Training _ Power System Protection _AREVA

TRAINING ON POWER SYSTEM PROTECTION

APPS COMBINED 'COURSE

Enter the world of the AREVA T&D Training web site:

wwvv.areva-td.com/training

m Endorsed' Provider

I I

INTRODUCTION TO

f i

POWER SYSTEM PROTECTON i

CONTENTS

Overview Of Protection Fundamentals

Notes Overcurrent Protection

Directional Overcurrnt

Transformer Protec:tion Notes

Transformer Setting Tutorials

Generator and Generator Transf - Protection

Generators Setting Criteria

Distance Protection Notes

Distance Protectiorr Schemes

Busbar Protection

Motor Protection

A C Motor Protection

Motor Setting Criteria

Notes 1 C T S

Notes Additional Analysis

Notes Unbalanced Faults

Tutorial Balanced Faults

Tutorial Grading Examples

Tutorials Generator Protection

Tutorial C T Selection

Tutorial Busbar Protection

Overview Of Protection Fundamentals

APPS- Corn bined course Overview Of Protection Fundamentals

Page 2 of 0

OVERVIEW OF PROTECTION FUNDAMENTALS

1.0 INTRODUCTION

I

Relays are compact devices that are connected throughout the power system to detect intolerable or unwanted conditions within an assigned area. They are in effect, a form of active insurance designed to maintain a high degree of service continuity and limit equipment damage. They are "Silent Sentinels". While protective relays will be the main emphasis of this chapter, other types of relays, applied on a more limited basis or used as part df a total protective relays system will also be covered.

2.0 CLASSIFICATION OF RELAYS

I Relays can be divided into five functional categories: i 1 I a. P r o t e c t i v e Relays, which detect defective lines, defective apparatus, or

i other dangerous or intolerable conditions. These relays can either

i initiate or permit switching or simply provide an alarm. I i

b. M o n i t o r i n g Re lays , which verify conditions on the power system or in the protection system. These relays include fault detectors, alarm units, channel-monitoring relays, synchronism verification, and network phasing. Power system conditions that do not involve opening circuit

, breakers during faults can be monitored by these relays. I

I c. P r o g r a m m i n g Re lays , which establish or detect electrical sequences. Programming relays are used for reclosing and synct-~ronising.

I d. R e g u l a t i n g Re lays , which are activated when an operating parameter deviates from predetermined limits. Regulating relays function through supplementary equipment to restore the quantity to the prescribed limits.

e. Auxi l iary Relays, which operate in response to the opening or closing of

1 the operating circuit to supplement another relay or device. These include timers, contact-multiplier relays, sealing units, receiver relays, lock-out relays, closing relays and trip relays.

i

OALSTOM Limited, Energy Automation & Information

APPS- Combined cc.?~~rse Overview Of Protection Fundamentals

Page 3 of O-

In addition to these functional categories, relays may be classified by input, operating principle or structure and performance characteristic:

Input Current voltage Power Pressure Frequency -

Temperature Flow Vibration

(ii) Operating Principle of Structure Percentage

> Multi-restraint > Product > Solid state > Electromechanical > Thermal.

The above c~assifi~ation and definitions are based on the ANSI Standard 37.90 (IEEE 31 3).

3.0 PROTECTIVE RELAYING SYSTEMS AND THEIR DESIGN

Technically, most relays are small systems within themselves. Throughout this chapter, however, the term systems will be used to indicate a combination of relays of the same or different types. Properly speaking, the protective relaying system includes circuit breakers as well as relays. Relays and circuit breakers must function together; there i s little or no value in applying one without the other.

Protective relays or systenls are not required to function during normal power system operation, but must be immediately availa,ble to handle intolerable system conditions and avoid serious outages and damage. Thus,. the true operating life of these relays can be on the order of a few seconds, even though they are connected in a system for many years. In practice, the relays operate far more during t.esting and maintenance than in response to'adverse service conditions.

--. - t

OALSTOM Limited, Energy Automation & Information I

. . -. - . . . APPS- Corn bined course

- Overview Of Protection Fundamentals

Page 4 of 0

In theory, a relay system should be able to respond to the infinity of abnormalities that can possibly occur within the power system. In practice, the relay engineer must arrive at a compromise based on the four factors that influence a n y re!oy rrpp!icatisn:

a. Economics - Initial, operating and maintenance. b. Available measure of fault or trouble - Fault magnitudes and location of

current transformers and voltage transformers. c. Operating practices - Conformity to standard and accepted practices;

ensuring efficient system operation. d. Previous experience - History and anticipation perhaps better expressed

of trouble likely to be encountered within-the system-.

The third and fourth considerations are perhaps better expressed as the "personality of the system and the relay engineer".

Since it is simply not feasible to design a protective relaying system capable of handling any potential problem, compromises must be made. In general, only those problems, which according to past experience are likely to occur, receive primary consideration. Naturally, this makes relaying somewhat of an art. Different relay engineers will, using sound logic, design significantly different proteclive systems for essentially the same power system. As a result there is little standardisation in protective relaying. Not only may the type of relaying system vary, but also will the extent of the protective coverage. Too much protection i s almost as bad as little.

Nonetheless, protective relaying i s a highly specialised technology requiring an in-depth understanding of the power system as a whole. The relay engineer must know, not only the technology of the abnormal, but have a basic understanding of all the system components and their operation in the system. Relaying, then, i s a "Vertical" specialty requiring a "horizontal" viewpoint. This horizontal, or total system, concept of relaying includes fault protection and the performance of the protection system during abnormal system operation such as severe overloads, generation deficiency, out-of-step conditions, and so forth. Although these areas are vitally important to the relay engineer, his concern has not always been fully appreciated or shared by his colleagues. For this reason, close and continued communication between the planning, relay design, and operation systems should be mandatory, since power systems grow and operating conditions change.

4


APPS- Combined course Overview Of Protection Fundamentals

Page 5 of 0

A complex relaying system may result from poor system design or the economic need to use fewer circuit breakers. Considerable savings can be realized by using fewer circuit breakers and a more complex relay system. Such systems usually involve design compromises requiring careful evaluation, if acceptable protection is to be maintained.

-

4.0 DESIGN CRITERIA

The application logic of protective relays divides the power system into --

several zones, each requiring its own group of relays. In all cases, the five design criteria listed below are common to any well-designed and efficient protective system or system segment:

a. Reliability - the ability of the relay p r relay system to perform correctly when needed (dependability) and to avoid unnecessary operalion (security).

b. Speed - minimum fault time and equipment damage: c. Selectivity - maximum service continuity with minimum system

disconnection. d. Economics - maximum protection at minimum cost. e. Simplicity - minimum equipment and circuitry.

Since it is impractical to fully satisfy all these design criteria simultaneously the necessary compromhes must be evaluated on the basis of comparative risks.

4.1 Reliability System reliability consists of two elements - dependability and security. Dependability is the certainty of correct operation in response to system trouble, while security i s the ability of the system to avoid mis-operation between faults. Unfortunately, these aspects of reliability tend to counter one another: increasing security tends to decrease dependability and vice versa. In general, however, modern relaying systems are highly reliable and provide practical compromise between security and dependability.

Protective relay system must perform correctly under adverse sysfem and environmental conditions. Regardless of whether other systems are momentarily blinded during this period, the relays must perform accurately and dependably. They must either operate in response to trouble in their assigned area or block correctly i f the trouble is outside their designated area.

OALSTOM Limited, Energy Automalion & informalion


Page 6 of 0

Dependability can be checked relatively easily in the laboratory or during installation by simulated tests or staged faults. Security on the other hand is much more difficult to check. A true test of system security would have to measure response to an almost infinite variety of potential transients and counterfeit trouble indicalions in the power system and i ts environment. A secure system is usually the result of a good background in design combined with extensive miniature power system testing and can only be confirmed in the power system itself and its environment.

4.2 Speed Relays that could anticipate a fa~llt wo!~ld be utopian. But, even i f 'available, they would doubtlessly raise the question of whether or not the fault gr trouble really required a trip-out. The development of faster relays must always be measured against the increased probability of more unwanted or unexplained operations. Time, no matter how short, i s still the best method of distinguishing between real and counterfeit trouble.

Applied to a relay, high speed indicates that the operating time usually does not exceed 50 ms (3 cycles on a 60-hertz base). The term instantaneous indicates that no delay is purposely introduced in the operation. In practice, the terms high speed and instantaneous are frequently used interchangeably.

4.3 Selectivity versus Economics High speed relays provide greater service continuity by reducing fault damage and hazards to personnel. These relays generally have a higher initial cost, which, however, cannot always be justified. Consequently, both low and high-speed relays are used to protect power systems. Both types have high reliability records. Records on protective relay operations consistently show 99.5% and better relay performance.

4.4 Simplicity As in any other engineering discipline, simplicity in a protective relay system is always the hallmark of a good design. The simplest relay system, however, is not always the most economical. As previously indicated, major economies are possible with a complex relay system that uses a minimum number of circuit breakers. Other factors being equal, simplicity of design improves system reliability - i f only because there are fewer elements that can malfunction.


\


Page 7 of 0

\ i 5.0 FACTORS INFLUENCING RELAY PERFORMANCE j I

Relay performance i s generally classed as:

( 1 ) Correct (2) No conclusion (3) lncorrect

lncorrect operation may be either failure to trip or false tripping. The cause of incorrect operation may be, a) Wrong application, b) lncorrect settings, c) A personnel error or 4) Equipment mal-function. Equipment that can cause an incorrect operation includes current transformers, voltage transformers, circuit breakers, cable and wiring, relays, channels or station batteries.

lncorrect tripping of circuit breakers not associated with the trouble area is often as disastrous as c failure to trip. Hence, special care must be taken in both appiication and installation to ensure against the possibility of incorrect tripping. -

" No conclusion" is the last resort when no evidence is -available for a correct or incorrect operation. Quite often this is a personnel involvement. 6.0 Zones of Protection The general philosophy of relay application is to divide the power system into protective zones that can be protected adequately with the mininwm amount of the system disconnected. The power system is divided into protective zones for:

i 1 Generators ii) Transformers iii) Buses iv) Transmission and distribution circuits v) Motors

. A typical power system and its zones of protection are shown in Figl. The purpose of the protective system is to provide the first line of protection, within the guide-lines outlined above. Since failures .do occur, however some form of backup protection is provided to trip out the adjace13f breakers or zones surrounding the trouble area. Protection in each zone is overlapped to avoid the possibility of unprotected areas

1

OALSTOM Limited, Energy kutomation & Informalion


Page 10 of 0

The device switching equipment are referred to by numbers, with appropriate suffix letters when necessary, according to the functions they

- perform.

These numbers are based on a system adopted as standard for automatic switchgear by IEEE and incorporated in American Standard C37.2 - 1970. 'This system is used in connection diagrams, in instruction books and in specifications.

8.1 Device Numb'erina Device Number

1 Definition

Master Elemenl Function

It is an initiating device, such as a control switch, voltage relay, float switch, etc., which serves either directly or through such permissive devices as protective and time delay relays. t o place an equipment in or out of

Starting or Closing Relay

2 a desired amount of time delay before or after any point of operation in a switching sequence or protective relaying system, except as specifically provided by device function 48, 62 and 79

1 described later. Checking or Interlocking Relay

Time Delay

It is a device which operates in response to the position of a number of other devices (or to a number of predetermined conditions), in an equipment, to allow an operating sequence to proceed, to stop, or to provide a check of the position of these devices or of these conditions

i for any purpose.

operation. It i s a device which functions to give

- -- - -- - 4


ibined course Overview Of Protection Fundamentals

I Device Number Definition Master Contactor

Page 1 1 of 0

Function It is a device, generally controlled by the device No.1 or equivalent, and the required perrr~issive and protective devices, that serve to make and break the necessary control circuits to place an equipment into operation under the desired conditions and to take it out

to shut down an equipment and hold it out of operation This device 1 may be manually or Electrically I actuated, but excludes the function of electrical lockout (see device 1

5 -

Anode Circuit Breaker

Stopping Device

Control Power Disconnecting Device

of operation under other or abnormal conditions. It is a control device used primarily

function 86) on abnormal conditions. 1 It i s a device whose principal) function is to connect a machine.to its source of staitina voltaae.

1

It is one used in-the anode circuits of a power rectifier for the primary purpose of interrupting the rectifier

6

circuit if an arc back should occur. It is a disconnecting device - such as a knife switch, circuit breaker or pullout fuse block, used for the purpose of connecting and disconnecting the source of control power to and from the control bus or equipment. Note: Control power is considered to include auxiliary power, which supplies such apparatus as sn~all

Starting Circuit Breaker

I

1 / any other reversina functions. I

Reversing Device

I 10 ( Unit Sequence ( It is used to change the sequence in 1

motors and heaters. It is used for the purpose of reversing a machine field or for performing 1

1 Switch / which units may be placed in and I


APPS- Corn bined course -- ~~

Overview Of Protection Fundamentals Page 10 of 0

The device switching equipment are referred to by numbers, with appropriate suffix letters when necessary, according to the functions they

- perform.

These numbers are based on a system adopted as standard for automatic switchgear by IEEE and. incorporated in American Standard C37.2 - 1970. This system is used in connection diagrams, in instruction books and in specifications.

8.1 Device Numb'erina Device Number

1 --

Definition Master Element

Function It is an initiating device, such as a control switch, voltage relay, float switch, etc., which serves either directly or through such permissive devices as protective and time delay relays. to

Checking c P

2

except as specifically provided b y device function 48, 62 and 79 described later. It is a device which operates in

Time Delay Stariing or Closing Relay

predetermined conditions), in an equipment, to allow an operating sequence to proceed, to stop, or to provide a check of the position of these devices or of these conditions

place an equipment in or out of operation. It is a device which functions to give a desired amount of time delay before or after any point of operation in a switching sequence or protective relaying system,

( Interlocking 1 Relay

!L- 1 / for any purpose.

response to the position of a number of other devices (or to a number of

-- $

. I OALSTOM Limited, Energy Automation & Information

. . I function 86) on c ~ - - ~ ~ . - ! ~ ~ .~= : :~ ; ,T !CJTI~ . i __ ,

l t i s a device .....--zs5 5:ir!.cipaI / Breaker function is to c o ~ - - ~ ~ - ~ ; ~ ~ v ! ~ r , ~ to !

pps- Combined course Overview Or Protection ~undamental~

page 1 1 of 0

-

Function It is a device, generally controlled b y the device No.1 or equivalent. ---=I and : the required permissive and I protective devices, that sr=rL/rs to make and break the rlecessarY control circuits to place a r t , equipment into operation vrde! 'the I desired ~onditiof?s end to toke i i out of operation ~ n d m TJ~I-!F-: Or 1 abnormal conditic:;~. ____---- I It is a coritiol d,-\:jCe usee ;,:irr~arily I to shut down c;; equipn.5~1: ar id)

-, . hold it out of oge:2-i&n- ;rli: C;e /ice -. i

may be mancc:ii. or I:5c.::i~~lly ,

actuated, but exc,,zss ;r,5 f;,..ctior~ 1 of elect!-ical I C ~ ~ - , - 1 ~ ~ 5 -, 2 :;edice '

Device Nurr~ ber 4

5

I ( Device / a mactlifie fiei& - - - :- A, - - -- - , s - 1 -<,!irtr; ./

Definition Master Contactor

. Stopping Device

i t s source of stariir:.~ -. G ; T C ~ ~ . - .

It is one used in i.-e s-seL 2i:i of a power- recjifie- :-- - - - - r,gy,gr ' j ;

purpose oi inte---, , --- 2 -/ - ,:- T 4:;' l t l~er - circuit if ar: arc F - : A 7 :T;~, .J~.

It i s a discanne;- -; ,I. ' - p L , - ;:,C~I $

as a knife switc: L-.-=_ - L-3r;/er or pullout fuse b!.zqzq - - - - - - - - :=. t h e

- purpose of I:-------- _ _ , - .;:Id - disconnecting ii-5 5 z . - - z l -' -_,<-,irC~l

power t2 ~ : ; d f: I -- - - - - - - - * / - - - r~1.J:

or equipr:ie!~i. Note: C ~ r ] i l . ~ / PO\.*. 5- 1 1 -;:;*5?

. ,

. - include zct..rilic-. 1 . . :- ,,.,< ~f-r supplies sctci, r - - - - - - - - - - *'5~\1

b - - - - - - 2 - -

( . 7 I Anode Circuit

I Breaker 1

) 9 Reversing

an other re\,ersir,z -- -.y .T; : -- . . Unit Sequence It is used :p , -~?C~. - .Z - - --.- _ -s--- _ _ / * :=- 'c. irl

which ur;i;- -,?c.,v --; - - - - - - -'"; Id;- --... _ - _ - - - - , ._ 4 _. . - - J . ' 2

8

motors a r ~ c nec:~.--,- ... - - - -

it is used iL7:. :he r*-.-.,- - L - -2 ...-cs~r~:; _ _ _ - A

OALSTOM Limited, Energy Automation & Info:;:-z'ior.

Control Power Disconnecting Device

I


Page 14ofO

Device Number 25

the armature winding of a machine, or that of a load limiting or load shifting resistor or of a liquid or other

26

medium exceeds a p.redefermined value ; or if the temperature of the protected appa~.atus, such as a

Definition Synchronising or Synchronism-

power rectifier, or of any medium decreases below a predetermined

Function It is a device that operates when two ac circuits are within the desired

Check Device 1 . Apparatus Thermal Device

limits of frequency, phase angle and voltage, to permit' or to cause the paralleling of these two circuits. It is a device, which functions when the temperature of the shunt field or

presence of the pilot or main flame In such apparatus as a gas turbine I -

value. It i s a device, which functions on a given value 'of undervoltage. It is a device that monitors the

I I I -

2 7

28

1 - 29 I Isolating

L- 32 I Direc:'anal ( It is a device which functions on a I

Under Voltage Relay Flanie detector

or a steam boiler. It is a device used for disconnecting

4


one circuit from another for the purposes of emergency operation, maintenance, or test. It is a non-automatically reset device that gives a number of separate visual indications upon the functioning of protective devices and which may also be arranged to perform a lockout function. It connects a circuit such as the shunt field of a synchronous converter, to a source of separate excitation during the starting sequence ; or one which energises the excitation and ignition circuits of a nower rectifier.

( Contcctor

30

3 1

Annunciator relay -

Sepcrzl te Excitciion Device

~ p p s - Combined course . Overview Of Protection Fundamentals

. . - Page 15 of 0

r ~

I Power Relay 1 desired value of power fiow in 7 m e Number I Definition

given direction, or upon reverse power, like resulting from arc back in I the anode or cathode circuits of a I

Function I

I I 1 main device or piece of apparatus, 1 33

Sequence Device

Position Switch

34 operated multi-conjact switch, or the equiv'alent, or a programming device, such 0 s a computer, that establishes or determines the

power rectifier. It makes or breaks contact when the

operating sequence of the major devices in an equipment during starting and stopping or during other

Master

which has no device function number, reaches a given position. It is a device such as a motor-

I Operating, or ] shifting, the brushes of a machine, or I 35

Voltage Device

Brush-

36

predetermined polarity only verifies the presence of a polarising

sequential operations. It i s used for raising, lowering, or

Slip-ring-short- circuiting Device Polarity or Polarising

1 Relav

for short circuiting i ts slip rings, or for engaging or disengaging the contacts of a mechanical rectifier. It operates or permits the operation of another device on a ,

1 37

Bearing Protective Device

Mechanical Condition Monitor

Undercurrent or Under power

predetermined value. It functions on excessive bearing temperature, or on other abnormal mechanical conditions, such as undue wear, which may eventually result in excessive bearing

voltage in an equipment. It functions when the current or power flow decreases below a

occurrence abnormal

- --

i OALSTOM Limited, Energy Automation & Information

APPS- Combined course Overview Of Pr~?xt!on Fundamentals

Page 1 6 of 0

I Device Number I Definition Function I

-

Field Relay

. .

Field Circuit

associated with bearings as covered under device function 38), such as excessive vibration, eccentricity, expansion, shock, tilting, or seal failure. It functions on a given or abnormally low value or failure of machine field current, or on an excessive value of the reactive component of armature current in an ac machine indicating abnormally low field excitation.

1 It is a device, which functions to

Breaker

-

function is to connect a machine to its source of running or operating voltage. This function may also be used for a device, such as a contactor, that is used in series with

Breaker

/ Device transfers the switching equipment or of some I of the devices.

apply, or to remove the field excitation of a machine.

42

1

I -

Manual Transfer Selector

Unit Sequence 1 Starting Relay I

-p

a circuit breaker or other fault protecting means, primarily for frequent opening and closing of the circuit. It transfers the control circuits so as to modify the plan of operation of

It is a device, whichfunctions to start the next available unit in a multiple- unit equipment on the failure or on.

I Atmospheric I Condition ! Monitor

I I I

preceding unit. It is a device that functions upon the occurrence of an abnormal atmospheric condition, such as damaging fumes, ex'plosive mixture, smoke or fire.

( the non-availability of the normally 1

46 I Reverse-Phase. It is a relav which functions when the 1

.. -

i OALSTOM Limited, Energy Automation & Information

Overview Of Protection Fundamentals Page 1 7 of 0

I Device Number I Definition Function I Phase-Balance, Current Relay

poly-phase currents are of reverse phase sequence, or when the poly- phase cu:cer?,?s fire vnbolonced zl;

contain negative phase-sequence components above a given

I 1 Sequence - 1 value of poly phase voltage in the ] 4 7

Voltage Relay Incomplete

Phase -

Sequence Relay

amount. It functions, upon a predetermined

desired phase sequence. It is a relay that generally returns the equipment to the normal, or off, position and locks it out if the normal starting, operating or stopping sequence is not properly completed within a predetermined time. If the

I device is used for alarm purpose only, it should preferably be

Transformer, Thermal Relay

,

l+achine, or temperature - of a machine armature, or other -load carrying winding or element of a machine, or the temperature of a power rectifier

designated as 48A (alarm). It is a relay that functions w.hen the

or power transformer (including a power rectifier transformer) exceeds an medetermined value.

Ilnstantaneous [ I t is a relay that functions1 overcurrent, or Rate of rise Relay -

AC Time Overcurrent Relay

I

52 / AC Circuit

instantaneously on an excessive value of current, or on an excessive current rise, thus indicating a fault in the apparatus or circuit being protected. It is a relay with either a definile or an inverse time characteristic lhat functions when the current in an ac circuit exceeds a predetermined value. It i s a device that is used to close

1 I Breaker and interrupt an ac power circuit 1 1 under normal conditions or to


APPS- Corn bined course . . Overview Of Pr~?w-t!on Fundamentals

! Page 16 of 0

I Device Number 1 Definition Function 1

-

Field Relay

associated with bearings as covered under device function 38), such as excessive vibration, eccentricity, expansion, shock, tilting, or seal failure. It functions on a given or abnormally low value or failure of machine field current, or on an excessive value of the reactive component of armature current in an ac machine indicating abnormally low field

42 ( Running Circuit It is a device whose principal I

( Breaker

' excitation. It i s :a device, which functions to apply, or to remove the field

!

function i s to connect a machine to its source of running or operating voltage. This function may also be

4 1 Field Circuit Breaker

protecting means, primarily frequent opening and closing of the /

used for a device, such as- a contactor, that is used in series with a circuit breaker or other fault

.

I I I 1 the non-availability of the normally 1

4 3

I Monitor

i atmospheric condition, such damaging fumes, explosive mixture,

Manual Transfer or Selector Device transfers

circuit. It transfers the control circuits so as to modify the plan of operation of the switching equipment or of some

4


of the devices. It is a device, which functions to start the next available unit in a multiple- unit equipment on the failure or on

1

I

I 46 1 ~e/erie-phase,

44

smoke or fire. l t i s a reiay which functions when the

Unit Sequence Starting Relay

1

APPS- CcmSined CGiiiSs Overview Of Protection Fundamentals

Page 1 7 of 0

4 7 It functions upon a predetermined value of poly phase voltage in the

Device Number

Volta e Rela Incomplete --j"- Sequence Relay

desired phase sequence. It is a relay that generally returns the equipment to the normal, .or off, position and locks it out i f the normal starting, operating or stopping sequence is not properly completed within a predetermined time. I f the device is used for alarm purpose

Definition Phase-Balance, Current Relay

I I I only, it should preferably be /

Function poly-phase currents are of reverse phase sequence, or when the poly- phclse currents me unbalaficzd oi contain negative phase-sequence cornponents above a given amount.

Transformer, Thermal Relay

I

49 / Machine, or

Instantaneous overcurrent, o i Rate of rise

, Relay -

designated as 48A {alarm). It i s a relay that functions when the temperature of a machine armature, or other load carrying winding or element of a machine, or the temperature of a power rectifier or power transformer (including a power rectifier transformer) exceeds an predetermined value. It is a relay that functions instantaneously on an excessive value of current, or on an excessive current rise, thus indicating a fault in the apparatus or circuit being ~rotected.

AC Time / It i s a relay with either a definile or Overcurrent Relay

an inverse time characterisiic l l m t functions when the current in an ac

( circuit exceeds a predetermined I value.

AC Circuit It is a device that is used to c:lose Breaker 1 and interrupt an ac power circuit

I under normal condilions or to

r


APPS- Combined course Overview Of Protec?bn Fundamentals

Page 20 of 0

Overcurrent / desired value of ac overcurrent ( Relay I flowing in a predetermined I

Device Number

6 7

for blocking of tripping on external faults in a transmission line or in other apparatus under predetermined

Definition

AC directional

1 68 1 Blocking Relay

conditions, or co-ordinates with other devices to block tripping or to

Function mechanical positioning. It i s a relay that functions on a

direction. It is a relay that initiates a pilot signal

block re-closing on an out-of-step ' - . , I condition or on powerswing:. 1

ermissive It i s - generally a two position, ! Control ~ev i ce ' manudlly operated switch that in

I one position permits the closing of a circuit breaker, or the placing of an equipment into operation, and in the other posilion prevents the circuit breaker or the equipment

I 1 I

1 Level switch

! 70 I Rheostat

used in an electric circuit, which is electrically operated or has other electrical accessories, such as auxiliary position or limit switches. It is a switch which operates on

from being operated. It i s a variable resistance device

I I

! I given values, or on a given rate of I 1

7 2 I DC circuit

i

OALSTOM Limited, inergy Automation & Informalion

change, of level. It is used to close and interrupt a dc

1 Breaker -

1 power circuit under normal conditions or to interrupt this circuit under fault or emergency conditions.

73 i Load - Resistor ' Contactor

1 I

I I

It is used to shunt or insert a step of load limiting, shifting, or indicating resistance in a power circuit, or to switch a space heater in circuit, or to switch a light, or regenerative load resistor of a power reclifier or


Page 21 of 0

1 Device Number Definition 1 Function other machine in and out of circuit.

Alarm ~ e b y It i s a device other than the annunciator, as covered under device No.30, which is used to operate in connection with a visual

that isused for Changing Mechanism

moving a muin device from one position to another inan equipment ;as . for example, shifting a removable circuit breaker unit to

1 and from the connected,

DC Overcurrent

1 77 / Pulse Transmitter 1 It i s used to generate and transmit I

disconnected, and test positions. It is a relay that functions when the

Relay

I pulses over a telemetering or pilot- / wire circuit to the remote indicating

current in a dc circuit exceeds a aiven value.

( out-of-ste-) Protective

-

i 78 Angle / ',","::ring, or between two voltages or between two currents or between voltage

or receiving device. It is a relay that funclions at a predetermined phase angle

that controls Relay automatic reclosing and locking out

8 0 Flow Switch It is a switch, which operates on

1 I 1 given values, or on a given rate of I

Relay

1 1 8 1 I ~iequency

predetermined value of frequency, either underlover on normal system frequency or rate of , change of

change, of flow. It is a relay that functions on a

1 I Relay - 1 automatic closing and reclosing of a (

1- 82

dc circuit interrupter, generally in resoonse to load circuit conditions.

- -


DC Re-closing frequency. 1

It is a relay that controls the

APPS- Combined course Overview Of Protec?i@r! Fundamentals

Page 20 of 0

Device Number 1 Definition Function I

1 67 1 AC directional

apparatus under predetermined conditions, or co-ordinates with

mechanical positioning. It is a relay that functions on a

/ Overcurrent ( Relay I

68 Blocking Relay I - I /

desired value of ac overcurrent flowing in a predetermined direction. It is a relay that initiates a pilot signal for blocking of tripping on external faults in a transmission line or in other

-

circuit breaker, or the placing of an equipment into operation, and in

!

! -

69 1 Permissive i Control Device

other devices to block tripping or to block re-closing on an out-of-step condition or on po\der swings: It is generally a two position, manually operated switch that in one position permits the closing of a

1 electrically operated or has other

I

I

70 I Rheostat

the other position prevents the circuit breaker or the equipment from being operated. It i s a variable resistance device used in an electric circuit, which i s

I -

- 7 1 i Level Switch

electrical accessories, such a: auxiliary position or limit switches. It is a switch which operates or

72 I DC circuit 1 Breaker - I

Contactor I I

given values, or on a given rate of change, of level. It is used to close power circuit under normal conditions or to interrupt this circuit under fault or emergency

7 3 : Load - Resistor load limiting, shifting, or indicating resistance in a power circuit, or to switch a space heater in circuit, or

conditions. It is used to shunt or insert a step of

OALSTOM Limited, inergy Automation & Information

1 i

to switch a light, or regenerative load resistor of a power rectifier or

i

OALSTOM Limited, Energy Automation & information

APPS- Combined course \

Overview Of Protection Fundamentals Page 21 of 0

Function other machine in and out of circuit. It is a device other than the annunciator, as covered under device No.30, which i s used io operate in connection with a visual or audible alarm. It is a mechanism that i s used for moving a main device from one position to another in an equipment ;as for example, shifting a removable circuit breaker unit to and from the connected, disconnected, and test posi lions. It is a relay that functions when the

1 1 i i ? I

Device Number

74

75

I

76

Definition

Alarm ~ e l a y

Position Changing Mechanism

DC 0ve:current current in a dc circuit exceeds a given value. It is used to generate and transmit pulses over a telemetering or pilot- wire circuit to the remote indicating or receiving device. It is a relay that functions at a predetermined phase angle between two voltages or between two currents or between voltage and current. It is a relay that controls the automatic reclosing and locking out of an ac circuit interrupter. It is a switch, which operates on given values, or on a given rate of change, of flow. It is a relay that functions or-) a predetermined value of frequency, e~ther underJover on normal system frequency or rate of change of frequency. It is a relay that controls automatic closing and reclosing of a dc circuit inter~upter, generally in response to load circuit conditions.

I i l

1 77 Pulse Transmitter I I

I 78 I Phase Angle

I Measuring, or I out-of-step I I Protective ' 79 Relay I AC Re-closing

, -

80

8 1

- 82

Relay

Flow Switch

~ t e q u e n c ~ Relay

DC Re-closing Relay

-


Page 24 oi 6

1 Device Number I Definition 1 Function ( to 94 i s suitable. I

8.2 Devices Performing ore Than One Function If one device performs two relatively important functions in an equipment so that it i s desirable to identify both of these functions, this may be done by using a double function number and name such as:

50/51 - Instantaneous and Time Overcurrent Relay.

8.3 SuffixNumbers If h.10 or more devices with the same function number and suffix letter (if used) are present in the same equipment, they rlay be distinguished by numbered suffixes as for example, 52X-1, 52X-2 and 52X-3, when necessary.

8.4 Suffix Letters Suffix letters are used with device function numbers for va~~ious purposes. In order to prevent possible conflict each suffix letter should have only one meaning in an individual equipment. All other words should use the abbreviations as contained in ANSI Y 1.1 latest revision, or should use some other distinctive abbreviation, or be written out in full each time they are used. The meaning of each single suffix letter, or combination of letters, should be clearly designated in the legend on the drawings or publications applying to the equipment.

Lower case (small) suffix letters are used in practically all instances on electrical diagrams for the auxiliary, position, and limit switches. Capital letters are generally used for all other suffix letters. Th,e letters should generally form part of the device function designation, are usually written directly after the device function number, as for example, 52CS. 71 W, or 49D. When it is necessary to use two types of suffix letters in connection with one function number, it is often desirable for clarity to separate them by a slanted line or'dash, as for example, 20D/CS or 2OD-CS. .

The suffix letters which denote parts of the main device, and those which cannot or need not form part of the device function designation, are generally written directly below the device function number on drawings, as for example, 52/CC or 43/A.

-

8.9 Standard reference positions of some typical devices



Page 250f 0 ,

Device Power Circuit Breaker Disconnecting Switch Load-break swiich - Valve Gate Clutch

Standard Reference Position Main Contacts Open Main Contacts Open Main Contacts Open Closed Posilion ) Closed Posilion Disengaged Position

Adjusting Means Position Relay (2)

1 Pressure Switch 131 I Lowest Pressure 1

Disengaged Position Maximum Gap Position

Rheostat - Maximum resistance Position

Contactor (21 Contactor (latched-in-type) Temperature Relay (3) Level Detector (3) Flow Detector (3) Speed Switch (3) Vibration Detector (3)

7

) Vacuum Switch (3) 1 Lowest Pressure i.e., Highest Vacuum Note : If several similar auxiliary switches are present on the same device, they should be

De-energised Position Mairi Contacts Open Lowest Temperature Lowest Level I Lowest Flow Lowest Speed Minimum Vibration

designated numerically 1.2.3 etc, when necessary.

( 1 ) 'These may be speed, voltage, current, load, or similar adjusting devices comprising rheostats, springs. levers, or other components for the purpose.

(2 ) These electrically operated devices are of the non-latched-in type, whose contact p,osition is dependent only upon the degree of energisation of the operating or restraining or holding coil or coils which may or may not be suitable for continuous energisation. The de-energised position of the device is that with all coils de- energised.

(3) The energising influences for these devices are considered to be, respectively, rising temperature, rising level, increasing flow, rising speed, increasing vibration, and increasing pressure.

The simple designation "a" or "b" is used in all cases where there is no need to adjust the contacts to change position at any particular point in the travel of the main device or where the part of the travel, where the contacts change position is of no significance in the control or operating scheme. Hence fhe "a" or "b" designations usually are sufficient for circuit breaker auxiliary switches.

OALSTOM Limited, Energy .4utomation & Information

I APPS- Combined course Overview Of Protection Fundamentals - .

Page 24 oi O

1 Device Number 1 Definition I Function to 94 is suitable.

8.2 Devices Performing ~ 6 r e Than One Funciion If one device performs two relatively important functions in an equipment so that it i s desirable to identify both of these functions, this may be done by using a double function number and name such as:

I 50151 - Instantaneous and Time Overcurrent Relay.

8.3 Suffix Numbers If two or more devices with the same-function number and suffix letter (if used) are present in the same equipment, they may be distinguished by numbered suffixes as for example, 52X-1, 52X-2 and 52X-3, when necessary.

8.4 Suffix Letters Suffix letters are used with device function numbers for various purposes. In order to prevent possible conflict each suffix letter should have only one meaning in an individual equipment. All other words should use the abbreviations as contained in ANSI Y 1 . l latest revision, or should use some other distinctive abbreviation, or be written out in full each time they are used. The meaning of each single suffix letter, or combination of letters, should be clearly designated in the legend on the drawings or publicalions applying to the equipment.

Lower case (small) suffix letters are used in practically all instances on electrical diagrams for the auxiliary, position, and limit switches. Capital letters are generally used for all other suffix letters. The letters should generally form part of the device function designation, are usually written directly after the device function number, as for example, 52CS, 71 W, or 490. When it is necessary to use two types of suffix letters in connection with one function number, it is often desirable for clarity to separate them by a slanted line or'das!?, as for example, 20DJCS or 20D-CS.

The suffix letters which denote parts of the main device, and those which cannot or need not form part of the device function designation, are generally written direcily below the device function number on drawings, as for example, 52lCC or 43lA.

-

8.9 Standard reference positions of some typical devices

i OALSTOM Limited, Energy ~utomatidn & Information

APPS- Combined course . . .- Overview Of Protection Fundamentals

Page 25 of 0

Device

I Clutch I

I Disengaged Position

Standard Reference Position

Valve Gate

7

Main Contacts Open Main Contacts Open Main Contacts Open Closed Position Closed Position

I Level Detector 131 ! Lowest Level 1

-

1 Vacuum Switch (3) 1 Lowest Pressure i.e., Highest Vacuum Note : If several similar auxiliary switches are present on the same device, they should be

Turning Gear Power Electrodes

Flow Detector (3) 1 Lowest Flow

designated numerically 1,2,3 etc, when necessary.

Disengaged 'Position Maximum Posi lion

Rheostat -

Adjusting Means ( 1 ) Relay (2) Contactor (2) Contactor (latched-in-type) Temperature Relay (3 )

Speed Switch (3)

( 1 ) These may be speed, voltage, current, load. or similar adjusting devices conlprising rheostats, springs, levers, or other components for the purpose.

Maximum resistance Posilion Low or Down Position De-energised position De-energised Position .

Main Contacts Open Lowest Temperature I

Lowest Speed

(2) These electrically operated devices are of the non-latched-in type, whose contact position is dependent only upon the degree of energisation of the operating or restraining or holding coil or coils which may or may not be suitable for continuous energisation. The de-energised position of the device is that with all coils de- energised.

(3) The energising influences for these devices are considered to be, respectively, rising temperature, rising level, increasing flow, rising speed, increasing vibration, and increasing pressure.

I

The simple designation "a" or "b" is used in all cases where there is no need to adjust the contacts to change position at any particular point in the travel of the main device or where the part of the travel, where the contacts change position is of no significance in the control or operating scheme. Hence fhe "a" or "b" designations usually are sufficient for circuit breaker auxiliary switches.

Vibration Detector (3) Pressure Switch (3)

OALSTOM Limited, Energy .4utomation & Informalion

-

I

Minimum Vibration Lowest Pressure

APPS- Corn bined course Overview Of Pr~:ec:Icn Fundamentals

Page 28 of 0

The following Chart gives a birds-eye view of the relay classifications based on technology.

I Relays I

1 Electromechanical 1

Analogue .-- -+ I Numerical I

TYPES OF PROTECTION

FUSES

The simplest form of overcurrent protection is the fuse. The fuse is capable of operating in less than 10ms for very large values of current, thus considerably limiting fault energy. However, it does have a number of disadvantages, namely;

Can be difficult to co-ordinate Its characteristic is fixed Needs replacing ioiiowing iauit ciearance Has limited sensitivity to earthfaults since it is rated above the full load current of the feeder Operation of single fuse results in a condition refereed to as single phasing. Single phasing .can be disastrous for rotating plant such as motors.

The fuse characteristic is split into two sections, the 'Pre-arcing Time' and the 'Arcing Time'. The addition of these times is referred to as the 'Total Operating Time'.

Fault

PRINCIPLE OF OVERCURRENT PROTEClION The purpose of overcurrent protection, as with other forms of protection, is to detect faults on a power system and as a result, initiate the opening of switchgear in order to isolate the faulty part of the system. The protection must thus be discriminative, that is to say it shall, as far as possible, select and isolate only the faulty part of the system leaving all other parts in normal operation.

Discrimination can be achieved by overcurrent, or by time, or by a combination of overcurrent and time.

DISCRIMINATION BY CURRENT Discrimination by current relies upon the fact that the fault curren't varies with the position of the fault. This variation is due to the impedance of various items of plant, such as cables and transformers, between the source and the fault. Relays throughout the system are set to operate at suitable values such that only the relay nearest to the fault operates. Relays which adopt this of operation are generally termed Instantaneous overcurrent relays. (Where the fault level does not vary greatly between two relay location then the use of ins tantane~s overcurrent relays is not possible). DISCRIMINATION BY TIME

Page 1

. - : If the fault level over a system is reasonably constant then discrimination by current will not be possible. An alternatlile Is tc use time discrimination in which each overcurrent relay is given a fixed ?irr?e delay with the relay farthest away from the source having the shortest time delay. Operating time is thus substantially,independent of fault level but the main disadvantage is that the relay nearest the source will have the longest time delay and this is the point with the highest fault level. Relays which adopt this principle of operation are generally termed definite (independent) time overcurrent relays. NOTE : When applying definite time overcurrent relays care must be taken to ensure

that the thermal rating of the current measuring element is not exceeded.

(Relay Current Setting)

D1SCRIMlNATlON BY BOTH TlME AND CURRENT Due to the limitat~ons imposed by the independent use of either t~me or current, the

, inverse time overcurrent characteristic has been developed. With this character~st~c the time of operation is inversely proportional to the current applied, i.e.; basically the higher the current applied, the faster the relay operates. Thus, the actual characteristic IS a function of both t~me and current settings, thereby gaining the advantages of the previous mentioned methods and eliminating some the disadvantages.

TlME

IS Applied Current' (Relay Current Setting)

PRINCIPLES OF CO-ORDINATION The principle of co-ordination refers to the procedure of setting overcurrent relays to ensure that the relay nearest the fault operates first and all other relays have adequate additional time to prevent them from operating. If the relay nearest fo the fault fails to clear the fault, and the co-ordination is correct, then the next up-stream relay should operate and so on towards the source, thus isolating the minimum amount of plant. The principle of co-ordination is often referred to as 'grading'. When performing any co-ordination exercise the following need to be considered:

Relay Characteristics -

Relay Current Setting Grading Margin Time Multiplier Setting

Relay Characteristics There are numerous characteristics, however they all confirm to either BS142lIEC or ANSIIIEEE standards. The BS142lIEC standard incorporates the following characteristics.

Standard Inverse Very lnverse Extremely Irlverse Long Time Inverse

The ANSIIIEEE standard incorporates the following characteristics: Moderately Inverse-

- Very lnverse Extremely lnverse Short Time lnverse Inverse

The BS142lIEC standard curves are mainly adopted in the LIK and the most commonly used ones are explained in more detail below:

Standard lnverse - This characteristic is commonly known as the 3110 characteristic, i.e. at ten times setting current and TMS of 1 the relay will operate in 3 secs.

The characteristic curve can be defined by the mathematical expression :

where I - - applied current -

15 - setting current

111, - - multiple of setting current

The standard inverse time characteristic is widely applied at all system voltages -as back up protection on EHV systems and as the main protection on HV and MV distribution systems.

I '

In general, the standard inverse characteristics are used when

There are no co-ordination requirements with other types of protective equipm2nt further out on the system, e.g. Fuses, thermal characteristics of transformers, motors etc.

The fault levels at the near and far ends of the system do not vary significantly.

Page 3

There is minimal inrush on cold load pick up. Cold load inrush is that cuient which occurs when a feeder is energised after a prolonged outage. In general the relay cannot be set above this value but the current should decrease below the relay setting before the relay operates.

Very lnverse Time - This type of characteristic is normally used to obtain greater time selectivity when the limiting overall time factor is very low, and the fault current at any point does not vary tno :vlde!y with system conditions. It is particularly suitable, if there is a substantial reduction of fault current as the distance from the power source increases. The steeper inverse curve gives tonger time grading intervals. Its operating time is approximately doubled for a reduction in setting from figures 7 to 4 times the relay current setting. This permits the same time multiplier setting for several relays in series.

The characteristic curve can be defined by the mathematical expression : 13.5 t = --

{i: - I] Extremely lnverse Time - With this characteristic the operating time is approximately inversely proportional to the square of the current. The long operating time of the relay at peak values of load current make the relay particularly suitable for grading with fuses and also for protection of feeders which are subject to peak currents on switching in, such as feeders supplying refrigerators, pumps, water heaters etc., which remain connected even after a prolonged interruption of supply.

For cases where the generation is practically constant and discrimination with low tripping times is difficult to obtain, because of the low impedance per line section, an extremely inverse relay can be very useful since only a small difference of current is necessary to obtain an adequate time difference.

-

Another application for this relay is with auto reclosers in low vo'ltage distribution circuits. As the majority of faults are of a transient nature, the relay is set to operate before the normal operating time of the fuse: thus preventing perhaps unnecessary blowing of the fuse.

Upon reclosure, if the fault persists, the recloser locks itself in the closed posjtion and allows the fuse to blow to clear the fault.

This characteristic is also widely used for protecting plant against overheating since overheating is usually an I,t function.

Page 4

This characteristic curve can be defined by the mathematical expression :

t = 80

{ti' - bong Time Inverse - This type of characteristic has a long time characteristic and may be used for protection of neutral earthing resistors (which normally have a 30 sec rating). The relay operating time at 5 times current setting is 30 secs at TMS of 1.

This can be defined by :

- Current Setting The current setting of a relay is typically described aS either a percentage or multiple of the current transformer primary or secondary rating. If the CT primary rating is equal to the normal full load current of the circuit then the percentage setting will refer directly to the primary system. This is an important point as if, for example, the normal primary full load current was, say, 400 amp but the CT ratio was 50015 then a relay with setting range 50-200% of 5 amp set at 100% would not represent a "full load" setting;-the actual setting would in fact be 125% of full load current. The choice of current setting thus depends on the load current and the CT ratio and is normally close to but above the maximum load current (typically'lO%) - assuming of course the circuit is capable of carrying the maximum foreseeable load. It should be stressed at this point, that the relay is neither designed nor intended to be used as an overload relay but as a protective relay to protect the system under fault conditions. It is also important to consider the resetting of the relay. The relay will reset when the current is reduced to 90%-95% of the setting (Depending on relay design) and if the normal load current is above this value the relay will not reset after starting to operate under through fault conditions which are cleared by other switchgear. The setting for a typical overcurrent relay with a reset ratio of 95% can be determined using the following:

Where: Is = Setting IF^ = Full Load Current

Grading Margin As previously mentioned, to obtain correct discrimination it is necessary to have a time interval between the operation of two adjacent relays. This time interval or grading margin depends upon a number of factors :

a) The circuit breaker fault interrupting time b) The overshoot time of the relay C) Errors d) Final margin on completion of operation (safety margin) The discriminating relay can only be de-energised when the circuit breaker has completely interrupted the fault current. It is now normal practice to use a value of 50 -

Page !

100 ms for circuit breaker overall interrupting time but obviously if it is known that the switchgear is slower than this time, this must be taken..injo account.-

Operating of the relay may continue for a short time after the relay is de-energised until a n i stored energy is dissipated. For example, an induction disc 'element will have stored kinetic energy (or inertia) and a numerical relay may have stored energy in capacitors. Although these factors are minimised by design, some allowance is usually necessary. It is common to use a figure of 50 ms.

NO-TE : The overshoot time is not the actual time during which some forward operation takes plan but is the time that the relay would have taken to travel the same distance had the relay remained energised.

Travel I looO/o

Overshoot Travel t l = relay de-energised

t3 - t l = actual overshoot time t2 - t l = overshoot time used in the

calculation of margin

t l t2 t3

All measuring dev~ces such as rejays and current transformers are subject to some degree of error The t~me characteristic of either or both of the relays involved may have positive or negat~ve errors. Current transformer errors are mainly due to the rnagnetis~ng characteristic. It should be noted the CT errors do not affect definite time overcurrent relays.

A safety margin of 100 ms is normally added to the final calculated margin to ensure correct discrirn~nation. This additional time ensures a satisfactory contact gap (or equivalent) is maintained.

In the past, a fixed margin of 0-4 secs was considered adequate for correct discrimination. With faster modern switchgear and lower overshoot times a figure of 0.35 secs is quite reasonable and under the best possible conditions 0-3 secs may be feasible.

However, rather than using a fixed margin it is better to adopt a fixed time for circuit breaker operation and relay overshoot and add to this a variable time value which takes into account relay and CT errors and the safety margin. This is particularly so when grading at low values multiples of setting current where the relay operating time is longer and a fixed total margin may be of the same order as the relay timing error.

A fixed value 0-25 secs is chosen which is made up of 0.1 secs for circuit breaker operating time. 0.05 secs for relay overshoot time and 0.1 sec for safety margin.

In considering the variable time value, it is assumed that each IDMT relay complies with basic assigned error class 7.5 according to British practice in BS 142. The error for a class 7.5 relay IS 5 7.5%, but allowance should be made for the effects of temperature, frequency and departure from the reference conditions as laid down in the BS. A more practical approximation is to assume a total effective error of 2 x 7-5 i.e. 15% and is to apbly to the relay nearest the fault which'is considered slow. To this total effective relay error a further 10% is added to allow for overall CT error.

Page 6

Thus it is proposed to adopt the following equstior: t:, determine the grading margin between IDMT relays :

t' = 0.25 + 0-25 secs where t = 'normal operating time of relay nearest the fault

As far as definite time overcurrent relays are concerned, the fixed value will remain the same but the relays are assumed to comply with error class 10 i.e. + 10%. For the reasons stated .previously, a practical approximation is to assume a total effective error of 20% with the relay nearest the fault considered slow. As previously stated, CT errors will have little effect of the operating time, thus it is proposed to adopt the equation :

I t' - - 0.25 + 0.25 secs

For the majority of systems an overcurrent grading exercise can be performed quite adequately using a fixed margin of 0.4 secs. It is only when a number of stages are involved and difficulties are being encountered that it may become necessary to invmtigate margin times in more detail. To summarise, each system is different and should be treated as so, it is not possible to lay down rigid rules regarding grading

I margins and every grading exercise will ultimately be a compromise of some form.

Grading Overcurrent Relays With Downstream Fuse For some applications ~t will be necessary to grade overcurrent relays with fuses. When the fuse is downstream of the relay the following formula can be used to calculate the grading margin.

- 1 Grading Margin = 0.4Tf + 0.1 5s over the whole characteristic.

I The above formula assumes a minimum fuse operating time of 0.01 seconds

Generally for this type of application a Extremely Inverse characteristic should be chosen to grade with the fuse and the current setting of the relay should be 3 - 4 x rating of fuse to ensure co-ordination.

Time Multiplier Setting The time multiplier setting is a means of adjusting the operating time of an inverse type characteristic. It is not a time setting but a multiplier. In order to calculate the required TMS (Treq), calculate the operating time of the'nearest downstream protection device at the maximum fault level seen by both devices, add to this the grading margin, calculate the operating time of the upstream device at this fault level with a TMS equal to one (TI) and then use the following for formula:

I TMS = Treq 1 T I

Page ";

;:,

Plotting Of Characteristic It is convenient to show the standard inverse time characteristic on logllog graph paper with the 'y' axis scaled in seconds and the"x' axis in terms of "multiples of current setting". By doing this the characteristic can be applied to any relay, irrespective of setting range and nominal rating.

i *

HIGH SET OVERCURRENT -

Where the source impedance is small in comparison with the protected circ~lit.i.mped.ance, . . - . the use of high set instantaneous overcurrent units can be advantageous (for example on long transmission lines or transformer feeders).

I The application of an instantaneous unit makes possible a reduction in the tripping time at i high fault levels and also allows the discriminating curves behind the high set unit to be !

f f:

lowered thereby improving overall system grading. i i is important io note iiiai when grading with the relay immediately behind the high set units, the grading interval should be established at the current setting of the high set unit .and not at the maximum fault level that would normally be used for grading IDMT relays.

When using high set units it is important to ensure that the relay does not operate for faults outside the protected section. The relays are normally set at 1.2 - 1.3 times the maximum fault level at the remote end of the protected section.

.This particularly applies when using instantaneous units on the HV side of a transformer when the instantaneous unit should not operate for faults on the LV side. ,

The 1-2 - 1.3 factor allows for transient overreach, CT errors and slight errors in .' transformer impedance and line length.

Transient overreach occurs when the current wave contains a dc component. Although a relay may have a setting above the rms value of current, the initial peak value of current due to the dc offset may be sufficient to operate the relay, if it has high transient overreach.

Percentage transient overreach is defined as 11-12 x ?OO 12

Where :

I1 = relay pick-up current in steady state rms amps 12 = rms value of current which when fully offset will just pick up the relay

Modern Relays have integral instantaneous elements which have low transient overreach. The degree of transient overreach is normally affected by the time constant of the measured fault current. For example, a typical transient overreacn of a numerical overcurrent relay is less than 5% for time constants up to 30 ms and less than 10% for t~me constant up to 100 ms. This allows the instantaneous elements to be used as h~gh set un~ts for application to transformers and long feeders. The low'transient overreach allows settings to be just above the maximum fault current at which discrimination IS

required. The instantaneous elements are also suitable for use as low set elements in conlunction with auto-reclose on distribution systems

EARTH FAULT PROTECTION

Earth faults, which are by far the most frequent type of fault, will be detected by phase overcurrent units as previously described but it is possible to obtain more sensitive protection by utilising a relay which responds only to the residual current in a system. Residual (or zero sequence) current only exists when a current flows to earth.

The residual current can be detected either by connecting a CT in an available neutral to earth connection or by connecting Ilne CT's in parallel. By using this parallel connection the earth fault relay is completely unaffected by load currents whether balanced or unbalanced. The parallel connection can be extended to include either two or three

Page 8

overcurrent units without any effect on the earth fault relay. Two elements are often considered sufficient 2s any interphase fault must affect at least one of the relays, however, consideration must be given to the possibility of 2-1-1 current distribution in the system (refer deltalstar transformer protection).

It should be noted that on an LV 4 wire distribution system, 4 CT's will be required to ensure stability under all load conditions, the 4th CT being placed in the neutral connection. This fourth CT can be omitted if the earth fault relay setting is above the maximum spill current caused by unbalanced loads, but as the degree of unbalance is not riorii~aiiy kiiowii (accilrately) the inclusion of the 4th CT is recommended.

Time Grading

The procedure for grading is similar to that for phase fault relays.

It is important to appreciate that fuses cannot discriminate between phase faults and earth faults and therefore grading of earth fault relays (which have relatively sensitive settings) with fuses is not possible.

When the system contains some neutral earthing impedance, the earth fault level is practically constant over the whole system and grading is carried out at !his fault level. As the fault level is consJant there is no particulai advantage is using IDMT earth fault relays over definite time earth fault relays.

Sensitive Earth Fault Relays

Where the earth path resistivity is high which may be the case on systems that do not utilise earth conductors, the earth fault current may be limited to such an extent that normal earth fault protection may not be sensitive enough. To overcome these problems a very sensitive relay is requirgd, but the relay must have a very low burden in order that the effective setting is not increased. This very sensitive protection cannot be graded with other conventional systems and it is normal to apply this protection with a definite time delay of up to 10 or 15 secs. This time delay will prevent unwanted operation due to transient unbalance under phase fault conditions. Care must be taken to ensure that the relay setting is above any residual current that may be present under normal load conditions. This may be due to slight d~fferences in CT characteristics or unbalanced leakage (capacitive) currents in the primary system. In order to ensure that the relay will reset after the transient operation of the current measuring unit, the dolpu ratio should be high, i.e.. approximately 99%.

IN'TERCONNECTED SYSTEMS

The foregoing has basically looked at grading procedure as applied to radial feeders. If the system is interconnected and involves parallel paths and rings, the grading can become increasingly more complex.

For example, the operation of a particular circuit breaker may not itself result in the isolation of the faulty plant, but may affect the fault current distribution in the other circuits. The affect of this may be to start other relays operating or to change the operating parameters of relays that havealready started. On such interconnected systems the fault level does not tend to vary very much and it may be found impossible to obtain correct discrimination for all faults. The system must be looked at in detail under maximum and minimum fault conditions and the best compromise reached. Very often directional overcurrent relaying can help to overcome the problems slightly.

Page 9

Directional Overcurrent

GiRECTiGNAL OVERCURRENT RELAYS

If fault current can flow in both directions through the relay location it is necessary to add directional properties to the overcurrent relays in order to obtain correct discrimination. Directional protection is commonly applied in two areas, namely, parallel feeders(transf0rmers) and ring mains.

RING MAINS -

The more usual application of directional relays is to ring mains. In the case of a ring system, fed at one point only the relays at the generafion end and at the mid-point substation, where the setting of both overcurrent relays are identical, the relays can be made non-directional, provided that in the latter case the relays are located on the same feeder, one at each substation. In this respect it is interesting to note that when the numbers of feeders in the rings is an even number, the two relays with the shme operating time are at the same substation and.will have to be directional whereas when the number of feeders is odd, the two relays. with the same operating time are at different substations and therefore, do not need'to be directional. Also at intermediate substations it will be noted that whenever the times of the two relays at a substation are different, the difference in operating time is never less than the grading interval of 0-4 seconds and consequently it is permissible for the relay with the larger operating time to be non-directional.

Grading Ring Mains

The usual practice for grading relays in an interconnected system is to open the ring at the supply point and to grade the relays first clockwise and then anti-clockwise. Thus, the relays looking in a clockwise direction around the ring are arranged to trip in the sequence 1 - 2 - 3 - 4 - 5 -3 and the relays looking in the anti-clockwise direction are arranged to trip in the sequence 1' - 2' - 3' - 4' - 5' - 6'. The arrows indicate the direction in which the power must flow in order that the directional units will close their contacts and prepare the overcurrent elements for operation. The double headed arrows on each of the two ieeders at the generating station indicate non-directional relays, directional features being unnecessary at these points, because power can flow in one direction only, that is out of the generating station. At all other points s~ngle headed arrows are shown. These ind~cate direct~onal relays connected so as to operate with power flow in the direction of the arrow which is in every case from the substat~on bus bars and into the protected line. See Figure 1.

This rule is invariable and applies to all forms of directional relays. Selection of the faulty section is by time and fault power direction. Fault power has two phases x and y. It divides between the two paths in the inverse ratio of the impedances an.d passes through all the substations in the ring. Thus, at every substation one set of relays will be inoperative because the power flow is against the arrow and other set operative because the flow is with the arrow. In every case it will be found that the time settings of the relays that are inoperative are shorter than those of the operative relays, except in the case of substation C where the settings happened to coincide. In this way, all relays with short time on sections between the fault one and the generating station are prevented from operation. The others, which are operative are graded downwards towards the fault and the last to be traversed by the fault current, namely that on the faulty feeder section, has the shortest time and operates first. This applies to both paths to the fault. Consequently, the faulty sectioh is the only one to be isolated and supply is maintained to all substations.

Page 1

Grading Ring Mains With More Than One Source

When grading ring systems with more than one infeed (say two sources of supply) the best method of approach is to either :

a) Open the ring at one the supply points by means of a suitable high set instantaneous overcurrent relays and then proceed to grade the ring as in the case of a single infeed.

b) Treat the inter-connector between the two sources of supply as a continuous bus, separate from the ring and protect it by means of a unit system of protection such as pilot wire relays. Then proceed to grade the ring as in the case of a single infeed.

PARALLEL FEEDERS -

If non-directional overcurrent relays are applied to parallel feeders any faults occurring on any one line will inevitably, irrespective of the relay setting chosen, isolate both lines and completely disrupt the supply. To ensure discriminative operation of the relays during line faults, it is usual with this type of system to design and connect relays Rq' and R2' such that they will only operate for faults occurring on the protected line in the direction indicated by the arrows. See Figure 2. With parallel feeders to ensure correct discrimination during line faults, it is important that the correct direct~onal relay R1' or R2' operates before the non-d~rectional relays Rq and R2. For this reason relays R1' and R2' are given lower time settings than relays R1 and R2 and also lower current settings. The usual practice is to set relays Rq' and R2' to 50% of the normal full load of the circuit (ensure that the relays are capable of carrying without damage, twice their setting current continuously), operating with an IOMT characteristic with a TMS 4.0

Care should be taken when using definite time relays. For such applications the directional relays should be set above full load current to prevent them operating due to load current reversal as a result of a phase to phase fault on the other side of the transformer.

ESTABLISING DIRECTION -

The direction of alternating current can only be determined with respect to a common reference. In relay terms, the reference is commonly referred to as the polarising quantity. The most convenient reference quantity is polarising voltage taken from the power system voltages.

The relay compares the power system current against this fixed polarising reference to determine direction of operation.

RELAY CHARACTERISTIC ANGLE (RCA)

This is a setting on the relay and is defined as the angle by which the current applied to the relay must be displaced from the voltage applied to the relay to produce maximum sensitivity.

Page 2 -

RELAY CONNECTIONS

This is the angle by which the current applied to the relay is displaced from the voltage applied to the relay at unity power factor.

The 90" connection (quadrature connection) is now used for all overcurrent relays. n

30" and 60" connections were used in the past, but no longer, as the 90" conneciion gives better performance. The 90" connection is achieved by using IA and VBC. Hence, for an A phase fault the polarising voltage does not collapse. Without a polaring voltage most relays are unable to make a directional decision. Modern numerical relays are able to use prefault data to make a decision, a technique referred to as memory .polarising.

90" Connection - 45" RCA

The 'a' phase relay is supplied with la current and Vbc volts displaced 45" in an anti- clockwise direction. ln-this case the relay maximum sensitivity is produced when the current lags the system phase to neutral voltage by 45". This connection gives a correct directional tripping zone over the range of current 45" leading to 135" lagging See Figure 3.

TYPICAL RCA SETTINGS

A relay designed for quadrature connection and having an RCA of 30" is recommended when the relay is being used for the protection of plain feeders with zero sequence source behind the relaying point.

In the case of transformer feeders or feeders which have a zero sequence source in front of the relay, a quadrature connected relay is recommended but it is preferable when protecting this type of feeder that the directional relay is designed to have an RCA 45".

An RCA 45" is necessary in transformers and transformer feeders, to ensure correct relay operation for faults beyond the starldelta transformer.

'Three fault conditions may theoretically cause mal-operation of the directional relay. They are phase to phase to ground on a plain feeder; phase to ground fault on -a transformer feTdmwlththezero sequence s o u r c e ~ l n f r o n t o t t h e l a ~ p h W t t o phase fault on a transformer with the relay looking into the delta winding of the transformer.

DIRECTIONAL EARTH FAULT RELAYS -

These relays are similar in construction to the overcurrent relays but are polarised by residual voltage or current. The polarising voltage is obtained from the secondary of a three phase voltage transformer connected in broken delta. It is essential to ensure that the correct voltage is fed to the relay that the voltage transformer primary neutral is earthed and that it be a three phase, five limb type or consist of three single phase units. Current polarisation is normally obtained by connecting a current transformer in a local jransformer neutral. If voltage polarisation is used a 45" RCA is normally used for solidly earthed systems and 0" for resistance earthed systems.

Page 3

Voltage Polarised Earth Fault Relays

Some care is necessary when using voltage polarised relays on solidly earthed systems, as the residual voltage under single phase to earth fault conditions will be equal to the phase to neutral voltage at the fault location or a sol~d earth fault only. Any line impedance between the fault point and the relay, or resistance in the fault itself will tend to reduce the value of the voltage and it can be very small if the line impedance between the fault point and the relaying point is large compared with the source impedance behind the relay. With modern directional relays however, which will operate down to 1 O/O of normal voltage, no trouble should be experienced. -

Current Polarised Earth Fault Relays

As already mentioned, current polarised relays may be polarised by a current transformer connected in the power transformer neutral Only certa~n types of power transformers however, are suitable as sources of polarising current, as in some the direction of the current in the neutral can reverse*depending upon the fault position and the ratio of system zero sequence impedances.

A staristar power transformer is not suitable for polarising relays even if both star points are earthed. A current transformer in one neutral would not be suitable as the current would reverse depending upon which side of the transformer the fault is on. Paralleling two current transformers, one in each neutral connection, will not be satisfactory as the resultant current would zero.

Three winding or two winding power transformers with one winding delta connected are suitable for relay polarisation. Provided the star point is earthed, then a current transformer in th~s neutral can be used to supply the relay. In the case of three winding transformers, if two star connected windings have the star point earthed, then current transformers in each neutral connected in parallel must be used having ratios inversely proport~onal to the power transformers voltage ratio. An alternative to this is to use one current transfomer within the delta winding provided that no load is taken from the delta. If load is taken from the delta winding it is necessary to use a current transformer in each leg of the delta to prevent unbalanced load or fault current producing incorrect polarising current.

Dual Polarised Earth Fault Relays

As the polarising current for current polarised earth fault relays is taken from a current transformer in a local power transformer neutral, this may be lost if the particular transformer is switched out of service and for this reason voltage polarisation is in general more reliable. However, as pointed out, in solidly earthed systems where the zero sequence source impedance is small the value of the residual voltage can be very low and dual polarised relays, with both current and voltage are used. It should be noted, however, that with modern relays the possibility of voltage polarised relays failing to operate is very remote and that for all practical conditions this possibility can in general be ignored.

Page 4

The operation of earth fault indication relays on systems earthed through a Petersen Coil or totally insulated system is dependent on the capacitive current flowing in the healthy feeders and when a Petersen Coil is used on the current due to the suppression coil flowing in the faulty phase.

In the case of overhead lines the majority of earth faults are of a transient nature and it is preferred that these faults shall not lead to automatic isolation of the faulty line. It is desirable, however, that an indication should be given of sustained system faults in order that the system may be supervised continuously and so that the faulty section of the network is indicated.

