protection settings

8/3/2019 Protection Settings

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ELEC 4302/7311

POWER SYSTEM PROTECTION:PROTECTION SETTINGS

Dr. Ramesh Bansal

School of Information Technology and ElectricalEngineering, Axon Bldg, 47/212

The University of Queensland, St Lucia, 4072Australia

[email protected]: +61 (07)33653394

Fax: +61 (07) 336 54999

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mailto:[email protected]:[email protected]


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Contents

Introduction

Functions of Equipment Protection

Functions of Protective Relays

Required Information for Protective Setting Protection Settings Process

Functional Elements of Protective Relays

Operating Characteristics of Protective Relays

Overcurrent and Directional Protection Elements Distance Protection Function

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PROTECTION SETTINGS:INTRODUCTION

A power system is composed of a number ofsections (equipment) such as generator,transformer, bus bar and transmission line.

These sections are protected by protective

relaying systems comprising of instrumenttransformers (ITs), protective relays, circuitbreakers (CBs) and communication equipment.

In case of a fault occurring on a section, itsassociated protective relays should detect thefault and issue trip signals to open theirassociated CBs to isolate the faulted sectionfrom the rest of the power system, in order toavoid further damage to the power system. 3


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Below Fig. 1 is an typical example of power system sections with their

protection systems. Where:G1 is a generator. T1 is a transformer. B1,...,B5 are bus bars. L45 is

a transmission line (TL).RG is a generator protective relay. RT is a transformer protective

relay. RB is a bus protective relay. RL-4,...,RL-9 are TL protective

relays. C1,..., C9 are CBs.

Protection Settings: Introduction

Fig. 1 Protection of power system sections


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PROTECTION SETTINGS:INTRODUCTION

Maximum fault clearance times are usuallyspecified by the regulating bodies and networkservice providers.

The clearing times are given for local and remote

CBs and depend on the voltage level and aredetermined primarily to meet stabilityrequirements and minimize plant damage.

The maximum clearance times of the backupprotection are also specified.

e.g. the clearing times for faults on the linesspecified by one network service provider inAustralia are presented in Table I (next slide).

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TABLE I: FAULT CLEARANCE TIMES

Voltagelevel [kV]

CB operate correctly[ms]

CB fail [ms]

Local Remote Local Remote

500 80 100 175 175330 100 120 250 250

275 100 120 250 250

220 120 140 430 430

132 120 160 430 430110 120 160 430 430

66 120 160 430 430

33 1160 - 1500 -6


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FUNCTIONS OF PROTECTIVE RELAYS

The protection functions are considered adequatewhen the protection relays perform correctly in termsof:

Dependability:The probability of not having a failure

to operate under given conditions for a given timeinterval.

Security: The probability ofnot having an unwantedoperation under given conditions for a given time

interval.

Speed of Operation: The clearance of faults in theshortest time is a fundamental requirement(transmission system), but this must be seen in

conjunction with the associated cost implications and

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Selectivity (Discrimination):The ability to detect a fault within a specified zone of anetwork and to trip the appropriate CB(s) to clear thisfault with a minimum disturbance to the rest of thatnetwork.

Single failure criterion:

A protection design criterion whereby a protectionsystem must not fail to operate even after one

component fails to operate.With respect to the protection relay, the single failurecriterion caters primarily for a failed or defective relay,and not a failure to operate as a result of aperformance deficiency inherent within the design of

the relay.

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The setting of protection relays is not a definitescience.

Depending on local conditions and requirements,setting of each protective function has to beoptimized to achieve the best balance betweenreliability, security and speed of operation.

Protection settings should therefore becalculated by protection engineers with vast

experience in protective relaying, power systemoperation and performance and quality of supply.

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REQUIRED INFORMATION FOR PROTECTIVESETTING

Line Parameters:

For a new line: final total line length as well as thelengths, conductor sizes and tower types of eachsection where different tower types or conductors have

been used.This information is used to calculate the parameters

(positive and zero sequence resistance, reactance andsusceptance) for each section.

Maximum load current or apparent power (MVA)corresponding to the emergency line which can beobtained from the table of standard conductor rating(available in each utility).

The number of conductors in a bundle has to be taken

into consideration.

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REQUIRED INFORMATION FORPROTECTIVE SETTING

Transformer Parameters:The manufacturer's positive and zero sequence

impedance test values have to be obtained.

The transformer nameplate normally provides the

manufacturer's positive sequence impedancevalues only.

Terminal Equipment Rating:The rating of terminal equipment (CB, CT, line

trap, links) of the circuit may limit its transfercapability therefore the rating of each device hasto be known.

