End to End and cordination

7/25/2019 End to End and cordination

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APPLICATION CASE OF THE END-TO-END RELAY TESTING USING

GPS-SYNCHRONIZED SECONDARY INJECTION

IN COMMUNICATION BASED PROTECTION SCHEMES

J. Ariza G. Ibarra

Megger, USA CFE, Mexico

Abstract

This paper reviews the philosophy of the end-to-endrelay testing using gps-synchronized secondary

injection in communication based protection schemes.

The paper describes an application case at a

Distribution Division in Jalsco, Mexico, operated by

the national utility CFE (Comisin Federal deElectricidad). The line protection scheme is specialdue to a tap derivation line in the middle of the line

which has a normally open switch to feed a sensitive

and important customer. In normal condition, the line

differential relay (87L) is the main protection and the

distance element (21 ) is an integrated back up

protection. Following the discrete back up protection

philosophy there is another relay which is used as

phase comparison (67N ). In maintenance condition the

line differential relay (87L) has to be disabled and the

settings for the distance element must be changed

remotely from the control center. All the above

protections are Communication based Protection(Transfer Trip Schemes). The document will describe

the purpose of the testing, the actual test scenarios,

special tools needed, resources, and criteria for success.

INTRODUCTION

Digital Signal Processors and high-speed operating

systems have revolutionized not only protective relays,

but protective relay testing as well. Modern

microprocessor-based relay test sets, combined with

personal computers and GPS satellite receivers have

provided the means to dynamically test relay protection

schemes end-to-end.

The philosophy for testing and maintenance of

protective relays has dramatically changed over the last

decade. The proliferation of microprocessor-based

relays, down sizing of maintenance and testing

personnel and ever increasing time between

maintenance intervals has caused many companies to

change how relays are tested. System reliability is still

a major concern, with increasing load and powerwheeling requirements [1].

Development of modern communication technology

and the need for selectivity of switched line faults inthe shortest time, have inspired Power System

Protection Communications Schemes for Line Current

Differential, Phase Comparison and Distance

Protection communication based protection.[2]

Electric utilities may vary in their application of end-

to-end testing of relays. At a Distribution Division in

Jalsco, Mexico, operated by the national utility CFE

(Comisin Federal de Electricidad) , a standardized

process and equipment set-up for end-to-end relaytesting was tested with successful result.

END TO END TESTING

The most common application of GPS-synchronized

secondary injection end-to-end relay testing is to verify

transmission line protection schemes of newly installedrelays. The test is normally performed at the end of

commissioning of a new substation or during relay

replacement projects. The objective is to perform a

complete check of the new system protection scheme,

including verification of circuit breaker operation,communication channel time and the effectiveness of

relay settings before the relays are placed in service.

Other applications have been in verifying relay setting

changes, troubleshooting relay malfunctions and

evaluating new relay protection schemes.[1]

The most important challenge in testing line protection

schemes is to provide the test quantities at all the line

terminal relays at the same time. A line differential

relay acquires the currents from its own terminal only

and, based on the method employed, the remote current

is provided via various communication channels. A

simple and quick test can detect the individual pickuplevel for each relay by gradually increasing the

current(s) at one end. Since no current is provided from

the other terminal, the local relay will trip as soon as

the threshold is reached. This method is not suitable to

determine the operating or restraining characteristic. Inorder to determine the characteristic all the terminal

currents have to be provided synchronously and each

of the relays has to send the quantities to the remote

ends in real time.

Modern relays are connected between each other by

fiber optic system so the processing of the pre-fault and

fault quantities and transmitting the trip or blockdecisions to the remote ends are performed extremely


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fast. In recent years the advancements in the new

microprocessor based relay test sets allow you to test

the line differential relays in such a way that simulates

the real life processes in the Power System. Theconcept of testing the relays is called End-To-End

and has become rapidly implemented as a standard

technique in the industry. Basically the method

requires two three phase test sets equipped with a

Global Positioning System (GPS) receiver and an

antenna. Fig.1 depicts the standard setup (antenna and

the receiver not shown). A Global Positioning System

(GPS) consists of a number of satellites orbiting at high

altitude (approx. 11000 miles) and ground stations

which monitor and control the system. The system

consists of 21 active satellites and 3 in-orbit spareseach of which orbit the earth twice per day. The design

of the system is such that at least four satellites are in

view at all times from all places on the earth, thus

providing continuous, worldwide, three dimensional

navigation capabilities. The satellites transmit encodedsignals at either 1575.42 or 1227.6 MHz.

For End-To-End testing it is recommended that a

minimum of 3 satellites must be tracked

simultaneously.

However a precise time (the only important parameter

for this application) can be derived by tracking one

satellite only. The GPS receivers are highly accurate

with a drift in the nanoseconds range. The satellites

send corrective signals to GPS receivers which allow

the internal clock to be aligned to the high accuracy

Cesium atomic clock of the satellites. The

programming of the system is simple since the trackingis performed automatically when the unit is powered

up initially.

Basically the user has to set the coincidence time

(compared to the Universal Time Clock-UTC) when hewants to start the test. The same coincidence time has

to be set at both terminals. The time is usually

displayed with a resolution within microseconds.[2]

TEST SYSTEM

In the past, relay test sets were manually controlled andwere used to evaluate the steady-state response of

relays. With advanced microprocessor-based relay test

sets, dynamic or multi-state testing of relays became

possible. Under dynamic conditions, the relay is tested

by applying simulated pre-fault, fault and post-fault

condition quantities using a pure sine wave. With

modern relay test sets, transient waveforms (which

include dc offset and harmonics) can be produced

several ways:1) mathematically using Fourier expansionwith exponential offset and decay, 2) using the replay of

actual recorded faults from a Digital Fault Recorder

(DFR) and 3) using simulation data derived from

running the Electromagnetic Transient Program(EMTP), or other Alternative Transient Program (ATP)

files converted to the COMTRADE ASCII format, (see

IEEE Standard C37.111 1999) [5]. The COMTRADE

Standard makes it possible to playback digital fault

records from different manufacturers fault recorders[1].

Figure 1: End to End testing Set-up

CASE

Power Line 63580 shows in Figure #2 has a special

protection scheme due to the tap derivation line in the

middle of the line which has a normally open switch to

feed a sensitive and important customer called SCI. In

normal condition, the line differential relay (87L) is the

main protection and the distance element (21 -POTT)

is an integrated back up protection. Following the

discrete back up protection philosophy there is another

relay which is used as phase comparison (67N - DTT).All the above protections are Communication basedProtection (Transfer Trip Schemes). Figure #3 shows

the protection scheme in one end of the line; the other

end has the same scheme.

