2. tneb testing manual
DESCRIPTION
Electrical Testing & Commissioning ManualTRANSCRIPT
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TAMIL NADU ELECTRICITY BOARD
MANUALMANUALMANUALMANUAL ONONONONPRE-COMMISSIONINGPRE-COMMISSIONINGPRE-COMMISSIONINGPRE-COMMISSIONING&&&&PERIODICALPERIODICALPERIODICALPERIODICAL
TESTINGTESTINGTESTINGTESTINGOFOFOFOF
ELECTRICALELECTRICALELECTRICALELECTRICAL INSTALLATIONINSTALLATIONINSTALLATIONINSTALLATION
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FOREWORDFOREWORDFOREWORDFOREWORDThe need for a comprehensive manual on Substation equipments and testing procedures
for these equipments is a long felt need. Initiative for this was taken in July 1999 to prepare
such a manual by constituting a Committee of experts.
It is not enough if the officers of specialized field such as GRT, MRT, SS Erection,
Transformer Erection etc., know about such testing procedures. The officers in charge of
Substations should also have adequate knowledge of the equipments they are in charge of, so
that these equipments are maintained well, operated in the way they should be done. Besides
the maintenance officials, the operators of the 400 KV, 230 KV and 110 KV Substations should
also be familiar about the functioning of each equipment they have to operate, observe and
monitor during the course of their duty.
Though piece meal instructions are available in various literature and supplier’s
manuals, they are not codified and written in the way the maintenance and operating officials
could easily understand and carry out their function with confidence and in a systematic way.
The expert committee has brought out a good manual covering pre-commissioning and
periodical testing on all the equipments. I congratulate the members of the team for their
excellent work particularly Thiru K. Mounagurusamy, Thiru M. Varadharajan and Thi ru M.
Arunachalam who have shouldered a major responsibility in bringing out this manual.
Any suggestions for improvement are welcome. An updated and improved version will
be published later based on these suggestions.
I am confident that the manual will be of immense use to the testing, operating and
maintenance personnel in the T.N.E.B.,.
CHENNAI-600 002 R. POORNALINGAM,
16.02.2001 CHAIRMAN
Tamil Nadu Electricity Board.
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INTRODUCTION:INTRODUCTION:INTRODUCTION:INTRODUCTION:The Institute of Electrical and Electronic Engineers (IEEE) defines a relay as “ an electric
device that is designed to interpret input conditions in a prescribed manner and after specifiedconditions are met to respond to cause contact operation as similar abrupt change in associatedelectric control circuits”.
Any unwanted operation or a non-operation can equally result in major system upsets. Todifferentiate between these two levels, a protection engineer has to be fully conversant andknowledgeable not only with the protection relay subject but also the protected equipments likegenerators, motors, transformers, transmission lines, distribution etc. For example, if aprotection engineer is not clear about the principles of transformers, he will not be able tohandle the protection of the transformers effectively.
TNEB’s policy has always been to the modern trends on protection system then and thereand to give opportunities to its engineers to have the latest philosophy of the system. TheTNEB engineers are well exposed to the protection field and are being responsible for theapplication of modern systems.
Now the experienced engineers of the TNEB in the field of protection have developed amanual, sharing their experiences.
The objective of this manual is to help the field protection engineers carry out their workseffectively to the extent possible. There may be different opinions about some of the pointsgiven in this manual. This is natural since protection though a science is an art by itself and anyart can not be defined or contained in a shell. It could be practically seen that decisions inprotection field are depending upon individuals mainly. This manual is to furnish a minimumcommon base for the protection “ art”
The topics chosen are grouped in separate chapters dealing with major area Power systemprotection and the power line carrier communication. A sample calculation of fault levels of asmall substation is given to generate the idea on the very important area to be familiarised byany protection engineer.
Subjects like design, application, principles etc are not dealt with since these are availablein various textbooks and brochures of relay manufactures. Care has been taken to includematerials, which are not normally available in text books and relay manuals. Importance hasbeen given to provide information and guidelines to the field engineers on theprecommissioning, commissioning, periodical maintenance and analysis of relay operations.
The provision of such a manual was suggested in response to Chairman’s D.O.Letter No.SE/CHO/D 493223 DT 08.07.99 seeking suggestion from various officers. It is not knownwhich officer has actually suggested this, but the subsequent efforts taken by our ChairmanThiru. R. Poornalingam IAS., has broughtout this publication. The engineering fraternityshould thank our chairman for having been the starter and keeping a constant drive to achievethe goal.
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The suggestion was accepted in the meeting held on 17.9.99 and it was decided that ChiefEngineer / Research & Development and Chief Engineer / Technical Audit shall print anddistribute.
A committee consisting the following officers was constituted wide LR No.CE/TA/EE/AEE/F.SSETP/D204/99 dt 12.11.99.
1) Er. A.S. Kandasamy
2) Er. K. Mounagurusamy
3) Er. S. Swaminathan
4) Er. M. Arunachalam
5) Er. P. Ponnambalam
6) Er. ULO Chenthamizh Kodai
7) Er. M. Varadarajan
It was also approved in the above ref. that the above committee shall prepare the manualand put up to the steering committee consisting of Chief Engineer / Technical Audit, ChiefEngineer / Research & Development and Chief Engineer / Operation.
First meeting of the committee was held on 22.11.99 and the subjects were decided alongwith the allocation of various subjects to the members of the committee. The members wereasked to submit the materials on or before 22.12.99. The copies of materials received werefurnished to all other members in order to check and avoid any technical errors and to suggestfor any improvements. Subsequent meetings were held on 28.1.2000and 28.2.2000.
The subject was reviewed by Chairman on 13.11.2000 and Chief Engineer / Protection &Communication was instructed to take up the work and complete the job.
The job was completed with the best cooperation of Engineers Thiru M. Arunachalam,Thiru M. Varadarajan and Thiru Ponnambalam in the final stages and a long felt need of relayengineers has been accomplished.
It is our best hope that the manual will be of valuable assistance to the field engineers.
Any suggestions and improvement are welcome and will be sincerely acknowledged andappreciated.
CHENNAI – 600 002 ChiefChiefChiefChief EngineerEngineerEngineerEngineerDATE: 16.2.2001 ProtectionProtectionProtectionProtection&&&&CommunicationCommunicationCommunicationCommunication
ChennaiChennaiChennaiChennai –––– 2.2.2.2.
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CONTENTSCONTENTSCONTENTSCONTENTSChapterChapterChapterChapter SubjectSubjectSubjectSubject AuthorAuthorAuthorAuthor PagePagePagePage
Introduction
1. Need for Tests on Electrical Instalation 72. Current Transformers Er. A. S. Kandasamy 19
CE/Transmission.
3. Potential Transformers Er.K. Mounagurusamy 43Capacitive Voltage Transformer CE/P&C
4. Pre-commissioning Tests Er.K. Mounagurusamy 48CE / P&C
5. Commissioning Test Er.K. Mounagurusamy 54CE / P&C
6. Testing of Circuit Breaker at Site Er. P. Ponnambalam 75EE/ S.S Erection
7. Testing of Relays Er.K. Mounagurusamy 78CE / P&C
8. Protection of Non Grid Feeders Er. M. Varadarajan 81EE / O&M.
9. Distance Protection Er. M. Arunachalam 121EE / GRT
10. Power Transformer Testing and Protection Er. M. Varadarajan 156EE / O&M
11. Generator Protection Er.K. Mounagurusamy 251CE / P&C
12. Under Frequency relaying Er.K. Mounagurusamy 267CE / P&C
13. Power-line Carrier Communication Er. M. Arunachalam 271EE / GRT
14. HV AC/DC Test By R&D. 290
15. Maintenance of Relays Er.K. Mounagurusamy 316CE / P&C
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16. Gas Insulated Sub-Stations. Er.K. Mounagurusamy 322CE / P&C
17. Review and Analysis of Tripping Er.K. Mounagurusamy 336CE / P&C
18. Experience in protection field Er.K. Mounagurusamy 353CE / P&C
19. Under ground Cable System Er. M. Arunachalam 366EE / GRT
20. Batteries Er. M. Arunachalam 370EE / GRT
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CHAPTER-ICHAPTER-ICHAPTER-ICHAPTER-I
NEEDNEEDNEEDNEED FORFORFORFORTESTSTESTSTESTSTESTS ONONONONELECTRICALELECTRICALELECTRICALELECTRICAL INSTALLATIONINSTALLATIONINSTALLATIONINSTALLATION
EACH AND EVERY PIECE OF EQUIPMENT IS TESTED IN THE FACTORY BEFOREDESPATCHING TO THE SITE. PRECOMMISSIONING TESTING AT SITE IS DONE TOPROVE THAT:
i) TO ENSURE THAT EQUIPMENT WAS NOT SUBJECTED TO ANY DAMAGEDURING TRANSPORTATION.
ii) EACH EQUIPMENT HAS BEEN INSTALLED CORRECTLY.
iii) EACH EQUIPMENT IS WORKING IN CO-ORDINATION WITH OTHEREQUIPMENTS AS DESIRED.
iv) ALL THE PROTECTION AND CONTROL SCHEMES ARE WORKING INACCORDANCE WITH RELEVENT SPECIFICATION AND PROTECTIONREQUIREMENTS.
v) EACH EQUIPMENT HAS BEEN ADJUSTED PROPERLY IN ACCORDANCEWITH TNEB’S SETTINGS.
vi) THE INSTALLATION IS SAFE FOR PUTTING IN TO SERVICE.
vii) THE PREIODICAL TESTING WILL ENSURE THE AVAILABILITY OF THEEQUIPMENT FOR THE RELIABILITY OF THE SYSTEM PERFORMANCE.
viii) THE TESTING OF PROTECTIVE SYSTEM FOR COMBINATION OFCONTINGENCIES THAT CAUSE THE SYSTEM INSTABILITY ANDSEPARATION WILL EVOLVE THE DYNAMICS OF THE SYSTEM.
ix) THIS WILL ALSO HELP IN UPDATING THE SYSTEM DISASTER CONTROLMEASURES IMPLEMENTED.
x) FINALLY THIS WILL GIVE A RECOGNITION FOR THE POSSIBILITY TO FACETHE UNFORSEEN MULTIPLE CONTINGENCIES AND/OR NATURALCALAMITY WHICH MAY CAUSE THE COLLAPSE OF THE ENTIRE SYSTEM.
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CHAPTER-I
PROTECTION SYSTEM FORTRANSMISSION AND DISTRIBUTION
UNDER NORMAL CIRCUMSTANCES, THE ELECTRICAL ENERGY INAN ELECTRICAL SYSTEM IS SAFELY CONTAINED ANDCONTROLLED.
WHEN EQUIPMENT FAILS, THE ENERGY IS RELEASED AND EVERYCOMPONENT IN THE SYSTEM IS AT RISK. THE PROTECTIVERELAYING SYSTEM MONITORS THE ENERGY FLOWING IN THESYSTEM AND INITIATE ACTION WHEN DAMAGING FAULTS OCCUR.
ELECTRICALENGINEER NEEDS TO UNDERSTAND:• ROLES OF PROTECTION• EFFECTS OF FAULTS ON ELECTRICAL EQUIPMENT• BASIC PROTECTIVE METHODS• ZONES OF PROTECTION IN RELAYING SYSTEMS
ROLES OF PROTECT ION IN ELECTRICAL SYSTEM.
THE PRIMARY ROLE OF ELECTRICAL PROTECTION SYSTEM IS TODETECT AND ISOLATE ABNORMAL CONDITIONS.
ABNORMAL CONDITIONS EXPERIENCED IN POWER SYSTEMS AREFAULTS, OVERLOADS, AND EQUIPMENT FAILURES.
THE CAUSES OF THESE ABNORMAL CONDITIONS INCLUDE;
• ENVIRONMENT DISTURBANCES• OPERATOR ERROR• EQUIPMENT MALFUNCTIONS• INSULATION DETERIORATION
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CHAPTER-I
OBJECTIVE OF SYSTEM PROTECTIONPROTECTION DOES NOT MEAN PREVENTION. IT IS RATHER MINIMISING THEDURATION OF THE TROUBLE AND LIMITING THE DAMAGE.
RELIABILITY, SELECTIVITY, SENSITIVITY, SPEED OF OPERATION,SIMPLICITY, AND ECONOMICS ARE SOME TERMS COMMONLY USED TODESCRIBE THE OBJECTIVE OF SYSTEM PROTECTION.
RELIABILITY HAS TWO ASPECTS I.E., DEPENDABILITY & SECURITY
- DEPENDABILITY is the certainty of correct operation in response to systemtrouble.
- SECURITY relates to the degree of ability that a relay system will avoid missoperation. Generally, enhancing security tends to decrease the dependability andvice versa.
SELECTIVITY:
- The ability of the protection system to “select” (search out) the point at whichthe fault appears and switch it out of the circuit by tripping the nearest circuitbreaker.
SENSITIVITY:
- The capability of the protection system to respond to abnormalities in normaloperating conditions
SPEED OF CONTROL:
- Quick disconnection of a short-circuit, decreases the amount of damage incurred,maintains the machines running in synchronism (A high speed relay willoperate in 3 cycles)
SIMPLICITY:
- The simpler the protection system the greater is its reliability.
ECONOMICS:
- Protection costs are considered high when considered alone, but they should beevaluated in the light of the much higher cost of the equipment they areprotecting and the cost of an outage and/or the loss of the protected equipment.
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CHAPTER-I
PROTECTIVE RELAY CLASSIFICATION1. According to functional categories
Protective relays, monitoring relays, reclosing relays, regulating relays, Auxiliaryrelays, synchronizing relays
2. According to input quantity, operating principle and performance characteristic.
Inputs: Current, Voltage, Power, Frequency, Pressure, Temperature, Flow, and vibration.
Operating principle: Current balance, Percentage, Multi restraint, product, Solid state,Static, Microprocessor, Electromechanical, Thermal Performance characteristics: Distance,Directional over-current, Inverse time, Definite time, Under-voltage, Over-voltage,Ground or phase, High or low speed, phase comparison, Directional comparison
3. According to the method of connection to the power circuitPrimary relays.Secondary relays connected through C.Ts and P.Ts.
4. According to the method of actionDirect-acting relaysIndirect-acting relays, those operate through auxiliary relays.
5. According to the degree of importanceMain relaysSupplementary relays such as signal relays, time relays, contact multiplier relays.
6. According to time of actionQuick relays: operate in 4-40ms.Ordinary relays: operate in 40-200ms.
7. According to type of contactsRelays with normally-open contactsRelays with normally closed contacts.
Relay performance is generally classified, as (1) correct, (2) no conclusion,(3) incorrect. Incorrect operation may be either failure to trip or false tripping, thecause of it may be poor application, incorrect setting, personnel error, or equipmentmalfunction.
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CHAPTER-I
ELECTRICAL ENVIRONMENT REQUIREDFOR THE PROTECTIVE RELAYS
Sl.No. Specification Number Details
1. IEC 255-11:1979 The unit should withstand a10ms interruption in theauxiliary supply, under normal operatingconditions, withoutde-energising.
2. AC ripple on DC supply The unit should withstand 12%IEC 255-11:1979 ac ripple on the dc supply.
3. High frequency disturbance 2.5 kv peak between independentIEC 255-22-1:1988 Class III circuits and case.
1 kv peak across terminals of thesame circuit.
4. Fast transient disturbanceIEC 255-22-4:1992 Class IV 4 kV, 2.5kHz applied directly to
auxiliary supply.
IEC 801-4:1988 Level 4 4kv, 2.5 kHz applied directly toall inputs.
5. Surge immunityIEC 1000-4-5:1995 Level 3 2kv peak, 1.2/50 μs between
all groups and case earth.2kv peak, 1.2/50 μs betweenterminals of each group.