Data can be obtained from the single linediagrams. 12


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Fault StudiesResults of fault studies must be provided.

The developed settings should be checked onfuture cases modelled with the system changes

that will take place in the future (e.g. within 5years).

Use a maximum fault current case.

CT & VT Ratios:

Obtain the CT ratios as indicated on theprotection diagrams.

For existing circuits, it is possible to verify theratios indicated on the diagrams by measuringthe load currents on site and comparing with a

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Checking For CT Saturation: Protection systems are adversely affected by CT

saturation. It is the responsibility of protection engineersto establish for which forms of protection and under whatconditions the CT should not saturate.

CTs for Transformer Differential Protection: MV, HV and LV CTs must be matched as far as possible

taking into consideration the transformer vector group,tap changer influence and the connection of CTs.

CTs for Transformer Restricted Earth Fault(REF) Protection:

All CT ratios must be the same (as with the buszone protection), except if the relay caninternally correct unmatched ratios.

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PROTECTION SETTINGS PROCESS

The Protection Settings team obtains all theinformation necessary for correct setting calculations.

The settings are then calculated according to thelatest philosophy, using sound engineering principles.Pre-written programs may be used as a guide.

After calculation of the settings, it is important thatanother competent person checks them.

The persons who calculate and who check the settingsboth sign the formal settings document.

The flowchart in Fig. 2 indicates information flow

during protection setting preparation forcommissioning of new Transmission plant.

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Project leader of the Protection

Settings team determines scope

of work and target dates

Summary and comparison of inputs

IED manufacturers provide bayspecific IED details

Engineering team provides bay

specific proformas and drawings

Corrective actions and re-issue of

drawings

Study new protection and create

necessary setting templates in

liaison with engineering team andIED manufactureres

OKNot OK

Calculation and verification of settings

Settings stored in central databaseand formal document issued

Implementation date and responsible

field person stored in the central

database -> implementation actionImplementation sheet completed

by field staff and returned to

Protection Settings team

Interface with the Expansion Planingteam and IED manufacturers to obtain

relevant equipment parameters for

correct system modelling

Centralised Settings ManagementSystem sends the action documents

to the field staff

Corrective actions required to

ensure implementation

Fig. 2 Information flow during

protection settings preparation


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FUNCTIONAL ELEMENTS OFPROTECTIVE RELAYS

To achieve maximum flexibility, relays is designed using theconcept of functional elements which include protectionelements, control elements, input and output contacts etc.

The protection elements are arranged to detect the systemcondition, make a decision if the observed variables are

over/under the acceptable limit, and take proper action ifacceptable limits are crossed.

Protection element measures system quantities such asvoltages and currents, and compares these quantities ortheir combination against a threshold setting (pickup

values). If this comparison indicates that the thresholds are crossed,

a decision element is triggered.

This may involve a timing element, to determine if thecondition is permanent or temporary. If all checks are

satisfied, the relay (action element) operates.

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FaultPickup of

protection element

Operation of

protection element

Assertion of relay

trip logic signal

Action of relay

trip contact

Circuit breaker

openingFault cleared

Fig. 3 Sequence of operation.

Sequence of protection operation initiated by a fault is

shown in Fig. 3.


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OPERATING CHARACTERISTICS OFPROTECTIVE RELAYS

Protective relays respond and operate according todefined operating characteristic and applied settings.

Each type of protective relay has distinctive operatingcharacteristic to achieve implementation objective:

sensitivity, selectivity, reliability and adequate speed ofoperation.

Basic operating characteristics of protective elements isas follows:

Overcurrent protection function: the overcurrent

element operates or picks up when its input currentexceeds a predetermined value.

Directional function: an element picks up for faults inone direction, and remains stable for faults in the other

direction.

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OPERATING CHARACTERISTICSOF PROTECTIVE RELAYS

Distance protection function: an element usedfor protection of transmission lines whoseresponse is a function of the measured electricaldistance between the relay location and the fault

point. Differential protection function:it senses a

difference between incoming and outgoingcurrents flowing through the protected apparatus.

Communications-Assisted Tripping Schemes:a form of the transmission line protection thatuses a communication between distance relays atopposite line ends resulting in selective clearing of

all line faults without time delay.

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OVERCURRENT AND DIRECTIONALPROTECTION ELEMENTS

An overcurrent condition occurs when the maximumcontinuous load current permissible for a particularpiece of equipment is exceeded.

A phase overcurrent protection element continuouslymonitors the phase current being conducted in thesystem and issue a trip command to a CB when themeasured current exceeds a predefined setting.

The biggest area of concern for over-currentprotection is how to achieve selectivity.