Figure # 2. Single Line Diagram 69 kV


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Figure # 3 Protection Single Line Diagram

During the maintenance period at the substation GUDin the Jalisco Distribution Division, CFE has to switch

the SCI load from substation GUD to the line 63580

closing the switch 6368C and opening the switch

6368B. Therefore the line differential relay (87L) has

to be disabled and the settings for the distance element

must be changed. This can be achieved by doing achange of group of setting remotely from the control

center. In this condition the distance element is the

main protection and the phase comparison is the back

up protection.

The objective is testing this line protection schemeproviding the test quantities at all the line terminal

relays at the same time, in order to verify the main

protection, back up protection and the transfer trips for

normal and maintenance conditions.

TEST PREPARATION

A kick off meeting is held to check the procedures and

to define the objectives. The points to be checked were

specified as follows:

Protection Schemes (schematics and relay

settings)

Teams Definition ( at least 1 engineer on each

side)

Relay Test Set (Synchronization test)

Software and test modules for end to end test

GPS receiver (Synchronization test)

Test Definition (Internal Fault, External Fault,

POTT, DTT etc)

Sequence Definitions for both sides (Pre fault,

Fault and Post fault)

Teams communication channel definition (i.e

radio, phone, cell phone, etc)

Figure 4. Kick off meeting

States Playback Sequence Definition.

For the line differential relay an internal and external

fault are simulated. A pre-fault condition is assumed,

which is typically the normal loading condition of theline. Once the pre-fault data are established, an

iterative process of running the internal fault and

external fault takes place.

Figure 5. External Fault Condition

For each pre-determined internal and external fault, the

pre-selected fault types are simulated.


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Figure 6. Internal Fault Condition

For the Permissive Overreach Transfer Trip ( POTT)

simulation, a previous calculation is necessary using

the distance setting of the relays. The local relay has todetect a fault in Zone 1 and the remote relay in Zone 2;

the local relay trips instantaneously and sends a signal

to the remote relay to accelerate the operation of theremote relay, therefore the trip time is faster than the

normal time for Zone 2.

Figure 7. Fault Simulation for POTT verification

The sequences have to simulate a fault at 10% of the

line, Zone 1 for the local relay and Zone 2 for the

remote relay in order to verify the POTT scheme.

TEST EXECUTION

The first phase of end-to-end testing involves setting

up test equipment, performing the planned sequence of

test events, evaluating test results and taking corrective

actions when necessary. A typical step-by-step

procedure can be specified as follows:

- Connecting the test equipment to the

protecting relays

- Connecting the GPS receiver and look for the

appropriate number of satellites- Preparing the test equipment software for

starting the test at both sides

- Coordination between testing teams regarding

the first test and starting time.

- Execute the first sequence and waiting for

GPS trigger

- Coordination between testing teams regarding

the successful start.

- When the first simulation is finished,

coordinate with the other side regarding the

results of the test and eventually thearrangements about editing of the test

sequence ( times, phase shift, etc)

- Test results are immediately evaluated and

compared to expected values or actions ( trip ,

block, transfer trip, etc)- Repeat this process for every fault simulationuntil getting the successful result

Figure 8: Test Waiting for Trigger.

Once the line differential relay is tested, the back upprotection has to be tested. At this particular scheme

the back up protection is a Distance Protection

communication based protection (Permissive

Overreach Transfer Trip, POTT). The procedure

basically is the same as described before, the only

difference is changing the group of settings in order to

block the differential element (87L) and add voltageschannel in the states playback based on the previous

calculation for Z1 and Z2.


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Figure 9 : Typical Test Set Up

Two PC's are typically used. The first PC hosts the

automation software program for the relay test set and

the GPS receiver. The second PC is used primarily to

monitor the relay and store relay fault data, see Figure

9.

A GPS antenna with flexible coaxial cable is used for

the GPS clock receiver. The antenna is run to the

outside of the relay building and can be easily mounted

on top of a parked vehicle or on any support structure

or platform. Care should be taken in handling andplacement of the GPS antenna in EHV yards.

Figure 10 : GPS Receiver Software

Modern relays have a sequence of event recorderwhich monitors and records the relay response. It is

useful in determining the timing of relay operation and

tracking of events. Communication channel times are

also readily determined from the sequence of event

graphs.

Figure 11. Test Results From Digital Relay

The post-test phase involves more in-depth analysis of

test results, which is typically performed when the

results do not meet expectations. This is a situation

when protection engineers are involved in reviewing

the fault study and investigating causes of

discrepancies. In this phase, test results are

documented and reports are prepared when required.

CONCLUSIONS

In this era of electric utility restructuring, particularly

when transmission line providers have to account for

line outages, Communication-assisted tripping

technology and the end-to-end tests will be applied

more often to realistically recreate line events.

End-to-End testing verifies a complete protection

scheme, including relays at different locations, plus the

communication link between them

REFERENCES

[1] M. Agudo, S. I. Thompson, et. al., End-to-End

Relay Testing Using GPS Synchronized Secondary

Injection, IEEE Computer Applications in Power, Vol

13, No. 3, July 2000

[2] C. Paduraru, "End-to-End Testing of the Alpha

Plane Characteristic of the New Line Differential

Relays Using Satellite Synchronization Signals"

Megger, Electrical Tester, Dallas, TX, 2005.

[3] IEEE Standard Common Format for Transient Data

Exchange (COMTRADE) for Power Systems, IEEE

C37.111-1999

SEL 311L Instruction Manual.Available online at : www.selinc.com

BIOGRAPHY

James Ariza received his B.S. in Electrical

Engineering from Universidad del Valle, Cali,

Colombia. He has extensive experience in the testingand commissioning of electrical schemes as well as


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performing power system studies and design and

electrical system fieldwork supervision. He has

previously worked with a electric utility, an R&D

technology center and a consulting engineeringcompany for the power industry. He joined Megger in

2005 as an Application Engineer in Technical Support

Group and he is in charge with developing custom

applications for numerical protection relays using

AVTS (Advanced Visual Test Software). He is also in

charge with testing and developing auto test modules,

which allow the customer to evaluate and diagnose of

microprocessor based protective relays. James is

currently worked toward a Master Degree in Power

Systems. He is a member of the IEEE.

Gerardo Ibarra received his B.S in Electrical

Engieneer from Universidad de Guadalajara, Jalisco

Mexico. He joined to CFE in 2001 as a protection

engineer. His activities include testing and

commissioning of new substations, modernization ofprotection schemes and relay programming. Prior to hisarrival at CFE he worked as subcontractor in the IBM

plant in Guadalajara. His activities included corrective

and preventive maintenance of PLCs in the

automation system.