6. EMC compliance In compliance with theEuropean Commission directive.89/336/EECGeneric standards ofEN5008-2:1994, EN5008-2:1995
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CHAPTER-I
REFRENCEREFRENCEREFRENCEREFRENCE STANDARDSSTANDARDSSTANDARDSSTANDARDS
01 IEC Electrical Relays-All-or-nothing electrical relays255-1-00
02 IEC 255-3 Electrical Relays – Single input energising quantity measuringrelays with dependent or independent time
03 IEC 255-6 Electrical Relays – Insulation tests for electrical relays
04 IEC 255-6 Electrical Relays – Measuring relays and protection equipments05 IEC 255-7 Electrical Relays – Test and measurement procedures for
electro-mechanical all-or-nothing relays
06 IEC 255-8 Electrical Relays – Thermal electrical relays07 IEC 255-10 Electrical Relays – Application of the IEC quality assessment
system for electronic components to all-or-nothing relays
08 IEC 255-11 Electrical Relays – Interruptions to and alternating component(Ripple) in DC auxiliary energising quantity of measuring relays
09 IEC 255-12 Electrical Relays – Directional relays and power relays with twoinput energising quantities
10 IEC 255-13 Electrical Relays – Biased (%) differential relays
11 IEC 255-16 Electrical Relays – Impedance measuring relays12 IEC Electrical Relays – Vibration, shock, bump and seismic tests on
255-21-1 measuring relays and protection equipment (Vibration tests)
13 IEC Electrical Relays – Vibration, shock, pump and seismic tests on255-21.2 measuring relays and protection equipment (Shock & Bump tests)
14 IEC Electrical Relays – Vibration, Shock, pump and seismic tests on255-21-3 measuring relays and protection equipment (Seismic tests)
15 IEC Electrical Relays – Electrical disturbance tests for measuring255-22-1 relays and protection equipment (1 MHz burst disturbance tests)
16 IEC Electrical Relays – Electrical disturbance tests for measuring255-22-2 relays and protection equipment (Electrostatic discharge tests)
17 IEC Electrical Relays – Electrical disturbance test for measuringrelays and protection equipment (Radiated electromagneticfield disturbance tests)
18 IEC Electrical Relays – Electrical disturbance tests for measuring255-22-4 relays and protection equipment (Fast transient disturbance tests)
19 IEC Electrical Relays – contract performance255-23
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CHAPTER-I
ATMOSPHERIC ENVIRONMENTTEMPERATURE
IEC-255-6:1988 Storage and transit -25°C to +70°COperating -25° to 55°C
IEC-68-2-1:1990 ColdIEC-68-2-3:1974 Dry Heat
2. Humidity
IEC-68-2-3:1969 56 days at 93%RH and 40°C
3. Enclosure Protection
IEC-529:1989 IP50 (dust protected)
Mechanical Environment
Vibration
IEC-255-21-1:1988 Response Class 1.The relay should be capable of performing 10000 operations. The relay should becapable of withstanding shock, bump and seismic disturbances.
IEC 255-21-2:1988IEC 255-21-3:1993 Exception: lowest frequency tested is 5Hz.
High Voltage Withstand
1. Dielectric WithstandIEC 255-5:1977 2Kv rms 1 minute between all
case terminals connectedtogether and the case earth terminal.
2Kv rms 1 minute between allterminals of independentcircuits, with terminals on eachindependent circuit connectedtogether.1.5 Kv rms for 1 minuteacross normally open outgoingcontact pairs.
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CHAPTER-I2. High voltage impulse
IEC 255-5:1977 Three positive and three negativeimpulses of 5 kv peak, 1.2/50 μs,0.5J between all terminals of thesame circuit (except outputcontacts), independent circuits,and all terminals connectedtogether and case earth.
THE FOLLOWING INFORMATIONS APPLY TO RELAYS:-
1. INPUT ENERGISING QUANTITIES
AC Voltages (rms) 115VAC Current (rms) 1Amp or 5 Amps
2. AUXILIARY ENERGISING QUANTITIES
Fixed Inputs Level sensitive inputs Jumper selectable inputs30Vdc 18Vdc 30Vdc48Vdc 28.8Vdc 48Vdc110Vdc 66Vdc 110Vdc220Vdc 132Vdc 220Vdc
3. FREQUENCY
Specified as 50Hzwith a range of operation from 47.5Hzto 52.5Hz
4. REFERENCE CONDITIONS OF INFLUENCING QUANTITIES
Ambient temperature 35±5°CPosition Horizontal
5. NOMINAL RANGE OF INFLUENCING QUANTITIES
Unless otherwise specified, the following values represent the reference condition
Ambient temperature -40°C to 85°CPosition 0° to 180°in any direction from the reference position
6. LIMITING SHORT TIME THERMAL WITH STAND
Current Inputs Voltage Inputs500amps (ac) for 1sec 365v (ac) for 10 sec
The above conditions are to be verified for the acceptance of relays for theprecommissioning test on protective relays.
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CHAPTER-IProtective relays have been called sentinels and electric brains.
From the economic point of view, relays are akin to insurance; they protect the powerutility from financial loss due to damage to equipment.
From the under writers point of view, they prevent accidents to personnel and minimisedamage to equipments.
From the consumer’s point of view, good service depends more upon adequate relayingthan upon any other equipment.
FUNCTIONFUNCTIONFUNCTIONFUNCTION OFOFOFOF PROTECTIVEPROTECTIVEPROTECTIVEPROTECTIVE RELAYSRELAYSRELAYSRELAYS ANDANDANDAND RELAYINGRELAYINGRELAYINGRELAYING
When anything abnormal occurs on an electrical system, some action is necessary toisolate the abnormal condition either instantaneously or in some circumstances, after a pre-determined time delay. Such action must be automatic and selective ie. it must segregate thefaulty section or piece of equipment leaving the healthy remainder in normal service. This isthe function of protective gear, which in one form or another is designed to sense the presenceof abnormal conditions and based on this a sensing, to isolate the circuit. The abnormalconditions against which protection is required, may be broadly summarised as follows.
1. The condition of overloading.
2. The failure of insulation to the extend where a dangerous leakage of current can occur toearth.
3. The failure of insulation to the extend where short circuit occurs between two or threephases.
Relays do not prevent occurring of abnormal conditions, but only to help to “protect”.
When we say that relays “ protect” we mean that together with other equipments such ascurrent transformers (CT), Potential transformers (PT) circuit breakers (CB), Battery, controlcircuit etc. the relays help to minimise damage and improve service.
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CHAPTER-I
GLOSSARYGLOSSARYGLOSSARYGLOSSARY OFOFOFOF COMMONCOMMONCOMMONCOMMON RELAYRELAYRELAYRELAY TERMSTERMSTERMSTERMS
1.1.1.1. OperatingOperatingOperatingOperating forceforceforceforce orororor torque.torque.torque.torque.
- that which tends to close the contacts of the relay.
2.2.2.2. RestrainingRestrainingRestrainingRestraining forceforceforceforce orororor Torque.Torque.Torque.Torque.
- that which opposes the operating force or torque and tends to prevent the closure of therelay contacts.
3.3.3.3. PickupPickupPickupPickup (level)(level)(level)(level)
- The value of current or voltage etc. which is the threshold above which the relay willclose its contacts.
4.4.4.4. DropoutDropoutDropoutDropout (level)(level)(level)(level) OROROROR ResetResetResetReset
- The values of current or voltage etc. which is the threshold below which the relay willopen its contacts and return to normal position or state.
5.5.5.5. CharacteristicCharacteristicCharacteristicCharacteristic (of(of(of(of aaaa relayrelayrelayrelay inininin thethethethe steadysteadysteadysteady state)state)state)state)
- The locus of the pick up or reset when drawn on a graph.
6.6.6.6. BackupBackupBackupBackup relayrelayrelayrelay
A relay which operates usually after a slight delay, if the normal relay does not operateto trip its circuit breaker.
7.7.7.7. SelectivitySelectivitySelectivitySelectivity
- The ability of the relay to discriminate between a fault in the protected section andabnormal conditions or a fault else where on the system.
8.8.8.8. ConsistencyConsistencyConsistencyConsistency
- The accuracy with which the relay can repeat its electrical or time characteristic.
9.9.9.9. FlagFlagFlagFlag orororor TargetTargetTargetTarget
- A visual device, usually spring or gravity operated for indicating the operation of arelay.
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CHAPTER-I
10.10.10.10. InstantaneousInstantaneousInstantaneousInstantaneous relayrelayrelayrelay
- One which has no intentional time delay and operates in less than 0.1 second.
11.11.11.11. BurdenBurdenBurdenBurden (VA)(VA)(VA)(VA)
- The power absorbed by the circuits of the relay expressed in volt-amperes ifalternating current, and in watts if direct current at the rated current or voltage.
12.12.12.12. OperatingOperatingOperatingOperating timetimetimetime
- The time which elapses from the moment when actuating quantity attains a valueequal to the pick up value until the relay operates its contacts.
13.13.13.13. BlockingBlockingBlockingBlocking
- Preventing the protective relay from tripping, either due to its own characteristic or toan additional relay.
14.14.14.14. AnnunciatorAnnunciatorAnnunciatorAnnunciator –––– Audible and/or visible alarm or signal initiated electrically.
15.15.15.15. CircuitCircuitCircuitCircuit breakerbreakerbreakerbreaker
- A device for interrupting a circuit between separate contacts under normal orabnormal conditions. May be operated manually or automatically for circuit control byoverload or the selected condition.
16.16.16.16. CircuitCircuitCircuitCircuit breakerbreakerbreakerbreaker mechanism:mechanism:mechanism:mechanism:
- An assembly of levers, cranks and other parts which actuate the moving contacts of acircuit breaker.
17.17.17.17. DashDashDashDash potpotpotpot
- A device using a gas or liquid to absorb energy or retard the movement of movingparts such as on a circuit breaker.
18.18.18.18. ClosingClosingClosingClosing CoilCoilCoilCoil
- The electromagnet or solenoid which supplies power for closing a circuit breaker.
19.19.19.19. TripTripTripTrip coil:coil:coil:coil:
- An electromagnet used for opening a circuit breaker.
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CHAPTER-I
20.20.20.20. DifferentialDifferentialDifferentialDifferential relayrelayrelayrelay
- A relay which functions by reason of the difference between two quantities of thesame nature such as current or voltage.
21.21.21.21. InstrumentInstrumentInstrumentInstrument transformerstransformerstransformerstransformers (CTs,(CTs,(CTs,(CTs, PTs)PTs)PTs)PTs)
- Used for measuring and control purposes, provides current and voltagesrepresentative of the primary components but of such magnitude that there is less danger toinstruments and personnel.
22.22.22.22. InterlockInterlockInterlockInterlock
- An electrical or mechanical arrangement that prevents one operation or sequence ofoperation from taking place, until another prerequisite operation or condition has been satisfied.
23.23.23.23. SolenoidSolenoidSolenoidSolenoid
- An Electro magnetic coil which when electrically energised produces a mechanicalforce by acting up on a free armature in the coil axis.
24.24.24.24. T.M.S.T.M.S.T.M.S.T.M.S. TimeTimeTimeTime MultiplierMultiplierMultiplierMultiplier settingsettingsettingsetting (UK)(UK)(UK)(UK)T.L.S.T.L.S.T.L.S.T.L.S. TimeTimeTimeTime leverleverleverlever settingsettingsettingsetting (U.S.A.)(U.S.A.)(U.S.A.)(U.S.A.)
- A means of adjusting the movable back stop which controls the travel of the disc andthereby varies the time in which the relay will close its contacts for given values of current.
25.25.25.25. PlugPlugPlugPlug settingsettingsettingsetting bridgebridgebridgebridge (UK)(UK)(UK)(UK) orororor TapTapTapTap blockblockblockblock (USA)(USA)(USA)(USA)
- A device providing a range of current settings at which the relay will start to operate.
26.26.26.26. CapacitorCapacitorCapacitorCapacitor
- An electrical device for storing of electricity and returning it to the line. It is used tobalance the inductance of a circuit since its action is opposite in phase to that of inductiveapparatus ie. it throws the current ahead of emf in phase.
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CHAPTER-IICHAPTER-IICHAPTER-IICHAPTER-II
CURRENTCURRENTCURRENTCURRENT TRANSFORMES:TRANSFORMES:TRANSFORMES:TRANSFORMES:Er. A.S. Kandasamy (CE/Transmission)
INTRODUCTION:The most widely used input quantity, in the application of protective relays is current.
The source of this quantity is from current Transformer (CTs) which are located on or near theprotected equipment. CT’s are used to provide isolation from the power system and reductionin magnitude to a level usable by relays and meters. Protective relays use this quantity innumerous ways to determine if the protected system is abnormal and requires isolation. Failureof CT’s to perform as designed, has resulted in failure to trip, failure to trip promptly andtripping when not required.
Many of these failures can be traced to incomplete or improper testing of the CT’s andthe associated circuitry. (This manual for field testing of relaying CTs is written to providetesting personnel with the basis to properly test the CTs.)
AccuracyAccuracyAccuracyAccuracy class:class:class:class:
Understanding of the accuracy class of a CT is necessary for proper testing andevaluation.
Ratiotest:Ratiotest:Ratiotest:Ratiotest:
CT ratio can be checked by two generally accepted methods. The voltage method oftesting measures ratio directly by impressing a voltage on the CT secondary with the primaryopen circulated, while reading primary and secondary voltages directly with a high impedancevoltmeter. The current method of determining ratio circulates a known value of current throughthe CT primary while measuring secondary current. Only the latter method is discussed indetail as the same is adopted on T. N. E. B.
PolarityPolarityPolarityPolarity Tests:Tests:Tests:Tests:
CT polarity can be determined by three generally accepted methods.
(1) The DC voltage test momentarily imposes a small DC voltage on one side of a C.T andthe direction of the momentary deflection of a milliammeter on the opposite side of theCT is noted and compared with polarity marks.
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CHAPTER-II
(2) The AC voltage test utilizes an osiloscope to compare the instantaneous values ofvoltage on the primary and secondary of a C.T while an AC voltage is impressed on thesecondary.
(3) The current method compares the polarity of the CT under test with that of a C.T.whose polarity is known by circulating current through both and measuring thedifference.
The first method is discussed in detail.
ExcitationExcitationExcitationExcitationTest:Test:Test:Test:
Excitation Tests are made to assure the CT is capable of developing its publishedsecondary terminal voltage without excessive excitation current. An excitation curve is plottedby applying various values of an AC voltage below saturation level to the secondary with theprimary open circuited. While measuring secondary current and voltage substantial deviationsfrom published curves should be investigated (or from the curves obtained duringcommissioning) and may indicate a turn to turn short circuit or a completed magnetic patharound the CT core.
Inter-coreInter-coreInter-coreInter-core coupling:coupling:coupling:coupling:
In many instances several secondary cores are mounted in close proximity on the sameprimary lead. It is possible, through failure of grading shields or CT support structures, to havecoupling between cores which is not detectible by excitation tests, but it is still substantialenough to improperly operate bus differential relays. The presence of abnormal coupling canbe detected by reading open circuit voltage on CT’s adjacent to a CT being excitation tested.
CT SATURATION:In present day power system, increased concentration of generation has caused
considerable increase in the ratio of the fault current to the normal load currents. Also in EHVnetworks increased reactance to resistance ratio causes slow decay of the d. c. component in theshort circuit current. The time constants of the decay of d. c. transients. Can be as high as 300m secs. The D. C. component in the magnetizing in rush current of a large power transformerhave still longer time constants. For a fault close to a generator the fault current may not touchthe zero current axis for several cycles. Saturation of a conventional current transformer undersuch situation can be avoided only by choosing the cross sectional area of their cores to beseveral times larger than that needed for the transformation of symmetrical current of the samepeak value.
21
CHAPTER-II
A CT used with slow speed protective relays should not saturate during steady statefault current. It may be allowed to saturate due to d. c. component in the fault current as theprotective relays energised with are slow, these operate only after the d. c. component decaydown.
CTs when driven above their knee point voltage can create substantial distortion in thesecondary current as well as reducing the rms value of that current. The fundamentalcomponent (frequency) is thus reduced by a larger factor than implied by the ratio error,causing non-operation of the relay, or slow operation of the relay.
The CT core may be of iron or air; Iron cored CTs have a substantial power output butare subject to many errors, both static and transient. Air cored CTs have linear characteristicswith no transient errors and are called linear couplers, but these CTs have a low power outputwhich is generally inadequate for electro magnetic relays but suitable for static relays.
Fig 2. Shows the magnetic characteristic of the iron lamination materials commonly used forCT cores. It will be seen that steel with very low exciting current tends to saturate at lower fluxdensities.
Effect of Remnance in iron core:
Remnance – the ability of a material to retain magnetization, equal to the magnetic fluxdensity of the material after the removal of the magnetic field – Also called retentivity.
The CT core may saturate prematurely at currents well below the normal saturationlevel due to the existence of remnant flux. Unfortunately cold rolled silicon steel, which isfavoured nowadays because of its high saturating level, has high remanence so that the recentoccurrence of a heavy fault may leave a remanent flux high enough to cause saturation when asecond fault occurs (Remanent – remaining or left over)
Cold rolled silicon steel
Hot rolled silicon steel
High nickel steel
Exciting AT
Flux
Den
sity
Bm
ax
FIGURE : 2
22
CHAPTER-II
Effect of transient D.C.component upon CT flux.
Saturation in CTs may be due to remnance or high primary current and / or high secondaryburden.
TOTOTOTO OVERCOMEOVERCOMEOVERCOMEOVERCOME THETHETHETHE DIFFICULTYDIFFICULTYDIFFICULTYDIFFICULTY OFOFOFOFSATURATIONSATURATIONSATURATIONSATURATION OFOFOFOF CTSCTSCTSCTS
If the CT gets saturated due to heavy fault current, thereby operating time will increaseconsiderably. If it is found that the CT gets saturated the following suggestion can beconsidered to avoid saturation.
1. O/L setting may be adopted as 100% if not already done:
2. Increase of CT Ratio, if possible.
3. As a last resort change the CT with higher VA burden and ALF if necessary.
CURRENT TRANSFORMERS (CTS)Current transformers (CTs) are used.
a) to reduce the power system currents to values low enough for safe measurement inprotective relays
b) to insulate the relay circuits from the primary circuit andc) to permit the use of standardized current ratings for relays.