For detection of a system earth fault, a sensitive directional relay or wattmetric relay is used (Petersen Cod Systems)

Petersen Coil Earthed System

The diagram in Figure 4 shows asystem 0-f radial feeders, with a phase to ground fault on the 'C' phase of one of the feeders. No current will flow in the 'C' phase of the healthy feeders as they will be at earth potential. Capacative current will flow in the healthy phases of all feeders to earth and back to the source via the fault. The vector sum of the currents- in the current coil of the relay on the faulty feeder Is is

1 proportional to :

':I Where :

The vector diagram of the currents in the sound phases'shows that the total wattage component of the currents in the restraining quadrant, hence the relays on the healthy feeders will not operate. However, the current in the faulty feeder show that the wattage component of the currents' is in the operating quadrant and hence, the relay in the faulty feeder will operate.

The current transformers are of a special design, class 0.2, having an exceptionally 1 low phase angle error and because of this cannot be balanced accurately for currents

I greatly in excess of rated current. The relay is provided with 0" MTA.

I Insulated System

The diagram in Figure 5 shows a system of radial feeders, with a phase to ground fault on the 'C' phase of one of the feeders. The residual current flowing in the current coil of the relay on the faulty feeder, neglecting the effect of magnetising current, is proportional to the 2 lc where lc is the vector sum of the currents in the healthy phases Ica and Icb. Since the system is an insulated one, the fault has the effect of raising the neutral point of the system by a voltage equivalent to the phase voltage and the voltages'of the healthy feeders by A .

I The relay is provided with a 90" leading MTA.

Page 5

FIGURE I RING MAIN OVERCURRENT PROTECTION

Page 6 . :.

FIGLIRE 2 RING MAIN OVERCURRENT PROTECTION

UNITY P.F.

+ZERO P.F.

ZERO SEN - -

LINE

FIGURE 3 90" CONNECTION 45O RCA

i

SITIWTY

I . .

Page 8

a b c

I

Location of CT's

dB

Source i

dB

d

T I I

Faulty Feeder

FIGLIRE 4

I Restrain

Operate

i b

D 4

B

Healthy Feeders

d

D 4

0 d

0

I +La

1 +lcb w

4

b I T

1 c T . - A - - - - - ) . - -

I + lca

I + Icb w I

D 4

I

T I I

D I

1c I

- - \------+--, I 1

I I ----) 1 ca

I I c b w. I I

B I

T 1. I - I I I I I I .. c 7 21, / - - 1-1- -+-

a b c

~ o c a t i i n CT'S

Faulty Feeder

t vRE

~ V R E . AVRE

/ /

/ '

Restrain +

k A #

- = -21, . RCA 1 RCA

+Operate Restrain 4 a +Operate

'VPO + VPO FIGURE 5

ction Notes

Power transformer is one of the most important links in a power system. Its development stems from the early days of electromagnetic induction, when it was discovered that varying magnetic flux in an iron core linking two coils produces an inducted voltage. From the basic discovery has evolved the power transformer we know today using advanced insulation materials and having complex windings on a laminated core using special magnetic steels cold rolled to ensure grain orientation for low loss and high operating density.

With transformers of large capacity, a single transformer fault can cause large interruption to power supplies. If faulted transformer is not isolated quickly, this can cause serious damage and also power system stability problems. Protective systems applied to transformers thus play a vital role in the economics and operation of a power system.

In common with other electrical plants, choice of suitable protection is governed by economic considerations brought more into prominence by the range of size of transformers which is wider than for most items of electrical plant. Transformers used in distribution and transmission range from a few KVA to several hundred MVA.

Fo( transformers of the lower ;stings, only the simplest protection such as fuses can be justified and for large rating transformers; comprehensive protection scheme should be applied.

1 TRANSFORMER FAULT CATEGORIES

I Transformer faults are generally classified into four categories :

I i) Winding and terminal faults ii) Core faults iii) Abnormal operating conditions such as overvoltage, overfluxing and overload iv) Sustained or uncleared external faults.

I TRANSFORMER CONNECTIONS

With tlie development of polyphase systems with more complex transformer winding connections and also possible phase displacement between primary and secondary windings, standardisation was necessary to ensure universal compatibility. (BS171 : 1970)

There are a number of possible transformer connections but the more common connections are divided into four main groups :

Group 1 0; Phase displacement e.g. Yyo Ddo Zdo

Group 2 180.. Phase displacement e.g. Yd6 Dd6 026

Group 3 30" lag Phase displacement e.g. Yd l D Y ~ Yz1

Group 4 30' lead Phase displacement e.g. Y d l l D y l l Yz l 1

High voltage windings are indicated by capital letters and low voitage windings by small letters (reference to high and low is relative). The numbers refer to positions on a clock face and

Page 1

indicate the phase displacement of the low voltage phase to neutral vector with respect to the high voltage phase to neutral vector, eg Ydl indicates that the low voltage phase vectors lag the high voltage phase vectors by 30" (-30" phase shift).

Individual phases are indicated by the letters A, B and C, again capital letters for the high voltage winding and small letters for the low voltage winding. All windings on the same limb of a core are given the same letter. A further numerical subscript serves to differentiate between each end of the winding.

8

Determination of Transformer Connections

, ! i

This is best illustrated by considering a particular example. The following points should be !- noted:

a) The line connections are normally made to the end of the winding which carries the subscript 2, ie : A2, 62, C2 and a2, b2, c2.

b) The line terminal designation (both letter and subscript) are the same as those of the phase windins to wh~ch thc line terminal is connected.

Consider the connection Yd1

i) Draw the primary and secondary phase to neutral vectors showing the required phase displacemed :

Phase rotation

T

Primary

Phase rotation

4-

b Secondary

ii) . Complete the delta winding connection on the secondary side and indicate the respective vector directions :

C A B 4 \ . . . 111) It is now possible to indicate the winding subscript numbers bearing in mind t-hh i f

the direction of induced voltage in the high voltage winding at a given instant is Crom A1 to A2 (or vice verse) then the direction of the induced voltage in the low voliage winding at the same instant will also be from a1 to a2.

Page 2

I -

. .

iv) It can now be seen'that the delta connection should be made by connxting a2 to c l , b2 to a1 and c2 to b l :

OVERCURRENT PROTECTION

I Fuses

Small distribution transformers are commonly protected only by fuses. In many cases no circu~t breaker is provided, making fuse protection the only available means of automatic isolation. Fuses are overcurrent devices, and must have ratings well above the maximum transformer load current in order to carry, without blowing, the short duration overloads that may occur because of such as motor starting. Also the fuse must withstand the magnetising inrush of the transformer. It follows that fuses will do little to protect the transformer, serving only to protect the system by disconnecting a faulty transformer after the fault has reached an advanced stage

( Overcurrent Relays

Overcurrent relays are often the only form of protection applied to small transformers. They are used for backup protection for larger transformers and both instantaneous and time delayed overcurrent can be applied.

Inverse time relays on the HV side of a transformer must grade with those on the LV side which in turn must grade with the LV outgoing circuits. Due to this, the HV overcurrent relays could have operating times which might cause operation of relays at other substations. To overco-me this problem, high set instantaneous overcurrent relays with low transient overreach are sometimes used. The settings of these relays should be 120-1 3O0/0 of the through fault level of the transformer to ensure that the relays are

Page 3 . .

~. ~~ .

stable for through faults. Care must also be taken to ensure that the relays do not operate under magnetising inrush conditions.

DIFFERENTIAL PROTECTION

The function of differential protection is to provide faster and more discriminative phase fault protection than that obtainable from simple overcurrent relays. Overall differential protection may only be justified for larger transformers( Typically >5MVA).

CTs on the HV side are balanced against'CTs on the LV side. There are a number of different connections but there are some important points that are applicable to all schemes.

Transformer Connection

Consider a deltalstar transformer. An external earth fault on the star side will result in zero sequence current flowing in the line but due to the effect of the delta winding there will be no zero sequence current in the line associated with the delta winding. In order to ensure stability of the protection this zero sequence current must be eliminated from the secondary connections on the star side of the transformer, ie the CTs on the star side of the transformer should be connected in delta. With the CTs on the delta side of the transformer connected in star, the 30" phase shift across the transformer is also catered for.

Since the majorlty of faults are caused by flashovers at the transformer bushings, it is advantageous to locate the CTs in the adjacent switchgear.

Interposing CT (ICT)

Where it is not possible to correct for zero sequence current and the phase shift across the transformer by using delta connected line CT's on the star side of the transformer, or were CT ratio mismatch exists between primary and secondary CT's, then interposing CT's are used. Tranditional ICT's were external devices, however modern numerical relays are able to account for ratio error, phase shift and zero sequence current within the relay. This eliminates the use of external ICT's and allows the protection to be set up and installed more easily.

General Rules for CT Connections

CT connections opposite to main-transformer :

ie. star CTs on delta side delta CTs on star side

If similar primary terminals ie PI or P2 are towards the transformer, then delta and star connection for the CTs should be the same as the transformer (or 180" opposite).

It is usual to assume that if current flows from P i --+ P2 then the secondary current will flow from S2 -+ SI.

Note :If the transformer induced voltage is A1 --+ A2 then the secondary induced voltage will be a1 -+ a2. Therefor?, current flo'w will be A1 --+ A2 and a2 -+ a1

Page 4 I

Tap Changers

Any differential scheme can only be balanced at one point and it is usual to choose CT ratios that match at the mid point of the tap range. Note that this might not necessarily be the normal rated voltage. For example, if the tapping range is +1O0h, -20% then the CT ratio should be based on a current corresponding to the -5% tap. The theoretical maximum out of balance in the differential circuit is then +_ 15%.

Three Winding Transformers

Differential protection of three winding transformers is essentially similar to that of two winding transformers. The same rules regarding CT connections still apply but the CT ratios used shpuld be based on the MVA rating of one of the windings (usually the highest rated winding) and not on the ratings of each individual winding.

For example, consider a 13213311 'I kV transformer with windings rated for 100/60/40 MVA respectively, then the current transformer ratios at all voltage levels should be based on 100 MVA, ie 44011. 176011 and 528011 respectively (these effective ratios are normally obtained by the use of interposing CTs which means that, for example, all the main CTs associated with the 11 kV system can be made equal to 200011 - rated current).

If there is a source associated with only one of the transformer windings, then a relay with only two bias coils can be used.- the CTs associated with the other two windings being connected in parallel. If there is more than one source of supply then it is necessary to use a relay with three bias windings in order to ensure that bias is available under all external fault conditions.

Page 5

Combined Differential and Restricted Earth Fault Protection

Although it is preferable to use separate CTs for restricted earth fault protection, it can be combined with differential protection using the same current transformers, together with

: interposing current transformers. A CT is required in the neutral connection and should be the same ratio as the line current transformers.

, 1

i I

i I I

II 'I

DIFFERENTIAL

Page 6

Magnetising Inrush -

When a transformer is first energised, a transient magnetising currqnt flows, which may reach instantaneous peaks of 8 to 30 times those of full load. The factors controlling the dirration and magnitude of the magnetising inrush are :

I i) Size of the transformer bank ii) Size of the power system iii) Resistance in the power system from the source to the transformer bank iv) Residual flux level v) Type of iron used for the core and its saturation level.

There are three conditions which can produce a magnetising inrush effect :

i) First energisation .

ii) Voltage recovery following external fault clearance

iii) Sympathetic inrush.due to a parallel transformer being energised.

Under normal steaay state cond'itions the flux in the core changes from maximum negative value to maximum positive value duriqg one half of the voltage cycle, ie a change of 2 0 maximum. Since flux cannot instantly be created or destroyed this transformers are normally designed and run at values of flux approaching the saturation value, an increase of flux to double this value corresponds to relationship must always be true. Thus, if the transformer is energised at a voltage zero when the flux would normally be at its maximum negative value, the flux would rise to twice its normal value over the first half cycle of voltage. This initial rise could be further increased if there was any residual flux in the core at the moment the transformer was energised.

Since extreme saturation which requires an extremely high value of magnetising current.

As the flux enters the highly saturated portion of the magnetising characteristic, the inductance falls and the current rises rapidly. Magnetising impedance is of the order of 2000% but under heavily saturated conditions this can reduce to around 40% ie an increase in magnetising current of 50 times normal, This figure can represent 5 or 6 times normal full load current.

Analysis of a typical magnitude inrush current wave shows (fundamental = 100%) :

Component -DC 2nd H 3rd H 4th H 5th H 6th H 7th H

55% 63% 26.8% 5.1% 4.1% 3.7% 2.4%

The offset in the wave is only restored to normal by the circuit losses. The time constant of the transient can be quite long, typ~cally 0.1 second for a 100 KVA transformer and up to 1 second for larger units. Initial rate of decay is high due to the low value of air core reactance. When below saturation level rate of decay is much slower.

The magnitude of the inrush current is limited by the air core inductance of the windings under extreme saturation conditions. A transformer with concentric windings will draw a higher magnetising current when energised from the LV side, since this winding is usually on the inside and has a lower air core inductance. Sandwich windings have approximately equal magnitude currents for both LV and HV. Resistance in the source will reduce the magnitude current and increase the'iate of decay. '

Page 7

I

p . ..

Effect on Differential Relays

Since magnetising inrush occurs on only one side of the transformer, the effect is similar to a fault condition as far as differential protection is concerned. The following methods are used to stabilise the relay during magnetising inrush period.

Time delayed - acceptable for small transformers or where high speed operation is not so important. (Note : necessary time delay when associated with parallel transformers could be

. : . excessive). -

Harmonic restraint - usual to use 2nd H restraint since magnitude inrush current contains pronounced 2nd harmonics.

Note : 3rd H restraint should not be used for two reasons :

a) Due to-delta connections in the main transformer and in the CT circuits (which provide a closed path for third harmonic currents), no third harmonic current would reach the relay.

b) CT saturation under internal fault conditions'also produces harmonics of which the 3rd is the most predominant. Second harmonics are also produced under these conditions (combination of dc offset and fundamental) so excessive saturation of CTs should be avoided.

The problem of any restraining tendency due to 2nd H currents produced by CTs saturating under heavy internal fault conditions is usually overcome by using high set instantaneous un~ts set at 8-10 x rated current.

While the second harmonic produces a useful restraint during external faults, it can produce unwanted restraint for Internal faults, due to dc saturation of CTs. Extremely large CTs are required such that they do not saturate and affect the operating times of the differential relay.

Gap Detection - If the various current waveforms that occur during magnetising inrush are analysed, it can be found that the magnetising currents have a significant period in each cycle where the current is substantially zero. Fault current, on the other hand, passes through zero very quickly. Detection of this zero is considered a suitable criteria.

Thus, a transformer differential relay can be made to restrain if zero is detected In a cycle for more than a certain period (typically 114f seconds). With the above principle of detection of magnetising inrush, fast operation of the relay can be achieved for internal faults and economically designed CTs can be used, without affecting the speed of operation.

Page 8 ;? :j;

. . . . - ;$?

I

VARIATION OF EARTHFAULT CURRENTS ON TRANSFORMER WINDINGS

An earthfault is the most common type of fault that occurs in a transformer.

1 For an earthfault current to flow, the following conditions must be satisfied :

1 - a path exists for the current to flow into and out of the windings, ie a zero sequence path

I - the ampere turns balance is maintained between the windings.

I The magnitude of earthfault current is dependent on the method of earthing solid or resistance and the transformer connection.

Star Winding - Resistance Earthed

An eadhfault on such a winding will give rise to a current which is dependent on the value of earthing impedance and is also proportional to the distance of the fault from the neutral point, since the fault voltage will be directly proportional to this distance.

The ratio of transformation between the primary winding and the short circuited turns also varies with the position of the fault, so that the current which flows through the transformer terminals

1 will be proportional to square of the fraction of the winding which is short circuited.

If the earthing resistor is rated to pass full load current, then

1 Assuming V, = V,. then T, = 43 TI

Page 9 -

For a fault at x p.u. distance from the neutrgl,

Effective turns ratio = T2 I x TI

Primary C.T. ratio is based on lF.L. for differential protection.

x L :. C.T. secondary current (on prin~ary side of transformer) = --F

\I 3

I f differential setting = 20%

A For relay operation > 20°/c

Y' 3

thus x > 59% i.e. 59% of winding is unprotected.

Differential relay setting Oh of winding protected

If as multiple

of ~ F . L .

Pase 10

Star Winding - Solidly Earthed

In this case, the fault current is limited only by the leakage reactance of the winding, which varies in a complex manner with the position of the fault. For the majority of the winding the fault current is approximately 3 x Iflc, reaching a maximum of 5 x Iflc.

1 From a study of the various current distributions shown for earth faults, ~t is evident that overcurrent relays do not provide aaequate earth fault protection. If the system is solidly earthed, some differential relays adequately cover the majority of faults, but in general separate earth fault protection is necessary.

I EARTH FAULT PROTECTION

It is usual to provide instantaneous earth faultprotection to transformers since it is relatively easy to restrict the operation of the protection to transformer faults only, ie the protection remains-stable for external faults. This protection is called balanced Gr restricted earth fault and the high impedance principle is utilised. However, modern numerical relays provide do provide both high and low impedance restricted earthfault protection.

I Balanced earth fault for a delta (or unearthed star) winding can be provlded by connecting three line CTs in parallel (residual connection). The relay will only operate for internal earth faults since the transformer itself cannot supply zero sequence current to the system. The transformer must obviously be connected to an earth source.

Source (Earthed)

w Balanced

Earth Fault

For an earthed star winding, the residual connection of line CTs are further connected in parallel with a CT located in the transformer neutral. Under external earth fault conditions the current in the line CTs is balanced by the current in the neutral CT. Under internal fault conditions. current only flows in the neutral CT and since there is no balancing current from the line CTs, the relay will operate.

On four wire systems in order to negate the effect of the neutral return current a further CT placed in the neutral and wired in parallel with the existing CT's. On a four wire system with the transformer earthed at the neutral point 5 CT's are required. However, if the transformer is earthed at the LV switch board only 4 CT's are required. If no neutral CT is used then therelay will have to be set above the maximum expected unbalance current in the neutral return.

I Page 11 ' I

A relay, insensitive to the dc component of fault current is normally used for this type of .. . . .. . protection. If a "current operated" relay is used, an external stabilising resistor is placed in . ..:

series with the relay to ensure protection stability under through fault conditions. The protection setting voltage is calculated by conventional methods. To reduce the setting voltage it is often useful to run three cores from the neutral CT in order that the relay is connected across equ~potential points.

Typical Settings for REF Protection (From ESI 48-3 1977)

Solidly earthed 10-60% of winding rated cur-rent

Resistance earthed - 10-25% minimum earth fault current for fault at transformer terminals

Unrestricted Earthfault Protection

Unrestricted earth fault or backup earth fault protection can be provided by utilising a single CT .;

mounted on an available earth connection eg transformer neutral, or (on an earthed systern) by . .

using a residual connection of three line CTs. In this case, the relay should be of the inverse or :.

definite time type in order to ensure correct discrimination.

On resistance earthed system, unrestricted earth fault protection is referred to as standby earth ,..;

fault protection. An inverse time relay is used which matches the thermal characteristic of the .:: earthing resistor. Earthing resistors normally have a 30 second rating and are designed to limit : the earth fault current to transformer full load current.

4 : :,

FAULT CURRENT DISTRIBUTION IN TRANSFORMER WINDINGS

Under fault conditions, currents are distributed in different ways according to winding connections. Understanding of the various fault current distribution is essential for the design of differential protection. performance of directional relays and settings of overcurrent relays.

Fault current distribution on a delta-star transformer, star-star transformer with unloaded tertiary and star-delta transformer with earthing transformer for phase and earthfaults are shown in the diagrams below :

b2 Source

_ _ P __t

PH-E Fault

I3 - B - -

-

Source

I - c2

PH-PH Fault

Fault Current Distribut~on on a Star - Star Transformer with Unloaded Tertiary

BUCHHOLZ PROTECTION

All types o i fault wlth~n a transformer w~ll produce heat which will cause decomposition of the transformer oil The resulting gases that are formed rise to the top of the tank and then to the conservator. A buchholz relay connected between the tank and conservator collects the gas and glves an alarm when a certain volume of gas has been collected. A severe fault causes so much gas to be produced that pressure is built up in the tank and causes a surge of oil. The buchholz relay will also detect these oil surges and under these conditions is arranged to trip the transformer circu~t breakers.

The maln advantage of the buchholz re4ay is that it will detect incipient faults which would not oiherw~se be detected by conventional protection arrangements. The relay is often the only way of detect~ng interturn faults which cause a large current to flow in the shorted turns but due to the large ratlo between the shorted turns and the rest of the winding, the change in terminal currents IS very small

PARALLEL TRANSFORMERS

Parallel transformers are typically protected by directional overcurrent and earthfault protection on the LV side set to look back into the transformers. Where an LV bussection exists the directional relays can be replaced by non-directional relays, with the addition of a non-directional overcurrent and earthfault relay at the bus-section.

If a transformer is connected in parallel with another transformer which is already energised, magnetising inrush will occur in both transformers. The dc component of the inrush associated with the switched transformer creates a voltage drop across the line resistance between the source and the transformer. This voltage causes an inrush in the opposite direction in the transformer that was already connected. After a time the two currents become substantially equal and since they flow in opposite directions in the transmission line they cancel and produe no more voltage drop in the line resistance. The two currents then become a single circulating current flowing around the loop circuit made up of the two transformers in series -the rate of decay being determined by the R/L ratio of the transformer.

Page 14

( I -

- p s far as protection IS concerned, non-harmonic restraint should not be used due to the long time delay required. A harmonic restrained relay should be used for each transformer since if a common relay were used the 2nd harmonic resGaint could be lost due to cancellation as described above.

I OVERLOAD PROTECTION

Overloads can be sustained for long periods with the limiting factor being the allowable temperature rise in the windings and the cooling medium. Excessive overloading will result in

, deterioration of insulation and subsequent failure.

8 .

! Overloads can be split into two categories :

Overloads which do not reduce the normal expectation of life of the transformers. Overloads in this category are possible because the thermal time constant of the transformer means that

, , there is a con,siderable time lag before the maximum temperature correspond to a particular load is reached. Quite high overloads can therefore be carried for short period.

) !

: Overloads in which an allowance is made for a rapid use of life than normal.

The length of life of insulation is not easily determined but it is generally agreed that the rate of using life is doubled for every 6°C temperature increase over the range 80-1 40°C (below 80°C the use of life can be considered negltgible).

I

; A hot spot temperature of 98°C gives what may be considered the normal rate of using life, ie a normal life of some tens of years. This temperature corresponds to a hot spot temperature.rise of 78°C above an ambient temperature of 20°C. The graph below indicates the relative'rate of using life against hot spot temperature.

Relative rate of using life

80 90 100 110 120 130 140 "C Hot Spot Temp

Protection for Overloads

Since overloads cause heating of the transformer above the normal recommended temperatures, protection against overloads is normally based on winding temperature

Page 15

Transformer Setting Tutorials

Advanced Industrial Power System Transformer setting Criteria & : Protection Tutorials

Page 1 of 33

INTRODUCTION

Power Transformer- is one of the most important links in a power system. W~th Transformers of larger capacity , a single transformer fault can cause large interruption to power supplies. If faulted transformer is not isolated quickly, this can cause serious damage and also power system stability problems. Protective system applied to transformers thus play a vital role in the economics and operation of a power system.

In common with other electrical plants, choice of suitable protection is governed by economic considerations brought more into prominence Ly the range of size of transformers which is wider than for most items of eiectrical plant.

For transformers of the lower ratings , only the simplest protection such as fuses can be justified and for large rating transformers ,

comprehensive protection scheme should be applied.

Transformer faults are generally classified into four categories:

1 ) Windlng terminal faults' 2) Core faults 3) Abnormal operating conditions , such as overvoltage, Overfluxing

and overload 4 ) Sustained or uncleared external faults

TRANSFORMER CONNECTIONS

With the development of poly phase systems with more complex transformer connections and also poss~ble phase displacement between primary and secondary windings, standardisation was necessary to ensure universal compatability( BS 171 : 1970)

There are a number of possible transformer connections but the more common connections are divided into four groups.

Group1 Odegree phase displacement E.g YyO - DdO

ZdO


.

- ?$

Advanced Industrial Power System Transformer setting Criteria & ,5- Protection Tutorials ,.

.- Page 2 of 33

Group2 180degree phase displacement E.g Yy6 Dd6 Dz6

Group3 30degree Lagphase displacement E.g Ydl

DY 1 Yz l

Group4 30degree Leadphase dispiacement E.g Yd 1 1 Dyl 1 Yz l 1

High voltage windings are indicated by capital letters and low voltage windings by snmll letters (reference to high and low is relative). The numbers refers to positions on a clock face and indicate the phase displacement of the low voltage phase to neutral vecior , e.9, Yd 1 indicates that the low voltage phase vectors lag the high voltags phase vectors by 30 degree (-30 degree phase shift]

Individual phases are ind~cated by the letters A,B &C , again capital letters for the low voltage winding. All windings on the same limb of a core are given the same letter. A further numerical subscript serves to differentiate between each end of the winding.

PROTECTION APPLIED TO TRANSFORMERS

Over current and earth fault protection(Unrestricted)

Plain overcurrent and earth fault protection utilising IDMTL relays are used primarily to protect the transformer against the effects of exiernal short circuits and excess overloads. The current settings of the protection must be above the permitted sustained over load allowance and below the minimum short circuit current. The ideal characteristic i s the extremely inverse (CDG 14)as it is closely approximates to the thermal curve of the transformer.

The protection is located on the supply side of the transformer and is arranged to trip both the HV and LV circuit breakers. In many cases the requirements for protecting the transformer and maintaining discrimination with similar relays in the remainder of the power syslern are not corilpatibile. In these circumstances , negative sequence filter protecrion or under voltage blocking may be used to obtain the desired ser?sii~vity. .

f 1

:3ALSTOM Limited, Energy Automation & Information

Advanced Industrial Power System Protection

Transformer setting Criteria & Tutorials

Page 3 of 33

1 . High set overcurrent cut-Off:

On small transformers where the main protection is provided with overcurrent devices and where the transformer i s fed from one end only, a high set instantaneous relay i s utilised to provide protection against terminal and internal winding faults.

The ,relay is set to be above the short circuit level on the secondary(load ) -side of the transformer and below: that for a terminal fault on the primary (supply)side of the transformer.

On choosing the type and setting of the high set relay, it i s important to consider the magnetising inrush currents under normal switching , offset fault currents and starting currents of motors.The first two problems can be overcome by using a relay sensitive only to fundamental frequency currents, while the third is overcome by setting the relay above the max. starting current level.

2. Stand-by earth fault protection

Where transformers are earthed via an earthing resistance which is short time rated , stundby earth fault protection is applied to protect the resistor from damage when an earth fault persists for a time longer than the rating of the resistors. The relay is energised from a CT in the neutral connection and its time of operation is made to match the thermal rating of the resistor. It is arranged to completely isolate the transformer. .

Some times a two stage relay is employed, each stage set to operate at a different time. The first staqe arranged to trip the LV breaker and i f still the fault is persisting, Ihe second stage relay trips the HV side breaker thus isolating the transiormer completely.

DIFFERENTIAL PROTECTION

The funciion of differential protection is to provide faster and more discriminative phase fault protection than that obtainable from simple over current relays.CTs on the primary and the secondpry sides

OALSTOM Limited, Energy Automation 8 Information

Advanced Industrial Power System Transformer setting Criteria & Protection Tutorials

Page 4 of 33

are connected to form a circulating current system. The following

figure illustrates the principle. .->?

. <. .&> .;;. .I

Basic Considerations for transformer differential protection A; . .

.>

.:m .- .:E

1. Line current transformer primary ratings :;3 . .. .$ .

.?

The rated currents of the primary and the secondary sides of a two : ..,:.; .%

winding transformer will depend on the MVA rating of thetransformer . . . ,.... >. b! ;E .. .~ and will be in inverse ratio to the corresponding voltages. For three ..:. I.-. .. . :+,

winding transformers the rated current will depend on the MVA rating ';.I. . ... -4 - S h

of the relevar-rt winding. Line current transformers should therefore Q ;" . ..

have primary ratings equal to or above the rated currents of the . . .P ...r ,.,

: .J

transiormer windings to which they are applied. . . ,.. h

-

2. Current transformer connections

The CT connections should be arranged , where necessary to compensate for phase difference between line currents on each side of the power transformer. If the transformer i s connected in delta/star as shown in figure, balanced three phase through current suffers a phase angle of 30 degree which must be corrected in the CT secondary leads by appropriate connection of the CT secondary wind~ngs.

Further more , zero sequence current flowing on the star side of the power transformer .will not produce current outside the delta on the other side. The zerosequence therefore be eliminated from the star side by connecting the CTs in delta, from which i t follows that the CTs on the delta side of the transformers must be connected in star, in order to give 30 degree phase shift. This is a general rule ; i f the

#

OALSTOM limited, Energy Automation & Information

Advanced Industrial Power System Transformer setting criteria & Protection Tutoriais

Pcge 5 of 33

transformer were connected starlstar , the CTs on both sides would need to be connected in delta.

- .

. . . . . . . < .

.... - . .- . - --- , . . , -

. A , . -

. . . . .--. -. . . . . . . a . -- . . . . .

o r 1 r , . :. . . .

. . . .

- ,.. ... . . . .

. . . . . . ....... - . .

. . _ _ l i ..-. ... .. . . . . ld,( - -.

. , . ' . 8

..... . ........ - --,- . . . . : . , . ;' :'.., !-.: , . . . . . . . . - . . . . . - .

. . . . . .- . . . . j

. t ' , , > 3 . - . . . . . . .-

,-: . : , i : :

. . . . . . , . - ; . [ ! : : : .---,i ' I -

. , . . . : I , . . . , . :.-? , . . : , I . . , ...... . .

L-.,,-.- , v.1, : 2 ' - ..:

, . , .

. . . . L . . ., v - :

--- -- . - . r - - -, , , : , , 8 . V ' , .-..-

N.. ! . : ' 4 -. ..: : ; . . : , . ,.<, . :

.-.--A.

: : , i

. . . . .

7 . . : . - . . . . .

. , , . <>-. ; , : 4 .->-: . . I.4 . + A : -3 . , ., . : a : . L .

. , . . , .

r-- 4 I

,----- . a n . - _ I ' -. : * .: ,..- , . . : . : A .: --. . . , - ! I-. . . . . . . . . . . .

. - , i . , . ! _ I ; l a 0 ;

. . . . ....... -. -.

-. I , i - , !

.... : .-,. ' . - : ; c c ; . , - . -. , . .. , . . . .

C - - - J - . . -

4 - a , .-.... -.

-. . . . . -. -

. . -:! ! . . . i i*: < . , -->

. - I . ._ , ,:..-.. . . . M . .

, I ; !

, . -.. - - i .

. . . , ..... 2 t. .

,. I. : .. . . . . . .. , . .

. . , :. , . I !

.. ...... . .... . . _ .... _ , .

- . . . . . . ........

. __-_ ;.- .- ' I .- -- 2

-ffKmsKX W ~ C O a t l * * S

NOTES O N R L U I COU~CCTIOMS

1. X 01 T a 0.4d em.rpo..64 ff. r e W-QDmCYd. m h ull d CT. r. MU-d v. . I m n d .rn' u. ormlod 2. I* a u r u r l IN, C? c-m. ul .rV..d. - m -1 m* L WIWQ wu ~ o r r uvr- to b C-OUCW *1.3 -I b NCJJ lo - IN n(n- --a 1- th. CT. rw.ut.d m' W q S l u d Z . m d t - l h a r w d h r n b p . 1 d 3 k * W c h C L b r d l o n - r t u C I ' s r n - a n g . 2 . ~ 3 - v b . c o n a a . d

4. T h ~ . r * c a roc. ~ e a r o ..(rrrr cap?rrd w lhor .prl(..d n I<C 76: 1967 rrd as 171- relo

4


Advanced Industrial. Power System Transformer setting Criteria & Proteciion Tutorials

Page 6 of 33

Figure 1

When Cis are connected In delta, their secondary rating must be reduced to 1 / 43 times the secondary rating of star connected Cis , inorder that the currents outside the-delta may balance with the secondary currents of the star connected CTs.

When line CT ratios proiide adequate matching between currents supplied to the differential relay under through load and through fault conditions , the necessry phase shift can be obtained by suitable connection of the' line CTs . Figure 1 above shows the required connections for various power transformer winding arrangemenis.

When delta connected CTs are required it is a common practice to use star conr;ecled line CTs and to obtain fhe delta connection by means of stal-/delta interposing CTs.

3. Bias to cover Tap-Changing facility and CT mismatch

If the transfor-n~er hcs a tapping range enabling its ratio to be varied , this must be allowed for in the differential system. This i s because the CTs selecled to balance, for the mean ratio of the power transformer, , a variation in ratio from the mean will create an unbalance proportional to the ratio change. At maximum through fault current , the spill oputput produced by the small percentage unbalance may be substantial.

Differential protection should be provided with a proportional bias of at-\ amount which exceeds in effect the maximum ratio deviation. This stabilises ihe protection under through fault conditions while still permitting the system to have good system sensitivity.

The bias characteristic for a typical differential protection is shown in figure2, iron-\ which it can be seen that the cursent required to operate the relay increases as the through fault increases.

.- -. --



Page 7 of 33

Figure 2

a 2 20-- 1 - -- - -. -. w ' OPERATE

.. .. - - - to- '- P . - - . . - . . -- - . A - -. -- - - - - 2-0 3;O 4-0

THROUGH BIAS CURREM (pa.)

When applying a differential relay, care should be taken that its characteristic will prevzr-it operation due to the combination of tap change variation and CT mismatch . To mininiise the effect of tap change variations , current inpuis lo the differeniial relay are usually matched at the mid poini of the tap range..

Figure 3 below shows percentage biased differential protection for a two winding transformer. The two bias windings per phase are conimonly provided on the same electromagnet or auxiliary 1r-a~isfornier core. .


I

b


- Page 8 of 33

The Merz-price principle remains valid for a system having more than two connections, so a transformer with three or more windings can still be protected by the application of above principles.

When the power transforn~er has only one of i t s three windings connected to a source of supply, with the other two windings feeding loads at differ-er~t voltages, a relay of the same design. as that used for two winding transformer can be employed.

. . .-. . . . .? . . . . . -- 8 :

. . . . ! Wj, g i i i__ .: j

- > - - . . ,. .

.... -, . i . . . . ,P.7'-$ : ; '

. ... . . - . . . . . . i - - J > ' :

! , .; ' ' .-

<__ --

I

, . -. . -.. ,-. : j : .. , ... ..i -:. ....... .... . . . . . . . . . . . . . .... I i :

; ..: ! i ! ,- ' :--. I : ' "

i : , ! . . . . j / j

j ; i i

. . . . I ! ! ;:;,5V..." dl. . ti:: ..;.. ; ! i i ;

'--L_1------- ,-. ,-- j / \

1 I ,-; : : i I I 1 0

; . I I i / I

1 ~2Y-y::- !

! . . !

Biased differeniiol pro:ec;ion for two winding DeJtalStar transformer Figure 3

The separate load cv!rents are summated in the CT secondar;/ circuits, and will balar~ce \with the infeed current on the supply side.

When more tho!] one winding is connected to a source , the disiributiol~ of CLII rer~t cz11,1ot readily be predicted and there is u danger in the scher~~e sflown (a) in Ihe figure 4 of current circulaling between the two paralleled sets of CTs with out producing any bias. It i s therefore impor-tani i:lat bias be obtained seperately from the current flowing in each set of line connections. In this case a ~eloy used with separate bios \vindings , arranged so that their mechanical or' electrical effects a l ~ ~ c y s add numerically , that is not vectoria'ily . lo give the total bias eiiezr. This is shown as (b) in the figure 4.

OALSTOM Limited, Enersy Automation & Information

Advanced Industrial Power System Transformer setting Criteria & : Protection Tutorials

Page 9 of 33

These considerations do not apply when the third winding consists of a delta connected tertiary with no connections brought out. Such an arrangement may be regarded GS t\.w \vvir,dlr,g trafisformer --for protection purposes and may be protected as (c) in the figure 4.

-

3. Inter posing CTs to compensate for mismatch of Line CTs

Besides their use for phase ccjmpensation, interposing CTs may be used to match up currents supplied to the differential protection from the line CTs for each winding. The amount of CT mism.atch which a relay can tolerate with out maloperation under through fault conditions will depend on i t s bias characteristic and the range over which the tap changer can operate. If the combined mismatch due to CTs and tap changer is above the accepted level , then interposing CTs may be used to achieve current matching at the mid point of the tap changer range.


.\:,;j . ::,,,*

:<

:. r f 2 :;

. ..

..?

Advanced Industrial Power System Transformer setting Criteria & Tutorials Protection

Page 10 of 33

Figure 4

. . . .

--J. !. -.- SUPPLY- 'END

BlAS\'I'WDINGS . - . .. - . , . .

-

. - . . . .

( ~ 1 . : THjlEE WlNDitllG W S m R M E R Icne poviar rource)

SUPPLY Em

[c) THREE VIINDING TfW.ISFOiU!ET( WITH U1:LOADED DELTA T E R M Y . .

@ALS:OivZ ?irnit+?d, Energ\/ Automation 8 Inforn;aiion


Page 1 1 of 33

-

For the protection of two winding transformers interposing CTs should ideaiiy t-1-~aich ihe---relay currents under through load conditions corresponding to the maximum MVA rating of the tran~fo~mer. An example of this for an 1 1 KV/132KV 30MVA, DELTA /STAR transformer is shown in the figure 5.

First the primary ratings of 1600A and200A chosen for the main CTs should not be less than the max. full load currents in each winding , which are ,

30 x 100 = 1575 A For 1 1 KV winding 3 3 ~ i i x 103 30 x 10. = 164 ,A For 132KV winding \/3x 132 x 103 r the 1 1 KV winding this is also the nominal full load current , but for 1172 132KV winding , with -5% tap , the latter is:

30 x 10" = 138A For 1 1 KV winding 43 x 0.95 x 132 x 103

Equivaienf secondary currents in the line CTs are 0.984 A and 0.69 A. Thus the ratio of the star /delta interposing CTs to achieve ideal n7atching is given by:

0.69 / 0.984 = 0.70 / L A OR 0.70/0.577 A \'3 \\ 3

.' >


Advanced Industrial Power System Protecti~n

..*a Transformer setting Criteria ,j%

.... >:A{ Tutorials ..g

Page 12cf 33 $ -

. . - . . _ r-- ..; . . A -

. . . . . , . . i

. . . . . . .

, . . .

, : , 2::,s z.:.;;;:.,:;,.

, . 2 9 , ,- .? --* ,-4 ~p.-.--.------l_l d

t- * L--- _- - .-

. . , 3

i 0 , . , . , . ! -1. _--I_-. .-

.-' ! i --' :x*-,-->. .-.. ... . -

i ,--.. I - \ . .. , -- - - - - -- - _ . __. ._ *-. 7-

. . I .... . i

(~jpL ,, . . 8 , ,- , * . T-\., 2-. ,A,

*,,,i i>." ,dr;:3;:4G: , 2: / ,. , .; . .: ', . . . L, ! i L: , s - 2 . 'y ' \/

, .

I R E U Y RATED CURRfNT - 1A

Figure 5

The pro!eciiori of three winding transfor-nier-s is complicated by the fact that line CTs for each winding ar-e riormally based on different MVA levels and will 1701 ttienlselves achieve balance under ttirough current ronditior~s. To achieve correct balarice , i t i s necessary to use inlerposir~g CTs wllicti hlill provide the relay with raied currerli when the rating of the highest rated winding is applied to all windings.

An exaniple for a 500KV/138KV/13.45KV, 120MVA/90MVA/30MVA, star/slar/delta transfornler is shown in the figure 6.

Load cur rent a i 599 KV = 120 x 10" = 138.6A - ~ 3 x500x 10"

OALSTOM Limiled, Energy Automaiion & Iriforniation

I

Advanced Industrial Power System Transformer setling Criteria & Protection Tutorials

Page 13 of 33 .-

Load current at 138 KV = 90 x 106 = 376.5 A ~ 3 x 138x 103

Load current at 13.45 KV = 30 x 106 = 1288 A i 3 x 13.45 x 103

Line CT ralio at 500KV = 20015 A I-ine CT ratio at 138KV = 40015 A .

Line CT ratio at 13.45KV = 150015 A

Current at 138 KV corresponding to 120 MVA = 120 x 1 O6 = 502 A 3 x 138x lo3

Current at 13.45 KV corresponding to 120 MVA = 120 x 1 O6 ~ 5 1 5 1 A \I3 x 13.45 x lo"

Secondary current from 500KV line CTs corresponding to 120 MVA =138.6 x 5 = 3 . 4 6 A

200


Advanced Industrial Power System Transformer setting Criteria &

Protection Tutorials Page 14 of 33

12OMVA SOMVA 2OO/M W k V . 1 W V

RELAY FATED CURKEICT - !2. Figure 6 -

-. lnele iore ratio of required starldelta interposing CTs

= 3.461 5 A OR 3.461 2.89 A \'3

Secondary current from 138 KV line CTs corresponding io 120 M V A

OALSTOM Limited, Enerhy Automation t Information

1 Advanced Industrial Power System Transformer setting Criteria & I Protection Tutorials i Page 15 of 33

There fore ratio of required starldelta interposing CTs

- Secondary current from 13.45 KV line CTs corresponding to 120 MVA

= 5151 x5 = 17.17 A 1 500

Therefore ratio of required star/star interposing CTs

= 17.1715 A

E l s / Under full load conditions of 30MVA, for the 13.45 KV delta winding ,

1 the current appearing in the primary of the 17.17/5 A inter posing CT I 1 .

will only be 4.29 A , the corresponding secondary current being 1.25 I I A . However the ratings of the primary and the secondary windings i ! should ideally be 17.1 7 A and 5 A respectively to minimise winding

resistances.

STABILIZATION OF DIFFERENTIAL PROTECTION DURING MAGNETlSlNG INRUSH

Tl~e n~agnetising inrush phenomenon produces current input to the energised winding which has no equivalent on the other sides of the transformer. The whole of the inrush current appears therefore as unbalance and is no1 distingushable from internal fault current. The normal bias is not , iherefore effective and increase of protection setting to a value which would avoid the operation would make the protection of little value.

Harmonic Restraint.

The inrush current, clthough y!~.nerally resembling an inzone fault current, differs greaily when the waveforms are compared. The distinctive difference in the4 woveforms can be used to distinguish


. Q 3.c: .k

. ..

Advanced Industrial Power System Transformer setting Criteria & .$ Protection Tutorials :,

Page 16 of 33 !(

between the condition;. The inrush contains all orders of harmonics, but these are not all equally suitable for providing bias. The study of this svbject is complex, as the wave form depends on the degree of saturation and on the grade of iron in the core.

a) D.C Offset component (Zero harmonic)

A uni-directional component will usually be present in the inrush current of the single phase transformer and in the principal inrush currents of a three phase unit. However i f at the instant of switching the residual flux for any phase is equal to the flux which would exist in the steady staie at that point on the voltage wave , then no transient

3.; _1 . - :

disturbance should take place on that phase. 3.; ! ,! , .' 'ii:. ... '! : :>: , Large inrush c~r~-enis will flow in the other two phases , corresponding

to high peak lux values established in these phase cores. The high flux circulates through the yokes , the saturation of which affects the iir-s: phase , L-:iiich. would have had no inrush effect, causing c substantial transient current to flow in this phase as well. This latter current , however will not be off set from the zero axis , althougt-1 the current waveform will be distorted..

I f the uni-directional current component were used to stabilise a differential sysiem, some sort of cross phase biasing would be required becc~lse of this effect.

b) Second Harmonic component

This connpone!3t is present in all inrush wave forms . It i s typical of wave forms in which successive half period portions do not repeat with reversal oi polarity but-in which the mirror image symmetry can be found abo:lt certain ordinates.

The portion of second harmonics varies some what with the degrce of saturation of core , but is always present as long as the unidireciior~ai ~ormponent of flux exists. It has been shown to have a minimum value of about 20% of the amount by which the inrush current exceecjs the steady state magnetising current.

I

- . . -. . - A --

OALSTOM Lirni:-?d, Energy Automation & Information

Advanced Industrial. Power System 1 Protection

Transformer setting Criteria & Tutorials

I Page 17 of 33

I Normal fault current do not contain second or other even harmonics, nor do distorted currents flowing in saturated iron cored coils under steady state conditions.

-

The output current of a current transformer which is energized into steady state saturation will also contain odd harmonics but i ~ o t even harmonics. However, should the current transformer be saturated by the transient component of the fault current, the resulting saturation i s not symmetrical and even harmonics are introduced into the output current. This can have the advantage of improving the through fault stability performance of a differential relay, but i t also has the adverse effect of increasing the operatioh time for internal faults.

The second harmonic is therefore an attractive basis for a stabilizing bias against inrush effects, but care must be taken to ensure that the current transformers are sufficiently large so that the harmonics produced by transient saturation do not delay normal operation of the relay.

. - The differential current is passed through a filter which extracts the second harmonic; this component is then applied to produce a restraining quantity sufficient to overcome theoperating tendency due to the whole of the inrush current which flows in the operating circuit.

By this means a sensitive and high speed system can be obtained. With the type DTH relay, a static design, a setting of 15% is obtained with an operating time of 45 milliseconds for all fault currents of twice or more times the current rating.

The relay will restrain when the second harmonic component exceeds 20% of the current.

c. Third harmonic The third harmonic is also present in the inrush current in roughly comparable proportion to the second harmonic. The separate

I phase inrush currents are still related in phase to the primary applied

I electromotive forces and the harmonics have a similar time spacing,

! which brings the third harmonic waves in the three windings into phase. If the windings are connected in delta, the line currents are each the difference of two phase currents. As the inrush components vary during the progress of the transient condition it i s

i possible for this qifference to pass, through zero, so that the third i . i. . .. f; ,:.

,, . %? %...., OALSTOM Limited, Energy Automation & Information

. .

Advanced Industrial Power System Transformer setting Criteria & Protection . Tutorials

Page 18 of 33

harmonic component in the line current vanishes; this component, therefore, be regarded as a reliable source of bias.

To this must be added the further consideration that a sustained third harmonic component is quite likely to be produced by CT saturation under heavy in-zone fault .conditions.

All this means that the third harmonic is not a desirable means of stabilizing a protective system against inrush effects.

d. Higher harmonics , ,

All other harmonics are theoretically present in inrush current but the relative magnitude diminishes rapidly as the order of harmonic increases; there may be 5% of fourth harmonic in a given inrush 'current. This component would be similar in response to the second harmonic but the small magnitude hardly justifies the provision of an extra filter circuit.

A still smaller proportion of fifth harmonic will be present. This component is not subject to cancellation as is the third harmonic, and can be present in the output of a CT in an advanced state of saturation, therefore offering no benefit. Still hlgher harmonics are of magnitude too small to be worth consideration.

The percentage of fifth harmonic in the transformer magnetizing current increases significantly when the transformer is subjected to a temporary overvoltage condition. Some manufacturers apply a measure of fifth harmonic bias to the relay to restrain operation for this condition. Typically such relays are restrained i f the magnetizing current contains 30% fifth harmonic.

RESTRICTED EARTH FAULT PROTECTION

A simple overcurrent and earth fault system will not give good y

protection cover for a star-connected primary winding, part~cularly il the neutral is eaithed through an impedance. The degree of protection is very much improved by the application of a ur-lil differential earth fault system or restricted earth fault protection, as shown in Figure 7. The residual current of three line current


Advanced Industrial Power System Transformer setting Criteria & Protection

- Tutorials

Page 19 cf 33

transformers is balanced against the output of a current transformer in the neutral conductor. The relay is of the high impedance type.

The system is operalive for faults within the region between current transformers, tha t Is, fs: fai;lts on the star winding in question. The

I system will remain stable for all faults outside this zone

HIGH lMPEDANCE RELAY

Res tric ted earth fault protection for a star winding. Figure 7

The gain in protection performance comes not only from using an instantaneous relay with a low setting, but also because the whole fault current i s measured, not merely the transformed component in the HV primary winding. Hence, although the prospective current level decreases as fault positions progressively nearer the neutral end of the winding are considered, the square law which controls the primary line current is notapplicable, and with a low effective setting, a good percentage of the winding can be covered.

Restricted earth fault protection is often applied even when the neutral is solidly earthed. Since fault current then remains at a high value even to the last turn of the winding , virtually complete cover



Page 1:: for earth faults if obtained, which is a gain compared with the performance of systems which do not measure the neutral conductor current.

Earth fault protection applied to a delta-connected or unearthed ..-:$I d

star winding in inherently restricted, since no zero sequence . ;+$ ?? .:g; component can be transmitted through the transformer to the -:a

secondary system. A high impedance relay can therefore be used, ;.:% .;$ giving fast operation and phase fault stability. 3 ,$$

.::<91 ::t

Both windings of a transformer can be protected separately with it ..$ restricted earth fault protection, thereby p~oviding high speed j ~ s

..$ protection against earth faults for the whole transformer with ..< ?.a ;L .

'4 relatively simple equipment. .- .':.. .q. :;.$

.\1

* This protection is based on high impedance differential principle, !%

offering stability for any type of fault occuring outside the protected : - z I 2'

zone and satisfactdry operation for faults with in the zone. .. .,. f ....

A high impedance relay is defined as a relay or a relay circuit whose ...,.. . . . c ~ ..." , -. ..% 4: .. - voltage setting is not less tnan the calculated rnax. voltage which. ....-cJ. . --

. ' . :.=s -.-<$ can appear across its terminal under the assigned-max. through fault -

current condition. . :.?2 ...- .- . ->5J - '.:3 -2 ..;+

It can be seen frorn the figure that during an external fault current . ..?. ,:! :-:

should circulate between the current transformer secondaries. The ., :! ":.

only current that can flow through the relay circuit i s due to any difference in CT output for the same primary current. Magnetic saturation will reduce the output of a CT and the most extreme case of stability will be if one CT is completely saturated and the other unaffected. At one end of the CT can be considered fully saturated with i t s magnetising impedance , while the CT at the other end being unaffected , delivers i ts full current output which which will then divide between the relay and the saturated CT. This division will be in the inverse ratio of R relay circuit and Rct +2RL and obviously i f R relay circuit is high compared with Rct +2RL, the relay will be prevented from undesirable operation.

To achieve the stability for external faults, the.stability voltage for the protection Vs must be determined by the formula, Vs = I f (Rct +2RL ) Where Rct = CT secondary winding resistance

RL= max. lead resistance from the CT to the common point

OALSTOM Limited, Energy Automation & Information . . ._. . . . .-.. . .. . .

1.:.

I

Advanced Industrial Power System Transformer setting criteria.& Protection . - - Tutorials

Page 21 of 33

I To ensure satisfactory operation of the relay under internal fault conditions the CT Knee point voltage should not be less than twice the relay setting voltage. i.e

The setting of the -stabilising resistor must be calculated in the following manner, where the setting is a function of the relay ohmic impedance at setting Rr , the required stability voltage setting Vs and the relay current setting Ir.

1 Rs t = - Rr -

lr -

The ohrriic impedance can be calculated using the relay VA burden at current setting and the current setting Ir,

-1 USE OF MFTROSL OR NON LINEAR RESISTORS.

When the max. through fault current is limited by the protected circuit impedance: such as in the case of power transformer REF protection , it i s generally found unnecessary to use non -linear voltage limiting resistors or Metrosils. How ever when the max. through fault current is high , it is always advisable to use a non linear resistor across the relay circuit. Metrsils are used to limit the peak voltage developed by the CTs under internal fault conditions, to a value below the insulation level of the CT s, relay and the connecting leads, wh~ch are normally withstand 3000V peak.

The following formulae should be used to estimate the peak transient voltage that could be produced for an internal fault. The peak voltage produced during an internal fault will be a function of the CT Knee point voltage and the prospective voltage that would be produced for an internal fault if CT saturation did not occur. This prospective voltage will be a function of max. internal fault secondary current , the CT ratio , the CT secondary winding resistance, the CT lead resistance to the common point , the relay lead resistance, the stabilising resistor value and the relay burden at relay operating current.

. t OALSTOM Limited, Energy Automation 8, Information

-

Advanced Industrial Power System . Transformer setting Criteria & . .

Protection Page 22 of 33

-

Vp= 2 d 2 Vk (Vf - Vk)

Vf = If (Rct +2rl+Rst + Rr ) .% :,.% :g

.>..% . .: > ;$

Where Vp= Peak voltage developed by the CT under internal fault :s ::$

conditions Vk = CT knee point voltage .,#

i% . :.. Vf = max. voltage that would be produced if CT saturation did . 3

not occur ,.. . kt ~ ..

Max. internal fault sec. Current . ..,. C? ."

Rct = CT secondary winding resistance ,

RL = max. lead burden from CT to relay Rst = stabilising resistor Rr = relay ohmic impedance .at setting

When the value given by t h e formula is greater than 3000 V peak, non-linear resistors (metrosils) should be applied. These non-linear . -. resistor s (metrosils) are effectively connected across the relay circuit, or phase to neutral of the ac bus wires, and serve the purpose of shunting the secondary current output of the current transformer from the relay ~norder to prevent very high secondary voltages. These non-hear resistors (metrosils) are externally mounted and take tne form of ann~~lar discs, of 152 mm diameter and approximately 10 mm thickness. The operating characteristics follow the expression: v= l-10 2 5

Where V= Instantaneous voltage applied to the non-linear res~stor (metrosils)

C= Constant of the non-linear resistor (metrosil) I = lnstantaneous current through the non-linear resistoi

(metrosil)

For satisfactory application of a metrosil, i ts characteristic should be sucli that i t requires the following requirement.

At the relay voltage setting , the non linear resistor, current should be as low as possible but no greater than approximately 30mA r.m.s for 1 A CT and approx. 100mA for 5A CTs.


. . . . . . . . . . . . .

-


Total impedance = 14 p.u

-.-, inere foi-e ! I = 1/:4 = Z.C714 p.u

Base current = 80 x 10 6

4 3 x 4 1 5

= 1 1 1 296 Amps There fore fault current = If = 3x 0.071 4 ~111296

= 23840 dmps ( Primary) = 14.9 Amps (Secondary)

-

Setting voltage Vs = If (Rc t + 2 R L ) Assuming Earth CT saturates,

Rct = 4.8 ohms ... . .. -. ..: 2RL = 2x 100 x 7 . 4 1 ~ 1 0 - 3 . . . . . .,

= 1.482 ohms . .- . .. . , . . . -. . .

Therefore setting voltage = Vs = 14.9 x ( 4.4+ 1.482)

= 93.6 V Sta bilising Resistor

Rst = Vs /IS - VA/ls

Where VA is the burden of the relay Is = relay setting current

-

Adopt the relay setting as lo%,

Rst = 93.610.1 - 1 / (0.112

= 836 ohms

EFFECTIVE SElTlNG OF THE RELAY

Effective setting = Ip = CT ratio x (Is + nle)

Where n= the no. of CT in parellel le = magnefising current of each transformer


Advanced Industrial Power System Transformer setting Criteria &

i Protection Tutorials I Page 25 of 33

From the CT characteristics & the Table -

i ine side CTs:

Flux density at 93.6 V, = 93.6'1 158 = 0.592 Tesla

Magnetising force at 0.592 T = 0.01 5 AT/mm

Therefore magnetising current = 0.01 5 x 0.34 1 = 0.0051 Amps

I GALSTOM Limited, Energy Automation & Information

Line side CT Earth CT

1 58 1 0.341 236 1 0.273 I

- -

OALSTOM Limited, Energy Automalion & Information

Advanced Industrial Power System - Transformer selting Criteria & Protection Tutorials

Page 27 of 33

Flux density at 93.6 V = 93.6 / 236 = 0.396 Tesla

Therefore mag current = 0.01 2 x 0.275 = 0.0033 Amps

Thus effective setting = 1600 x [0.1 + (3x 0.0051 + 0.0033) ]

= 190 Amps

Transformer full load current = 1391 Amps

Peak Voltage developed across the relay circuit = Vp= 2 4 2 Vk (Vf -

Vf= 14.9xVs/\s= 14.9x936= 13946volts

For earth CT froni the graph, Vk = 1.4~236 = 330 V

Therefore Vp = 2 11 2 x330 ( 13946 - 330)

Since this value is more than 3 KV , Metrosil voltage limiter will be

OVERFLUXING PROTEC'TION

Power frequency overvoltage causes both an increase in stress on the insulation and a proportionate increase in the working flux. The

latter effect causes an increase ip the iron loss . and a

Advanced industriai Power System Transformer setting Criteria & Protection Tutorials

Page 28 of 33

disproportionately great increase in magnetizing current. In addition,

flux is directed from-the laminated core

structure into steel structural parts. In particular, under conditions of

over-excitation of the core, the core bolts, which normally carry little

flux, may be subjected to a large component of flux diverted from

the highly saturated and constricted region of core alongside.

Ui~der such conditions, the bolts may be rapidly heated to a

temperature which destroys their own insulation and will damage the

coil insulation if the condition cantinues.

Reduction of frequency has an effect with regard to flux density,

similar to that of overvoltage.

It follows that a rransformer can operate with some degree of

overvottage with a corresponding increase In frequency, but

operation must not be continued with a high voltage input at a low -

frequency.

Operation cannot be sustained when the ratio of voltage to

frequency, with these quantities given values per unit of their rated

values exceeds un~ty by more than a small amount, for instance if V/f

> 1 .l. The base of 'unit voltage' should be taken as the highest

voltage for which the transformer i s designed i f a substantial rtse in

system voltage has been catered for in the design.

The condition does no1 call for high speed tripping; instantaneous

operation is undesirable as this would cause tripping on momentary

system disturbar~ces which can be borne safely, but normal

conditions must be restored or the transformer must be isolated within

one or iwo minutes at most. The fundamental equation for the

generat~on of e.m.f. in a transformer - can be arranged to give:


8. : Advanced Industrial Power System Transformer setiing Criteria &

Protection Tutorials Page 29 of 33

ii is necessary to detect a ratio of E l f exceeding unity, E and f being

expressed in per unit values of rated quantities.The system voltage, as

measured by a voltage transformer, is applied to a resistance to

produce a proportionate current; this current, on being passed

through a capacitor, produced a voltage drop which is proportional

to the function in question, El f , and hence to the flux in the power

transformer. -

Feedback techniques are used in the type GTT relay to make the

measured ratio accurate over a wide range of frequency and

voltage.Two time delay outputs are given by auxiliary elements, each

with multiple contacts. One element, the contact of which are used

to effect a control operation to reclify the abnormal condition,

operates after a pre-selected fixed,time delay between 0.5s and 1.0s

or between 2s and 5 s.

The second element is arranged to trip the supplies to the transformer

after a pre-set time delay of 5s to 30s or 12s to 120s if the abncrmal

condition persists.

Overfluxing protection is mostly confined to generator-transformers

for which the risks appear to be greatest, although overfluxing trouble

has been known to occur for other transformers as

well.

OALSTOM Limited, Energy Automation - & Information

Advanced Industrial Power System Protection

Page 30 of 33 -

USE OF INSTANTANEOUS OVERCURRENT

SOiJQCf

it-; .,"> Y :

"2 ..-.

. . ' . ., .<is

. $ $f .:g+ ...? $5 ..$

The use of instantaneous relays for the primary side of the transformer . .;.+ .a i? .??

is recommended inorder to improve fault clearance time and enable ..+: , ..* * .

. - a lower time multiplier setting on relays elsewhere on the system. The ..::. .> -- .. _ I

-... relay should have low transient overreach and be set to ...

approximately 125% of the maximum through fault level of the ..

transformer, in order to prevent operation for faults on the secondary .. . ..

side. .. ". . t t

,:>: , ,.

. A

.<.; . .

5

.,. :*., 1:;

x ,' '$5 .. (1 ? i . , :

OALSTOM Limited, Energy Automation & Information :..> . .$ .4

.A?

Generator and Generator Transf - Protection

Generator and Generator-Transformer

-":<&-" :y-.. ,,>.x. -*:- <zz+$+>e.i; .:.;:.: 'The core of an electric power system is the generation. $ ~ ~ ~ ~ ~ : ~ .

.': - 7. ..'&.'.:<.'.:

With the exception of emerging fuel cell and solar-cell $ , : ~ ; ~ ~ y : ~ ~ ~ - ~ ~ - technology for power systems, the conversion o f the fundamental energy into i ts electrical equivalent . normally reqdires a 'prime mover' to develop mechafiical power as an intermediate stage.

The nature of this machine depends upon the source of energy and in turn this has some bearing on the design o f the generator. Generators based on steam, gas, water or wind turbines, and reciprocating combustion engines are all in use. Electrical ratings extend from a few hundred kVA (or even less] for reciprocating engine and renewable energy sets, up t o steam turbine sets exceeding 1200MVA.

Small and medium sized sets may be directly connected to a power distribution system. A larger set may be associated with an individual transformer, through which it is coupled to the EHV primary transmission system.

Switchgear may or may not be provided between the generator and transformer. In some cases, operational and economic advantages can be attained by providing a generator circuit breaker i n addition to a high voltage circuit breaker, but special demands will be placed on the generator circuit breaker for interruption o f generator fault current waveforms that do not have an early zero crossing.

A unit transformer may be tapped o f f the interconnection between generator and transformer for the supply of power to auxiliary plant, as shown in Figure 17.1. The unit transformer could be of the order ., :.;:,.: --..

of 10% of the unit rating for a large fossil-fuelled steam ..:f.?:<..;?: set with additions( flue-gas desulphurisation plant. bu t %?~;~~;~~~<~;:

6.:.<.7, ..,;. . .,,. it may only be of the order o f 1% o f unit rating for a .+s;:;~,:.:,:.

.-> - ., .. hydro set. ..?..$<!: , . . . . . :-. :;. , ;:.: .:

, :y.;:..:, :::,..: . . . . . .

Generator Main ttansformcr

,--, HV busbars . . *'<. Unit transforrncr

i : I : '-4'

: ,' -.-- Auxiliary supplics switchboard

required. The amount of protection applied w i l l be governed by economic considerations, tak ing i n t o account the value of the machine, and the value o f i ts output t o the plant owner.

Industrial or commercial plants w i th a requirement for steamlhot water now often'include generating plant ut i l is ing or producing steam t o improve overall economics, as a Combined Heat and Power (CHP) scheme. The plant w i l l typically have a connection t o the public Ut i l i ty distribution system, and such generation is referred t o as 'embedded' generation. The generating plant may be capable of export nf wrp lus power, or simply reduce the impor t o f power from the Uti l i ty. This is shown i n Figure 17.2.

-

The following problems require consideration f rom the point o f view o f applying protection:

a. stator electrical faults

b. overload

........................................ PCC

Gcncra:or

d. unbalanced loading

e. overfluxing

f. inadvertent energisation

e. rotor electrical faults

f. loss o f exci tat~on

g. loss of synchron~sm

h. failure o f prlme mover

j. lubrication oi l failure

I. overspeed~ng

m. rotor distortion

n. difference i n expansion between rotat ing an stationan/ parts

o. excessive v ibra t~on

p. core lamination faults

The neutral point of a generator is usually earthed facilitate protection of the stator winding and associat system. Earthing also prevents damaging transic overvoltages i n the event of an arcing earth faul t ferroresonance.

f'l;inl l rcdr r , - tola1

dcn?:tnd: xtbtlV

PCC- Poirll G ! Common C o u l > l ~ n ~

W h c n plan1 o r n r r r l < l r I \ lbnrrlni)

II y>r, PI:,": n A y c r f l o r : l o U1111:y ;:to,> I'CC I! x>y, Plrn; - 3 . orrn;l.>: om I::.Ib:v I \ ~ r ~ l ~ c c d

A modern yencrat ing un i t is a complex system comprising the generator stator winding, associated transformer and un i t transformer (if present), the rotor w i th its f ield winding and excitation system, and the prime mover w i th i ts associated auxiliaries. Faults of many kinds can occur wi:hin this syslem for which diverse forms of electrical and mechanical protection are

For HV generators, impedance is usually inserted i n stator earthing connection t o l imit the magnitude earth fault current. There is a wide variation i n the e: faul t current chosen, common values being:

1. rated current

2 . 2 0 0 A - 4 0 0 A (low impedance earthing]

3. IOA-20A (high impedance earthing)

The main methods of impedance-earthing a genet are shown i n Figure 17.3. Low values of earth ' current may l imit the damage caused from a faul t they simultaneously make detection of a fault tov the stator winding star point more difficult. Excel special applications, such as marine, LV generator normally solidly earthed t o comply w i t h s requirements. Where a step-up transformer is ap

the generator and the lower voltage winding transformer can be treated as an isolated system not influenced by the earthing requirements power system.