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Distribution Automation HandbookSection 8.2 Relay Coordination


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Distribution Automation Handbook (prototype)

Power System Protection, 8.2 Relay Coordination

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Contents

8.2

Relay Coordination and Selective Protection .................................................................................... 3

8.2.1

Introduction .............................................................................................................................. 3

8.2.2

Time-graded Protection ............................................................................................................ 3

8.2.3

Time- and Current-graded Protection .................................................................................... 11

8.2.4

Time- and direction-graded protection .................................................................................. 12

8.2.5

Current- and Impedance-graded Protection .......................................................................... 15

8.2.6

Interlocking-based Protection ................................................................................................ 17

8.2.7

Differential Protection ............................................................................................................ 19

8.2.7.1 LOW-IMPEDANCE PRINCIPLE ............................................................................................................................................... 208.2.7.2 HIGH-IMPEDANCE PRINCIPLE .............................................................................................................................................. 22


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8.2 Relay Coordination and Selective Protection

8.2.1 Introduction

The selected protection principle affects the operating speed of the protection, which has a significant im-

pact on the harm caused by short circuits. The faster the protection operates, the smaller the resulting ha-

zards, damage and the thermal stress will be. Further, the duration of the voltage dip caused by the short

circuit fault will be shorter, the faster the protection operates. Thus, the disadvantage to other parts of the

network due to undervoltage will be reduced to a minimum. The fast operation of the protection also reduc-

es post-fault load peaks which, in combination with the voltage dip, increase the risk of the disturbance

spreading into healthy parts of the network. In transmission networks, any increase of the operation speedof the protection will allow the loading of the lines to be increased without increasing the risk of losing the

network stability.

Good and reliable selectivity of the protection is essential in order to limit the supply interruption to the

smallest area possible and to give a clear indication of the faulted part of the network. This makes it possi-

ble to direct the corrective action to the faulty part of the network and the supply to be restored as rapidly as

possible.

Thus, attention must be paid to the operating speed of the protection, which can be affected by a proper se-

lection of the applied protection principle. Selective short-circuit protection can be achieved in different

ways, such as: Time-graded protection

Time- and current-graded protection

Time- and direction-graded protection

Current- and impedance-graded protection

Interlocking protection

Differential protection

8.2.2 Time-graded Protection

A straightforward way of obtaining selective protection is to use time grading. The principle is to grade the

operating times of the relays in such a way that the relay closest to the fault spot operates first. Time-graded

protection is implemented using overcurrent relays with either definite time characteristic or inverse time

characteristic. The operating time of definite time relays does not depend on the magnitude of the fault cur-

rent, while the operating time of inverse time relays is shorter the higher the fault current magnitude is. The

time-graded protection is best suited for radial networks.

The principle of inverse time protection is especially suited for radial networks where the variations of

short-circuit power due to changes in network configuration are small or where the short-circuit current

magnitude at the beginning and end of the feeder differs considerably. In these cases, the use of inverse

time relays in favor of definite time relays can usually speed up the operating time of the protection at high


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fault current magnitudes. Time grading with fuses is also easier to obtain with inverse time relays. Consi-

dering the above arguments and also taking into account, for example the short-circuit current withstandcapacity of the network components, applying inverse time relays for the network short-circuit protection

may be justified.

The IEC 60255-151 and BS 142 standards define four characteristic time-current curve sets for inverse time

relays:

Normal inverse

Long-time inverse

Very inverse

Extremely inverse

For inverse time relays the operating time (s) can be calculated from the equation:

1

>I

I

k=t

(8.2.1)

where

k is an adjustable time multiplier

I is the measured phase current value

>I is the set start (pickup) current value

, are curve set-related parameters

According to the standards, the relay should start once the energizing current exceeds 1.3 times the set start

current when the normal, very or extremely inverse time characteristic is used. When the long-time inverse

characteristic is used the relay should start when the energizing current exceeds 1.1 times the set start cur-

rent.

The parameters and define the steepness of the time-current curves as follows:

Table 8.2.1: Curve set related parametersType of characteristic

Normal inverse 0.02 0.14

Very inverse 1.0 13.5

Extremely inverse 2.0 80.0

Long-time inverse 1.0 120.0

Figure 8.2.1 shows a time-graded protection arrangement in a radial network. In the example network,

three-stage protectionis implemented. For the low-set stage(3I>), either inverse time or definite time cha-

racteristic can be given. The high-set andtheinstantaneous stage(3I>> and 3I>>>) have definite time cha-


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racteristic and their purpose is to accelerate the operation of the protection under heavy fault current condi-

tions. A multiple-stage protection is often required to meet with the sensitivity and operating speed re-quirements and to achieve a good and reliable grading of the protection, see Figure 8.2.1.

Studying and planning of time-selective protection schemes is most conveniently carried out usingselectiv-

ity diagrams. The selectivity diagram is a set of specific time/current curves which shows all the

time/current curves, that is, the operating characteristicsof the relays of the concerned chain of protection

relays. The chain of relays in the example of Figure 8.2.1 includes two relays. The selectivity diagram also

includes additional information needed for the planning and operation of the protection, such as the lowest

and highest fault current levels in the relaying points, maximum load current, nominal currents and short-

circuit current withstand capacity of network components and the maximum limit values of possible

switching inrush currents and start currents.

The selectivity diagram of Figure 8.2.1 shows that should a fault arise, for example, in the far end of the

feeder (outgoing feeder 1) protected by relay 1, the fault current magnitude will be on the level indicated by

. This fault causes both the relay 1 and relay 2 to start (outgoing feeder 1). Thus, the concerned feeder be-

longs to the protection area of the relay 1 and relay 2, providing an inherent backup protection for the feed-

er. Should relay 1 or its circuit breaker fail to operate, relay 2 will be allowed to operate.