Time
Mul
tiple
sof
stea
dyst
ate
flux
Flux Withoutd.c. component
Flux With d.c.component
23
CHAPTER-II
1.1.1.1. Polarity,Polarity,Polarity,Polarity, TerminalTerminalTerminalTerminal markingmarkingmarkingmarking’’’’ssss
The relative polarities of CT primary and secondary terminals are identified either bypainted polarity marks or symbols.
P1 and P2 for the primary terminals
S1 and S2 for the secondary terminals
or
1S1 1 S2 for the secondary terminals of2S2 2 S2 of CTs having 3 cores.3S3 3 S 2
The convention is that when primary current enters the P1 terminal, secondary currentleaves the S1 terminal as shown by the arrows in Fig. 5. (or when current enters the P2 terminal,it leaves the S2 terminal.
Since a. c current is continually reversing its direction, one might well ask what thesignificance is of polarity marking. Its significance is in showing the direction of current flowrelative to another current or to a voltage as well as to aid in making proper connections.
If CTs are not interconnected or if the current from one C. T. did not have to Co-operatewith a current from another CT or with a voltage from a voltage source to produce somedesired result such as torque in a relay, there would be no need for polarity marks.
1S1 1S2
P1 P2
2S2 3S1 3S22S1
FIGURE: 5
S1
P2P1
S2
24
CHAPTER-II
PolarityPolarityPolarityPolarity ofofofof instrumentinstrumentinstrumentinstrument transformers:transformers:transformers:transformers:
When instrument transformers are used with measuring or control devices that respondonly to the magnitude of the current or voltage, the direction of current flow does not affect theresponse and the connections to the secondary terminals can be reversed without affecting theoperation of the devices. When instrument transformers are used with measuring or controldevices that respond to the interaction of two or more currents, the correct operation of thedevices depends upon the relative phase positions of the currents in addition to the magnitudes.To show the relative instantaneous directions of current flow one primary and one secondaryterminal are identified with a distinctive polarity marker, these indicate that at the instant whenthe primary current is flowing into the marked primary terminal the secondary current isflowing out of the marked secondary terminal.
MarkingsMarkingsMarkingsMarkings ofofofofCTSCTSCTSCTS shallshallshallshall bebebebe asasasas indicatedindicatedindicatedindicatedbelow:below:below:below:
(1) SINGLE RATIO CT (2) CT WITH INTERMEDIATE TAPPINGON
SECONDARY WINDING.
S2 S2 S3S1S1
P2P1 P1P2
2S22S11S21S1S2
P1
C1
P1
C2
S1
P2P2
(3) CT WITH PY WINDING IN 4) CT WITH TWO SECONDARYTWO SECTIONS INTENDED WINDINGSFOR CONNECTION EITHERIN SERIES OR PARALLEL
25
CHAPTER-II
Primary Series connection gives – 2 turns P1- C2- C1- P2Primary parallel Connection gives – 1 turn P1C1 – P2 C2.
2.2.2.2. CTCTCTCTMANGETISINGMANGETISINGMANGETISINGMANGETISING CHARACTERISTICS:CHARACTERISTICS:CHARACTERISTICS:CHARACTERISTICS:
The working range of a protective CT extends over the full range between the ankle andthe knee points and beyond, whereas the measuring CT usually operates in the region of theankle point.
The major difference in requirement between those for metering and those forprotection is that with the former, specified accuracies are essential over a range of primarycurrent about 5% full load upto 125%. Whereas the protective purposes, we are concerned withaccurate secondary reproductions of the primary currents from about full load upto those ofshort circuit magnitude, the latter being many times full load. It is therefore a primaryrequirement, that protective CTs should have a high saturation level. Whereas those formetering should preferably saturate at low level, thus protecting the connected instruments ormeters against over currents. The point at which a CT begins to saturate is known as the kneepoint on the curve of its magnetising characteristic and is by definition, the point where theexciting current increases by 50% for a 10% increase in secondary voltage typically as shownin figure.
It is very difficult to avoid saturation of protective CTs during short circuit condition;the effect of saturation is the reduced output hence reduced speed of over current relays.
10% Increase insecondary voltage
KNEEPOINT
50% Increase inexciting current
SECO
ND
ARY
VO
LTA
GE
EXCITING CURRENT
26
CHAPTER-II
Figure shows, the characteristics of two CTs both for the same rated burden, but one forprotection and the other for metering. It is quite obvious that a core of larger cross sectionwould be required for a protective CT if the material has to be the same.
CAUTION:CAUTION:CAUTION:CAUTION:
The relays should not be connected to the metering characteristic CTs and the metersshould not be connected to the protective characteristic CTS. If connected meter will bedamaged and the relay will be inactive during faults.
DUALDUALDUALDUAL PURPOSEPURPOSEPURPOSEPURPOSE APPLICATION:APPLICATION:APPLICATION:APPLICATION:
The requirements for a protective current transformer differ radically from those from ameasuring CT. A measuring CT has to be accurate within the specified working range of ratedcurrent. Accuracy is not required on high over current, it is in fact, an advantage if the CTsaturates at a moderate over current, since this tends to relieve the measuring instruments of thesevere strain caused by heavy over current. A protective CT has to be accurate within theappropriate limits at all higher values of current upto the rated accuracy limit primary current,whereas on the otherhand it is not usually required to be accurate below rated current.
It follows that the difficulties of producing a dual purpose CT are accentuated whenhigh accuracy is required for measuring purposes or a when a high accuracy limit factor isneeded for protective purposes or both.
EXCITING CURRENT
KNEEPOINT
SECO
ND
AR
YV
OLT
AG
E
Protective CTCharacteristic
KNEE POINT
Meetering CTCharacteristic
27
CHAPTER-II
The question of using a single CT for the dual purpose of protection and measurementmay be decided by considering all relevant factors such as design, cost, space and the capabilityof the instruments of withstanding high currents.
A CT for the dual purpose of protection and measurement will have both a protectionand a measurement rating.
When dual purpose CTs are used it should be ensured that under maximum fault currentno damage is caused to meters and instruments. When such a CT is used for both purposessimultaneously and the rated burdens for measurement and protection differ, the totalconnected burden shall not exceed the lower of the two rated burden.
RatedRatedRatedRated accuracyaccuracyaccuracyaccuracy limitlimitlimitlimitprimaryprimaryprimaryprimary currentcurrentcurrentcurrent
The value of the current assigned by the manufacturer as the highest primary current atwhich the CT will comply with the appropriate limits of composite error under specifiedconditions.AccuracyAccuracyAccuracyAccuracy limitlimitlimitlimit factorfactorfactorfactor – The ratio of the rated accuracy limit primary current to the ratedprimary current.
The standard accuracy limit factors shall be 5, 10, 15, 20 and 30.
AccuracyAccuracyAccuracyAccuracy classclassclassclass
5P 10P 15P (P means protection)
3.3.3.3. RATEDRATEDRATEDRATED BURDENBURDENBURDENBURDEN
The burden on a protective CT is composed of the individual burdens of the associatedrelays or trip coils, instruments (when used) and the connecting leads.
When the individual burdens are expressed in ohmic values, the total burden may becomputed by addition. This total ohmic burden should then be converted to a VA burden at therated secondary current.
When the individual burdens are expressed in terms of VA, it is essential to refer theVA values to a common base before they can be added together to form the total computedburden. This common base shall be the rated secondary current of the CT.
Normally the standard VA rating nearest to the burden computed should be used, butattention is drawn to the fact that a device may have an impedance with one or more of thefollowing characteristics.
28
CHAPTER-II
1. The impedance is constant, regardless of the current setting subject to 4 below (for exampleuntapped relay coils).
2. The impedance changes with the current settings (notably in trip coils and relays withtapped coils)
3. The impedance decreases when the current passing through the coil exceeds the currentsetting.
4. The impedance changes with the changed position of the armature of the relay or trip coil.
For correlation of Burden and Accuracy limit factor refer IS 2705 (Part III) – 1964. Also IS4201/1967.
All accuracy considerations require knowledge of the CT burden. The external loadapplied to the secondary of a CT is called the burden.
The error of a CT increases with the resistance of its secondary external circuit.Therefore its rated secondary burden in ohms or rated capacity in VA is usually indicated bythe manufacturer.
The rated secondary burden of a CT is the maximum resistance that can be connected toits secondary winding without exceeding the permissible error specified for the given class ofaccuracy.
The number of electrical measuring instruments that can be safely connected to a singleCT is determined by the total resistance of the instruments and the connecting leads. This valueshould not exceed the burden of the CT.
EXAMPLEEXAMPLEEXAMPLEEXAMPLE NO.1NO.1NO.1NO.1
Determine, whet her an ammeter having a resistance of 0.2 ohm and the current windingof a wattmeter having a resistance of 0.2 ohm can be connected to a single 0.6 ohm CT ifcopper conductor leads of 20 meter length and 4 sq mm cross section are used for connectingthe instruments.
i) The resistance of lead r = P l/s
= 0.0175 X 20/4
≅ 0.09 ohm.
The impedance (z) of the secondary external circuit of CT is equal to the geometric sumof impedances of the current windings of the connected instruments and the leads.
For an approximate solution it is sufficient to add the impedances arithmatically ie.neglect the comparatively low reactances of the windings.
29
CHAPTER-II
Thus, the total resistance of the secondary external circuit is found to be
= 0.09 + 0.2 + 0.2 = 0.49 ohm.
This resistance (0.49ohm) is less that the rated burden of the CT (0.6 ohm) consequentlyquite allowable.
EXAMPLEEXAMPLEEXAMPLEEXAMPLE NO.NO.NO.NO. 2222
CALCULATE the V A output required for a CT of 5 A rated secondary current whenburden consists of relay requiring 10 VA at 5A plus loop lead resistance 0.1 ohm suggestchoice of CT.
VA required to compensate = I2 R = 5 X 0.1loop lead resistance = 2.5 VA
Relay burden at 5 A : = 10 VA-----------
TOTAL VA outputrequired = 12.5 VA
--------------Hence a CT of rating 15 VA and secondary current 5A may be used.
4.4.4.4. COMMONCOMMONCOMMONCOMMONPRACTICEPRACTICEPRACTICEPRACTICE TOTOTOTO USEUSEUSEUSE ““““1A1A1A1A”””” CTCTCTCTRATHERRATHERRATHERRATHER THANTHANTHANTHAN ““““5A5A5A5A”””” CTCTCTCT
If the distance between CTs and measuring instruments or relays are appreciable, it iscommon practice to use the CT whose rated secondary current is equal to 1A. In this case, thesecondary circuit resistance of a CT may be 25 times that of the CT whose secondary current isequal to 5A.
This will be explained as below:
Saturation of the CT may cause no inconvenience and may even be desirable for itslimiting action in the case of switch board instruments (ie. CTs for metering) but obviously itcould seriously upset the performance of a time current relay or any form of comparator relaysuch as differential relay or a distance relay during heavy faults. Saturation can be avoidedeither by increasing the cross section of iron cores of CT or by reducing the burden. The firstmethod is expensive and the second may be difficult. The burden on the CT is due to theresistance of the relay, the CT secondary and the leads. For a given performance, the relayburden can not be reduced except by changing its design. On the other hand the lead burdencan be reduced by using a lower secondary current rating.
For instance in a large station with long runs from the switch yard to the relay panel(like ERODE 110/22 KV GRID STATION), the lead resistance may be as 6 ohms.
30
CHAPTER-II
With a 5A CTs the normal burden imposed by the 6 ohm leads isI2 R = 52 x6 = 150 VA
In order not to saturate with a fault current, twenty times normal, the iron circuit wouldhave to be large enough to avoid saturation below. 600 V.(IR = 20 x 5x6 = 600 Volts). This would require quite a large CT, on the other hand with a 1 ACT secondary rating, the lead burden would be I R = 1 x 6 = 6 VA. The resistance of thesecondary of the 1 A CT would be about 5 ohms compared with 0.2 ohm for the 5 A CT.
5 A CT 1 A CT
Resistance of the Resistance of the
Secondary of 5A CT = 0.2 ohm secondary of 1A CT = 5 ohmlead resistance = 6.0 ohm lead resistance = 6 ohm
---- ----Total = 6.2 ohm total = 11ohm
---- ----Total burden = I2 R total burden = I2 R
= 52x6.2 = 12x 11= 155 VA = 11 VA
Maximum voltage = 20 x IR Maximum voltage = 20x IR= 20x5x6.2 = 20x1x11
= 620 Volts = 220 Volts
Actually for mechanical reasons, the size of the CT wire is not scaled down inproportion to the current and the maximum voltage would be nearer 150 Volts.
CT.CT.CT.CT. REQUIREMENT:REQUIREMENT:REQUIREMENT:REQUIREMENT:
NOTE: To ensure that the relay operating times are not unduly affected by CTsaturation, they should be capable of developing aaaa kneepointkneepointkneepointkneepoint voltagevoltagevoltagevoltage sufficientsufficientsufficientsufficient totototo circulatecirculatecirculatecirculate 20202020timestimestimestimes thethethethe plugplugplugplug settingsettingsettingsetting currentcurrentcurrentcurrent through the relay for phase and earth faults.
VT.VT.VT.VT. REQUIREMENT:REQUIREMENT:REQUIREMENT:REQUIREMENT:
The residual voltage transformers (RVT) for voltage polarised directional earth faultrelays should confirm to an accuracy class 10.
It is important that for the correct reproduction of residual voltage across the brokendelta winding of the voltage transformers either three single phase VT or one three phase, fivefivefivefivelimblimblimblimbVTVTVTVT should be used.
31
CHAPTER-II
5.5.5.5. CTsCTsCTsCTs PERFORMANCEPERFORMANCEPERFORMANCEPERFORMANCEANDANDANDAND SELECTIONSELECTIONSELECTIONSELECTION OFOFOFOFCTs.CTs.CTs.CTs.
The performance of a CT is normally related to the rated primary circuit, but if there is asignificant difference, the effects of this on the performance need to be studied, particularly onthe fault setting and on stability. On systems where the fault current is high and full loadcurrent is low, it may be necessary to choose CTs with primary current ratings related to thefault current rather than ratings related to full load currents.
6.6.6.6. FAILUREFAILUREFAILUREFAILURE OFOFOFOFCTSCTSCTSCTS
CTs are unlikely to fail in themselves, but they may be inadvertently short circuited by atest link having been left in the wrong position during maintenance testing; also a CT insulationmay breakdown if the secondary circuit is accidently opened.
It is therefore important to design test gear and switch board components so that there isno risk of open circuiting the secondary of a CT because in this condition it can produce anextremely high secondary voltage which may breakdown the insulation and destroy CT. Thisis because although the CT iron may saturate at a sinusoidal secondary voltage of a fewhundred, the rate of change of flux near the zero points of the cycle can produce enormousvoltage peaks.
CAUTION:CAUTION:CAUTION:CAUTION:
If there is any inadvertent opening in the secondary circuit of a CT, the CT should bechecked for its magnetising characteristic and for its insulation.
ABB Ltd: Current Transformer oil minimum type
Make Type IMB – 145 KV
TanTanTanTan DeltaDeltaDeltaDeltaMeasuringMeasuringMeasuringMeasuring Terminal.Terminal.Terminal.Terminal.
The outer shield of primary insulation is brought out through a bushing in the secondaryterminal box and earthed. This is designated as D3 terminal.
32
CHAPTER-II
For periodical preventive check tan delta of complete primary insulation can bemeasured by opening earthing link of D3 terminal and connecting tan delta measuring bridge atthis point. This measurement will give total picture of health of PrimaryPrimaryPrimaryPrimary insulation.insulation.insulation.insulation.
There are three cores. One is class 1.0 and the other two PS Class. Class 1.0 ismetering core. PS class core are protection core. This should be ensured by conductingmagnetising characteristic. Metering core will have a very low knee point voltage (say 65 V).Whereas the protection core knee point voltage will be > 750 V.
CAUTION:CAUTION:CAUTION:CAUTION:
1) Relays should be connected to the protection core and Ammeter should beconnected to the Metering core.
2) Secondary winding notnotnotnot beingbeingbeingbeing usedusedusedusedmust be short-circuitedshort-circuitedshort-circuitedshort-circuitedandandandand grounded.grounded.grounded.grounded.
3) Secondary terminals must be short-circuited before the burden is disconnected.
4) Ensure D (Tan delta) Bushing connection with earth.
5) Higher CT ratio means higher knee-point
Voltage For 600/1 – 780 V For 300/1 = 390 V
For 150/1 = 195 V
CTsCTsCTsCTs TESTINGTESTINGTESTINGTESTING
The following tests are carried out on CTs.