.... .....

la1 Oirccr carlhing

Typical scrring (%of carthing rcsisror raring)

10

5

-

o f the that is o f the

will7 n v C I C ~ f l c t l f relay

........... ig,,,r. i ? .:: :;:: :,.:.::. (.! .;:. :I 'I'

.. , . .: l ' An earthicg transformer or a series impedance can be

impedance. If an earthing transformer is ntinuous rating is usually in the range 5-

250kVA. The secondary winding is loaded with a resistor of a value which, when referred through the rransformrr turns ratio, wil l pass the chosen short-time earth-fault current. This is typically in the range of 5-20A. The resistor prevents the production of high transient overvoltages in the event of an arcing earth fault, which i t does by discharging the bound charge in the circuit Capacitance. For this reason, the resistive component of fault current should not be Icss. than the residual Capacitance current. This is the basis of the design, and in practice values of between 3-5 I,,, are used.

It is .important that the earthing transformer never becomes saturated; otherwise a very undesirable Condition of ferroresonance may occur. The normal rise

'

ofthe generated voltage above the rated value caused by a sudden loss of load or by field forcing must be

as well as flux doubling in the transformer point-on-wave of voltage application. 11 is

r..... ..........;.... p r . t ? A

sufficient that the transformer be designed to have a primary winding knee-point e m f . equal to 1.3 times the generator rated line voltage.

Failure of the stator windings or connection insulation can result in severe damage to the windings and stator core. The extent of the damage will depend on the magnitude and duration of the fault current.

The most probable mode of insulation failure is phase to earth. Use of an earthing impedance limits the earth fault current and hence stator damage.

An earth fauit involving the stator core results in burning of the iron at the point of fault and welds laminations together. Replacement of the faulty conductor may not be a very serious matter (dependent on set rating/voltage/construction) but the damage to the core cannot be ignored, since the welding of laminations may result in local overheating. The damaged area can sometimes be repaired, but i f severe damage has occurred, a partial core rebuild will be necessary. A flashover is more likely to occur in the end-winding region, where electrical stresses are highest. The resultant forces on the conductors would be very large and they may result in extensive damage, requiring the partial or total rewinding of the generator. Apart from burning the core. the greatest danger arising from failure to quickly deal with a fault is fire. A large portion of the insulating material is inflammable, and in the case of an air-cooled machine, the forced ventilation can quickly cause an arc flame to spread around the winding. Fire will not occur in a hydrogen-cooled machine, provided the stator system remains sealed. In any case, the length of an outage may be considerable, resulting in major financial impact from loss of generation revenue and/or import o f additional energy.

Phase-phase faults clear o f earth are less common; they may occur on the end portion of stator coils or in the slots if the winding involves two coil sides in the same slot. In the latter case, the fault wil l involve earth in a very short time. Phase fault current is not limited by the method of earthing the neutral point.

lnterturn faults are rare, but a significant fault-loop current can arise where such a fault does occur.

Conventional generator protection systems would be blind to an interturn fault, bu t the extra cost and complication of providing detection of a purely interturn fault is no t usually justified. In this case, an interturn fault must develop into an earth fault before it can be c!eared. An exception may be where a machine has an abnormally complicated or mult iple winding arrangement, where the probqbility o f an interturn fault might be increased.

To respond quickly to a phase fault w i th damaging heavy

- current, sensitive, high-speed differential protection is - normally applied t o generators rated in excess of 1 MVA. . - -- For large generating units, fast fault clearance will also '4

2 maintain stability of the main power system. The zone P - of differential protection can be extended to include an

associated step-up transformer. For smaller generators, L

IDMT/instantaneous overcurrent protection is usually the - 5 - only phase fault protection applied. Sections 17.5-17.8 .o -r--. detail the various methods that are available for stator

winding protection. - L

The theory o f circulating current differential protection is discussed fully in Section 10.4.

Stator - . - .- . .

1?'3 - A

High-speed phase fault protection is provided, by use of the connections shown in Figure 17.4. This depicts the derivation of differential current through CT secondary circuit connections. This protection may also offer earth fault protection for some moderate impedance-earthed applications. Either biased differential or high impedance differential techniques can be applied. A subtle difference w i th modern, biased. numerical generator protection relays is that they usually derive the differential currents and biasi'ng currents by algorithmic

i

calculation, after measurement of the individual q : secondary currents. In such relay designs, there is full.: galvanic separation o f the neutral-tail and terminal Q;.

secondary circuits, as indicated in Figure 17.5(a). This is not the case for the application of high-impedance differential protection. This difference can impose some special relay design requirements t o achieve s t a b i l i t y f ~ ~ , biased differential protection i n some applications.

.@ . ;-,4

.:,@ ;i>2 .,=.& ..w

The relay connections for this form of protection are shown in Figure 17.5(a) and a typical bias characteristic is shown in Figure 17.5(b). The differential current threshold setting I,, can be set as low as 5% o f rated :. generator current, to provide protection for as much of: the winding as possible. The bias slope break-point$& threshold setting I;, would typically be set to a value.?$, above generator rated current, say 12O01o, to achieve::?.

, ..& external fault stabil ity i'n the event of transient,{2 asymmetric CT saturation. Bias slope I;, setting would:?

- ! typically be set at 150%. :..>

c: :i., : ,.:.

This d~ffers from biased differential protection by manner in which relay stability is achieved for eXt faults and by the fact that the differential current be attained through the electrical connections secondary circuits. I f the impedance of each re Figure 17.4 is high, the event oC one CT bec saturated by the through fault cutrent (leadin!

-280-315 17/06/02 10~44 page 285 -

latively low CT impedance), wi l l allow the current from unsaturated CT t o flow mainly through the saturated rather than through the relay. This provides the uired protection stability where a tuned relay element

$4 is employed. I n practice, external resistance is added to the relay circuit io prwidc the necessary high impedance. The principle of high-impedance protection application is illustrated in Figure 17.6, together with a summary of the calculations required to determine ttie value o f external stabilising resistance.

i Hcalthy CT Saturated CT

*I L', = K V ,

wherc J.O<Krl .S Stabilising resistor, R,, limits spill currcnt to <I, lrclay sctting)

R,,= 5 - R R - I

whcn RE - r:lay burden

'. ' i n some applications, protection may be required to limit voltages across the CT secondary circuits when the differential secondary current for an internal phasc fault flows through the high impedance relay circuit(s1, but this is not commonly a requirement for generator differential applications unless very high impedance

ii.. . . relays .are applied. Where necessary, shunt-connected. . . . : . ..a . ,..,.l

. . . . ", . ..:: , .. non-linear resistors, should be deployed, as shown in : I

To calculate the primary operating current, the following expression is used:

I,, = N X (is, + nl,)

where:

lop = prima y operating current

N = CT ratio

lsl = relay setting

n = number of CT's in parallel with relay element

I, = CT magnetising currerft at V,

I, , is typically set to 5% of generator rated secondary current.

It can be seen from the above that the calculations for the application of high impedance differential protection are more complex than for biased differential protection. However. the ~rotect ion scheme is actually cuite simple and it bffers a high level of stability for through f a k and external switching events. 2 2

L

With the advent of multi-function numerical relays and 5 with a desire to dispense with external components; high -= impedance differential protection is not as popular as 2 biased differential protection i n modern relaying 9 practice. . . . . - . L . 0

. . . . . . . . . - . . .-

. . 2 9) ..,... ,.l :.. . - ., . :., ; ... . i . J i . . ....... !.. .-.

. . - G - i

The CT requirements for differential protection will vary .%

according to the relay used. Modern numerical relays E

may not require Ci's specifically designed for differential protection to IEC 60044-1 class PX (or BS 3938 class X). 3 However, requirements i n respect of CT knee-point 2 voltage will still have to be checked for the specific relays used. High impedance differential protection may be more onerous in this respect than biased differential protection.

Many factors affect this, including the other protection 1.7. functions fed by the CT's and the knee-point requirements of the particular relay concerned. Relay manufacturers are able to provide detailed guidance on this matter.

A common connection arrangement for large generators ;:: ..:::.. .:,:,-

is to operate the generator and associated step-up p . . . . . . . . . . . . .i:;.j:-:.':.?+.i ..... transformer as a unit without any intervening circuit $;:.i,:::': . . . '<i.:-.: - breaker. The unit transformer supplying the generator $i.:i;:;:::'&>. . . . . , ....

auxiliaries is tapped off the connection between :::;:.<' -:>I:.: . I- generator and step-up transformer. Differential f. ' .i: . .

protection can be arranged as follows.

chz.17-20-31 11/06/02 1 0 4 4 Page 206 &

- . . .:<:. . ' . . ,;. .. . . . . ,*,\>' . . . $>,$$. .+ <... .T:y<?$ ...

..... . . . ~ $ . j ~ ~ . ; ~ ~ : 17.6.1 Gencrato~.iSrcp-up Tra~isiorrner transformer rating is extremely low in relation to th . . . . . . . . . > ,, v,, . . . ,... i. : .: ,,. Dlffc-rcntial Protection generator rating, e.g. for some hydro applications. ~h ... ..

.' : ",. ,',' * ,. . ..c:~$~..~;: The generator stator and step-up transformer can be .. location of the third set o f current transformers

...: ::.: .. c.. %.a+-:,'. . . . . _ ~ ~ ~ . ~ i ~ ~ - ~ ~ protected by a single zone of overall differential normally on the primary side of the unit transformer.

... k:z:4>$ ;t. !...:1.+.,.. .., .,.. .%. protection (Figure 17.8). This will be in addition to located on secondary side of the unit transformer, th(

:Y:: .. ' . : ....:. :. differential protection applied to the generator only. The wnuld have-to- be of an exceptionally high ratio, : . . . . , - .< .. . current transformers should be located in the generator exceptionally high ratio interposing CT's would have.

... . neutral connections- and i n the -transformer : HV be used. Thus, the use of secondary side CTs is not to I ....

. .... connections. Alternatively, C rs within the HV . . recommended. Cne advantage is that unit transform

. switchyard may be employed if the distance is not faults would be' within the zone of protection of

, - technically prohibitive. Even where there is a generator generator. However, the sensitivity of the generat circuit breaker, overall differential protection can still be protection to unit transformer phase faults would

provided i f desired. considered inadequate, due to the relatively low rating

- - the transformer in relation to that of the generat . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 - U

Thus, the unit transformer should have its 0,

.u U .differential protection scheme. Protection for the u QJ Main - Generator transformer transformer is covered in Chapter 16, including methc 2 - .r 3/- \.....- ;-i-<y7-p!-;,~. ,\ ,'

for stabilising the protection against magnetising inn

L conditions.

-4 ..a C - 1 -Protcctcd zonc - - ! .....

.O ! busbars ; > .- ,...:E3{.; :).,r,' - . -- i.:c .*-. c.,

Id> 3 , . . 52t..%<.,-s x.>J-,i..: . :>. .j:;:>. < t i <

3 I - s - - . Ti Overcurrent protection of generators may take : 2 +: L : forms. Plain overcurrent protection may be used a;

I i I - . principle form of protection for small generaton,.

;: -4 A. back-up for larger ones where differer s...... . -

. . . . . . . . . . . . ... . . . .. . . . . . - . ' . . .- - - - - . protection. is used asthe primaty method of ge&i El

. ... E:

5qurc : 7.5: O,.rr:?:i :<?:rr~l<;t-i::n~rcrzi~i. stat0.i winding protection. Voltage dep;nc t r - . :~.i!cr<,cr;:;; Ji<<::m:i<nn a ' . ' . . ovekcurrent protection may tie applied where differel

protection isnot justified on larger generators, or w 2 - problems are met i n applying plain overcur C - The current transformers should be rated according to L protection. Section 16.8.2. Since a power transformer is included .r-

within the zone of protection, biased transformer Q differential protection, with rnagnetising inrush restraint ;,; r>,;2ir; c;c,,j .L:L:yrc!l:, .:! Tc:2zL; ah.: z

should be applied, as discussed in Section 16.8.5. C3 Transient overfluxing of the generator transformer may It is time-delayed plain overcu

arise due to overvoltage following generator load protection to generators. For generators rated less

rejection. In some applications, this may threaten the lMVA, this will form the principal stator wi'

. 172.. . , stability of the differential protection. In such cases. protection phase For larger gener .. 4 A

-:,:is:::.: consideration should be given to applying protection Overcurrent protection can be applied as remote ba . , .., ...,. . ...,pv.j* *&- . with transient overfluxing restraintlblocking (e.g. based ~rotection, to disconnect the unit from any uncl , . . . . ..-. ..z.'-.$' on a 5th harmonic differential current threshold). external fault. Where there is only one set of differ : Protection against sustained overfluxing is covered in main protection, for a smaller generator, the OverC

Section 17.1 4. protection will also provide local back-up protecti the protected plant, in the event that the protection fails to operate. The general princi~

. . . . . ! : .,!. ;, i.j,,,l - , ; ,,.. ,,,:,7-,Ll. (I;.:,, I . i . :, .,4 ,! - ,.!(.!;. setting overcurrent relays are given in Chapter 9.

.... . . . . . The current taken by the unit transformer must be In the case of a single generator feeding an i: . . . .

. . .... ..;_,; . . ,.,. allowed for by arranging the generator differential system, current transformers at the neutral end : 'e l ''

I . . protection as a three-ended scheme. Unit transformer machine should energise the overcurrent protect

. . current transformers are usually applied to balance the allow a response to winding fault conditions.

. . generator differential protection and prevent the unit characteristics should be selected to take into ;

. . transformer through current being seen as differential the fault current decrement behaviour of the ge

. : current. An exception might be where the unit with allowance for the performance of the ex

. . . . .- . . ,. , . :. . - - .*.: . - ..:. ' .-,qC/c ;& -T&*;; ;>ipiQi - I 1 6 . _/ N , t w . r k P r . t < r t i . m & , f . t . m . r i . a C

.z.; .L7;.ps.** 2G3y5..

- .... : z m I -.s- I . .

. . . .

+tern and its field-forcing capability. Without the provision o f fault current compounding from generator CT's, an excitation system that is powered from an wcitation transformer a t the generator terminals wi l l whibit a pronounced fault current decrement for a terminal fault. With failure to consider this effect, the potential exists for the initial high fault current to decay to a value below the overcurrent protection pick-up setting before a relay element can operate, unless a low current setting and/or time setting is applied. The protection would then fail to trip the generator. The settings chosen must be the best compromise between assured operation in the foregoing circumstances and discrimination with the system protection and passage of normal load current, but this can be impossible with plain overcurrent protection.

In the more usual case o f a generator that operates in parallel with others and which forms part o f an extensive interconnected system, back-up phase fault protection for a generator and its transformer will be provided by HV overcurrent protection. This will respond to the higher- level backfeed from the power system to a unit fault. Other generators in parallel would supply this current and, being stabilised by the system impedance, it wi l l not suffer a major decrement. This protection is usually a requirement of the power system operator. Settings must be chosen to prevent operation for external faults fed by .the generator. I t is common for the HV overcurrent protection relay to provide both time-delayed and instantaneous high-set elements. The time-delayed elements should be set to ensure that the protected items of plant cannot pass levels o f through fault current i n excess o f their short-time withstand limits. The instantaneous elements should be set above the maximum possible fault current that the generator can supply, but less than the system-supplied fault current in the event of a generator winding fault. This back-up protection will minimise plant damage in the event of main protection failure for a generat~ng plant fault and instantaneous tripping for an HV-side fault wil l aid the recovery of the power system and parallel generation.

The plain overcurrent protection setting diff iculty referred to in the previous section arises because allowance has to be made both for the decrement of the generator fault current with time and for the passage of full load current. To overcome the diff iculty of discrimination. the generator terminal voltage can be measured and used to dynamically modify the basic relay currentltime overcurrent characteristic for faults close to the generating plant. There are two basic alternatives for the application of voltage-dependent overcurrent Protection, which are discussed in the following sections.

* .................. -. . . . . . . . - . . r r u . r k P r . r r r r i , n W A w r . - , r i . m G - i J r ... -. ...

I

--

The choice depends upon the power system characteristics and level of protection to be provided. Voltage-dependent overcurrent relays are often found applied to generators used on industrial systems as an alternative to full differential protection.

Voltage controlled overcurrent protection has t w o timelcurrent ciiaracteristics which are selected according to the status of a generator terminal voltage measuring element. The voltage threshold setting for the switching element is chosen according to the following criteria.

1. during overloads, when the system voltage is sustained near normal, the overcurrent protection should have a current setting above ful l load current and an operating time characteristic that wi l l prevent the generating plant from passing current to a remote external fault for a period i n excess o f the plant short- time withstand limits " 9 - 5-*

2. under close-up fault conditions, the busbar voltage - .- must fall below the voltage threshold so that the second protection characteristic wi l l be selected. This is characteristic ihould be set to allow relay operation ' sg with fault current decrement for a close-up fault a t 5 .- the generator terminals or- a t the,HV- b u s b a ~ . T h e .~~,~,&; . . :~~: , :

..... 0 -; ,-.. .' . . protection . . . . . . . sh&d also . . t ime~jrade.. ' .with:~xteI??l~- . . . . . . 'i.=:;". 24y.-i: . . protection..~~&ie jy&-be.gdditiond i"fe&ds t o I ~ ~ ~ ~ ~ : ' - : , . . ~ ' ' - '

an external circuit. fault . that.ki l l . . . . assist with:gradi?g - .. '-. s:-:.g.: .&. . -,.,,. , .f.:.

Typical characteristics are shown i n Figure 17.9. -a =

- --. - - P . - ...... . . . . . . . . . . . . . . .... ................ 2-

Currcnr pick-up k v c l

"s Voltagc lcvcl

f:,r.;,r ! ; - 'V:~ll~!.~c c ~ ~ n l ~ ~ l l r d r d c ~ y c h o i c i i r ~ h l i c r .= . .<: . - <?:r

. ,,;,.,:. ,.,, ,< ~..-:,'.?~:#~ !: !. .:;..;.j/.fr, . [!-i;!. ( :., The alternative technique is to continuously vary the relay element ,pickup setting with generator voltage variation between upper and lower limits. The voltage is said to restrain the operation o f the current element.

The effect is to. provide a dynamic I.D.M.T. protection characteristic, according to the voltage at the machine

terminals. Alternatively, the relay element may be regarded as an impedance type with a long dependent time delay. In consequence, for a given fault condition, the relay continues to operate mnre or less independently of current decrement i n the machine. A typical characteristic is shown i n Figure 17.10.

5 2 V , Voltage level

Earth fault protection must be appl~ed where impedance earthing is employed that limits the earth-fault current to less than the pick-up threshold of the overcurrent andlor differential protection for a fault located down to the bottom 5% o f the stator winding from the star- point. The type of protection required will depend on the method of earth~ng and connection of the generator to the power system

A single direct-connected generator operating on an isolated system wil l normally be directly earthed. However, i f several direct-connected generators are

' 17*. . operated in parallel, only one generator is normally ... ... \! . . . .... earthed at a time. For the unearthed generators, a

. , t , . ........ . .:..i",':;,. simple measurement of the neutral current is not

~. . possible, and other methods of protection must be used. . The following sections describe the methods available.

With this form of protection, a current transformer in the neutral-earth connection energises an overcurrent relay element. This provides unrestricted earth-fault protection and 'so i t must be graded with feeder protection. The relay element will thereforfhave a zime- delayed operating characteristic. Grading must be carried out in accordance with the principles detailed in Chapter 9. The setting should not be more than 33°/~ of the maximum earth fault current of the generator, and a lower setting would be preferably, depending on grading

considerations.

This method is used i n the following situations:

a. direct-connected generators operating i n parallel

b. generators with high-impedance neotral earthin, the earth fault current being limited to a few ter of amps

c. installations where the resistance of the grour fault path is very high, due to the nature of t[ ground

In these cases, conventional earth fault protection described i n Section 17.8.1.1 is of little use.

The principles o f sensitive earth fault protection ; described i n Sections 9.17.1. 9.18 and 9.19. The ea: fault (residual] current can be obtained from residl connection of line CT's, a line-connected CBCT, or a 0 the generator. neutral. The latter is not possible directional protection is used. The polarising voltagt usually the neutral voltage displacement input to . relay, or the residual o f the three phase voltages, s. suitable VT must be used. For Petersen Coil earthin! wattmetric technique {Section 9.19) can also be usec

. For 'direct '&nnected. operating in . para - . directional'..&nsitive earth: fault :protection. may

necessary. This is to ensure that a faulted ge&rat~r be tripped. before there is any ossibi l i ty of the:+ ~ "e rcu r ren t protection tripping a parallel he; generator. When being driven by residually-conne phase CT's, the protection must be stabilised ag; incorrect tripping with transient spill current in thee of asymmetric CT saturation when phase faul magnetising inrush current is being passed. Stabil techniques include the addition o f relay ci impedance and/or the application of a time delay. W the required setting o f the protection is very lo comparison to the rated current of the phase C would be necessary to employ a single CBCT for the fault protection to ensure transient stability.

Since any generator in the paralleled group m: earthed, all generators will require to be fitted wit1 neutral overcurrent protection and sensitive direc earth fault protection.

The setting o f the sensitive directional earth protection is chosen to co-ordinate with ger differential protection andlor neutral v displacement protection to ensure that 95% of thc winding is protected. Figure 17.11 illustrat, complete scheme, including optional blocking where difficulties i n co-ordinating the generat downstream feeder earth-fault protection occur.

)-315 17/06/02 10:46 Page 285

As the protection is still unrestricted, the voltage setting o f the relay must be greater than the effective setting o f any downstream earth-fault protection. It must also be

I I time-rirlavrri tn rn-nrriinatr wi th c ~ r r h nrnt r r t inn .......... ,-- ........................ '. .......... Sometimes, a second high-set element with short time delay is used to provide fast-acting protection against major winding earth-faults. Figure 17.12 illustrates the possible connections that may be used.

.: 3 . . . . . - i-

; figorc 77. ll: CC~??M):C.~S;;~ rcrr:.?-c?uli c,

pr8>:wrifir; SCIICV~C :CI: , ; , :cc I -~- , ; , I : ;~ ,~ .~c c o~nrra!:lrs :),8eroi;.za . ir: . 13;;ruiir.i ..

;z

For cases (b) and (c) above, it is not necessary t o use a = directional facility. Care must be taken t o use the correct E:

RCA setting - for instance if the earthing impedance is @ Ocrivcd from phasc ncutral voltagcs 2 mainly resistive, this should be 0". On insulated or very @ Measurcd from carth impcdancc . &

I 1..:..'

.,,high impedance earthed systems, an RCA o f -90" would @ Mcasurcd from brokcn dclta VI -L -. . 0

. . . . . . . . -. :,'?-be . . :used, as the .earth fault current is -predominately . -. ..- . .=.'. -. . - . . . . . ?,w,r< 17. 1.:: ?:<!i,fr": b.:,j:,>:c <:::;::;<?:c;e!!!

. . .u

,- " -..:;<. ,..L .;. 7 , : C, -2: -. . . . j . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . : = . :.:~irectional . - sensitive earth-fault protection can also be . .

used for detecting winding earth faults. I n this case, the As noted in Section 17.2, a directly-earthed generator- % . relay element is applied to the terminalsof the generator transformer uni t cannot interchange zero-sequence 2

and is set to respond t o faults only within the machine current with the remainder o f the network, and hence an L . 0

windings. Hence earth faults on the external system do earth fault protection grading problem does not exist * e

not result in relay operation. However, current flowing The following sections detail the protection methods for k .,,

from the system into a winding earth fault causes relay the various forms of impedance earthing of generators. E : . C,

operation. It will not operate on the earthed machine, so . . . . , . ... ..I. _ . . . . . . . . . : . . . < .- u that other types of earth fault protection must also be

1 applied. All generators must be so fitted. since any can be operated as the earthed machine. A current transformer mounted on the neutral-earth 17 77.13, 7 :? ;:r.,l:..:: !,(!';: . . . . . . . . . . . . . . . . conductor can drive an instantaneous and/or time

. . delayed overcurrent relay element, as shown in Figure

In a balanced network, the addition of the three phase- 17.13. I t is impossible to provide protection for the whole earth voltages produces a nominally zero residual of the winding, and Figure 17.13 also details how the

. voltage, since there would be litt le zero sequence voltage percentage of winding covered can be calculated. For a Present. Any earth fault wil l set up a zero sequence relay element with an instantaneous setting, protection is system voltage, which wi l l give rise to a non-zero typically limited to 90% of the winding. This is to ensure residual voltage. This can be measured by a suitable that the protection wi l l not maloperate wi th zero relay element. The voltage signal must be derived from sequence current during operation of a primary fuse for a

........ a VT that is suitable - i.e. it must be capable of W earth fault or with any transient surge currents that . ..... .

. , -. - . . . . . transforming zero-sequence voltage, so 3-limb types and could flow through the interwinding capacitance of the ..,,.,... ........ . .

I ,

those without a primary earth connection are not step-up transformer for an HV system earth fault. .: . ; . .-"?.;: .- ,,- . . . . \.'.. . - . -:;;.; suitable. This unbalance provides a means of A time-delayed relay is more secure i n this respect, and if ,.; ...

--.r-r detecting earth faults. The element be may have a ~ t t i n g to cover 9% of the stator winding. . - ,,. . ' . - . ... sfl 'nsensitive third harmonic voltages that may be Since the generating units under consideration are usually

... Present in the system as these will large, instantaneous and time delayed relay elements are ,,-- i

. - .

Chap11-280-315 11 /06 /02 1 0 : 4 6 P a g e 2 9 0 I . . ,:. . , .., . . . . - ...... .: % ....... * . .:~.'<,;'<,7:.,. .+,.., .. - . . . . . . . ...... <.. . :': ':. .!. . . . .... .: . . -.. r:.:. . . . . . . . . . . . >.. i;i: .:." ,. ..,.. ,::,,>c .., : \ . ..

,;+&;:$ >?\&? ,;.,..: . : y v : * . "r?":.!.., .. :_ -,*. ..> ..: !..$.,. > z , . . ..-,.:*>:,,:*..;. .,.. ! . , ......... , .. .... . often applied, with settings of 10% and 5% of maximum

. ' " ,..? ,.+&. -:!,','..:. . x 2 : .,Y, , .... .".. . ,,~~:,z&&;;g~id;~ earth fau It current respectively; this is the optimum : &*,3,$$3: ,*:,** y:l,,w

...... : compromise in performance. The portion of the winding ..& .z,. .... :, .>' .. :..-c<. .'- . : ...v. ;',:.

@ left unprotected for an earth fault is at the neutral end. :

.: ! "" 2 % ..-., C.,?.A,: -.:>::?~..,.:~;i...:,.-.. .i.::::$,:<, 2 +.:+.. Since the voltage t o earth at this end of the winding is : .; > . , .. , . ... .::< <.<, . '.;a-. ........... 2%: . ,.. low, the probability of an eartn fauit occurring is also lo^. . . . . . ~ . . ; . . . ............ : I- Hence additional protection is often not applied.

I k .: .. ............................... . . ................. I -v !. , i

,... / ,* ., . , ........ 1 2 .. ........................ + . . : -*- i : I . .

T ! (a) Protection using a currcnt clcmcnt i - ,.

. . . . . . . . . i 0 I - U

)..

u U

j *;. P -

=4 - - 1, W - 6 2 L I ( R - 7-71 0

I...., '2, ..-.. - -

C-

2 %co~rwd - (I-omic 1 x 1100% .- (bl Protection uring a voltagc clcmcnt %C :.c -- h ...-

I C.', .. . ., . . . . i ...- .. D gcncrator stator winding using a currcnt clcmcnt .T. x

. . . . U - . ?b;i:< ? I.?f;: G:zni:fcr kl.!i::!:nc; r.afrh-bup.

. . . . . . . . . - . . .......... .:...,:i. ..... ,, . . .w%... .... :. .-*. -3, :rc~$:c:?.?;~:&hh& .... . .2 F;q,,r< I?.?:;: €<,::I, I">!< ,>!o;?<l;cc c i l:!<h-,c5::!::7:? , .- . . - .. ,.

QJ : . .--b

ednhea $c?::z ivz:d:~~r 2...<::%?..?s : s : z z %-t;rrc,?r :!<.-:.:i . . - 2

. - . . ..\ . ',' j- . 2 ' . . .2; .

I _ . _ . . . . . . I . . . . . . . . . . . .,r

. . . . ... u .- : :% , . . . . . ,(. . . . . . . ..*$ .. . - . 2 ., . . . .,.. .' 1 ." .>.'. 'P"ei - .-,i . . . . . . . . . c M

1, Earth fault protection can also be provided using a voltag

In this arrangement, shown in Figure 17.14(a), the measuring element in the secondary circuit instead. ;T. generator is earthed via the primary winding of a setting considerations would be similar to those for:$

0 r distribution transformer. The secondary winding is fitted current operated ~ ~ o t e c t ~ o n * but transposed to voltat

with a loading resistor to l imit the earth fault current. The circuit diagram is shown in Figure 17.l4(b). . ;

An overcurrent relay element energised from a current Application of both voltage and current opera. transformer connected in the resistor circuit is used to elements to a generator with distribution transfon

17.0 measure secondary earth fault current. The relay should earthing provides some advantages. The curr .; ,,,;., ,;: ..;.> : ., . . . . .

j ,, '.., . have an effective setting equivalent to 5% of the operated function will continue to operate i n the ev <> ,;,;;..$?,. ;:.

‘ . . .,;,. ...ie+;>::Gc. - < . . maximum earth fault current at rated generator voltage, of a short-circuited loading resistor and the volt . . . ..:. . in order to protect 95% of the stator winding. The relay protection still functions in the event of an OF . . . . . . . . . .

- , . * .: ... element response to third harmonic curre_nt should be circuited resistor. However, neither scheme will ope .. , , _ . . I . . . limited to prevent incorrect operation when a sensitive i n the event of a flashover on the primary terminal

........ . . . . ,;- 9.'. . .... ,*.* ... . . . setting is applied. the transformer or of the neutral cable between

generator and the transformer during an earth faul As discussed in Section 17.8.2.1 for neutral overcurrent CT could be added in the neutral connection closet, protection, the protection should be time delayed when generator, to energise a high-set overcurrent elerne a sensitive setting is in order to prevent detect such a fault, but the fault current pro' maloperation under transient conditions. It also must high enough to operate the phase differ< grade with generator VT primary protection (for a, VT protection. primary earth fault). An operation time in the range . . .. :; .. ,., ....;. ,.';., .:. . . " ::: ,.,.;. . ., . . . . ... , , 0.5s-3s is usual. Less sensitive instantaneous protection can also be applied to provide fast tripping for a heavier This can be applied in the same manner as for c earth fault condition. connected generators (Section 17.8.1.3). The

. - . . . . . . . . . . . . . . . . . . . ....- 1 9 0 . . . N * t r * . l P r . r < r l i . . U A . l . - a r i . m C.

: :

-280-315 17/06/02 10:46 Page 291

rence is that 'the are no grading problems as the protection is inherently restricted. A sensitive setting .

! can therefore be used, enabling cover of up to 95% of the stator winding t o be achieved.

- 17.t3.3 Rcs:rir';ccl Ear l ! i F:i~l: P~.nicc::ic~$

This technique can beused on small generators not fitted with differential protection to provide fast acting earth fault protection within a defined zone that encompasses the generator. It is cheaper than ful l differential protection but only provides protection against earth faults. The principle is that used for transformer REF protection, as detailed in Section 16.7. However, in contrast to transformer REF protection, both biased low- impedance and high-impedance techniques can be used. .-,q.; : i . ' . . . ! / ., ......... !'<;--:": .... ".":' ,I:;.:!.,. L::+>:: : : . .:..;:<. ..

This is shown in Figure 17.15. The main advantage is that the neutral CT can also be used in a modern relay to provide conventional earth-fault protection and no external resistors are used. Relay 'bias is required, as described in Section 10.4.2, bu t the formula for calculating the bias is slightly different and also shown in Fiqure 17.15.

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . ,---. Phasc CT ratio 100011 . .

\ :.._--_!har.cA

l1 I ,

3 IN

(highrst of 1,. IS. ICJ +(INx scoiina.foctorJ I,,,, - 2

nrurral CT ratio 200 u.hrrr scnlit~g factor - phnriTT - -

1000 - 0.2

The initial bias slope is commonly set to 0% to provide maximum sensitivity, and applied up to the rated current of the generator. I t may be increased to counter the effects of CT mismatch. The bias slope above generator rated current is typically set to 150% of rated value. The initial current setting is typically 5qo of the minimum earth fault current for a fault at the machine terminals.

....... * 7 q . p ; : , , , : . ...., .... ?.. - !. .<..:. ..... 1 8 , , . I , , . :,. ::: :.!.<::::,,::.:.#c. - The principle of high impedance differential protection is given in Chapter 10 and also described further in Section 17-52. The same technique can be used for earth-fault

CT in the neutral connection. Settings of the order of 5010 :-: 2-i.;: . . ,..-. .-A + *.-e .a,. :.&+:w,

of maximum earth fault current at the generator ~sm. I -.-. .-.- ' terminals are typical. The usual requirements i n respect @+-+ ?:.$-3. ;*: of stabilising resistor and non-linear resistor to guard

F-+., *:%-?.c: against excessive voltage across the relay must be taken, 2; ;y;:<.-

$$*$>, where necessary. g , :~ . : , ... i - ... . . . . . . &:. !$.

>.."<.-:<6--. wrtr .>.- ..... . . . -\,;..\,. .. i ; 8 . > E,>,:i\l* i:<<j;<:.<;;.,:j,> ;Q; . . . : : . -v .... .

. . . .:.:.:"6..

. . . . . ;i.l.c.'..: . ..: - . . . . . : .,. . . . : .:, ,, ..'?Z

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. :... All of the methods for earth fault protection detailed so

. . -i,.i . . ...... % :...

far leave part of the winding unprotected. In most cases, ,.:::&. . .

this is of no consequence as the probability of a fault o

occurring in the 5010 of the winding nearest the neutral :.:'?:$%'' . .

connection is very low,due to the reduced phase to earth 2 . . r. 0 . .

voltage. However, a fault can occur anywhere along the ::-

n, stator windings in the event of insulation failure due to localised heating from a core fault. In cases where .. ' 2 - protection for the entire winding is required, perhaps for 2 alarm only, there are various methods available.

. .

s . .

.f= ; i . : . . . . . 0

One method is to measure the internally generated third L harmonic voltage that appears across the earthing . sl. impedance due to the flow of third harmonic currents :.":c

.-L' . through the shunt capacitance b f the windings : . 2 . . . ,-

etc. When a fa'ult occurs in.the p a r t of the stator G .r winding nearest the neutral end, the third harmonic %

voltage drops to near zero, and hence a relay element r: that responds to third harmonic voltage can be used to

0 detect the condition. As the fault location moves +

progressively away from the neutral end, the drop in 2 third harmonic voltage from healthy conditions becomes less, so that at around 20-30010 of the winding distance, it no longer becomes possible to discriminate between a healthy and a faulty winding. Hence, a conventional earth-fault scheme should be used in conjunction with a 17 third harmonic scheme, to provide overlapping cover of the entire stator winding. The measurement o f third harmonic voltage can be taken either from a star-point VT or the generator line VT. In the latter case, the VT must be capable of carrying residual flux, and this prevents the use of 3-limb types. I f the third harmonic voltage is measured at the generator star point, an undewoltage characteristic is used. An ovewoltage characteristic is used i f the measurement is taken from the generator line VT. For effective application of this - :

. . form of protection, there should be at least 1010 third :-.-.;..

harmonic voltage across the generator neutral earthing i..::; .. ::

impedance under all operating conditions. . :..,: :, . -,.:.. ; .... . , .

A problem encountered is that the level of third '

harmonic voltage generated is related to the output of the generator. The voltage is low when generator output - * -

-315 17/06/02 10:46 Page 292 + is low. In order to avoid maloperation when operdting at low power output, the relay element can be inhibited using an overcurrent or power element (kW, kvar or kVA) and internal programmable logic.

. . . . . . . . . . . . . . . . , , .(,. > ," ; y,<?,,;..; LS2 %j:;<:;>; :,.>f.:j<>,:..., , ........ , 9 . :.' '1

Another method for protecting the entire stator winding of a generator is to deploy signal injection equipment to

I inject a low frequency voltage between the stator star

I point and earth. An earth fault at any winding location i will result in the flow of a measurable iniection current

to cause protection operation. This form of protection can provide earth fault protection when the generator is at standstill, prior to run-up. It is also an appropriate method t o apply to variable speed synchronous

0 -- machines. Such machines may be employed for variable - speed motoring in pumped-storage generation schemes

)r . .. or for starting a large gas turbine prime mover. - Is, L C, .I..... . . - ; ': ,:

.. . . . . - , , . : >.>. : - i .a Overvoltages on a generator may occur due t o transient

surges on the network, or prolonged power frequency - overvoltages may arise from a variety of conditions.

z- Surge arrestors may be required to protect against . transient overvoltages, but relay protection may be used 0

to protect against power frequency overvoltages. *

. A sustained overvoltage condition should not occur for a - - Q mach~ne with a healthy voltage regulator, but i t may be

caused by the fol!owing cont~hgencies. "ct E c: a. defective operation of the automatic voltage r, 0

regulator when the machine is in isolated operation .-. 2 b. operation under manual control with the voltage C) .-. .r

regulator out of service. A sudden variation of the Q, load, i n particular the reactive power component. u will give rise to a substantial change i n voltage

because of the large voltage regulatinn inherent in a typical alternator . 17.-

. . . ,.. c. sudden loss of load (due to tripping of outgoing . . . . . . . : . . . . . ?

feeders, leaving the set isolated or feeding a very small load) may cause a sudden rise in terminal voltage due

. . to the trapped field flux and/or overspeed

Sudden loss of load should only cause a transient overvoltage wh~ le the voltage regulator and governor act to correct the situation. A maladjusted voltage regulator may trlp to manual, ma~ntalnlng excitation at the value

..< >' /.

, . . ..... .. \

prior to load loss while the generator supplies litt le or no d':::.!;':, . ,.I". ...... .!. load. The terminal voltage will increase substantially, . . . . . . - .. ..... 2,.. . <:7.:,:; ;i and in severe cases i t would be limited only by the

"'. B'.'.. .:. . ... . saturation characteristic of the generator. A rise in speed ,.: -.,: ,.;,. ., I .. - ,. ,

, .. , simply compounds the problem. I f load that is sensitive >- . ........ . . . , . . . to overvoltages remains connected, the consequences in ... ... ... terms of equipment damage and lost revenue can be . a - . '- , A,,. severe. Prolonged overvoltages may also occur on

For these reasons, it is prudent to provide powerx frequency overvoltage protection, in the form of a time- delayed element, either IDMT or definite time. The time *; . delay should be long enough to prevent operation during l%; .~.- normal regulator action, and therefore should take ;V account of the type of AVR fitted and its transient .:;,

2;;.

response. Sometimes a high-set element is provided as j - .. .>.,

well, wi th a very short definite-tirne delay !?+

instantaneous setting t o provide a rapid trip in extreme<:$ circumstances. The usefulness of this is questionable ford generators fitted with an excitation system other than static type, because the excitation wil l decay in$ accordance with the open-circuit time constant of the;:: field winding. This decay can last several seconds. The-j relay element is arranged to trip both the main circuit, breaker (if not already open) and the excitation; trippingL! the main circuit breaker alone is not sufficient. . - I s . A .

- - .+'

' 5 :

. . . , ii

.%

Undervoltage protection is rarely fitted to generators. l t is sometimes used as an interlock element for anothe protection function or scheme. such as field failu.6; protection or inadvertent energisation protection,.+yheg the abnormality to be detected leads -directly$ ...

. -. . . . ... indirectly to an undervoltage condition. . .-. -, q

... -.. ...

A transmission system unde~ol tage condition may arix when there is insufficient reactive power generation to maintain the system voltage profile and the conditior must be addressed to avoid the possible phenomenon system voltage collapse.

However, i t should be addressed by the deployment o 'system protection' schemes. The generation should no be tripped. The greatest case for undervoltage protectio being required would be for a generator supplying a isolated power system or to meet Utility demands fl connection of embedded generation (see Section 17.21

In the case of generators feeding an isolated systei undervoltage may occur for several reasons, typica overloading or failure of the AVR. In some cases. t performance of generator auxiliav plant fed via a u transformer from the generator terminals could adversely affected by prolonged undervoltage.

Where undervoltage protection is required, it sho comprise an undervoltage element 'and an associa time delay. Settings must be chosen to a\ maloperation during the inevitable voltage dips du, power system fault clearance or associated with m1 starting. Transient reductions in voltage down to 80' less may be encountered during motor starting.

7-280-315 17/06/02 10:46 Page 2Sf -

-

, . ;7.!1 LOV.; FOR;hJ;;RC F-<,'>;ERj~Fb~E:t5z 7 - 1 ---.' PC'. :: Y ~ J , (-(.-Ji[).?.i

,Low forward power or reverse power protection may be required for some generators to protect the prime mover. Parts o f the prime mover may not be designed to experience reverse torque or they may become damaged throuqh continued rotation after the prime mover has suffered some form o f failure.

Low forward power protection is often used as an interlocking function to enable opening of the main circuit breaker for non-urgent trip< - e.g. for a stator earth fault on a high-impedance earthed generator, or when a norinal shutdown o f a set is taking place. This is to minimise the risk o f plant overspeeding when the electrical load is removed from a high-speed cylindrical rotor generator. The rotor of this type o f generator is highly stressed mechanically and cannot tolerate much overspeed. While the governor should control overspeed conditions, it is not good practice t o open the main circuit breaker simultaneously with tripping of the prime mover for non-urgent trips. For a steam turbine, for example, there is a risk o f overspeeding due to-energy -storage i n the trapped steam, after steam vaive tripping,

:.:.orliri the.everlt that the steam valve(s1 do not fully close f o r some reason. For urgent trip conditions, such as

.:stator differential protection operation, the risk involved in simultaneous prime mover and generator breaker tripping must be accepted.

I I firclcrplosion due to unburnt fucl

Dicxl Engine i 5-25 Mechanical damaqc

(split shaft) Gas Tuhinc ........... gcarbox damage

>M4Lo ' (single *ah1

. . . . . . . . . . . . . . . . . - . . . . . . . . 0.2-2

(bladcs out of watcrl bladc and runncr Hydro .

>2 cavitation I (bladcs in water) .....

turbinc bladc damaqc Stcam Turbinc : 0.54 gcarbox damayc

.- on gcarcd XIS

. . . . . . . . . .

7lJh!< 17. 1 ; (i<-,:l.:::;<;~ ,cc<,><- e:wcr :,::sll;%.:c, -. . . . . . . . .

Reverse power protection is applied to prevent damage to mechanical plant items in the event o f failure of the prime mover. Table 17.1 gives details o f the potential problems for various prime mover types and the typical settings for reverse power protection. For applications

.. ... .-A .... -- . . . . . . . . . . . - . . . .

. . . . .

where a protection sensitivity o f better than 3% is required, a metering class CT should be employed t o avoid incorrect protection behaviour due to CT phase angle errors when the generator supplies a significant level of reactive power at close to zero power factor.

The reverse power protection should be provided with a definite time delay on operation to prevent spurious operation with transient power swings that may arise following synchronisation or in the event of a power transmission system disturbance.

........ . . - , ; :. :.. \!:..srr_,..,z: . -3kT?i:<-;S

A three-phase balanced load produces a reaction field that, to a first approximation, is constant and rot;;; synchronously wi th the rotor field system. unbalanced corfdition can be resolved into positive, negative and zero sequence components. The positive . sequence component is similar to the normal balanced . I- ,.

load. The zero sequence component produces.no main a armature reaction. . . L . a

'3 - > ' S

. . .-. , . . ; / . ; r . . ;:; :; ,:.:, ;:j;si. :...

u . . . ,. ......... ,,:,L:I'.C ct.i?i:.!?! A,. The negative sequence compdnent i j similar: to , the- v$<$$:<{2'

.~ . . ; ; .+y. . .~ ...:. *.,!<...&;.-:...>. .. positive . sequence .system,.-.except )that<Jhe -. cesulti"q, 1; .,=,,. u : . f.

reaction field rotates in -the.@p+ite direction t d t h 6 . d ; ~ - .:::.-, field system, Hence, a flux, is produced which cuts the:. -. 55 ..:':.: rotor at twice the rotational velocity, thereby inducing ..

double frequency currents in the field system and in the 'e rotor body. The resulting eddy-currents are very large .

and cause severe heating of the rotor. I- O

So severe is this effect that a single-phase load equal to the normal three-phase rated current can quickly heat the rotor slot wedges to the softening point. They may then be extruded under centrifugal force until they stand above the rotor surface, when it is possible that they may strike the stator core.

A generator is assigned a continuous negative sequence rating. For turbo-generators this rating is low; standard values of 10% and 15% of the generator continuous rating have been adopted. The lower rating applies when the more intensive cooling techniques are applied, for example hydrogen-cooling with gas ducts i n the rotor to facilitate direct cooling of the winding.

Short time heating is of interest during system fault conditions and it is usual i n determining the generator negative sequence withstand capability to assume that the heat dissipation during such periods is negligible. Using this approximation i t is possible to express the heating by the law:

where:

I Z R = negative sequence component (per unit of MCR)

t = time (seconds)

K = constant proportional to the thennal capacity of the generator rotor -

For heating over a period of more than a few seconds, it is necessary to allow for the heat dissipated. From a combination of the continuous and short time ratings, the overall heating characteristic can be deduced to be:

. ;3, ;\'tff G.5

sequence capacity and may not require protection.-,;@ Modern numerical relays derive the negative sequen~ $3 current level by calculation, with no need for speciiI circuits to extract the negative sequence component. A.'.& true thermal replica approach is often followed. to aliOw i..;$

> ....... . . for:

a. standing levels of negative sequence current below the continuous withstand capability. This has the effect of shortening the time to reach the cri t ial a

temperature after an increase in negative sequence current above the continuous withstand capability .'

b. cooling effects when negative sequence current levels are below the continuous withstand .

capability k u Q.l

The advantage of this approach is thz: cooling effects are - % where: modelled more accurately, but the disadvantage is that P -

= Ilegarive P I I a S e requetlce corrrilluous ratillg i l l the tripping characteristic m3Y not follow th; withstand

L per unit of MCR characteristic specified by the manufacturer accurately. ., U

The heating character;stics of various designs of generator are shown in Figure 17.16.

.......... -. ................... >

-1nd;rcctly coolcd (air)

lndircctly coolcd (H2) ; ...

350MW dircct coolcd j

660MW dircct coolcd i : - 1000MW d~rcct cooled,

Usmg I:t modcl

Usmg truc thcrmal modcl

The typical relay element characteristic takes the form of ;:

time to trip

Kg = negative sequence witltstand coeficient - (Figure 1 7.1 6)

IZcmr = generator maximum coittinuous Iz withstand

Iflc = generator rated primary curretlr

I , = CTpriinary current \I IN = relay rated current

. . . . Figure 17.16 also shows. the thermal replica time .. . . . . . . . . . . . . . .L. ' 0.01 . . characteristic described by Equation 17.1, frorn which it..

. . . - . . 0.01 0.1 1 - 10

Ncgativc scqucncc currcnl (p.u.1 will be seen that a significant gain in capability is

. . a : . ? . : ... achieved at low levels of negative sequence current' ....... . ). ..<:.:+. ... ....... , , , , , , , , , Such a protection element will also respond to phase-:

.. r i . /,g",c ,,7 j ( j . . ;,,; >,< - - .. > ....... ... ....

.:..::; .; . : . ( , , i f I earth and phase-phase faults where sufficient negative ..L.J?.&'L :'",,?>.;:;.

m l o r qcr;r~irluri sequence current arises. Grading with downstream. :;:*;w: q>'a;uS,

:.&-&! 1 I . iIj.7 N:~;J-.I,!~, I',;L:.V :,b::::.:.::i I: a . . . ~ i u n power system protection relays is therefore required. A, '!:<q ? . .:&s!: definite minimum time setting must be applied to the .: i ! L . . , , . . :

This protection is applied to prevent overheating due to negative sequence relay element to ensure .' : . .?(;:;> negative sequence currents. Small -salient-pole , .. grading. A maximum trip time setting may also be used

...... .: , .. ..... . :..;.:; s;.,.. ..,

generators have a P ~ ~ P ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Y larger negative to ensure correct tripping when xquenF

. . _%'.. *

-280-315 17/06/02 10:46 Page 295 -

rrent level is only slightly in excess of the continuous thstand capability and hence the trip time from the

ay depart significantly from the rotor

Accidental energisation of a generator when it is not running may cause severe damage to it. With the generator a t standstill, closing the circuit breaker results in the generator acting as an induction motor; the field winding (if closed) and the rotor solid ironldamper circuits acting as rotor circuits. Very high currents are induced i n these rotor components, and also occur i n the stator, with resultant rapid overheating and damage. Protection against this condjtion is therefore desirable.

A combination of stator undervoltage and overcurrent can be used to detect this condition. An instantaneous overcurrent element is used, and gated with a three- phase undervoltage element (fed from a VT on the generator side of the circuit breaker) to provide the protection. The overcurrent element can have a low setting, as operation is blocked when the generator is

,;.;ioperating normally. The voltage setting should be low ;"enough t o ensure that operation cannot occur for

-.' . . ,transient fautts. - A setting of about 50% of rated voltage . - :-,. is -typical. VT failure can cause maloperation o f the

. . protection, so the element should be inhibited under these conditions.

These conditions are grouped together because these problems often occur due to a departure from synchronous speed.

Overfluxing occurs when the ratio o f voltage to frequency is too high. The iron saturates owing to the high flux density and results in stray flux occurring in components not designed to carry it. Overheating can then occur, resulting i n damage. The problem affects both direct-and indirectly-connected generators. Either excessive voltage, or low frequency, or a combination of both can result in overfluxing, a voltage to frequency ratio i n excess of 1.05p.u. normally being indicative of this condition. Excessive flux can arise transiently, which

: is not a problem for the generator. For example, a . generator can be subjected to a transiently high power

. frequency voltage. at nominal frequency. immediately after full load rejection. Since the condition would not

2.: be sustained, it only presents a problem for the stability !. L!. . k - .. .- -..... -. .......... . . . . . : ~ ~ t v ~ r i ~ r . t r , r i , m u ~ . r , - a r i a * ~ . i , r .

of the transformer differential protection schemes applied a t the power station (see Chapter 16 for transformer protection). Sustained overfluxing can arise during run up, i f excitation is applied too early with the AVR in service, or i f the generator is run down, wi th the excitation still applied. Other overfluxing instances have occurred from loss of the AVR voltage feedback signal, due to a reference VT problem. Such sustained conditions must be detected by a dedicated overfluxing protection function that will raise an alarm and possibly force an immediate reduction i n excitation.

. .: . ., ' ,i..

...... Most AVRs' have an overfluxing protection facility - - < .;$>. ...-

.. . . . . ...,& ...... - ... included. This may only be operative when the generator ,.?, .;:. ..:. -r..... . -. .? , . . - . . ,.: is on open circuit, and hence fail to detect overfluxing . : ;s :~ . : . : . ,:.. . .

.,y:.:.h conditions due to abnormally low system frequency. " . .:.z

p..;~::*-.:. .' . ow ever, this facility is not engineered to protection z.$:.?~:.u.::;. ... : .... ..i. *,:,,. ,:- Q :: , .

relay standards, and should not be solely relied upon t o $;%;z' .,. r.1. ...

provide o v e k ~ u x i n ~ protection. A separate relay element Y':>& ' I -

is therefore desirable and provided i n most modern CI relays. E - ?.

I t is usual to provide a definite time-delayed alarm 5 . setting and an instantaneous or inverse time-delayed trip setting, to match the withstand characteristics o f t~

the protected generator and transformer. It is very important that the VT reference for overfluxing : -1:':i -

.

. . . . . . protection is not.the same as that.used.for the AVR. :. .- ....z... &, . : - .

W . ' :.: = w - . . . . . . . . . . . . . . ? . . : > : . ::<;. . . . . . . . . . . . - u -%

The governor fitted to the prime mover normally provides r protection against overfrequency. Underfrequency may occur as a result of overload of generators operating on 2 an isolated system, or a serious fault on the power 2 system that results in a deficit of generation compared to load. This may occur i f a grid system suffers a major fault on transmission lines linking two parts o f the system, and the system then splits into two. I t is likely that one part will have an excess of generation over load, 17 - and the other will have a corresponding deficit. Frequency will fall fairly rapidly in the latter part, and the normal response is load shedding, either by load shedding relays or operator action. However, prime movers may have to be protected against excessively low frequency by tripping of the generators concerned.

W ~ t h some prime movers, operation i n narrow frequency bands that lie close to normal running speed (either above or below) may only be permitted for short periods, -

together with a cumulative lifetime duration of .. ' . . .

operation in such frequency bands. This typically occurs ai,.:,.. . . . . . . . :

due to the presence of rotor torsional frequencies in such ~ ~ ~ ~ ; ~ . ....

frequency bands. In such cases, monitoring o f the period iij?.::: of time spent in these frequency bands is required. A :'. ,.. .::. .

special relay is fitted in such cases, arranged t o provide ' .

alarm and trip facilities i f either an inoividual or I- ,>-.

:hepl7-280-325 1 7 / 0 6 / 0 2 1 0 : 4 8 Page 2 9 6

cumulative period exceeds a set time. -

The field circuit of a generator, comprising the field winding of the generator and the armature of the exciter, together wi th any associated field circuit breaker if it exists, is an isolated d.c. c i rcu~t which is not normally earthed. I f an earth fault occurs, there will be no steady- state fault current and the need for action will not be evident.

Danger arises if a second earth fault occurs at a separate point in the field system, t o cause the high field current

= to be diverted, in part at least, from the intervening 0 -- turns. Serious- damage to the conductors and .possibly %.A

the rotor can occur very rapidly under these conditions. %.A

P - More damage may be caused mechanically. If a large portion of the winding is short-circuited, the flux may

L adopt a pattern such as that shown in Figure 17.17. The ... " L

attracting force at the surface of the rotor is given by: .=

produce a balancing force on this axis. The result is an unbalanced force that in a large machine may be o f the order o f 50-100 tons. A violent vibration is set up that may damage bearing surfaces or even displace the rotor by an amount sufficient t o cause it t o foul the stator.

. . , ;. . :,!. ; :<,<;;;<,! ;:: : >;-::;j;jit ;><<>f<~,,,:.;,jg.:

Two methods are available t o detect this type o f fau l t The first method is suitable for generators that incorporate brushes in the main generator field windina: The second method requires at least a slip-ring connection to the field circuit:

a. potentiometer method

b. a.c. injection method

. . . : . . ; ,.,:: .,,,, . . . . . . . ,, . ~ . ; !r:!.;,!>.!>,: . . . . . . . . . . .

This is a scheme that was fitted t o older generators, and it -is illustrated in Figure 17.18. An earth fault on the field winding w o u l produce a voltage across the relay, the maximum voltage occurring for faults at the ends of

3 B ' A the winding. = F=- c L 8rc A 'blind spot' would exist a t the centre of the field L I winding. To avoid a fault at this location re,mainipg.,,.,. i where: 'undetected., the tapping point dn the potentiometi$~~ %.A

2 A = area could be varied by a pushbut to~ o r switch:.. l~h%'i@l&j.*. . .

Q . setting is typically about 5% of the exciter.vol-tage.- ...::;:+; = . . . . . . . B = flux density :. ,- -. . *- ..... . . . . .. u .*:.

. .; 't 2 e - o Short Circt i i l .I, = 1, 0 E c2

U

17. [;?arc ; 7. IS: LI;;:: : U ! I I : p x : ~ c t t ~ ! ~ ~fi;&f ..

. . . . . . : . . . . . . . . . . . r . . -

,:ir8::,:: !~y?,):#:r!!;?;cc!,.r ?crno,i . .:.. ,. , . . . , . . , :.,

:.i

Two methods are in common use. The first is based on i

low frequency signal injection, with series filtering, as ::

shown in Figure 17.19(a). It comprises an injection::'. source that is connected between earth and one side the field circuit, through capacitive couplir~g and the.:; measurement circuit. The field circuit is subjected to anj i

F,qt,,c T ? . : 7: .F!"Y ,fr>lr,r>.,!~r- 4,: r,..:,;, : alternating potential at substantially the same level;l ....

, .,- wirh put:!~! +,.onrJl.cg thorl r,trv;l

. . ., .. throughout. An earth fault anywhere in thc ficld system':

I t will be seen from Figure 17.17 that the flux is will give rise to a Current that is detekted as an;? concentrated on one pole but widely dispersed over the equivalent voltage across the adjustable rcsistor by the.$

other and intervening surfaces. .[he attracting force is in relay. The capacitive coupling blocks the normal d.~. fie143

consequence large on one pole but very weak on the voltage, preventing the discharge of a large d i r c ~ e

opposite one, while flux on the axis will current through thc protection scheme. Thccombina t i~?~~ . . . x! ... C

. i i3. ... ' . . c-. '.

:g . . ; l: ............. ............................. .I ,r ... . . . -!I:.:;; . 1 9 6 - ,

z .. ,':, P.,.,... :. ......... ......_......A__- I

~ 8 l w ~ ' r k P r , l r < , i . q U A m r , r . r i , # C w i l t ..f.5. ...

,.,+.-!?.&$%. : L:-.:'.;r..*... : ,.'.i.'..;.f~;l ..%. ....... .', ,,, ;;:->-...>. .? .~~*:>;+?g, LC. ,- <.b, . .

+.: . . :. ..' .. . . . .

1-280-315 17/06/02 10:48 Page 297 -

of series capacitor and reactor forms a low-pass tuned

I circuit. the intention being to filter higher frequency rotor currents that may occur for a variety of reasons.

Other schemes are based on power frequency signal injection. An impedance relay element is used, a field winding earth fault reducing the impedance seen by the relay. These suffer the draw back of being susceptible to

1 static excitation system harmonic currents when there is significant field winding and excitation system shunt - capacitance.

Greater immunity for such, systems is offered by capacitively coupling the protection scheme to both ends of the field winding, where brush or slip ring access is ~ossible (Figure 17.19(b)).

The low-frequency injection scheme is also advantageous in that the current flow through the field winding shunt capacitance will be lower than for a power frequency scheme. Such current would flow through the machine bearings to cause erosion of the bearing surface. For power frequency schemes, a solution is to insulate the bearings and provide an earthing brush for the shaft.

;;;rator I winding

I .

L.F. injection

(a1 Low (rcqucn& a.c. voltage injection - currcnt mcarurcmcnt

17.1 5.2 Rotor Earth Faul? Proreaior? For 6rush;czs Gcr-erato:s

A brushless generator has an excitation system consisting of:

1. a main exciter with rotating zrmatzre and stationary field windings

2. a rotating rectifier assembly, carried on the main shaft line out

3. a controlled rectifier producing the d.c. field voltage for the main exciter field from an a.c. source (often a small 'pilot' exciter)

Hence, no brushes are required in the generator field circuit. All control is carried out in the field circuit of the main exciter. Detection of a rotor circuit earth fault is .j;;+zS;:-. still necessary, but this must be based on a dedicated . : - $ ~ ~ . ~ ~ $ ; ? ~ rotor-mounted system that has a telemetry link to .!.?p*y$@;: provide an alarmldata. 'a - ' ' .'

L ...: 'PI" ' . CI %=

. . . . . . . . j . : : , . : , ,,L..!.>. :;!.#~:.::;! !:. , .-: . .\:. L ,.... <... . As detailed in Section 17.15 a shorted section of field

5 E:

winding will result in an unsymmetrical rotor flux 2 b .. pattern and in potentially damaging rotor vibration. ... ,. . . .

~e tec t i on of such an electrical fault is possible using a -;-. & . -..: . . *.. , -

probe consisting of a coil placed i n the airgap. The flux. -1: .-ct. . . . . C - ' .

pittern i f t k positi"e and negative poles is me&ured". , 2 .

1 C ' and any significant difference in flux pattern between .".- PI

the poles is indicative of a shorted turn or turns. ' U ?J 1

Automated waveform comparison techniques can be t, .

used to provide a protection scheme, or the waveform ' 1 0 can be inspected visually a t regular intervals. An

immediate shutdown is not normally required unless the 2 effects of the fault are severe. The fault can be kept under observation until a suitable shutdown for repair 5 can be arranged. Repair will take some time, since it

0

means unthreading the rotor and dismantling the winding. - 17- Since short-circuited turns on the rotor may cause damaging vibration and the detection of field faults for all degrees of abnormality is difficult, the provision of a vibration a detection scheme is desirable - this forms part of the mechanical protection of the generator.

A short-circuited diode will produce an a.c. ripple in the exciter field circuit. This can be detected by a relay monitoring the current in the exciter field circuit, however such systems have proved to be unreliable. The relay would need to be time delayed to prevent an alarm being issued with normal field forcing during a power system fault. A delay of 5-10 seconds may be necessary.

i C

- 1 9 7 - , ......... .. ,

+ . ,

. , .,.,

Fuses to disconnect the faulty diode after failure may be fitted. The fuses are of the indicating type, and an inspection window can be fitted over the diode wheel t o enable diode health to be monitored manually.

P. dinde that fails open-circuit occurs less often. I f there is more than one diode in parallel for each arm of the diode bridge. the only impact is to restrict the maximum continuous excitation possible. If only a single diode per bridge arm is fitted, some ripple will be present on the main field supply but the inductance of the circuit will smooth this to a degree and again the main effect is to

I restrict the maximum continuous excitation. The set can be kept running until a convenient shutdown can be

' arranged. 0 - w +r L. 9, 17.I 5.5 i i c ' c s!,rl.?fiy;;o:.i 0

- 1 '

The need t o rapidly suppress the field o f Ti'machine in which a fault has developed should be obvious, because as long as the excitation is maintained, the machine will feed its own fault even though isolated from the power system. Any delay in the decay o f rotor flux wi l l extend the fault damage. Braking the rotor is no solution, because of its large kinetic energy.

- . - The field -w ind ing current cannot be interrupted . .

.;: - ~n 's tantaqeoui l~ as i t fidws i n a highly inductive circuit. : - Consequently, the flux energy must b e ' dissipated'.to

. ..i?; '.prevent' an excessive- inductive voltage rise in the field .:: circuit. For machines of moderate size, it is satisfactory -,: to open the field circuit with an air-break circuit breaker

without arc blow-out coils. Such a breaker permits only a moderate arc voltage, which is nevertheless high enough t o suppress the field 'current fairly rapidly. The inductive energy is dissipated partly i n the arc and partly in eddy-currents in the rotor core and damper windings.

With generators above about SMVA rating, i t is better t o provide a more definite means o f absorbing the energy without incurring damage. Connecting a 'field discharge resistor' i n parallel with the rotor winding before opening the field circuit breaker will achieve this objective. The resistor, which may have a resistance value of approximately five times the rotor winding resistance, is connected by an auxiliary contact on the field circuit breaker. The breaker duty is thereby reduced to that of opening a circuit with a low L/R ratio. After the breaker has opened, the field current flows through the discharge resistance and dies down harmlessly. The use of a fairly high value o f discharge resistance reduces the field time constant t o an acceptably low value, though i t may still be more than onc second. Alternatively. generators fitted with static excitation systems may temporarily invert the applied field voltage to reduce excitation current rapidly to zero before the excitation system is tripped.

7.1 6 LcjsS i l F [_X::[';p,TigN ?g:)';Ei;;iQx.i

Loss of excitation may occur for a variety of reasons. i f . : the generator was initially operating at only 20%-3(&,, 1 of rated power, it may settle to run super-synchronously I

as an induction generator, at a low level of slip. I n doing !: so, it will draw reactive current from the power system . ' -

3,s

for rotor excitation. This form of response is particularlv ~ 2 z i . .'(:I.,

true of salient pole generators. In these circumstances, ;$ti: 6: .

the generator may be able to run for several minute- .<%-

without requiring to be tripped. There may be sufficient .:;$, time for remedial action to restore the excitation, but the '-:%. reactive power demand o f the machine during the failure may severely depress the power system voltage to an {.$

unacceptable level. For operation at high initial power &; output, the rotor speed may rise t o approximately 105% :$; of rated speed, where there would be low power output -$$ and where a high reactive current of up to 2.0p.u. may ,:$

. ., , ,. .

be drawn from the supply. Rapid .;automatic.'% disconnection is then required to protect the stator 3: windings from excessive current and to protect the rotor :-' from damage caused by induced slip frequency currents. '4:

.::*. The protection used varies according to the s.ize of i.2: . . ;.,. generator being protected. .... . - . -+:+. S -.;% r!