Figure 8.2.1: Overcurrent protection of radial network and the corresponding selectivity diagram

The selection of the propergrading timeis of essential importance for the selectivity of the protection. The

grading time is the time difference between two consecutiveprotection stages. In heavy fault current condi-

tions, the relay operating time must not be unnecessarily prolonged and, on the other hand, a satisfactory

FEEDER 1

MF3I >

3I >>

3I >>>

0 I

linetype 2

linetype 1

I

3 = INRUSH CURRENT PEAK VALUE, FEEDER 1

2 = OPERATING CHARACTERISTICS OF O/C PROTECTION, INCOMER 1

4 , 5 = THERMAL WITHSTAND, LINE TYPE 1 AND 2

1

3I >

3I >>

3I >>>

2

INCOMER

9 = INCOMER RATED CURRENT

11 = LINE TYPE 1 RATED CURRENT

12 = HIGHEST LOAD CURRENT, FEEDER 1

Kmax

IKmin

20 kV

IKmax

IKmin

IKmax

IKmin

6

7

8

MF

current (A)

1 4

10

time

(s)

2

53

1

100

10-1

102 103 104

8 7 691112

tIDMT

tDT

IL

10

1 = OPERATING CHARACTERISTICS OF O/C PROTECTION, FEEDER 1

10 = LINE TYPE 2 RATED CURRENT

IL


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margin must be maintained to secure the selectivity. When inverse time relays are used instead of definite

time relays, longer grading times must generally be used, because, among other things, the effect of the in-accuracy of the current measurement on the operating time must be observed.

In the example of Figure 8.2.1, the grading times have been defined separately for each stage. The grading

time between the inverse time stages have been denotedIDMTt and, correspondingly, the grading time be-

tween definite time stages has been denotedDTt . When defining the grading time, it must be noted that at

lower fault current levels the prevailing load currentsLI of the healthy feeders during the fault must be

taken into account to a certain degree. These currents are summed, for example, into the current measured

by relay 2 when a fault appears on feeder 1.

When numerical relays are used, the required grading times can be calculated from Equations (8.2.2) and

(8.2.3). Figure 8.2.2 shows how the grading times and the factors affecting them are formed. For definitetime relays, the grading time

DTt is obtained from Equation (8.2.2).

MCBREDT ttttt +++= 2 (8.2.2)

where

Et is the tolerance of the relay operating time

CBt is the circuit breaker operating time

Rt is the relay retardation time

Mt is the safety margin

The safety margin takes into account the possible delay of the relay operation due to CT-saturation caused

by the DC-component of the fault current. The length of the possible additional delay thus occurring is af-

fected by the fault type, fault current magnitude and the ratio between the CT-accuracy limit factor and the

set current value. In theory, the delay can even be as long as the time constant of the DC-component,

should the fault current just slightly exceed the set value and should the set value have been chosen just

slightly below the corresponding CT-accuracy limit factor. In practice, however, the CTs of the consecutive

relays of the protection chain will saturate within a certain fault current range, which means that the opera-

tion of the relays is about equally delayed. For this reason, a safety margin of about the length of the fun-

damental frequency cycle is enough.

If, however, relatively big differences in the accuracy limit factors of successive CTs in the protection chain

exist, it might be justifiable to increase the safety margin in relationto the time constant of the DC-

component. The safety margin is also to be increased if auxiliary relays are used in the trip circuit of the

circuit breaker.

The retardation time is the time period just before the elapsing of the operation delay timer. If the fault dis-

appears before the starting of the retardation time, the protection relay that has been started by the fault is

still able to cancel its tripping command. If the fault disappears during the retardation time just before the

elapsing of the operation delay timer, the tripping command will be initiated.


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The grading time IDMTt for protection schemes based on inverse time relays is obtained from Equation

(8.2.3):

MCBRIDMT tttE

Ett +++

+= 1

1001

1001

2

11

(8.2.3)

where

1E is a factor which takes into account the superimposed effect of the oper-

ating time error caused by the inaccuracy of the current measurement

and the operating time tolerance in the relay located closest to the fault

spot (%) 1)

2E is a factor which takes into account the superimposed effect of the oper-ating time error caused by the inaccuracy of the current measurement

and the operating time tolerance in the relay located next in the protec-

tion chain (%) 1)

CBt is the circuit breaker operating time

Rt is the retardation time

Mt is the safety margin

1t is the calculated operating time of the relay closest to the fault spot 1)

1) Corresponds to the current value with which the grading time is determined, Figure 8.2.2.

Figure 8.2.2: Grading time determination and factors affecting it. Notations: I1 , I2 = current val-

ues with which the grading time between the low-set stages (3I>) is determined, Ikmax

= maximum short-circuit current. For other notations, see Equations (8.2.2) and

(8.2.3).

tDT

IL

I1 I2

E (%)1t1

E (%)2

tIDMT

t2

tCB tR+

IKmax

tCB tR+tE

tE

current

time

FEEDER 1

MF

3I >

3I >>

1

3I >

3I >>

2

INCOMER

20 kV

2

1

MF

IL


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The tolerance values of the operating times are standardized, Table 8.2.2:

Table 8.2.2: Limit values, according to the BS 142 standard, of the operating times expressed as a

percentage. E= accuracy class index

I/I> Normal inverse Very inverse Extremely inverse Long time inverse

2 2.22E 2.34E 2.44E 2.34E

5 1.13E 1.26E 1.48E 1.26E

7 - - - 1.00E

10 1.01E 1.01E 1.02E -

20 1.00E 1.00E 1.00E -

Furthermore, the effect of the current measuring inaccuracy on the operating time of the inverse time pro-

tection must be observed. The effect can be evaluated using Equation (8.2.1) by giving values to the phase

current according to the measuring inaccuracy used. The measuring inaccuracy is affected not only by the

relay type but also by the accuracy of the measurement transformers. By adding the percentage of the oper-

ating time inaccuracies thus obtained to the values of Table 8.2.2 , the values of the factors 1E and 2E can

be found.


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Example of the determination of the grading time DTt

The grading time between the high-set stages of the numerical protection relays in

Figure 8.2.1 is determined using the Equation (8.2.2):

2 times the tolerance of the operating time: 2 x 25 ms

Circuit breaker operating time: 50 ms

Retardation time: 30 ms

Safety margin: 20 ms

Total: 150 ms

The safety margin has been given the smallest possible value, and so the grading timeDTt =150 ms can be

chosen, see Figure 8.2.1.

Example of the determination of the grading time IDMTt

The grading time between the low-set stages of the numerical protection relays in Figure 8.2.1 is deter-

mined using Equation (8.2.3):

Current values with which the grading time is determined:

Relay 1: 1I = 1200 A 4.0 times the current setting of the stage

Relay 2: 2I = 1700 A 2.4 times the current setting of the stage

The selected curve type is normal inverse and the accuracy classEwhich equals 5%.

Table 8.2.2 is used and the operating time tolerances are selected to correspond to the currents1I and 2I

mentioned above. Table 8.2.2 shows that tolerances closest to those currents are 1.13E(relay 1) or 6% and

2.22E(relay 2) or about 11%.