1. Polarity check
2. Ratio check
3. Magnetization curve.
4. Measuring insulation resistance of C.T. secondary windings (Caution: only 500 Vmegger should be used)
33
CHAPTER-II
1.1.1.1. POLARITYPOLARITYPOLARITYPOLARITY CHECK:CHECK:CHECK:CHECK:
Polarity check is necessary to see the relative polarity of the primary and secondaryterminals when terminals are not marked or to establish the correctness of the marking ifalready marked. In otherwords the polarity checking consists actually in making sure that thedesignations P1 and P2 made on the leads of the primary winding and S1 and S2 made on theleads of the secondary winding corresponds to thethethethe windingwindingwindingwinding startstartstartstart andandandand FinishFinishFinishFinishends.ends.ends.ends.
34
CHAPTER-II
The d. c. source, a dry cell or storage battery of 4-6 V is connected in series with theprimary winding of the CT through switch. The positive pole of the battery is connected to thebeginning of the primary winding and the negative pole to the end of the primary.
While closing and then opening switch, watch the indicating instrument connectedacross the secondary winding to see in which direction its pointer deflects. If, when theprimary circuit is closed, the pointer deflects to the right and then deflects to the left when thecircuit is broken. It is a sign of like polarity (and correct marking) of the CT primary andsecondary terminals, one of the which connected to the positive pole of the battery, the other tothe positive terminal of the indicating instrument.
2.2.2.2. CHECKINGCHECKINGCHECKINGCHECKING CURRENTCURRENTCURRENTCURRENTRATIO:RATIO:RATIO:RATIO:
The ratio of the CT is checked by dividing the value of the primary current I1, by that ofthe secondary current I2 and comparing it with the rated value.
35
CHAPTER-II
IDENTIFYINGIDENTIFYINGIDENTIFYINGIDENTIFYING ANDANDANDANDMARKINGMARKINGMARKINGMARKING OFOFOFOFBUSHINGBUSHINGBUSHINGBUSHINGCTs.CTs.CTs.CTs.
When bushing CTs are being checked, it is also necessary to make sure that their tapleads are correctly marked. This can be done while checking the current ratios.
In cases when the tap leads have no markings, the simplest circuit for identifying andthen marking them is that shown in Figure…
A voltage from the auto transformer (AT) (Variac) is applied first to any two of the tapleads. Then by measuring the voltage between each pair of the CT tap leads, the pair with thegreatest voltage will be extreme (beginning and end) leads corresponding to the largest currentratio. The voltage from the auto-transformer is now applied to the two extreme tap leads,following which the voltage between one of the extreme leads and all the other leads ismeasured to check the voltage distribution along the winding. When the lowest voltage isobtained, it corresponds to the position for the least current ratio. According to the voltageobtained above all the leads can be marked and then compared with the manufacturer’s diagramfor the distribution of the turns between the taps.
NOTE:NOTE:NOTE:NOTE: The ratio check is also usually carried out during the primary injection test describedlater. The ratio of the readings of the ammeters in the primary and secondary circuit of the CTunder test is taken which should approximate to the ratio marked on the CT.
36
CHAPTER-II
3.3.3.3. MAGNETIZATIONMAGNETIZATIONMAGNETIZATIONMAGNETIZATION CURVE:CURVE:CURVE:CURVE:
CTs intended for different purposes will have different magnetization characteristics.On a single bushing there may be several CTs of the same ratio, but differing characteristics toperform different duties such as protection, metering or operation of ammeters only. Amagnetization test is a convenient method for identification of the different CTs which willhave differing knee points.
The curve showing the voltage across the terminals of the secondary winding in a CT asa function of the current in the winding, known as the Magnetization characteristic is thereforeof prime importance.
To obtain the data for plotting the magnetization characteristic the primary circuit is leftopen circuited and an ac voltage is applied across the secondary winding with the aid of testingauto transformer (AT) Figure …..
By raising the voltage one step at a time, readings of the corresponding current aretaken with the ammeter. When commissioning, data for 10-12 points are thus obtained forplotting the characteristic. During all subsequent scheduled checks during service, data for 3-4points are obtained to make sure that the characteristic has not changed and the points coincidewith the curve of the first characteristic. It is best to take the characteristic upto saturation i. e.to a point where further increase in the current passed through the winding is not accompaniedby noticeable rise in the voltage.
CAUTION:CAUTION:CAUTION:CAUTION:
Prior to taking the readings for the characteristic and after they are obtained, the core ofthe CT should be demagnetized by slowly raising the voltage to a high value and then slowlyreducing it to zero two or three times.
HOWHOWHOWHOWTOTOTOTO FINDFINDFINDFINDCTSCTSCTSCTSWITHWITHWITHWITH SHORTEDSHORTEDSHORTEDSHORTED TURNS.TURNS.TURNS.TURNS.
If some of the turns in the secondary are shorted, the characteristic will be much lowerthan normal. This defect is detected by comparing the characteristic just obtained with the oneplotted at an earlier date or with that of an identical CT. Deviation from normal in the case ofshorted turns is most noticeable in the magnetization characteristics over the initial range ofmagnetization where the current from 0.1 to 1A. See Figure…
37
CHAPTER-II
MAGNETIZATION CHARACTERISTICS OF A NORMAL CT AND ONE WITH SOMEOF THE TURNS SHORTED.
200V200V200V200V
1 2 3 4 5
EXCITINGEXCITINGEXCITINGEXCITING CURRENTCURRENTCURRENTCURRENT
SECONDARY
SECONDARY
SECONDARY
SECONDARYVOLTAGE
VOLTAGE
VOLTAGE
VOLTAGE NORMALNORMALNORMALNORMAL CTCTCTCT
CTCTCTCTWITHWITHWITHWITH SHORTEDSHORTEDSHORTEDSHORTED TURNSTURNSTURNSTURNS
38
CHAPTER-II
PHASEPHASEPHASEPHASE ANGLEANGLEANGLEANGLEERROR.ERROR.ERROR.ERROR.
− The phase angle error for the protection CTs is not normally measured as the burdenon the secondary of the CT is generally of such highly lagging power factor that thesecondary current is practically, in phase with the exciting current and hence theeffect of the exciting current on the phase angle accuracy is negligible.
THETHETHETHE REQUIREMENTREQUIREMENTREQUIREMENTREQUIREMENT OFOFOFOF CTsCTsCTsCTs FORFORFORFOR OVEROVEROVEROVER CURRENTCURRENTCURRENTCURRENT PROTECTIONPROTECTIONPROTECTIONPROTECTION FORFORFORFOR HVHVHVHVFEEDERSFEEDERSFEEDERSFEEDERS LIKELIKELIKELIKE 11111111 KV,KV,KV,KV, 22222222 KV,KV,KV,KV, 33333333 KV,KV,KV,KV, ANDANDANDAND 66666666 KVKVKVKV FEEDERSFEEDERSFEEDERSFEEDERS ANDANDANDANDTRANSFORMERS:-TRANSFORMERS:-TRANSFORMERS:-TRANSFORMERS:-
The requirement of CTs for over current protection for HV feeders, is normally met by ISS: IS2705 – Part III.
The following are the major requirement.
1. Burden
2. Accuracy class
3. Rated Accuracy limit factor.
39
CHAPTER-II
1.1.1.1. BURDEN:BURDEN:BURDEN:BURDEN:
The impedance of the secondary circuit expressed in ohms and power factor. Theburden is usually expressed in volt-ampere absorbed at a specified power factor and at ratedsecondary current. The impedance of the secondary circuit is normally vectorial addition ofburden of relay, cable leads and any meters, connected in series.
2.2.2.2. ACCURACYACCURACYACCURACYACCURACY CLASS:CLASS:CLASS:CLASS:
Standard accuracy classes are 5P, 10P, and 15P and their details of error are as notedbelow:
Sl. Class Ratio error phase displace- compositeNo. at Rated ment at rated error at
primary current primary current rated accuracylimit primarycurrent.
1. 5 P ± 1% ± 60 minutes 5%
2. 10 P ± - 3% ’’ 10%
3. 15 P ± 5% ’’ 15%
3.3.3.3. RATEDRATEDRATEDRATED ACCURACYACCURACYACCURACYACCURACY LIMITLIMITLIMITLIMIT FACTOR:FACTOR:FACTOR:FACTOR:
The value of the accuracy limit factor for which the accuracy requirements of thisspecification are met at rated burden.
SPECIFICATIONSPECIFICATIONSPECIFICATIONSPECIFICATION OFOFOFOFCTSCTSCTSCTS FORFORFORFOR HVHVHVHV FEEDERS:FEEDERS:FEEDERS:FEEDERS:
Normally for 11 or 22 KV feeders, the specification of CTs is as below:
“400-200400-200400-200400-200 /1/1/1/1 AmpAmpAmpAmp 15151515(or(or(or(or 30)30)30)30)VAVAVAVA 5P5P5P5P15151515”
It means that when primary current 200 Amps flows, the secondary current will be 1amp and can feed a burden of 15 ohms (30 ohms). When primary current reaches 15 times(during fault conditions) it can be still feed the burden of 15 ohms and the composite error willnot exceed 5555 percentpercentpercentpercent in the transformation.
40
CHAPTER-II
HOWHOWHOWHOW DOESDOESDOESDOES THISTHISTHISTHIS SPECIFICATIONSPECIFICATIONSPECIFICATIONSPECIFICATION OFOFOFOF CTSCTSCTSCTS REALLYREALLYREALLYREALLY MEETMEETMEETMEET UNDERUNDERUNDERUNDERPRACTICALPRACTICALPRACTICALPRACTICAL SITUATION:-SITUATION:-SITUATION:-SITUATION:-
In Tamilnadu Electricity Board, it is normal practice to provide two over current IDMTrelay and one earth fault IDMT relay with instantaneous element as drawn in the diagram.
The burden of the IDMT relay at 100% plug setting is 3 VA. For one 1 amp rated relayit is equal to 3 ohms. For over current relay it is normal practice to adopt 100% and for earthfault relay it is 40% plug setting.
For O/L element the burden is 3 ohm (z)
For E/L element I2z = 3
(0.4)2z=3
z = 3/(0.4)2 = 3/0.16 = 18.7 ohm
The burden of instantaneous element is 5 VA or 5 ohm.
Hence the total burden in series for an earth fault will be
= Z O/L inst + Z O/L IDMT + Z E/L inst + Z E/L IDMT
= 5 + 3 + 5 + 18.7 = 31.7 ohms.
The current practice in TNEB is to use CT of 30 VA 5P 15 capacity. The CT willdevelop 450 volts as its output. (ie. 30x15 = 450). The impedance (Z) and current can vary sothat the product should not exceed 450 V. In a sub-station, where 3 Nos. 110 KV/22 KV 10MVA transformers with 10% impedance are provided, the fault MVA will be 300; wheninfinite Bus is assumed on H. V. side (110 KV). Under actual condition the fault MVA will beabout 2/3 of this value ie. 200 MVA. The fault current (If) on L. V. side (22 KV side) will beabout 5200 Amps.
(√3x22xIf = 200x103 KVA)
If = 200 x 103/√3 x 22 ≈ 5249A
When 300/1 amp CT is used, CT secondary current will be 17.3 amp [5200/300 = 17.3]Apparantly it may look that with 31.7 ohm burden, CT will not develop sufficient voltage todrive this current.
31.7 x 17.3 = 548.4V
But in case of IDMT relay as current increases, corecorecorecore inininin thethethethe relayrelayrelayrelay saturatessaturatessaturatessaturates andandandand thethethetherelayrelayrelayrelay burdenburdenburdenburden willwillwillwill reducereducereducereduce totototo 40%40%40%40%ofofofof itsitsitsits valuevaluevaluevalue atatatat 10%10%10%10%timestimestimestimes thethethethe currentcurrentcurrentcurrent setting.setting.setting.setting. So the O/Land E/L burden (of IDMT relays) (3+18.7) = 21.7 ohms will be reduced to
41
CHAPTER-II
3 x 40/100 + 18.7 x 40/100 = 8.68 ohms.
and the total burden of IDMT and instantaneous relays will be 8.68 + 5+5 = 18.68 ohms.
The CT will have to develop 18.68 x 17.3 = 323-16V only. The relay will correctly act.
OPERATION:
In a current transformer the primary ampere-turms must be equal the sum of theseconddary ampere-turms and the magnetising ampere-turms (Ie)
N1I1 = N2 (I2 + Ie)
OPENOPENOPENOPENCIRCUTEDCIRCUTEDCIRCUTEDCIRCUTED CURRENTCURRENTCURRENTCURRENT TRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER
If the load (Burden) impedances Rb+jXb is very high, then the voltage calculated from I2(R2+Rb+jXb) would be very large, (Where R2 is secondary winding resistance) Well aboveKnee-point voltage (as a rough guide the knee-point voltage is the product of the VA rating andthe accuracy limit factor / the rated secondary current) and Ie would become significantly largein the ampere-turn balance equation N1I1 = N2(I2+Ie) and I2 would be reduced. The limitingvalue is when the CT secondary winding is open circuited and I2 = 0. All the input ampere-turns will be used as magnetising ampere-turns and will drive the current transformers intosaturation the greatly increase magnetising current will not cause much increase to the averagevoltage. However the change in flux from 0 to the knee-point value is not accomplished in ¼thcycle but in perhaps 1/100 of this time thus the ratio of change of flux and, therefore theinduced voltage during this period would be about hundred times the knee-point voltage.Insulation can be damaged by this high short duration voltage and overheating caused by thegreat increase of iron losses.
RRRR
YYYY
BBBB
CTCTCTCT
CTCTCTCT
CTCTCTCT E/LE/LE/LE/L
IDMTIDMTIDMTIDMT
INSTINSTINSTINST IDMTIDMTIDMTIDMTO/LO/LO/LO/L
INSTINSTINSTINST
IDMTIDMTIDMTIDMTINSTINSTINSTINST
O/LO/LO/LO/L
42
CHAPTER-II
B.2.4. CURRENT TRANSFORMERTESTS CHECK LIST
ALL CTs ARE TO BE TEST ED FOR THE FOLLOWING TESTS.
1. INSULATION RESISTANCE TEST IS DONE WITH 500 VOLTS MEGGER.
2. C.T INTERNAL RESISTANCE AND LEAD RESISTANCE IS MEASURED WITHWHEATSTONE BRIDGE.
3. POLARITY TEST OR FLICK TEST WITH A SIMPLE BATTERY.
4. PHASE IDENTIFICATION OF CT CABLES BY INJECTING A SMALL D.CVOLTAGE DIFFERENT FOR ALL THREE PHASES.
5. MAGNETISATION TEST.
IT IS DONE TO CHECK KPV (KNEE POINT VOLTAGE) WHICH IS DEFINED ASTHE SECONDARY VOLTAGE AT WHICH AN INCREASE OF 10% IN VOLTAGEWILL RESULT IN AN INCREASE OF 50% IN THE MAGNETISING CURRENT.
43
CHAPTER-IIICHAPTER-IIICHAPTER-IIICHAPTER-III
POTENTIALPOTENTIALPOTENTIALPOTENTIAL TRANSFORMERSTRANSFORMERSTRANSFORMERSTRANSFORMERSEr. K. MOUNAGURUSAMY
Design of a Potential transformer is similar to that of a power transformer, but theloading of the Potential transformer is only a few VA. Accuracy in design is more importantthan efficiency.
Due to short circuit fault, the transient D. C. component in the line voltage is less andthat too occurs when the A. C. component is low, therefore a Potential transformer is notrequired to be oversized to handle the transient conditions.
Voltage drop in the secondary leads should be well taken into account. This canseriously falsify the accuracy of measurement. Take the case of V. T. with burden of 300 VAin 57.7 V secondary and the lead resistance (for Exp. 100 m, double core 2.5 mm2
RL = 1.44 ohms)
Current in P. T. = 300/57.7 = 5.2 A
•• • Voltage drop = 5.2 x 1.44 = 7.5 V.
This accounts to 13%
Such drops will make the distance relays over reach by equal percent. A seriousproblem. Hence 6 Sq.mm cables are advised for P. T. circuits.
CAPACITANCECAPACITANCECAPACITANCECAPACITANCE VOLTAGEVOLTAGEVOLTAGEVOLTAGE TRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER
PERFORMANCE POINT OF VIEW:
The transient response of the CVT depends on the following :
1. Point on the primary voltage wave where the fault occurs.
2. The value of equivalent capacitance, which is dependent on three items namelyCapacitor rating, Tap position, Turns ratio of the Intermediate voltage transformer.
3. Magnitude and power factor of the burden.
Composition and connection of the burden for the same burden and power factor theburden can be made up of parallel and series components.
44
CHAPTER-III
4.Type of ferro resonant damper circuit.
For well designed transformer the exciting current of intermediate transformer ispurposely kept low of the order of 2 to 3 ma and does not adversely affect the response.
To see the effects of various important parameters, it is assumed that a single phaseground fault occur at the CVT location itself. Only resistance burden is considered. Twoextreme conditions (a) fault at peak of voltage and (b) fault at zero point on the primaryvoltage wave.
i1 (O) = V1 max/R4
Vc (O) 1 0
On analysis, the following conclusion are arrived.
For fault at the peak of voltage the transient component decays very fast.