..::.-v On the smaller machines, protection again&.% ;$ asynchronous running has tended to be optional, but it$$ may now be available by default, where the functionality iz

, - is available within a modern numerical generator.:;d! protection package. I f fitted, it is arranged either to.:ii provide an alarm or t o trip the generator. If the .? generator field current can be measured, a relay element ;!; can be arranged to operate when this drops below a -: preset value. However, depending on the generator design and slze relative to the system, it may well be that the machine would be required to operate synchronously with l i t t le or no excitation under certain system- conditions.

The field undercurrent relay must have a setting below the minimum exciting current, which may be 8% of that. corresponding to the MCR of the machine. Time delay _ relays are used to stabilise the protection againsti maloperation in response to transient conditions and to!. ensure that field current fluctuations due to pole slipping do not cause the protection to reset.

I f the generator field current is not measurable. then the technique detailed in the following section is utilised.

For generators above about SMVA rating, protection against loss of excitation and pole slipping conditions is normally applied.

Consider a generator connected to network, as shown in Figure 17.20. On loss of excitation, the terminal voltage will begin to decrease and the stator current will increase, resulting in a decrease of impedance viewed frEm the generator terminals and also a change in power factor.

!.

A relay to detect loss of synchronism can be located at point A. I t can be shown that the impedance presented to the relay under loss of synchronism conditions (phase swingi~g or pole slipping) is given by:

!_. . I

O = n i ~ g l c by 11~11icll E(; 1cc~tl.c li,

I f the generator and system voltages are equal, thcabove expression becomes:

- (x, +x,4-~ , ) (1- ,co lO 2 ) .,

The general case can be represented by a system of circles with centres on the line CD; see Figure 17.21. Also shown is a typical machine terminal impedance locus during loss of excitation conditions.

field

The special cases of EG=Es and EG=O result in a straight-line locus that is the right-angled bisector of CD, and in a circular locus that is shrunk to point C, respectively.

When excitation is removed from a generator operating a r= synchronously the flux dies away slowly, during which period the ratio of is decreasing, and the rotor angle of the machine is increasing. The operating condition plotted on an impedance diagram therefore travels along 17. a locus that crosses the power swing circles. At the same time, it progresses in the direction of increasing rotor angle. After passing the anti-phase position, the locus bends round as the internal emf . collapses, condensing on an impedance value equal to the machine reactance. 'The locus is illustrated in Figure 17.21.

'The relay location is displaced from point C by the . . . . .' generator reactanceXG. One problem in determining the . : , . . . .

position of these loci relative to the relay location is that ..';..;j::i.i>: the value of machine impedance varies with the rate of :,:7:$,$$$:i:G..: ...... .-.., . slip. At zero slip XG is equal to Xd, the synchronous ;>!:$@&?$$;I:~ -..<z*&?zi'.;p. .. reactance. and at 10090 slip XG is equal to X ' j , the sub- : ; : i ~ ~ t ~ ~ g ~ ; ~ .

transient reactance. The impedance in a typical case has 7;-::Fi$y ,.,,.,

been shown to be equal to XId, the transient reactance, j:~?~$$+#~~: at 50% slip, and to 2X; with a slip of 0.33%. The slip ::-%&?$.$:::. likely to be experienced with asynchronous running is . :.'&&<$<:i

-,..I..&"'* -. ... i .-;: ,L>%...+ .,..-.i..!:.- . .,.. .. .,.., . >?

:;:s+<,:.,:&';;>:~: ............. .,;..;.. C

' 9 9 ' +* ..$;:f, - . "..<-..:.: 5;;; ;,;:.;tg ,.., ........ .-'. ... .. ,.: ';. " . . . . . ,?.,*,:.':: . ,- .. .,? ....<,,, ;?.,. .:ca51:~ ,:..

I' t

1s. low, perhaps 146, so that for the purpose o f assessing the

f :' power swing locus it is sufficient to take the value XG=2Xd.

;i '

ti This consideration has assumed a single value for XG. However, the reacranceXq on the quadrature axis differs from the direct-axis value. the ratio of Xd/Xg being known as the saliency factor. This factor varies with the

A slip speed. The effect of this factor during asynchronous operation is to cause XG to vary at slip speed. In

I consequence, the loss of excitation impedance locus 1

does not settle at a single point, but it continues to !

describe a small orbit about a mean point.- j L.. A protection scheme for loss of excitation must operate I . =t decisively for this condition, but its characteristic must t . .

0

;.:: -3 not inhibit stable operation of the generator. One limit 1: u of operation corresponds to the maximum cracticable Y-.

k; ; p rotor angle, taken to be at 120'. The locus of operation r. - >. : i: can be represented as a circle on the impedance plane.

g-.. as shown in Figure 17.22. stable operation conditions gI S lying outside the circle. g:,, - 5,: ... . ... .. . .

$<.. I - t<< IC +jA' Locus of conyant MVA

. .

, ... ._!. - , . . . . figvrc ; 7.2;: LC'.,;, <I/ ii!:li:i.?$ c>c!,v:!th! _ .o.::,

' ' , . . . . . I

,;,!,>:!',I;,,!,< C! s,.,:cc.,;,:<>"> , ? , : ;<I : ; , : , : . .

: .,<

.* .... . , . ..

< . .i.\ ... .

! ,.,<:.. ..,> . . -. On the~same diagram the full load impedance locus for . . . .:.. 5$-i,*.': . c ~ . : . ~ one per unit power can be drawn. Part of this circle .. ..

;<:.?A: *";:; represents a condition that is not feasible, but the point

$$% of intersection with the maximum rotor anqlc curve can ig+ ; v=: p+,, be taken as a limiting operating condition for setting

-.. & Q. impedance-based loss o f excitation protection. . "F kip; :$n ..9 rw:=-. ... *+ rgfy . 1 .;, -: [;.I; : ,q. , .; !-\. - . : . .. - . ! ' . . ; :. . . .. ' '.. ..: $$*$>:.

Figure 17.21 alludes to the possibility that a protection

. - - .. . . - -. . - -- . . . . - - - - -- . - -

. . -+

scheme for loss o f excitation could be based on impedance measurement The impedance characteristic must be appropriately set or shaped to ensure decisive operation for loss of excitation whilst permitting stable generator operation within allowable limits. One or two offset mho under impedance elements (see Chapter. 11 for the principles of operation) are ideally suited for providing loss of excitation protection as long as a generator operating at low power output (20-30%Pn) does not settle down to operate as an induction generator.The characteristics o f a typical two-stage loss of excitation piotection scheme are illustrated in Figure 17.23. The first stage, consisting of settings X,, and Xbl can be applied to provide detection of loss of excitation even where a generator initially operating at low power output (20-30%P,] might settle dowv to operate as an induction generator.

Normal machinc opcraring impcdancc

Pick-up and drop-off time delays t d l and tdo, are associated with this impedance element. Timer td , is used to prevent operation during stable power swings that may cause the impedance locus o f the generator to transiently enter the locus of operation set by Xbr However, the value must short enough to prevent damage as a result of loss of excitation occurring. If pole-slipping protection is not required (see Section 17.17.2). timer tdo, can be set to give instantaneous reset. The second field failure element, comprising settings Xbl , and associated timcrs IdI and tdo2 can be used to give instantaneous tripping follovring loss of excitation under full load conditions.

1 / . I ti.:? ~:O:Cf '~~2:1 S~l:!r,v:

The typical setting values for the two elements vary according to the excitation system and operating regimf of the generator concerned, since :hew affect th( generator impedance seen by the relay under normal an1 abnormal conditions. For a generator that is neve

ii0-315 17/06/02 l0:re page 301

-

*crated at leading power factor, or at load angles i n .! 7:!?.1 Protectio:~ usinq Rc-VC~SC Pov:r: Eic!-ynt e s s of 90" the typical settings are:

During pole-slipping, there will be periods where the impedance element diameter Xbl = Xd direction of active power flow will be i n the reverse

impedance element offset X,! = -0.5% direction, so a reverse power relay element can be used . tn detect this, i f not used for other purposes. However,

time delay on pick-up, t d r = 0.5s .- 10s since the reverse power conditions are cyclical, the element will reset during the forward power part of the time delay on drop.-off, tdo, = 02.

cycle unless either a very short pick-up time delay andlor , lf a fast excitation system is employed. allowing load a ,,itable drop-off time delay is used to eliminate

of up to 120" to be used, the impedance diameter resetting. must be reduced to take account of the reduced generator impedance seen under such conditions. The The main advantage of this method is that a reverse offset also needs revising. In these circumstances, power element is often already present, so no additional

typical settings would be: relay elements are required. The main disadvantages are the time taken for tripping and the inability to control

pedance element diameter Xb, = 0.5Xd the system angle at which the generator breaker trip . : ~ . ~ < ~ ~ 2 . . ~ . y ; . . .

impedance element offset X,, = -0.75X; command would be issued, if i t is a requirement to limit :...,jj.?$.:.:"<.;"'.'

the breaker current interruption duty. There is also the , , ' j '.:+!(:. time delay on pick-up, f d l = 0.5s - 10s difficulty of determining suitable settings. %

time delay on drop-off, tdol = 0s Determination of settings in the field, from a deliberate . !,:

fie typical impedance settings for the second element, if pole-slipping test is not possible and analytical studies E L

may not discover all conditions under which pole- slipping will occur. %

impedance element diameter .r 2 . . . . .

h kV ; :. : ,-,. !-!.,~~,~:::.,.;:? k ;:.. ,.:i ;:i.) ;,;;?c8,.: ;;,,y!t::c:;k.,,.:, . . . x b 2 = - . it. - .

MVA <:..;.>.-,.,- .. .a, . . . . . . . . . . +.. . : : - . Q , :

. . . . . . . . . . .

- . = . - -* -

With reference to Figure 17.21. a !ass of excitation und& r . : ,. 2. ::. .- 1 . & . -.

impedanke characteristic may also be capable - o f - . pi . :+ CY The time delay settings i d 2 and tdO2 are Set to zero to give detecting loss of-synchronism, in applications where the fs

I instantaneous operation and reset. electrical centre of the power system and the generator r=

lies 'behind' the relaying point This would typically be the case for a relatively small generator that is 2 connected to a power transmission system (XG >> (XT + . 2

A generator may pole-slip, or fall out of synchronism Xsll- With reference to Figure 17.23; i f pole-slipping 2 with the power system for a number of reasons. The protection response is required. the drop-off timer tdor of

principal causes are prolonged clearance of a heavy fault the larger d ~ ~ m e t e r impedance measuring element

on the power system, when the generator is operating at should be set to prevent its reset of in each slip cycle,

a high load angle close to the stability limit, or partial or until the rdl trip time delay has expired. - 17. Complete loss of excitation. Weak transmission links * with reverse power protection, this would be an between the generator 2nd the bulk of the Power system elementary form of pole-slipping protection. I t may not aggravate the situation. I t can also occur with be suitable for large machines where rapid tripping is embedded generators running in parallel with a strong . required during the first slip cycle and where some Utility network if the time for a fault clearancean the control is required for the system angle at which ,the

slow. perhaps because only lDMT relays generator circuit breaker trip command is given. Where are provided. Pole slipping is characterised by large and protection against pole-slipping must be guaranteed, a rapid oscillations in active and reactive power. Rapid more sophisticated method of protection should be used.

, . . of the generator the network is A typical reset timer delay for pole-slipping protection ...

required to ensure that damage to the generator is might be 0.6~. . F ~ ~ generator transformer units, the .. , '. '. .... .... avoided and that loads supplied the are additional impedance in front of the relaying point may , ' . . . affected for very long. take the system impedance outside the under impedance ..::.: :~~:~~-.'~=!:;::'::. .: ., _ . . . . .

Protection can be provided using several methods. The relay characteristic required for loss of excitation ~.~..:~;.-;:~<;:~., . . :.... *

. . . choice of method will depend on the probability of pole protection. Therefore, the acceptability of this pole- +;.:*: .\ . _ .!.:.. . . . . ,. occurring and on the consequences should it slipping protection scheme will be dependent on the .. : - -7 . ...

. . application. A=-....::;:

. . ,., >. . . . . . . . . . , . ..... .-'...i ... .* ..: ?:.. -':."..:.: . ' '-.5<:e(<: :y;::r;

. . . . ......... ........ :.. ..-?,+ .:" :,. . , :

1.. . J O I ' .. ... ;,.. ......,. %.. .::; '

.y8. ..... . , -..::.: s. ." ~,':::~.:,~:,~~:.'. _ _ - . . . .

. .

Large generator-transformer units directly connected to grid systems often require a dedicated pole-slipping protection .scheme to ensure rapid tripping and with system angle control. Historically, dedicated protection schemes have usually been based on a n ohm-type impedance measurement characteristic.

Although a mho type element for detecting the change in impedance during pole-slipping can be used in some applications, bu t with performance limits, a straight line

- ohm characteristic is more suitable. The protection principle is that o f detecting the passage of the

..4

generator impedance through a zone defined by two U

3 such impedance characteristics, as shown in Figure P - 17.24. The characteristic is divided into three zones, A,

B, and C. Normal operation o f the generator lies in zone +

A. When a pole-slip occurs. the impedance traverses 6

zones B and C, and tripping occurs when the impedance - D characteristic enters zone C. 5 - ,. tz L +j.Y *

Ohm relay 1

Tripping only occurs i f all zones are traversed sequentially. Power system faults should result i n the zones not being fully traversed so that tripping will not be initiated. The security of this type of protection

. . . . . . . . scheme is normally enhanced by the addition of a plain ..... . * .

a , under impedance control element (circle about the origin . . . . . . . . . . of the impedance diagram) that isset to prevent tripping . .

. . for impedance trajectories for remote power system faults. Setting of the ohm elements is such that they lie

. . . parallel to the total system impedance vector, and . . . . . . . enclose i t , as shown in Figure 17.24. . . . . <

A more sophisticated approach is tb measure the impedance of the generator and use a lenticular impedance characteristic to determine i f a pole-slipping condition e~ists. The lenticular characteristic is shown i n Figure 17.25. The characteristic is divided into two haives by a straight line, called the blinder. ;9 A<'

8 The inclination, 6, of the lens and blinder is determined.by the angle of the total system impedance. The impedance ;:: of the system and generator-transformer determines the .:.. forward reach of the lens, ZA, and the transient reactance i : o f the generator determines the reverse reach ZB.

. . . . . . . .

-280-315 17/06/02 10:48 Page 303

. . . . _ ...................

I f the impedance locus lies above line PP', the swing lles far out in the power system - i.e. one part o f the power system, including the protected generator. is swinging against the rest of the network Tripping may sti l l occur, but only if swinging is prolonged - meaning that the power system is in danger of complete break-up Further confidence checks are introduced by requiring that the

I . ~mpedance locus spends a minimum tlme withln each zone for the pole-slipping condition t o be valid. The trip signal may also be delayed for a number o f slip cycles even i f a generator pole-slip occurs - thls IS t o both provide confirmation of a pole-slipping condition and allow time for other relays to operate i f the cause of the

1 pole slip lles somewhere In the power system. Should the impedance locus traverse the zones i n any other 1 sequence. trlpping IS blocked.

-

I

windings and to issue an alarm or trip to prevent damage.

Although current-operated thermal replica protection cannot take in to account the effects o f ambient temperature or uneven heat distribution, it is often applied as a back-up .to direct stator temperature measuring devices to prevent overheating due to high

Overheating of the stator may result from:

ii. failure o f the cooling system

iv. core faults

Accidental overloading might' occur through the Combination o f full active load current component, governed by the prime mover output and an abnormally

: high reactive current component, governed by the level

a modern protection relay, it is ielatively simple to Provide a current-operated thermal replica protection element to estimate the thermal state of the stator

*

................. - -.

stator current. With some relays, the thermal replica temperature estimate can be made more accurate through the integration of direct measuring resistance temperature devices.

Irrespective of whether current-operated thermal replica protection is applied or not, it is a requirement to monitor the stator temperature of a large generator in .:;.%E.$$~:s

-N order to detect overheating from whatever cause. 1.. c j ~ ~ : ~ ; ~ ~ ; ::., '- c ..,-. :.-::>-.:,:.

Tempe~ature sensitive elements, usually of the resistance ,$:.2*;ccf7':ii-.--. ..... 0 ,:.;:,

type, are embedded in the stator winding at hot-spot ..- +& :'3',

a, locations envisaged by the manufacturer, the number , . - used being sufficient to cover all variations. The - 2

Z elements are connected to a temperature sensing relay L

element arranged to provide alarm and trip outputs. The 3. settings will depend on the type o f stator winding S=

insulation and on its permitted temperature rise. 2 L

I Various faults may occur on the mechanical -side o f a :.- 2 : f l .. - generating set. The following sections detail the m i r e 6 important ones from an electrical point of view.

When a generator operating in parallel with others loses its power input, it remains in synchronism with the system and continues to run as a synchronous motor. drawing sufficient power to drive the prime mover. This condition may not appear to be dangerous and i n some circumstances will not be so. However, there is a danger of further damage being caused. Table 17.1 lists some typical problems that may occur.

Protection is provided by a low forward powerlreverse power relay, as detailed in Section 17.11

The speed of a turbo-generator set rises when the steam input is in excess of that required to drive the load at nominal frequency. The speed governor can normally control the speed, and, in any case, a set running i n parallel with others i n an interconnected system cannot accelerate much independently even i f synchronism is lost. However. i f load is suddenly lost when the HV circuit breaker is trippcd, thc set will begin to accelerate

J O J - .... . .

I ~hap17-280-315 17/06/02 10: 50 Page 304

rapidly. The speed governor is designed to prevent a dangerous speed rise even with a 100% load rejection, but nevertheless an additional centrifugal overspeed trip device is provided t o initiate an emergency mechanical shutdown i f the overspeed exceeds 10%.

To minimise overspeed on load rejection and hence the mechanical stresses on the rotor, the following sequence .

event of loss of vacuum, as this would cause rapid overheating of the low-pressure turbine blades.

17-20 CO>JP;flE GEFJERAioz pr<(j iEn!Q>:

From the preceding sections, it is obvious . . . . . . . . . .. . .:. : I . is used whenever electrical tripping is not urgently protection scheme for a generator has to take account of 3 .-.: . . . . - -h

- required: many possible faults and plant design variations. :;SEzJ

i. trip prime mover or gradually reduce power input to Determination of the types of protection used for a ;,@{ ..,,

particular generator wi l l depend on the nature of the :$&, zero plant and upon economic considerations, which in turn :;$$$

ii. allow generated power to decay towards zero -,.>

is affected by set size. Fortunately, modern, multi- ,'-?$ . -7

5;: iii. trip generator circuit breaker only when function, numerical relays are sufficiently versatile to 'gig. 0

-N power is close t o zero*or when the power flow include all of the commonly required protection ':%< k --a starts to reverse, to drive the idle turbine - functions in a single package,. thus simplifying the .{.$$ P1 *- CI decisions to be made. The following sections provide :g

E, - ? A failure of the condenser vacuum i n a steam turbine is

driven generator results i n heating of the tubes. This then produces strain in the tubes, anJ a rise i n .-. temperature o f the low-pressure end of the turbine.

vh Vacuum pressure devices initiate progressive unloading I L 0

of the set and, if eventually necessary, tripping of the . . turbine valves followed by the high voltage circuit > ..- breaker. The set must not be allowed t o motor i n the E G

5 , . 3 .

Elcctr~cal trlp of govcmor L -

L / w

illustrations of typical'protection schemes for generators ,:j.$$: .I-&....

'connected to a grid network, but not all possibilities are ':$: illustrated, due to the wide variation in generator sizes i$$: and types.

. . . . . . . . . . . . : ; .. :.: . . . . . ., . . . . . . .... ..-" .. I. ., .zc

A typical protection scheme for a direct-connected '::;$;> generator is shown i n Figure 17.27. It comprises the:::@

.,: =:e following protection functions: . - .~ . .::: .-;.g

. . . . . . .. :: =rv *Z :__: . . . . . . . -:>;..

L Emcrgcncv push b u ~ o n J - - P

I E) C v II: P

Q., Stator diffcrcntial (biascdlhigh '3

P

Stator E/F (or ncutral voltagc

Back-up ovcrcurrcnt lor voltagc dcpcndcnt OICI

1 Loss 0-1 Stator winding tcmpcraturc Excitation P

Unbalanced loading circult brcakcr

Undcrlovcrvoltagc Low powcr

~nlcrlock Gcncrator p-

( Mechanical fatrlts ( n o n - u r g c n t l ~ circuit brcakcr

N.8. Alarms and I ~ m c dclays arnittcd for simplicity

i 7 - 2 8 0 - 3 1 5 1 7 / 0 6 / 0 2 1 0 : 5 0 Page 3 0 5

1. stator differential protection

2. overcurrent protection - conventional or voltage dependent

3. stator earth fault protection

4. over;o!:agc protection

5. undervoltage protection

6. overloadllow forward power1 reverse.-power protection (according t o prime mover type)

7. unbalanced loading

8. overheating

9. pole slipping

10. loss of excitation

'11. underfrequency

12. inadyertent energisation

13. overfluxing

14. mechanical faults

instantaneous electrical trip and which can be t ime delayed until electrical power has been reduced t o a low value. The faults that require tripping o f the prime mover as well as the generator circuit breaker are also shown.

These units are generally of higher output than direct- connected generators, and hence more comprehensive protection is warranted. In addition, the generator transformer also requires protection,. for which the protection detailed in Chapter 16 is appropriate -

Overall biased generatorlgenerator transformer differential protection is commonly applied in addition, or instead of, differential protection for the transformer alone. A single protection relay may incorporate all of the required functions, or tbe protection o f the transformer (including overall generatorlgenerator transformer differential protection) may util ise a separate relay.

In recent years, through de-regulation o f the electricity supply industry and the ensuing commercial competition, many electricity users connected to MV power distribution systems have installed generating st% to operate in parallel with the public supply. The intention is either to utilise sur.?lus energy from other sources, or to usewaste heat or steam from the prime mover for other purposes. * Parallel connection o f generators to distribution systems did occur before de- regulation, but only where there was a net power import from the Utility. Power export to Util ity distribution systems was a relatively new aspect. Since generation o f this type can now be located within a Util ity distribution system, as opposed t o being centrally dispatched generation connected to a transmission system, the term 'Embedded Generation' is often applied.- Figure 17.2 illustrates such an arrangement. Depending on size, the embedded generator(s) may be synchronous or asynchronous types, and they may be connected at any voltage appropriate to the size o f plant being considered.

The impact o f connecting generation t o a Util ity distribution system that was originally engineered only for downward power distribution must be considered, particularly i n the area of protection requirements. In this respect, it is not important whether the embedded generator is normally capable of export t o the Utility distribution system or not. since there may exist fault conditions when this occurs irrespective o f the design intent.

I f plant operation when disconnected from the Utility supply is required, underfrequency protection (Section 17.4.2) will become an important feature of the in-plant power system. During isolated operation, it may be relatively easy to overload the available generation, such that some form of load management system may be required. Similarly, when running in parallel with the Utility, consideration needs t o be given to the mode of generator operation if reactive power import is to be controlled. The impact on the control scheme of a sudden break in the Util ity connection to the plant main busbar also requires analysis. Where the in-plant generation is run using constant power factor or constant reactive power control. automatic reversion to voltage control when the Util ity connection is lost is essential to prevent plant loads being subjected to a

. . ... . . -. . : . . ,:

. .

. .

frequency and voltage, or for other reasons.

From a Util ity standpoint, the connection o f e generation may cause problems wi th voltage co increased fault levels. The settings for protecti in :he vicinity cf the ;!ant may require adjustment-with the emergence of embedded generation. It must also be ensured that the safety, security and quality o f supply of the Util ity distribution system is not compromised. The i embedded generation must not be permitted t o supply .' any Util ity customers i n isolation, since the Util ity supply is normally the means of regulating the system voltage'; and frequency within the permitted limits. It aiso ; normally provides the only system earth connection(s], to :. ensure the correct performance o f system protection in response to earth faults: If the Utility power infeed fails, it is also important t o disconnect the embedded generation before there is any risk of the Util ity power': supply returning on to unsynchronised machines. In, practice this generally requires the following protection ': functions to be applied a t the 'Point o f Common 'j Coupling' (PCC) t o t r ip the coupling circuit breaker:

a. overvoltage -:if 3.. , :.: !4 ->

b. undervoltage ,+! .... "-5' -I-.

... .C,(' e. loss o f ~ t i l i t ~ s u ~ ~ l ~ .:, . . : .%. .. :-. ... i;g ..*- - . . . . - . :;"*

In addition: 'partichiar ci;cumstances ' may require:$ additional protection functions: ,:, '3

f. neutral voltage displacement

g. reverse power

h. directional overcurrent

In practice, it can be difficult to meet the protection settings or performance demanded by the Utility without a high risk o f nuisance tripping caused by lack of CO-

ordination wi th normal power system faults and disturbances that do not necessitate tripping o f the embedded generation. This is especially true when applying protection specifically to detect loss of the Utility supply (also called 'loss of mains') to cater for operating conditions where there would be no immediate excursion in voltage or frequency to cause operation o f conventional protection functions.

voltage outside acceptable limits. .

. . . . Limits may be placed by the Utility on the amount of > I . : / : , I P ! o i r c ~ i o n I'.,(;;~inst Los5 ::I Il:ili.:v Sv;)~!y

.......... ....... .,...... powerlreactive power importlexport. These may demand ;.;.,,. , .- . .

I f the normal power infeed to a distribution system, o r ta the use o f an in-plant Power Management System to

. .- .? . >,A: . , the part of it containing embedded generation is lost, the ........ ..:. .

control the embedded generation and plant loads ; . ..- . effects may be as follows: . . . . ...... accordinqly. Some Utilities may insist on automatic . - . .. .... .2:,.:..,, - .7;,-'r... . . ,. tripping o f the interconnecting circuit breakers i f there is a. embedded generation may be overloaded, leadin!

.... .=.,I... .. >+.A i a significant departure outside permissible levels of to generator undervoltage/underfrequency .,.;.', ,.; . . . . -., . .

-315 17/06/02 10:50 Page 307

embedded generation.may bc underloadcd, leading 17.27.2 ROCOF Ee;ay Description to ove~oltage/overfrequency - A ROCOF relay detects the rate o f change of frequency i n

little change to the absolute levels of voltage or excess of a defined setpoint. The signal is obtained from

frequency if there is little resulting ,-hange to the a voltage transformer connected close t o the Point of

load flow through the PCC Common Coupling (PCC). The principal method used is to measure the time period between successive zero-

rst two effects are covered by conventional voltage crossings to determine the average frequency for each ..

equency protection. However, if condition (c) half-cycle and hence the rate of change of frequency. conventional protection may not detect the loss The result is usually averaged over a number of cycles.

ty supply condition or it may be too slow to do so the shortest possible auto-reclose dead-times . . . % . . . .

. ' ..'.::;.:(!.: '$.; .-,. 1:,ir ::.!,.:, ~;:!;i~j tj.::s:v;;;..::::!] ay be applied in association with Util ity overhead ''-'" . * ..

otection. Detection of condition (c) must be A voltage vector shift relay detects the dr i f t i n voltage

d if the requirements of the Util ity are to be met. phase angle beyond a defined setpoint as long as it takes

ossible methods have been suggested, but the place within a set period. Again, the voltage signal is

t often used is the Rate of Change of Frequency a voltage transformer connected 'lose to

relay. - I t s application is ba;ed on the fact that the Point o f Common Coupling (PCC). The principal method used is to measure the' time period between

of change o f small changes i n absolute successive zero-crossings to determine the duration o f ?.% , in response to inevitable small load changes, each half-cycle, and then to the durations . . = C-

ter with the generation isolated than when the the memorised average duration of earlier half-cycles in L

is i n parallel with the public, interconnected order to determine the phase angle drift. s . -E tern. However, problems w i t h nuisance P

tional power system events. & . . . -:;...::k; ;. .: . .

.. . . : . . . .% . = . . following the loss of a large generator.or a . sho;ld loss of the Utility supply occur, .it is 2:;. -*,-;; :-.. .::

. - & - , .; c . - r interconnector, have occurred. "nlikely that there will be an exact match between'the 5': o, : - - -...

:; . : ularly true for geographically islanded power output o f the. embedded generator(s) and the connected -.?,. o, -.:-

h as those of the British Isles. An alternative load. A small frequency change or voltage bhase angle u -3

otection is a technique sometimes referred change will therefore occur, t o which can be added any

vector shifts protection. ln this technique changes due to the small natural variations i n loading o f L

+I

ase ,-hange between the directly an isolated generator with time. Once the rate of change 2 mpared with a memorised ax. of frequency exceeds the setting of the ROCOF relay for 2

a set time, or once the voltage phase angle dr i f t exceeds the set angle, tripping occurs to open the connection

d generation are not normally between the in-plant and Util ity networks. G

s a potential safety hazard. In the While it is possible to estimate the rate of change of system earth fault, the Uti l i ty frequency from knowledge o f the generator set inertia . 17 rate to remove the Uti l i ty power and MVA rating, this is not an accurate method for

Id also re&lt in removal of the setting a ROCOF relay because the rotational inertia of , through the action o f the the complete network being fed by the embedded ency protection and dependable generation is required. For example, there may be other n. H ~ ~ ~ ~ ~ ~ , in view of safety embedded generators to consider. As a result, it is

considerations (e.g. fallen overhead line conductors in invariably the case that the relay settings are determined

al form of earth fault protection at site during commissioning. This is to ensure that the Uti l i ty requirements are met while reducing the - . . '

may also be demanded to prevent the backfeed of an . possibility of a spurious trip under the various operating .-:::!.... :

earth fault by embedded generation. The.only Way of scenarios envisaged. However, i t is very diff icult t o . ';.'':.:;' .: . . '

:'.;\ ,i<. ......: ...,i: detecting an fault is use determine whether a given rate of change o f frequency ~~;$:$~&$,c.;~~- neutral voltage displacement protection. The additional wi l l be due to a 'loss of mainsq incident o r a !p$riq;i:?-; ..5.: .-..:: .<*,,,

. . requirement is only likely t o arise for embedded load/frequeno/ change on the public power network, and .;i:$?...j!;;.c. !! generation rated above 15OkVA. since the risk of the hence spurious trips are impossible to eliminate. Thus ?.+::?:.:--:<!:

.'..<. '.':.''. ,:.. ;..=; ma l l embedded generators not being cleared by other the provision of Loss of Util ity Supply protection t o meet ." . . .

means is negligible. , power distribution Ut i l i ty interface protect ion ....".... .:'. . , ,, < + .? -" .. ...A', ....:.... ..... :.. -r .:.. ii. ..... . . . . .

;.- ..'. :; . . . . . . . . . . . . . . - . . . . . . . . . . . . . . - . . . . . . . . . . . . ,1... : . ... . . . N , t w . r l P , . r r , t i . m U r l . r . - . r i . . G m i l * '\ - J 0 7 .- .,.:<:.:. .

-. . -..-.....- :+:. . . . . . . . . . . . :,.. . . : . : .*;.. .,

requirements, may actually conflict wi th the interests o f the national power system operator. With the growing contribution of non-dispatched embedded generation to the aggregate national power demand, the loss o f the embedded generation following a transmission system incident tna i may aireaiiy ciialleilge the security-of the system can only aggravate the problem. There have been claims that voltage vector shift protection might offer better security. but it will have operation times that vary with the rate o f change of frequency. As a result, depending on the settings used, operation-times might not comply wi th Uti l i ty requirements under all circumstances. Reference 17.1 provides further details of the operation of ROCOF relays and the problems that may be encountered.

Nevertheless. because such protection is a common requirement of some Utilities, the 'loss o f mains' protyction may have to be provided and the possibility of spurious trips will have t o be accepted in those cases. Site measurements over a period of time of the typical rates of frequency change occurring may assist in negotiations of the settings wi th the Utility, and with the fine-tuning of the protection that may already be commissioned.

This section gives examples of the calculations required for generator protection. The first is for a typical small generator installed on an industrial system that runs in parallel wi th the Util ity supply. The second is for a larger generator-transformer unit connected to a grid system.

-

Salient details o f the generator, network and protection required are given i n Table 17.2. The example ?.

calculations are based on a MiCOM P343 relay in respeq o f setting ranges, etc.

. . . , .. ' .< .:.'.?;,, <.. . ,~ . .. . ...,.. :-.,. ..... - >.. .. :' 'i . ..:. . . . . . . . . . . . .

Biased differential protection involves the determinatio of values for four setting values: I,,. ISz, K I and Kz in :;$ Figure 17.5. I;., can be set a t 5OIoof the generator rating, .@ in accordance with the recommendations for the relay, j:"

and similarly the values of I,, 1120010) and K 2 (15Wo) of ; generator rating. It remains for the value of K , to be :, determined. The recommended value is generally @h, :; but this only applies where CT's that conform to IEC ..: 60044-1 class PX (or the superseded BS 3938 Class X] /j:#$ are used - i.e. CT's specifically designed for use in .$@ differential protection schemes. In this application, the x - CT's are conventional class 5P CT's that meet the relay '!$s

.:',%,P requirements in respect of knee-point vcltage, e tc $3:.

.*,. Where neutral tail and terminal CT's can saturate at :!.:&:

.- >...

different times due to transiently offset magnetising .:&; inrush or motor starting current waveforms with an r.m.s. :;(?': level close t o rated current and where there is a high l j R .$& time constant for the offset, the use of a 0% bias slope';:& may give rise to maloperation. Such waveforms can k :,$$ encountered when plant o f . similar ..rating t o . the~22~.~$~, generator i s being energised or staited: Differen&;yX$ between CT de'sibns'ordiffering remanent fluilevels d":;I%

. . . . lead to asymmetric saturation and the producticin differential spill current. here fore, it .is appropriate t o ::% select a non-zero setting for K , , and a value of 5% isy@ usual i n these circumstances. .-. ::=. ,.sf ., :. 3: .

..-.I*

This protection is applied as remote backup to the ,3 downstream overcurrent protection i n the event of .$ protection or breaker failure conditions. This ensures $ that the generator will not continue to supply the fault -.%,

... . ~ --- :, - - under thew conditions. :.%. ,4 'L . z AWL' . -c--"-., ..-, , . . . . =.x ...- & > . * ~ . d * 4

17 . ; kv* Lw : PF Ra;~d Rarcd Rarcd Ralcd Primc Movcr ~t normal voltage, the current setting must be greater , , .. .. ..,,:. .... 1 wl;agc cuncnl frcqucncy spccd 0.pc

I . . . than the maximum generator load current of 328A. A '1 . . . . . . . .

,: ' , .,-; .r.;i ;::: / 6250 1 ,5000 1 0.8 j llw 328 : 50 : 1500 !Stcam Turbinc ' . . . ..:>. .;.,,:3.:5+ I

I margin must be allowed for resetting of the relay at this ';j 1 ., ! ....... ... . . . m,">y;.::. al--- --;

.>! :: +A-l-Gwkcib! ;~,+: :5~F.k35r..~,~r! current (reset ratio = 950101 and for the measurement 5 ... ......a . . .-,.,.d:

. . . . . . / Gcncrator hlpc : x * ~ . L . X ; p . ~ . CI Ratio VT Ratio tolerances of the relay (Solo o f r, under reference :; . . .,F.:.,< . . . ! h l i c m ~ I C / 2349 1 0.297 50011 : 11000,110 ; conditions), therefore the current setting is calculated as: ,.:

. ,. . . , ...... ... , .-, - . . . . . 1 . . . . :-.G 3 v ,

. . . ... ,. ... ., ,.. .., ,.. j Eanhing . Maximum carth ! Minimum pharc Maximum downslrcam .... . .,... rcsistor . faull currcnl fault currcnl p h a ~ faull CunCnl

,, . . . . ::;;A+::::,~ / . 31.7.n >:I,';: -: 2004 1.. ,'.. 145. ..*,.-o>-. , .2,,<e:Js:.! I ::;.;%>.? !.;'i$aig&,. : ?:&?. kc?*: ih? Eanh Faull Scllingr 1 ~..:F;g?r' ,, ,,,. :<:,> 2:

,..!;.:.:, ", ".'.,> .

I:. . . i. . . -.. j 20011 j " ' ,SI . ; 1 4 4 1 0.176 j 51 : 48A j 0.15 j ..... ....... 1. .- .. .- ....-..-.. ..',&..', ... >::::;<,!:; 1 T#rl~lc I?.?: Oslo I:,, : . : r : : : ' . ~ : c ~ c ~ ' : l o r ,?,,::r+.:*o~ c,:, .-;.. ;

-.::. Ui , . . . . . . . ........ . . . . . ..:.v.*,,:- i - .i.C.;.<<,-. - ' ..Z >-i. - ....... 2 :<-.,.s :. ....

The nearest settable value is 3654 or 0.731,.

The minimum phase-phase voltage for a close-up single- .. phase to earth fault is 57%. so the voltage setting V, must be less than this. A value of 30°10 is typically used, .- giving V, = 33V. The current setting multiplying factor.

K must be chosen such that Kls is less than 50% of the an operation time of not less than 1.13s. At a TMS of 1.0, generator steady-state current contribution to an the generator protection relay operating time will be: uncleared remote fault. This information is not available

protection such that:

=45.6V

where: L 0 h

Vrfl = eflective voltage setting a L .. P1

I,,, = dorunstrearn earth-fault current setting r ~1

Z , = eaflhing resistarlce C3

Hence a setting of 48V is acceptable. Time grading is

==0.362 required, with a minimum operating time of the NVD 17 3.01 protection of 1.13s at an earth fault current of 200A

Using the expression for the operation time of the NVD

t = K/(M-I) sec

. . . . ;..:.,*.>, ?<,.+ :... . - ,. .,

Providing protection for 90% of the winding.

V = voltage seer1 by relay

Vrnvd = relay setting voltage

31s 17/06/02 10:sO Page 3 1 0 + ., - : ;.,71.7.5 loss (1:' (<;.r.;rc: lisi: s;-.;.;i.;ifir:

Loss of excitation is detected by a mho impedance relay element, as detailed i n Section 17.16.2. The standard settings for the P340 series relay are: - X, = 0 . 5 ~ ' ~ x (0 ratio/VT ratio)

(in secondary quantities]

= -0.5 X 0.297 x 19.36 x 500/100

= -14.5n

Xb = Xd x (CT r a t i o m ratio)

= 2.349f l x 19.36 x (500/100)

= 227Q

The nearest settings provided by the relay are X, = - 14.552 Xb = 22752. The time delay tdl should be set t c avoid relay element operation on power swings and a' typical setting of 3s is used. This value may need to be modified i n the light of operating experience. To prevent cyclical pick-up of the relay plement without tripping. such as might occur during pole-slipping conditions, a drop-off time delay td,, is provided and set to 0.5s. . , ..... , ,

.#/, :.,: :.:+., (<. , , .,, ., .-%;>..<,;;c G.e:<;>< = < ,, .;:.::s:c !< .: .::<::.:k<.-!.':j:.

This protection is required to guard against excessive heating from negative phase sequence currents. whatever

, the cause. Thegentrator, i s o f salient-pole design, so from IEC '6&34-1;-.the'&ntinuok withstand is-8qo of rating and the -' ~ : r w l u e ii:20s. . ~s in<.G~uatTon 17.i, the required relay settingsmn found as f2>>,= 0.05 and K = 8.6s. The nearest available values are I,>> = 0.05 and K = 8.6s. The relay also has a cooling time constant K,,,,, that is normally set equal to the value o f K. To co- ordinate with clearance o f heavy asymmetric system faults, that might otherwise cause unnecessary operation of this protection, a minimum operation time tmi, should

quantities (corresponding to voltage) is typically used, with '10s to allow for transients offlrejection, overvoltages on motor starting, etc.

The second element provides pr otection in the event of; large overvoltage, by tripping excitation and th; generator circuit breaker (if closed]. This must be set below the maximum stator voltage possible, taking account saturation. As the open circuit the generator is not available, typical values must bec@ .. ., used. , Saturation will normally l imit the maximum"'"" overvoltage on this type of generator to 130%, so a. setting of 120% (132V secondary) is typically used:' Instantaneous operation is required. Generato< manufacturers are normally able to provide' recommendations for the relay settings. Far embedded ger:erators, the requirements of the local Utility may a1 have to be taken into account. For both elemen&, variety of voltage measurement modes are available t$@ take account of possible VT connections (single or three:@ phase, etc.], and conditions to be protected against I" this example, a thee-phase VT connection is used, aid overvoltages on any phase are t o be detected, so.'? selection of 'Any' is used for this setting.

..<$F@

~ h i s ' i s iequiied t o protect the generator from s;&i$$$ overloid conditions during periods df op'erat ion.isi i~tdh :.;;qG from the Utility supply. The generating set manufacturer# will normally provide the details o f machine short-tim$$ capabilities. The example relay provides four stages @$ underfrequency protection. In this case, the first stageis! used for alarm purposes and a second stage would b$, applied to trip the set. ,"$ a *i

<;. 01

Q be applied. I t is recommended to set this to a value of 1. The alarm stage might typically be set to 49Hz, w i tha Similarly, a maximum time can be applied to ensure that time delay of 20s, to avoid an alarm being raised unds the thermal rating o f the generator is not exceeded (as transient conditions, e.g. during plant motor starting;

. 17,. ,:, this is uncertain, data not available) and to take account The trip stage might be set to 48Hz. with a time delay of x?. _,, . .C::F&+;i . -, of the fact that the P343 characteristic is not identical 0.5s, to avoid tripping for transient, but recoverable, dips 6c;$&$$$i with that specified i n .lEC 60034. The recommended in frequency below this value. .:. ,..,".&.k%,~. setting for t,,, is 600s. . . ‘, i D ;:,.. ... . . . . . . . . . . . !..,. :.~,.'', ' . , ,: :j: . .: . ,.:, , ;.;j.: ..:: :.

'.'.:f.- . . . . : .. 1 .

. . . . . . ....,.. 7 :.:I;.' : .; - .. t :. .,. ;.:< . ." .......... ......... . . . . The relay setting i s 5% of rated power.

--- ., ..-. ,.. This is required to guard against various failure modes, ..; . - . 0 . 0 5 ~ 5 ~ 1 0 ~ !C

:-.:+ . e.g. AVR failure, resulting in excessive stator voltage. A 8"-. .:.?

.- ,.., .:a:.,::. r,-i.l two-stage protection is available, the first being a low- -L:

set time-delayed stage that should be set to grade with .G transient overvoltages that can be tolerated following

500 X 100 ;.: .. v

load rejection. The second is a high-set stage used for' -. instantaneous tripping in the event of an intolerable =5W overvoltage condition arising. .V. ,

This value can be set in the relay. A time deb;; en era tors can normally withstand 105% of rated to guard against power swings while genera$i voltage continuously. SO the low-set stage should be set at low power levels, so use a time delay of 5s. NO " ..:: higher than this value. A sctting of 117.7V in secondary time delay is required. 7

. . . . . . . __-A

, .~ . J 1 0 - . J N e r u e r ) P r . r r r r i . m U A w r . m . i i a . C.;!'

. - : :.! ....

'. ,.. .. >

/ 0 6 / 0 2 1 0 : 5 0 Page 311

x a -14.5Q 1 Loss of excitation xb

j i z ? ~ ' ' ::

Id 1 3s

... .- ._ ........... Iw1 , 0.55

.... I,,, 0.73-

j '3 . : ,"I...". .""'."ll..J ovcrc"ncnt vs K 0.6

yi ir>> 0.05 ',G..

. . , X" K . I 86s ' . ,<\. . , Ncgatiw phase xqucncc Kme 8.6s

I 1.5s tmi.

6005 ~ m o x - - . V, mcas modc k c - p h a s c

. . F<l tim; dclay

Undcrfrcqucncy 205 . i .. 'I.. F<Z wtting i 4 8 k

F<2 timc dclay 0.5s . . . . . - .-.... - . . . . . . . . . . . . . . . . . . PI har t i on ; lrvmc powcr

..... -. - .- . - . . . . . - . ... - ...... PI tirnc dclay j 5s

PI DO limc Or

. . . ! I I : I ; - r : - 5 1

............ .... .....

., , ,:,

$>: d, . . The data for this uni t are given i n Table 17.4. It is f i t ted 2.- with t w o main protection systems to ensure security of

$ : ' tripping i n the event of a fault. To econornise on space. I. - . . the setting calculations for only one system, that using a c- MiCOM P343 relay are given. Settings are given i n t::;

Prhary quantities throughout.

The settings fol low the guidelines previously stated. AS

. 1OOoIo stator winding earth-fault protection is provided. 8: ,,.high sensitivity is not required and hence J,, can bc set

;::"' to 1O0Io of generator rated current. This equates to 602A. E'' and the nearest settable value on the relay is MOA I = ' 0.08 of rated CT current]. The settings for K , . I,, and K,

,L f0ll0w the guidelines i n the relay manual. .:<'.

j Gcncrator MVA rating / 187.65 MVA 1 ixG~MwGtik>; 1:. ....... , ...+. _ .. . -.. ;,.. ... I: i Gcncrator voltagc 1 18 ; W i ( r..........,..........-.... . ,... ~ ~ ~ ~ ! , e ~ F : ~ 2 ~ F ! ! ~ i ; ~~~<~;$~2~~;5]~~~~3,2$~~~\'32~@" 'i:s@{ j Oirccl-axis Uansicnt rcactancc 1 0.189 \ pu !

. . ()A'::::: 1 ' ,:. , . " ,: *&. >: ! 8 . ' ~ in iG"& ;'@ti"i+li?& , ;. .' ' : .~ . ,I : . : ~ ~ ~ : ~ ~ ~ : : , : , ~ ~ ~ " : ' 1 ;,k.i: ::,::-:\

I Gcncrator ncgatiw xqucncc capability 0.08 pu i . . .

. . Gcncrator ncgativc xqucncc factor, Kg 1 . . 1 ' . ,' . : : . a ,

Gcncrator third harmonic vol

Gcncntormotoring powcr

Gcncrator ovcwoltagc

Gcnuator ~ n d c w o l t y c

Max polc slipping frcqucncy

Gcncntor trhsformcr rating

Gcncrator tnnsformcr lcaka~c rcactancc 0.244 DU ... . .!

\ ' Gcncrator transfoicr o w d u x alarm . I 1 . : pu :::!

Gcrlcrator transformer ovcdux alarm 12 1 pu i

Nctwohrcristanct (rcfcncd to 18W 1 056 mfl : i- . . ~ ~

Nctwoh rcactancc (rcfcrrcd to 18kW OD1 99 Q i ,::I. w - ':: Systcm impcdancc anglc (cstirnatcdl 80 dcg

Z ?.

Minimum load rcsistancc 0.8 0 ' I

Gmcrator CT'ratio - r '5 ! -ap311 j j

Gcncrator VT ratio ; lRWo/lZO ' \.:;.~l::~;:..j..:

2 j Numbcr o f gcncratas i n parallcl . . . . . . & . . . . . . . . . . . - ..

The setting current has t o be greater than the full- 2 load current o f the generator (6019A). A suitable margin Q

L must be allowed for operation a t reduced voltage, so use 2 a multiplying factor of 1.2. The nearest settable value is 2

9) 72OUA. The factor K is calculated so that the operating r: current is less than the current for a remote end three P,

phase fault. The steady-state current and voltage a t the C3

generator for a remote-end three-phase faul t are given by the expressions: - 17-

where:

VN = 110-load phn rc -~ reu t ra l go lc ra tor volrngc ' >, .. . . Xd = go lera tor d-aris synchronous rcoctance ~~:,';;,..-r:.?~:~-~. . .;. .,,, ,.-...- .......

,-hap17-280-315 17 /06 /02 10:50 Paqe 312

hence. A TMS value of 10 is selected, to match the withstand curve supplied by the manufacturer. IJlr = 2893A ; ;,72,7,6 ':()L?<b :S:r;[oi crrr[,+ 6:::~ p::r:~:~c-$un

= 0.361,y

and This is provided by a combination of neutral voltage dispiaceiiicnt ai;d :bird h8rmnnic undewoltagc

vN.\I?Gf I ' + I x , + ~ ~ x ~ 1 ' ) protection. For the neutral voltage displace V P r = ----

f i ~ ~ ~ I ' + I X ~ + X , + ~ ~ X ~ j 2 protection to cover 90% o f the stator winding, minimum voltage allowing for generator operation

=J304V minimum of 92% o f rated voltage is:

=0.07UN 0.92x18kVxO. 1

A suitable value of K is therefye 0-36x2=0.3 . =956.7V .-. ..

0 A suitable value of V,,,, is 120010 of V':. giving a value . - of 1565V. The nearest settable value is 3000V, minimum Use a value of 935.3~, nearest setfable value u

9, allowable setting. The value of V,,, is required ensures of the is covered. A 0.5s definih, -4"

be above the minimum voltage seen by the generator for time delay is used to prevent spurious trips. The third; a fault. A value 80010 rated harmonic voltage under normal conditions is 20h of rated voltage is used for V;,,,. 14400V. - - voltage, giving a value of: - . . . . . . . . . i - . . . - .'a 78kV xO.02

3 - This protection is a combination of overcurrent with % 4T

undervoltage, the voltage signa! being obtained from a h VT on :he generator side of the system. The current =207.8V ;I setting used is that of rated generator current of 6019A. . . . . D - in accordance with IEEE C37.102 as the generator-ii for . The sett ing- of,..the :.third har

- installation i n the USA. Use 6000A nearest settable- protettion-hu;t.be belo6 this-" P,

E - . value. The voltage setting cannot be more than 85% of . beingacceptable: use-avslue 6f 166.3V. A tiiiiqde - Q

a the generator rated voltage to ensure operation does not of 0.5s is used. . lnhibiiion o f the e1ement:at.l % occur under normal operation. For this application, a generator output requires determination dur~n z value of 50010 of rated voltage is chosen. commissioning. - . . . . . . . . . . . ; ....... 0 ; /, ; :,;:>.., ::: (;.<:::<;<i.:!: ;;::;c - C

2 The generator has a maximum steady-state capability of The client requires a two-stage loss 8010 of rating, and a value o f 1;9 of 10. Settings of I,,,,,, protection function. The first is alarm only. while th

VJ = 0.06 (=480A) and I;, = 10 are therefore used. second provides tripping under high load conditions.: Minimum and maximum timedelaysof 1s and 1300s are achieve this, the first impedance element of the P3 used to co-ordinate with external protectiori and ensure loss of excitation protection can be set in a c c ~ r d a n . ~

17 tripping at low levels of negative sequence current are with the guidelines of Section 17.16.3 for a generatok used. operating at rotor angles up to 120", as follows: . . . . . . . . . . . ..,, ,.. Xbl = O.SXd = 1.666f2 . .

The generator-transformer manufacturer supplied the Xa, = 0.75X',j = 0.245R . . . . . following characteristics: - . . . . . Use nearest settable values of 1.669fl and 0.25

. . . . . . . .., .. Alarm: yf > I . J time delay of 5s is used to prevent alarms

< . . . . , transient conditions. For the trip stage, settings fo . . . . . . . . . . . . . load as given in Section 17.16.3 are used: - ... .......... c ....... Trip: v/$ > J . ~ , ~ ~ I , c ~ s c li!i~c cliaracfc"slic

:.:::,;A ...... ; ;;>:"+ ...... .:....., . . ....

I ; ,.. ; p < ~ y ;?.? k V 2 - 18' . .s>.;!., ,.I .', ... Hence the alarm setting is J8°00xJ.05 =315V/Hz.

A 0 Xb,=-------=1.727Q

.+~;i;~ MVA 187.65 :::. +,..i'.i. . .<": .::>,_:. . .... .I.-, A time delay of 5s is used to avoid alarms due to Xa,=-0.75X;=-0. 1406R / ,: '.,.?> . .

i. : .' .3, . ' I : . . -.-

:-.?..; . , transient conditions. .>:. . ..,, . i

. h: . .+. v.: ,- .<.. .:.Ly+.s . The nearest settable value for Xb2 is 1.72512. A ' $$ '.$.%.'j'.,,. -...a:, The tr,ip setting is J8000xJ-3/6O=360~/1fz .

z..: '. .... delay of 0.5s is used. 6:"' .:.c.->.:.. .... , . . I;c;:'

I:::.: 6; :

. .

Loss of cxcitalion

Alarm: 59.3H2, 0.5s t ime delay Voltagc conlrollcd ovcrcurrcnl

1st stage trip: 58.7Hz, 100s t ime delay

tage trip: 5 8 . 2 ~ z , Is t ime delay

Alarm: 62Hz, 30s t ime delay

Trip: 63.5Hz, 10s t ime delay

These characteristia can be set in the relay directly.

The generator manufacturers' recommendation is:

lates in to the fol lowing relay settings:

Alarm: 19800V. 5s t ime delay

Trip: 23400V, 0.1s t ime delay Rrvcnc P ~ W C ~

d. 'The setting data, according t o the relay

Forward reach, Z, = Z,, + Z, ~ o ~ c Slipping Protcclion

= 0.02 + 0.22

Reverse reach. Zn = ZGr,, Rcrcnc Powcr

F>2 rime dclay 105

:er

gh

me

.. . - = 0.652fl : PI function . , i-~~rx powcr

. . PI scrling 1 1.6MW Reactance line. Zc = 0.9 x Z o ~ c d r c q u ~ n q PI timc dclay ' I - 0.5s

= 0.9 x 0.22 . . PI . DO . tirnc : . s s os j,-..-.- -- F<I setting '.

= 0.138R Fcl i i c dclay : 0.5s , .. . ..

where: ! i . ,,F+ xnilig ,.:::. 1 .- : 58.7Hz , ,:.::,:-. Undcrfrcqucnol Fc2 tirnc dclay lOOs

! <,.:.- '< .. . . Z, = gct~rrofor r r a ~ ~ s f o n i ~ e r leakage ir i~prdor~ce F<fxttifi$ "...' .( 5821ii ' ' ':

F < 3 limc dclay ' Is 2, = rlerluork impcrior~ce . . , . . . . -- . .-

.I .. :. . , . ..

. . . .. . . . . . . . .. . . .<.... :.. . . .

: . :! , ... . . ,. .? .7,:' ;. <:;':;.: i>;:;&,.?;: -- ::*. ::. . . i&,%:i.-. . .. .?. . . ky$z7L;. .. .:., . ,-.... . . - . : . . * . . . . ... .><;:..;,;...

-:.. . !. !:::.= .:... ;irrb!r i i 5 . R*r? :.< i:roty, I.,, blrgc ~ C I I C I O I ~ I I , ~ ~ O ; C C : ~ ~ ~ C A U ~ P ! C j 3. ,x7:.- ,.,.: ., . .> .-r

I I :?,,-$; 2.

, .:.cP . ' ..,. .,. .. ;ks:;yi.::;<,. ,%'d".:.. .... - . . .

/'L ~ - ~ , ~ h * " ' ~ ~ , N ~ f w . t k P r a r a c r i s a ff A s f . - . r i . m G m i l c J I J . ~ ;:;;.' - I ~ . -,y: ,;:

~ . . ~ ~ -. - .<<.s: >; , . ... . . . ..L. - . . ..;-. , .... .. . . .;

{ ~ h a ~ 1 7 - 2 8 0 - 3 1 5 17 /06 /02 10:50 Page 314 m

The nearest settable values are 0.2434 0.656Q, and 0.206Q respectively.

The lens angle setting; a, is found from the equation:

and, substituting values.

amin = 62.5'

Use the minimum settable value of 90". The blinder angle, 8, is estimated to be 80', and requires checking during commissioning. Timers T, and T, are set to l5ms as

- .. experience has shown that these settings are satisfactory - to detect pole slipping frequenries up to IOtlz. -- .c1

This completes the settings required for the generator, *-r

o and the relay settings are given in Tabte 17.5. Of course, - ;?, additional protection is required for the generator

transformer, according to the principles described in U

Chapter 16. L

5 E c

C L 17.1 Survey of Rote O f Change o f Frequency Relays 2 - - . ond Voltoge Phase Shif? Relays for Loss o f Moins C F Protection. ERA Report 95-0712R. 1995. ERA

5 k Technology Ltd. .

ng Criteria

APPS Combined course Generator Protection -Setting

Criteria & Tutorials Page 1 of 45

-

The action required f3llowing response of an electrical or mechanical protectior~.is often catzgorised as follows: . -

- I i Urgent shutdown 7 Non-urgent shutdo.:. 'i Alarm only

-An urgent shutdown I:. 3uld .be required, for example, if a phase to phase fault occurred within -vie generator electrical connection. A non-urgent shutdown might be s ~ ~ u e n t i a l , where the prime mover may be shutdown prior to electr-ically ur, zading the generator, in order to avoid over- spesd. A non-urgent shutdc.-,,n may be initiated in the case of continued unbalar~ced loading. n this case, it is desirable that an alarm should be given before shutdo\/. .- becomes necessary, in order to allow for operator intervention to remed.. -iie situation.

. ... I. . . .<. : . .:.,::

For urgent tripping, - may be desirable to electrically niaintain The \ 1 ,. :- . :i p . ..-. .. .: :. -

shutdowr-7 condition :.!ith -latching protection output contacts, which ... ,. i .

would requir-e manuc resetting. For a non-urgent shutdown, i? rnay be *. . .::. . .+'..

. . d... .. . required that ttie oc-zvt contacts are self-reset, so that production of -:;..-.a ;'.-. . . ,... ,,

,.. ~. . :. power can be re-stcr-53 as soon as possible. .. < &:'.

. 1 Generator differential protection

Failure of stato~. winc--,gs, or connection isulalion, can result i ! i severe damage to ttie wine'.-3s and stator core. The extent of the dar-riage will depend upon the f::ult current level and the duration of ihe fault. Protection should be zpplied to limit the degree of damage in order to limit repair costs. For :::.iniary generating plant, high-speed disconnection of the plant from t t i t - ::Jwer sysiem niay be necessary to niaintain sysieni

- -- - -- -

OALSTOM Limited, Eries-gy ~utomat ion & Inforniation

APPS Combined course - Generator Protection -Setting

Criteria & Tutorials Page 3 bf 45

High impedance differntial protection

I The high impedance principle is best explained by considering a differential scheme where one CT is saturated for an external fault, as shown in Figure 3.

If the relay circuit i s . considered to be a very high impedance, the secondary current produced by the healthy CT will flow through the saturated CT. If 'the magnetising impedance of the saturated CT is considered to be negligible, the maximum voltage across the relay circuit will be equal to the secondary fault current multiplied by the connected impedance , (Rw+ R L ~ + R.iz~12)

The relay can be made stable for this maximum applied voltage by increasing the overall impedance of the relay circuit, such that the resulting current through the relay is less than its current setting. As the impedance of the relay input alone is relatively low, a series connected external resistor is required. The value of this resistor, RST , is calculated by the formula shown in Figure 3. An additional on linear resistor, Metrosil, may be required to limit the peak secondary circuit voltage during internal fault conditions.


. .

$.- I:. , r. . 5

APPS Combined course

- Protected zone

I Voi lage a c r o r s relay circuit I ..<?'.! .. ~ . . . . ..

Criteria & Tutori

j where K .- i .S

, .:"! Srab:l i s i n g resistor, R . l imi ts s p i I : curren: t.= lc j r s l u y sertir;g.l .:-:md .51fi

g . 4

R st - VS ..;;<g - - R~ .;:*:n .. . Is -. . !* *

... W'here R R = rdq burden . ;: ..., ..:.

. :.= ;

To ensure that the protection will operate quickly during an internal fault the CTs used to operate the protection must have a kneepoint voltage of at least 4Vs.

42:; "7%' .

Setting guidelines for high impedance differential protection . Is? :g,

. .... .p,

.. ..G ,C: ..I*!

;:%$. The differential current setting, should be set to a low setting to protect as much of the machine winding as possible. A setting of 5-10 % of rated-$$ current of the machine is generally considered to be adequate. his'% ,;i&

setting may need to be increased where low accuracy class CTs are used ;;. : to supply the protection. A check should be made to ensure that the , . # :$ primary operating current of the element is less than the minimum fault& cyrrent for which the protection should operate. ,q 3 OALSTOM Limited, Energy Automation & Information 1 :% ;&



The primary operating current (lop) will be a function of the current transformer ratio, the relay operating current , the number o f current transformers is parallel with a relay element (n) and the magnetising current of each current transformer (le) at the stability voltage(Vs). This relationship can be expressed in three ways:

I. To determine the maxim~~m current transformer mgnetising current to achieve a specific primary operating current with a particular .

relay operating current.

le < 1 /n (lop/CT ratio - I diff)

11. To determine the maximum relay current setting to achieve a specific primary operating current with a given current transformer magnetising current.

Idiff < ( Iop/CT ratio - nle )

... 111. To express the protection primary operating current for a particular

relay operaling current and with a particular level of magnetising current.

I,, = (CT ratio) x ( ldiil + nle)

In order to achieve the required primary operating current with the current transformers that are used, a current setting (I diff) must be selected for the high impedance element, as detailed in expression(ii) above. The setting of the stabilising resistor (RST) must be calculated in the following manner, where the setting is a function of the required stability voltage setting (Vs) and the relay current setting (I diff).

V s RST =

(I diff)

Note: the above fo;mula assumes negligible relay burden.

OALSTOM Limited, Energy Automation & Informalion

, '

APPS Carnbinecf course 4

Generator Protection -Setting '

Criteria & Tutorials - Page 6 of 45

Metrosils are used to limit the peak voltage developed by the current transformers under internal fault conditions, to a value below the insulation level of the current transformers, relay and interconnecting leads, which are normally able to withstand 3000V peak.

The following forn~ulae should be used to estimate the peak transienl voltage that could be produced for an internal fault. The peak voltage produced during an internal fault will be a function of the current transformer kneepoint voltage and the prospective voltage that would be produced for an internal fault i f current transformer saturation did not occur. This prospective voltage will be a function of maximum internal . -..< ..:

. . fault secondary current, the current transformer -ratio, . . the .current::$ transformer led resistance to the common point; the relay lead resistonc&-"j

. : and the stabilising resistor value. . . .

. . .

Vp = 2 < 2 Vk (V f - Vk)

Where

Vp = peak voltage developed by the CT under internal fault condiiiol-1s.

Vk = current transformer knee-point voltage

Vr = Maximum voltage that would be produced if CT saturation did not 1 occur.

Setting guidelines for Stator earth fault protection function (51 N)

Current operated from a CT in the neutral earth path. -- ----

, OALSTOM Limited, Energy Automation & Information

',.: APPS Combined course ?.... Generator Protection -Setting f 3 !+-:. Criteria & Tutorials

Page 7 of 45

Two independent tripping stages. First stage tripping can incorporate either a definite time or standard

inverse type IDMT delay Second stage tripping can be instantaneous or definite time delayed. . .- Immune to third harmonics.

Applied to directly connected generators.

The protection must be time graded with other earth fault protection.

The setting employed should be less than 33% of the earth fault level.

A setting of 5% of the earth fault level should be applied for applications where the differential protection provides less than 95% coverage of the stator winding.

Applied to in-directly connected generators. (with the generator earthed via a distribution transformer)

Can be supplied from a CT in either the primary or secondary circuit of the distribution transformer.

With a CT in the primary circuit, th.e protection has the advantage of being able to detect an earth fault which causes flashover of the primary winding of the distribution transformer. With the CT in the secondary circuit the protection has the advantage of detecting a short circuit across the loading resistor. A sensitive 5% setting can be applied to the first tripping stage, a short time delay can be applied to stabilise the protection against small earth currents due to VT failures or earth leakage during HV system faults.

The second tripping stage can be utilised as a high set. A 10% setting and instantaneous operation ensures fast clearance of generator earth faults.

In the case of direct generator connection, it is common that only one generator of a parallel set is earthed at any one time, with the earth connections of other machines left open. If the generating plant can also be run directly in parallel with a medium voltage public supply, i t i s a common requirement that all generator earth connections are left open during parallel operation. In such circumstances, the main earth fault

- I -


APPS Combined course Generator Protection -Settins

- Criteria 8 Tutorial P a g e 4 ! -

protection element (le>) will only be operational for an earthed machine It will provide primary earth fault protection for the associated machine backup earth fault protection for other machines and the rest of th power system and thermal protection for the earthing resistor.

For indirectly connected applications, the time-delayed earth fat protection function may be employed in one of two ways:

1 . To measure earth fslult current indirectly, via .a CT in the secondc circuit of a distribution transformer earthing arrangement.

-

2. To measure earth fault directly, via a CT in the generator winding ea connection.

With the first mode of application, the current operated protecli function (51 N) may be used in conjunction with voltage operat protection function {59N) , measuring the distribution transforr, secondary voltage. This is a complementary arrangement, where .

voltage operated protection function (59N) is able to operate in event of an open-circuited loading resistor and the current opera protection function (51N) is able to operate in the event of a sh circuited resistor.