The effect of the current measuring inaccuracy on the operating times in per cent from the calculated oper-

ating times1t and 2t is determined using Equation (8.2.1), and when the joint current measuring inaccuracy

of the relay and the measurementtransformer is expected to be 3%, Table 8.2.3 and Table 8.2.4. It must

also be noted that the operating time error thus arising is independent of the setting of the time multiplier k

of the inverse time curve.

Table 8.2.3: The effect of the current measuring inaccuracy on the operating times in relation to the

calculated operating times t1 of relay 1 for the current I1

I1

(x I>)

Current measurement

error

(%)

Operating time error

(t-t1) / t

1x 100

(%)

4.0 +3 -2

4.0 -3 +2


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Table 8.2.4: The effect of the current measuring inaccuracy on the operating times in relation to the

calculated operating times t2 of relay 2 for the current I2

I2

(x I>)

Current measurement

error

(%)

Operating time error

(t-t2) / t2x 100

(%)

2.4 +3 -3

2.4 -3 +3

The factors 1E and 2E are calculated as the sum of the absolute values of the errors:

Relay 1: 1E =8%

Relay 2: 2E =14%

By inserting factors1E and 2E into Equation (8.2.3) and by observing that the calculated operating time 1t

of relay 1 is 1000 ms at 1200 A (4 x the set current), the required grading time can be calculated as follows:

+ 1

1001

1001

2

11

E

Et : 260 ms

CB-operating time: 50 ms

Retardation time: 30 ms

Safety margin: 20 ms

Total: 360 ms

According to this, the grading time IDMTt should be given a value of at least 360 ms, Figure 8.2.1.

The time-graded protection can also be implemented with definite time underimpedance relays. The relay

measures the phase currents and phase-to-phase or phase-to-earth voltages. Based on these values, it deter-

mines the apparent impedance seen from the relay location. The relay operates if the measured impedance

falls below the set start value. The set start value determines the so-called reachof the relay, which defines

at which distance faults seen from the relaying point can still be detected. Owing to the measuring prin-

ciple, the advantage of the impedance relay is that its operation is independent of the short-circuit power ofthe incoming network. The reach and the operating time of the relay are unchanged even if the source im-

pedance changes, for example, when the network configuration is altered. Thus the relay operates reliably

even though the short-circuit current would be particularly low. For this reason, underimpedance relays are

frequently used as feeder protection relays in networks with low short-circuit power. Another typical appli-

cation is the use of underimpedance relays as backup protection relays in vicinity of power plants where the

fault current may decay under the set start value of overcurrent relays due to the effect of generators. If the

protection of the outgoing lines from the power plant is also based on the impedance-measuring principle,

selectivity between the relays can be easily obtained. The aforementioned salient principles of time grading

also apply to underimpedance protection.


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8.2.3 Time- and Current-graded Protection

Time- and current-gradedprotection can be used in cases where the fault current magnitudes in faults oc-

curring in front of and behind the relaying point are different. Due to the different fault current levels using

inverse time relays but also multi-stage definite time relays, different operating times can be obtained in ei-

ther direction. In this way the requested time grading can be obtained and the operating time requirements

can be fulfilled.

Figure 8.2.3 shows an example time- and current-graded overcurrent protection application. The study of

the time grading towards one particular generator feeder is straightforward if the operating characteristic of

the protection of the other generator feeders are combined in a single operating characteristic of a so-called

equivalent generator feeder. This is obtained by multiplying the current values of the relay operating cha-

racteristic of a single generator by the number of generators in use at any time, operating characteristic 3G ,

Figure 8.2.3. From the selectivity diagram, it can be seen that when a fault occurs on feeder 4, for example,

the total fault current fed by the network and the other feeders reaches the level indicated by . Thus, the

operating time of the protection can even be shorter than 100 ms. The fault current fed by the equivalent

generator is at least on the level indicated by. It can clearly be seen that in this way a reliable time-

grading is obtained between the generator feeders also in cases where the fault current fed by the network is

particularly low or if one generator is out of operation. The same method of study can be applied for plan-

ning the time-grading between the protection relays of the block transformer and the generator feeders for

faults occurring in the network side. In this planning, special attention must be paid to the number of gene-

rators in operation and its effect on the the selectivity. Should machines be taken out of operation, the time-

grading towards the network can be endangered if the settings of the protection relays of the block trans-

former are not adapted to the operating conditions at any time.

The protection practice described can also be used in the overcurrent protection of ring and meshed net-

works. Another area of application is the earth fault protection of effectively earthed ring and meshed net-

works.


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1MRS757285

12

Figure 8.2.3: Power plant overcurrent protection implemented with time and current grading to-

wards the generator feeders. The generators are of equal rated power and their in-

verse time relays share the same settings. Ing= rated current of a single generator.

8.2.4 Time- and direction-graded protection

In ring and meshed networks, the selectivity of the protection can be based on directional overcurrent re-

lays. Directional relays are needed as different operating times are required depending on the location of the

fault, that is, if the fault spot is in front of the relaying point on the feeder or behind the relaying point, for

example, on the incoming feeder or on the busbar system.

The directional overcurrent relay operates once the fault current exceeds the set start current and the direc-

tion of the fault current complies with the setting. Thus the selectivity of the protection is based on both

time and current direction. The directional overcurrent protection can operate either according to definite

time or inverse time characteristics and the aforementioned central principles of time-grading are also ap-plicable to directional protection.

Typical applications based on directional protection are shown in Figure 8.2.4.

1 102 3 4 5 6 7 8 9

101

100

10-1

tim

e(s)

current (I/ I )

1 3G1G

1 3 4

MF

3I >

1G

BLOCK TRAFO

IK

4

GEN.FEEDER 1

MF

GEN.FEEDER 2

MF

GEN.FEEDER 3

MF

GEN.FEEDER 4

~ ~ ~ ~

3I >

3G

IK

1

IK

1

IK

1

IK

3

1 = GENERATOR THERMAL WITHSTAND (IEC 34-1)

1G = OPERATING CHARACTERISTICS, GENERATOR FEEDER

1 = FAULT CURRENT SUPPLIED BY ONE GENERATOR

3 = FAULT CURRENT SUPPLIED BY EXTERNAL NETWORK

4 = TOTAL FAULT CURRENT SUPPLIED BY EXTERNAL NETWORK AND EQUIVALENT GENERATOR

20 30

3G = OPERATING CHARACTERISTICS, EQUIVALENT GENERATOR (3 GENERATORS )

ng

2 = FAULT CURRENT SUPPLIED BY EQUIVALENT GENERATOR (3 GENERATORS)

3

2

3 = EQUIVALENT GENERATOR THERMAL WITHSTAND (IEC 34-1)(3 GENERATORS)

NETWORK


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1MRS757285

13

Figure 8.2.4: Directional overcurrent relays applied to short-circuit protection of ring-type net-

works supplied from one point

Various principles are used for determining the direction of the fault current. The most conventional way is

to determine the direction phase-specifically so that the current phasor of each faulty phase is compared tothe phasor of the opposite phase-to-phase voltage, for example, the direction of the phase current phasor

1LI is compared to the direction of the phasor 23U . The relay operates if one or more of the direction com-

parisons show that the fault is located in theforwardor reversedirection with regard to the setrelay operat-

ing direction. An example operating characteristic formed in this way is shown in Figure 8.2.5.