For fault at zero point on the voltage wave transient will decay slowly.
The magnitude of the transient output voltage (for fault on zero point of voltage wave) willdecrease with increase in equivalent capacitance value but duration will be increased due tocorresponding decrease in value of equivalent conductance value. With the increase in burden(decrease in the magnitude of the resistine burden) CVT performance will further worsens forfaults at the zero point of the wave.
The voltage transformers are normally connected phase to earth. In the event ofdisturbance in the network the voltage across the VT ’s (CVT’s ) will be increased in thehealthy phases.
IEC specifies the voltage factors:
19 for systems not having solidly earthed
15 for solidly earthed system.
The saturation is specified to be 30sec. for systems with tripping earth fault protection and 8hours if no earth fault tripping protection is used.
The VT’s must not be saturated at the voltage factor.
For metering cores a high accuracy for voltages in range (80 - 120%) of nominal voltage isrequired.
45
CHAPTER-III
For protection where disturbance information must be transferred to the secondary side, a loweraccuracy is required but a high capability to transform voltages to allow the protection tooperate and disconnect the fault. Class is 3p.
The 3p class will have measuring error of 3% and an angle of 120 min.
The voltage transformer winding can be given a continued class ie 0.5/3p which meansthat metering accuracy is fulfilled for 80-120% of nominal voltage but the requirement for 5%of nominal voltage and the transient response requirement from protection cores is also fulfilled.
A good transient response is required to the protection transformers and this is aproblem for CVT’s where the energy stored in the capacitive voltage divider and theinterposing voltage transformer will result in a transient voltage oscillation on the secondaryside. The transient oscillation consists of a low frequency components. (2-15Hz) and highfrequency oscillation (900-4000Hz). The time constant for the high frequency part is shortwhere as the low frequency part has long time constants. The amplitude is decided by the faultinception angle. Higher capacitances in the voltage divider gives lower amplitude of the lowfrequency oscillation. The secondary value, one cycle after the short circuit should be lowerthan 10%.
Ferro resonance can occur in circuits containing a capacitor and a reactor incorporatingan iron core (a non-linear inductance). Both the CVT and a magnetic VT can be involved inFerro resonance phenomenon.
Ferro resonance in a magnetic VT is an oscillation between the inductance of the VTand the capacitance of the network. Ferro resonance can only occur at ungrounded networks,but note the risk that some part becomes ungrounded under certain circumstances.
An oscillation is normally triggered by a sudden change in the network voltage.Ferroresonance phenomenon can occur both with sub-harmonic frequencies or with harmonicfrequencies. Generally it is difficult to state when a risk of ferro resonance occurs but as soonas a system with a voltage transformer is left ungrounded under some circumstances,preventive actions should be taken (also consider the risk of capacitive charged systems with aVT). The damping of Ferro resonance is normally done with a 27 – 60 ohms 200 W resistorconnected across the open delta winding. The resistor value should give a current as high aspossible but a current below the thermal rating of the voltage transformer.
The CVT with its capacitor and IVT is by itself a ferro-resonance circuit. Thephenomenon is started by a sudden voltage change. A sub – harmonic oscillation can be startedand must be damped to prevent damage to the transformer. The CVTs must be provided withferro resonance damping devices, normally this consists of a saturating reactor and a resistor ineach phase.
46
CHAPTER-III
COMMISSIONINGCOMMISSIONINGCOMMISSIONINGCOMMISSIONING INSTRUCTIONINSTRUCTIONINSTRUCTIONINSTRUCTION FORFORFORFOR CVTs:CVTs:CVTs:CVTs:
Test Equipments :- Meggar 0.5 or 1 KVBattery box (with atleast three voltage levels).Multimeter class 1.5Phase sequence meterTest leads etc.,
SAFETYSAFETYSAFETYSAFETY PRECAUTIONS:-PRECAUTIONS:-PRECAUTIONS:-PRECAUTIONS:-
The transformer to be tested is to be checked for primary earthing before commencingthe test. If it is not earthed, disconnected bus bars and lines can attain dangerous high voltagelevels due to induction from energised parallel tying busbars or lines.
TESTTESTTESTTEST PROCEDURE:-PROCEDURE:-PROCEDURE:-PROCEDURE:-
1. Data and serial numbers, given in the rating plates of the transformer are to beentered in test record. Ensure that the serial number of each unit of the capacitor voltagedivider is the same as that given on the main rating plates of the each respective transformer.The accuracy classes given for the transformers apply only if the units, that are jointly trimmedat the workshop are mounted together at the site.
Check the oil level in the VT.
Check the connection to the voltage direction of any carrier frequency equipment. Thecoupling unit of the PLC equipment should be connected to the terminal HF which is the lowvoltage terminal of the capacitor stack. On delivery of the transformer this terminal normallyearthed.
If PLC equipment is to be connected to the line, the direct earth connection is toremoved and the voltage divider earthed via the connection unit.
When a transformer is energised, the earthing switch must be closed before any work isdone in the marshalling kiosk. It is extremely dangerous to open the low voltage earthconnection of an energised transformer. If no PLC equipment is connected, make a check toensure that the low voltage terminal is earthed.
The secondary terminal box is to be visually checked for
1. That any spare winding that are not connected to the common marshalling kiosk, are openand earthed at one point.
2. That the correct terminals and connected in the core of multi terminal secondary windings.3. That in the core of multi terminal windings, the unused terminals are left free is not earthed.4. The terminals of damping circuit are connected to each other checking polarity.
47
CHAPTER-III
POLARITYPOLARITYPOLARITYPOLARITY CHECK:-CHECK:-CHECK:-CHECK:-
The check is made by connecting a battery having predetermined polarity, for shortbetween transformers primary terminal and earth. The polarity of the voltage, induced in thesecondary, is checked with the aid of a directionally sensitive voltmeter. The test is similar tothe polarity test of CTs. ie by checking the deflection of the pointer in the secondary connectedvoltmeter when the switch is operated in the primary side.
CHECKINGCHECKINGCHECKINGCHECKING INSULATIONINSULATIONINSULATIONINSULATION RESISTANCE:-RESISTANCE:-RESISTANCE:-RESISTANCE:-
Checking the insulation resistance of the windings and of the voltage circuits betweenthe transformers and the marshalling kiosk.
Check the phase to earth and the phase to phase insulation values when checking thephase to earth resistance, only the earthing terminal block, if the winding being tested os to beopen. All phase terminal blocks of the voltage transformers are to be closed.
CHECKINGCHECKINGCHECKINGCHECKING PHASEPHASEPHASEPHASE RELATIONSHIPS:-RELATIONSHIPS:-RELATIONSHIPS:-RELATIONSHIPS:-
To be performed when the new voltage transformer and the voltage transformer of thereference group have separate infeed on the primary side if they are not connected together.
To be performed when the new voltage transformer and the voltage transformer of thereference group is connected together on the primary side in the sub station.
48
CHAPTER-IVCHAPTER-IVCHAPTER-IVCHAPTER-IV
PRECOMMISSIONINGPRECOMMISSIONINGPRECOMMISSIONINGPRECOMMISSIONINGTESTSTESTSTESTSTESTSEr. K. MOUNAGURUSAMY
CE/P&C
There are debates and difference of opinions about the demarcation betweenpre-commissioning and commissioning tests. Many feel that there can be only one test – eitherpre-commissioning or commissioning.
It is suggested that there should be a demarcation between them. Duringpre-commissioning, every one can work together and separately – people like GCC,Contractors, Civil and Protection Wing. But, during commissioning tests, all others exceptprotection wing should clear the area. This means that once pre commissioning test done,nobody should touch anything except protection people. In this way, pre-commissioninginclude :-
- Visual inspection
- Checking the installation, circuits cabling, wiring connections, etc.
- testing the equipments, relays as individual components
- Meggering of A.C, D.C., C.T., P.T., circuits
- Checking of equipment operations like closing and tripping.
- Adopting relay settings
- Conducting secondary injection
- Corrections in Scheme drawings
- Function & tests
Commissioning tests include:- Primary injection tests
- Energising of individual equipments, step by step
- Energising and commissioning the total system
- Conducting on load testsThese will be discussed item by item in detail.
49
CHAPTER-IV
I. Pre-commissioning Tests:1. Visual inspection – to confirm that the equipment has not been damaged during transit
2. Installation, Cabling and Wiring
- Capacity of cable leads to be checked
- Proper laying of cable to be confirmed
- Cable tags to be provided as per cable schedule
- Spare holes for future cable should be provided in panel plates.
- Care to be taken in glanding the cables the sheath wires should not end within thegland. Atleast 5 mm should protrude out and they should be bent towards outside sothat they will not prick the inner jacket and cause/insulation failure.
- The cable jacket should be removed only by skilled people without damaging thelead insulation. This is a common mistake done by unskilled persons withoutknowing the implications.
- The jacket over the inner leads should protrude out from the gland finishing atleastby 2 Cms. Gland mouths should not be covered with insulation tapes to concealunskilled finishing.
- Cable cores shall be identified at both ends and ferruled properly. In cables withsame colour leads, clockwise – anti-clockwise method shall be used for easieridentifying.
- Lead to lead meggering between all leads individually should be done at this stageitself without fail.
- Any joints to make up short length of one or two cable leads should be prohibitedaltogether.
- If lead connections are done without lugs, the end loop should be made clockwiseonly so that the round loop will not open while tightening screw or stud.
- Only proper lugs should be used. Dispensing with one or two strands of the cores toaccommodate in the undersize lug should be avoided. Likewise the eye of the lugshould not be developed to accommodate the screw or stud.
- Use snugly fitting ferrules
50
CHAPTER-IV
- Each lead should be lugged separately. More than one lead should not be clubbed, inone lug.
- Lugs should not be taped or covered with anything.
- When two lugs are put in one TB, they should face back to back so that there isgood meshing.
- Lugs should be crimped only with correct size crimpers.
- Use correct size screw drivers; use only star screw drivers where star screws areprovided
- use washers always
- Another person should make 100% check of the connection with the drawing andalso the tightness of the lug and screw.
- Bunch spare cores separately and leave their full length; put the cable number asferrules; unconnected individual wire should not be left strayed
- Dress everything neatly.
- Plug out the spare cable holes for vermin proof.
- Clear the loose screws, washers, iron filings dust etc. from the panels.
3. Testing individually:
a) Breakers
- Closing and opening time of main and auxiliary contacts.
- Meggering of H.V. terminals, (a) To earth individually (b) Between poles withbreakers open.
- Meggering of A.C D.C. P.T. and C.T. circuits individually and in between each ofthem.
- Measuring the contract resistance.
- Checking the interlocks.
- Checking the minimum operating voltage level of closing (80%) and trip coils(70%).
51
CHAPTER-IVb) Isolators:
- Control circuits
- Checking of simultaneous closing of main contacts
- Checking auxiliary contact
- Meggering of limbs(Isolators should not be used to break currents in load circuits like PARALLELTRANSFOMERS AND UNLOADED LINES.)
c) P.Ts:
- Meggering of HV windings, secondary windings between H.V. and each secondarywinding
- Measuring the resistance of secondary winding with multimeters.
- Polarity tests.
- Ratio test.
- Checking the earthing.
- After wiring is finished, do the secondary injection in each phase at rated secondaryvoltage ensuring that the test voltage does not reach the P.T. secondary.
- Checking the transfer schemes if more than one P.T. are available.
d) C.Ts:
- Meggering between each windings in secondary- Meggering of H.V.Points- Meggering between H.V. and Secondary- Measuring the D.C. resistance of secondary cores- Polarity test- Magnetising test upto knee point is a must. It should be ensured that the applied
voltage is slowly reduced to Zero after reaching the knee point. This is to avoid highrate of change of flux causing high induced voltage damaging secondary insulation.
- Ratio test at rated primary current for all the taps in secondary. This test shall bedone after magnetising test.
- Unused cores shall be shorted- Unused portion of a core shall never be shorted- All the C.T. secondary circuits shall be earthed at only one point, preferably nearer
to C.T. end.- After making the connections to load point, megger the entire secondary circuit and
then do the secondary injection from the terminals at the C.T. end. The secondaryinjection shall first be done without the grounding and it shall be repeated with thegrounding done. Now, the voltage burden at each terminals from the CT terminalupto the load shall be measured and promptly recorded for the rated secondarycurrent of the C.T. When current is injected in one phase, it should be ensured thatthere is no current in other phase at any point. Secondary injection is a very very
52
CHAPTER-IV
important one. In multi secondary CTs, there is frequent possibility of protection wiringdone to a metering secondary. ONLY secondary injection can reveal this fault. Primaryinjection will not reveal.
e) Metering instruments:
- Calibration- Checking the readings during secondary injection on P.Ts and CTs and checking the
burdens in current coils- Checking the selector switches
f) Control Circuits – Check points:
- Meggering- Energising the panels with auxiliary supply- Voltage across fuses should be clear zero- Indication circuits- Annunciator points- Semaphores- D.C. auxiliary relays to be checked for 60% voltage pick up- Interlocks- Inter trip- Functional tests- Closing circuits and trip circuits- Trip supervision cicuits to be checked- Trip healthy lamps – the lamps should be shorted several times and to be ensured
that the trip Plunger does not move- Auto reclose- Protection trip circuits – it should operate even when the breaker control is in local
or remote
g) Relays:
- Megger wherever allowed- Test the relays for all P.U. settings- Adopt the final settings and test- See the operation during secondary injection wherever possible
53
CHAPTER-IV
h) Power equipments like Generators: Transformers
1. Generators:
- Winding D.C. resistance of stator and rotor- Meggering of stator and rotor- H.V. test on stator and rotor- Pole drop test on rotor- Tan δ test
i) Transformers:
- Meggering- Vector group- D.C. resistance, S.C. test, Ratio test in all taps- Tap changer operation- Polarity check- Control panel checks- Thermometers calibration- Buchholz relay test- Oil B.D.V. test- Tan δ (delta) test on bushings- If there are C.Ts in transformer bushings these CTs should be checked before
erection of bushings.- Check oil levels.- Check breathers and silica gel.- Fan operations, oil pumps, C.W.system- Control schemes of OLTC- Earthing
54
CHAPTER-VCHAPTER-VCHAPTER-VCHAPTER-V
COMMISSIONINGCOMMISSIONINGCOMMISSIONINGCOMMISSIONINGTESTSTESTSTESTSTESTSEr. K. Mounagurusamy
CE/P&C
After completion of precommissioning works, the protection wing only should proceedwith further commissioning tests. The area protection engineer at the level of AssistantExecutive Engineer will be the commissioning in charge. Others should not be allowed to doany work anywhere. Any modifications thereafter will be done only by protection wing. If allthe precommissioning tests are done perfectly, no problem will be there during thecommissioning tests and actual commissioning. If there are any major problems, the services ofthe other wings shall be called for.
PrimaryPrimaryPrimaryPrimary injectioninjectioninjectioninjection tests:tests:tests:tests:
This test is included under the commissioning test because, all the other people shouldhave completed their jobs before going for this test. This test should be done only afterfinishing the secondary injection test from the output terminals of the C.T.
A comprehensive table should be prepared indicating the point or terminal of currentand voltage measurements, expected value of current at each point etc. The entire protectionwing should sit together and discuss in detail so that every one should under stand what is beingdone. The complete secondary current path should be well known. For example, if current isinjected in R Phase in the star side of a transformer there will be current in the R and Y phasesor R and B phases in the delta side. If confident, three phase injection can also be done. Eventhe helper should participate in the discussion since he will be normally handling the probes ofmeters and any open circuit in a C.T. would cause high voltage in the secondary circuit.
As many meters should be made available and atleast one person should be ready at thepoint of each C.T. to measure the parameters. Multimeters shall not be used to measure the C.T.secondary current. The reasons are (1) They have only plugs for lead connections. They maybe loose or they may get disconnected at any moment (2) some meters have overloading orprotection cutout, the measuring circuit may get open circuit inadvertently. Now-a-days, verylow range tongue testers are available. They can be procured.
One person should be ready at the ammeter point. There should be some way ofcommunication from each one with the person who injects the primary current.
55
CHAPTER-V
If current is injected using a loading transformer the primary current leads should notcross with the leads of the ammeter leads measuring the C.T. secondary current of loadingtransformer or any other C.T. under primary injection since the ammeter readi ngs will beerratic in such cases. If it is found difficult to drive current through a simple bus bararrangements, it can be understood that some C.T. secondary is open.
First a very low current should be injected and be ensured that there is limited voltageburden across all the concerned C.T. secondaries. This is the indication that current circuit isthrough. If high voltage burden is noticed, the current circuit might be open. This is not alwaysthe case. In the case of high impedance circulating current relays, there will be high voltagenoticed comparing with low burden circuit loads. After passing a small current every oneshould give clearance to go ahead after also checking the current in each C.T. secondary. It ispreferable to keep connected ammeters in each secondary current if possible.
The current can be raised now. There is no need to go upto rated current. The point isthat it should be possible to measure the currents clearly. In the cases of primary injection ontransformers only very small primary injection currents are actually possible.