The second mode of application would be used for cases of di resistive earthing. For distribution transformer earthing, this mode offers advantage of being able to respond to an earth fault condition leads to a flashover of the distribution transformer primary connect Such a primary short circuit would render protection on the secon side of the transformer inoperative and it would also result in a very and damaging primary earth fault current.

In either mode of application, the main stator earth fault current oper protection element (le>) should be set to have a primary sensitiv' around 5% of the maximum earth fault current as limited by the ear impedance. Such a setting would provide protection for up to 95% c generator stator windings. The probability of an earth fault occurring lower 5% of the generator windings would be extremely low, due i fact that the winding voltage with respect to earth is low in this regior



Page 9 of 45

The time characteristic and setting of the main current operated protection element (le>) should be set to prevent false sperufion during HV system earth fault clearance, where a transient generator earth connection current may appear as a result o: the inter-winding capacitance of the generator step-up transformer. The protection element should also co-ordinate with operation of generator VT primary -fuses, for a VT primary earth fault, and with VT secondary fuses for a secondary earth fault on a VT that has its primary windings earthed. Depending on the VT fuse characteristics, and on HV system earth fault protection clearance times, a definite time delay anywhere between 0.5s and 3.0s would be appropriate.

In machiqes with complex winding connection arrangements, e.g. some hydrogenerators, the probability of a fault occurring in the stator winding star-end region (first 5% of-the winding) might be higher. For a highly rated, expensive machine, such increased probability may prompt operators to apply 100% stator earth fault protection. A suitable 100% stator earth fault protection scheme can be3pplied in these cases.

100 % Stator Earth Fault Protection

The conventional unit type generator has the neutral earthed through a resistance loaded distribution type transformer. For a single ground fault near the neutral end of the winding , there will be proportionately less voltage available lo drive the current through the ground, resulting in a lower fault current and a lower neutral bus voltage.

8 ,

i' OALSTOM Limited, Energy Automation & Information

Q - iiealtky Cor,dlt.ion F - Faulty Condition

Figure 4

If an earth fault occurs and remains undetected because o its location ( otherwise the probability of a second fault occurring is much greater. Tt- second fault may result from insulation deterioration caused by transie overvoltages due to erratic , low current , unstable arcing ut the first fat point. This second fault may yields of larger magnitudes.

. A 100% stator earth fault protection is designed to detect earth fat occuring in the regions of machine windings close to the neutral end works on principle involving monitoring of the neutral side and line si components of the third harmonic voltages produced by the generators.

-- --

OALSTOM Limited, Energy Automation & Information -

APPS Combined course -

Generator protection -Setting Criteria & Tutorials Page 11 of 45

AC generators in service produce a certain magnitude of third harmonic voltages in their windings. Under healthy conditions of working the third harmonic voltage developed by the machine is shared between the phase to ground capacitive impedance at the machine terminal and the neutral to ground impedance at the machine neutral. In general, under healthy conditions the line and neutral impedances are fixed. Thus irrespective of the magnitudes of the generated third harmonic V3, the third harmonic voltages at the machine line end VL3 and neutral end VN3 should bear a constant ratio.


.- Criteria 8 Tutorials Page 12 of 45-

Referring to figure 4 it may be noted that when fault occurs at a point say F on the machine -winding, the voltage distribution VN3/VL3 undergoes a change from that during healthy running condition. In the extreme case of a fault occuring on the machine neutral , VN3 becomes

i:. ;:,. r zero and VL3 becomes equal to V3. Similarly when a fault occurs on the r'r g. phase terminal VN3 becomes equal to V3. Ffor all other fault positions,and ic depending on the f a ~ ~ l t resistance, VL3 & VN3 magnitudes will vary. F:

, ,

$! p

f . [rom the figure 5 it is clear that in order to remain stable under healthy !.: 5::

conditions the relay should restrain with in the two lines . The slopes of the I..; : : two lifles namely n11 & m2 can be suitably set to ensure stability and the r : same will vary from n~achine to machine.

Setting guidelines for Neutral voltage displacement protection function

Voltage operated

Single n7easuring element two time delay stages.

In~mune to third harmonics.

Applied to directly connected generators.

Supplied from a broken delta VT

The voltage setting should be greater than the effective setting of any down-strean? earth fault protection.

A time delay sufficient to allow downstream earth fault protection to operate first should be used.

Fast earth fault protection can be enabled when the generator is no1 connected to the rest of the system.

Application to a directly connected generator -

I t


. APPS Combined course Generator Protection -Setting

Criteria 8, Tutorials Page 13 of 45

For .tl-~is mode of application, the neutral voltage displacement protection fa ,n,-tin I L I I , ~ should be driven from a broken-delta-connected secondary

winding of a generator terminal VT that has i ts primary winding star-point earthed. 'This VT should be made up of three single-phase units or should be a single-phase unit with a 5-limb core. If the VT is not provided with an independent set of secondary windings for broken delta connection, a set of three single-phase interposing VT's should be applied. The interposing VT's should have their primary windings connected in star to the main VT secondary winding terminals and star-point. Their secondary windings should be connected in broken-delta ,;ormat, to drive the neutral voltage displacement protection function. ~lternafively, this protection function could be driven from a single-phase VT connected between the generator winding star-point and earth.

The voltage setting of the neutral voltage displacement protection function should be set higher than the effective setting of current operated earth fault protection on any outgoing feeder from the generator bus. The setting should also be higher than the effective setting of the sensitive directional earth fault protection applied to any parallel generator. The effeciive voltage setting of any current operated earth fault proteclion may be established by multiplying the primary operating current of the protection b y the generator grounding impedance and dividing by one-third of the VT winding ratio, in the case of a broken delta VT arrangement, or by the actual VT winding ratio in the case of a single- phase star-point VT. -

Applied to in-directly connected generators.

Supplied from the secondary winding of a distribution earthing transformer or from a broken delta VT.

A sensitive setting can be applied.

A short time delay can be applied to stabilise the protection during voltage fluctuations due to VT failures or earth linkage during HV system faults.

OALSTOM Limited, Energy Automation & 1nf6rmation

-

APPS Combined cocrrse - Generator Protection -Setting


Application to an indirectly connected generator

For this type of application, the voltage operated stator earth fault protection function should be driven from the secondary winding of a distribution earthing transformer. In the case of direct resistive. earthing, or of no deliberate earth connection, the protection should be driven from a VT winding.

The voltage setting of the protection function should be set to 5% of the voltage that would be applied to the relay in- the event of a solid fault occurring on one of the generator terminals. This would offer approximately 95% coverage of the generator winding. The voltage operated protection function might be used to complement the current operated protection fundion in the case of distribution transformer earthing.

Setting guidelines for Voltage-dependent overcurrent protection function (51 V)

Provides back up protection for uncleared downstream faults.

The protection operating mode can be configured to be: a simple overcurrent, a voltage controlled overcurrent or a voltage restrained overcurrent function.

In any of the modes of operation, the associated time delay can be either definite time or standard inverse IDMT.

-The voltage dependent overcurrent protection must be time graded with down-stream overcurrent protection. Where overcurrent reluys with start contacts are used on outgoing feeders, time grading con be achieved by blocking the opera-tion of the voltage del-~cndent overcurrent protection.

In the simple overcurrent mode the system voltage has no effecl on the current setting of the protection.

At normal system voltage the current setting should be 5% above ful load current. - - . . .. .-

r OALSTOM Limited, Energy Automation & Information


Criteria (L Tutorials Page 15 of 45

When a fault close to the generator will result in a fault current decrement the system vgltage should be monitored to distinguish

I between normal load current and a system fault. Here either the voltage controlled or the voltage restrained modes of operation should be se1ected.A step change in the current setting is initiated i f the system voltage falls below a selected level.

1 Applied when the generator i s directly connected to the system.

I At normal system voltage the current setting should be 5% above full load current.

I Under low voltage conditions, the current setting should be reduced to less than 50% of the minimum steady state fault current

The voltage control threshold should be selected to ensure that a voltage reduc-

- tion due to a single phase to earth fault will not result in a change of the current setting. -

When negative phase sequence protection is also applied, the calculation of the voltage threshold need only consider the effect of a remote three phase fault.

I The voltage-dependent overcurrent protection function is a three-phase protection function that is driven by the general protection CT inputs and which is intended to provide backup protection for an uncleared phase fault on the generator busbar or on a feeder from the busbar.

In the case of a generator passing h~ghly reactive current to a fault the level of fault current can fall below the maximum possible machine load current within 0.5s-1 .Os unless a fast-acting automatic voltage regulator (AVR) is available. This is because the AVR is able to boost the level of field excitation during a fault. The problem of fault current decrement can be most acute when the excitation supply is derived from a transformer connected to the generator terminals. Where a fault current decrement - is

t


$ APPS Combined course ':,A. .' :%

Generator Protection -Setting Criteria 8, Tutorials . " : ,$

Page 16 of45 X t .i:

.. , .

*. possible, voltage-dependent overcurrent protection provides lime- delayed backup protection with adequate sensitivity for a multi-phase 2 busbar or feeder fault, whiist remaining siabie for ;he highest aniicipaieci level of generatar load current. The generator terminal voltage is monitored as a way of being able to distinguish between normal load and system fault conditions.

In the voltage-controlled protection mode, a step-change in current setting (I> to K.I>) is imposed when the monitored voltage signal drops . below an adjustable threshold setting (Vs).

The under voltage switching threshold setting (Vs) should be selected so that switching does not take place with the minimum possible phase- 1.;; phase voltage for single phase to earth fault conditions. For a single phase :'; fault, the minimum possibje phase-phase voltage would be for a close-up :.!;

earth fault on a solidly earthed power system, where the voltage could fall iK:: to 57% of the nominal level. The voltage setting should also be set above..,$;. the maximum phase-phase voltagefor anyelement required to operate-:$ for a remote-end feeder fault. If the negative phase sequence thermal::;: protection function is set and enabled, a remote three-phase fault need !$i

.:* only be considered when determining the voltage threshold setting (Vs). .:& . i; .*. .'. .+%

. .... . . ." . :.:. ..*

. . ,.:, Reverse power and low forward power protection functions (32R/32L)

... , *;:;

Reverse power protection-

:,; ,..- r . : .

Detects active power flow into the generator. ,>

., ..a , ,\ ,: ~..>.

The level of power required to motor the generator will depend on the :;$ , .

type of prime move[. ...$ . p. ! ..i.

..>$

A high sensitivity current input is used to monitor the system power. his$ may be connected to the main system protection CT's or, for application^,$ which require a sensitive setting, the input can be driven from a high4 accuracy measuren7ent CT. 3%

$3

QALSTOM ~ik i ted, Energy Automation & Information

>mbined course Generator Protection -Setting

A compensation angle setting is provided to compensate for CT and VT phase errors.

A time delay (typically 5s) should be used to prevent operation of the protection during some system fault conditions and power system swings.

I To detect fluctuating reverse power flow, which could result from failure of a reciprocating prime mover, a delay on drop off timer is available, in addition to .the delay on pick up timer.

Low forward power protection.

1 Operates when the fom/ard power falls below the set level.

1 Operation can be instanianeous or time delayed. -

Usually interlocked with non-urgent protection to reduce over speeding of the generator following breaker operation for a non-urgent fault.

~ypical levels of motoring power and possible motoring damage that could occur for various types of generating plant are given in table

I below.

Prime mover power Possible damage

Risk of fire or explosion Gas Turbines 10 - i5% Reverse torque on

- Blade and runner cavitation

Steam Turbines Thermal stress in blades

The need for automatic disconnection is arguably less for plant that i s continuously supervised, but, in .the event of prime mover failure, the attention of control staff could be diverted by other aspects of the --

t


A?PS Combined course Generator Protecfioii -Seffing

Criteria 8 Tutorials Page 18 of 45

mechanical failure. If motoring damage can occur rapidly, operator action may be too slow to prevent the onset of damage, so there may be a requirement for automatic generator disconnection or for an alarm to be raised. For unattended generation plant, e.g. small hydro schemes that are only periodically supervised, automatic generator disconnection should occur even if immediate prime mover damage would not be envisaged. If automatic disconnection did not occur in such cases, motoring may be possible for hours, with plant damage being gradually inflicted. Automatic disconnection would also prevent an unnecessary power system loss-,

In many cases, prime mover failure can be detected by non-electrical means; e.g. by a steam turbine differential pressure switch or by a hydraulic flow device. If mechanical means of detecting prime mover failure are provided, an electrical measurement method would not be required or would only be used for backup detection.

. . . --."? - .*-,

: :. .:-g< -> ....

,.A- . -.-- - .,*..

. .>',.;:2' . . .t:xd ..

. . .--4 .

The reverse power protection function needs to be time-delayed to'.$$ij prevent false tripping or an alarm given during power system swings, ,$g

..-<

following power system disturbances or following synchronisation. In some .$!! r.T7-

applications, the reverse power protection function should be disabled ';$$ during certain modes of protected machine operation. One example of $@ such a situation is where, during dry seasons, a synchronous machine is 3 de-coupled from its hydraulic prime mover and operated as a g. ..,::,:

synchronous compensator for power system VAR control. .::$j$

.:3. +>:: . . .!=; .,,: ..I;:?;

Low forward power protection function (32L)

. . ,.-

This protection function is offered for those users who wish to interlock non-

power measuring element confirms that the mechanical drive has bee cut. Such an arrangement would ensure that there w o ~ ~ l d be no possibilif of generator set over speed when any restraining electrical load is cut b electrical tripping.


APPS Combined course . -. .- Generotor Protection -Setting

-- Criteria & Tutorials . Page 19 of 45

With any generator, tripping of the generator breaker and excitation system should be accompanied by throttle or valve closure. There is always a risk, however, that the throttle/valves may not close fully and that machine over speed will result when electrical loading is removed. With large high-speed steam turbo-alternator sets, an apparently small over speed could result in machine damage or wreckage, as well as a threat to human safety. Failure of a steam valve to fully close during a shut-down is an obvious risk This over speed risk could be addressed by using duplicate valves in series.

Even where valves, etc., do close fully, there will be some lag in dissipating all the energy within a prime mover, especially in the event of a shutdown from full-load. Some types of plant, are very prone to over speed following rejection of full-load, but have a good over speed tolerance, e.g. slow- speed hydro generators. Large turbo-alternators, with slender,low-inertia rotor designs, do not have a high over speed tolerance and trapped steam in the turbine, downstream of a valve that has just closed, can rapidly lead to over speed. To reduce the risk of over speed damage to such sets, i t i s sometimes chosen to interlock non-urgent tripping of the generator breaker and the excitation system with a low forward power check. The delay in electrical tripping, until prime mover energy has been completely absorbed by the power system, may be deemed acceptable for 'non-urgent' protection trips; e.g. stator earth fault protection for an indirectly connected generator. For 'urgent' trips by instantaneous electrical protection, e.g. stator winding current differential protection, any potentially delaying interlock should not be imposed. With the low probab~lity of 'urgent' trips, the risk of over speed and possible consequences must be accepted.

With a large generator, even a very small percentage of rated power could quickly accelerate an unloaded machine to a dangerous speed. A typical under power setting requirement would be 0.5% of rated power.

The time delay associated with the low forward power protection function (t) could be set to zero. However, some delay is desirable so that permission for a non-urgent electrical trip is not given in the event of power fluctuations arising from sudden steam valvelthrottle closure. A typical time delay for this reason is 2s.


APPS Combined course . .

Generator Protection -Setting .i Criteria 8 Tutorials ,.:

Page 20 of 45 B

:$!

-

Negative phase sequence thermal protection function (46)

l Protects the rotor of a generator from damage resulting from the heating effects of negative phase sequence currents.

l Provides true negative phase sequence thermal protection and a definite time alarm.

l Accurate over a wide system frequency range.

l The trip threshold should be set slightly higher than the constant negative phase sequence current withstand of the generator.

l The protection must be time graded to allow downstream protection to clear an unbalance fault.

.-

T o achieve easier grading with. down stream protection, during-:-f clearance of a heavy asymmetric fault, a minimum operating time for the''$

. . negative phase sequence protection can be set.

l For negative phase sequence currents slightly above setting, a .

maximum trip time can be set.

l Can provide back up protection for uncleared asymmetric faults.

l Models the cooling characteristic of the generator, following exposure to negative phase sequence currents.

l The alarm element is commonly set to 70% of the trip setting with a time delay well above the time taken to clear any system faults. The alarm element functions directly on the measured level of negative phase sequence current.

The NPS protection function is provided for applications where a generator (synchronous machine) is particularly susceptible to rotor thermal damage, in the event of the current supplied to the power system becoming unbalanced. The degree of susceptibility will depend on the -

generator rotor design (cylindrical or salient construction), methods - of




forced cooling employed and the presence of any ancillary metallic rotor components.

Monitors the generators terminal irr~pedance in order to detect failures in the excitation system.

Uses a circular, offset mho, irr~pedance characteristic. '

The diameter of the impedance characteristic is based on the direct synchro-nous reactance of the generator.

.The offset of the impedance characteristic based on the direct axis transient reactance of the generator.

. An associated definite time delay prevents operation of the protection during stable power swings.

I Can be interlocked with the under voltage protection element to

I prevent operation during power swings.

A delay on drop off timer-can be used to detect cyclic operation of the field failure protection. This could result during pole slipping.

This protection function measures the impedance at the terminals of a generator that is run in parallel with another source to detect failure of the generator excitation. The current used for single phase impedance measurement is obtained from the 'general protection CT inputs and the voltage is obtained from the main VT inputs. This protection function is provided with an adjustable, offset circular impedance characteristic, see Figure 6 , an adjustable tripping delay timer (t) and an adjustable measuring element reset time delay (tDO).

OALSTOM Limited, Energy Automation - & Information

Figure 6

Complete loss of excitation-may arise as a result of accidental tripping of the excitaiion system, an open circuit or short circuit occurring in l11e excitation DC circuit, flashover of any slip rings or failure of the excilolion power source. A pure open circuit in the excitation system i s unlikely to he long-lasting in view of the high voltage that would be developed crc~oss the open circuit with the machine running and connected to a po\ver system. Such a fault is likely to evolve quickly into a short circuit fauli.

OALSTOM Limited, Energy Automalion & Information

.. ? APPS Combined course

Generator Protection -Setting Criteria 8 Tutorials

Page 23 of 45

Where a generator stabilises at a high level of slip, following excitation failure, the reverse inductive impedance seen at the generator terminals will be highly reactive and will be less than the direct axis synchronous reactance of the machine (X d ). A typical minimum value for this impedance is twice the direct-axis transient reactance of the generator (2X d ' ) for a level of slip below 1%. Figure 6 shows a typical machine terminal loss-of-field impedance locus, which illustrates the effect of rotor flux decay, leading to gentle pole-slipping and eventual stabilisation as an induction generator with a level of slip of around 1%.

To quickly detect a loss-of-field condhion where machine damage may occur, the diameter of the relay field-failure impedance characteristic (Xb) should be set as large as possible without conflicting with the impedance that might be seen under normal stable conditions or during stable power swing conditions. To meet this objective, it is recommended that the diameter of the relay impedance characteristic is set equal to the generator direct-axis synchronous reactance in secondary ohms. The characteristic offset should be set equal to half the direct-axis transient reactance (O.5X d' ) in secondary ohms.

The above guidelines are suitable for applications where a generator i s operated with a rotor angle of less than 90" and never at a leading power factor. For generators that may be operated at slightly leading power factors and which may be operated with rotor angles up to 1 20°, by virtue of high-speed voltage regulation equipment, the settings would need to be different. The impedance characteristic diameter should be set to 50% of the direct-axis synchronous reactance (O.5X d ) and the offset should be set to 75% of the direct axis transient reactance (0.75X d ' ) .

The field failure protection time delay (t) should be set to minimise the risk of operation of the protection function during stable power swings following system disturbances or synchronisation. However, i t should be ensured that the time delay is not so long that stator winding or rotor thermal damage will occur. The stator winding should be able to withstand a current of 2.0 p.u. for the order of 15s. It i s unlikely that rotor damage would be incurred in much less time than this. It must also be appreciated that i t may take some seconds for the impedance seen at the generator terminals to enter the selected characteristic of the protection function. However, a time delay less than 10s would typically be applied. The minimum permissible delay, to avoid potential problems

#




of false tripping due to stable power swings with the above impedance settings, would be of the order cf 0.5s.

Some operators have traditionally interlocked operation of impedance- type field failure protection with operation of under voltage detection elements in order to allow a low field failure protection time delay without the risk of unwanted tripping for stable power swings. This arrangement may also have been used to prevent field failure protection operation for hydrogenera tors that may be run as synchronous compensator's, with the turbine mechanically decoupled. ,

The field failure protection fucction is offered with an adjustable delay on reset of the trip timer (tDO). This lime delay can be set to ovoid delayed tripping that might arise as a result of cyclic operation of the impedance measuring element during the period of pole-slipping following loss of excitation. The delay on reset of the trip timer (tDO) might also be set to allow the field failure protection funclion to be used for detecting pole slipping of the generator when excitalion is not fully lost; e.g. following time-delayed clearance of a nearby power system fault by delayed protection.

Under voltage protection function (27)

Operates when the three phase voltages fall below the common set point. An adjustable timer is available.

Can be interlocked with the field failure protection to prevent its operation during stable power swings.

Can be used to initiate dead machine protection

Can detect failure of the AVR or system faults which have failed to be cleared by other means.

Prevents damage to any connected loads which could occur- during operation at less than rated voltage.


p

t APPS Combined course Generator Protection -Setting

Criteria &Tutorials Page 25 of 45

nrc ;;:<, *... The pick up level sho~lld be set to less than the voltage seen for a three F;;7; .2-' 9..

t:2t- phase fault at the remote end of any connected feeder. #*?.;,.

$. . .

The time delay should be set to allow the appropriate feeder protection I I to operate first to clear the fault, and. also to prevent operation of the

protection during transient voltage dips.

A dedicated input is provided to block the operation of the under voltage and under frequency protection during run-up or run-down of the generator. This input can be driven from an auxiliary contact in the circuit breaker.

Under voltage protection can be used to detect abnormal operating conditions or an uncleared power system fault that may not have been detected by other generator protection.

',: .. .:... ...-. . For an isolated generator, or for an isolated set of generators, especially in - ..

. . the case of standby generating plant, -a prolonged, under voltage

..: :- . , . . . condition could arise for a number of reasons. One reason would be some ;.,.. :.. .. .,. , failure of automatic voltaae reaulation IAVRY eaui~ment. If such a g:::: +:. condition persists, automatic generator tripping should be initiated. to &.:, .:-.: &:,.l:: kf' r . .C ...

prevent -possible damage to system loads. Another reason could be that 3.;::. ,;. :.. a fault exists somewhere on the power system that has not been cleared P by other means. 1 : . ,p '

s..:; .~ F :, ,, In the case of generators feeding an industrial system, which is normally e;:: fed from a public-power supply, system overcurrent protection settings . . .. would have to be above maximum levels of system load current with the

i .,._ 5~: .. .' %..

normal supply available. I f the public supply fails, the local generation :.'..': . , ,. would be left feeding the entire system. Where the local generation is ;i ;

unable to meet the entire system load, there would be a provision for the . ...

:?:: I+'c automatic shedding of non-essential loads. If a fault subsequently i l.IC, Occurred on the system, the relatively low fault current contribution of the .>.< . . local generation and its decrement with time may result in the system ,;;::> ,... ~s;. .. overcurrent protection failing to respond. In this case it would be , :"" ,:.> : expected that the generator backup overcurrent should operate. :;5 $: 4; . . I . g2:. ;,,:;: & L ~ v>;y,.: Operation of generator overcurrent protection in the above : ,, .,>- . . circumsfances can be assisted by employing voltage-dependent :,.; , &;,:! ,2i:....., r.lr.bl-.

- protecfion.Wt-,ere there is a parallel set of generators, -- and where the fault

: OALSTOM Limited. Enerav Automation & Information

APPS Combined course Generator Protection -Setting ::

Criteria 8 Tutorials .:

Page 26 of 45 ?% 3 ,:s<. !B <j

is relatively remote from the generators, even the generator voltage- ,$ dependent proteciion r i iay fail to respond to the fault. If the fault is $ "; asymmetric, and if the negative phase sequence thermal protection function has been set and enabled, the unbalanced fault current may be sufficient to operate this form of generator protection. The worst situation would be for an uncleared three-phase fault. Although such a fault would be rare, it may be that the only form of protection that would reliably detect the fault would be generator under voltage protection.

In the case of large thermal power plant generators, a prolonged under voltage condition could adversely affect the performance of the auxiliary plant such as boiler-feed pumps and air-blowers. This would ultimately have an effect on the primary plant performance. If such a situation is envisaged, the application of time-delayed under voltage protection to trip the generator might be a consideration.

The under voltage protection function threshold (V<) should be set below the steady-state phase-phase voltage 'for a. three-phase fault at the-' remote end of any feeder connected to the generator bus or up to selected locations within an industrial power network. Allowances should be made for the fault curcent contribution of parallel generators, which will tend to keep the generator voltage up. The time setting of the under voltage protection function (t) should be set longer than the time required for backup feeder protection to clear remote-end feeder faults. The delay should preferably be longer than the time required for the generator back-up overcurrent protection function to respond to such a fault. ~ddifionally, the delay should be long enough to prevent unwanted operation of the under voltage protection function for transient voltage dips during clearance of faults further into the power system or by starting of local machines. The required time delay would typically be in excess ol 3s-5s.

To prevent tripping of the under voltage protection function followinc normal shutdown of a generator, a normally closed circuit breake auxiliary contact should be used to energise the under voltage inhib logic input.

Over voltage protection function - (59)




* Operates when the three phase voltages are above the common s e t point.

t i Two tripping stages, each with an aajustable timer.

i 1 Protects against damage to the generator insulation and that of any

L connected plant.

Recommended for hydrogenerators which may suffer from load rejection. -

f t *Time delayed protection should be set with a pick up voltage of 100- i 120% of the nominal voltage and a time delay ~ufficient to overcome 1 operation during transient over voltages. E I Instantaneous protection with a setting of 130% - 150% of the nominal I voltage can be implemented. I -. L -

An unsynchronised generator terminal over voltage condition could arise when the generator is running, but not connected to a power system, or where a single generator is running and providing power to an isolated power system. Such an over v~l tage could arise in the event of a fault with automatic voltage regulating equipment or if the voltage regulator is set for manual control and an operator error is made. Over voltage protection should be set to prevent possible damage to generator insulation, prolonged over fluxing of the generating plant or damage to isolated power system loads,

E: When a generator i s synchronised to a power system with other sources, a - synchronised over voltage could only arise i f the generator was lightly loaded and was requiced to supply a high level of power system capacitive charging current. An over voltage condition might also be possible following a system separation, where a generator might experience full-load rejection whilst still being connected to part of the original power system. The automatic voltage regulating equipment should quickly respond to correct the over voltage condition, but over voltage protection is advisable to cater for a possible failure of the voltage 'regulator to correct the situation or for the possibility .of the regulator having been set to manual control.

t.


APPS Combined course Gsnerctor Protection -Setting ,


4 g $ The worst case of generating plant over voltage following a system 3 separation, which results in full-load rejection, could be experienced by

hydrogenerators. The response time of the speed governing equipment can be so slow that transient over speeding up to 200% of nominal speed could occur. Even with voltage regulator action, such over speeding can ;

result in a transient over voltage as high as 150%. Such a high voltage could result in rapid insulation damage.

The time-delayed over voltage protection function threshold (V>) should typically be set to ] 00%-120% of the nominal voltage . The time delay (t>) silould be set to prevent unwanted tripping of the delayed over voltage protection function due to transient over voltages that do not pose a risk to the generating plant; e.g. following load rejection with non-hydro sets. The typical delay to be applied would be 1 s-3s.

Under frequency protection function (81 U)

Two under frequency stages each with an independent timer.

First stage can be used to initiate load shedding for industrial systems. Time delayed to allow any down stream load shedding equipment to operate first.

Second under frequency stage to trip more rapidly.

.A dedicated input is provided to block the operation of the under voltage and under frequency protection during run-up or run-down of the generator. This input can be driven from an auxiliary contact in the circuit breaker.

As well as being able to initiate generator tripping, the under frequency protection can also be arranged to initiate local load-shedding, where appropriate. Under frequency operation of a generator will occur when the power system load exceeds the prime mover capability of an isolated generator or of a group of generators. Where the system load exceeds

--- I


APPS Combined course - . Generator Protection -Setting

.- Criteria & Tutorials Page 29 of 45

the alternator rating, but not the prime mover rating, the alternator could become overloaded without a frequency drop. !t would therefore be important for the alternator manufacturer to provide stator winding temperature measurem-ent devices, to give alarm or to automatically shut down the generator before winding thermal damage results.

-

Power system overloading can arise when a power system becomes split, with load left connected to a set of 'islanded' generators that is in excess of their capacity. Such events should be allowed for by system planners and automatic system load-shedding should be implemented so that the load would rapidly be brought back within the generation capacity. In this case, under frequency operation would be a transient condition; as during power swings. The degree of load shedding would have to take into account the fact that some generating plant, e.g. gas turbine plant, may have a reduced power capability when running below nominal frequency. In the event of under shedding of load, the generators should be provided wit,h backup under frequency protection to shut down the generating plant before plant damage or unprotected system load

. _ . . . .damage could' occur. . .

. .

Under frequency running at nominal voltage will result in some over fluxing of a generator, and its associated electrical plant, which needs to be borne in mind. However, the more critical considerations would be in relation to blade stresses being incurred with high-speed turbine generators; especially steam-driven sets. When running away from nominal frequency, abnormal blade resonance's can be set up which, if prolonged, could lead to turbine disc component fractures. Such effects can be accumulative and so operation at frequencies away from nominal should be limited as much as possible, to avoid the need for early plant inspections/overhaul. Under frequency running is most difficult to contend with, since there is little action that can be taken at the generating station in the event of load under shedding, other than to shut the generator down.

To prevent under frequency protection tripping following normal shutdown of a generator, a normally closed circuit breaker auxiliary contact should be used to energise the under frequency protection function inhibit logic.

-- 1

DALSTOM Limited, Energy ge tom at ion & Information

KT! A nnc r,,~:-- A - -. .-- - 8 . 7 ~ r r a ~ u r ~ i ~ ~ r i t f u course

ti i

Over frequency protection function (810)

i

r.: i. : G,: r,. ti t; r: i.", f ! f . Ci

Generator Proieciion -Seiiing Criteria 8, Tutorials

Page 30 of 45

. . . .'( ,;,2!.

, .'$? ..,&. . . . ri Single over frequency stage with associated timer. ?.+$; :,.a :,&i< .'LLz*!

,?$ Should be set abdve the sustainable over frequency level with a time .!# delay sufficient to overcome transient over frequencies following load 3; . .. rejection. ,!.:?> .:,so<> .. > ' . .83

.::? ..* ..: ln.4

. . C i i .:....

Over frequency running of a generating set arises only when the 3; mechanical power input to the alternator is in excess of the electrical 3 load and mechanical losses. The most common occurrence of over :I$

.&.$

frequency is after substantial loss of electrical loading. When a rise in ;:;j\ running speed occurs, the governor should quickly respond to reduce the :$

r L

mechanical input power so that normal running speed is quickly regained. :!;, ..,,:; .in. . .. . ,:?L rr)

Over frequency protection may be required as a backup protection .@ function to cater for governor or thiottle control failure following loisot.$ load or dyring unsynchronised running. -

- . . - :,!* :.+? M.: . ..<?

-.,$ ::*, ,.+..; .....LJ . .- ;;Q

Voltage balance protection function (60) . i$j . ?a .., .~ . ~ . X ..., I .? .'a ..?

..?.$2, . ,... .:5< :%

Detects VT fuse failure. . ;?; %.

-Supplied from the secondaries of two VTs or two separately fused'.. . ..

secondary circuits of a single VT. Used to raise an alarm and block voltage sensitive protection if,::

necessary. - . . ... .

Dead machine protection

For a multiple source power system, closure of a generator circuit breakel must be controlled either by automatic synchronising equipment, or by manual breaker closing carried out with the aid of synchronising instruments, and supervised by a synchronism check relay. .... .:F

1.p .. ,

Whilst inadvertent closure of a generator circuit breaker should not b! possible, a small risk does exist; especially when fault finding, carrying 0~

'.L ,> .>:

OALSTOM Limited, Energy Automation & Information :$ L 3' ?

APPS Combined course Generator Protedion -Setting


maintenance tests or testing control systems. The possible damage , caused by connecting a dead machine to a live power system, or

@ $ energlsing a steam turbo-alternator when on turning gear, could be extremely costly if a method of quickly tripping the generator breaker is not provided.

If a dead machine is energised from a live power system, rotor currents will be induced and the machine will accelerate as an induction motor. The induced currents in the rotor body and windings would be very high with the machine initially at standstill and could rapidly result in thermal damage unless the machine is designed for direct-on-line run-up as an induction motor (possibly for starting a gas turbine prime m'over). 'The unexpected shaft rotation could also result in rapid mechanical damage if lubrication systems are not running or if a steam turbo-alternator is on turning gear.

A number of protection functions could. respond to the inadvertent energisation of a dead .machine. The effective machine impedance. during such enegisation would be similar to i ts sub-transient reactance and so the current drawn from the power system would-be high. So under voltage and overcurrent protection functions could respond to the condition and can be interlocked with manual tripping Jogic to protect the machine against the inadvertent energisation of a dead machine.

OALSTOM Limited, Energy Automation, & Information



CTlG - I \ a a dead tl~lachine

1 t ?rip ping Backup Tripping

Pole-slipping protection

A generator might pole-slip, or fall out-of-step with other power system sources, in the event of failed or abnormally weak excitation or as a result of delayed system fault clearance; especially when there is a weak (high reactance) transmission link between the generator and the rest of the power system.

With large utility base-load generators, the requirement for pole-slipping f protection will be dependent on the transmission system reactance. In the ; case of generators connected to a dense, interconnected system, pole- ;' slipping protection may not be required. In the case of remote generation :! and a weak radial transmission link to the load centre, stability of :': generation may be an issue. Pole-slipping protection is frequently . !;.a -+

requested for relatively small generators running in parallel with strong $# public supplies. This might be where a co-generator runs in parallel with!$$ the distribution system of a public utility, which may be a relatively strong C# source, but where high-speed protection for distribution system faults is not $ provided. The delayed clearance of system faults may pose a stability$ .$

threat for the co-generation plant. . , , ... u..

OALSTOM Limited, Energy Automation & Information -

.b ,it:

C B 8:: :.-. ;-.: - . . - . APPS Combined course $%

- g2L Generator Profection -Setting. - . I' Criteria & Tutorials

Page 33 of 45

The pole slipping relay ZTO has been designed to protect Synchronous generators against the possibility of the machine running in the unstable region of the power angle curve which would result in pole slip.

The relay consists of one directional relay and one blinder relay operating in conjunction with 40-80 mSec timer . Both characteristics look into the source and consequently ignore all condifions of load other than those which produce a reversal of power flow such as would occur with a condition of pole slip or power ;wing exceeding 90 degree.

The timer is incorporated so that the discrimination can be made between a power swing and a pole slip -condition. A trip condition can only occur if the timer has timed out before the fault moves into t h e

. .

. .

If the fault never reaches the operate regionof the b1inder:or moves between the directional and blinder char.acteristics in a time less than the timer setting , no operation will occur.

lpodorro

.X

NUMERICAL EXAMPLE:

i'. h. . i: ' , . ' '%; k '. 6'-

Generator Details Terminal voltage Synctironous Reactance Xd Transient Raactance Xd' Sub-Transient Reactance Xd' ' Continuous Negative withstand capability 12' t Length of longest line emanating from the bus Impedance of the line

247 MVA 15.75 KV

205 % 23.4 %

17.9 %

Bus fault MVA 2071 -5 MVA

Full load current of the machine A ( MVAx 1000/ 1.732~ KV) Synchronous reactance of the machine Xd ohms (KVxKVx pu Xd / MVA) Transient reactance of the machine Xd' ohms (KVxKVx pu Xd ' / MVA) Sub transient reactance of the machine Xd" ohms (KVxKVx pu Xd' ' / MVA)

Generator line/neutral side CT primary current A Generator line/neutral side CT secondary current CT sec resistance Lead resistance

Generator PT primary voltage Generator PT secondary voltage

1 OYdO 5 k

1.5 ohms 1.1 1 ohms

},

9


5 APPS Combined course c Generator Protection -Setting


CT/ PT Ratio

CT primary for inter turn protection CT secondary for in-ter turn protection CT sec resistance Lead resistance

Generator Transformer rating -

Voltage ratio 24011 5.75 KV

Transformer lmpedance Transformer lmpedance in ohms ohms

Generator Differential Protection 87G - CAG 34

Maximum three phase fault current (Full load current/sljb transient reactance) Fault current referred to secondary

5000 A 5 A

0.75 ohms 1 ohm

250 MVA

1 4 %

Voltage developed across the relay circuit 93.68 V Fault current ref to sec ( CT resistance + 2 lead resistance)

Pick-up setting recommended Voltage developed across the relay at pick up (VA burden .of the relay / pick up current)

Stabilising resistance value 183.4

(Voltage developed across the relay-Voltage acro'ss rely at pick up/ Pick

Generator Inter-turn Protection 87G1- CAG 34

Maximum three phase fault current 25183 A + *

O A L ~ ~ O M Limited, Energy Automation & Information

Generator Field Failure Protection 40G--YTGM 15 ' '

. . . . . .

APPS Crmbiiied course Generator Protection -Setting

Criteria 8 Tutorials - Page 36 of 45 . .

(Full load current/sub transient reactance) Fault current referred to secondary

Voltage developed across the relay circuit 69.25 V Fault current ref to sec ( CT resistance + 2 lead resistance)

Pick-up setting recommended Voltage developed across the relay at pick up (VA burden of the relay / pick up current)

Stabilising resistance value 134.5 ohms (Voltage developed across the relay-Voltage across rely at pick up/ Pick up current)

Diameter setting (0.5 x synchronous recatance)

Diameter setting ref to secondary ohms

Offset setting of the relay ohms ( 0 . 5 ~ transient reactance)

Offset setting of the relay ref - to secondary

. . 1.03 ohms

1.68 ohms

Timer settings:

Pick up timer 10 Sec Drop off timer 2 Sec

OALSTOM Limited, Energy ~utomation & Information

Protection -Setting Criteria 8, Tutorials

Page 37 of 45

0.1 6 ohms

0.14 ohms

0.22

3.07 ohms

75 degree

55

. - -

- .- APPS Combined course Generator Protection -Setting


Generaivr Irr-~pedzjiice . -~ Generator transformer impedance :.A, . ,... ,.. Source impedance angle (generally assumed to be 80") .-,.

,.,+ .. .:> <;> , .

Rate of slip ( should be provided by the manufacturer, otherwise 26 assumed to be .I 600 Elec. Deg per second) :$*

-i* I I.,r ti., .p. ', .:, ,:2 ;-.. . .., . .. Procedure : .,... I' .*, . $ :>.; 1. Select a suitable scale for the diagram. Draw the X and Y axes with (8

5 , .

Origin as (0) - :?, : ..$

.*. a

2. Plot .the Generator impedance along the negative "Y- axis" to get 'i .- .. . point (G) J :.. , .. .. .

3. Plot the Generator Transformer impedance at positive "Y - axis" to get i ,.8'

point (T) -a

.: 4 . Draw source imped&nce at an angle of 80° (or source, impedance;::.<$ . .-::.

angle i f available) from point (T) to getpoint (S) . . -. .:..,,:2 _ : ..- . .:: .-. ..

. :,$< . . -.

5. Connect points (G) and (S) by a straight line.

6. The locus of Pole slip will be nearer to either (G) or (S) depending on the 1; ratio between emfs at (G) and (S). We assume this ratio to be equal to 1. Thus the pole slip locus is the bisector of line (G)--- (S). Mark the point ( 1 ) on the line (G) ---(S) where the Pole slip locus cuts it (centre of the line).

7. With point ( 1 ) as center and (1)---(GI as radius draw a circle. Mark the point where this circle cuts the locus as (2 ) .

8. Draw a line passing through the origin (0) at 75". Mark the point v,/here this line cuts the pole slip locus as (3). This i s the directional line.

9. Measure the obtuse angle at point (4) between the lines (G)---(4) and (S)---(4). This is named as (4.

1O.The obtuse angle at point (2) should be 270". Name this as (a,). .. .

. . , . . -.

- - -.: I

2, ;.: . . .:' OALSTOM Limited, Energy Automation & Information ' 3

:d .7:

4

APPS Combined course' Generator Protection -Setting

Criteria 8. Tutorials Page 40 of 45

;G

;*? ' ,.;f

OALSTOM Limited, Energy Automation & Information : rrc ...., 3 .%....

p"- g;:: g:: . : - :?,: APPS Combined course

Generator Protection -Settina Criteria 8, ~utofiag

Page 41 of 45

g: . Generator Back-up Impedance 21 G - YTGMl5

lmpedance required to cover the entire line under maximum generation conditions,

1 Where n is the No. of niachines in parallel

secondary

: . . .~ . [ . ._ .. ; ~ :~oward reach to be set in relay - ~ ohms

Reverse reach (25% of forward reach)

Timer setting = I sec

Timer setting need to be co-ordinated with Zone 2 Timing

= 0.98 ohms

i Negative Sequence Protection 46G- CTNM31

Negative seq current 125 = 5 %

122 t ( in terms of K1 & K3 ) = 8

QALSTOM Limited, Enerqy Automation & Information

APPS Combined course - . .- - .

12 Alarm setting -

Alarm timer setting (fixed) Sec

Generator Reverse Power Protection 32G - WCDM + VTT

Pick-up setting (depends on the type of prime mover)

Time delay

Generator

= 5 Sec

Voltage setting = 5.4 V . .:Q

'> ..

Time delay = 1 Sec .'.!/ -.* :.-

;% A* .<.

Time setting need to be co-ordinated with down stream Earth Fault relays in;'! ;$ case of Direct connected svstems. .-:+

Genera tor

Criteria & Tutorials

95 % Stator Earth Fault Protection 64s - VDGl4 . .-

-

100 % Stator Earth Fault Protection 64s - PVMM163

~ -~ ~ - - . - - - - ~ -~ . ~ ~ . . -~ -~ .~ ~ - ~ -

The required settings for this 95-1 00 % protection can be selected only on measurement and studying the machine third harmonic behaviour a1 site.

Measurement of Generator Third Harmonic Voltaaes

OALSTOM Limited, Energy Automation & Information J 9

Generator Protection -Setting Criteria 8, Tutorials Page 43 of 45

a) Measure the filtered third harmonic voltages from neutral side (VN3) and Line side (VL3) at the following TEST SOCKET pins provided on the front of the reiay PVMM. Digital muitimeter in AC millivolts range can be used for this purpose.

VN3 - Across 1 & 7 VL3 - Across 2 & 7

b) 'These measurements areto be made during voltage build up of Generator before synchronization and after synchronizing at different load (MW) and excitation (MVAR j conditions.

'

Study of Generator Third Harmonic Voltages

I ' The third harmoni; voltages measured above are plotted in a graph with VN3 on X-axis and VL3 on Y-axis. Drawtwo lines enclosing. all, measured values with some tolera-nee. . . .. ~v 'a l~ate~i io~es'ml .. . .and,m2 of these lines. The slopes can be calculbted by ielecting any pointalongthe line-and by

. . - . . computing i ts V N ~ / \ / L ~ ratio; . . . . . . . .

Alternatively, calculate VL3/VN3 from each set of readings under different load conditions. Select the maximum and minimum values of these ratio. Then ml will be maximum VL3/VN3+5% and m2 will be VL3/VN3 - 5%.

-

The dead band setting K and the null setting potenliometer "a" can be b calculated as given below and set it accordingly in the relay.

Example: I'..

4 i OALSTOM Limited, Energy Automation & Information

2. At different load (MW) conditions SI.No - Active Reactive

Load(MW)

-- , -- - *


3 ,$g

APPS Combined course R - Generator Protection -~eftj,$

Criteria 8, TvtorialS- Page 44 o f z

-,

The following table shows the actual values of the generator VL3 and VN3 obtained from site:

1. Before Synchronization: V13(mvolts) Poi1

20.9 - 76.4

1 28 194.5 263 - 325 -

390. 452 534 650 698 720

Vn3(mvolts) Point: 187 Volta e kV

193.6

!-L 4 5 6 7 8 9

-

2 3 4 5 6

- 7 8

- 9 10 1 1 --

324 49 1 658 810 967 -- 1 1 16 1306 1570 1 680 1730

APPS. Combined course Generafor Profecfion -Setting

criteria & Tutorials .

Page 45 of 45

0.414 . . 0.435 . 0.393 0.415 - 0.436 0.395

0.427 0.448 0.405

Generator 3rd Harmonics

Vn3(N eutra I Side)

From the table.

m 1 = 0.454

1

. - . . . . . .

APPS Combined course Generator Protection -Setting '

Criteria 8, Tutorials -

Page 46 of 45 -.

Calculated values are K = 3.1 and a = 0.409

Dead Machine Protection 6: B - CTIG+VTUM+VTT

Overcurrent setting 'FLC

Under voltage relay setting -

Timer setting = 1 Sec ,

.r-


Distance Protection . Notes .

. . . . .

1.6.1 Zone 1 Setting



1.6.4 Settings for Reverse Reach and Other Zones

1.7.: Amplitude and Phase Comparison

1.7.2 Plain lmpedance Characteristic

1.7.3 Self-Polarised Mho Relay

1.7.4 Offset MhoJLenticular Characteristics

1.7.4.3 Application of Lenticular Characteristic

1.7.5 Fully Cross-Polarised Mho Characteristic

1.7.6 Partially Cross-Polarised Nlho Characteristic

1.7.8 Protection Against Power Swings - Use of the Ohm Characteristic

1.7.9 Other Characteristics

1.8.1 Starters for Switched Distance Protection

1.9 Effect of Source lmpedance a_nd Earthing Methods

1.9.1 Phase Fault lmpedance Measurement

1.9.2 ' Earth Fault lmpedance Measurement

1.1 0.1 Minimum Voltage at Relay Terminals

1.10.2 Minimum Length of Line

1.10.3 Under- Reach - Effect Of Remote lnfeed

1.10.4 Qver-Reach

1.10.5 Forward Reach Limitations

4.10.6 Power Swing Blocking

1.10.7 Voltage Transf~mer Supervision

Other Distance Relay Features

Distance !?e!ay Application Example

1.12.1 Line Impedance

1.1 2.2 Residual Compensation

1.12.3 Zone 1 Phase Reach -

1.1 2.4 Zone 2 Phase Reach

1.12.5 Zone 3 Phase Reach

1.12.6 Zone Time Delay Settings

1.12.7 Phase ~ a u l t Resistive Reach Settings

1.12.8 Earth Fault Impedance Reach Settings

1.12.9 Earth Fault Resistive Reach Settings

References

1 Introduction

The problem of combining fast fault clearance with selective tripping of plant is a key aim for the protection of power systems. To meet these requirements, high-speed protection systems for transmission and primary distribution circuits that are suitable for use with the automatic reclosure of circuit breakers are under continuous development and are very widely applied.

Distance protection, in its basic form, is a non-unit system of protection offering considerable economic and technical advantages. Unlike phase and neutral overcurrent protection, the key advantage of distance protection is that its fault coverage of the protected circuit is virtually independent of source impedance variations. This is illustrated in Figure 1.1, where it can be seen that overcurrent protection cannot be applied - satisfactorily. Distance protection is comparatively simple to apply and it can be fast in operation for faults located along most of a protected circuit. It can also provide both primary and remote back-up functions in a single scheme. It can easily be adapted to create a unit pr'otection scheme when applied with a signalling channel. In this form it is eminently suitable for application with high-speed auto-reclosing, for the protection of critical transmission lines.

Relay R, setting >7380fi

I 1 SIN

Therefore, for relay operat ion for l ine fau l t s , Relay current setting <6640A and >7380A This is impractical, overcurrent re lay not su i tab le

Must use Distance or Un i t . P ro tec t ion

Figure I . 1: Advantages of distance over overcurrent protection

I

. . . . . . . . . . .: . . . . . . . Page 3

. . . . . . . . . . . .

1.2 Principies of Distance Relays

Since the impedance of a transmission line is proportional to its length, for distana measurement it is appropriate to-use a relay capable of measuring the impedance of : line up to a predetermined point (the reach point). Such a relay is described as a distana relay and is designed to operate only for faults occurring between the relay location an( the selected reach point, thus giving discrimination for faults that may occur in differen line sections.

The basic principle of distance protection involves the division of the voltage at th relaying point by the measured current. The apparent impedance so calculated compared with a predetermined impedance (normally the impedance of the circuit tieir protected multiplied by some factor), known as. the reach point. If the measurc impedance is less than the reach point impedance, it is assumed that a fault exists on-tt line between the relay and the reach point.

The reach point of a relay is the point along the line impedance locus that is intersect by the boundary characteristic of the relay. Since this is dependent on the ratio of volta and current and the phase angle between them, it may be plotted on an RMdiagram. 7 loci of power system impedances as seen by the relay during' faults, 'power swings c load variations may be plotted on the same diagram and in this manner the performar of the relay in the preser,ce of system faults and disturbances may be studied. '

7.3 Relay Performance

Distance relay performance is defined in terms of reach accuracy and operating t Reach accuracy is a comparison of the actual ohmic reach of the relay under prac conditions with the relay setting value in ohms. Reach accuracy particularly depend the level of voltage presented to the relay under fault conditions. The imped: measuring techniques employed in particular relay designs also have an impact.

Operating times can vary with fault current, with fault position relative to the relay sc and with the point on the voltage wave at which the fault occurs. Depending o measuring techniques employed in a particular relay design, measuring signal tra~ errors, such as those produced by Capacitor Voltage Transformers or saturating can also adversely delay relay operation for faults close to the reach point. It is us1 electromechanical and static distance relays to claim both maximum and mir operating times. However, for modern digital or numerical distance relays, the va between these is small over a wide range of system operating conditions an1 positions.

1.3.1 ElectromechanicallStatic Distance Relays

With electromechanical and earlier static relay designs, the magnitude 1

quantities particularly influenced both reach accuracy and operating time customary to present info-mation on relay performance by voltagelreach as shown in Figure 7.2, and operating timelfault position curves for variou of system impedance ratios (S.I.R.'s) as shown in Figure 1.3, where:

Page 4

' . and

ZS = system source impedance behind the relay location

ZL = line impedance equivalent to relay reach setting

% relay rated vo l tage

L, (a) Phase-earth fau l ts Ll rn

% relay rated vol tage (b) Phase-phase fau l t s

% relay rated vol tage (c) Three-phase and three-phase-earth fau l ts

Figure 1.2: Typical impedance reach accuracy characteristics for Zone I

0 10 20 30 40 50 60 70 80 90 100

Fault position (% relay setting)

(a) With system impedance ratio of I/?

o i o i o 3 o 4 b ~ o 6 b 7 0 a o 9 0 1 b o Fault position (Oh relay setting)

( b ) With system impedance ratio of 3011

Figure 1.3: Typical operation time characteristics for Zone 1 phase-phase faults

Alternatively the above information was combined in a family of contour curves, where the fault position expressed as a percentage of the relay setting is plotted against the source to line impedance ratio, as illustrated in Figure 1.4.

........ /-- :.- . . . . . . .

-:- . . . . ... ...

z , ..

: . , '

.: . . I : ' .

. ... . . . .. .:.:; +;: : . . . . . . . ; ; . ... . . . . . . . . . . :.. , . ' . . :... .:. .:>... . . . . . . . . . . . . . . . . . . . . . . . - . . . ( : : i

. . , . ' : ! ;

. . . - . . -.. ............ . .= , .

: , 0.4 J-! ; .- . . . . 6 03 . .

Q

5 0 2 - . . . : . . . _ . . . . . . . .. . . . . . . . . . . 0 , . . . . . . . . . . . . . . .

. . . . . . - . . . . . . ..-:-..; . . . . . . . . . . : .... o o1 0.1 I a $to t~

Z p , or S i. R. (a) Zone 1 phase-phase fault: minlmum operation tlmeS

. . . . . . . . . . . . . . . . !

. . %o,in<&sr .

................ . . . . . . . . . . . , . . . . . . . : ' ; ' ' . ' . I I , .

I . I , . , - . . . . :

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I.. . . . . . . . . . T.i~~,u I : . -y~-?-...,,. i : ; ; I.: . ... .......................... ...-.... 4- ............. - ...-.i

I ! . . ,

. . ....... .-... , . I

. . .... . . .......

. . . . . . I . . . . _ . . . __,.__ -..._

I : ! . . . . . . . . . . . ...'.,.

I ' ! . . . . . . I . .

. :

Z,fZ, or S1.R. 0

:b) Zone 1 phase-pnase fault: maximum operation times e

Figure 1.4: Typical operation-time contours

. . . : 1.3.2 DiqitalINumberical Distance Relays

DigitalINumerical distance relays tend to have more consistent operating times. They are usually slightly slower than some of the older relay designs when operating under the best conditions, but their maximum operating times are also less under adverse waveform - conditions or for boundary fault conditions.

4 Relationship Between Re!ay Voltzge and ZS!ZL Rs;tio

A single, generic, equivalent circuit, as sbown in Figure 1.5(a), may represent any fault condition in a three-phase power system. The voltage V applied to the impedance loop is the open circuit voltage of the power system. Point R represents the relay location; iR and VR are the current and voltage measured by the relay, respectively.

The impedances Zs and ZL are described as source and line impedances because of their position with respect to the relay location. Source impedance Zs is a measure of the fault level at the relaying point. For faults involving earth it is dependent OP the method of system earthing behind the relaying point. Line impedance ZL is a measure of the impedance of the protected section. The voltage VR applied to the relay is, therefore, For a fault at the reach point, this may be alternatively expressed in terms of source to line impedance ratio Zs/ZL are by means of the following expressions:

VR = IRZL

where :

therefore : . .

I V, = V ... Equation 1 .I

(Zs / Z L ) + 1

(a) Power sys tem configuration

. . . : ; . . . . . . . . . . . ...... ... ...........-..... .....-...- . . : X j : i s < j . . : .- .- ! : i ; ! ! . : . .

i ; ! / .. . : .... . . . . . : . . . . . . . . . . . . . . . . ....................

8 0 . . I . .:. i.. ! : , ..:.. .;. . . ! . .! 0.1 012 0.3 0.5 1 2 3 4 5 10

z s System ~mpedance rat io -- =, (b) Variation of relay voltage w ~ t h system source to line impedance r a

Figure 1.5: Relationship between source to line ratio and relay voltage

The above generic relationship between VR and ZdZL, illustrated in Figure 1.5(b), i for all types of short circuits provided a few simple rules are observed. These are:

For phase faults, V is the phase-phase source voltage and ZdZL is the positive sec source to line impedance ratio. VR is the phase-phase relay voltage and IR is the phase relay current, for the faulted phases

I ... VR = "P -P Equation 1.2

(Zs / Z L ) + 1

i. Foi earth faults, V is the phase-neutral source voltage and Zs/Zl

is a composite ratio involving the positive and zero sequence impedances'. V phase-neutral relay voltage and IR is the relay current for the faulted phase

Paoe 8 :

and

Voltaae Limit for Accurate Reach Point Measurement

The ability of a distance relay to measure accurately for a reach point fault depends on the minimum voltage at the relay location under this condition being above a declared value. This voltage, which depends on the relay design, can also be quoted in terms of an equivalent maximum ZslZL or S.I.R.

Distance relays are designed so that, provided the reach'point voltage criterion is met, any increased mea~uring errors for faults closer to the relay will not prevent relay operation. Most modern relays are provided with healthy phase voltage polarisation andlor memory voltage polarisation. The prime purpose of the relay polarising voltage is to ensure correct relay directional response for close-up faults, in the fohard or reverse direction, .where the fault-loop voltage measured by the relay. may be very small. . . .

.

Zones of Protection

Careful selection of the reach settings and tripping times for the various zones of measurement enables correct co-ordination between distance relays on a power system. Basic distance protection will comprise instantaneous directional Zone 1 protection and one or more time-delayed zones. Typical reach and time settings for a 3-zone distance protection are shown in Figure 1.6. Digital and numerical distance relays may have up to five zones, some set to measure in the reverse direction. Typical settings for three forward-looking zones of basic distance protection are given in the following sub-sections. To determine the settings for a particular relay design or for a particular distance teleprotection scheme, involving end-to-end signalling, the relay manufacturer's instructions should be referred to.

1.6.1 zone' 1 Settinq

Electromecha~nicallstatic relays usually have a reach setting of up to 80% of the protected line impedance for instantaneous Zone 1 protection. For digitallnumerical distance relays, settings of up to 85% may be safe. The resulting 15-20% safety margin ensures that there is no risk of the Zone 1 protection over- reaching the protected line due to errors in the current and voltage transformers, inaccuracies in line impedance data provided for setting purposes and errors of relay setting and measurement. Otherwise, there would be a loss of discrimination with fast operating protection on the following line section. Zone 2 of the distance protection must cover the remaining 15-20% of the line.

1

Page 9

1.6.2 _Zone 2 Setting

To ensure full coverage of the line with allowance for the sources of error already listed in the previous section, the reach setting of the Zone 2 protection should be at least 120% of the protected line impedance. In many applications it is common practice to set the Zone 2 reach to be equal to the protected line section +50% of the shortest adjacent line. Where possible, this ensures that the resulting maximum effective Zone 2 reach does n.ot extend beyond i i ~ e rniniiiiiii-ii zffective Zone 1 reach of the adjacent line protection. This avoids the need to grade the -Zone 2 time . settings between upstream and downstream relays. In electromechanical and static relays, Zone 2 ,, protection is provided either by separate elements or by extending the reach of the Zone 1 elements after a time delay that is initiated by a fault detector. In most digital and numerical relays, the Zone 2 elements are implemented in software.

Zone 2 tripping must be time-delayed to ensure grading with the primary relayins applied to adjacent circuits that fall within the Zone 2 reach. Thus completc coverage of a line section is obtained, with fast clearance of faults in the first 80 85% of the line and somewhat slower clearance of faults in the remaining sectior of the line.

A- <* T ~ m e l

Source Sol

Time)

Zone 1 = 80435% of protected line impedance

Zone 2 (minimum)= 120% of protected line

Zone 2 (maximum) < Protected line + 50% of shortest second line

Zone 3F =-I .2 (protected line + longest second line)

Zone 3R = 20% of protected line

X = Circuit breaker tripping time

Y = Discriminating time

Figure 7.6: Typical time/distance characteristics for three zone distance protection

1.6.3 Zorie 3 Settinq

Remote back-up protection for all faults on adjacent lines can be provided t third zone of protection that is time delayed to discriminate with Zone 2 protec plus circuit breaker trip time for the adjacent line. Zone 3 reach should be set 1

i least 1.2 times the impedance presented to the relay for a fault at the remote of the second line section.

Page 10 . . .. . . _. , :tx;. A'.

. . . . . . . . . .

On interconnected power systems the effect of fault current infeed at the remote busbars will cause the impedance presented to the relay to be much greater than the actual impedance to the fault and this needs to be taken into amount wilen setting Zone 3. In some systems, variations in the remote busbar infeed can prevent the application of remote back-up Zone 3 protection. but on radial distribution systems with single end infeed, no difficulties should arise.

1.6.4 Settinqs for Reverse Reach and Other Zones

Modern digital or numerical relays may have additional impedance zones that can be utilised to provide additional protection functions. For example, where the first three zones are set as above, Zone 4 might be used to provide back-up protection for the local busbar, by applying a reverse reach setting of the order of 2.5% of the Zone 1 reach. Alternatively, one of the forward-looking zones (typically zone-3)

&: %:

could be set -with a small reverse offset reach from the origin of the- RIX diagram, i'. . *: L.. :. : + ' .

in addition to its forward reach setting. An offset impedance measurement characteristic is non-directional. One advantage of a non-directional zone of

1:': impedance measurement is that it is able to operate for a close-up, zero- ! .:. . .

impedance fault, in situations where there may be no healthy phase voltage signal or memory voltage signal available to allow operation of a directional impedance zone. With the offset-zone time delay bypassed, there can be provision of 'Switch- On-To-Fault' (SOTF) protection. This is required where there are line voltage transfoimers, to provide fast tripping in the event of accidental line energisation with maintenance earthing clamps left in position. Additional impedance zones may be deployed as part of a distance protection scheme used in conjunction with a teleprotection signalling channel.

'. 1.7. Distance Relay characteristics _ . . . . . . . . . . .

. .

Some numerical relays measure the absolute fault impedanceand then determine whether operation is required according to impedance boundaries defined on the R/X diagram. Traditional distance relays and numerical relays that emulate the impedance elements of traditional relays do not measure absolute impedance. They cornpare the measured fault voltage with a replica voltage derived from the fault current and the zone impedance setting to determine whether then fault is within zone or out-of-zone. Distance relay impedance comparators or algorithms which emulate traditional comparators are classified according to their polar characteristics, the number of signal inputs they have, and the method by which signal comparisons are made. The common types compare either the relative amphtude or phase of two input quantities to obtain operating characteristics that are either straight lines or circles when plotted on an R/X diagram. At each stage of distance relay design evolution the development of impedance operating characteristics shapes and sophistication has been governed by the technology available and the acceptable cost. Since many traditional relays are still in service and since some numerical relays emulate the techniques of the traditional relays, a brief review of impedance comparators is justified.

1.7.1 Amplitude and Phase Comparison

Relay measuring elements whose functionality is based on the comparison of two independent quantities are essentially either amplitude or phase comparators. For the impedance elements of a distance relay, the quantities being compared are the voltage and current measured by the relay. There are numerous techniques available for performing the comparison, depending on the technology used. hey vary from balanced-beam (amplitude comparison) and induction cup (phqse comparison) electromagnetic relays, through diode and operational .amplifier

Page 11

. . . .

. . . . . . : .- . . . .

comparators ir! static-type- distance relays, to digital sequence comparators in digital relays and to algorithms used in numerical relays.

Any type of impedance characteristic obtainable with one comparator is also I obtainable with the other. The addition and subtraction of the signals for one type j of comparator pioduces the required signals to obtain a similar characteristic using the other type. For example, comparing V and I in an amplitude comparator results ~.

in a circular impedance ch3racteistlc-sentred at the ofiglr! of the--=diagram. If the sum and difference of V and I are applied to the phase comparator the result is a similar characteristic.

Plain Impedance Characteristic -

This characteristic takes no &ccount of the phase angle between the current an the voltage applied to it; for this reason its impedance characteristic when plotted on an R/X diagram is a circle with its centre at the origin of the co-ordinates and radius equal to its setting in ohms. Operation occurs for all impedance values le than the setting, that is, for all points within the circle. The relay characteris shown in Figure 11.7, is therefore nondirectional, and in this form would oper for all faults along the vector AL and also for all faults behind the busbars up to impedance AM. It is to be noted that A is the relaying point and R A B is the a by which the fault current lags the relay voltage for a fault on the line A 5 and is the equivalent leading angle for a fault on line AC. Vector A 5 represents the -

impedance in-front of the relay between the relaying point A and the end o AB. Vector A C represents the impedance of line A C behind the relaying point. AL represents the reach of instantaneous Zone 1 protection, set to cover 80% to 85% of the protected line. . .

Line GK Line GH : t I

C B

-

Figure 1.7: Plain impedance relay characteristic

Page 12 ..,

Iirect i I el erne

I

(a) Character is t ic of combined directional! impedance r e l a y

e 2 - a ... . I source ! ; Source

, i ,--. . . - . . . : - . . . .. ... .

\-,> :

I

j C D - +-/ - - -. . . - . 2. 1

. _- . .\ I ' . .

, .

F (b) Illustration of use of directional!impedance relay:

circuit diagram

.. . ;, ti- .*>:

R,,: d is tance element at A R,,: direct ional element at A

(c) Logic for directional and impedance elements at A

Figure 1.8: Combined directional and impedance relays

. - . y+: fi: Page 13 .. r F.:. 32: -- ,-a. ?--!,

A relay using this characteristic has three important disadvantages:

i. it is non-directional; it will see faults both in front of and behin point, and therefore requires a directional element to give it discrimination

i. it has non-uniform fault resistance coverage

iii. it is susceptible to power swings and heavy loading of a long line, be the large area covered by the impedance .circle

Directional control is an essential discrimination quality for a distance make the relay non-responsive to faults outside the protected line. Thi obtained by the addition of a separate directional control element. The i characteristic of a directional control element is a straight line on the RI so the combined characteristic of the directional and impedance re semi-circle APLQ shown in Figure 1.8.