Some possible solutions have been developed,including monitoring current levels (current grading),introducing time delays (time grading) or combiningthe two as well as including a directional element todetect the direction of current flow.

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TIME DELAYS An alternate means of grading is introducing time delays

between subsequent relays. Time delays are set so that the appropriate relay has

sufficient time to open its breaker and clear the fault on itssection of line before the relay associated with theadjacent section acts.

Hence, the relay at the remote end is set up to have theshortest time delay and each successive relay back towardthe source has an increasingly longer time delay.

This eliminates some of the problems with current gradingand achieves a system where the minimum amount of

equipment is isolated during a fault. However, there is one main problem which arises due to

the fact that timing is based solely on position, not faultcurrent level.

So, faults nearer to the source, which carry the highestcurrent, will take longer to clear, which is very

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DIRECTIONAL ELEMENTS

Selectivity can be achieved by using directional elementsin conjunction with instantaneous or definite-timeovercurrent elements.

Directional overcurrent protection schemes respond tofaults in only one direction which allows the relay to be setin coordination with other relays downstream from therelay location.

This is explained using example in Fig. 4.

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DIRECTIONAL ELEMENTS

By providing directionalelements at the remote endsof this system, which wouldonly operate for faultcurrents flowing in one

direction we can maintainredundancy during a fault.

This is in line with one of themain outcomes of ensuringselectivity, which is to

minimize amount of circuitrythat is isolated in order toclear a fault.

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Fig. 4: Use of direction elementexample


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DIRECTION OF CURRENT FLOW In AC systems, it is difficult to determine the direction of

current flow and the only way to achieve this is to performmeasurements with reference to another alternatingquantity, namely voltage. The main principle of howdirectional elements operate is based on the followingequations for torque:

If current is in the forward direction, then the sign of thetorque equation will be positive and as soon as thedirection of current flow reverses, the sign of the torqueequation becomes negative. These calculations are

constantly being performed internally inside directionalelement.

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)cos( ABCABCA IVIVT =

)cos( BCABCAB IVIVT =

)cos( CABCABC IVIVT =


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DISTANCE PROTECTION FUNCTION

A distance protection element measures thequotient V/I (impedance), considering thephase angle between the voltage V and thecurrent I.

In the event of a fault, sudden changes occurin measured voltage and current, causing avariation in the measured impedance.

The measured impedance is then comparedagainst the set value.

Distance element will trip the relay (a tripcommand will be issued to the CB associatedwith the relay) if the measured value of theimpedance is less then the value set.

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In Fig. 5 the impedance measured at the relay pointA is , wherexis the distance to the fault(short circuit), and R and L are transmission lineparameters in per unit length. The line length is l

in the fig..

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Fig. 5 Distance protection principle of operation.

( )inZ R j L x= +


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We can see that the impedance value of a faultloop increases from zero for a short circuit at thesource end A, up to some finite value at the remoteend B. We can use this principle to set up zones of

distance protection as well as to provide feedbackabout where a fault occurred (distance to fault).

Operating characteristics of distance protectionelements are usually represented using R-X

diagrams. Fig. 6 shows an example of Mho R-X operating

characteristic. The relay is considered to be at theorigin. 29


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Region ofoperation

Zone 1

Region of

non-operation

outside the circle

Load

region

R

X

Zone 2

A

B

80%

120%

Line P

Line Q

R SZ

Fig. 6 Mho positive-sequence R-X operating

characteristic of a distance element.


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DISTANCE PROTECTIONFUNCTION

The need for zones shown in Fig. 6 arises fromthe need of selective protection; i.e. the distanceelement should only trip faulty section.

We can set the distance element to only trigger a

trip signal for faults within a certain distancefrom the relay, which is called the distanceelement reach.

The setting impedance is represented by

, where ZL is the line impedance. The distanceelement will only trip when the measuredimpedanceZR is less than or equal to the setting

impedance hsZL.31

RS s LZ h Z=


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Typically hs is set to protect 80% of the line between two

buses and this forms protection Zone 1. Errors in the VTs and CTs, modeled transmission line data,

and fault study data do not permit setting Zone 1 for100% of the transmission line.

If we set Zone 1 for 100% of the transmission line,unwanted tripping could occur for faults just beyond theremote end of the line.

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DISTANCE PROTECTIONFUNCTION

Zone 2 is set to protect 120% of the line,hence making it over-reaching, because itextends into the section of line protected bythe relay at point B. To avoid nuisance

tripping, any fault occurring in Zone 1 iscleared instantaneously, while faults whichoccur in Zone 2 are cleared after a time delayin order to allow relay B to clear that fault

first.This provides redundancy in the protection

system (backup), whilst maintainingselectivity. 33

protection settings

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