Record all the values. The stability of the differential relays if any in the circuit shouldbe confirmed at this stage itself by measuring the spill current. By reversals in wiring, spillcurrents can be created and confirmed.
Injections shall be completed in all phases.
Series injection – to ensure that all the CTs are tested for correct polarity, erected forcorrect polarity, and secondary wired for correct polarity. There will be three times the currentin the neutral circuit and therefore suitable precautions should be taken to avoid failure of E/Frelays, ammeters etc.
The test circuits for such tests are wantonly avoided since too much spoon feeding willbe unhealthy. The habit of searching for knowledge should be cultivated among the protectionengineers.
Details of such a test conducted on machine-1 at Kadamparai PH on 26-7-87 aredetailed below:
A lay out of the Kadamparai power House is given in figure-5.
There are more than 25 CTs in all in each machine. All the CTs were covered in onestroke by planned primary injection.
When primary injection is done in the system which has power transformer also, theinjection current is normally derived by applying 3 phase L.T. supply voltage directly to theH.V. winding making a short in the L V.side. An approximate value of short circuit
56
CHAPTER-V
57
CHAPTER-V
current in the H.V. side should be first arrived at to ensure that the L.T. supply available in thetest site can cater it.
A simple method without paper, pen calculator is as below:
- Look at the transformer nameplate and find out the H.V. Voltage, H.V. rated current, L.V.rated current and percentage impedance.
Percentage impedance is the percent of H.V. voltage required to pass the rated currentthrough the H.V. and L.V. of the transformer when the L.V. is shorted.
Example: H.V. voltage = 230 KVH.V. rated current = 300 AL.V. rated current = 6200 A% percent impedance= 10%
Hence, 23000 volts are needed to pass 300 A through HV and 6200 A through L.V.with L.V. shorted.
If 400 V is applied, the expected HV at400/23000 x 300 = 5 Amp.
This can be arrived at by mental calculation in two minutes. Approximately 1/60 th ofvoltage is applied. Hence 1/60 of 300 A is 5-A. Similarly 1/60th of 6200 is 100 Amps. Looks sosimple.
It was decided to inject three phase 400 V at the point shown as (A) in the figure-5.Since the reactance of the generator winding is very high we will not be getting any shortcircuit current at all for injection. Hence, the stator windings were bypassed by temporaryjumpers as indicated.
The travelling distance by road from the point of injection in the yard to the generator isnearly 4 KM.
One engineer was posted inside the Powerhouse cavern near the relay panel where allthe C.T. wirings are terminated.
One person was posted in the B/B relay panel in the control room at yard.
One person was at the marshalling box in the yard.
One person was there to switch on the 400 V supply and to measure the current injectedat 230 KV side.
58
CHAPTER-V
- The supply was switched on.
- Current injected at 230 KV point was 3.5A
- Current obtained in 11 KV side was 82 A
- The C.Ts in the yard are 400/1
- The CTs in the Generator at 8000/5
- 8 mA was obtained in the 230 KV CT secondaries.
- 50 mA was obtained in the 11 KV CT secondaries.
- Stability of the transformers – Generator Differential relay, 230 KV cable differential relayand generator differential relay were established.
- Currents measured O.K. in all the CT secondary circuits.
- Fault simulation was done by creating a short between R and B phases of the 11 KVterminals of the transformer i.e. fault within the Generator – transformer differential relay.Expected spill current was measured O.K. in the R and B phases of the Generator –transformer differential relay. There was no spill current in Y Phase. The STABILITY ofREF relay was confirmed thro’ the single loading current in 230 KV side.
- A three phase short was made after unit auxiliary transformer which is also in Generatortransformer differential relay zone. There was no spill current as expected since the shortwas outside the relay zone.
- A fault was created within the cable differential zone by introducing a 2000 W heater as thefault source. Spill current was measured O.K. in the cable differential relay.
Since the secondary injection was done to the full satisfaction, there was absolutely noproblem in the primary injection test and the test was completed in one stroke in less than twohours. These tests are normally done by Assistant Executive Engineers.
FAULTFAULTFAULTFAULT SIMULATIONSSIMULATIONSSIMULATIONSSIMULATIONS
It is our practice to create faults in the generator transformer system and building upcurrent slowly from zero to rated value in the generators and to confirm that all protections areworking satisfactorily. These will be done before building up the full voltage on the generatorfor the first time. Executive Engineer and Superintending Engineer from Protection wing willbe present.
Such a test done in machine 2 at Kadamparai on 25-2-88 is explained below:
- A short was made between the 11 KV terminals (three phase) at the output point of thegenerator but after the generator differential CT at the output terminal.
- Excitation was slowly built up.
59
CHAPTER-V
- A short circuit current of 2400 A (Full load current of the generator is around 6000 A) wasslowly achieved.
- Spill currents were measured in the generator differential relay
- Removed the current from one side C.T taking precaution to short the concerned C.Tsecondaries. The generator differential relay operated O.K.
- Two phase currents to the negative sequence relay were interchanged and the relay pickedup O.K. at around 1900 A.
- A short was made is within the zone of the generator transformer overall differential relay.When the current level reached the pick up limit, the relay operated O.K. at around 1340A.
- Short circuit characteristic of the generator was taken by recording field volt, field currentagainst the shorted generator current.
- The above short was removed and a short was then made at the yard after the 230 KV CTs.
- Built up a current of 2000 A through the generator and the stability of the cable differentialand Generator – transformer differential relays were confirmed.
- R phase was earthed at yard and the stability of REF was confirmed.- The R phase 11 KV terminal of the generator were grounded by a short and the 95% stator
earth fault relay operation was confirmed at around 11 volts across the relay input. Machinevoltage was 1.4 KV in the ungrounded phases and the field voltage was 13.4 v.
- After these tests, full voltage was built up slowly. The open circuit characteristic of thegenerator was taken by recording the main field voltage for each KV step.
Next step is the synchronism check.
CHECKINGCHECKINGCHECKINGCHECKING THETHETHETHE CORRECTNESSCORRECTNESSCORRECTNESSCORRECTNESS OFOFOFOF SYNCHRONISINGSYNCHRONISINGSYNCHRONISINGSYNCHRONISING EQUIPMENTSEQUIPMENTSEQUIPMENTSEQUIPMENTSCONNECTIONS:CONNECTIONS:CONNECTIONS:CONNECTIONS:
This is included under commissioning tests since this can be done only after energisingthe main equipments.
This is somewhat a complicated subject. Mistakes can very easily creep in. In depthknowledge is essentially required for the protection engineer to finalise things. But, the job willbe very interesting once one gets involved.
In my experience, the scheme of connections supplied by even reputed agencies needmodifications at site in most cases. The burden falls at the very last moment on the shoulders ofthe protection engineer to finalise the correct connections.There is an instance in TNEB itself where one thermal generator was wrong synchronisedduring commissioning causing some damages.
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1.1.1.1.SynchronisingSynchronisingSynchronisingSynchronising ofofofof GridGridGridGrid feedersfeedersfeedersfeeders inininin Sub-stations:Sub-stations:Sub-stations:Sub-stations:This is not much complicated. The scheme can be derived easily but the practical
confirmation is laborious.
Normally, the P.T. voltages are taken from Y phase of Bus and the Y phase of singlephase P.T. in the line. Both are phase to ground voltages. The bus P.T. is normally star/starconnected. The line P.T. is phase to earth connected. Only possible point of mistake is in thepolarity of PT connections.
Physical correction has to be done in some cases in a round about way. For example,take the case of 110 KV PH-5 – Sandynallah line.
Tudialur Singara
SBus 1 Bus2PT 1 PT 2
Geddai Kundah KundahPH 1 PH 5
When it is needed to synchronise the new line between Kundah PH-5 and Sandinallah,we cannnot depend upon the 12 ‘O’ clock position of the synchroscope only. Thesynchroscope will give 12 O’clock position even if only Y phase connections of grid lines arecorrect. This will not reveal the defect if R and B phase are interchanged in the new line.
Sandinallah
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CHAPTER-V
The physical correctness can be checked by energising bus 2 at Singara through PH-5 –Sandynallah – Singara lines, keeping the established grid in Bus 1 at Singara. When the clockat PH-5 or Sandynallah is showing 12 O’clock, the R1 – R2, Y1 – Y2, B1 – B2, voltagesmeasured between the Bus PT-1 and Bus PT-2 should be zero. R1 – Y2, R1 – B2, Y1 – B2, Y1– R2 B1 – R2, B1 – Y2 voltages should be 110 V. These should be confirmed.
If suitable hot line equipments are available the confirmation can be done either at PH 5 orSandynallah end.
The phasing out of 230 KV Udumalpet – Kadamparai feeders 2 and 3 was done on 28-7-87 as below:
The main bus and auxiliary bus at Udumalpet was split.
Kadambarai Bus was from Udumalpet main bus via feeder No. 2.
Udumalpet Auxiliary bus was charged then via feeder 3 from Kadamparai.
The R-R, Y-Y, B-B voltages were confirmed tobe zero between the P.Ts of main busand Auxiliary Bus at Udumalpet.
This was done since there was not established synchronising scheme at Kadamparai.
2.2.2.2. SynchronisingSynchronisingSynchronisingSynchronising ofofofof GeneratorsGeneratorsGeneratorsGenerators:
This is more complicated since there is normally a star delta transformer in betweencausing a thirty degrees or sixty degrees shift depending upon the vector group of thetransformer.
We experienced some very interesting problems worth mentioning when Kadamparaiunits were commissioned. They are discussed below:
Refer figure: 6
62
CHAPTER-V
63
CHAPTER-V
First check on synchronism scheme was started in machine 1 on 3-8-87. Unlike in mostof the generators, provision is available to delink generator stator winding from 11 KV take offsystem. (Generally stator windings are solidly connected to 11 KV take off system). The statorwas delinked and the 230 KV Bus transformer of machine-1 was back charged from 230 KVBus and 11 KV reached up Generator 11 KV PTs. Synchroscope was switched on. It showed 6O’clock instead of 12 O’clock. Traced out that the 11 KV PT secondary outputs were reversed.Set right and synchroscope showed 12 O’clock O.K. R-R, Y-Y, B-B voltages were measuredbetween the 230 KV Bus P.T. (Running) and 11 KV machine 1 P.T. (incoming) secondaries.They were around 25 V as expected. This is due to the 30° phase shift existing between the P.Tsecondaries due to YD 1 power transformer. This means that there is always an inherent phaseshift of 30° between the generator and the running bus though the synchroscope connectionsare made up by manipul ations to show that they are in phase and this is done for practicalpurposes to enable synchronising without confusion.
Machine 1 was put on test run on 14.10.87. With the field breaker open, the voltage atthe 11 KV output terminals of the generator was carefully measured with multimeter. It wasjust 50 V only. Checked the phase sequence. It was not RYB. It was BYR to everyone’ssurprise. It is impossible to interchange two phases to make it RYB upto the output of 230 KVbreaker. When the BHEL people were discussing about modifying the stator end connections,which work could take a minimum of 2 months, we, the protection department of TNEB,decided to rename and treat everything upto the 230 KV breakerr output terminals as BYR. Theinterchanging of R and B Phase were done only at the dropper jumpers of 230 KV bus.
There were more than 25 CTs and 9 PTs. All the secondary connections were modifiedfrom yard to Generator in all the junction boxes by interchanging R Phase and B Phase wires.Even now, Red colour lead indicates Blue Phase and blue colour lead indicate red phase in thePT and CT circuits of all machines inside the PH and in case of machine 1 & 2 at yard. Theyard wires of machine 3 & 4 indicate Red as red, yellow as yellow and Blue as blue.
The YD 1 transformer of the generator has now become YD 11 and the deltaconnections of the auxiliary CTs of the Generator – transformer differential relay weremodified to YD 11 connection. Necessary corrections were done in the YD 1 auxiliary PTconnections of the synchronising scheme after studying through vector diagrams. Completeprimary injection was repeated in all the 25 and odd C.Ts and stability of the three differentials(including cable differential relay) relays were established. All these wo rks were started at 5AM on 15-10-87 and were completed before 12 AM on the same day with the help of dedicatedAEs of Kadamparai Power House. The machine was synchronised O.K. The modifiedsynchronising scheme is shown in Figure-7.
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CHAPTER-V
65
CHAPTER-VThe experience in Machine 4 at Kadamparai is more teaching.
The tests done on 3.8.87 in Machine.1 was repeated on Machine.4 on 15.12.88. Thesynchroscope showed 6 O’ clock instead of 12 O’ clock and the R-R, Y-Y, B-B voltages were120V against the expected value of around 25V for 30° phase shift in YD11 transformer: What?How? Why? Rechecked all the circuits upto 1 AM on 16.12.88. Nothing could be traced out.
Next day, Machine.1 was electrically coupled to 230 KV Bus. 1 (Both dead) andMachine.4 was connected to 230 KV Bus.2 (Both dead). The 230 KV Bus coupler was open tosegregate the two buses. Parallelling connections were done in the 11 KV terminals of bothMachines using test wires and a three phase supply of 2 volts derived from a 3 phase variac wasinjected at 11 KV terminals to both parallelled machines.
Refer figure 7 again.
Machine.4 power transformer was also of vector group YD11. Under the circumstances,the voltage should have been zero in the voltmeters VR, VY and VB. But, the voltage was 35volts:
After further struggling, it was found that the physical position of the 11 KV terminalsof Machine.4 (BHEL Transformer) was opposite to that of machine.1 transformer (TELK).
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CHAPTER-V
67
CHAPTER-V2.1 2.2 2.2 2.1
1.1 1.2 1.1 1.2
Machine.1 (TELK) Machine.4(BHEL)
Top view of transformers
1.1, 1.2 – 230 KV Terminals
2.1, 2.2 – 11 KV terminals.
Thus, for the same bus duct connections of 11 KV and 230 KV cable terminations in 1.1and 230 KV side neutral in 1.2, the Machine.4 transformer has become YD5. It should beunderstood that there is no flexibility in the connections anywhere to interchange phases etc. 11KV connections are by insulated bus ducts and they can not be modified.
When the Grid Relay Test has done the polarity tests, 1.1 corresponded to 2.1 and 1.2corresponded to 2.2 in both the transformers and hence the problem was not revealed by thistest.
The important lesson is here. When short circuit run was made in Machine.4 at 2500Amps, there was no spill current in the differential relay of Generation-Transformer. How? Thedelta was made in the auxiliary CTs of this relay for YD11 transformer. Even then, no spillcurrent for YD 5 transformer. The reason is: During the stability check done by Grid RelayTest by primary injection, spill current was noticed at double the value. Without probing intothe problem, they just interchanged the C.T. output leads to “ SOLVE” the problem. Had thisbeen probed on that day itself, the culprit could have been identified.
The riddle of 120 V was thus solved and the machine was synchronised confidently at18.02 Hours on 16.12.88 after inter-changing the leads 83 and 85 to makeup for YD 5 groupand to get 12 O’ clock at synchronism.
BHEL. Engineers later interchanged the terminals in 4/90 inside the transformers ofMachine.3 and Machine.4 (BHEL) to make the terminal configuration as in TELK transformerof Machine 1 & 2, since there was no possibility to interchange anywhere else i.e in the fixed11 KV Bus ducts or 230 KV cable pot head location.
We used to experiment with other methods. When machine.2 was first synchronised,the synchronism check was done on 25.2.88, as below:
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CHAPTER-V
230 KV Bus coupler kept open. Eastern Bus on Grid. It’s P.T. supplied the“RUNNING” voltage to synchroscope. Western bus was connected to machine.2 by closing itsbreaker. When the synchroscope was showing 12 O’ clock, zero voltage was confirmed acrossR-R, Y-Y, B-B of both Bus P.T. secondaries.
Another type of synchronism check was done on 18.3.91 in machine.1 whenrecommissioning after fire accident. This was done by dummy charging one 230 KV Bus.1from Machine.1 and checking the R-R, Y-Y, B-B voltages of both Bus PTs. with 230 KV Bus-2 on grid and confirming that the voltages were zero when the synchroscope showed 12 O’clock.
The lessons are:
1) Don’t assume things and any abnormality should be viewed seriously and probedthoroughly.
2) Correct procedure for synchronism scheme checking are:
a) First establish that synchroscope gives 12 O’ clock for correct inputs. This could bedone, by giving same voltage in both side inputs and confirm.
b) The machine should be dummy tied to a system where the other reference P.T. voltageis available and R-R, Y-Y, B-B voltages compared in between machine P.T. and BusP.T secondaries for 12 O’ clock position of synchroscope. The expected voltage shouldbe around 25 V in case of YD 1 and YD 11 transformers and 120 V in respect of YD 5or YD 7 transformers.
OK- How to identify the vector group of a transformer by just looking at the connectiondiagram? There is a nemonic secret.
If R phase winding of star side feeds to R-Y in the delta side, it is a YD 1 transformer.Remember this RRYYD 1. First R denotes star side. RY denotes delta etc. This can alsorepresent YD 7 but such groups are normally non existing.