If a fault occurs at F close to C on the parallel line CD, the directio will restrain due to current IF,. At the same time, the impedance unit i from operating by the inhibiting output of unit RD. If this control is not under impedance element could operate prior to circuit breaker C opening. .,

Reversal of current through the relay from IF, to IF2 when C opens could then result :::

in incorrect tripping of the healthy line if the directional unit Ro operat impedance unit resets. This is an example of the need to consider t ordination of multiple relay elements to attain reliable relay perfor evolving fault conditions. ,. In older . relay designs, ,.the .type. of ..p addressed was commonlyiefefred toas orie of 'coritact race'.

i

1.7.3 Self-Polarised Mho Relay I

The mho impedance element is generally known as such characteristic is a straight line on an admittance diagram. It cleverly combines the ,.: discriminating qualities of both reach control and direction~l control, thereby .X eliminating the 'contact racet problems that may be encountered with separate 4 reach and directional control elements. This is achieved by the addition of a 2 polarising signal. 'Mho' impedance elements were particularly attractive for ;$ economic reasons where electromechanical relay elements were employed. As a ,!x

$ result, they have been widely deployed worldwide for many years and their -:; advantages and limitations are now well understood. For this reason they are still jj emulated in the algorithms of some modern numerical relays.

The characteristic of a 'mho' impedance element, when plotted on an R/X .: diagram, is a circle whose circumference passes through the origin, as illustrated ,r in Figure 11.9(b). This demonstrates that the impedance element is inherently 'i directional and such that it will operate only for faults3n the forward direction along . .

\ line AB.

The impedance characteristic is adjusted by setting Z,, the impedance reach, :' . ,

along the diameter and cp, the angle of displacement of the diameter from the R:: axis. Angle cp is known as the Relay Characteristic Angle (RCA). The relay,

. . , operates for values of fault impedance ZF within its characteristic. . . .: .

. -

.. - . . %

. -

. .. .. +

:, ,,..

It will be noted that the impedance reach varies with fault angle. As the line to be protected is up of resistance and inductance,. its fault angle will be dependent upon the relative values of R and X at the system operating frequency. Under an arcing fault condition, or an earth fault involving additional resistance, such as tower footing resistance or fault through vegetation, the value of the resistive component of fault impedance will increase to change the impedance angle. Thus relay having a characteristic angle equivalent to the line ang!e will under-reach under resistive fault conditions.

( a ) Phase comparator inputs

/x

/ Restrain

K i

(b) Mho impedance cha rac te r i s t i c

Page 15

G Q Relay impedance s e t t i n g Relay character is t ic angle sett ing

GL Protected l i n e PQ Arc res is tance 6' L ~ n e angle

Figure 1.9: Mho relay characteristic

It is usual, therefore, to set the RCA less than the line angle, so that it is possi to accept a small amount of fault resistance without causing under-rea However, when setting the relay, the difference between the line ar "EQUATION MISSING" and the relay characteristic angle cp must be known. - resulting characteristic is shown in Figure 11,9(c) where AB corresponds to length of the line to be protected. With cp set less than 0, the actual amount of protected, AB, would be equal to the relay setting value AQ multiplied by CO!

(0-cp). Therefore the required relay setting AQ is given by:

Page 16

Distance Protection Schemes

. , . ,

. . . . , . , .

12 Di s tance Protec t ion

Conventional time-stepped distance protect ion is illustrated in Figure 12.1. One of the main disadvantages o f this scheme is that the instantaneous Zone 1

. . . . protection at each end of the protected l ine cannot be . . :,

in these zones are cleared in Zone 1 t ime by the protection at one end o f the feeder and in Zone 2 t ime (typically 0.25 to 0.4 seconds) by the protection at the other end o f the feeder.

. . . .

. . . . .

I

l a ) Srcppcd tirncldisrancc characlcri:lics

(b) Trip circuit (solid statc logic) . . . . . . . .

This situation cannot be tolerated in some applications. for two main reasons:

a. faults remaining on the feeder for Zone 2 time may cause the system to become unstable

b. where high-speed auto-reclosing is used. the non-

time' during the auto-reclo;e cycle for the fault to ;

cause permanent lockout o f the circuit breakers at , .! each end o f the line section

',

-- .. . . .. . - . . ..

f r 1 I i . a U A . r . - . , i . . C . i d r

:hap12 exe 1 4 / 0 6 / 0 2 13::s Page 1 9 4 ' ,

Even where instability does not occur, fhe increased duration of the disturbance may give rise t o power quality problems, and may result i n increased plant damage.

Unit schemes of proieciiori tii%i compare the ccnditinns at the two ends of the feeder simultaneously positively identify nhether the fault is internal or external t o the protected section and provide high-speed protection for the whole feeder length. This advantage is balanced by the fact-that the unit scheme does not provide the back up protection for adjacent feeders given by a distance scheme.

The most desirable scheme is obviously a combination of the best features o f both arrangements, that is, instantaneous tripping over the whole feeder length plus back-up protection t o adjacent feeders. This can be achieved by interconnecting the distance protection relays at each end o f the protected feeder by a communications channel. Communication techniques are described in detail in Chapter 8.

The purpose of the communications channel is to transmit informarion about the system conditions from one end of the protected line to the other. including requests to initiate or prevent tripping of the remote circuit breaker. The former arrangement is generally known as a 'transfer tripping scheme' while the latter is generally known as a 'blocking scheme'. However, the terminology o f the various schemes varies widely, according to local custom and practice.

This scheme is intended for use with an auto-reclose facility, or where no communications channel is available, or the channel has failed. Thus it may be used on radial distribution feeders, or on interconnected lines as a fallback when no communications channel is available, e.g. due to maintenance or temporary fault. The scheme is shown i n Figure 12 .2 .

The Zone 1 elements of the distance relay have two settings. One is set to cover 80010 of the protected line length as in the basic distance scheme. The other, known as 'Extended Zone l ' o r 'ZlX', is set to overreach the protected line, a setting of 120010 of the protected line being common. The Zone 1 reach is normally controlled by the Z 1 X setting and is reset to the basic Zone 1 setting when a command from the auto-reclose relay is received.

.. . .. . ... .. . ..... . . . . . . . . . - ... .-

Zone 2

Zonc 3

(b) Simplilicd logic

~eclose~facil ity is out of service: Reversion t o the reach setting occurs only at the end of the reclaimt For interconnected lines, the Z1X scheme is establis

The disadvantage of the Zone 1 extension scheme is th external faults within the Z1X reach o f the relay result tripping of circuit breakers external to the fault

circuit breakers operate.

. . . . ~

-.

. . . ... ?.. .....>..-A . I ,"..$;.::.c.::,...,, :-., ... .Pv ::;:e.: ........ :.. .. . - I.. .............. :..- . -,< s.- .. . . . . . .

p..:. .

. (bl Faul: within Zonc I cx:cnsion rcach of distance rclays .. .- . . (doublc circuit lincs) 2 5 : ; . ...

g..zL-- . . Fj:: F;J"rr 72.:'. F:.?; ,,,, :, , l-:<C ,,::: I.. ; :*i;.,:l:.i..c ! j , 5,-.?r.?y ,.. ,'.,;:.!,.:s f..;.: ..... !i. . . ,.- .:a:: : ,;:,c . r L .::., C'- s., ,.'-.

- ,,. .- r ' ~ . : ~ , . !. .

\;A number of these schemes are available, as described below. Selection of an appropriate scheme depends on

i, the requirements'of the system being protected.

i

LThe simplest way of reducing the fault clearance time at Ithe terminal that clears an end zone fault in Zone 2 time 3 .

;Isto adopt a direct transfer trip or intertrip technique, the 'logic of which is shown in Figure 12.4. ! > .

7- Sggnal scnd

u ' Signal r c c c w c

.-

...... - .<.&?:.;.; :-...: ,,..::. . iF ... >..<.:-.. = . .... - . . . . . . . . * - . : I..... - , . , )I.* 2 s : \ - L > . : : . . . +*,,, -T,%K-$.??.* ,. ,<:<%.>* $5:: y.

A contact operated by the Zone 1 relay element is .~E<%jf +.. 3.: ,. arranged to send a signal to the remote relay requesting a '$%:&%' ... >?s.~,:.? ......... .2:,*iq; trip. The scheme may be called a 'direct under-reach !?. $2":;. transfer tripping scheme', 'transfer trip under-reaching .-::* :, :;<;* * .A<. 8.

scheme', or 'intertripping under-reach distance protection ;<.:+$$+? .... . .+- . . -.<'.."t .'

scheme', as the Zone 1 relay elements do not cover the ,....* \;p %5. ,.fir"

whole of the line. ,. ' J .-, , . x . ... 2 ,:, -:,,&:' A fault F i n the end zone at end B in Figure 12.l(a) :::&;.>&;: v...,pSi..

&.~% *>.. results in operation of the Zone 1 relay and tripping of &.%: : ,. -.:i;,,. - the circuit breaker at end B. A request to trip is also sent ;;;:+A. : :;$@::

' t o the relay at end A. -The receipt of a signal a t A ?{:,:*" .r t. ..TT*.

initiates tripping immediately because the receive relay ..;<,*p:. .... ?-&C . . . . . . . . . . . _ : L -2..

contact is connected directly to the trip relay. The . . . ,S.:+J:K.,. ) ........ _ : ........ .....

disadvantage o f this scheme is the possibility o f :--*.:.:::G~,;:.:

undesired tr ipping by accidental operation or maloperation of signalling equipment, or interference on .. - . . '::.'

the communications channel. As a result, i t is not . .

com~[anly used.

The direct under-reach transfer tr~pping scheme described above is made more secure by supelvising the received signal with the operation of the Zone 2 relay element before a~~bwing an instantaneous trip; as shown in Figure 12.5. The scheme is then known as a 'permissive under-reach transfer tripping scheme' (sometimes abbreviated as PUP 22 scheme) or 'permissive under-reach distance protection', as both relays must detect a fault before the remote end relay is permitted to trip in Zone 1 time.

----c Signal scnd

z i I

Signal e rcccivc 0-

(a] Signal logic

Signalling cquipmcnl -End A

(bl Signalltng arrangcmcnt

IchaPl2 exe 1 4 0 6 0 2 13:15 Page 196

-

A variant o f this scheme, found on some relays, allows tripping by Zone 3 element operation as well as Zone 2, provided the fault is i n the forward direction. This is sometimes called the PUP-Fwd scheme.

Time delayed resetting o f the 'signal received' element is required to ensure that the relays at both ends o f a single-end fed faulted line o f a parallel feeder circuit have t ime to trip when the fault is close to one end. Consider a fault F i n a double circuit line, as shown i n Figure 12.6. The fault is close to end A, so there is negligible infeed from end B when the fault a t F occurs. The protection at B detects a Zone 2 fault only after the breaker at end A has tripped. I t is possible for the Zone 1 element at A to reset, thus removing the permissive signal to B and causing th: 'signal received' element at B to reset before the Zone 2 unit at end B operates. I t is therefore.,necessary to delay the resetting sf the 'signal received' element to ensure high speed tripping at end B.

. . -. .. . - . ;. .. ,,. : .= .. ** \ 2' 'I 0

- ! - - (a1 Fault occurs-bus bar vol lagc low so - K - ncgligiblc fault currcnl v ia cnd B L

I (bl End A rc lav clcars fault and cur rcn l

s ta r ts lccdnng from cnd R

The PUP schemes require only a single communications channel for two-way signall~ng between the line ends, as the channel is keyed by the under-reaching Zone 1 elements

When the circuit breaker at one end is open, or there is a weak infeed such that the relevant relay element does not operate, instantaneous clearance cannot be achieved for end-zone faults near the 'breaker open' terminal unless special features are included, as detailed in section 12.3.5.

This scheme IS applicable only to zone sw~tched d~stance

?#

relays that share the same measuring elements for both' Z Zone 1 and Zone 2. In these relays, the reach of thca measuring elements is extended from Zone 1 to Zone 2 S 4 by means o f a range change signal immediately, instead: o f after Zone 2 time. It is also called a n 'accelerated: underreach distance protection scheme'.

The under-reaching Zone 1 uni t is arranged to send a signal to the remote end o f the feeder in addition to tripping the local circuit breaker. The receive relay: contact is arranged to extend the reach o f the measurini element from Zone 1 to Zone 2. This accelerates theA fault clearance at the remote end for faults that lie in the! region between the Zone 1 and Zone 2 reaches. The scheme is shown in F~gure 12.7. Modern distance relays, do not employ switched measuring elements, so the, scheme IS likely to fall into disuse

3~ * -

.. > .>l

(a) Distancc/timc charactcristics - . - ,:2

i!3 1 Trip t(

S~gnal rcccivc 1 1 I I

Signal

(b) Signal l o g ~ c . "9 .Y

,. , . . . . . .

8 . . . . . . .%

- :.+ . . I..:keq . :!,' ?;,

r; In this scheme, a distance relay element set to re?: beyond the remote end of the protected line is used: send an intertripping signal to the remote end. Howev; it is essential that the receive relay contact is monito!: by a difectional relay contact to ensure that trippl! does not take place unless the fault is within 9 protected section; see Figure 12.8. The instantane6 contacts of the Zone 2 unit are arranged to send $ signal, and the received signal, supervised by zone; operation, is used to energise the trip circuit. scheme is then known as a 'permissive over-rc transfer tripping scheme' (sometimes abbreviate1 'POP'). 'directional comparison scheme', or 'permi: ov~rreach distance protecf io~ scheme'.

1 4 / 0 6 / 0 2 :3:15 Page 15-

. . . . . .

w Signal

-

.- <.,. .. 2 3 :: . - Trip . . . . t

(a] Signal logic

Since the signallinc channel is keyed by over-reaching Zone 2 elements, the scheme requires duplex communication c'nannels - one frequency for each direction of signalling.

If distance relays with mho charac~eristics are used, the scheme may be more advantageous than the permissive uhder-reaching scheme for protecting short lines, because the resis:ivc coverage of the Zone 2 umt may be greater than that o f Zone 1.

To prevent opera:ion under current reversal conditions in a parallel feeder circuit, i t is necessary to use a current reversal guard tirnrr to inhibit the tripping of the forward Zone 2 elements. Otherwise maloptration of the scheme may occur under current reversal conditions. see Section 11.9.9 for more details. It is necessary only when the Zone 2 reach is set greater than 1500fo of the protected line impedance.

The timer is used to block the permissive trip and signal send circuits as shown in Figure 12.9. The timer is energised i f a signal is received and there is no operation of Zone 2 elemer,:~. An adjustable time delay on pick-up (1,) is usually set to allow instantaneous tripping to take place for any ir,ternal faults, taking into account a possible slower operation of Zone 2. The timer will have operated and blocked the 'permissive trip' and 'signal send' circuits by the time the current reversal takes place.

The timer is de-energised i f the Zone 2 elements operate or the 'signal received' element resets. The reset time delay (I,) of the timer is set to cover any overlap in time caused by Zone 2 elements operating and the signal resetting at the remote end. when the current in the healthy feeder reverses. Using a timer in this manner means that no extra time delay is added in the permissive trip circuit for an internal fault.

Trip 7- ; j

s i g n a ~ i v c ~ F ~ f p ' p ~ i I

The above scheme using Zone 2 relay elements is often -

referred to as a POP 22 scheme. An alternative exists that uses Zone 1 elements instead of Zone 2 , and this is referred to as the POP 2.1 scheme.

In the standard permissive over-reach scheme, as with 2 the permissive under-reach scheme, instantaneous - - - clearance cannot be achieved for end-zone fau& under . , !-: 3. , .t <. .

weak infeed or breaker ppen cqnditions. ~oove rcbme , . . . . . . :..,.;-.- .: , : . . . . . . . .

. ..:. this disadvantage, two possibilities exist. ' : . . . - . . .c- ! - . 0 . -

The Weak lnfeed Echo feattire available i n s ' 6 m e 1.::: . $ - .

protection relays allows theremote relay toecho the trip . 2 signal back to the sending relay even if the appropriate 2 remote relay element has not operated. This caters for conditions of the remote end having a weak infeed or 2 circuit breaker open condition, so that the relevant r

C remote relay element does not operate. Fast clearance .L.

h

for these faults is now obtained at both ends of the line. -- The logic is shown in Figure 12.10. P, time delay (T,) is Q

required in the echo circuit to prevent tripping of the remote end breaker when the local breaker is tripped by the busbar protection or breaker fail protection 1.2 associated with other feeders connected to the busbar. The time delay ensures that the remote end Zone 2 element will reset by the time the echoed signal is received at that end.

From 'POP' signal

! g i . - l

lap12 exe 14/06/02 13:15 Page 158 + Signal transmission can take place even after the remote end breaker has tripped. This gives rise to the possibility of continuous signal transmission due to lock-up of both signals. Timer T, is used to prevent this. After this time delay, 'signal send' is blocked.

A variation on the Weak lnfeed Echo feature is to allow tripping o f the remote relay under the circumstances described above, providing that an undervoltage condition exists, due to the fault. This is known as the Weak lnfeed Trip feature and ensures that both ends are tripped i f the conditions are satisfied. -

The arrangements described so far have used the signalling channel(s) to transmit a tripping instruction. I f the signalling channel fails or there is no Weak lnfeed feature provided, end-zone faults may take longer to be cleared.

Blocking over-reaching schemes use an over-reaching distance scheme and inverse logic. Signalling is initiated only for external faults and signalling transmission takes place over healthy line sections. Fast fault clearance occurs when no signal is received and the over-reaching Zone 2 distance measuring elements looking into the line operate. The signalling channel is keyed by reverse- looking distance elements (23 in the diagram, though which zone is used depends o'n-the relay used]. An ideal blocking scheme is shown.in Figure 12.11.

(a1 D ~ s r a n c c l r ~ r n c characlcristics

- 12 - a Signal scnd Z I -

- -

Signalling cquipmcnl Signalling cquipmcnl -End A -End B

(cl Signalling arrangcmcn(

initiated at any end of the protected section.

to two variants of the scheme.

as a 'directional comparison blocking scheme' or a 'blocking over-reach distance protection scheme:

Chacncl In 5 c ~ i c c

A fault at F 1 is seen by the Zone 1 relay elements at,, both ends A and B; as a result, the fault is cleared instantaneously at both ends o f the protected l inq

Zone 1 elements.

1 9 6 . . ,. . -

-

2 13::s Page 199 -

-

nal transmission takes place, since the ernal and the fault is cleared i n Zone 1 t ime a t after the short t ime lag (STL) a t end A.

relay elements a't end B associated w i th

the 22 elements a t end A f rom tripping, the

neously by the protection on l ine section B-C,

l i ty o f Zone 2 elements in i t iat ing tr ipping and the I c ~ k i n g Zone 3 elements fai l ing t o see an

I fault. This would result i n instantaneous ing for an external fault. When the signalling nel is used for a stabilising signal, as i n the above

takes place over a healthy line section is used. The sigrialling channel

uld then be more reliable when used i n the blocking e-than, i n tr ipping mode.

. .

:'&iential that , the operating t imes o f the various .bPskilfully co-or'dinated for all system conditions,

@thatsuff ic ient t ime is always allowed for the receipt K=:blocking signal f rom the remote end o f the feeder. #.this is not done accurately, the scheme may t r ip for an $ernal fau l t or alternatively, the end zone tripping imes may be delayed longer than is necessary. L . f the signalling channel fails, the scheme must be $ranged t o revert t o conventioaal basic distance uotection. Normally, the blocking mode tr ip circuit is upervised by a 'channel-in-service' contact so that the locking mode trip circuit is isolated when the channel is ut of service. as shown i n Figure 12.1 2.

(b] Solid %ta lc logic of rcnd circuit

e!..:,,. .+:: .: .:, .......... I + _ -

. L-,;, ,;.3.:;+;:,;. ..:. $:;I:: “. ".. .........: -.,:..: ..... a.:.::.. . . -4 .~- :-..; -1 . -+.:<..I.:.; 5 2 . ; .

I n a practical application, the reverse-looking relay .!???T,:.'<;;::' elements may be set w i t h a forward offset characteristic to provide back-up protection for busbar faults after the zone t ime delay. It is then necessary t o stop the blocking signal being sent for internal faults. This is achieved by making the 'signal send' circuit conditional upon non- operation o f the forward-looking Zone 2 elements, as $;tg&$Q? .::,... _-:.. _.*_ . .

. . . . ,.: . . . ' shown i n Figure 12.1 3. -1.. :,,>: ,:...,, ~.%... ,.....- $ ..: ,. .

Blocking schemes, l ike the permissive over-reach scheme, are also affected by the current reversal i n the healthy feeder due t o a faul t i n a double circuit line. If current reversal conditions occur, as described i n section 11.9.9, it may be possible for the maloperation o f a breaker on the healthy line t o occur., To avoid this, the resetting o f the 'signal received' element provided i n the blocking scheme is t ime delayed.

The t imer w i t h delayed resetting (t,) is set t o cover the :

t ime difference between the maximum resetting t ime o f reverse-looking Zone 3 elements and the signalling channel. So, if there is a momentary loss o f the blocking signal during the current reversal, the t imer does no t have t ime t o reset in the blocking mode t r ip circuit and no false tr ipping takes place. -.

p.

c/I, This is s~mi la r t o the BOP 22 scheme described above. -

I except that an over-reaching Zone 1 element is used i n I +- the logic, instead o f the Zone 2 element. It may also be 2

0 I

known as the BOP Z1 scheme. - I 0 L

c,

r; The protection a t the strong infeed terminal wi l l operate 2 for al l internal faults, since a blocking signal is not -2 received from the weak infeed terminal end. In the case Q of external faults behind the weak infeed terminal, the reverse-looking elements a t that end wi l l see the faul t current fed from the strong infeed terminal and operate, . 12. init iating a block signal to the remote end. The relay a t the strong infeed end operates correctly wi thout the need for any additional circuits. The relay a t the weak infeed end cannot operate for internal faults, and so tripping of that breaker is possible only by means o f direct intertripping from the strong source end.

: . . . . . The permissive over-reach scheme described i n Section ;:.,::.. : -, -.- . - .

12.3.4 can be arranged t o operate on a directional :.;:+-.):...:,:? . .

comparison unblocking principle by providing additional ;:;.. . . ' . .,,.:;;,, circuitry i n the signalling equipment. I n this scheme ,:::''' -;',.":

- . .... . . . . (also called a 'deblocking overreach distance protection . :.'- . . . . .

... -

;Chap12 exe 14/06/02 13:lS Page 200

! -

scheme'), a continuous block (or guard) signal is transmitted. When the over-reaching distance elements operate, the frequency of the signal transmitted is shifted to an 'unblock' (trip) frequency. The receipt of the unblock frequency signai arid thc pera at inn crf over- reaching distance elements allow fast tripping to occur for faults within the protected zone. In principle, the scheme is similar to the permissive over-reach scheme.

The scheme is made more dependable than the standard permissive over-reach scheme by providing additional circuits in the receiver equipment. These allow tripping to take place for internal faults even i f the transmitted unblock signal is short-circuited by the fault. This is achieved by allowing aided tripping for a short time interval, typically 100 to 150 milliseconds, after the loss of both the block and the unblock frequency signals. After this l ime interval, aided tripping is permitted only i f the unblock frequency signal is received.

This arrangement gives the scheme improved security over a blocking scheme, since tripping for external faults is possible only i f the fault occurs within the above time interval of channel failure. Weak lnfeed terminal 'conditions can be catered for by the techniques detailed in Section 12.3.5.

In this way, the scheme has the dependability of a blocking scheme and the security of a permissive overreach scheme. This scheme is generally preferred when power line carrier is used, except when continuous transmission of signal is not acceptable. -

On normal two-terminal lines the main deciding factors in the choice of the type of scheme, apart from the reliability o f the signalling channel previously discussed, are operating speed and the method of operation of the system. Table 12.1 compares the important characteristics of the various types of scheme.

i'~~~~;j.:,,,,i;Ilq.@p qi~~ing.*mf;!~:~*~*;~:?~?~ : . ; Spccd of opcrarion Fast Not as fast

Spccd with in-wnicc te t ing Slowcr 1 A$ fast i

SuiUblc lor auto-rcclosc Ycs YC 8

Scarify against malopcraticm duc la : !

Cumnr r r v c m l Sprcial fcaturcs rcquircd Special fcalurcs rcqulrcd

Lou of communica~~ons Pmr ! Good

Wrak l n l r r d l O ~ n CB Sprcial fcaturcs rquircd Special fcalurn rcquircd

Modern digital or numerical distance relayrare provided with a choice of several schemes in the same relay. Thus scheme selection is now largely independent of relay selection, and the user is assured that a relay is available with all the required features to cope'with changing system conditions.

; f;; :. -.. -.: f$: : R,

;,:- .<-.

h '1 .,..:. .... r.: C-:

Busbar Protection

:, :..?,c;T?-7:< .:I p,:<"<;;.+-::,,.-< :??A%;<&+#::'=.! - g&=@$$;;, : . :;*.<&;;+-:=;> . '. .... .?$ : , ,:*+;++, <. 5*?3&53;<.:. .... 1:.

.....% **.*<a;. . r?%yTmh i

~ . . . y * ~ * - ' ,; -. .<'-. . ....... .c.. ... ....... . . . . . t.'"",,' :e.:3, ,,<,> m.;+>g..: g;~?.s<>.

;., p&%*2..;; $;$k>y: gg{*.::.. --.?-.,%:.: s:..; .... .. &,<: :;* : - sh.::<+$2;-. ..-_._. ......... i. 5.-.. ' ... ...., ........... . . . <.. ' ....... . ;;-;$i.;+.. . *.>.?

..$> z.-:-:.

........... *... i:,*.i . . ............ . .a:..- '. . . . . . - .'.L'.;: .............. . . . . . . . . . . ................ The protection scheme for a power system should cover . ..- ._ . . I . :

the whole system against all probable types of fault. .......... .'. .-:.,. \ . ,.: .-; - . ' ;" .. -. . .:. !

Unrestricted forms of line protection, such as overcurrent . . . . . . . . : . .

and distance systems, meet this requirement, although .::.: .: faults in the busbar zone are cleared only after some time delay. But if unit protection is applied to feeders ...; . :;;../, .

. . and plant, the busbars are not inherently protected.

Busbars have often been left without specific protection, for one or more of the following reasons:

a. the busbars and switchgear have a high degree of reliability, to the point of being regarded as intrinsically safe

b. i t was feared that accidental operation o f busbar protection might cause widespread dislocation of the power system, which, i f not quickly cleared. would cause more loss than would the very infrequent actual bus faults

c. i t was hoped that system protection or back-up protection would provide sufficient bus protection i f needed

I t is true that the risk of a fault occurring on modern metal-clad gear is very small, but i t cannot be entirely ignored. However, the damage resulting from one uncleared fault, because of the concentration of fault MVA, may be very extensive indeed, up to the complete loss of the station by fire. Serious damage to or destruction of the installation would probably result in widespread and prolonged supply interruption.

Finally, system protection will frequently not provide the cover required. Such protection may be good enough for small distribution substations, but not for important stations. Even i f distance protection is applied to all feeders, the busbar will lie in the second zone of all the distance protections, so a bus fault wil l be cleared relatively slowly, and the resultant duration of the voltage dip imposed on the rest of the system may not be ,: .: . tolerable.

. .

With outdoor switchgear the case is less clear since. ..'.... , _ :: . . I . .:, . . . . .

although the likelihood of a fault is higher, the risk of -.:?/>:...':,.

widespread damage resulting is much less. In general ':,::'. ;.:.:. then, busbar protection is required when the system . - . .

protection does not cover the busbars, or when, in order . - .

p15-232-253 17/06/02 9:4i Page 234

to maintain power system stability, high-speed fault clearance is necessary. Unit busbar protection provides this, with the further advantage that if the busbars are sectionalised, one section only need be isolated to clear a fault. The case for unit busbar protection is in fact strongest when there is sectionallsation.

The majority of bus faults involve one phase and earth, but faults arise from many causes and a significant number are interphase clear of earth. In fact, a large proportion of busbar faults result from human error rather than the failure of switchgear components.

With fully phase-segregated metalclad gear, only earth favlts are possible. and a protection scheme need have earth fault sensitivity only. In other cases, an ability to respond to phase faults clear of earth is an advantage, although the phase fault sensitivity need not be very high.

Although not basically different from i t h e r circuit protection, the key position of the busbar intensifies the emphasis put on the essential requirements of speed and stability. The special features o f busbar protection are discussed below.

Busbar protection is primarily concerned with:

a. limitation of consequential damage

b. removal of busbar faults in less time than could be achieved by back-up line protection, with the object of maintaining system stability

Some early busbar protect i~n schemes used a low impedance differential system having a relatively long operation time, of up to 0.5 seconds. The basis of most modern schemes is a d~fferential system using either low impedance biased or high impedance unbiased relays capable of operating in a time of the order of one cycle at a very moderate multiple of fault setting. To this must be added the operating time of the tripping relays, but an overall tripping time of less than two cycles can be achieved. With high-speed circuit breakers. complete fault clearance may be obtained in approximately 0.1 seconds. When a frame-earth system is used, the operating speed is comparable.

. , ,. . .

The 5tability of bus pr02ection is of paramount '.,. . .. . importance. Bearing in mind the low rate of fault

incidence, amounting to no fault per busbar in twenty years, it is clear that u the stability of the protection is absolute, the degr disturbance to which the power system is li subjected may be increased by the insta protection. The possibility of incorrect operation h the past, led to hesitation in applying bus protectio has also resulted in application of some very co systems. Increased understanding of the response of : differential systems to transient currents enable systems to be -applied wi th confidence i n their { fundamental stability. The theory of differential protection is given later i n Section 15.7.

Notwithstanding the complete stability of a correctly , applied protection system, number of reasons. These are:

a. interruption of the secondary circuit of a transformer will pr might cause trippin relative values of circuit load and effective setting. :; It would certainly do so during a through fault, :. producing substantial fault current i n the circuit in .;. question

b. a mechanical shoc cause operation, although the likelihood occurring- with modern numerical sch reduced

c. accidental interference'with the relay, aris a mistake during maintenance testing, may lead to operation

In order to maintain the high order of integrit for busbar protection, i t is an almost invariable practice I

to make tripping depend on two independent > measurements of fault quantities. Moreover, if the : tripping of all the breakers within a zone is derived from ' common measuring relays, two separate elements must -:

be operated at each stage to complete a tripping i operation. Although not the relays are separated reasonable accidental m relays simultaneously is possible.

The two measurements may be made by two similar differential systems, or one differential system may be checked by a frame-earth system. by earth fault relays energised by current transformers in the t

neutral-earth conductors or by overcurr Alternatively. a frame-earth system may be checked by earth fault relays.

If two systems of the unit or other similar t y they should be energised by separate current transformers in the case of high impedan differential schemes. The duplicate ring CT mounted on a common primary

*

~ . . . - . -- l J 4 , .. . .

- .- -

253 17/06/02 9:46 Page 235

be maintained throughout the

he case of low impedance, biased differential mes that cater for unequal ratio CTs, the scheme be energised from either one or t w o separate sets o f

'isthen no more than that o f normal circuit protection, so no duplication is required a t this stage. No t least among the advantages o f using individual tr ipping relays is the

through a common multi-contact tr ipping relay.

? the section switch tr ips bo th the adjacent zones. This %' has sometimes 'been avoided i n the past by giving the

-

zone on the faul ty side o f the section switch

: is obtained a t the expense of seriously delaying the bus

k?.., protection for a l l other faults. This practice is therefore not generally favoured. Some var~at ions are dealt w i th

;, >\ P. later under the more detailed scheme descriptions. There are many combinat ions possible, bu t t he essential principle is that no single accidental incident of a secondary nature shall be capable o f causing an e: unnecessary t r ip o f a bus section.

Security aqainst maloperation is only achieved by

i increasing the amount o f equipment that is required to function to complete an 0peration;'and this inevitably

! increases the statistical risk tha t a tr ipping operation due

[ to a fau l t may fail. such a failure, leaving aside the i. question o f consequential damage, may result i n ! disruption o f the power system t o an extent as great, or

greater, than would be caused by an unwanted trip. The relative risk of failure o f th is kind may be slight, but i t has been thought worthwhi le in some instances t o

1 provide a guard in th is respect as well. -

Security o f both stability and operation is obtained by providing three independent channels (say X, Y and Z) whose outputs are arranged i n a 'two-out-of three' voting arrangement, as shown i n Figure 15.1.

A number o f busbar protection systems have been devised:

a. system protection used t o cover busbars

b. frame-earth protection

c. differential protection

d. phase comparison protection . . . . . . . . . . . . . .

e. directional blocking protection - .. . . . . . . :; ..: . . . . . . . . . . . - ..

Of these, (a) is-suitable for small substations only, while ', , . '

. . (d) and (e) are obsolete. Detailed discussion o f types (b). = -. and (c] occupies most o f this chapter. 0 - -

.LI b CI Early forms o f biased differential protection for busbars. -

such as versions o f 'Translay' protection and also a 2 scheme using harmonic restraint, were superseded by > unbiased high impedance differential protection. c

-a C,

The relative simplicity o f the latter, and more important ly 2

the relative ease wi th which its performance can be Q

calculated. have ensured its success up to the present day. 1 5 - But more recently the advances i n semiconductor technology, coupled wi th a more pressing need t o be able to accommodate CT's o f unequal ratio, have led t o the re-introduction o f biased schemes, generally using static relay designs, particularly for the most extensive and onerous applications.

Frame-earth protection systems have been in use for -. .

many years, mainly associated wi th smaller busbar . ... protection schemes at distribution voltages and for

metalclad busbars (e.g. SF6 insulated busbars). However, i t has often been quite common for a uni t protection , . . . . .

scheme to be used in addition, to provide two separate . .

means o f fault detection. , ..

The different types o f protection are described i n the ~ ..,. . . . . . . - .

fol lowing sections. ....... . ,. .. . + .

.~ . . . 7 :. .: . . . . . . . . .

.253 17 /06 /02 9:46 Past 236

System protection that includes overcurrent or distance systems wi l l inherently give protection cover to the busbars. Overcurrent protection wi l l only be applied t o relatively simple distribution systems, or as a back-up protection, set t o give a considerable time delay. Distance protection will provide cover for busbar faults wi th its second and possibly subsequent zones. In both cases the busbar protection obtained is slow and suitable only for l imiting the consequential damage.

The only exception is the case of a mesh-connected substation, in which the current transformers are located at the circuit breakers. Here, the busbars are included, in sections, in the. individual zones o f the main circuit protection, whether this is o f unit type or not. In the special case when the current transformer_s are located on the line side o f the mesh. he circuit protection will not cover the busbars i n the instantaneous zone and separate busbar protection, known as mesh-corner protection, is generally used - see Section 15.7.2.1 for details.

Frame leakage protection has been extensively used in the' past i n many different si~uations. There are several variations of frame leakage schemes available, providing busbar protection schemes wi th different capabilities. The following sections schemes have thus been retained for historical and general reference purposes. A considerable number of schemes are still i n service and frame leakage may provide an acceptable solution in

c --. particular circumstances. However, the need to insulate 2 - the switchboard frame and provide cable gland !XI insulation and the availabiliry of alternative schemes

using numerical relays, has contributed to a decline in use o f frame leakage systems.

- 15.

This is purely an earth fault system and, in principle. involves simply measuring the fault current flowing from the switchgear frame to earth. A current transformer is mounted on the earthing conductor and is used to energize a simple instantaneous relay as shown in Figure 15.2.

No other earth conncctions of any type, including incidental conncctions t o structural steelwork are allowed. 'This rcquircmcnt is so that:

. . . . . . . . . . . . . . Switchgear framc

A' C-_________________-~----------------------------------~

. . 7 ," 0 - ..-.

' i ~ . - - . . -: . :'. . . . . Frame-carth ''. . '

. ,.~ : fault rclay .. &, .. . .

I L...:: .' Neutral . . . . . ... check rclav

. . . ,! " circuit :,.'7+? :,.$

: brcakcr :.,:$:, ..... .*!Z

,c:.2.;:<. 3 . 2 : .j;,?!,!!, ,$:, "!<A ':.'.b?<

b. earth current flowing to a system cannot flow into or out of the

. . . .

The iwitchgcai must b e insulated i s a standing it on concrete. Care must founddtion bolts do not touch the sufficient concrete must be cut permit grouting-in wi th no risk o f touching metalwork :;:.$ The insulation to earth finally achieved will not be high, .:$$

. :2 3 a value of 10 ohms being satisfactory. .::;$ .. ..s.

,.I*. >-A:,.

When planning the earthing arrangements of a frame- .',(:?: leakage scheme, the use of one common electrode for ::$; both the switchgear frame and the power system neutral '.$.?

: :&,. point is preferred, because the fault path would :$; otherwise include the two earthing electrodes i n seriel ;:<%, I f either or both of these are of high resistance or have :,% inadequate current carrying capacity, the fault current may be limited to such an extent that the protection .:z$ equipment becomes inoperative. In addition, if the >;& electrode earthing the switchgear frame is the offender, '.!$' the potential of the frame may be raised to a dangerous value. The use of a common earthing electrode of I$&

adequate rating and low resistance ensures sufficient $8 current for scheme operation and limits the rise i n f r a m e i s

. :$$ potential. When the system is resistance earthed, the ;g earthing connection from the switchgear frame is made

a. thc principal carth connection and current earthing electrode. transformer arc not shunted, thereby raising the

This risk is small i n practice necessary.

........ -~ .... ......

2-253 17/06/02 9 : i S Page 237

. . . . . . . . . . . . . . . . . . . . . . . .

Outgoing Switchgear feeder frame

-

rcsistancc to caYn I A -

! : , :

. . ;;<,;,- ' > C,;: ;cni . . . . . I . . .- . :.. ;;, , > . :! , . ; .

Under external fault conditions, the current I , flows through the frame-leakage current transformer. If the

' insulation resistance is too low, sufficient current may

, . : f low t o operate the framc-leakage relay, and, as the check . ... feature is unrestricted, this wi l l also operate t o complete :-'the . . tr ip circuit. The earthresistance between the Gr th ing :-'electrode and true earth is seldom greater than IR, so

with 10R insulation resistance the current I , is l imited to 10% of . the total earth faul t current I , and 12. For this reason, the recommended minimum se;:ing for the scheme is about 30% of the minimum earth faul t current.

barriers A

t ' Zonc G I : framc lcakagc

, rclay

' I Zonc 11 '

A : framclcakagc : & rclay I

1 , - - - - - - - , 1 , - - - - - - - .

. - - - - - - - f

1 t 1 Trip i; Trip L Trip iI1

If it is inconvenient to insulate the section switch frame o n one side, this switch may be included in tha t zone. It is then necessary to intertrip the other zone after approximately 0.5 seconds if a faul t persists after the zone including the section switch has been tripped. This IS illustrated in Figure 15.5.

& I.. ,

ln iu l~t ion All cable glands must be insulated, to prevent the

/ barrier L e circulation o f spurious current through the frame and . , . . -2 . i ? . ,

earthing system by any voltages induced in the cable - Zonc G Zonc I1 ,

- sheath. Preferably, the gland insulation should be Q

. . . . ' .:

provided i n two layers or stages, wi th an interposing layer of metal, t o facil i tate the testing of the gland . : ..

15 . i:,. insulation. A test level o f 5kV from each side is suitable.

8- - . ..* . . . . .

Section 15.6.1 covered the basic requirements for a system t o protect switchgear as a whole. When the busbar is divided into sections, these can be protected separately, provided the frame is also sub-divided, the sections mutual ly insulated, and each provided wi th a separate earth conductor, current transformer and relay.

Ideally, the section switch should be treated as a Separate zonc, as shown i n Figure 15.4, and provided wi th either a separate relay or two secondaries on the frame-leakage current transformer, w i th an arrangement t o t r ip bo th adjacent zones. The individual zone relays t r ip their respective zone and the section switch.

Zonc H $& B--& I I I I

8 , I I

I L - - - - - - J

t t t Trap J Trip A' Tr~p L

Chap15-232-253 17/06/02 9 : 4 6 Page 238

. .

!>X ,.. . 2 as operation due to mechanical shock or mistakes made ,.,$

by personnel. Faults in the low voltage auxiliary wiring 3 must also be prevented from causing operation by !# :% passing current to earth through the switchgear frame ':..$:

A useful check is provided by a relay energised by the, 4 system neutral current, or residual current. I f the neutral ,f check cannot be provided, the frame-earth relays should ': have a short time delay. . . .<+9 <!,&

When a check system is used, instantaneous relays can $ be used, with a setting of 30% of the minimum earth ,$ fault current and an operating time at five times setting 3 . . .\, of 15 milliseconds or less. ij Figure 15.7 shows a frame-leakage scheme for a .: metalclad switchgear installation similar to that shown ':: in Figure 15.4 and incorporating a neutral current check !!

a;

obtained from a suitable zero sequence current source, < ;s' such as that shown in Figure 15.2. I ,

For the above schemes to function it is necessary to have a least one infeed or earthed source of supply, and i n the latter case it is essential that this source o f supply be connected to the side o f the switchboard not containing the section switch. Further, if possible, it is preferable that an earthed source of supply be provided on both sides of the switchboard, in order to ensure that any faults that may develop between the insulating barrier and the section switch will continue to be fed with fault current after the isolation o f the first half o f the switchboard, and thus allow the fault to be-removed. Of the two arrangements, the first is the one normally recommended, since i t provides instantaneous clearance of busbar faults on all sections of the switchboard.

. ;. , .: ' . , . . . . . . i : : i . - , . .

I t is not generally feasible to separately insulate the metal enclosures of the main and auxiliary busbars. Protection is therefore generally provided as for single bus installations, but with the additional feature that circuits connected to the auxiliary bus are tripped for all faults, as shown in Figure 15.6.

Trip relays

Insulation A b a r r i c r s

. .

Zonc G

5 Zonc 1,

I I ! : I Zonc G

74 Alarm canccllat~on relay CS5 Control sclcctor swftch protcct~on ~n/prolccl~on out L, Busbar prolcclcon In scrvtcc lamp 3 I, Busbar protcclton oul of scrv~cc l ~ m p L, lrlpptng supply hcallhy lamp I , , Alarm and ~nd~cal !on supply hcalthy lamp

Tripptng rclayr

r rwitchcs

:1z.,.c. ! 5 ;. lk::,cc( r?<p;2,",! ::>I: !,:2f:? . : 3

,.,r,'s::: ? : r : :; r ra r ;c . - l r c .oyc . , < ! ~ c : n r .:A '.! '.

' J .. il . '? i . .,.

The protection relays used for the discriminating an check functions are of the attracted armature type, wit; two normally open self reset contacts. The tripfln circuits cannot be complete unless both ,,.:r

discriminating and check relays operate; this is becay: the discriminating and check relay contacts connected in series. The tripping relays are attracted armature type.

On all but the smallest equipments, a check system should be provided to guard against such contingencies

. . . . Pj'.'. , . : , . -

162L253 1 7 / 0 6 / 0 2 9 : 4 6 Paae 2 3 9 -

fis usual to supervise the satisfactory operation o f h tcc t ion scheme with audible and visual alarms &$cations for the following:

busbar faults ', b&?!. prc::diofi ifi service y:

c. busbar protection out o f service

the and

d. tripping supply healthy *-

' e. alarm supply healthy

enable the protection equipment-of each zone to be out of service independently during maintenance

periods, isolating switches - one switch per zone - are '.provided i n the trip supply circuits and an alarm cancellation relay is used.

The scheme may consist of a single relay connected to the bus wires connecting all the current transformers in parallel, one set per circuit, associated with a particular zone, as shown i n Figure 15.8(a). This will give earth fault protection f o r the busbar. This arrangement has often been thought t o be adequate.

If the current transformers are connected as a balanced group for each phase together with a three-element relay, as shown i n Figure 15.8(b), additional protection for phase faults can be obtained.

The phase and earth fault settings are identical, and this scheme is recommended for its ease of application and good performance.

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .; + ? ! , ,,:. :;, . .

8 . L i. 3 Each section o f a divided bus is provided with a separate

+: 'The Merz-Price principle is applicable to a multi-terminal circulating current system. ~h~ zones so formed are Zone such as a busbar- The principle is a direct over-lapped across the switches, so that a fault

i . application of Kirchhoffs f i rst law. Usually, the the latter trip the two adjacent zones. hi^ is f- circulating current arrangement is used, in which the illustrated in ~i~~~~ 15.9. 2 .. current transformers and interconnections form an

1 1; -analogue of the busbar and circuit connections. A relay Tripping two zones for a section switch fault can be .... $.F?cQ?nected -across t h c . 0 bus .wires represents a fault avoided by using the time-dela~ed technique Section ..

c;path:in the-prima-w.system i" the analogue and hence i s . 15.6.2. However instantaneous . . operation is the .

~~'%bt,n&gised until i f a u l t occurs on the busbar; it then - preferied . . . . . . . . . . . . . . . . . . . ii3eceiyes an input that, in principle at Icast, represents - . .

. . . > . . . . . . ........................................ = - f ;::the fault current. o

...................................... ............. . . . . . .

- - : ) -

Zonc B b

El - P - G i

...... . . . . . Q 9 C, - - Q

A - : . 15 I I Zonc C

............ ....... a) Basic circulating currcnt schcmc (carth fault protcction only) j i

. i '. H -

Typical fccdcr circuits

F:z!,r< ! 5.9: zo,:<.> 1,: ~ 1 r ~ : c ~ f ~ : l l ~

for d<!l,!,l<. b,,, > I : ; ! , < , , :

. . . . . . . . . . . . .

: For double bus installation, the two busbars will be .....:!j;i....-s>y ... . . . . ,. i treated as separate zones. 'The auxiliary busbar zone will ' ;:::::.',;..-.' .:'.

Diffcrcntial rchy i overlap the appropriate main busbar zone at the bus ..;....:. . . . - :. . :',,;:::-.. . .. -,, ; - / coupler. ..,.;:s...- ....... .,.:.I, ;. ,.:; :. -:;:,:.

i , ,,:- .:. . : ?;.:.''; : b) P ~ P S C and carth fault circulating currcnt schcmc using I Since any circuit may be transferred from one busbar to ;:+?i<~:l3:+;;!f:.

, .-. . . . . . . . . . thrcc-clcmcnt rclay i the other by isolator switches, these and the associated ::;.!$..:;?&-;, ....... - .. .-. . . . . . - - - - ...... . . . . . ./-.'iz;c 15.9: Circolor ing currcnr schcn;r tripping circuit must also.,be switched to the appropriate .. ,.:?; l/..,;~L:::?:, ..:.

:.:<..: :'..+~ .:<;,;.;?.* .' ::: :.

I . . ,, ,-;:;,:z.;z:::<. . :. .&;. .- J.w.: ;

.,I . +:.*. .:, , -e;,>. .:B:Y-.;.

..;,+,$.&$;.:~;;y:.. Z J 9

.. ,.; *;;-a,.. ~ , r - . ~ l p r . r r r r i . . u A . r . - . r i * ; G a i l * \_ ! '. -:&;.;:.;,.,:, .

\ * , - -,.cp,;;:<, Y!?'. , . .. +;+,$$%, 1, 8s ,,. .... ..> 3: t>.:..v,;.;.:?< . .

ir.;,;44,5x.2;:,:.q:.- . . . :.i;:>5fi5c.-.,., -. i . .

. . . . . . . . . . ... .,: ;.;. e. , . . . . . . . . . . . . . . . - .

, . . . .

Chap15-232-253 17/06/02 9 : 4 8 Page 240

:.. :

zone by 'early make' and 'late break' auxiliary contacts. This is to ensure that when the isolators are closing, the auxiliary switches make before the main contacts of the isolator, and that when the isolators are opened, their main contacts part before the auxiliary switches open. The result is that the secondary circuits of the two zones concerned are briefly paralleled while the circuit is being ransferred: these two zones have in anv case been

:-:. . . . ,.::.2.:\c~, ........ .. united through the circuit isolators during the transfer . - ..... ?:?>:$;: operation. .: ;.y:<:.?:

:..\ .. . . . ...... . . . .

Ideally, the separate discriminating zones should overlap each other and also the individual circuit protections. The overlap should occur across a circuit bteaker, so that the latter lies i n both zones. For this arrangement i t is necessary to install current transformers on both sides of the circuit breakers, which is economically possible with many but not al l types o f switchgear. With both the circuit and thc bus protection current transformers on the same side o f the circuit breakers, the zones may be overlapped a t the current transformers, but a fault between the CT location and the circuit breaker will not

:. , .be completely isolated. This mat ter is important in all

. . . . . . . . . .:., ..

. . . .. . . . . 1 . . . . .. switctigear,to '.wl%ch these . conditions apply, and is :: .i:-;;.:::, paaiculaily impohant.in the case of outdopr switchgear - . . .

. . . . -- . . where :se.parately 'mbirnted. ' muiti-secondary current . . . .

- :.,: ,!s. - transformers are generally 'used. The conditions are. ;,o. -'::. shown i n Figure 15.10.

i *. :/ L a

W 'L1

a. Currcnt lransformcrs mounted on bolh rider of brcakcr -no unprolcclcd region -

b. Currcnt transformers mounted on c ~ r c u ~ l side only of brcakcr

-law11 shown not cleared by circuil prolcction

1

. . c , ) a . 7 ~ s t l i c c . : cc cr,i,r!! f > * c g k c r *):.:,.

. -. . -. -- ..

A

. .

Figure 15.10(a) shows the ideal arrangement i n which, ...: both the circuit and busbar zones are overlapped leaving!: no region of the primary circuit unprotected.

a small region of the priniary circuit unprote unprotected region is typically refcrred to as the 's zone: The fault shown will cause operation o f the busbar protection, tripping the circuit breaker, but the fault will continue to be fed from the circuit, if a source of p is present. It is necessary for the bus protecti intertrip the far end of the circuit protection, if the is of the unit type.

With reference -to Figure 15.10(b), special 'short

technique may be used, particularly when th

the fault is i n the switchgear connections generator; the latter is therefore tripped electrical shut down on the mechanical side so as to

The protection of busbars.in.mesh c o h e gives rise t o additional considerations location. A single mesh corner is s

. . . .

Norc I : Only 1 connection lo (hc rncsh corncr pcrmiltcd : <$@ 1 (a) CT arrangcrncnlr for protection including mesh corner j .....

i .>?$ ; , , :.g ,

Nocc 2: Multiplccircuils may bc conncclcd lo rhc mesh corncr

(b1 CT arrangcmcnlr for protccrion - additional mesh corncr prolcclion required

. . . . . . . . . . . . . . . . . . . . . .: . ! . , t i

. . , . I

. . . : I.

32-253 17/06/02 ' 9 : 4 8 Page 241 -$-

onnection to the mesh is An equivalent circuit, as in Figure 15.12, can represent a irculating current system.

...... .- . - - -- - ...-.. -. - - .-...... - . - . . - -. . - - - - . - .... - ....... - .

I '\$

I hout any means of determining the faulted

'connection. Protection CT's must therefore be located on . :

each connection, as shown in Figure 15,11(b). This leaves

t R a RLG hown in Figure 15.11 (b).

RR

. . . . . . . . . . .

I d >

considerations that have to be taken into account are detailed i n the following sections. -

2.; .-.!,".. ............ :: . .!2. E : : ~ ; G < ! ! ? : > ! i : : < ; : ; i k;g, !.:.~;:, - c c . : . :3 . ,> . ." . ' I : : ; . G: c ~ ~ f < i i ~ Z ~ ~ O Z < U ; < < L : : : > k > : C . 5

~ h , current transformen are replaced in the diagram by of flux ideal current transformerj feeding an equivalent circuit . ....................... -; ,, :

that represents the ,magn,etising losses and seco":da,iy= :j:,-~;~~~;~:~.~:;i::,:. ..,: . .. . .

. winding .resistance, ..and a i so . the resistan,& ' df .;.I.:-.;;.- ;::j :-.;.

the convecting .leads. ~h~~~ . circuits can then be ,:GI~ 1.:. . . . . is not' detrimental as long as it interconnectedas shown, with a relay connected to the. ':'.'- 2 . .,

linear range of the junction points to form the complete equivalent circuit '.;f .4

Q

Saturation has the effect of lowering the exciting 2 region of the and is assumed take place severeiy in

1 characteristic; this not in itself a spill current transformer H until, at the limil. the shunt b

output from a pair of balancing current transformers impedance becomes and the " can produce 2 1 provided that are identical and equally output, This condition is represented by a short circuit. 3 1 A group of transformers, though may be of shown in broken line, across the exciting impedance. it a7

the same design, will not be completely identical, but a should be noted that this is not the equivalent of a

important factor is inequaliOl of burden in the physical short circuit, since it is behind the winding

case of a differential system for a busbar, an external resistance . 15-

fault may be fed through a single circuit, the current Applying the Thkvenin method of solution, the voltage being supplied to the busbar through all other circuits. developed across the relay will be given by: The faulted circuit is many times more heavily loaded than the others and the corresponding current

I = "I transformers are likely to be heavily saturated, while RR+ R,.,i +RUN .

those of the other circuits are not. Severe unbalance is .. : < , d G ! , : , a T5 . !

. . . . . . . . . . . . ...... .. ., therefore probable, which, with a relay of normal burden, The current through the relay is given by: . . . ,.:......c ..:.. ,~,!< . . . . ...... 2 . . . \ IU. . . . . . . . . . . . : ..>.. . could exceed any acceptable current setting. For this .: ,,.+, ;$;?, -. ..:.

;;. . , - I

.,?' reason such systems were at one time always provided ~ , ( R u i +&H) >, :. ~+;$;>;~ ,5~;~< . ,T<-27-,A... . , .. - - .... dclay. This practice is, however, no longer .xe&+,;::pz-.~

R ~ + R f f i + R ~ ~ i ?:-:.4c-.:,", ..:, ",%.7,. ; ,'.."'

. , . f ">I! , , ,: ,. ! 5 . 2 $ii&$;!$::; .,*".. ,,.&&: asible to calculate the spill current that may If RR is small. IR will approximate to IF which is ?$@<@$@: ortunately, this is not necessary; an alternative unacceptable. On the other hand, i f RR is large IR is jr.7~:c:22~,-v~j

approach provides both the necessary information and the reduced. Equation 15.2 can be written, with little error. - ' ' ~ ~ ~ < ? ~ f % ? ~ . .,,'+?.,.& .:;:>;:: 1

.. ..... ... - technique required to obtain a high performance. as follows: .:.- . . . .,. ...::> .,.. , . . .. ,.;.,.<; . .A,, . . ..,,,, ':.k.j,; . . .......... ,.: :.: :,,: .:$,,. ...<,::;S;t.i'

... .- - . . . . . . . . . . . a. , .L.. ,. .::: .., ..;,.:;.: -.,.,, - ' . P r . r r , r i . . U I . r . - # l * . . C - i d , 1 4 1 -.-I. . ; .? :\i_&~y>Tp >, ,'. , .";*,.' jy;j . . . ,?*< .~.?.>,?, %.5.*'.

- ; . . ,;5:<.;: ::-'. .;. ;. .&d9".+$i,?,. ..... ,- *a. $,,,.'k L?<!s,< ; r, >:

. ,: . . . . . - :j . . . . -. .

. . -- -. .-

I ; ;a!i - .,,i .. . . .

-253 17 /06 /02 9:48 Page 242

V, I , ( R , + R m ) I # = - - = R R .R R ... E g u o t i o n !5.3

or alternatively:

It is clear that,by increasing RR, the spill current ZR can be reduced below any specified relay setting. RR is frequently increased by the addition of a series-connected resistor which is known as the stabilising resistor.

It can also be seen from Equation 15.4 that it is only the voltage drop in the relay circuit at setting current that is important. The relay can tie designed as a voltage measuring device consuming negligible culrent; and provided its setting voltage exceeds the value Vf of Equation 15.4, the system will be stable. In fact, the setting voltage need not exceed V/. since the derivation of Equation 15.4 involves an extreme condition of unbalance between the G and H current transformers that is not coppletely realised. So a safety margin is built-in i f the voltage setting is made equal to Vf

I t is necessary to realise that the value of I/to be inserted in Equation 15.4 is the complete function of the fault current and the spill current IR through the relay, in the limiting condition, will be of the same form. I f the relay requires more time to operate than the effective duration of the d.ct transient component, or has been designed with special features to block the d.c. component, then this factor can be ignored and only the symmetrical value of the fault current need be entered in Equation 15.4. I f the relay setting voltage. V,, is made equal to VJ - that is, I / (RL + RCr], an inherent safety factor of the order of two will exist.

RL + RCI. = lead + CT winding resistance

(range 0.7 - 2.0)

It remains to be shown that the setting chosen.. suitable.

The current transformers will have an excitation curve which has not so far been related to the

winding resistance, with the maximum secondary fa current flowing through them. Under in-zone fa conditions it is necessary for the current transformers produce sufficient output to operate the relay. This will be achieved provided the CT knee-point voltage exceeds. the relay setting. In order to- cater for er to specify that the current transformers knee-point e.m.f. of at least twice the necessaq'settin voltage; a higher multiple is of advantage in ensuring high speed of operation.

. .

carrying primary cuiwnt or n strictly speaking be vecto arithmetically. t t can be expressed as:

IR = IS + l l I C s

cycle and with no special f~atures to block the d.c. IR = eflective setting component, it is the r.m.s. value of the first offset wave

n = number ofparallel - conilecred CT's

Equation 15.4 as:

Equol iorr 1 5 . 5

= stabiliry of schetne

= relay circuit voltage setting ,- -- . p _ _ . _ _ - -

/ N ~ f w a r k P r . r r r t i . m €d A . t . r , r i . m C a i l r

. ,

Fi; a. phase-phase faults give only86% o f the three- This will not happen to any large degree if the fault

phase fault current current is a larger multiple of setting; for example, if the E' T.I . .- , . . . ' fault current is five times the scheme primary operating

':h resistance current and the CT knee-point e.m.f. is three times the y reauce raulr currents somewhat relay setting voltage, the additional delay is unlikely to

....

, . c. a reasonable margin should be allowed to ensure exceed one cycle.

that relays operate quickly and decisively - b! , The primary operating current is sometimes designed to

~t is desirable that the primary effective setting should not exceed the maximum expected circuit load in order to

graceed 30% of the prospective minimum fault current. reduce the possibility of false operation under load p current as a result of a broken CT lead. Desirable as this

earth fault safeguard may be, it will be seen that i t is better not to %.protection, the minimum earth fault current should be increase the effective current setting too much, as this 8.: considered, taking into account any earthing impedance will sacrifice some speed; the check feature in any case, . ?

iy that might be present as well. Furthermore, in the event maintains stabilitv. 1 of the inter-

An overall earth fault scheme for a large distribution .f. is available

board may be difficult to design because of the large I n in the earth

number of current transformers paralleled together, g;? nu l r currenc. Ine prlmary operating current must which may lead to an excessive setting. It may be e not greater than 30°/0 of the minimum advantageous in such a case to provide a three-element

se earth fau;t current. In order to achieve phase and earth fault scheme, mainly to reduce the ed operation, it is desirable that settings should number of current transformers paralleled into one group.

r, particularly in the rase of the solidly power system. The transient of the Ems-high-voltage substations usually present no such

i n conjunction with wnfavourable residual problem. Using the voltage-calibrated relay, the current consumption can be very small.

can cause a high degree of saturation and utput, possibly leading to a delay of several cycles A simplification can be achieved b y providing one relay

91 to the natural time of the element. per circuit, all connected to the CT paralleling buswires:

-

Zonc R .......... *. ..... .

1' : r21. /

Zonc A I I Bus wircs

Zonc Bur wi

Chcck 208 Bur wir

. .

I Zonc AIZ 1 '' ' 1

Zonc A12 Bur wircl

~ u l l r n aclay L V ~ C nr r rcla --...,..-... ", w m e ar chcct u m c ar chcci samc as chcck

A11 First main burbar A12 Second main burbar

5tabiliring Rcrirtor

K Rcrcwc burbar Iligh lmpcdancc Ctrculattng Currcnt Rclav

IS-

53 17 /06 /02 9 : 4 8 Page 2 4 4

....................... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3 0 Zonc indicating rclay Zonc bus wircs shorting relay 74 Alarm cancclla:~on relay CSS Control selector switch

80 D.C. volts supcw~sion relay L I Indicating lamp protection in scrvicc 8 7 High impcdancc circulating current relay L2 Indicating lamp pcorection out of scrvicc , 95 Bus wires supcwision rclay

This enables the trip circuits t o be confined to the least subdivision being necessary. For phase fault sche

area and reduces the risk o f accidental operation. the check will usually be a similar type of scheme ap to the switchboard as a single overall zone.

i ..... :;. ; i':>, : . : : .:; A set of current transformers separate from those use

Schemes for earth faults only can be checked by a frame- the discriminating zones should be provided. No" earth system, applied to the switchboard as a whole, no switching is required and no current transformers

,

. . . . . . - 2 4 4 . .-. N , r r . r k P r . r r r r i . m U A , r . n . r i . . C . . . . .

-4-

: zone i n bus-coupler and bus-

CT Scconciarf Circuits

CT secondary circuit up to the :tions will cause an unbalance in

equivalent to the load being carried by the c i rcu i t Even though this degree o f .- -* ' . ~ r i o u s output is below the effective setting the

'&dition cannot be ignored, since it is likely to lead to a b i l i t y under any through fault condition. . -. PL

h r v i s i o n can be carried out to detect s;ch conditions $ connecting a sensitive alarm relay across the bus &es of each zone. For a phase and earth fault scheme, mjnternal three-phase rectifier can be used to effect a bthmation of the bus wire voltages on to a single alarm ' I

lcment; see Figures 15.13 and 15.14. . . .:

he alarm relay is set so that operation does not occur ~ith the protection system healthy under normal load. ubject to this proviso, the alarm relay is made as wsitive as possible; the desired effective setting is 125 imary amperes or 10% of the lowest circuit rating, hichever is the greater. -

cubicle. It is possible that special circumstances involving onerous conditions may over-ride this convenience and make connection to some other part o f the ring desirable.

Connecting leads will usually be not less than 710.67mm (2.5mm1), but for large sites or in other diff icult circumstances it may be necessary to use cables of, for example 711.04mm (6mm1] for the bus wire ring and the CT connections to it. The cable from the ring to the relay need not be of the larger section.

When the reserve bar is split by bus section isolators and the two portions are protected as separate zones, it is necessary to common the bus wires by means o f auxiliary contacts, thereby making these two zones intb one when the section isolators are closed.

This section provides a summary of practical considerations when implementing a high-impedance

busbar protection scheme.

nce a relay of this order o f sensitivity is likely t o !:! ::: :: ; .,I. .;:;! :':! .i:r:!j,.;:::,. -,:: ; . ..

%rate;during thrdugh faults; a t ime delay, typically of . . i&;:s@cd"ds; is to . . avoid unn&cessary alarm, For normal circumstances, the stability level should be I- :-';: - . -

. . . . designed to correspond to the switchgear rating; even if . . - : : I

jnals. .- . - . . - . . . . . . . the available short-circuit power in the systemis much I

... less than this figure, it can be expected that the system -5 ! . i: '. .8.5 krrangc:-- . i - ; .!- . Car :i.;: .... . . wil l be developed up to the limit of rating. b

E, C

;s shown in Equation 15.4 how the setting voltage for liven stability level is directly related to the resistance the CT secondary leads. This should therefore be )t to a practical minimum. Taking in to account the lctical physical laying of auxiliary cables, the CT bus 'es are best arranged in the form of a ring around the tchgear site.

I double bus installation, the CT leads should be taken

Current transformers must have identical turns ratios. &. m

but a turns error of one in 400 is recognised as a - . 2 - reasonable manufacturing tolerance. Also, they should rq preferably be of similar design; where this is not possible the magnetising characteristics should be reasonably matched. 15.

:ctly to the isolator selection switches. The usual Current transformers for use with high impedance ting of cables on a double bus site is as follows:

protection schemes should meet the requirements of a. current transformers to marshalling kiosk Class PX of IEC 60044-1.

b. marshalling kiosk to bus selection isolator auxiliary . I

switches The setting voltage is given by the equation

2. interconnections between marshalling k i d s to form a closed ring v, > I f ( R , + Red

rclay for each zone is connected to one point of the where: bus wire. For convenience of cabling, thc main zonc VI = relay circuit voltage

ys wi l l be connected through a multicorc cable vcen the relay panel and the bus section-switch I f - steady-state through fault curreirt rhall ing cubicle. The reserve bar zone and the check

R,. = CT ICS iS t e t ICe : relays wi l l be connected together by a cable l ing to the bus coupler circuit breaker marshalling Rcr = CT secondary ruinditrg resistntrce

i

. . ,., I..,. .., , .,;:

!':.., . . . . . .,.< .. .,,.

> I - . . f.

*:I'

.:!,.?;* , !: :I, ., . , . i l. ; 3 *>:. , LC).

. : . ,..!I

.. ; I $ I . , i.., .

. .: ,.wk; ! : I$I.*

.". ::,,L.? . ' *I

', , :,[~;c:,,. : , ,.?,

. . I.,,.