3I>

3I>

3I>

3I>3I>

3I>

3I>

3I>

3I> 3I>

3I>

3I>3I>

3I>

3I>3I>

3I>3I> 3I>

3I> 3I>

3I>

3I>3I>

3I>

3I>

3I>3I>

3I>

3I>


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1MRS757285

14

Figure 8.2.5: Direction determination principle of phases L1 and L2 based on using the opposite

phase-to-phase voltage 23LU and 31LU correspondingly. The fault is located in for-

ward direction.

Another way of determining the direction is first to indentify the faulty phases on the basis of the starts of

the phase-specific overcurrent functions and then compare the difference between these current phasors to

the difference between the other two phase-to-phase voltages, for example, the direction of the phasor

21 LL

II is compared to the direction of the phasor3123

UU . Alternatively, the phasor21 LL

II can also

be compared to the direction of the corresponding faulty phase-to-phase phasor 12U , or to the correspond-

ing positive-sequence voltage1U ,which must be suitably rotated according to the fault type in question.

The said direction determination methods need to be supported by a voltage memorywhich stores the pha-

sors of the pre-fault voltages. The relay uses the stored information for determination of the fault current di-

rection in cases where the voltages are too low to be measured, that is, close-in short circuits. The advan-

tage of the methods not using the corresponding faulty voltage is that the voltage memory is needed only in

three-phase close-in short circuits. In two-phase short circuits, the voltages needed for the determination of

the direction are always high enough to be measured. If using the faulty voltage in direction determination,

the voltage memory is needed also in two-phase close-in short circuits. However, the advantage of this me-

thod is that the phase order of the power system has no impact on the direction determination.

The protection of ring and meshed networks can also be carried out using directional definite time unde-

rimpedanceor distance relays. These relays are frequently used for the protection of transmission and sub-

transmission networks, meshed or ring-operated distribution networks or weak radial networks. The advan-

tages of the use of distance relays are the same as for the underimpedance relays in general, and the general

time-grading principles also apply in this protection concept. To achieve a good and reliable selectivity and

to fulfill the operating speed requirements as well as possible, it is typically necessary to implement mul-

tiple directional underimpedance stages. The reach of these stages defines thezonesof protection toward

the desired operating direction, which can be either forward of reverse. An example of this can be seen in

Figure 8.2.6, where multiple-stage numerical distance relay units are applied to the short-circuit protection

of a sub-transmission network. The figure also shows the principal reaches of the different zones of the ex-

+90

U23

UL2UL3

U12

U31

IL1

180

-90

REVERSE

FORWARDU23

UL1

UL3

U12

U31

IL2

1

80

-90

+90

Phase L1: Phase L2:

UL1

UL2

REVERSE

FORWARDcurrent setting

current setting


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1MRS757285

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ample relay unit. The zones Z1, Z2and Z3are set in the forward direction, that is, toward the protected line

and the zone Z4in the reverse direction.

The zone Z1is underreachingthe remote end station, making it possible to apply minimum operating times.

Zone Z2is slightly overreachingthe remote end, which means that the time coordination with zone Z1of

the successive line is required; therefore the operating time is delayed as much as the grading margin re-

quires. Zone Z3operates as an overreaching backup protection and the operating time must be selected so

that it coordinates with the protection in the forward direction in all conditions. Zone Z4 operates as an

overreaching backup protection in the reverse direction, and the reach of this zone is selected so that it can

detect faults even on the MV-side of the transformers. The operating time is selected accordingly. The main

purpose of the zone Z4is to operate as a backup protection for the transformers. The main advantage of us-

ing distance relays in this example is that all faults occurring in the sub-transmission network can be

cleared by the zones Z1or Z2in less than 0.2 seconds. Also possible fault current infeed from the distribu-tion network side due to distributed generation, for example, does not affect the selectivity of the protec-

tion.

Figure 8.2.6: The application principle of numerical multiple-stage distance protection for short-

circuit protection of a sub-transmission ring main system. MV=distribution voltage.

The notation 1 //- or 2 // transformer indicates the number of parallel transformers

feeding the distribution network at any given time

8.2.5 Current- and Impedance-graded Protection

In certain cases, protection principle based oncurrent and impedance grading can be used to essentially

accelerate the operation of the protection in faults arising close to the relaying point. The protection is im-

plemented by using one directional or non-directional stage of the overcurrent or underimpedance relay.

MV-network

MV-network MV-network

MV-network

MV-network

MV-network

MV-network

MV-network

MV-network MV-network

MV-network

MV-network

MV-network

MV-network


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1MRS757285

16

The intention is to set the start current of the overcurrent stage so high that when a fault arises in front of

the next relay in the protection chain, the concerned stage will not operate and no time-grading is needed.Correspondingly, when an underimpedance stage is used, the reach should be set low enough to obtain the

corresponding function. For example, in Figure 8.2.6 the zone Z1operates according to this principle.

In accordance with the principle, the operating times of the stages can be set to their minimum without en-

dangering the selectivity, because the protection operates only in faults occurring inside the protection

zones determined by the current or impedance settings. The protection zones thus created do not overlap.

Therefore, a normal time-graded protection arrangement should always be incorporated in parallel with the

protection based on current or impedance grading.

When the settings of a current-graded protection arrangement are determined, the behavior of the relay type

used in unsymmetrical faults must be taken into account, that is, does the DC-component of the fault cur-

rent possibly cause a so-called transient overreach DCk (%),which is defined as:

100

=

F

FSDC

I

IIk (8.2.4)

where

SI is the RMS-value of the steady-state phase current at which the protec-tion operates, that is, the set current.