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Similarly Y-YR-YD 11 for YD 11 group.
How to deduce the relationship between the group symbol and winding connections?
Take DY 11 for example (equivalent to YD 1)
CONNECTION DIAGRAM OF DY 11
VECTOR SYMBOL OF DY 11
In the vector diagram r, y and b represent the phase voltages of the supply. Let the HVterminals of the transformer A2, B2 and C2 be connected to these supply voltages r, y and brespectively. Then the voltage applied to HV windings between the terminals A2-B2, B2-C2and C2-A2 will be r minus y, y minus b and b minus r which form a closed delta represented bythe triangle A2, B2, C2. The HV winding between the terminals A2 and B2 in this case and theL.V. winding between the terminal a2 and neutral are on the same limb. Therefore, the voltageinduced in the L.V. winding between a2 and n measured with a reference positive from n to a 2is a vector parallel to A2-B2 and is represented by a2 n as shown. This gives the “a” phase L.V.voltage. On the same line the L.V. voltage of the other two phases can be drawn. Comparingthe vector position of corresponding HV and LV voltages in the diagram, it can be seen that theL.V. voltage vector is ahead of the HV voltage vector by 30 degrees which is the same as theangle between the hour hand and minute hand on the clockface at 11 O’ clock.
a1b1
c1
a2
b2c2
N
B2
C2
A2
a2
b
b2y
r
B2C2
A2
c2
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CHAPTER-V
INTERPRETATIONSINTERPRETATIONSINTERPRETATIONSINTERPRETATIONS OFOFOFOF SYNCHRONISINGSYNCHRONISINGSYNCHRONISINGSYNCHRONISING SCHEMESCHEMESCHEMESCHEME
I.I.I.I. GENERATINGGENERATINGGENERATINGGENERATING STATIONS:STATIONS:STATIONS:STATIONS:
a) When the synchronising equipment is switched on in a generator panel, the“running” means the “ bus” and “ incoming” means “ generator”.
b) If the synchroscope runs in the anticlockwise direction (i.e. SLOW), the generator isrunning at a lower speed than the grid frequency. The generator speed has to be increased tomatch for proper synchronising.
If the synchroscope runs in the clockwise direction (i.e. FAST), the generator is runningat a higher speed than the grid frequency. The generator speed has to be decreased to match forproper synchronising.
Sometimes, the pointer may be at 12’O clock position without rotating but vibrating.This shows that there is complete mismatch of frequencies. When the difference goes high, thepointer cannot rotate at that corresponding speed and get stalled. This may not be construed as“matching”. If the frequency meters are read now, they will indicate different frequencies andmatching may be done based on the frequency levels first as a “course” action and when thesynchroscope starts rotating again, matching may be done using synchroscope rotation.
As a general guideline, synchronising can be effected at 11’O clock position when thepointer is rotating in clockwise direction. But this has to be learnt precisely on experience.Synchronising when the pointer is rotating in the anticlockwise direction can be done at 1’Oclock position but this shall generally be avoided. Reverse power relays may operate sometimesif the matching is not close if synchronized in SLOW direction.
II.II.II.II. SUBSTATIONS:SUBSTATIONS:SUBSTATIONS:SUBSTATIONS:
a) Take the case of 230 KV Arasur Substation. Assume that there was grid collapse andsubsequently Kundah Complex supply is available upto Arasur “ bus”. Mettur complex supplyis available upto Arasur on Gobi feeder.
The synchroscope is switched on in Gobi Feeder. Kundah Complex is now in“RUNNING” and Mettur complex is now “ INCOMING”.
The pointer rotates in clockwise direction. This means that the machines at KundahComplex are running at a higher speed than the Mettur Complex.
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To get matching the possibilities are :
(i) to increase the frequency of Mettur machines by contacting the Mettur people if thefrequency of Mettur machines is less than 50 Hz and the frequency of Kundah machine isnearer to 50 Hz.
(ii) to decrease the frequency of Kundah machines by contacting the Kundah people ifthe frequency of the Kundah machines is more than 50 Hz and the frequency of Metturmachines is nearer to 50 Hz.
(c) The pointer rotates in anticlockwise direction. This means that the machines at KundahComplex are at lower speed (frequency) than the Mettur Complex. To get matching, thepossibilities are:
i) to increase the frequency of Kundah machines by contacting Kundah people if thefrequency of Mettur is nearer to 50 Hz and the frequency of Kundah machine is less than 50 Hz.
ii) to decrease the frequency of Mettur machines by contacting Mettur people if thefrequency of the Kundah machines is nearer to 50 Hz and the frequency of Mettur machines ismore than 50 Hz.
d) The other points mentioned in I (b) are also applicable in these cases also.
III.III.III.III. EFFECTEFFECTEFFECTEFFECTOFOFOFOFWRONGWRONGWRONGWRONG SYNCHRONISINGSYNCHRONISINGSYNCHRONISINGSYNCHRONISING ::::
If a generator is synchronised at 180° apart i.e. when the pointer is at 6° clock, it isequivalent to a three phase short circuit on the machine.
The impact is less severe when the clock position is nearer to 12° clock.
Any out of step synchronising with severe grunt on the machine may cause severestrains on the machanical parts also damaging the end lashings of stator windings.
PRECAUTIONSPRECAUTIONSPRECAUTIONSPRECAUTIONS WHILEWHILEWHILEWHILE ENERGISINGENERGISINGENERGISINGENERGISINGANANANAN EQUIPMENT:EQUIPMENT:EQUIPMENT:EQUIPMENT:
1. For the first time to be done in the order.
2. Get clearance from all wings
3. Keep the fire extinguishers ready.
4. Keep awa y from the equipments atleast for 5 minutes after energising.
5. Switch off the equipment if any abnormality is noticed.
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6. Release the air from transformers frequently for a few days.
7. Keep a close watch on the panel meters of all other equipments which are already in serviceto observe for any voltage dip or flow of fault currents etc. at the particular time of energisingthe new equipment.
8. Keep the control of L.T. change over schemes of generators in “Manual ” mode.
AFTERAFTERAFTERAFTER COMMISSIONING:COMMISSIONING:COMMISSIONING:COMMISSIONING:
- Confirm that currents are equal in all the three phases.
- Measuring of P.T voltages and their phase sequence.
- for P. T. supply change over between two P. Ts, ensure that the distance relays do notoperate.
- Check for availability of P.T secondary voltage on all the loads like relays, voltmeters,energymeters, other panel meters etc.
- Measuring the voltage burden of CTs and recording.
- Checking of all meters for correct direction display and energymeters for correct directionalrotation.
- Energising the station supply from the new generator commissioned and check for thevoltage and phase sequence.
- Watch the performance of bearings in generators very closely atleast for 24 Hours.
- Watch for any abnormal temperature rise in bearings, stators, transformers.
- Watch for any abnormal vibrations in the generators while loading for the first time.
- Watch for any arcing in the commutator brushes of D.C machines.
- Measure the shaft voltage in generators.
- Generators should be under close watch for atleast 72 Hours of first running.
- Carryout “ directional on load” test on distance relays, directional over current relays.
- Simulate and check for directional feature of Earth Fault relays.
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GENERALGENERALGENERALGENERALCHECKCHECKCHECKCHECKLISTLISTLISTLISTBEFOREBEFOREBEFOREBEFOREENERGISATION:ENERGISATION:ENERGISATION:ENERGISATION:
AS A FINAL CHECK BEFORE ENERGISATION, THE FOLLOWING POINTS AREONCE AGAIN CONFIRMED.
i) ALL CT AND VT CIRCUITS ARE THROUGH.
ii) ALL DC SUPPLIES TO THE RELAYS ARE NORMAL.
iii) ALL WIRES AT THE BACK OF THE RELAYS ARE TIGHT.
iv) NO ABNORMAL FLAG OR INDICATIONS IS EXISTING ON ANY RELAYOR ANNUNCIATOR.
v) ALL AC SUPPLIES TO C.Bs, ISOLATORS etc., ARE NORMAL.
vi) THE RELAYS LIKE AUTO-RECLOSURE etc., ARE SELECTED TO THEDESIRED MODE OF OPERATION.
vii) CONFIRM THAT ALL THE NECESSARY PROTECTION TESTS HAVEBEEN DONE.
viii) CONFIRM THAT HIGH VOLTAGE TEST HAS BEEN DONE FOR EACHEQUIPMENT AS PER REQUIREMENTS OF THE RESULTS.
ix) CONFIRM SATISFACTORY TESTING OF ALL SAFETY SYSTEMS ANDS/S EARTHING SYSTEM etc.,
x) CONFIRM THAT ALL OPERATING PROCEDURES ARE BEINGPREPARED AND INSTRUCTIONS WITH REGARD TO PROTECTION SYSTEMARE INCORPORATED.
ENERGISATIONENERGISATIONENERGISATIONENERGISATION
i) CARRY OUT NECESSARY TRIP/INTERTRIP TESTS OF THE INVOLVEDCIRCUIT BREAKERS IN THE TEST POSITION WITH RELEVANTPROTECTION.
ii) ENERGISING THE FEEDERS AND TRANSFORMERS.
iii) CARRY OUT NECESSARY PHASING BY USING V.TSECONDARY ANDFINALLY MAKE PARALLELING.
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ONLOADONLOADONLOADONLOAD CHECK:CHECK:CHECK:CHECK:
PURPOSE:-PURPOSE:-PURPOSE:-PURPOSE:-
i) TO PROVE CORRECT CT & VT CONNECTIONS.
ii) TO PROVE STABILITY OF UNIT PROTECTION.
iii) TO PROVE CORRECT DIRECTION OF DISTANCE RELAY AND OTHERDIRECTIONAL RELAYS LIKE DEF(Directional earth fault) ANDDIRECTIONAL O/C RELAY etc.,
METHOD:METHOD:METHOD:METHOD:
i) ALL THE CURRENTS AND VOLTAGES ARE RECORDED AND THEBURDEN OF CT CIRCUITS MEASURED AND RECORDED.
ii) ALL THE DIRECTIONAL CHECKS ARE CARRIED OUT INACCORDANCE WITH THE MANUFACTURER’S PRESCRIBEDPROCEDURE.
CAUTION:CAUTION:CAUTION:CAUTION: NoNoNoNo ProtectionProtectionProtectionProtection isisisis totototo bebebebe putputputput inininin serviceserviceserviceservice unlessunlessunlessunless itititit’’’’ssss directionalitydirectionalitydirectionalitydirectionality isisisisprovedprovedprovedproved.
75
CHAPTER-VICHAPTER-VICHAPTER-VICHAPTER-VI
TESTINGTESTINGTESTINGTESTING OFOFOFOF CIRCUITCIRCUITCIRCUITCIRCUIT BREAKERBREAKERBREAKERBREAKERATATATAT SITESITESITESITEEr. P. PONNAMBALAM
EE/SS Erection
1.1.1.1.MEASUREMENTMEASUREMENTMEASUREMENTMEASUREMENTOFOFOFOF INSULATIONINSULATIONINSULATIONINSULATION RESISTANCE:RESISTANCE:RESISTANCE:RESISTANCE:
(a) MAIN CIRCUIT:
The measurement shall be made with an Insulation Tester (Megger) power operated ofnot less than 1000 volts capacity.
The value measured shall not be less than 2 (Two) Megaohm per KV rating.
(b) CONTROL CIRCUIT
The measurement may be made with a 500 V hand operated Megger or at the most 1000volts Megger. The value so obtained shall be not less than 5 (Five) mega ohms.
2.2.2.2. OPERATIONOPERATIONOPERATIONOPERATION TEST:TEST:TEST:TEST:
After satisfying the pre-conditions such as Gas pressure, Air pressure etc., the circuitbreaker may be operated in the following manner :-
(i) Manual closing and tripping(ii) Local electrical closing and tripping at normal control voltage.(iii) Remote electrical closing and tripping at normal control voltage.(iv) The above operations at the minimum control voltage. (i.e. at 80% of normal voltage for
closing and 70%of normal control voltage for tripping).(v) Measurement of trip coil current & voltage dip during coil energisation – the values so
obtained shall be comparable to the coil rating specified by the manufacturer.
3.3.3.3.MEASUREMENTMEASUREMENTMEASUREMENTMEASUREMENTOFOFOFOF SPEEDSPEEDSPEEDSPEED OFOFOFOF OPERATION:OPERATION:OPERATION:OPERATION:
The measurement may be made at normal control voltage and the values obtained shallbe not more than the ones given below: -
(a) Closing time = around 100 milli seconds.(b) Tripping time = 40 milli seconds.
The above values are applicable to minimum oil, SF6 and vacuum circuit breakers.In the case of Bulk oil circuit breakers, however, a tripping time of upto 100 milli
seconds is permissible.
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4.4.4.4.MEASUREMENTMEASUREMENTMEASUREMENTMEASUREMENTOFOFOFOFRESISTANCERESISTANCERESISTANCERESISTANCEOFOFOFOFMAINMAINMAINMAINCIRCUITCIRCUITCIRCUITCIRCUIT(CONTACT(CONTACT(CONTACT(CONTACTRESISTANCE)RESISTANCE)RESISTANCE)RESISTANCE)
As per I.E.C. Publication 694 which has been adopted in toto by I.S.S. 13118 of 1991the measurement of contact resistance shall be made by voltage drop method by passing adirect current (d.c.) of not less than 100 Amps through the Circuit Breaker (in closed position)and measuring the voltage drop across the breaker terminals (incoming – outgoing).
This procedure is, however, not practicable at site. Therefore the following methods aresuggested: -
(i) Milli-volt drop method – by passing an alternating current of not less than 100 ampsand measuring the voltage drop and calculating the A.C. resistance. This value whendivided by factor of 1.2 will give the exact resistance of the contact.
(ie) V x 1.2I
(ii) Direct measurement of resistance by using MICRO OHM METER
As regards bench mark value, it stated that the I.E.C. 56, 694, as also the I.S.S. 13118 of1991 are silent about it.
It is suggested that a value of upto 100 micro ohms for new breakers and upto 200micro ohms for fairly old ones be permitted.
5.5.5.5. TESTTESTTESTTESTFORFORFORFOR AUXILARIES:AUXILARIES:AUXILARIES:AUXILARIES: ----
(a) Anti pumping relay functioning.(b) Spring charge motor functioning.(c) Gas pressure switches functioning – operation of switches and their contacts as per
the set values as prescribed by the manufacturers.(d) Air pressure switches functioning – operation as per set values.(e) Compressor motor functioning.(f) Gas leak test. by the use of leak detector or by applying(g) Air leak test. soap solution.
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The voltmeter lead should beconnected inside the currentapplying zone.
78
CHAPTER-VIICHAPTER-VIICHAPTER-VIICHAPTER-VII
TESTINGTESTINGTESTINGTESTING OFOFOFOFRELAYSRELAYSRELAYSRELAYSEr.K. Mounagurusamy
CE / P&C
This manual is generally prepared for those who are already have some experience inprotection department. Basic test circuits of each relay will not be given. General guide lineswhich are not normally available in relay catalogues / Books only are given.
6.1:6.1:6.1:6.1:OverOverOverOver current,current,current,current, Earth,Earth,Earth,Earth, fault,fault,fault,fault, overoveroverover voltagevoltagevoltagevoltage relays:relays:relays:relays:
Adjust zero in time setter to close the contacts at this position.
Pass rated P.S. current. The disc should start to rotate. This test is for bearing check.This is not the pick up value. Find out the value when the contacts make. This is the pick upvalue. The disc may take some time to get back to starting point. Do not force it manually toget back, since this may deform the disc, spoil the bearings.
Time may be taken for three or four currents, 2 times, 4 times, 10 times, 20 times arebetter. Adjust the time needed only for 4 times current. Let this be a uniform procedureeverywhere.
While doing the tests at 1.3 times the current, reduce the CT to 85%at 85%travel of thedisc. The disc should return without making contact. This is overshoot test. Resetting currentafter closing the contact – 50% PS.
Permissible errors:
Operating current error + 30% PS
Time error : 40 ms
Routine tests shall be done only for the adopted settings
6.2: Differential relays:
- Minimum pick up of operating coil should be determined – 5% error
- Find time for twice value of P.U.current
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CHAPTER-VII
- Restraint characteristics – 3 points on curve at 2,4 and 10 times to be donedetermining the pick up current also.
- Harmonic restraint test shall be done as prescribed by manufactures using diodecircuit or using frequency generator. Percent 2nd harmonic
0.472 x Idc= ------------- x 100
Iac + 1.11 Idc
- Every time, the burden voltage at the C.T. end shall be taken after normalising theL.C. and recorded with the corresponding load current. This will reveal any looseconnections in the terminals in due course.
6.3:6.3:6.3:6.3: VoltageVoltageVoltageVoltage restraintrestraintrestraintrestraint overoveroverover currentcurrentcurrentcurrent relays:relays:relays:relays:
When the test current is injected in these type of relays of EE make using a simplevariac and loading transformer combination, the relay behaves erratically. If suitable resistanceis included in the current circuit, the results are O.K. Using standard test kits is thereforepreferable.