'hap15-232-253 17/06/02 9 : 4 a Page 246

- ,\L .' ,..:. ,. . .

. . -.:.&;,;?< . .,?u"4'+

, .,.G*.g , -. ;;.:

. , . +x?,< f5.&.6.<</:(:'<-3:?j17;.,;:.-.- ~fa:I:;~:ie:-?: ,.,r..;Ii!:,...'..r\ . - .. , . . . ,<>

:$<.: $2: This is given by the formula . - .. .:brs

.,.,' .

;.*.>,> 7..:vr<-b . . .The effective setting of the relay is given by

.:'..:'.

..- ..

Is = relay-circuit current settirlg

Ics = CT exr i tat io l~ current at voltage seff i~lg

n = number of CTS i n parallel

For the primary fault setting multiply IR by the CT turns ratio.

It is clear from Equations 15.4 and 15.6 that i t is advantageous to keep the secondary fault current low; this is done by making the CT turns ratio high. I t is common practice to use current transformers with a secondary rating of 1A. . I t can be shown that there is an optimum turns ratio for

.. . ;.I the current transformers; thiswalue depends on all the . . application but is generally about 200011.

' ' . though a lower ratio, fo r instance 40011, is often ' . employed; the use of the optimum ratio can result. in a

sz ,I.:. considerable reduction in the physical size of the current 0 . -= : .:. transformers.

.. E, . . .. 4 , ~ : ~ . ~ . z , , . > L',.:,: :.;.:.. : .

, . :, ,, . . . , . ,/.. ; , 3 ., :,.., , ., ,: ,: .

? Z Under in-zone fault conditions, a high impedance relay +, constitutes an excessive burden to the current 'a s transformers, leading to the development of a high -

voltage; the voltage waveform will be highly distorted * but the peak value may be many times the nominal saturation voltage.

15 . When the burden resistance is finite although high, an . c approximate formula for the peak voltage is: . - . . -.

where:

V p = peak voltage del)elopcd

VK = knee-poit~t voltage

VF = prospective voltagc i n abserlce ojsaturation

This formula does not hold for the open circuit condition and is inaccurate for very high burden resistances that

. :

approximate to an opcn circuit, because simplifying assumptions used in the derivation of the formula are not valid for the extreme condition.

. . Another approach applicable to the opcn circuit ,: . , - c; .. .?--

secondary condition is:

I f =fault current

Ick = exciting current a t knee - point voltage

VK = knee - point voltage

simple combination of burden and exciting impedance

These formulae are therefore to be regarded only as guide to the possible peak voltage. With large current transformers, particularly those with a low sesonda current rating, the voltage may be very high, above

ceramic non-linear resistor in parallel having a characteristic given by:

v= CP

where C is a constant depending on dimensions and a constant in the range 0.2-0.25. . '

voltage setting depends on the value of ~ ; . i ' n keep the shunting effect t o a minimu recommended to use a non-linear resistor with a value of

Instantaneous attracted armature relays are used. Simple fast-operating relays would have a low safety factor constant in the stability equation, Equation 15.5, as discussed in Section 15.8.1. The performance is improved by series-tuning the relay coil, thereby making the circuit resistive in effect. Inductive reactance would tend to reduce stability, whereas the action of capacitance is to block the unidirectional transient component of fault current and so raise the stability constant.

An alternative technique used in some relays is to apply the limited spill voltage principle shown in Equation 15.4. A tuned element is connected via a plug bridge to a chain of resistors; and the relay is calibrated in terms of voltage.

The principles of low impedance differential protection have been described in Section 10.4. including the principle advantages to be galned by the use of a bias.

32-25: 17:05/02 9 : 4 8 Page 2 4 7

&nique. Most modern busbar protection schemes use

e principles of a check zone, zone selection, and .

gements can sti l l be applied. Current . . En transformer secondary circuits are not switched directly ' ' by isolator contacts but instead by isolator repeat relays kr_ tis= after a secondary stage of current transformation. These 3 switching relays form a replica of the busbar within the !:, protection and provide the complete selection logic.

,.I

;!< With some biased relays, the stability is not assured by. I:. the through current bias feature alone, but is enhanced , .. ;: by the addition of a stabilising resistor, having a value .: :; which may be calculated as follows.

' The through current will increase the effective relay

i minimum operating current for a biased relay as follows:

where:

IR = eflecfive 1nii1i111uii1 o p r n t i ~ i g currer~t - .

; - G = relay s e n i i ~ g cunei l t

As IF is generally much greater than Is, the relay effective current, IR = B k approximately.

From Equation 15.4, the value of stabilising resistor is given by:

- - LH + < ; ! I

t3 It is interesting to note that the value of the stabilising resistance is independent of current level, and that there would appear to be no limit to the through-faults stability level. This has been identified [15.1] as 'The Principle of Infinite Stability:

The stabilising resistor still constitutes a significant burden on - the current transformers during internal faults.

An alternative technique, used by the MBCZ system described in Section 15.9.6, is to block the differential measurement during the portion of the cycle that a current transformer is saturated. If this is achieved by momentarily short-circuiting the differential path, a very low burden is placed on the current transformers. In this way the differential circuit of the relay is preventtd from responding to the spill current.

It must be recognised though that the use of any technique for inhibiting operation, to improve stability performance for through faults, must not be allowed to diminish the abilii\i of the relay to respond to ir~iernai fauiu.

For an internal fault, and with no through fault current flowing, the effective setting (IR) is raised above the basic relay setting (Is) by whatever biasing effect is produced by the sum of the CT magnetising currents flowing through the bias circuit. With low impedance biased differential schemes particularly where the busbar installation has relatively few circuits, these magnetising currents may be negligible, depending on the value o f Is.

. . .

The basic relay setting current was formerly defined as the minimum current required solely i n the differential circuit to cause operation - Figure 15.45(a]. This $@@:1i&3&. approach simplified snalysis of performance. bu t was .;:s&:,;._.-::::: ~ - .. considered to be unrealistic, as i n practice any current -y*+c::7..~. . flowing i n the differential circuit must f low i n a t least . .-

one half o f the relay bias circuit causing the practical . . 25,

minimum operating current always to be higher than the . . . . ,- nominal basic sett ing current.. As a.. result,.-a: : .... ._:. ............... later: :...-... - . ..,L....r2,; ,. +. . '. .- .' . , - definition, as shown i n Figure l5.l:5(b) w+.developed;: -;.i;~~;:~~.rl..i;~;r;~~~. . . . . . . . . . . . . . . . . . . . . . . . . . .:-:. .. .... . . :.--:-..' . .c>. - , .* ........ ;, .:._ . ..;.. . . . . . . . . . - . . . Conversely, if needsto be. appreeiif& tkit applying' . thi~.1:6:.....1<.~....~~...r. ,.,-.-. ...........

later definition of relay setting cu.rrent, whicti. flows . : -. .$:;i= ::.. ;:!.:-.:.. .-:-- ::: -..- .:.. -'-I - through at least half the bias circuit, the notional mini- i ~ r : . "-

: :-4 rl

mum operation current in the differential circuit alone -.. o is somewhat less, as shown in Figure 15.15(b). .L..

%. 'a

Using the def in i t iw presently.applicable, the effective .L..

minimum primary operating current 2 Q

where: N = CT ratio

i (al Suocrxdcd definition (bl Currcnt dcfinition

hapis-232-253 17/06/02 9:54 Page 248

Unless the minimum effective operating current of a scheme has been raised deliberately to some preferred value, it will usually be determined by thy check zone, when present, as the latter may be expected to involve the greatest number of current transformers in parallel. A slightly more onerous condition may arise when two discriminating zones are coupled, transiently or otherwise, by the closing of primary isolators. .,

It is generally desirable-to 'attain an effective primary operating current that is just greater than the maximum load current, to prevent the busbar protection from operating spuriously from load current should a secondary circuit wiring fault develop. This consideration is particularly important where the check feature is either not used or is fed from common main CTs.

For some low impedance schemes, only one set of main CT's is required. This seems to contradict the general principle of all busbar protection systems with a check feature that complete duplication of all equipment is required. but it is claimed that the spirit of the checking principle is met by making operation of the protection-, dependent on two different criteria such - as directional',

. . . and d.iffere?tialmeasllrements. . . . . ..

.In the MBCZ scheme, described in Section 15.9.6, the provision of auxiliary CT's as standard for ratio matching also provides a ready means for introducing the check feature duplication at the auxiliary CT's and onwards to the relays. This may be an attractive compromise when 3nly one set of main CT's is available.

In low impedance schemes the integrity of the CT secondary circuits can also be monitored. A current

. . operated auxiliary relay, or element of the main . . ..,. : .. protection equipment, may be applied to detect any

. L. . . . . , . . .... . unbalanced secondary currents and give an alarm after a

. . time delay. For optimum discrimination, the current

setting of this supervision relay must be less than that of the main differential protection.

In modern busbar protection schemes, the supervision of the secondary circuits typically forms only a part of a

.. . comprehensive supervision facility. . .. -

7 . .. , . ':. . ,.,.::., ; ; r , f : , , I ! : . , ! : g : . ..! ~ , , : , . ,.\ior::, . . . .

It is a common modern requirement of low impedance . . schemes that none of the main CT secondary circuits

. .~. . f, ,.

1 should switched. in the previously convcptional manner,

1 I .

, . -. to match the switching of primary circuit isolators.

.. ~

. . . .. . . .

. .

isolators may provide the latter.

auxiliary relays within the protection. Theserelays form ' j

them to be connected into this busbar replica.

transformers available per circuit Where the facility of :. a check zone is still required, this can still be achieved .'! with the low impedance biased protection by connecting :

. . . . . . ,. - 8 . . , .! :;;i, :., .,:,;;<.:; .!! - TYl" p.:lEjU

particular busbar installation. Additional modules can be ..

added at any time as the busbar is extended.

A separate module is used for each circuit breaker and also one for each zone of protection. In addition to these

range of CT mismatch.

. .. .~ ... . 1 8 8 - ,' -A

N < l o . r & P r . ~ r r t i . . W A . I . r . 1

&yL -lntcrmodulc plug-in buswire connections 5: i'*.. . . . . . . - . . . . . . . .

,:. 6 . . F;scre i s . 17: Jy2c :,!3CZ b:iI;o! i c : c r : ! < . n >ir::b,;i:;.i ::.;rc.int!;!r! t.'..:.. ,,,. berwccfl c8.rco8.: :::?;+<,:? o,>d p,:t;,:c:+,:,; :?,:;:;;?> . . . . . . L . . . . \.j,.. . 2. '? ' ... ..: %

;I: figure 15.17 shows the correlation between the circuit ,&:. '$;,.beakers -,.- . and the protection modules for a typical double ~~%usb8r ins ta l la t ion. In practice the modulesare mounted i+._ , . . @?nia,,multi-tier rack or cubicle: '

%-.:; $<<ve modules a r c interconnected via a multicore cable ETthat is plugged in to the back o f the modules. There are $3' five main groups o f buswires, allocated for: i .,'. I:

' c - i. protection for main busba~ I "

y',:: , ii. protection for reserve busbar r . . . . . . . .

Ill. protection for the transfer busbar. When the , . reserve busbar is also used as a transfer bar then ;4 }, " -..: .. this group o f buswires is used r .J

65 ...; iv. auxiliary connections used by the protection to p? ,

combine modules for some of the more complex kq. busbar configurations +,,!' F&,.;: ,

V. protection for the check zone ;.&: E;:: One extra module. not shown in this diagram, is plugged h.?: into the multicore bus. This is the alarm module, which ??!< ? ;,I Wntains the common alarm circuits and the bias resistors. [<%-The power supplies are also fed in through this module. E$j .,."!,..$. if#^. f 5 3, ;;, .! , . >

. . . . ' . , _; : : . . .

The traditional method for stabil isinga differential relay is t o add a resistor t o the differential path. Whi lst ' th is improves stability it increases the burden on the current transformer for internal faults. The technique used hi the MBCZ scheme overcomes this problem.

The MBCZ design detects when a 'CT is saturated and short-circuits the differential path for the portion o f the cycle for wk,ich saturation occurs. The resultant spill current does not then f low through the measuring circuit and stability is assured.

This principle allows a very low impedance differential circuit t o be developed that wi l l operate successfully wi th relatively small CT's.

. . . .

If the CT's carrying fault current are not saturated there wil l be ample current i n the differential circuit to operate the differential relay quickly for fault currents exceeding the min imum operating level. which is adjustable between 20%-200% rated current.

When the only CT(s) carrying internal fault current become saturated, i t might be supposed that the CT

5.':" : saturation detectors may completely inhibit operation by @;,All zones o f measurement arc biased by the to ta l current y,k+, short-circuiting the differential circuit. However, the B. .flowing to or f rom the busbar system via the feeders.

resulting inhibit pulses remove only an insignificant h i s cnsurcs that al l zones o f measurement w i l l have

portion o f the differential current, so operation of the similar fault sensitivity under all load conditions. The

relay is therefore virtually unaffected. bias is derived from the check zone and fixed a t 20% , w i t h a characteristic gencrally as shown i n Figure . lS.lS(b). Thus some ratio mismatch is tolerable.

' -3.1 ' Out of scrvicc C

!$$': !,.&!

. .-

: : 5 . 3 9::?$:i :i;vu,::r:: t j i -r(:or;;r;ng o n i f ;

..>;t : . . . .*' . .

.... . . . I . . . . . . . . ;:: . j <; : . ' .:., .-.. . . . . . . . . . . . . . . . . . . to operate the two busbar sections as a single bar:-:'&!:

fault currgnt will then divide betweenthe two meas&Gn,@ ! : . . ' As shown in Figure 15.18, each measuring module

elements in the iatio'of their impedances. I f both of th$ ., contains duplicated biased differential elements and also j. two measuring elements are of low and equal impedang

i ' 0 . a pair of supervision elements. which are a part of a - - .-; f!

i -: ", --- comprehensive supervision facility. the effective minimum operating current of the scheme .I

I" u will be doubled. ...$

r - . U .*< 2 This arrangement provides supervision of CT secondary . .,.

circuits for both open circuit conditions and any rhis is avoided by using a 'master/follower' arrangerneri<

i . impairment of the element to operate for an internal By making the impedance of one of the measuring

i . 9, fault, without waiting for an actual system fault elements very much higher than the other it is possibletp = to show this up. for a zone to operate it is ensure that one of the relays retains its original minimum

I , . Q necessary for both the differential supervision element operation current. Then to ensure that both the ~ ~ ~ ~ l l ~ ~ - ~ ~ ~

and the biased differential element to operate. F~~ a connected zones are tripped the trip circuits of the Me's I

: . l j . circuit breaker to be tripped it requires the associated zones are connected in parallel Any measuring unit can

i ;:. ,,,. , main zone to be ooerate,-j and also the ,-heck have the role of 'master' or 'follower' as it is selectable by , .- . * . - . . , ........ . . . t. ....: -... - . zone, as shown in Figure 15.19. : .."' :. -. ."."

,A?<..;.:-.: .:>;::;., Y -

means of a switch on the front of the module. ... .... . . . . . . . , . . . . . . . . . . . . .

ji::. ... . . . .:. ., , .;I . Main zonc cheek zonc - Serious damage may result, and even danger to life, if,;

circuit breaker fails to open when called upon to do S$ i + v c

.-..a,-.- To reduce this risk breaker fail protection schemes wefl ! .$

developed some years ago. ,

i. I These schemes are qenerally based on the assumptiol

. - , ; 7.. ..........;....... . , , .. ., . . i t has failed to function. The circuit breakers in the n$

stage back in the system are then automatically trippet When two sections of a busbar are connected together by isolators i t will result in two measuring elements For a bus coupler or section breaker this would invc

5 , being connected in parallel when the isolators are closed tripping all the infeeds to the adjacent zone, a f a t

that is included in the busbar protection scheme. .:I 13 ,. r!

1 7 / 0 6 / 0 2 9:54 Page 2 5 1 +I+

.

fibre optic link

Ccntral Unit - CU

Systcm Communication Nctwork

PU: Pcriphcral Unit

CU: Ccntral Unit

... ' .-.. p;;: r. > . : . . , . . . . . ;*; - ' . . . ig?. d. dead zone protection c. .,-.. . . .

In addition, monitoring functions such as CB and isolator The application of numerical relay technology to busbar monitorinq, disturbance recordinq and transformer

. . . . ... j !.' .. protection has lagged behind that of other protection. supervision ace.provided: . :... - . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . - . . . . i \?<functions. Static technology is still usual for such . . , . . . - Because .- o f , . the : , distributed :- topology. used, r.:l".':.:;.: . . . :,

...... ::::&hemes, !-- .. -~ . . . but numerical technology. is j o w ~ i e a d ' i l y " .'. - . . . . . . , ~~nchronisat ion o f the 'me&urernents .taken-'.by the ' :&;!-:;:

. . k;;available. The very latest d e v e l o p m ~ ~ t s i n the. . .;:- ;;, .. , , .- ; ~ iP ,:':, -pe;ifiheral u "its .is:of vital iipo.rt+ce. '.'rX1high &ability; , ~~2.'techriology are included, such as extensive use o fa data

numerically-c6ntr;11e& oscillator is fitted-in'each o f the bus to link the various units involved, and fault tolerance --

. . . . . central and peripheral units, with t ime synchronisation i 2, against loss o f a particular link by providing multiple

between them. I n the event o f loss o f the .:.z ; i communications paths. The development process has o

synchronisation signal, the high stabil ityof the oscillator . . i : been very rigorous, because the requirements for busbar % i n the affected feeder unit(s) enables processing o f the . . , j protection i n respect-of immunity to maloperation are .

~ncoming data to continue without significant errors .. Q ; very high.

. . . ! until svnchronisation can be restored. : :2 - The philosophy adopted is one of distributed processing of the measured values, as shown in Figure 15.20. Feeders each have their own processing unit, which collects together information on the state of the feeder (currents, voltages. CB and isolator status, etc.) and communicates it over high-speed fibre-optic data links to a central unit. For large substations, more than one central unit may be used, while i n the case of small installations, all of the units can be co-located, leading to fhe appearance of a traditional centralised architecture.

The peripheral units have responsibility for collecting the required data, such as voltages and currents, and processing it into digital form for onwards transmission to the central unit. Modelling o f the CT response is included, to eliminate errors caused by effects such as CT saturation. Disturbance recording for the monitored feeder is implemented, for later download as required. Because each peripheral unit is concerned only with an individual feeder, the protection algorithms must reside in the central unit.

feederr. interface units at a may be used The differential algoriihm can be much more wi th the data transmitted t o a single centrally sophisticated than wi th earlier technology, due t o located peripheral unit. The central unit performs the improvements in processing power addition to calculations required for the protection functions. calculating the sum of the measured currents, the Available protection functions are: algorithm can also evaluate differences between

- a. protection successive current samples, since a large change above a

threshold may indicate a fault - the threshold being b. backup overcurrent protection

choscn such that normal load changes, apart from inrush c. breaker failure conditions do not exceed the threshold. The same

:CbaplS-232-253 17/06/02 9 : 5 i Page 252

considerations can also be applied to the phase angles o f currents, and incremental changes i n them.

One advantage gained f rom the use o f numerical technology is the a h i ! i q )ls easi!\t re-configure the protection t o cater for changes i n configuration o f the substation. For example, addi t ion o f an extra feeder involves the addit ion o f an extra peripheral unit, the fibre-optic connection to the central un i t and entry via the M M I o f the new conf igurat ion in to the central unit. Figure 15.21 illustrates th,e latest numerical technology employed.

In considering the introduct ion o f numerical busbar protection schemes, users have been concerned w i th reliabil i ty issues such as secur i ty and availabil i ty. Conventional h igh impedance schemes have been one o f the main protection schemes used for busbar protection. The basic measuring element is simple i n concept and has few componen:s. Calculation o f stabil i ty l imi ts and other sett ing parameters is straightforward and scheme performance can be predicted wi thout the need for costly testing. Prac;ically. h igh impedance schemes have proved t o be a very reliable f o rm o f protection.

I n contrast, modern numerical schemes are more .complex w i th a much greater range o f facilities and a :\ much high component count. Based o n low impedanc bias techniques, and w i t h a greater range o f facilities t

,. <.+-.. set, sett ing calculations can also be more complex. :::.> . ..: However, studies o f the comparative reliabil i ty of i6 conventional high impedance schemes and .modern ,::-':

.~.. - numerical schemes have shown that assessing relative .:+ ....! ;I. reliability is not qui te so simple as i t might appear. The

->&? .. .. ? !*'

numerical scheme has t w o advantages over i ts older ,;$;;;i counterpart:

a. there is a reduction i n the number. o f external '..: components such as switching and other auxiliary

.,;:A

relays, rcany o f the func t ions o f which ?re performed in terna l ly w i t h i n the software ;>

alqorithms

b. numerical schemes include sophisticated monitoring features which provide alarm facilities i f the scheme is faulty. In certain cases, siniularion of the scheme functions can be (performed on line f rom the CT inputs through i o the tripping o ~ i p d t c and thus scheme functions can be checked on a regular basis t o ensure a fu l l operational mode is available a t a l l t imes

Rel iabi l~ty analyses using faul t tree analysis methods have examined issues o f dependability (e.q. the abil i ty to -

operate when required) and security (e.g.-the abil i ty no t ,

t o provide spurious/indiscriminate operation). These -.

analyses have shown that:

a. dependability o f numerical schemes is better than ""

conventional h igh impedance schemes

b. secur i ty o f numerical and conven:ional h igh impedance schemes are comparable

I n addition, an important feature o f numerical schemes is the in-bui l t monitor ing system. This considerably improves the potent ia l availability o f numerical schemes compared to conventional schemes as faults w i th in the equipment and i ts operational state can be detected and alarmed. W i t h the conventional scheme, failure to re- instate the scheme correctly after maintenance may not be detected unt i l the scheme is required to operate. In th is situation, i t s effective availability is zero unt i l it is detected and repaired.

15.1 The Behaviour o f Current Transformers subjected to Transient Asymmetric Currents and the Effects o n Associated Protective Relays. J.W. Hodgkiss. ClGRE Paper Number 329. Session 15-25 J'une 1960.

Motor Protection

lNTRODUCTlON

serious loss of production may result.

. The following table indicates typicall protection depending on the size of the motor. However, other factors should be considered when selecting motor protection, for example importance of

PROTECTION

Contactor 1. Fuses 2. Fuses + '~herrnal

Overload + U N

'I MW-3MW Options - Stalling & Undercurrent

overcurrent +

phase and earth faults.

The protection must be able to distinguish between abnormal conditions and normal motor operation. Therefore, it is important to understand the behaviour of the motor under certain conditions to be able to apply protection successfully. For example, the magnitude and duration of the starting current affects the application of overload protection; the magnitude and maximum allowable duration of stalling current in relation to those of staring current determir.~e whether separate stalling protection is required.

THERMAL OVERLOAD PROTECTION

The tolerance to overload of motors depends on the motor design and differs considerably iri Practice. The risk of damage of the insulation depends on the temperature. It is very difficult il not impossible to cover all types and ratings of motors with different applications, variety (1;

4

Page 1

If a motor is assumed to be a homogeneou and dissipating heat at a rate directly proportional temperature at any instant is given by :

b '15

where T,, = final steady teniperature ii

f = heating time constant

This assumes a thermal equilibrium in the form :

Heat developed = Heat stored + Heat dissipated.

Temperature rise is proportional to the current square.

7

Thus T = K I ,: - ! 1 - e I, is that current \vhich produces the rated

temperature rise T,; when flo\vs

continuously in the motor.

whent="C . . .

For an overload current 1 the temperature rise is given by : , ' I i . .

I .. : . .

i: 8 . ..-....... (2) -- >: *- t;.,

For the motor not to exceed the rated temperatu i ' . , ! rhe motor can withstand the current I is obtained by equating equations (1) and (2) with t = OC in i L i - equatim (1).

' ;

j:

! . . I-lcncc K I , , - =

ii. 1 g . s;. or t = r . 1 0 ~ ~

Rr ,.:: ,;;:. I-:

5.) .. . ..:: . ... -. . t i ' >;.

rload protection should satisfy the above r :notor current or a percentage of it, depending on the motor design.

is an over-simplification to regard a motor as a homogeneous .body. It actually comprises ral parts each with a characteristic surface area, mass, heat capacity, thermal conductivity rate of heat production. The temperature rise of different parts or even of various point in

e same part may be very uneven. However, it is reasonable to consider that the current-time lationship follows an inverse fashion.

b h i l e infrequency overloads of short duration may not damage the motor, sustained overload ; of a few percent may result in premature ageing and failure of insulation so that the time lag !:..characteristic of the device is of vital importance in permitting the normal starting duty and /:pmviding close sustained overload protection for the motor at the same time. C::, 1. :.STARTISTALL PROTECTION t.

t :A Direct-On-Line machine (DOL) will typically draw a starting current of approximately 6 times \full load current for a period defined by the machines starting time. This is because the :impedance of the machine is related to the slip frequency, which varies during start up; the :impedance beirlg smaller at low speeds where the slip is larger.

With normal 3-phase supply, should a motor stall when running, or be unable to start due to excessive load, it will draw a current equivalent to the locked rotor current. On the basis of starting current being equal to locked rotor current it is not possible to distinguish between 3-phase stalling and healthy starting by monitoring the current alone.

In the majority of cases, the starting time of a normal induction motor is less than the maximum stalling. time allowable to avoid excessive deterioration of the motor insulation.. Under this. . ' ..

condition it is possible to discriminate on a tim.e basis between the two and provide' protection against. stalling. In applications where the stalling time is less than the startingtime 'such' as motors driving high inertia loads, it is more difficult to discriminate between a healthy start and a stall condition. A separate stalling relay may be required depending on the type of overload xotection relay used and the ratio of normal starting time to the allowable stall time.

The following conditions may be examined

lssume startrng current = stall current

ST = maximum starting time ~ S L = niaximum allowable stall time

Thermal relay operating time at the same current level < t , ~ but

In this case the thermal relay can 1s

Protect the motor against 3-phase stall, no separate stalling relay is required.

ii) Thermal relay operating time at the same current level > t , ~ and

A . , Thermal ST

In this case no stalling protection is provided by the thermal - - - - - - - - - - overload relay even though the stall time is greater than the '1 ---------I . , b i starting time. A separate stalling relay is required. If the difference

:?, between tsL and t s ~ is adequate to cater for relay errors a simple . . . ,

single phase definite time over- I current relay may be used. . . ..

Is current setting < locked rotor current hut > load current ....

ts time setting < t s ~ but > t s ~

overcurrent

. . .

I Motor starting cilaracteristic

1

- a a ..z<

'TRIP -:L

OIC = overcurrent 4 . .. * a TD = time delay . .i .

86 = trip relay ..:, 5~ ..*

I :??

IS tsL > TD > tsT d. .,. .* . ~ . 4

'3

i; '<

In this case a separate stalling relay in the form of a definite time over-current relay and a shaft . ,2

monitoring device are required. The latter is used to check the motor speed while the relay j-e

measures the motor current. Instead of the overcurrent relay a simple definite time delay relay - may also be used as shown below : - . .

Page 4

Use of a tachoswitch monitor with a definite time delay relay:-

TD < tSL + -

o o TD The tacho contact will open when the set speed (say 10% of rated speed) is reached. It m x t operate well within TD.

MSD = Motor switching device i

I auxiliary contact, closed I when the motor is

: . -43- switched on. , ! '

TRIP

. - :. ii) i

Use of a tachoswitch monitor with a definite time overcurrent relay:- F.i!i! This offers more reliabil~ty

TD < tsL

OIC < stall current, > load current

-0-OcF- -

TRl P

iii) Use of a 2-stage definite time overcurrent relay:-

TDI > t s ~ TD2 < t s ~ OIC < stall current

> load current

-10- - TRIP

Page 5

No protection during motor starting period. TDI is continuously energised when the motor is in operation.

. .

If tsL > tsT the same arrangement can be used in which case stalling protection is provided during the starting period. This method provides additional advantage for motors with different ' hot and cold stall times in that TD2 cah be set to less than hot stall time irrespective of cold stall :, time.

TD1 ' ST

(TD1 + TD2) < tsL (cold)

OPERATION ON UNBALANCE SUPPLY

The supply voltage to a 3-phase induction motor can become unbalanced due to such reasons as single phase load, imperfect transportation of feeders etc. The degree of unbalance is small in normal installation except when onephase become ope'n circuited. This would not affect at first sight, the motor to any large extent, but a small voltage unbalance could produce a much larger negative phase sequence current in the winding due to the relative small negative phase sequence impedance of the machine compared with the positive phase sequence impedance. Consider the following equivalent circuits for positive and negative phase sequence currents, the magnetising impedance being neglected:

. . . - . . . ..... . .,: & ,? ..- . -

, . :,: ..,. - . . , - ..<< . . . .. . /_--

. . . -. ;s, .L. . . .... . l.. j.

- - '5.

. .7c . - :.<-

I-S -R'2 S

R'2 ' ' .

With positive phase sequence voltages a rotating field will be set up and the rotor will rotate in the direction of rotation of the filed giving a slip s and slip frequency sf. With negative phase sequence voltages the field will rotate in the opposite direction cutting a rotating rotor conductor at almost twice the frequency. The actual frequency of negative phase sequence voltage and current in the rotor circuit is (2 - s)f. From the equivalent circuits:

Motor +ve sequence impedance at a given slip s

= [ ( R ~ + R ' ~ ) + (XI + X', )~j" when s = 1 at standstill.

, Page 6

Motor -ve sequence impedance at a given slip s

- ~ ' 2 2 1

, ~ ' 2 2

(R, + + (x, + l2 when s << 1 at normal running speed i 1" I

L J

L

!

The value of resistance is generally much less than the leakage reactance. Therefore j neglecting the resistance term the motor -ve phase sequence impedance at normal running : speed can be approximated to the +ve phase sequence impedance at standstill. i.:

; . ~ t normal running speed : i' .

+ve sequence impedance starting current - - -ve sequence impedance normal load current

If a motor has a starting current 6 x the full load current, the -ve sequence impedance would be about 116'~ of the +ve sequence impedance.

Therefore if 1 pu +ve sequence voltage applied to the motor would produce 1 pu of +ve ;.;..sequence current, the same 1 pu of -ve sequence voltage would produce 6 pu - ve sequence !::.'current. Consequently, if there is 5% -ve sequence voltage present in the supply it would result I.-- .'

. . :z:;in-an . approximate 30% of -ve sequence component of current. ~. -

. . .

'The ac resistance of the rotor conductor to the induced -ve sequence current is greater than the dc resistance due to the higher frequency [(Z-s)fl causing skin effect. The heating effect of -ve sequence current is therefore greater and increases the motor losses. The machine output must be reduced to avoid overheating.

Because of the reversed rotation of the magnetic field due to -ve sequence current, a small -ve torque is also produced.

As mentioned previously one unit of -ve phase sequence current has a greater heating effect than one unit of +ve phase sequence current, this unequal heating effect should be taken into account in the design of a thermal characteristic based on:

I equivalent = JF"17 where 11 = +ve sequence component

12 = -ve sequence component N = a fixed constant

A typical value of n in motor protection relays is 6. This value has been carefully chosen to provide adequate protection to both the stator and rotor windings for all designs of motor without causing nuisance tripping.

I . Page 7 . . .- . _ . -_ . . . . . . . . . . . . - . . . .

.. .

LOSS OF ONE PHASE WHILE STARTING

J Assume a balanced 3-phase supply:

Normal starting current IA 2 (VnN.Z)/2 = Standstill impedance per phase of the motor

With one phase open-circuited ssy

C phase :

i.e, Starting current with one phase open circuited = 0.866 x normal starting current.

Page 8

1 i.e. + ve sequence current = - normal starting current.

2 1 2

Similarly, I 2 = - ( I tA + a IaB ) 3

normal starting current. ,..; ..-

.'--. For delta-connected winding motors the actual line starting current with one phase open circuit iZ., e:. is the same as a wye-connected machine : Ir : :.

1 For delta-connected winding motors the ii;. actual line starting current with one 7 ;. ? : . . . . . . phase .. open circuit is the same as a 5;-bye-connected machine:- I<..: < - . f : - V AS i . Normal starting current = ,fi x - I . z

VAB i Actual starting current = --

21122

- A- - -- x normal starting current 2

= 0.866 x normal starting current

Note that one winding will carry twice the current in the other two windings

! ; Page 9 t

SINGLE PHASE STALLl'NG PROTECTION

On loss of one phase supply while starting the motor will remain stationary.. It has been sho the motor will draw a current equal to 0.866 x the normal starting current. Therefore, if measuring the total stator current is used it must have a time delay longer than the starting ti of the motor. I f the allowable stall time at that level of current is less than the starting ti simi!ar arr=lr?gements as in the case of 3-phase stalling protection have to be used.

However, it has also been shown that the negative phase sequence component present in current is equal to half the normal starting current. A negative phase sequence curren can therefore detect this condition. In the CTM relay an instantaneous negative sequence current detector is fitted. It has a setting of 2-8 x rated current. If a setting of normal starting current the relay will detect single phase stalling condition.

LOSS OF ONE PHASE WHILE RUNNING

It is difficult to shown in simple mathematical terms the behaviour o f the motor when one ph supply is lost with the motor running due to the complex nature of the s l i ~ calculation and possibility of additional negative phase sequence current being fed into the motor from par equipment. However, the following would happen:

i) Heating increases considerably due to high rotor losses caused by the -ve s current

ii) Output of motor is reduced and depending on the load it could stall altogether. , .

- ... . . . . .. .. .

iii) Motor current increases..

REVERSED PHASE SEQUENCE STARTING

Ir: many installations such as lift motors and conveyors, protection is occasionally requ ensure correct direction of rotation. Although not damaging to the motor this can be detri to the process.

Under reversed phase sequence conditions the relay is designed to respond to the ex negative phase sequence component of current. A number of methods can be disconnect the motor from the supply during this condition

Instantaneous Negative Sequence Overcurrent Relay - This will respond very quic load current is sufficient on the system. Time Delayed Thermal Trip - As mentioned previous the thermal overload prot influenced by the negative phase sequence component of the current, this elemen more benificial for smaller loads. . . ,.

..:.;:$ .+ I. : .. . .."

The disadvantage of the above methods is that in order for them to operate the motor must be:; switched on, dpending on the inertia of the motor it may start to turn in the wrong direction.

, this is unacceptable then a negative phase sequence voltage monitoring device can be used- *.

This device will monitor the phase rotation of the incoming supply to the motor and if interlocked.: with the motor switching device will prevent closure onto a revese phase sequence supply. his': ,z approach is also used when the motor can only draw very low load currents.

Page 70

- - -

)LOW VOLTAGE PROTECTION -

P A; !for induction motor the torq;e developed is approximately proportional to the square of the Tapplied voltage. Low voltage level prevents motors from reaching rated speed on starting or 'may draw heavy current on losing speed. Some form of undervoltage protection is therefore desirable with suitable time delay to disconnect the motors when severe low voltage conditions

tpersist for more than a few seconds. The time delay is required to prevent tripping on ' momentary voltage dips

I INSULATION FAILURE

.The majority of stator winding faults are the result of prolonged or cyclical overheating which causes the insulation to deteriorate. Most faults are cleared by instantaneous earth fault protection as the windings are generally surrounded by earthed metal. Sensitivity of the earth fault relay is limited by the spill current from residually connected CTs during starting, usually 20%.

' Most other faults are cleared by thermal or unbalance protection. Instantaneous overcurknt units if fitted protect only against terminal flashovers and other heavy short circuits. This is because of the high settings necessary to prevent maloperation on starting current surges. For motors above say 1MW differential protection may be used to give high speed clearance of phase and earth faults. This usually takes the form of high impedance differential or biased differential. 6 current transformers are required with 2 per phase at the two ends of winding.

.. . -. . ,;:.

:',SELF . .. BALANCE TYPE DIFFEREN'TIAL PROTECTION ( r . . .

I

4 1 I I I i

f b I I 1

1

A - -

An alternative is to use self balance type different~al protection arrangement Using instantaneous current relays.

shown above

' , If conductors are placed reasonably bncentric w~thin the window of the core balance current ;: transformers, spill current can be kept to a minimum. W~th this low spill current and a ~ - . . - 1 ,

Page 11

reasonably indepenaence of CT ratio to full load a lower fault setting could be achieved than:. conventional high impedance circulating current differential schemes.

Disadvantages : .,;q .3

i) the necessity of passing both ends of each phase winding through the CT and hence the -I, need for extra cabling on the neutral end. .; $ 3~

I -'q ii) to avoid long cabling position of CTs are restricted to the proximity of the machine output :+F

terminals in which case the cable between the machine output terminals and controlling '.

switchgear might not be included within the differential zone. . .

. .:.

..;i OPERATION WITH FUSED CONTACTORS j:

. -.. -r.

Where the motor is switched via a fused contactor, the interrupting capacity of the contactor ':,: must be taken into consideration. In general they will not be rated to break the maximum fault ::. current. In this case it is important to prevent the protection attempting to operate the contactor '% above its maximum rating. This is usually achieved by disabling all instantaneous tripping .'.

T* 3 elements and time co-ordinating with the associated fuije. This is illustrated in the following .?

,. j

diagram: ..a.

- .. .

TIME

Ts . MPR I I ELEMENT I I

I T Ice CURRENT

Ts > Tfuse at Icont. -

Page 12

RING FAILURE PROTECTION

ings can suffer from both electrical and mechanical failure:

rical Interference - can result in an induced voliage and corresponding circulating aring, it is important to take precautions against this, for example adequate

ng of equipment. -

anical Failure - results in increased friction, generating heatirig and eventually failure of

f bearings are detailed below:

this type of bearing will cause the motor to come to a standstill' immediately. The motor will draw a heavy current equivalent to the locked rotor ;'' current. There is very little change that a relay monitoring the motor current can detect

. - bearing failure of this type before the bearing is destroyed. However, it is essential to disconnect the motor before excessive winding damage. This may be covered in the form of stalling protection.

ii) Sleeve Bearings

Failure of this type of bearing is a very occurrence. If it occurs it will be indicated by rature rise, vibration and increase in motor current in the order ~f 10% to20%.prior.

. . . .

It is generally accepted that the bearing will need replacing following failure, however stall protection will help niinimise damage to the motor itself. Unfortunately, in extreme cases this .is not the case and distortion of the shaft may occur. One method used to prevent this is direct temperature monitoring of the bearings using RTD's for example.

1 SYNCHRONOUS MOTORS

3 Out-Of-Step Protection

1 A synchronous motor decelerates and falls out of step when it is subjected to a mechanical overload exceeding its maximum available output. It may also lose synchronism from a fall'in field current or supply voltage. An out-of-step condition will subject the motor to undesirable Overcurrent and pulsating torque leading to eventual stalling.

I Two methods are available to detect out-of-step condition in a synchronous motor:

1 i) Field Current Method

The alternating component of current induced in the field circuit when the motor falls out of step provides the basis for this method. One arrangement is to connect a reactor in series with the field circuit to divert alternating current to a polarised field-frequency relay, a coil of which is connected in parallel with the reactor.

Disadvantages :

a) difficult to discriminate between alternating current induced by pole slip and induced by'faults on the supply system or sudden swing of load.

b) certain faults introduce harmonics, in particular second harmonic alternating cu in the filed circuit.

Power Factor Method .

This method makes use of the change of power facto that occurs when, the motor poles. When the motor loses synchronism a heavy current at a very low power fac drawn from the supply.

Av -

r 1'

... "ti:

- - Stator current on :.;$ . ., . :,+5

loss of synchronism -.q .;I<" ::+* -.* .. '-32

i*

..t

Protection Against Sudden Restoration Of Supply . -.;;+

-. : .- .!,<> On loss of supply a synchronous motor- should be disconnected if the'supply couldbe restoied:;+ automatically or restored without knowledge of the machine operator. This is to .avoid the..$

. .. , .- ..-..

possibility of the supply beingarestored out of phase with the motor generated emf. - ..,.,- : ,+ 3 'I \

Q

Two ways of detecting loss of supply : -8 -:*? -.I - - ." .. ... :?:

i) Overvoltaqe and Underfrequency

If the supply busbars have no other load connected and the motor is not loaded the motor,;; terminal voltage could rise instantaneously to 20-30% on loss of supply due to the open ii: circuit regulation of the machine. If the motor is loaded it will decelerate fairly quickly on : loss of supply and the frequency of terminal voltage will fall. . ‘ ,

ii) Underpower and Reverse Power

Applicable when power reversals do not occur under normal operating conditions. . .

. .

Underpower - arranged to look into the machine; applicable when there is a possibility of no load connected on loss of supply.

Reverse power - arranged'to look away from the machine; applicable where there is always load connected.

Time delay is required to overcome momentary power reversal due to faults etc.

f ;3' I!::'

A . ~

- Page 14

A C Motor Protection

A. C. Motor Protection . , . \ . . . . '>;: , . . . . , ! i .

There are a wide range of a.c. motors and motor i::.<&>r,

characteristics i n existence, because o f the numerous gi;$p . ... ... . + .

duties for which they are used. All motors need ...;:.j.,-2' :;:A,,.-& \?;;.p:..:

protection, bu t fortunately, the more fundamental . ,<...,-'":' . . ,. ',

-problems affect ing the choice of protect ion are . " . .. . . . .; . - independent o f the type o f motor and the type o f load t o : ~ ~ ~ ~ ~ ? , Y ~ ; ~ ~ ' ~ : I ; ... .: which it is connected. There are some important :*.;;:.:' , A < -

< : . . . . . . differences between the protection o f induction motors ' " ' .-.'.

and synchronous motors, and these are'fully dealt w i th i n the appropriate section.

Motor characteristics must be carefully considered when applying protection; while this may be regarded as stating the obvious, it is emphasised because it applies more t o motors than to other items o f power system

. . plant. For example, the start ing and ,s ta l l ing . , , - . , ..

currents/times must be known when applying.overload. ?':.-.I.-;.--'.,-. : - '

protection, and furthermore the thermal'withstand o f ".' '- i . . . 1

the machine under, balanced and unbalanced loading -1.' - ' . ++ . - must be clearly defined. I

! The conditions for which motor protection is required can be divided into t w o broad categories: imposed external conditions and internal faults. Table 19.1 provides details of all likely faults that require protection.

<- -- - -- -. . - -- -- Extcmal Faults , In:crnal faults

Unbalanced rupplics , Bcating failurcs

! Undcrwltagcs ! Winding faults

Singlc phasing Overloads

Rcvcnc phasc wgucncc I . j !- --.

The design of a modern motor protection relay must be adequate t o cater for the protection needs of any one of the vast range of motor designs in service, many of the designs having no permissible allowance for overloads. A relay offering comprehensive protection wi l l have the following set o f features:

a. thermal protection

b. extended start protection

c. stalling protection

d. number o f starts l imitat ion heat a t a rate proportional to temperature rise. This is :;

e. short circuit protection the principle behind the 'thermal replica' motor used for overload protection.

f. earth fault protection The temperature T a t any instant i s given by:

g. winding RTD measurementltr ip T = T,,,,,, ( 1 - e-fk)

h. negative sequence current detection where: i. undervoltage protection T,,,, = final steady state temperature

j. loss-of-load protection s = heating time constant

k. out-of-step protection Temperature rise is proportional t o t he curre

I. loss of supply protection T = ~i ( 1 - e-'I7 1 m. auxiliary supply supervision where:

(items k and I apply to synchronous motors only) IR = current which, i f f lowing continuously, pr temperature T,,,,, i n the motor I n addition, relays may offcr options such i s circuit

breaker condition monitoring i s an aid t o maintenance. ~ t , ~ ~ ~ f ~ ~ ~ , it can be shown that, for any overload Manufacturers may 3lso offer relays that implement a 1 , the tirne t for this current to flow is: reduced functionality t o that given above where less comprehensive protection is warranted [e.g. induction motors o f low rating).

t x l o I [ ( I The following sections examine each o f the possible 7 - (I,? 11) ] failure modes of a motor and discuss how protection may be applied t o detect t ha t mode. - In general. the supply to which a motor is connec - -

Q contain bo th positive and negat ive'- s - C .. . . _; . ? . i . . , . . - .' . . . , . . . - . . . . .... .. . . . . components, and both compbnents o f c l rrrentgi

b heating in thr motor. Therefore,. the, the!m . u: - . The majority of winding failures are either indirectly or should take into account both of these Q. L directly caused by overloading [either prolonged or typical equation for the equivalent current being:

cyclic), operation on unbalanctd supply voltage, or single phasing, which a l l lead through excessive heating t o the

lcq = - deterioration of the winding insulation unt i l an electrical 3 fau l t occurs. The generally accepted rule is that where -.

insulat ion l i fe is halved for each 10" C rise i n I , = po5irive sequence current 2 tercperature above the rated value, modified by the

rr , length of t ime spent a t the higher temperature. As an I 2 = negative sequence ,current

electrical machine has a relatively large heat storage 2nd capacity, it follows that infrequent overloads of short

negative sequence rotor resistance . 19 - durat ion may n o t adversely a f fec t t he machine. ,q= positive sequence rotor resistance However, sustained overloads o f only 'a' few percent may

- result i n premature ageing and insulation failure. at rated spced. A typical value o f K is 3.

Furthermore, the thermal withstand capability of the motor is affected by heating i n the winding prior to a Finally, the thermal replica model needs to take in to

faul t . It is therefore impor tant that the relay account the iact that the motor wil l tend t o cool down characteristic takes account o f the extremes o f zero and during periods of light load, and the in i t ia l state of the full- load pre-fault current known respectively as the motor. The rllotor wil l have a cooling time constant, T,. 'Cold' and 'Hot' conditions. - that defines the rate of cooling. Hence, the final thermal

model can bc expressed as: The variety o f motor designs, diverse applications, variety o f possible abnormal operating conditions and resulting , = T 0 [ k 2 - A j 2 - 7 [,7* ,.,,(." ; . j , modes o f failure result i n a complex thermal relationship. A generic mathematical model that is accurate is therefore impossible to create. However. i t is possible to develop an approximate model if it is assumed that the motor is a homogeneous body. creating and dissipating

8 -. . .-.. , . -, .. ~ . . . ,?,.; -. - . . ,. A;. J J 8 . \ . , ~ . o r h P r . ( r . t i o . V A W I . - . , ; . ~ C ‘ i l r _ ...; . > &,.' . .~ I.:;. - ,>...'. .? ,:-'.-. .... . ...:<c.&

:, f i ... '' *; >, .. . :. -,-+,.:.+.-, . 4-

. . .

,

10:42 Page 339

-: 9,.{ START!ST,?[.L >R! lTCC- fO? ; .... . . . ,_ . : . . . = heating t ime c o ~ i s t a ~ t t When a motor is started, i t draws a current well in excess

. . . . .: . . . . . of ful l load rating throughobt the period that the motor . - > . . . . . takes to run-up to speed. While the motor starting . . . ,:<ri.

r; . . . . . . . . .

. . . . . . Ciiiient iedijces somewhat as motor speed increases, i t is normal in protection practice to assume that the motor i a l stare of rr~oror [cold o r /lor) current remains constant throughout the starting period!. . . . .

?la/ setr iug c l t r rent :. . . . . . The starting current will vary depending on the design of \ . . into account the 'cold' and 'hot' the motor and method of starting. For motors started , . . . . . . .

d in IEC 60255, part 8. - . . . . . . . DOL (direct-on-line], the nominal starting current can be . .

ays may use a dual slope characteristic for the 4-8 times full-load current. However, when a star-delta

time and hence values the starter is used, the line current will only be 7 / f i o f the &time constant are required. Switching between DOL starting current. "' values takes place at a pre-defined motor

may. be used to obtain better tripping Should a motor stall whilst running. or fail to start, due .. . . .

knee during starting on motors that use a star- to excessive loading, the motor will draw a current equal '<-+.. . .

rjtarterA ~~~i~~ starting, the motor windings cam/ to its' locked rotor current. It is not therefore possible to .+ :'

E; current, while in the condition, they carry distinguish between a stall condition and a healthy start . :.

:m of the current seen by the relay. similarly, solely on the basis of the current drawn. Discrimination I , ~e motor is disconnected from the supply, the between the two conditions must be made based on the

i;g time constant is set equal to the cooling time duration of the current drawn. For motors where the starting time is less than the safe stall time o f the motor.

iant TI- protection is easy to arrange.

f the relay should ideally be matched to the dd motor be capable of close sustained However, where motors are used to drive high inertia

&j protection, a wide range of relay adjustment is loads, the stall withstand time can be less than the . - - . . . . .

+!e with good accuracy and low thermal starting time. In these cases, an additional means must .:. iZ--:. . . . . ;., . . .

fikt" be provided to enable discrimination between the two ' '- 2; U . - - - . - 1 ' - . . . ....

=. - conditions to be achieved. -- .L1 .,. a ... ' . I ..

i i je lay setting curves are i h o w n in Figure 19.1. 'i' L 2. .

CL ! - . . . .: . . - . m . .

. . 0

A motor may fail to accelerate from rest for a number o f 2 . . . . - . . reasons: b c= CQ . . . . loss of a supply phase 6 . . . . . . . . . . . . . . . . . . . . . . . . .

: . . . . . . . . . . . . . . . . . . . . . . mechanical problems h \

. . low supply voltage

excessive load torque 19 - etc.

A large current will be drawn from the supply, and cause extremely high temperatures to be generated within the

....... ...... motor. This is made worse by the fact that the motor is

not rotating, and hence no cooling due to rotation is ... ...- .. available. Winding damage will occur very quickly -

! ........ i either to the stator or rotor windings depending on the :-- ............... ............

thermal limitations of the particular design (motors are - z . ' .

1: -.. . . . . . . . . . . . . . said to be stator or rotor limited i n this respect). The :

. . - . - . . . . . . .-... . . . . method of protection varies depending on whether the : '.-:. '.

. . 4 . ' . . . . . . . . . . . . . . . . . ..I , ; . starting time is less than or greater than the safe stall ..-.I , . , - . . . . . . . . . - . . - . . - . . - . ., ......, _ . . . . . . time. In both cases, initiation of the start may be sensed

0. I 10 by detection of the closure of the switch in the motor Thcrnnal cquivalcnl current I in term5 of thc currcnl feeder (contactor or CB) and optionally current rising . .

- -. . thermal lhrcrhold I , > above a starting current threshold value - typically . ' ., 4 * .. . .

: ?I

9. :' TI:,.?!,-,,! <#..,.;I,,'.: :.,,<;,,,: !: * .: < <.u.r;<.> . . - r ,> / , j~ , ,~ . . , .~ :~,, ,- .3; s~T:c!!::: . . . . . . . . .

. . : -.:", .; . / .

.. ... . . . - - - --. - -- .-- . . . . . . . . - ... . -> . . , - : , p' . . . . . . 'ra.4 ~ ~ . r . ~ r , . . u ~ . r . ~ a r i . r n G - i l * - - J J O - - ..... . . - . . . . . . ' '-

, . . . ' / '

-8 , : . :.

. . .

. P '

. . .': <

. - . . . , : i i:;.',

-351 20/06/02 10-42 Page 340

"( i. '-.?

successful start is used to select relay timer used for the safe run up time. This time can be longer than the safe :! stall tjme, as there is both a (small) decrease in current 2; drawn by the motor during the start and the rotor fans ':;

begin to improve cooling of the machine as i t :;.,* accelerates. I f a start is sensed by the relay through monitoring current and/or start device closure, but the . :S$ speed switch does not operate, the relay element uses ...:::$ the safe stall time setting to trip the motor before :;: damage can occur. Figure 19.3(a) illustrates the principle i$J of operation for a successful start. and Figure 19.3(b) for . :$ an unsuccessful start. ~t ..*a

'I 36

200% of motor rated current. For the case of both conditions being sensed, they may have to occur within a narrow aperture of time for a start to be recognised.

.---a,., ~ ~ c L ; a ! requirements may exist for certain types of < motors installed in hazardous areas (e.g. motors with type o f protection EEx 'e') and the setting of the relay must take these into account. Sometimes a permissive interlock for machine pressurisation (on EEx 'p' machines) may be required, and this can be conveniently achieved by use of a relay digital input and the in-built logic capabilities. .

Protection is achieved by use of a definite time overcurrent characteristic, the current setting being greater than full load current but less than the starting current of the machine. The time setting should be a l i t t le longer than the start time, but less than the permitted safe .starting time of the motor. Figure 19.2 illustrates the principle of operation for a successful start.

CB Closcd ...............

Timc

Currcnt :

Spccd rime Swctch I

............ Information O t

- - T;m. .,.,,. .. Trip 3 1

.*:> ..: :..- ,..B Command oi . .A,< I I-' ....

(a] Successful start :.& '3, ... .-. qfi-

Ce Closcd " 1 o ---J .. . - r - -

Currcnt oI..... . _ ......... .., Spccd , i ; Switch .. ,

Information '; , , ~i~~ >,a>, ,>,>*C

Trip 1. ' .. .:-.=a

. : L rcnms

.r .p.?; ....-L.,4 .

Command o' -- Time .-?Av,. . .-,, . ibl Unrucccssful start

..:?Pi . ~ .*.,

Should a motor stall when running or be unable to start? because of excessive load, it will draw a current from the i3 : supply equivalent to the locked rotor current. I t is:3;g; obviously desirable to avoid damage by disconnecting %$$d .:w the machine as quickly as possible i f this condition4@$ arises. &,$ .,,+Y,

-L$@$!

Motor stalling can be recognised by the motor current:;@$ exceeding the start current threshold after a successful^:$$;

, . . . . . I .:. . . i : . . 1 10

Currcnt (p.u. I start - i.e. a motor start has been detected and the motor:+$?' current has dropped below the start current threshold,::-% within the motor safe start time. A subsequrnt r i a in$ ...,:$ motor current above the motor starting current:i;i?; threshold is then indicative of a stall condition, and,,'@ tripping will occur i f this condition persists for than the setting of the stall timer. An instantaneou~;i$:' .+. - J: overcurrent relay element provides protection. :iy,t.?. :,?a?

For this condition, a definite time overcurrent characteristic by itself is not sufficient, since the time delay required is longer than the maximum time that the motor can be allowed to carry starting current safely. An additional means of detection of rotor movement, indicating a safe start, is required. A speed-sensing switch usually provides this function. Detection of a

'-a In many systems, transient supply voltage loss (typical!Y;$ up to 2 secmdr) does not rerult in tripping of designate<& motors. They are allowed to re-accelerate upon@ restoration of the supply. During re-acceleration, the%? ..&$

. .

.................................................. ...... --- ..... . . . . . . ............

I: * :

!T. S t a a lockout A . . . i ; > .

.............. .- . lime Inhib. start time

3 :3 9 r draw a current similar t o the starting current for a period : that may be several seconds. It is thus above the motor : stall relay element cur rent threshold. The stal l

protection would be expected to operate and defeat the ?bject of the re-acceleration scheme.

motor protection relay w i l l therefore recognise the 'resence o f a voltage dip and recovery. and inhibi t stall lrotection for a defined period. The undervoltage, 'rotection element (Section 19.11) can be used to detect he presence o f the voltage dip and inh ib i t stal l 'rotection for a set period after voltage recovery. 'rotection against stalled motors i n case of an nsuccessful re-acceleration is therefore maintained.

he t ime delay se t t ing is dependent o n the re- c~elerat ion scheme adopted and the characteristics o f ldividual motors. I t should be established after Vforming a transient stabi l i ty study for the re- Seleration scheme proposed.

. . . . , ..;:,,?fit,,.. :>1 :>:;:,:I. i ,!".: . ...

Any motor has a restriction on the number of starts that are allowed i n a defined period wi thout the permitted winding, etc. temperatures being exceeded. Starting should be blocked if the permitted number o f starts is exceeded. The situation is complicated by the fact the number o f permitted 'hot' starts i n a given period is less than the number o f 'cold' starts, due t o the differing init ial temperatures o f the motor. The relay must maintain a separate count o f 'cold' and 'hot' starts. By making use o f the data held i n the motor thermal replica, 'hot' and 'cold' starts can be distinguished.

To allow the motor to cool down between starts, a t ime delay may be specified between consecutive starts (again distinguishing between 'hot' and 'cold' starts). The start inhibit is released after a time determined by the motor specification. The overall protection function is i lhstrated in Figure 19.4.

Cha ~ ~ 1 9 - 3 3 6 - 3 5 1 20/06/02 10:42 Page 3 4 2

Motor short-circuit protection is often provided t o cater for major stator winding faults and terminal flashovers. Because of the relatively greater amount o f insulation between phase windings, faults between phases seldom occur. As the stator windings are completely enclosed in grounded metal, the fault would very quickly involve earth, which would then operate the instantaneous earth fault protection. A single definite t ime overcurrent relay element is all that is required for this purpose, set to about 125% of motor starting current. The time delay is required to prevent spurious operation due to CT spill currents, and is typically set at looms. I f the motor is fed from a fused contactor, co-ordination is required with the fuse, and this will probably involve use o f a long time delay for the relay element. Since the object of the protection is to provide rapid fault clearance to minimise damage caused by the fault, the protection is effectively worthless in these circumstances. It is therefore only provided on motors fed via circuit breakers.

Differential (unit) protection may be provided on larger HV motors fed via circuit breakers to protect against phase- phase and phase-earth faults, particularly where the power system is resistance-earthed. Damage to the motor in case of a fault occurring is minimised, as the differential protection can be made quite sensitive and hence detects faults in their early stages. The normal definite time overcurrent protection would not be sufficiently sensitive, and sensitive earth fault protection may not be provided. The user may wish to avoid the detailed calculations required of capacitance current in order to set sensitive non-directional earth fault overcurrent protection correctly on HV systems (Chapter 9) or there may be no provision for a VT to allow application of directional sensitive earth fault protection. here is still a lower limit to the setting that can be applied, due to spill currents from CT saturation during starting. while on some motors. neutral current has been found t o flow during starting. even with balanced supply voltages. that would cause the differential protection to operate. For details on the application of differential protection, refer to Chapter 10. However, non-directional earth fault overcurrent protection will normally be cheaper in cases where adequate sensitivity can be provided.

One o f the most common faults to occur on a motor is a stator winding fault. Whatever the initial form of the fault (phase-phase, etc.) or the cause (cyclic overheating, etc.), the presence of the surrounding metallic frame and casing will ensure that i t rapidly develops into a fault involving earth. Therefore. provision of earth fault protection is very important. The type andscnsitivity of protection provided depeAds largely' on the system earthing, so the various types will be dealt with in turn.

I t is common, however, to provide both instantaneous and time-delayed relay elements to cater for major and ,:,- slowly developing faults. ..:$ .;d

'%xi

, ... :. . . . . . . . , ; I:!'; ;, , , . . :.. ... E < - . . - . . z ....... ; " i

Most LV systems fall into this category, for reasons of personnel safety. Two types o f earth fault protection are , . commonly found - depending on the sensitivity required.

For applications where a sensitivity of > 20% of motor continuous rated current is acceptable, conventional J earth fault protection using the residual CT connection .:$ of Figure 19.5 can be used. A lower l imit is imposed on :g the setting by possible load unbalance and/or (for HV - ,';$ systems) system capacitive currents.

. . $ r . 7

Uosrrcam ., 1.1

Flow of

c"'i'"r

Downsrrcam

Care must be taken to ensure that the relay does not operate from the spill current resulting from unequal CT saturation during motor starting, where the high currents involved will almost certainly saturate the motor CT's. I t is common to use a stabilising resistor i n series with the relay, with the value being calculated using the formula:

.r.-..

where: . .,,<,;+ 5.B

I,, = starting current referred to CT secondary . ,:G$

I,, = relay earth fault setting (A) ;::# L ,.

Rslah = stabilising resistor value (ohms]

R,, = d.c. resistance of CT secondary (ohms)

RI = CT single lead rcstistance (ohms)

Page 3 4 3

CT connection factor

L 1 for star p t at CT

2 for star p t a t relay)

relay input restistance

If a more sensitive relay setting is required, it is necessav to use a core-balance CT. This is a ring type CT. through which all phases of the supply t o the motor are passed, plus the neutral on a four-wire system. The turns ratio of the CT is no longer related to the normal line current expected t o flow, so can be chosen to optimise the pick- up current required. Magnetising current requirements are also reduced, with only a single CT core to be magnetised instead of three, thus enabling low settings to be used. Figure 19.7 illustrates the application of a core-balance CT, including the routing of the cable sheath to ensure correct operation in case of core-sheath cable faults.

(ohms)

ffect of the stabilising resistor is to increase the ive setting of the relay under these conditions, and delay tripping. When a stabilising resistor is used,

tripping characteristic should normally be ntaneous. An alternative technique, avoiding the use stabilising resistor is to use a definite time delay cteristic. The time delay used will normally have to und by trial and error, as it must be long enough to

ent maloperation during a motor start, but short gh to provide effective protection in case of afault. I Cablc gland

Cablc b o x . m, rdination with other devices must also be considered.

low the maximum system fault current - reliance is b c e d on the fuse ir, these circumstances. As a trip command from the reiay instructs the contactor to open. &re must be taken to ensure that this does not occur until

Cablc gland /sheath ground connection

the fuse has had time to operate. Figure 19.6(a] illustrates '$correct grading of i he relay with the fuse, the relay k r a t i n g first for a range of fault currents in excess of the nntactor breaking capacity. Figure 19.6(b) illustrates &ect grading. To achieve th~s, i t may require the use of ;liintentional definite :ime delay in The relay.

Timc . Furc : Contactor

8 brcaklng

: capacnty

4

, . , C / f rclay I .

.. ... i u r c : Contaclor ,,,,.: ; ! I ;. .....'., : ! . . . . . . . I ;,,:!.-.!.;,;,.~ r :';

: brcaking ' capacity

\ I

\; These are commonly found on HV systems, where the I,:.. . , . . . 7;

Current intention is to l imit damage caused by earth faults . . ,.:: . .

. . . .I :. , . . . . . ... (b) Correct - through limiting the earth fault current that can flow. I%:.! $ $,!

Two methods of resistance earthing are commonly used: ' .$.

.... , I : .- ::1.(. tnr;lrrq s!rc$:tv::,: b.vai . in!cr.:ro: . .

:. i , .. . . , @

! Chap19-336-351 20/06/02 10:46 Page 344

.'P i . .+.

. \ . ; : ~ : . . . . .. .. . . . - sensitivity that is possible using a simple non-directional 'i

In this method, the value of resistance is chosen to limit earth fault relay element is limited to three times the .:$

the fault current to a few hundred amps - values of steady-state charging current of the feeder. The setting i j ~ O O A - ~ O O A being typical. With a residual connection of shoild not be greater than about 30% of the minimum 'i line crs, the senjjliviti; pos;i';le is about !no/, earth fault current expected. Other than this, t he <,-.

of CT rated primary current, due to the possibility of CT considerations in respect of settings and time delays arc .# saturation during starting. For a core-balance CT, the as for solidly earthed systems.

, I \ ' I , I 1 * I T I

R Ogme HV systems, high resistance earthing is used t o &rt the earth fault current to a few amps. In this case, S;c system capacitive charging current will normally &vent conventional sensitive earth fault protection &ng applied, as the magnitude of the charging current i l l be comparable wi th the earth fault current i n the

of a fault. The solution is t o use a sensitive ircctional earth fault relay. A core balance CT isused in rnjunction wi th a VT measuring the residual voltage of he system, with a relay characteristic angle setting of 45' [see Chapter 9 for details). The VT must be suitable the relay and therefore the relay manufacturer should : consulted over suitable types - some relays require )at the VT must be able to carry residual flux and this lies out use-of a 3-limb. 3-phase VT. F,. setting o f 125% f the single phase capacitive charging current for the hole system is possible usins this method. The time :lay used is not critical but must be fast enough to sconnect equipment rapidly in the event of a second ~ r t h fault occurring immediately after the first. 'inimal damage is caused by the first fault, but the ,cond effectively removes the current l imi t ing sistance from the fault path leading to very large fault !rrents.

1 alternative technique using residual voltage detection also posible, and is described in the next section.

rth fault detection presents problems on these systems Ice no earth fault current flows for a single earth fault. lwever, detection is still essential as overvoltages occur sound phases and i t is necessary to locate and clear t fault before a second occurs. Two methods are ssible, detection of the resulting unbalance in system arging currents and residual overvoltage.

nsitive earth fault protection using a core-balance CT -equired for this scheme. The principle is that detailed Section 9.16.2, except that the voltage is phase shifted +go' instead of -90'. To illustrate this, Figure 19.8

)WS the current distribution in an Insulated system ljected to a C-phase to earth fault and Figure 19.9 the ay vector diagram for this condition. The residual -rent detected by the relay is the sum of the charging 'rents flowing in the healthy part of the system plus

healthy phase charging currents on the faulted der - i.e. three times the per phase charging current the healthy part of the system. A relay setting of 30% this value can be used to provide protection without : risk of a trip due to healthy system capacitive ~ rg i ng currents. As there is no earth fault current, it is o possible to set the relay at site after deliberately

-

applying earth faults a t various parts of the system and measuring the resulting residual currents.