FI is the RMS-value of the steady-state phase current onto which a supe-

rimposed full DC-component causes the protection to operate at the setcurrent SI

The primary value of the set start current of the current-graded overcurrent stage should be higher than or

equal to CSI

( ) KDCmCS IkkI += 1001 (8.2.5)

where

mk is a safety factor which takes into account the inaccuracy of the fault

current calculation and the errors of the measurement transformers andthe relay; a typical value equals 1.2

KI is the maximum fault current, which is calculated in the location of the

successive/next relayin the protection chain

Especially the application of the current grading requires a sufficiently low source impedance ratio(SIR),

Equation (8.2.6), at the relaying point. In the current-graded protection, this ensures that the fault current

difference in the beginning and the end of the protected feeder, or in the HV- and the MV-side of the pro-

tected transformer, is high enough to enable suitable settings to be found for the protection. The reach of

the current-graded protection in relation to the total length or impedance of the protected feeder depends on


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1MRS757285

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both the SIR-value and theICS-setting of the current-graded stage. The higher the SIR-value, the shorter the

reach of the protection on the protected feeder will be.

L

S

Z

ZSIR = (8.2.6)

where

SZ is the impedance of the incoming network, that is, the source impedanceas seen from the relaying point

LZ is the impedance of the protected feeder as seen from the relaying point

A high SIR-value may also limit the use of the impedance-graded protection concept because in such a casethe magnitudes of the currents and voltages measured by the protection at the end of the zone and in the

immediate vicinity may be so close to each other that measuring errors may cause a false operation of the

protection.

8.2.6 Interlocking-based Protection

The purpose ofinterlocking-based protection is to accelerate the operation of the protection. The concept is

especially suited for busbar protection, but it can also be implemented for the protection of short outgoing

and incoming feeders and the transformer MV-side. The basic idea is to use interlocking between consecu-

tive protective relays in the protection chain, Figure 8.2.7. This protection practice is generally used in

combination with overcurrent relays.

In the example of Figure 8.2.7, the protected object is a busbar system, the bus tie circuit breaker of which

is normally open. When a fault arises on the feeder, the overcurrent relays of both the incoming and out-

going feeders start. The overcurrent relay of the faulty feeder sends an interlocking signal that blocks the

operation of the 3I>>>-stage of the incoming feeder relay and trips the circuit breaker after the set time de-

lay. When the fault appears within the area of protection, that is, on the busbar, no interlocking signals will

be generated and the 3I>>>-stage of the incoming feeder relay trips the circuit breaker after the set time

delay, which is shorter than what would be required in the time-graded solution in the corresponding situa-

tion. When also the bus tie circuit breaker is incorporated in the interlocking chain, the protection operates

selectively even if the bus tie circuit breaker were closed.

The interlocking-based protection concept is best suited for use in radial networks, where the short-circuit

currents are considerably higher than the load currents. In this case, a current setting value can easily be

found for the overcurrent stage that issues the interlocking signal. It must also be noted that the stage is-

suing the interlocking signal is not allowed to start for faults within the protected area if the fault current

can also be fed by the concerned feeder (backfeed). Then the start current of the stage which issues the in-

terlocking signal must be set higher than the backfeed current (c.f. current selective protection) or a direc-

tional relay must be used for issuing the interlocking signal.

For a reliable and selective operation, the overcurrent stage to be interlocked must be slightly delayed. In

the example of Figure 8.2.7, the 3I>>>-stage of the incoming feeder relay is used for this purpose. The re-

quired delay depends on the features of the relay type applied, the accuracy limit factors of the CTs and the


24/34



1MRS757285

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implementation of the interlocking channel. The required operating delay can be estimated by observing the

following: Start time of the overcurrent stage issuing the interlocking signal. This starting time includes both

the start delay of the stage and the inherent delay of the binary output of the relay (typically

3I >>

3I >>>

MF

TIEBREAKER

Bin

Bout

3I >

3I >>

3I >>>

Bin

3I >

3I >>

3I >>>

3I >

3I >>

3I >>>

Bout

MF

DISTR.

FEEDER

3I >

3I >>

3I >>>

Bout

B in

Bout

BLOCKING

BLOCKING 1

BLOCKING 2


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1MRS757285

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8.2.7.1 Low-impedance pri nciple

A low-impedance differential schememeasures the currents on either side of the protected object and forms

from these a differential current dI , Figure 8.2.8. In practice, a small differential current, mainly caused by

measuring errors of the current transformers and the relay, can be noticed even though there is no fault

within the area of protection. In transformer protection applications, a so-called apparent differential current

like this is additionally caused by the no-load current of the transformer, the position of the tap changer and

momentarily by the transformer inrush current, which fully appears as differential current. The magnitude

of the differential current caused by the measuring errors and the position of the tap changer is directly pro-

portional to the load current of the transformer. A particularly crucial situation from the apparent differen-

tial current point of view appears at faults just outside the area of protection. The through-fault current is

high and may contain a DC-component which may cause saturation of the current transformers resulting in

a momentary increase in the differential current. To avoid a false operation of the differential relay, the re-lay must be stabilized, which means that the higher the through-fault current, the higher differential current

is required for tripping. Thestabilizing current bI is formed from the phase currents measured on both

sides of the protected object. An example of the operating characteristic of a stabilized differential relay is

shown in Figure 8.2.8. The shape of the characteristic is defined by the basic setting,starting ratioand the

second turning point, Figure 8.2.8. For stabilizing current values greater than the second turning point, the

starting ratio is fixed.

Figure 8.2.8: Operating characteristic of a low-impedance type differential current relay

As the name implies, the basic setting defines the basic sensitivity of the relay under no-load conditions of

the protected object. The basic setting must be higher than, for example, the transformer excitation current

or the line-charging current at maximum operating voltage to avoid a false operation of the relay. The basic

setting also affects the level of the entire characteristic curve and thus also the operating sensitivity at high-

er stabilizing current levels.


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1MRS757285

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The starting ratio caters for the sources of the apparent differential current, which are directly proportional

to the through-flowing current. It is mainly the starting ratio together with the second turning point that de-termines the operating sensitivity of the relay for internal transformer or machine faults when these objects

are loaded. Winding and interturn short circuits and earth faults in the windings or elsewhere in the pro-

tected area are fault types that call for a sensitive and fast operation of the protection.

The second turning point also affects thestabilityof the protection at faults outside the area of protection.

In this situation, the relay must not operate incorrectly and trip the circuit breaker under the influence of the

apparent differential current. The lower the setting of the second turning point, the better the stability ob-

tained will be. On the other hand, the sensitivity of the relay for internal faults may be decreased in the

same time, particularly in the transformer protection applications. By taking notice of the accuracy limit

factors of the CTs, the fault current levels and their supply directions and the sensitivity requirements of the

protected object, the setting of the second turning point is in general easily found.

