.

Outage rate with line recloser equals 1500/2000 or 75% of ratewithout line recloser; or: 500/2000 = 25% reduction in outagerate.

NOTE: A sectionalizer can be substituted at point A to produce the

same 25% reduction in outage rate.

The actual reduction in outage rate will be greater than the25% calculated due to the shorter time required to patrol the lineand locate the fault (crew must patrol only 1/2 of total line for

fault at either F1 or F2).

Example 2Circuit Breaker In Substation WithoutInstantaneous Tripping

PROBLEMAll faults on taps result in an outage due to fuse operation andoutage rates can be high. Refer to Figure 4.

Figure 5.Substation breaker with typical relay settings.

OPTIONS TO IMPROVE SERVICE RELIABILITY1. Replace breaker with recloser.

a. Outage rate should decrease by a rate equal to the ratioof transient faults to permanent faults on the system.Therefore, if 70% of faults are initially transient by nature,outage rate will decreaseby 70%.

2. If committed to existing breaker protection adding a recloserin line will still provide a dramatic decrease in outage rate:a. 25% decrease due to line sectionalizing as described in

earlier systems.PLUS

b. Reduction in tap outages due to transient fault protectionprovided by recloser. 50% of taps x 70% transient faultrate = 35% reduction in outage rate.

c. Therefore, the total reduction in outage equals 25% +

35% = 60% reduction in outage rate.

Example 3Circuit Breaker In Substation With FastAnd Delayed Relay Settings

PROBLEMBreaker utilizing conventional relay settings of one INST tripfollowed by time delay trip operations, with the INST trip levelset typically at 2-1/2 times the basic phase and ground trip set-tings. Refer to Figure 5.

Phase trip = 800 amperes, INST at 2000 amperesGround trip = 300 amperes, INST at 750 amperes

The 750 ampere ground trip instantaneous setting generallywill not provide reach for faults distant from the substation;thus all transient faults occurring at these locations and allfaults below 750 ampere magnitude on any tap, will result in anoutage.

OPTIONS TO IMPROVE SERVICE RELIABILITY1. Replace breaker with recloser with conventional recloser

sequence providing fast tripping at basic trip levels select-ed. With electronic control, the fast TCC can be selectedwith adequate time delay near minimum trip to prevent anynuisance trips. Sequence coordination feature can be usedfor even better coordination if any down line reclosers areused.

The reduction in outage rate is dependent on the parame-ters of the circuithow many faults below 750 amperes (asan example) are experienced. For a moderateIy long feederwith lengthy taps, a 50% reduction in the outage rate may bereasonable.

2. Even without breaker changeout, adding a recloser in line willstill provide dramatic improvement. The 25% reduction in out-age rate is due to a line recloser, plus the reduction in out-ages on the taps due to the increased reach of the recloser.

Example 4Feeder Protected By Recloser

OPTION TO IMPROVE RELIABILITY1. Refer to Figure 6. Add a recloser in the line. This will provide

the 25% reduction in the outage rate as described earlier,plus some added improvement due to the added reach (orsensitivity) afforded by the more sensitive trip settings of theline recloser.

R280-90-7


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UNDERGROUND DlSTRIBUTlONFor an underground distribution feeder or system, comparison toan overhead distribution system for purpose of operating reliabil-ity presents some differences. An underground feeder has notransient faults, fewer outages and outages of longer duration.

Since an underground system has no transient faults, theregenerally is no need for fast tripping or reclosing operations.Typically, protection at the substation consists of a single time

delay trip operation and lock open.An underground system will have fewer faults than an over-head system, since there is no exposure to wind, trees, ice,sleet, etc., and limited exposure to wildlife, lightning surges, etc.

When a fault does occur, the outage duration can be quitelong. The time to patrol the line and locate the fault can be quitelengthy, equipment or cable repair can also require considerablymore time than equivalent overhead equipment repair. Eventhough the number of outages on an underground feeder maybe limited, the long outage times required for fault location andrepair can result in unacceptable outage ratio. Addition of a mid-point fault sensing and interrupting device can be used toreduce the number of customers affected and reduce the timerequired for fault location.

SYSTEM AUTOMATIONAfter protective devices are properly applied on a distributionsystem, the next higher level of system reliability can beachieved by automating the entire system for remote identifica-tion of faulted sections and rapid isolation of these sections bymeans of remote switching operations.

Remote identification of the faulted section eliminates the timerequired for line patrol. The remote switching function allows thefaulted line to be isolated, and service restored to all other linesections (assuming availability of an alternate feed to the remotesections) in less than 2 minutes. Thus, the outage is limited toonly the faulted portion of the line.

Figure 11 illustrates a distribution system using both remotelyoperated switches and line reclosers that can also be operatedremotely.

For this automated operation, switches have been developedthat have a stored energy operator (allows remote switchingwithout power at the switch location) and fault indicators to pro-vide remote indication of fault location. Use of switches allowsmore sectionalizing points on the feeder without adding anysteps of coordination. Reclosers are used to provide immediatelocal fault clearing capabilities that are independent of the com-munication system or remote computer control.

SUMMARYIncreased usage of electricity has led to the need to increasedistribution system voltages. Utilization of these higher distribu-tion voltages has resulted in decreased system reliability andhigher customer outage rates. Efficient application of recloserscan provide dramatic improvements in distribution system relia-bility.

Using reclosers to provide transient fault protection on theentire distribution system can improve outage rates by 50-90%.Reclosers or sectionalizers used as main line sectionalizingdevices can improve outage rates an additional 25%.

Even greater service continuity can be achieved by usingnearby feeders as backup supplies. By using reclosers or sec-tionalizers as normally open feeder ties with local supervisorycontrols, outage rates can be improved by an additional 50%over unsectionalized systems.

Additional improvements in distribution system reliability canbe obtained through the application of supervisory control ordistribution automation.

Figure 11.

Automated distribution system.

R280-90-7


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Analysis of Distribution System Reliability and Outage Rates