If it is possible to set the relay to a value between the charging current on the feeder being protected and the charging current for the rest of the system, the directional facility is not required and the VT can be dispensed with.

The comments made in earlier sections on grading with fused contactors also apply.

A single earth fault results in a rise in the voltage between system neutral and earth, which may be detected by a relay measuring the residual voltage of the system (normally zero for a perfectly balanced, healthy system]. Thus, no CT's are required, and the technique may be useful where provision of an extensive number of core-balance CTs is impossible or difficult, due to physical constraints or on cost grounds. The VTs used must be suitable for the duty, thus 3-limb, 3-phase VTs are not suitable, and the relay usually has alarm and trip settings, each with adjustable time delays. The setting voltage must be calculated from knowledge of system earthing and impedances, an example for a resistance- earthed system is shown in Figure 19.10.

Grading of the relays must be carried out with care, as the residual voltage will be detected by all relays in the affected section of the system. Grading has to be carried out with this in mind, and will generally be on a time basis for providing alarms (1" stage), with a high set definite time trip second stage to provide backup.

dl.; .: ... ; .-, . . -. Z i . 2

I ' . ...

.- - --. . . N I I - . . ~ P r . r r < r i . . ff A . f . - . I i * n c s i r t \ . J 4 r r '

. ' ' 8

. ' t , ..

. . !L., . ,'4 . . . . , .

, . .'i . - . . . . . . .

. ... . ., ,

. . , . . : . .:. . . . . . . . . . . . - . . . . . . . .

, ' :, . . 'I.. . . ..:;fia -

. . . . . . . . . . . .. . - .... . . , .

.'.

tor positive sequence impedance at slip s - ' leading to' excessive heating. F o r the same motor, negative sequence voltages i n excess of 17% wil l result in a negative sequence current larger than rated fu l l load

rice, a t standstill (s=1.0), impedance Negative sequence current is at twice supply frequency. Skin effect in the rotor means that the heating effect in the rotor of a given negative sequence current is larger than the same positive sequence current. Thus, negative sequence current may result in rapid heating o f the motor. Larger motors are more susceptible i n this respect, as the rotor resistance of such machines tends t o be higher. Protection against negative sequence currents is therefore essential.

Modern motor protection relays have a negative sequence current measurement capability, in order to. provide such prote~tion. The level of negative sequence unbalance depends largely upon the type of fault. For

. . loss of a single phase at start, the negative sequence current will be 50010 of the normal starting current. It is . . .

suffix p indicates positive sequence quantities more diff~cult to provide an estimate of the negative ,..

sequence current i f loss of a phase occurs while running. This is because the impact on the motor may vary widely,

suffix 11 indicates negative sequence quantities from increased heating to stalling due to the reduced torque available.

A typical setting for negative sequence current rr: R , + R ; j ( X , + X;l o

protection must take into account the fact that the y;::i,..:c.:.-.. motor circuit protected by the relay may not be the f!::...': :..;

rf f -SJISI x R; ?ource of the negative 5equence current. Time s h ~ u \ d b e :- =% . : -+. allowed for the appropriate protection to clear -the -' .< .: 1:

,- source of the negative sequence current without ; introducing risk of overheating to the motor being considered. This indicates a two stage tripping o

K,+ R; j ( X , + X;/ % characteristic, similar in principle to overcurrent < protection. A low-set definite time-delay element can be used to provide an alarm, with an IDMT element used

u to trip the motor in the case of higher levels of negative seq"ence current, such as loss-of-phase conditions at start, occurring. Typical settings might be 20% o f CT rated primary current for the definite time element and ' 19 ' 50010 for the IDMT element. The IDMT time delay has to be chosen to protect.the motor while, if possible, grading

negative sequence relays on the system. s may not incorporate two ekments, in which ingle element should be set to protect the

speed is approximately equal to the positive sequence motor, with grading being a secondary consideration. reactance at standstill. An alternative more meaningful - ;. ...,. ':>:.' . way of expressing this is: . . ~ . .,,,... !. .

. . , ,,.,.: , : :., , 1 ', 1 ' . : . . ; ;;\; ,,:j';.. :'bi?~:;) . , :: . .:...,,;;.>; :;,. . ...

positive seq. impedance starting current .:.. .>*.,, ?::..: . . ,. ,+..;~:-..;..{.; :

- . . . negative seq. impedance rated current On wound rotor machines, some degree of protection p;.!:$>.j2;'?;;>::: ,..c,:.;~ ... ::,, ,.+?:

against faults in the rotor winding can be given by an ;<g';;::;: and i t is noted that a typical LV motor starting current is instantaneous stator current overcurrent relay element. i~~~~iz;,22;!$f~.: GxFLC. Therefore, a 50j0 negative sequence voltage (due As the starting current is normally limited by resistance '$$~ii~$t

'- 1 p. ~+P",P". to, say, unbalanced loads on the system) would produce to a maximum of twice full load, the instantaneous unit 5:??$?:,,;$;2: a 30010 negative sequence current in the machine, can safely be set to about three times full load i f a slight :,:!'6~!T!.~-:!~' , . ..,.. , . . . . . ' I . ,:;.,:;:;;;;.::;:'4 <.

. . . . . @. @

~ - . . . . .. . . . .. . .. . 3 4 7 . h f ~ f - . r l P , . r r r r ; . . C a i ' r \ ---. . . . . .~ ~- ..

; -1ap19-336-351 20/06/02 10:46 Page 348

. , .. ..:.c. ;. " . :.:.v.,, . .... <?,::~ .... " .,

i

.s ,..ha ;.?*+\.V": - ! :br,kga t ime delay o f approximately 3 0 milliseconds is ; ...;: +$:$.:&$. - . . , . . ++ .z ; incorporated. It should be noted that faults occurring i n :;.3:::*&:$; : .c~~,y~~::.i . . , . the rotor windinq would n o t be detected by any :::<!;>;$e:::.: . . d~fferential protection applied t o the stator. ;$;:?*;!@*-> . >*>.< x ...% $,.;?. ;**:..?&$

.......... <. ::: , >+:..5:.: .:..:~s@:.: .... RTD's are used t o measure temperatures o f motor ........ e:: . . , ..,

A\.. ',! :~. .:.:.*>:,: windings or shaft bearings. A rise i n temperature may

>,>, . denote overloading o f the machine, or the beginning of a fault in the affected part. A motor protection relay will therefore usually have the capability of accepting a number of RTD inputs and internal logic to initiate an alarm and/or trip when the temperature exceeds the appropriate setpoint(s). Occasionally, HV motors are fed via a unit transformer. and in the;e circumstances, some o f the motor protection relay RTD in.puts may be assigned to the transformer winding temperature RTD's. thus providing overtemperature protection for the transformer without the use o f a separate relay.

There are two types o f bearings to be considered: the

. . anti-friction bearing (ball or roller), used mainly on small 'a. . ' . . I .:. ,. motors (up to,.around 3 5 0 k ~ ) , and the sleeve bearing.

. .a. ?. .. L . ,.. . -used mainly on large motors: . - D ;.-:-:

The failure of ball or roller bearings usually occurs very quickly, causing the motor to come to a standstill as pieces of the damaged roller get entangled with the others. There is therefore very l itt le chance that any relay operating from the input current can detect Searing failures of this type before the bearing is completely destroyed. Therefore, protection is limited to disconnecting the stalled motor rapidly to avoid consequential damage. Refer to Section 19.2 on stall protection for details of suitable protection.

. . - . : +:;:: Failure of a sleeve bearing can be detected by means of

_ I . I ....... ,,i:.:i&-i.j;, a rise in bearing temperature. The normal thermal

.~ .. . . . . . . . ...+ . . . . . . . . . . . . overload relays cannot give protection to the bearing . . . . . ....... . .-I. .. -.r::Z-

itself but wil l operate to protect the motor from ...... , .<, . . , . . excessive damage. Use of RTD temperature detection, as ....

.... ;x: ..- noted in Section 19.9, can provide suitable protection. -. , .. -.,... . ... ... allowing investigation into the cause of the bearing a9,'.;' $7~.

running hot prior to complete-failure. r:.:,::::

a: - 1 %

p2 ;;.; :w:, Motors may stall when subjected t o prolonged F?: ,-,r, z.%r undervo!tage conditions. Transient undervoltages will >: ? ' ....... generally allow a motor to recover when the voltage is . . . .

. .

factors in mind.

failure in a mechanical transmission (e.g. conveyor belt), '

or i t can be used with synchronous motors to protect,

maloperation.

system transients. This is especially important for synchronous motor loss-of supply protection.

. .; , .. . . , . - . , \ l ! ; , ; < ; { \ . j ' 5 , ; t \ ; ; i ; . ; ; . ;

sections.

. . . . . . . . ~

~ .. ....

+

6 - 3 5 1 2 0 / 0 6 / 0 2 :C:46 Page 3 4 9 -

ied voltage to stator or field windings. Such a fall not need to be prolonged, a voltage dip o f a few nds may be all that is required. An out-of-step it ion causes the motor to draw excessive current generate a pulsating torque. Even if the cause is

oved promptly, the motor will probably not recover chronism, but eventually stall. Hence, it must be

m&iinecird from the supply. &. i q e current drawn during an out-of-step condition is a t 5 v e r y low power factor. Hence a' relay element that b o n d s t o low power factor can be used to provide

- The element must be inhibited during rting, when a similar low power factor condition

rs. This can conveniently be achieved by use of a !&finite time delay, set t o a value slightly in excess of the k.

otor start time. g n e power factor setting will vary depending on the rated tpwer factor of the motor. It would typically be 0.1 less fh& the motor rated power factor i.e. for a motor rated at 0.85 power factor, the setting would be 0.75. !.I . <

If the supply to a synchronous motor is interrupted, it a essential that the motor breaker be tripped as quickly 3s possible if there IS any possibil~ty o f the supply 3eing restored automatically or without the machine ~perator's knowledge.

his is necessary in order to prevent the supply being estored out of phase with the motor generated voltage.

'WO methods are generally used to d'etect this condition, I order to cover different operating modes of the motor.

he underfrequencv relay element will operate in the ase of the supply failing when the motor is on load, !hich causes the motor to decelerate quickly. Typically, NO elements are provided, for alarm and tr ip ldications. -

i e underfrequency setting value needs to consider the Iwer system characteristics. In some power systems. ngthy periods of operation at frequencies substantially :low normal occur, and should not result in a motor ip. The minimum safe operating frequency of the otor under load conditions must therefore be :termined, along with minimum system frequency.

is can be applied in conjunction wi th a time delay to feet a loss-of-supply condition when the motor may are a busbar with other loads. The motor may attcmpt supply the othcr loads with power from the stored

letic energy of rotation.

A low forward power relay can detect this condition. See- Section 19.12 for details. A time delay will be required to prevent operation during system transients leading t o momentary reverse power flow i n the motor.

.. - 19.14- MOTOR PROTECTION E X A M P L E S

This section gives examples o f the protection o f HV and LV induction motors.

Table 19.2 gives relevant parameters of a HV induction motor to be protected. Using a MiCOM P241 motor protection relay, the important protection settings are calculated in the following sections.

1 Ratcd Voltagc , 33kV j ,. ,-c

I i Ratcd frequency WHz ! j Ratcd powcr factorlcficicncy 0.9lO.92

j Stall withstand timc cuIdIhot ! 2017s i Slaning cumnt 5505 DOL

i Rrmincd starts culd/hot i 312 I

i CI ratio 250/1 4 .

! 5= start tirncal- ~ l t a g c I . 4s 0

. . 1 -< ..- - .--

Start tirnc@ f)(PYo+tagc , , . . .55s . . , .i . ., .. . . I ; ,.. *:: ...+'.'......

2 :~.}:;~-'f;;:;25,75~in. . . . . . . . . . . . . . . . . . .: . . . . . . . . 1. ji ,.;;.:.:;:. $1: ;:. ; ::+ . . . . . . .

. . . . . . . . . . .Solid < ! . .:y ..: .> ::. ; ::< .- . . . . . .

1 . ;.,&"tro,.(j,.& s:.. =.-:. . . . ..:..z. : . . . .:: j.; :.:: . . . - 0 .

. . . . . . . . . . . . . . . . . . . . . . . . . . -. ,. ~ii~ltBrcak&...' ." -1 . :.. . .% . . I i .q. --. -

U The current setting IT" is set equal to the motor full load . current, as it is a CMR rated motor. Motor full load + current can be calculated as 211A, therefore (in secondary quantities): - 1 9 .

Use a value of 0.85, nearest available setting

The relay has a parameter, K, to allow for the increased heating effect of negative sequence currents. In the absence of any specific information, use K=3.

Two thermal heating time constants are provided, r , and - . : : r,. r, is used for starting methods other than DOL, . . ,.. , .

otherwise it is set equal to r,. r , is set to the heating ,-., j.::,..: .:.::: time constant, hence r,=r2=25mins. Cooling time :::':?'.!f.?$::.

, \,p:,'. :. :-j- .' "" constant r, is set as a multiple'of r,. With a cooling time @;$i$zi&;;., constant of 75mins, $.:c;::; .... -!.";.::,;: .G>y. :,:: ., , . \-. - . . ..... , A><' . ..,.'.. .. . . . . . . r ,= 3 x r , ?.:?,;i.

. . . . . . . . . ' - :..:.: .:.. ......

. < :. , .

, , 47.. ,.

condition at starting. 19.1 .I..? Ptotcct iot i of ; a t ; S! r ~ i ~ , t < j :

In accordance with Section 19.7, use a ~e t t i ng o f 2O0I0

/ 02 1 0 : 4 6 P a g e 3 5 1

be carefully co-ordinated w i t h the fuse re t ha t the contactor does n o t at tempt t o break a i n excess of i t s rating. Table 19.3(a) gives details LV motor and associated fused contactor. A

M P 2 l l motor protection relay is used t o provide

where

I,, = motor rated primary current

Ip = CT primary current

Hence, I b = 5 x 132/150 = 4.4A

With a motor starting current o f 670% o f nominal, a setting o f the relay thermal t ime constant w i t h motor init ial thermal state o f 5.9% o f 15s is found satisfactory, as shown i n Figure 19.14.

\I Contactor

250 A

(a1 LV motor cxamplc data

setting Ib 4.4 A :

M r l o a d tirnc dclay I> t 15 5 ; &niaIaIK:c 12 20 'XI 1 2: Unbalance timc dclay I2>t 25 s

P~xlimcdcla~..;.. .... .5!> .......... 5 . . -- 5 .

b. :. . lb l Rclay settings j %b;c r3.3: ;L:!.<c:arpn!r<f :ion w!;;r;g c,.oc;,?i . . .

(a1 LV Motor Protcction - contactor fcd cxamplc

1 3 3 j 1 . . . . . . . . . . .

1 \-\ . . . . .

. . . . . . . . . . . . . . . . . . . . ........................................... .... ... .- . - . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . I . 1 . . . . . . . . . . . . . . . . . . . . . . " I . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ..__ . . ...... .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . '3 ! . . . . . . . . . . . . . . . . . . . . . -

. . . . . . . . . . . . . . . . . . . . - . . . - .-:; . . . . . . . . . . - ....... .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

I . .- - . I . . 4

1 3

0 1 2 3 4 5 6 7 . 8 I / / ,

[b] Rclay trip c h a r a c l c ~ ~ ~ t i c

1:: ..

Re relay is set i n secondary quantities, and therefore a hi table CT ra t io has t o be calculated. From the relay ianua l , a CT w i th 5A secondary rating and a motor rated :urrent i n the range of 4-6.4 when referred t o the secondary of CT is required. Use o f a 15015A CT gives a notor rated cuirent o f 4.4A when referred to -the CT iecondary, so use this CT ratio.

h e fuse provides the motor overcurrent protection, as the Irotection relay cannot be allowed to trip the contactor on Wrcurrent in case the current to be broken exceeds the The motor is bui l t to IEC standards, which permit a mntactor breaking capacity. The facility for overcurrent negative sequence (unbalance) voltage of 1% on a jrotection wi th in the relay is therefore disabled. continuous basis. This would lead t o approximately 7010 1:; r - . . - . . . . . . . . . . . . . . . . negative sequence current-in the motor (Section 19.7).

As the relay is f i t ted only w i th a definite t ime relay The motor is an existing one, and no data exists for it element, a setting of 200,~ (from Section 19.7) is xcept the standard data provided i n the manufacturers appropriate, w i th a tirne delay of 2ss to allow for short :atalogue. This data does not include the thermal high-level negative sequence transients arising from heating) t ime constant o f the motor. other causes.

n these circumstances, i t is usual t o set the thermal jrotection so that it lies just above the motor starting :Went.

;he current sett ing o f the relay, Ib , is found using the orm mu la

I b = 5 X I l I l l p I

- . . - . . . . . . . . . . . . . . -- ...

N , r u . r l P , . r r r r i . . 3 A . r . r . 1 i . m C . i J r -7 ..........

. . . . . The relay has a separate element fo r this protection. Loss - :? . , .... . of a phase gives rise to large negative sequence currents, .::' .

. .

and therefore a much shorter t ime delay is required. A .:

definite t ime delay o f 5s is considered appropriate. The relay settings are summarised i n Table 19.3(b).

&*? ,.. MOTOR PROTECTION

1 Motor Details : r,

Motor Protection Setting Criteria and Tutorials Page 1 of 38

IETTING CRITERIA

by. - M ~ t o r Rating iri KW

..- .- / Rated Voltage in KV -

: Motor Application Others

Motor Control by ( Contactor / Circuit Breaker ) CB

Motor Full Load current 230 Amps

-: - CT Ratio 300/1 A

:I:, - ' ' Type of Motor Starting DOL

Starting current in Primary Arnps ( 100 % Voltage ) 1 380

Starting current in Primary Amps ( 80 % Voltage ) 1104

Moto~' Starting time in seconds ( 100 % Voltage ) 5

Motor Starting time in seconds ( 80 % Voltage ) 8

Thermal overload characteristics ( Available/ Available not-availa ble) Stalling current in primary Amps 1380

Hot stall withstand time in seconds 20

Cold stall withstand time in seconds 30

- - - -

OALSTOM Limited, f nergy Automation & Information 6

Advanced Industrial Power System Protection - Motor Protection Settins Crie

and Tutofi, Page 2 G

Thermal Overload characteristic Curves

OALSTOM Limited, Energy Automation & information

Hot Characteristics 2700 500

Times full load current X 1.4 X 2.0

X 4.0 X 5.0 X Stalling current .

Cold Characteristics 4000 750

85 48 30

5 7 30 20

. . Advanced Industrial Power System Protection Motor Protection Setting Criteria

Calculations

Thermal Overload Protection:

Set the pick-LIP at 103% of the rated current = 230 x 1.03 = 236.9 Amps -

~eferred to secondary = 0..789 = 0.78 Set Is = 0.78

Calculation for the time constant at overload levels ( 1 <leq<2) times the pick-up current

Cold Curve :

The operating time for the thermal overload characteristic available in the relay is as follows :

. . .. . . .... .

t = T x In { ( PSM2)/( PSM2- 1 ) ''

. . Therefore the required time constant can be calculated as : T = t / { In { ( PSM2)/( PSM2 - 1)))

At 1.4 time rated current

-

For Cold Curve PSM = 1.411.03 = 1.36, we require a operating time of 4000 x 0.7= 2800 ( 30 % margin )

T = t / { In { ( PSM2)/( PSM2 - 1 ))) T = 2800 / { In { ( 1.362)/( 1.362 - I ) ) ) = 3599 Seconds = 59.98 min

Calculation for the time constant at overload levels ( leq > 2) times the pic k-up current

At 2 time rated current the relay curve is adiabatic.

we require an ope;ating time of 750 x 0.7= 525 ( 30 % margin )

OALSTOM Limited, Enemy Automation & Information

:, .::. , . - .; 3 .. . . . > I ,:.:

- .., . . . . ,.

, Advanced Industrial Power System _ I. : . -I:., . . . \ .c9q

Protecfion Motor Protection sewrn

(2)2 x 525 = (1.03)2 XT - .T$ .--

r = 1979.45 sec = 32.99 min

At 3 time rated current

dperating time of 190 x 0.7= 133 ( 30 % margin ) . .-1 <:;.+g . . - - ... ;..-

(3)2 x 133 = (1.03)2 xr . -. , ..:@ ..:__

r,: _ I

r = 1128 sec = 18 min .d3 : ; iQ ;i i . 2 . ....

The minimum value of the time constant is considered. So the time j:.?

constant considered in this case is 18min -

Based on the above setting, the hot curve based on the Hot to Cold R ~ I .. .$ setting can be calculated as follows.

For Hot curve

. . . - . . ..-, -54 Select HCR ( hot to cold Ratio ) = 0.66 - : .?.+I>

. . .. - ?>3 .. ..7. . ., -;< -e .. . 4,;;

For 1.4 times Full load Current time of operalion :

t = { r x In { ( PSM2)/( PSM2 - 1 ) ) x 0.66 = (18 x In ( 1.362)/(1 .362- 1 ) ) x 0.66 = 9.24 min = 554.4 seconds

For 2 times Full load Current time of operation :

For 3 times Full load Current time of operation :

-


I. 9, 5 - ked Industrial Power System

>n Motor Protection Setting Criteria and Tutorials Page 5 of 38

;"ce the following settings are recommended ermal Pick-up current IS = 0.78 -

ne constant T H = 18 minutes HCR = 0.66

ling time constant Tc = 5 x Is ( normally adopted, if data

I<

$>L E available ) bermal Alarm required = YES i t

pmparing the above values with the hot withstand characteristic of the &tor, we find that the safety margin between relay curve and the motor h e is clearly more than 30 %.

3ALSTOM Limited, Energy Automation & Information

-3% .<+3 :-,q

:.-A<.

2.F . :, -. Mvcnced fndustrial Power System ..;&

Protsction Motor Protection Setting c&&$ and Tutorials': Page 6 of a-

Start Protection -

Maximum Motor starting current at rated voltage - . - 6 Times Full load Current

- - 1 380 Amps

Maximum ~ o t o r starting current at lower voltage of say 80% - - 80% of max starting curent

1 104 Amps

Prolonged Start Proteclion :

This protection will operate if the motor takes longer time to start. The setting will be based on the worst case type of voltage for starting, which occurs when starting with low voltage

Therefore Current setting will be 80% of Max current during starting at low voltage

-

IS, = 0.8 x 0.8 x 1380 / 300= 3.76 0.78

Set IS{- = 3.76

Time Setting will determine after how much time with this current will the relay detect it as a prolonged start. This requires the value of the maximum starting time, which is applicable, when the motor starts with low voltage.

Is, = 8 + 4 seconds ( margin) = 12 seconds

GALSTOM Limited, Energy Automation & Information @

lvanced Industrial Power System otection

. .

Motor Protection Settit?= Criteria and Tutorials Page 7 of 38

of start limita.lions

!&' Number of Cold starts per hour Set = 3 as motor is rated for 4 starts per hour Number of Hot starts per hour Set = 1 as motor is rated for 2 starts per hour

This setting can be changed depending on how frequently we use the -

Phase Sequence Startinq

.id.i. As the motor most probably will be unidirectional, it is generally advised to enable Reverse Phase sequence protection.

Set RPS as enabled -


Mvancsc! !ndustrial Power System Protection Motor Protection Setting Cfie*

and Tutoriak Page 6 of s

Siait Protection -

Maximum Motor starting current at rated voltage

Maximum Motor starting currenl at lower voltage of say 80%

- - 6 Times Full load Current

1380 Ar;ips

- - 80% of max starting curent

1 104 Amps

Prolonged Start Protection :

This protection will operate i f the motor takes longer time to start. The setting will be based on the worst case type of voltage for starting, which occurs when starting with low voltage.

Therefore Current setting will be 80% of Max current during starting at low voltage

-

Isi = 0.8 x 0.8 x 1380 / 300= 3.76 0.78

Set 1st- = 3.76

Time Setting will determine after how much time with this current will the relay detect i t as a prolonged start. This requires the value of the maximum starting time, which is applicable, when the motor starts with low voltage.

1st = 8 + 4 seconds ( margin) = 12 seconds


-

. . . . i . . . g;? F f .: g .

'{dvanced Industrial Power System . .

protection Motor Protection Settinz Criteria

Number of start limitations 6

and~utoriais Page 7 of 38

B ii Number of Cold starts per hour Set = 3 as motor i s rated for 4 starts per ; hour :I, Number of Hot starts per hour Set = 1 as motor is rated for 2 starts per hour

'' This setting can be changed depending on how frequently we use the

!:- v .. Zeverse Phase Sequence Startinq li- F As the motor most probably will be unidirectional, it is generally advised to '1 enable Reverse Phase sequence protection.

Set RPS as enabled -

OALSTOM Limited, Energy Automation & !nformation +

t'ui . :%

Advanced Industrial Power System Protection Motor Protection Setting Criie 4

and Tutorial - Page 1 0 of S

Ne~ative Phase Sequence:

The negative phase sequence protection has to be graded with the NPS withstand levels of the motor. In absence of this, it is recommended to provide current setting equal to rated current.

Set current setting - - 1 .oo

Time characteristic-setting may be set to-definite time as we de do not have the inverse withstand level of motor.

The definite time setting can be set to 0.1 sec.

This means that i f the negative sequence settings reaches rated current, the relay will operate instantaneously. -


OALSTOM Limited, Energy Automation & Information *

Advanced Industrial Power System . .

Protection , '

..: . ., q: ... .: . ... . . . ...

. . . .

. . . .

: 1

Motor Protection Setting Critei and Tutori~

- Page 10 of I

Negative Phase Sequence:

The negative phase sequence protection has to be graded with the NPS withstand levels of the motor. In absence of this, it is recommended to provide current-setting equal to rated current.

Set current setting - - 1 .oo

Time characteristic .setting may be set to defiriite time as we de do not have the inverse withstand level of motor.

The definite time setting can be set to 0.1 sec.

This means that if the negative sequence settings reaches rated current, the relay will operate instantaneously. -

OALSTOM Limited, Energy Awtomation & Information

strial Power System - .Motor Proiection Setting Criteria

and Tutorials Page 1 1 of 38

ault setting shall be based on the standing leakage currents ethod of system earthing. If the system is'resistance earthed, be required and the required primary operating current may based on system study.

ent case is assumed to be on a system which is solidly earthed, balance leakage currents can be measured using standard de of connection and earth fault setting shall be made . Generally the leakage currents shall not exceed 5 % of the t. Therefore the current setting may be set to 10% of the rated

Current setting - - 0.1 x full load Current x CTsec x1000 CTpri

- - 0.1-x 230 x 1 x 1000 300

= 76.67 -

Set lo = 80mA

Time delay setting may be set to instantaneous which will be 0.1 sec ( 100mA ) . This is an intentional delay and is used to prevent inrush currents, which last for couple of cycles from operating the e/f element during

-.

-.

OALSTOM Limited, Energy Automation & Information I

Advanced Industrial Power System

Negative Phase Sequence:

provide current setting equal to rated current.

- Set current setting - 1 -00

Time characteristic-setting may be set to definite time as we de do not . < . . .,.<,./>f'

have the inverse withstand level of motor. :-A .:.g ..:-"$ ; :>&<

. \.4b, ,, ,,$!

The definite time setting can be set to 0.1 sec. .I.$ * :.a> .:x. .'Y%

.':.A , c. ,!,..* I jn

This means that if the negative sequence settings reaches rated current, $! :.$ the relay will operate instantaneously. - .&: ..?. .:., .. ,i ,"..

OALSTOM Limited, Energy Automation & Informatian

Advanced Industrial Power System Protection - - -Motor Prokction Setting Criteria

and Tutorials Page 1 1 of 38

Earth Fault Protection:

P" - 'The earth fault setling shall be based on the standing leakage currents

\ _ and the method of system earthing. If the system is resistance earthed,

1 CBCT may be required and the required primary operating current may be studied based on system study.

c-

As this present case is assumed to be on a system which is solidly earthed, I standing unbalance leakage currents can be measured using standard

residual mode of connection and earth fault setting shall be made I accordingly. Generally the leakage currents shall not exceed 5 % of the

rated current. Therefore the current setting may be set to 10% of the rated current.

Current setting - - 0.1 x full load Current x CTsec x1000 CTpri

-

Set lo = 80mA

Time delay setting may be set to instantaneous which will be 0.1 sec ( 100mA ) . This is an intentional delay and is used to prevent inrush currents, which last for couple of cycles from operating the e/f element during starting.


Notes 1 C T S

URRENT TRANSFORMERS - STEADY STATE BEHAVIOGR

'-';Current hnsformers are among the most commonly used items of electrical apparatus and yet, !g "~surprisingly, there seems to be a general lack of even the most elementary knowledge

-2*.

$'concerning their characteristics, performance and limitations among those engineers who are $,continually using them. The importance of current transformers in the transmission and :&distribution +<. of electrical energy cannot be over emphasised because it is upon the efficiency of Ecurrent transformers, and the associated voltage transformers, th& the accurst=: metering and " effective protection of those distribution circuits and plant depend.

-

Current and voltage transformers insulate the secondary (relay, instrument and meter) circuits from primary (power) circuit and provide quantities in the secondary which are proportional to those in the primary. The role of a current transformer in protective relaying is not as readily defined as that for metering and instrumentation. Whereas the essential role of a measuring transformer is to deliver from its secondary winding a quantity accurately representative of that which is applied to the primary side, a protective transformer varies in its role according to the type of protective gear it serves.

. Failure of a protective system to perform its function correctly is often due to incorrect selection of the associated current transformer. Hence, current and voltage transformers must be regarded as constituting part of the protective system and carefully matched with the relays to fulfil the esseqtial requirements of the protection system.

There are two basic groups of current transformer, the requirements of which are often radically different. It is true in some cases the same transformer may serve both purposes but in modern practice this is the exception rather than the rule:

1. Measurement CT's - The measuring current transformer is required to retain a specified accuracy over the normal range of load currents.

2. Protection CT's - The protective current transformer must be capable of providing an adequate output over a wide range of fault conditions, from a fraction of full load to many times full load.

Therefore they generally have different characteristics.

CURRENT TRANSFORMER STANDARDS

Various international standards are available. Such standards give information on the classification, selection, error and operation of current transformers. They are a valuable source of reference and can be used in conjunction with the relay manufacturer guide when selecting the appropriate CT. The list below gives some examples:

I EC IEC 185.1987 IEC 44-6:1992 IEC 186.1 987

' EUROPEAN BS 7625 BS 7626 BS 7628

8RI-rISH BS 3938:1973 BS 3941 : 1975 -

AMERICAN ANSI C51.13.1978 CANADIAN CSA CAN3-C13-M83 AUSTRALIAN ' AS 1675-1986

CTs CTs v r s v r s CTs CT+VT CTs v r s CTs and VTs CTs and VTs CTs

Page 1

. . . . . - . . , . .

Please note that the above are the applicable standards at the ti,me of print of this document an' therefore they may vary.

:* CURRENT TRANSFORMER CONSTRUCTION . . ..: . ...

+,;c ..?.s. . .

7 A current transformer consists essentially of an iron core with two windings. One winding is connected in the circuit whose current is to be measured and is called the primary and the other winding is connected to burden, and called the secondary. Two of the most basic construction of current transformers are the bar type and wound type:

1. Bar Type - Sometimes referred to as 'Bushing Type'. Such current transformers normally '

have a single concentrically placed primary conductor, sometimes permanently built into the. CT and provided with the necessary primary insulation, but very often the bushing of a circuit breaker or power transformer. At low primary current ratings it may be difficult to obtain ~ufficient output at the desired accuracy because a large core section is needed to provide enough flux to induce the secondary emf in the small number of turns.

PRIMARY

DARY

2. Wound Type -With this device it is possible to change the number of primary turns, thus increasing the CT output voltage with altering the turns ratio. Therefore, for the same output the wound CT is smaller in CSA than the bar type.

Page 2 I

TENT TRANSFORMER POLARITY

: is no official standard when it comes to defining the polarity of current transformers. ver, most Engineers will use P I and P2 to define the primary winding and S1 and S2 to the secondary winding. Generally speaking when P1 goes high S1 goes high. Therefore

current flows from P1 to P2 it is transferred and flows through the external circuit from S1 Typically P2lS2 is towards the Item of plant being protected.

{ENT TRANSFORMER THEORY

3w current in the primary winding produces an alternating flux in the core and this flux 2s an e.m.f. in the secondary winding which results in the flow of secondary current when ~nding is connected to an external closed circuit. -The magnetic effect of the secondary ~ t , in accordance with fundamental principles, is in opposition to that of the primary and the of the secondary current automatically adjusts itself to such a value, that the resultant 2tic effect of the primary and secondary currents, produces a flux required to induce the necessary to drive the secondary current through the impedance of the secondary. In an ransformer, the primary ampere-turns are always exactly equal to the secondary ampere- and the secondary current is, therefore, always proportional to the primary current. In an current transformer, however, this is never the case. All core materials, so far discovered,

e a certain number of ampere-turns to induce the magnetic flux required to induce the sary voltage.

lost accurate current transformer is one in which the exciting ampere-turns are least in rtion to the secondary ampere-turns. Exciting ampere-turns may be reduced in three ~ l e ways:

By improving the quality of the magnetic material

Cold rolled grain oriented silicon steel (C.R.O.S.S.) has a magnetisation characteristic with a knee point at 1.6 tesla.

Nickel steel (Proprietary name Mumetal) has a knee point of 0.7 tesla.

By decreasing the mean magnetic path of the core.

By reducing the flux density in the core.

Page 3

. , , . , , . .

.4! ,. , . ....I

: . . . ! , ..

:,t., , I ' .C . ..a , .,

. / ..I >, . :7:; :! 2. .. : .<

."; Q:. :?.;&A ,

:I. $'.& 8 ,:.L .g+\;

:,; ,b# ': >;:g .; ;, . . (,!b!,I$t ,. : !'.

;!$;pb ' . : , ; : , $ , ! ) i :. p,,: :,, !, 2 .y

. .,A , j , i,;:: ' !

,r:r:.a.>L.

CURRENT TRANSFORMERS BASIC FORMULAE - ' a . .$; *

Protective relays are designed to operate from secondary quantities supplied from current ..... ... ,.

transformers and from voltage (or potential) transformers. The secondary output of these .. devices is the information used by the relays to determine the conditions existing in the plan >i being protected. It is necessary, therefore, that the secondary output of current and voltage ?

present a true picture to the relays of the conditions in the primary circuit during faults as well as -,. during normal loads. Or, alternatively, that their performance be known under extreme conditions so that any error in reproduction in the secondary circuit can be partially or completely compensated for in the setting and characteristics of the relay.

In many applications, core saturation will .almost inevitably occur during the transient phase of a heavy short circuit. The performance of the associated instrument transformers during faults is, therefore, an important consideration in providing an effective relaying scheme. The relays and their associated current transformers must be considered as a unit in determining the overall performance of the protective scheme. Consequently, the characteristic of the current and potential transformers at high currents and low voltage respectively, must be known. In any current transformer the first consideration is the highest secondary winding voltage possible prior to core saturation. This may be calculated from :

Ek = 4.44 x B A f N volts Where :

Ek = secondary induced volts (rms value, known as the knee-point

voltage) N = number of secondary turns f = system frequency in hertz A = net core cross-sectional area in square meters.

This induced voltage causes the maximum current to flow through the external burden whilst still maintaining a virtually sinusoidal secondary current. Any higher value of primary current demanding further increase in secondary current would, due to core saturation, tend to produce a distorted secondary current.

-

The relevant circuit voltage required is typically :

Equation 1

Where :

Is = secondary current of ct in amps (assume nominal value, usually 1A or 5A)

ZB = the connected external burden in ohms ZS = the ct secondary winding impedance in ohms ZL = the resistance of any associated connecting leads

In any given case, several of these quantities are known or can usually be estimated in order to predict the performance of the transformers. From the ac magnetisation characteristic, commonly plotted in secondary volts versus exciting current, Es can be determined for a minimum exciting current. The equation for the relevant circuit voltage given above then indicates whether the voltage required is adequate.

Page 4

-

at a bar primary type 200015A (CROSS core) current transformer having a core csa square cm's is available with a secondary resistance of 0.31 ohm. The maximum to which the transformer must maintain its current ratio is 40,000 amperes. It is

-- k:required to determine the maximum secondary burden permissible if core saturation is to be P' , ,;.

Assume that the current transformer core will start to saturate at 1.6 tesla. - .. < C,

) : P r From the data given :

N = 2000/5 = 400 turns f = 50 Hz .

Secondary current (Is) with a primary current of 40,000A is given by

Knee point voltage Ek is-given as follows :

= 284 volts

Maximum burden permissible (including ct secondary resistance and lead burden) is equal to 284 / 100 = 2 84 ohms

Consequently, the connected burden including that of the p~lots can be as high as 2.84 - 0.31 = 2 -53 ohms for negligible saturation in the core. Thus it mav be seen that the secondary burden and the maximum available fault current are two important criteria in determining the performance of a given current transformer.

A current transformer may operate satisfactorily :

a) At a high primary current where the connected secondary burden is low

b) At a lower primary current where the secondary burden IS high

CURRENT TRANSFORMER MAGNETISATION CURVE

'The primary current contains two components. These are respectively the secondary current which is transformed in the inverse ratio of the turns ratio and an exciting current, which supplies the eddy and hysteresis losses and magnetises the core. This latter current flows in the primary

. . winding only and therefore, is the cause of the transformer errors. It is, therefore, not sufficient to assume a value of secondary current and to work backwards to determine the value of primary current by invoking the constant ampere-turns rule, since this approach does not take into account the exciting current. From this observation it may be concluded that certain values of secondary current could never be produced whatever the value of primary current and this is of course, the case when the core saturates and a disproportionate amount of primary current is required to magnetise the core.

The amount of exciting current drawn by a current transformer depends upon the core m and the amount of flux which must be developed in the core to satisfy the burden require the current transformer. The appropriate current may be obtained directly from the exciting characteristic of the transformer since the secondary e.m.f. and therefore the flux develope proportional to the product of secondary current and burden impedance.

-

The general shape of the exciting characteristic for a typicai yrade of CRZSS (cold rol!e orientated silicon steel) is shown. The characteristic is divided into three regions, define 'ankle-point' and the 'knee-point'. The work i~g range of a protective current transformer e over the full range between the 'ankle-point' and the 'knee-point' and beyond, while a mea current transformer usually only operates in the region of the 'ankle-point'. The difference in working ranges between metering and protective current transformers stems from the radical difference in their functions. Metering current transformers work over the range 10% to 1 load and it is even an advantage if the current transformer saturates for currents above this range in order to provide thermal protection for the instruments. Protection current trans on the other hand are required to operate correctly at many times- rated current-.

b' MMF ampere-turns per metre

KNEE-POINT

. : The knee-point of the excitation characteristic is defined as the point at which a 10% increase in secondary voltage produces a 50% increase in exciting current. It may, therefore, be regarded as practical limit beyond which a specified current ratio may be maintained.

.:: The current transformer magnetisationcurve, is usually expressed in terms of Kv and Ki which when multiplied by the flux density in teslas and ampere-turns per cm respectively gives

!, I corresponding volts and amperes :

:;@

1&& x..

.@$ ,$X -;z':

, , . ; + i .-;+? :;A . g(+ .gg .-. ' .::yzc . . c : : **.

. .., .,!... '(,>. . ...A .-:<. I.'

Page 6

equation, the flux density 6 is in teslas and the core cross-sectional area is in squar

sity B is in teslas and the cross-sectional area is in square centimetres :

e exciting current le in amps can be obtained from the M'MF using the relationship:

le = Ki x MMF

I depend on the units of MMF.

k l f the MMF is in ampere-turns per meter.

S 3' g. rf i

L I?:;. Ki = - where L is in metres $.! I1 g...

! EXAMPLE

' Consider the case of a current transformer ratio 10015A connected to an earth fault relay. Relay : burden at minimum tap setting of 1O0/0 of rated current is given as 2 VA. Calculate the required ' values of Kv and Ki to provide the necessary output up to 10 times the plug setting, with :

1 A barprimaryjype current transformer and with

ii) A wound primary (5 turns current transformer).

Assume the use of a CROSS core; B = 1.6 tesla.

i ) Ring Type Current Transformer (Bar Frimaryj .- -

,Relay current setting = 0.5 ampere : ie.lO% of 5A.

Volts required to operate relay

Voits required at i O times the the plug setting

- L - - = 4 volts 0.5

= 4 x 10 = 40 volts ignoring lead burden and CT secondary winding resistance

Therefore, 40 volts must correspond to the knee-point of the saturation curve which represents a flux density of 1.6 tesla.

With a bar primary, secondary number of turns = 20

Assume stacking factor = 0.92

.-. Gross CSA = 56.310.92 = 61.2 cm2

Assuming :

I.D. = 18 cms O.D. = 30 cms Depth = 10.2 cms

Wound Primary CT , . . - -. . -

Assume current transformer is wound with 5 primsry turns :

loo = 100 econdary turns = 5 x - 5

-

49 = 4-44 x 53 x 1.6 100 x A. 7 9-4 (A in cm'j

7 . 1 1.26 m - le. csa = - = 12.24 cm' 0.92

18 cm 30 cm 2.04 cm

2 6 x 100 = 25

45

= 0.754 cm 1 turn

OPEN ClRCUlTED SECONDARY WINDING

The secondary circuit of a current transformer should never be left open-circuited whilst primary continues to flow. In these circumstances only the primary winding is effective and thus the current transformer behaves.as a highly saturated choke (induction) to the flow of primary winding current. Thus a peaky and relatively high value of voltage appears at the secondary output of terminals, endangering life, not to mention the possible resulting breakdown of secondary circuit insulation.

In those cases where current transformers are associated with the "high impedance type" earth fault relay the secondary circuit burden may have ohmic values up to several thousands of ohms.

Page 9

EQLIIVALENT CIRCUIT

The errors of a current transformer may be considered as due to the whole of the primary current :& not being transformed, a component thereof being required to excite the core. Alternatively, we .I!"

.. '2 may consider that the whole of the primary current is transformed without loss, but that the , ,,,;(: -..~ . .?..

secondary current is shunted by a parallel circuit the impedance of which is such that the . 2 . . . . . . .

equivalent of the exciting current flows there in. The circuit shown is the equivalent circuit of the ':1 current transformer.. The primary current is assumed to be transformed perfectly, with no ratio or phase single error, to a current Ip/N which is often called 'the primary current referred to the secondary'. A part of the curre'nt may be considered consumed in exciting the core and .this current le is called the secondary excitation current. The remainder Is is atrue secondary current. It will be evident that the excitation current is a function of the secondary excitatbn voltage Es and the secondary excitation impedance Ze. It will also be evident that the secondary current is a function of Es and the total impedance in the secondary circuit. This total impedance consists of the effective resistance (and any leakage reactance) of the secondary winding and the impedance of the burden.

primary current in amperes current transformer ratio (primary to secondary amperes) burden impedance of relays in ohms (r + jx) current transformer secondary winding impedance in ohms (r + jx) secondary excitation impedance in ohms Cjx) secondary excitation current in amperes secondary current in amperes secondary excitation voltage in volts secondary terminal voltage in volts across the current transformer terminal: (input to the relay or burden)

SATW RATION

Beyond the knee-point the current transformer is said to enter saturation. In this region the major part of the primary current is utilised to maintain the core flux and since the shunt admittance is not linear, both the exciting and secondary currents depart from a sine wave. For example, in the case of a wholly resistive burden, correct transformation takes place until saturation flux density is reached. The secondary volts and current then collapse instantly to zero, where they

- Page 10

Notes Additional Analysis

TRODUCTION

n understanding and working knowledge of System Analysis is ver rotection Engineer as he must know how the system operates under load efore choosing suitable relays to match the system parameters.

Analysis of load and fault conditions also provides useful information for :-

Choice of Power System Arrangement

Required Breaking Capacity of Switchgear and Fusegear

Application of Control Equipment

Required Load and Short Circuit Ratings of Plant

System Operation. Security of Supply, Economics

Investigation of Unsatisfactory Plant.Perforrnance

-

110 = R + jX = Zi (cos 0 + jsin 0) = 1Zl ejO

i B 1 and Z2 = iZ2! - z1 JZ1l 1Z21 LO, +(I2 and =-- = I- L O 1 -(I2 22 I i 1 jz2 I

. OPERATORS

rotates a vector anti-clockwise through 90"

a = 1 L120° rotates a vector anti-clockwise through 120" used extensively in symmetrical component analysis

a2 = 1 L240° a2 + a + 1 = 0

y important to the and fault conditions

\, Page 1 - . . .

I CONVENTION USED FOR VOLTAGE DIRECTION -

Current I flowing in direction shown produces a voltage drop in Z such that A is positive with respect to B.

!

BASE QUANTITIES AND PER UNIT SYSTEM

3 This is particularly useful when analysing large systems with several voltage levels. Before any j?s

Q4 system calculations can take place the system parameters must all be referred to common + base quantities. The base quantities are fixed on one part of the system and base quantities .-$ on other parts at different voltages will depend on the ratio of intervening power transformers. - 1 -

The base quantities used are :-

,.<.::yr<* Base voltage = kVb = phase to phase voltage in kV . .,>! ,: ;@$,

2 5 .- :w .A

Base MVA = MVAb = three phase MVA - -$ .r .. .v

-5 Other base auantities can then be established :- .,.>' .. ~,

Base impedance = Zb

Base current = Ib F

- - - (kVb)' in ohms. MVAb

MVAb in M. J3. kvS

Per unit values are obtained by dividing actual values by base values as follows :-

- . . - Actual im~edance Z, - MVA Per unlt ~mpedance Zp.u

Per rlnit v n l t a n ~ kV-

- - Base impedance

-

- k Va - -

Per nit MVA MVA- - MVA, -- -

Per unit current I P u - l a - -

11,

, - . . Percentage values are commonly used for transformer impedances and where per unit values :% :..::. .. are very small. Percentage values are 100 times the equivalent per unit values. .r;y$a L+

Q

Page 2

EXAMPLE 1 -

Find t h e fault current in e a c h sect ion f o r a three p h a s e fault a t F.

Base kVb = 3 1 132

Base MVA = 50 b

?, = kv; = 2 . 4 2 ~

MVA b

50 Z2.u 3n 0.3 x - = 0.75,, 0.1 p u common base 20

p.. g.; g.

- k: ti. .*. Zp.u.2 - zp.u,l x i 2 MVAb2 p $ :

MVAbl (kvb2 )* -

FROM ONE SET OF BASE VALUES

Page 3

The base voltage on each side of a transformer must be in the same ratio as the of the transformer.

OVERHEAD LINE

mrrect Selection of kVb 11.8 kV 132 kV I 1 kV

irrect Selection of kVb 132 x 1 1.8 = 1 1 -05 kV 132 kV I 1 kV

$ 141- >. iornative Correction Selection of kVh 11.8 kV 141 kV 141x11 =11.75kV ,,,-...- -. -

EXAMPLE 3

. . . . .. '.; The per [,]nit impedance of a transformer is the same on each side of the transforn

Consider a transformer with voltage ratio kVllkV2.

I 0 MVA 0

1: Actual impedance of the transformer viewed from side 1 = Zal

i I Actual impedance of the transformer viewed from side 2 = Za2.

- z a ~ MVA zp.u 1 - -- = Zal X

Zbl kv12

- z a 2 - MVA Zp.u.2 - - Za2 X

zb2 kv2

kv2 but Za2 = Zal x

kv1

- MVA :. Zp,u,2 - Z a 1 x = Z L: I

kV1 2

Page 5

voltage ratio

C)!STR!BCITIS:4 SYSTEM

ier

CIRCUIT LAWS

There are three basic laws :

i) Ohms Law

ii) Kirchoffs Junction Law

At any junction (or node) CI = 0: '

i.e. 1, + I 2 + l 3 = 0 . .

13

' - 'r iii) Kirchoffs Mesh Law

Round any mesh CE = CIZ

eg, in mesh (1): El = il Z1 + il Z3 - i2 Z3

- ,

Page 6

CIRCUIT THEOREMS

These are derived from the circuit laws. The three most commonly used for system analysis are Thevenins, Star/Delta Transform and Superposition Theorems.

i) Thevenins Theorem

This is useful for replacing part of a network which is noi of pan~cular interest. .

Any active network viewed from any 2 terminals can be replaced by a s~ngle drivirlg voltage in series with a s~ngle impedance where :-

Driving voltage = Open circuit voltage between terminals Impedance = Impedance of the network as viewed from the two

terminals with all driving voltages short circuited.

Example :

L3 Where E' = - --- L 3 . 4 E, and Z' = -- z3 + z1 z3 + z1

ii) DeltalStar and StarlOelta Transform Theorems

Page 7

i i i )

z10.z20 212 = z10 + 220 +

z30

z12.z31 - - ZI2 + + Z31

Superposition Theorem

In any linear network the current in any b r a ~ c h du different driving voltages is equal to the vector sum voltage acting alone with the others short circuited.

Example :

z 1

I 1

l3 = 1 3 1 + 13?

. . ..,: .-: .,.. .

Page 8

INTRODUCTION

. In a balanced three-phase system, each of the three phases of any part of the system will have currents and voltages which are equal and 120° displaced with respect to each other. To maintain balanced operation, each Item of system plant must be symmetrical: i.e. have identical impedances In each line, equal mutual impedances between phases and ground, and equal

etween two lines and ground.

circuit faults. They can arise the operation of fuses.

SYMMETRICAL COMPONENTS METHOD

Consider n-dimensional system of phasors.

Va = Val + Va2 + Va3 + ... + Van

Vb = Vbl + Vb2 + Vb3 + ... + Vbn

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Vn = Vnl + Vn2 + Vn3 + ... + Vnn

Where Val , Vbl , etc. are phasors of the first set of balanced n-phase system. Phasors are single spaced. .

Va2 , Vb2 , etc. are phasors of the second set of balanced n-phase system. Phasors are double spaced.

Page 9

And so on.

Van , Vbn . etc. are phasors of the uni-directional phasor system.

Take for example an unbalanced 5-phase system. V, , Vb , V, , Vd , V,.

First set of aalanced Phasors

Fourth set of Balanced Phasors

Second set of Balanced Phasors

Fifth set of Zero Sequence Phasors

Now consider an unbalanced three phase system. Va . Vb , V,.

A vc1 v,. . v t>

I f i vc2

Positive Sequence

Negative Sequence

Zero . . . ..: , 1

$7 Sequence . , ,..

. T,.: ., ..

Three unbalanced phasors have been resolved into nine phasors.

Choose 'a' phase as the reference phase and replace Vas by Vao.

where a = 1.0 L120° -

It is convenient to delete subscript 'a' for the symmetrical components.

Add equations 1. 2,and 3

2 Multiply equation 2 by u amd equation 3 by u and add the resulting equations to equation 1.

Multiply equation 2 by u2 and equation 3 by a and add the resulting equations to equation

Equations 1 to 6 can be re-written in matrix form

Re-write matrix equations 7 and 8 respectively as

[VP 1 = [A] PSI .................... 9

Where Vp = phase components

Vs = sequence components

Example

Resolve the following 3-phase unbalanced voltages into their symmetrical components.

Fig. 1 Symmetrical Components

t;:

E SYMMETRICAL COMPONENT TRANSFORMATION

,

/ . Fig. 2 .. ?

Take a set of symmetrical three phase impedances (equally spaced, fully transposed, etc.) \

. carrying unbalanced phase currents L a , I b and I,.

We may write the following equations.

Va = Zsla + Zmlb + Zmlc

where Zs = self impedance per phase

Z, = mutual impedance betrween any ~ h a s e pair

Or, in matrix form

Resolving V and 1 phasors into their symmetrical components.

. Page 15

I

= [: :2 ;I [i i; [i ;2 ;*I I a a

where Z1 = Z, - Z,

Therefore, if the system is. symmetrical in its normal state the symmetrical co~~?poiaent impedance becomes diagonal (equation 11) and, therefore, isolated sequence networks are .

obtained with impedances Z1, Z2 and Zo. These three networks will become interconnected when an unbalance such as a fault or unbalanced loading is introduced. The manner of interconnection will depend on the new constraints: i.e. the additional system connect~or~s.

Page 16

r F $

PLANT IMPEDANCE DATA F - For static networks i.e. non-rotating plants, the positive and negative sequence Impedances are

the same. These are the leakage impedance of the transformers and the normal phase impedance of the transmission circuits.

Zero sequence impedance of overhead line and cable circuits is determined by the return path of the zero sequence currents through earth, earth wires or cable sheaths. The zero sequence impedance is generally' greater than the positive and negative sequence impedance, being usually of the order of two to three times the positive sequence value in the case of overhead lines.

For transformers, if zero sequence currents have an available path and can flow, they will again see the leakage reactance in each phase. If no path exists, an open circuit must be shown for the particular windings in the zero sequence network. The flow of zero sequence current in any winding is possible only if other windings provide a path for the flow of balancing zero sequence currents. -

,- Consider the transformer equivalent circuit in F~gure 3 overleaf. The magnet~sing impedance Z , is of the order of 2000°/~, compared to the leakage impedance ZIP + Z1, of about 10%. Therefore, magnetising impedance can be ignored and the transformer can be represented in the positive and negat~ve sequence networks by a series impedance (=ZIP + Z,,).

1 1 . - .

ZL* J .

. . . . .. . 0

.. - I

. ... -

O zLp = prima ry winding leakage > .

... impedance

Zm Z1, = secondary winding leakage impedance

Zm = rnagnetising impedance

1 Fig. 3 Transformer Equivalent Circuit

In the zero sequence network, although the leakage impedance is identical to the positive sequence value (when zero sequence path is available) the zero sequence rnagnetising impedance is dependent upon the transformer core construction and can be much lower. In three-phase banks of single phase transformers and in three-phase shell cored transformers, the zero sequence magnetising impedance is ,large and can be ,ignored as in the positive and negative sequence networks. In three-limb core type transformers, however, the zero sequence flux must be completed through the oil or tank. Owing to the high reluctance of the flux path, zero sequence magnetising impedance is of the order of only 100% to 400%. However, this is still high enough to be neglected in most fault studies, particularly when a delta winding Is present.

- Page 17

I

Therefore, consider zero sequence circuit of transformer as a series impedance Zt. The mode of connection of Z, to the external circuit is determined by taking account of each winding arrangement and its connection or otherwise to ground.

-

Imaginary links 'a' and 'b' (see Figure 4) are used to derive the connections. If zero sequence currents can flow into and out of a winding, for example a solidly earthed star winding, the winding terminal is connected to the external circuit, that is link 'a' is closed.

'a' 'a'

Fig. 4

,!: If zero sequence currents can circulate in the winding without flowing in the external circuit, for k d' example a delta winding, the winding terminal is directly connected to the zero bus, that is link ' . . .. ti:. 'b' is closed. !i . il: b -

Example 1 ..:

'a' 'a'

Zero Sequence Equivalent Circuit Connections

-

..iL ... . Page 18 -.; .*

m

ihe zero sequence impedance of a neutral earthing impedance Zn is 32.. The reason for this can be readily understood from Figure 5 below.

I At the neutral point the zero sequence currents I0 in the three phases combine to give 310 in the neutral earthing impedance. The zero sequence voltage at the neutral point is given by

. vo = 3I0Zn . . . . . . . .

. . . . . . . . . . . . . .

. zo = vo = 32" . . - . - . .

lo

Example 2

Transformer Connections

'a' 'a' 3R - Zero Sequence Equivalent Circuit Connections

. . Page 19

. . : . . . . . . .

-

The positive sequence impedance of synchronous machines is the normal machine reactan There are three defined values of positive sequence impedances, namely the synchron transient and subtransient impedances and they are used according to whether steady st transient or initial short-circuit values of current are required.

L Unlike the non-rotating networks, the negative sequence impedance of the rotating plants is equal to the positive sequence impedance. It relates to mmf at synchronous speed travelli the opposite direction to the rotor. Its value is usually less than that of the positive sequ

& impedance. , <.,.,~< .. .~.. ., . . . .....

In the zero sequence network, the winding connection and earthing arrangement must be ,'.;!& considered as for transformers. Any earthing impedance will be seen by each phase and '$$$ therefore the correct voltages will be obtained if three times the impedance value is included in . .;$@ the zero sequence network. . Y.%%.. . ,?.

, :,.;3j?; . s. .,;: /?;.,T?. ., ..

e"' ",:,;,. G

Typical turbo-generator sequence reactances are : ,:a?%! ..;:.4:: ... ,.

synchronous reactance - - 1.0 p.u. transient reactance - - 0.15 p.u. -

subtransient reactance - - 0.10 p.u. negative sequence impedance = 0.13 p.u. zero sequence impedance - - 0.04 p.u.

.:.> .". . .., ,

,, ",:$:<' , . ~ A . . , .. '.,?'

CONNECTION OF SEQUENCE NETWORKS TO REPRESENT UNBALANCED FAULTS .<. >-+,; . .. .<.%:.. .+...- d

. . . .:. ., &xS! . . :;TZ&, . .><.>.

. . " ' > . c : ~ . . : < 6. . . ,*- , . ~ . > -

(a) For anygiven fault there a% six quantities'to be mnsidered at the.fault point; Vat Vb, V,, - . y!j$p ~ . 4

.:,:.:<:.. I , , It,, lc. If any three are known(provided they are not all voltagesor all currents) or.if . :.:$&$ . . ..,:-,

":r .. .,. any two are known and two others known to have a specific relationship, then a ~.!j~$v.,, i

relationship between V1, Vp and Vo and 11, 12 and 10 can be established. : 2-% .;:! . .,? . . . . ,. . t- .'f. : .- .'. .. . ..:. .. -

These relationships are-called the circuit constraints. - ? .. .-

From the circuit constraints we can determine the manner in which the isolated sequence .::, . ,... .%.

networks can be interconnected. .

. ,. . . . ..

(b) The relationships are derived with phase 'a' as the reference phase and the faults are :.,?"

selected to be balanced relative to the reference phase. This yields the simplest ..* $$:

interconnection of the sequence networks. If this is not done the interconnections of the ;:,

sequence networks require additional transformations which are achieved by the ...$ introduction of phase shifting transformers. This will be apparent in the case of ,.:(,

simultaneous faults where it is not possible for both the faults to be symmetrical about the ..:? reference phase. . . :.

..: ;yfi I .:$

Page 20 :: :) . .?

i t Faults

F ine-to-ground faults, line-to-line faults, line-to-line to ground faults and three phase faul'ts all ,fall into the category of shunt faults. ; /(a) Figure 6 shows a system with a fault at F. The positive, negative and zero sequence

networks of the system are shown in Figure 7. The fault terminals for the positive sequence network are F1 and N1, and the corresponding fault terminels for the negative

and zero sequence networks are F2, N2 and Fo, No respectively. It is at these terminals

:\ , that the interconnection of the networks will occur. In the denvation of sequence network

i, interconnections, it is convenient to show the sequence networks as blocks with fault

I terminals F and N for external connections (F~gure 8)

, (b) To derive the system constraints at the fault terminals, it IS convenient to imagine three short conductors of zero impedance connected to the three line conductors at the point of fault (F~gure 9). The terminal conditions imposed by the different types of faults will be

applied to these imaginary leads, the potential to ground of which will be V,, Vb and V, and the currents I, I b and I,. .,

A

B I

Fig. 9

- - - - Fis. 6 Single Line Diagram of Two Machine System

PF

. 6 ~ , Pos~tive Sequence Network of System

@ Sequence & k k of System

Fiq. 7 Sequence Networks of Faulted S y s t e ~

Sequence Sequence Network Network

etwork Blocks

Page 22

Line to Ground on Phase 'A'

At fault point :

We know from section (2.2) that

v, = v, + v* + vo

But Va = 0

.'. v, + v 2 + v o = o --------------------- 3


10 = 1/3(la + l b + 1 , ) . -

But l b = Ic = 0

:. 10 = 113 1,

L Also, l 1 = 113 (Ia + ulb + a I,) = 113 1,

2 12 = 113 (I, + u l b + ul,) '= 113 I,

Equations 3 & 4 are the CIRCUIT CONSTRAINTS. They suggest that the sequence netwo are connected in series. -

Sequence Network

Network

Network

Page 23

Line to Ground Fault through Fault Impedance ZF

At fault point :


:. I0 = 113 I,, since lb = 1, = 0

Similarly,

:. 11 = 12 = 10 = 113 1, 3

We know

But V, = I,Zf from constraint 2

But 1, = 310 from equation 3

Equations 3 & 4 suggests the following interconnections.

1 1 F1 +ve - A

Sequence Network -

N 1

12 -ve - F2

Network

F4 lo

Zero - - Fo Sequence Network -

No

Page 24

Line to Line Fault on Phases 'B' and 'C'

At fault point :

. We know l o = '113 (I, + I b + I,) ..................... 4

Sequence Network

Sequence Sequence Network Network

No

-

Substituting equations 2 & 3 into equation 4,

Similarly,

2 2 11= 1/3(Ia + a l b + u I,) = 1 / 3 ( a - a ) Ib

2 2 12 = 113 (I, + a Ib + uI,) = -113 (a - a ) Ib

:. I1 + 12 = 0 ..................... 6

Substituting equation 1 into equation 7,

V1 = 113 (V, - Vb)

2 Similarly V2 = 113 (V, + a Vb + a ~ i ) = 113 (V, - Vb)

From equations 5, 6 & 8, the positive and negative sequence networks are in parallel but the zero sequence network is unconnected.

Line to Line Fault on Phases 'B' and 'C' through Fault Impedance ZF

-

Page 25

At point of fault,

I, = 0

Ib + lc = 0

Vb - Vc = IbZf

:. 10 = 113 (la + I b + I,) = 0

2 . 2 11 = 113 (I, + a l b + a 1,) = 113 (a - a ) lb

2 2 12= 113(1, + a Ib + al,) = - 1 / 3 ( a - a ) l b

:. I0 = 0 ..................... 4

I1 + I2 = 0

2 We know Ib = 10 + a I l + u12 ) - --------------------- 5

Substituting equation 4 in 5

Vb = VO + aLvl + a V 2

2 V,= Vo + rxVl + cr V2

2 2 ... V b - V = (a - a ) V 1 - (a - a ) V 2 ..................... 7 C

Substitute equation 3 8 6 into 7,

Equations 4 8 8 suggest the following interconnections. + Sequence Network

Sequence Network

N Network

I I Line to Line to Ground Fault on Phases 'B' and 'C'

Page 26

At fault point :,

v b = vc = 0

I, = 0

2 V2 = 113 (V, + a Vb + UV,) = 113 V,

From equation 3 & 4, it can be concluded that the sequence networks are connected in parallel.

11 12 +ve - -C-OFl -ve - w F 2 Zero

--FO

Sequence Sequence Sequence Network Network ON Network

O N 1 - - Q NO

Line to Line to Ground Fault on Phases 'B' and 'C' through Fault Impedance Z,

At fault point :,

Page 27

2. . 2 V1 = 113 (V, + aVb + a vc) = 113 [V, + (a + a)Vb] = 113 (Va- Vb)

2 v2 = 113(~, + a2vb + aVc) = II~[V, + (a + a)Vbl = II~(v,- vb)

.'. v1 = v2 ..................... 5

Vo - Vl = 113 (2Vb + Vb) = Vb

- - (Ib + 1,) Zf ..................... 6

Substitute equation 4 in 6

vo - v1 = 31ozf

Equations 3, 5 and 7 suggest the following interconnections.

Page 28

-

11 - I2 - l o Fo 3Zf

+ve - -FI -ve - L ~2 Sequence t ~2 Network Network ON

N 1

Zero - sequence Network L.

/ N

1. SERIES FAULTS (or Open Circuit Faults)

(a) Figure 1 shows a system with an open circuit PQ. The positive, negative and zero sequence networks of the open-circuited system are shown in Figure 2. Unlike the case of shunt faults, the fault terminals for interconnection are P and Q, therefore not I nvolving the neutral. The sequence equivalent network blocks (Figure 3) will have terminals P and Q for interconnection. Terminal N is also indicated in the blocks although it is not used for interconnections.

(b) The terminal conditions imposed by different open circuit faults will be applied across points P and Q on the three line conductors (see Figure 4). Therefore the fault terminal currents will be IA, IB and Ic flowing from P to Q on the three

conductors, and the terminal potentials will be the potential across P and Q, i.e. V,

- V,',Vb - Vbl, Vc - V; They will be represented by v,, vb and vc respectively.

Figure 4

Page 29

Documents

Training _ Power System Protection _AREVA