At stabilizing current levels above the second turning point, the high starting ratio secures stability at faults

arising outside the area of protection.

Stability problems may be caused by switching inrush currents. When a protected power transformer is

energized, the inrush current fully appears as differential current, in which case the stabilization of the relay

alone is not enough to prevent false relay operations. This situation calls for a blocking function based on

the second harmonicto inhibit the operation of the stabilized stage. The second harmonic is typically abun-

dantly present in the inrush current.

Problems may also arise when the transformer inrush current fed by the protected generator is fairly high

compared to the rated current. In these cases, the unsymmetrical phase currents containing second harmon-ics may cause non-simultaneous saturation of the current transformers and thus apparent differential current

for the relay. To secure the operation of the relay under these circumstances, the activation of the second

harmonic-based blocking function is often justifiable.

In transformer protection applications, the stability is also endangered by a temporary overvoltage. The in-

creasing voltage generates a growing magnetizing current because of the saturation of the transformer,

which is fully seen as differential current. When the ratio between the differential current and the stabilizing

current exceeds the settings, the relay operates. The operation can be inhibited by incorporating a blocking

function based on the fifth harmonic. The magnetizing current of a saturated power transformer contains a

great deal of this particular harmonic. If the overvoltage situation becomes worse, the proportion of the fifth

harmonic typically grows up to a certain knee point level. At this point it may be appropriate to remove theblocking and to enable the relay to operate in order to prevent too excessive overexcitation of the transfor-

mer. This can be done with the release function of the fifth harmonic-based blocking.

To obtain as fast and dependable relay operation as possible at faults inside the area of protection, a high-

set stage is used in addition to the stabilized stage. The high-set stage cannot be blocked and it is unstabi-

lized. The high-set stage operates when the differential current momentarily exceeds the set start value.

For a fast and dependable operation of the high-set stage, the accuracy limit factor of the current transfor-

mers used in the protection must be high enough. This will also prevent the unnecessary operation of the

second harmonic blocking function and in this way additional delay in operation of the stabilized stage can

be prevented. On the one hand, a sufficient similarity in the accuracy limit factors of the current transfor-


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1MRS757285

22

mers used in the protection further assures that the relay maintains its stability at faults outside the area of

protection.

8.2.7.2 H igh- impedance pri nciple

Thanks to its operating principle, thehigh-impedance differential scheme is particularly easy to implement

and set and has a high operational reliability, Figure 8.2.9. The stabilization of the high-impedance scheme

is performed by a separatestabilizing resistor. As the name implies, this resistor is employed for the pre-

vention of false relay operations on faults outside the area of protection. Such operations may be caused by

the differential current arising from non-simultaneous saturation of the current transformers. Because the

current transformer circuits are galvanically interconnected, all the current transformers of the protection

should have the same turns ratio. The use of intermediate current transformers is not recommended as this

increases the requirements set on the main current transformers and lowers the sensitivity of the protection.The high-impedance principle is particularly well suited for the short-circuit protection of machines, short

lines and busbar systems and the earth-fault protection of these and transformers in effectively earthed and

low-impedance-earthed networks.

The design of the stabilization of the high-impedance scheme is based on the assumption that one of the

current transformers of the protection fully saturates at faults outside the area of protection, while the rest of

the current transformers do not saturate at all. The idea is to route the apparent differential current formed

in the mentioned way to flow through the saturated current transformer rather than through the relay. Be-

cause the impedance of the saturated current transformer is low, a high resistance, that is, the stabilizing re-

sistor, is connected in series with the relay circuit. Now the entire differential current is forced to flow

through the secondary circuit of the saturated current transformer, which can be described by short-circuiting the magnetizing reactanceEX in Figure 8.2.9. The voltage drop formed over the secondary cir-

cuit will then be the same as that over the relay circuit, Figure 8.2.9. This stabilizing voltagemust not cause

a relay operation.


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1MRS757285

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Figure 8.2.9: Single-phase equivalent circuit diagram and operating principle at faults outside the

area of protection, and calculation of the stabilizing voltage USbeing the setting cri-

terion for the relay. RS= stabilizing resistor, RU= voltage dependent resistor (varis-

tor).

When the protection is implemented using a voltage relay, the selected setting must be equal to or exceed

the calculated stabilizing voltage. The value of the stabilizing resistor is determined according to this vol-

tage setting. In case of a voltage relay, the stabilizing resistor is often integrated into the relay. When theprotection is implemented using a current relay, the current value at which the relay should operate must be

determined first. By means of the stabilizing voltage and the current setting, the value of the stabilizing re-

sistor is obtained. Typically in case of a current relay the stabilizing resistor must be separately installed

and connected to the relay circuit.

On faults inside the area of protection, the current transformers attempt to feed a secondary current propor-

tional to the short-circuit current through the relay. But because the impedance of the relay circuit is high,

the secondary voltage may exceed the ratings of the relay and the secondary wiring. For this reason, a vol-

tage-dependent resistor is to be connected in parallel with the relay in order to limit the voltage to a safe

level.

The current transformers used in the high-impedance protection applications must have an adequate accura-

cy limit factor to be capable of supplying enough current to the relaying circuit on faults inside the area of

protection. This requirement is fulfilled if the knee point voltage of the current transformers is at least twice

the chosen stabilizing voltage. This way, the protection operates fast and reliably also for differential cur-

rent levels just slightly exceeding the set value. The protection requires class X or PX current transformers

according to BS 3938 or IEC 60044-1 respectively, the repetition capability of which is determined by the

knee point voltage and the resistance of the secondary circuit. In the specification of the class X or PX CTs,

the magnetizing current corresponding to the knee point voltage is also given. This current value is needed

for the calculation of the overall sensitivity of the protection.


30/34

Document revision history

Document revision/date History

A / 08 April 2011 First revision

Disclaimer and Copyrights

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In no event shall ABB Oy be liable for direct, indirect, special, incidental or consequential damages of any nature or kind aris-ing from the use of this document, nor shall ABB Oy be liable for incidental or consequential damages arising from use of anysoftware or hardware described in this document.

This document and parts thereof must not be reproduced or copied without written permission from ABB Oy, and the contentsthereof must not be imparted to a third party nor used for any unauthorized purpose.

The software or hardware described in this document is furnished under a license and may be used, copied, or disclosed only inaccordance with the terms of such license.

Copyright 2011 ABB Oy

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ABB

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d.

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Contact information

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