6.4:6.4:6.4:6.4: InstantaneousInstantaneousInstantaneousInstantaneous andandandand armaturearmaturearmaturearmature attractedattractedattractedattractedrelays:relays:relays:relays:
The test current should be applied suddenly to determine the pick up. Results will differif current is raised slowly to find out the pick up value.
6.5:6.5:6.5:6.5: Adjustments:Adjustments:Adjustments:Adjustments:
If adjustments are made in the mechanical parts of a relay, all the tests like P.U., resetshould be repeated.
6.6:6.6:6.6:6.6: DistanceDistanceDistanceDistance relays:relays:relays:relays:
Each relay manufacturer and every distance relay testing kit (like ZFB, TURB, TURH,etc.) give in detail the testing circuits and procedures. Hence, they need not be elaborated here.The protection engineer testing distance relays has to get a good and thorough knowledge ofthe relay scheme, test procedures before proceeding to test the relay. AEE should be presentduring the test.
During routine maintenance,
- pick up voltage and current levels (for the MTA) of the Zone 1, Zone 2, Zone 3,Zone 4, Starter, Reverse reach, powerswing have tobe determined for the adoptedsettings and for all the phase combinations.
- Timings of all zones (including 1st zone) need be taken for any one phase test/phaseto neutral test.
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CHAPTER-VII
- A minimum of two times the relay current shall be applied to get better results.
- Test current should be switched on only after test voltage is applied while testingotherwise the relay will misbehave.
- Testing kits are available to carry out static tests and dynamic tests. Dynamic testsare more preferable. Even when static tests are done as routine, dynamic tests shallbe done if recurring mal-operations are experienced.
- Testing done for line angle is more preferable than testing for relay angle
- No need to plot R-X diagram for routine tests. This may be done only during initialcommissioning.
- In case of armature attracted type starters, pick up and drop off shall be checked
- Non operation for reverse faults should be confirmed even in annual tests.
6.7:6.7:6.7:6.7: BuchholzBuchholzBuchholzBuchholzrelays:relays:relays:relays:
- Electrical check by shorting top and bottom float terminals
- Oil draining to check operation of top and bottom floats during onlyprecommissioning tests.
- Air pumped to check the operation of top and bottom floats using cycle pump orpressurised air from compressor. This is an essential maintenance test.
- During mal-operations, checks should be made for entry of oil into the floats(recently experienced at Singara PH) entry oil into the mercury switch (recentlyexperienced in Kundah PH-2) puncturing of diaphragms frequently occurring atKundah PH-3.
81
CHAPTER-VIIICHAPTER-VIIICHAPTER-VIIICHAPTER-VIII
PROTECTIONPROTECTIONPROTECTIONPROTECTION OFOFOFOFNONNONNONNONGRIDGRIDGRIDGRID FEEDERSFEEDERSFEEDERSFEEDERSEr. M. Varadarajan
EE / O&M.
INTRODUCTION:INTRODUCTION:INTRODUCTION:INTRODUCTION:
The greatest threat to a secure power supply is the shunt fault better known as shortcircuit which causes large currents to flow from the power source to the point of fault,accompanied by the localized release of considerable quantity of energy. This can causemechanical damages to electrical equipments, equipment failure and fire unless otherwise thereis a reliable and sensitive protective gear to sense and isolate the fault at the right speed.Protective gear is a collective term covering all the equipments used for detecting, locating andinitiating the isolation of the fault and relays are the major player in this. Graded over currentrelays, one of the simplest form of relays are used in the protection of H. T. Radial lines thatin-turn offer protection of power transformers against external faults.
Protection against excess current was naturally the earliest protective system to evolve.From this basic principle has evolved the graded over-current system, a discriminative form ofprotection. This is not to be confused with “Over load” protection, which normally makes useof relays that operate in a time, related in some degree to the thermal capacity of the plant to beprotected. Over-current protection, on the other hand, is directed entirely to the clearance offaults, although with the settings usually adopted, some measure of overload protection may beavailable which in that case has to be treated as a bonus and not as one of the basic features ofthe protection.
When a fault occurs, the protection is required to select and trip only the nearest circuitbreaker/breakers. This property of selective tripping is called “discrimination”. In theprotection of H. T. radial lines, discrimination by both time and current is employed.
H. T. radial lines and the feeding Sub Station may be at different voltages, i.e. 11 or 22KV to feed H. T. distribution network, the intermediate 33 KV and 110 or 66 KV. In thissection, 11 KV is chosen as the H. T. distribution feeder and 110 KV as the Sub Station EHTvoltage for the explanatory notes. Similar treatment applies to other voltages.THETHETHETHE NEEDNEEDNEEDNEED FORFORFORFORSELECTIVESELECTIVESELECTIVESELECTIVE TRIPPING:TRIPPING:TRIPPING:TRIPPING:
Consider the single line diagram of substation in fig., (1). This is a non-grid stationreceiving power at 110KV. 2 Nos. of 10 MVA, 110 /11KV Power Transformers feed 11KVdistribution networks through 11KV feeders. 1No, 16 MVA, 110/33KV Power Transformerfeeds 2Nos, 33/11KVSubstations situated elsewhere through 2 Nos. of 33KVfeeders.
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Suppose there is a fault at location “ P” in the 11KVline No (1). Power Transformer (1)and (2) will feed power into the fault at current values many times their rated current. This flowof fault power has to be stopped to protect the power transformers and can be stopped in threeways.
(1) By the opening of 11KVfeeder CB1 – Protection (1)(2) By the opening of 11KV, LVCB 1 & LVCB2 – Protection (2)(3) By the opening of the 110KVGCCB. – Protection (3)
Any one of the above three operations will cause the flow of fault current to cease. Butobviously No. (1) is the best method because, faulty 11KVfeeder No. (1) alone is isolated andloads fed through 11 KV feeders (2) to (4) and 33 KV feeders (1) and (2) continue to havepower. Selective tripping takes place here.
No. (2) is the next best. Here power to all the 11 KV feeders are cut off while the loadsof the two 33/11KV substations are continued to be fed. However, protection (2) is needed ifprotection (1) fails for some reason.
No. (3) is the last of the three options. This is so because power is shut off to all the11KVand 33KVfeeders. But the importance of this cannot be ignored because, this will be thelast resort to prevent destruction should protection (1) and (2) fail for some reason.
So, for line faults, protection (1) is primary protection, Protection – (2) is the first back-up and protection –(3) is the second back up.
For faults in the 11KV bus bars or any where in the zone between the LV breakers andfeeder breakers, protection (2) will be primary protection and protection (3) will be the backup.
For faults in the 110KV bus bars or any where in the zone from the 110 KV GCCB topower transformer HV bushings, protection (3) will be primary protection and protection in the110 KV line at the grid station feeding this station will be the backup.
Generally, Primary protection offers selective tripping and back-up protection does notin the radial mode of operation of sub-stations.
The protection system is designed for selective tripping which is achieved by relaycoordination, also known as relay grading.
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FAULTSFAULTSFAULTSFAULTS ANDANDANDAND FAULTFAULTFAULTFAULT CURRENTCURRENTCURRENTCURRENT ANALYSIS:ANALYSIS:ANALYSIS:ANALYSIS:
There are four major types of faults that can occur in the HT lines and sub stationbusbars.
1. Three phase fault2. Double phase fault (fault across two phases not involving ground)3. Double phase to ground fault.4. Single phase to ground fault.
Except for the first, the other three are unsymmetrical faults. It is essential to know thefault current distribution, maximum fault current for a fault at the relaying point for thedifferent kinds of fault to design correct relay settings if the fault is to be cleared withdiscrimination. Load currents can be neglected and the faults are assumed to be through zeroimpedance at the point of fault.
The ideal method to calculate the fault currents for the different types of faults is fromthe symmetrical component networks and the positive, negative and zero sequence voltages andimpedances. However, this elaborate method is seldom required to choose adequate relaysettings for sure clearance of faults and discrimination. The approximate method of choosingthe settings from the three phase symmetrical bus fault MVA gives satisfactory results.
TYPETYPETYPETYPE OFOFOFOFRELAYSRELAYSRELAYSRELAYS PROVIDED:PROVIDED:PROVIDED:PROVIDED:
Over current relays with an IDMT element (inverse definite minimum time) with orwithout High set instantaneous element are provided. The IDMT element, irrespective of thecurrent flowing through the relay has a minimum time of operation below which the timecannot be reduced for a given time setting. Actual time of operation depends on the magnitudeof the current, the current setting of the relay and the time multiplier setting (TMS). The relaytakes less time for heavy faults and a higher time for faults of low magnitude to let the faultclear itself incase it is a passing fault and follows a current-time inverse characteristics. Thetime multiplier setting can be set at any value from 0.05 seconds to 1 second to suit theprotection need. The relay operating current can be set using the plugs provided, usually from50% to 200% in steps of 25% for phase fault protection and from 20% to 80% in steps of 10%for earth fault protection. The high set element is meant for instantaneous operation at highvalue s of fault current to limit the stress on the power transformer and may have an operatingtime of about 20 milli-seconds.
In TNEB, as of now, almost all the relays in use are of electromechanical type withinduction disc for IDMT element and an attracted armature type of relay for the high setelement. The present TNEB standard for normal current rating of relays is 1 A. Most of therelays in service in TNEB have this rating though relays with a normal rating of 5A are still inuse. The treatment in this section is based on 1A rated relays.
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The IDMT relays usually have an operating time of 3 seconds at 10 times rated relaycurrent at 100% plug setting and 1 sec TMS. For convenience, these relays may be said tofollow a 3 sec graph or simply called “3 sec relays”. However, some of the older relays in usemay have an operating time of 1.3 seconds at 10 times rated relay current at 100% plug settingand 1 second of TMS. These relays may be said to follow a 1.3 sec graph or simply called “1.3sec relays”. The relay current divided by the per uni t plug setting is called the Plug SettingMultiplier (PSM)
PROTECTIONPROTECTIONPROTECTIONPROTECTION SCHEME:SCHEME:SCHEME:SCHEME:
FEEDERS: The feeders are provided with 3 over current relays and one Earth fault relay allwith both IDMT and High Set instantaneous elements.
LV BREAKERS: The LV breakers are provided with 3 over-current relays with IDMTelements but without High set elements. High set instantaneous elements if any provided are tobe kept disconnected. Earth fault relays are not provided for LV breakers. Earth fault relay ifany provided are kept disconnected. However, now there is a rethinking on this subject andfuture L.V. Protection may have earth fault protection also, with a higher time setting to serveas backup for future earth fault protection.
GROUP CONTROL BREAKERS: The Group Control circuit breaker on the HV side of thePower Transformers is to be provided with 3 Nos. Over-current relays and 1 No. Earth faultrelay all with both IDMT and High Set instantaneous elements.
The current transformers on the secondary side have a standard rating of 1A, thoughwith some of the older breakers in service, the current transformers may have 5A SecondaryCurrent rating.
The Standard IDMT elements usually have a burden of 3VA at 100% plug setting andthe High set elements impose a burden of about 5VA. These amount to 3 Ohms and 5 Ohmsrespectively for 1A relays. (3/52 = 0.12 ohm and 5/52 = 0.2 ohm respectively for 5A relays).
In the IDMT elements, as current rises in the relay coil, relay core saturates and therelay burden gets reduced to about 40% of its value at rated current when the current risesabove 10 times rated current. No such phenomenon takes place in High Set elements and theburden is more or less the same at different values of current.
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FAULTFAULTFAULTFAULTCURRENTCURRENTCURRENTCURRENTDISTRIBUTIONDISTRIBUTIONDISTRIBUTIONDISTRIBUTIONONONONONTHETHETHETHEPRIMARYPRIMARYPRIMARYPRIMARYSIDESIDESIDESIDEOFOFOFOFTRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER
The Power Transformers in the TNEB Substations belong to the Vector group of Dynll.That is, the primary windings are delta connected and the secondary windings, star connectedwith the neutral brought out and solidly earthed. The Secondary Phase to Phase voltage vectorleads the primary phase to phase voltage vector by 30 degrees. Considering a Single 10 MVA,110/11KV Power Transformer at principal tap, the current distribution on the primary side fordifferent types of faults on the secondary side will be as shown in figure.
a) Transformer delivering full load, condition normal – fig (2)b) 3 Phase fault on the SY side (Load current neglected) – fig (3)c) Single Phase to ground fault on the SY side – fig (4)
(Load current neglected)d) Phase to Phase fault on the SY side – fig (5)
(Load current neglected)e) Two phase to ground fault on the Secondary side – fig (6)
(Load current neglected)Two important points to note are that
i) A single phase to ground fault on the LV side is reflected as a phase to phase fault on theprimary side.ii) Phase to Phase fault and two phase to ground fault on the secondary side are bothreflected as three phase faults on the primary side with primary current distribution of the form1:2:1 and 1: √3:1 respectively.
TWOTWOTWOTWO VERSUSVERSUSVERSUSVERSUS THREETHREETHREETHREE OVEROVEROVEROVER CURRENTCURRENTCURRENTCURRENTRELAYSRELAYSRELAYSRELAYS
Over current relays are provided for clearing three phase faults and double phase faults. Asthese faults involve a minimum of two phases, two over current relays are enough for clearingthese types of faults. The relays are usually provided in the red and blue phases. The scheme of“two O.C + E.F relay” may still be in vogue in some of the older stations. As seen from fig (5),for a phase to phase fault on the LV side of the Power Transformer (DY11), the HV side relayssee a three phase fault of the current distribution 1:2:1, which phase in the HV side carriescurrent twice that on the other two phases depends upon which two phases are under shortcircuit on the LV side. So, when the relays on the HV side gives backup protection duringprotection failure on the LV side, fault clearance time depends on which two phases are undershort circuit on the LV side. Though this protection scheme is acceptable, the present standardis to have “3 O.C + E.F” protection scheme both on the LV and HV sides.
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30.3A
30.3A
30.3A
88
30.3A30.3A30.3A30.3A
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89
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CTCTCTCTREQUIREMENTSREQUIREMENTSREQUIREMENTSREQUIREMENTS
The CT requirement for over current protection is met by IS:2705 Part .III. The majorrequirements are (1) Burden (2) Accuracy class and (3) Rated Accuracy limit factor.
The Burden is the impedance of the secondary circuit expressed in ohms and powerfactor. It is usually expressed in Volt-amperes absorbed at rated secondary current. Theavailable burdens are 15 or 30 VA. for H.T. Feeders and LVCBs. CTs with higher burden maybe provided for the 110 kv GCCBs.
Normally the VA burden is specified. However if not specified for a particular ratio, itis assumed for the maximum ratio. If there is no series-parallel arrangement for ratio change inthe primary and taps are provided in the secondary only, the VA burde n has to be reducedproportionally for lower ratio. Alternatively Knee point voltage (Vk) of Intermediate currentratio taps can be measured and VA burden found out from
1.2 x VA (burden) x ALFVk = -------------------------------
Rated current
Accuracy class “5P” is normally used in TNEP for over current protection. For thisclass, the ratio error at rated primary current is 1% and composite error at rated accuracy limitprimary current is 5%.
An accuracy limit factor of 15 is normally used for over current protection in TNEB. Sospecification of CT for H.T feeder may be generally – Ratio: 400-200/1A, Burden: 30 VA,Class: 5P15, Ratio Adopted: 200/1A.
This means that when a primary current of 200A flows, the secondary current will be 1ampere and can feed a burden of 30 ohms. When the primary current is 15 times the rated value(ie., 15x200 = 3000A) the CT can still feed the burden of 30 ohms and the composite error willnot exceed 5%.
Normally, the IDMT elements of over current relay of feeders are set at 100% and thatof the E.F. relay at 40%. The burden of the IDMT relay at 100% plug setting is about 3VAwhich is 3 ohms for 1 ampere relay. The burden of the High set Inst. element is about 5 VA, ie.,5 Ohms for 1 ampere relay. For an earth fault on one phase say U-Phase, the U-phase CTsecondary current flows through the U-phase O.C relays (IDMT and HS) and the earth faultrelay (IDMT and HS) all in series.
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IDMT relay burden at 100% setting = 3 Ohms.-do- at 40% setting = 3/(0.4)2 = 18.7 Ohms.-do- at 20% setting = 3/(0.2)2 = 75 Ohms.
HS Inst. element burden = 5 Ohms.
Total burden Z = Z O.C(HS)+Z O.C(IDMT) + Z E.F(HS)+Z E.F(IDMT). Hence thetotal burden for an earth fault with 40% setting on E.F. relay will be Z = 5+3+5+18.7 = 31.7Ohms. The present practice in TNEB is to use a CT of class 5P15 with 30 VA burden. So theCT can develop 30x15 = 450 V at its output without saturation. The Z and I can vary but ‘IZ’should not exceed 450V.
Consider a Substation with a high 11KV fault level and a solid earth fault at the out goingline AB Switch. Assuming an earth fault current of 6000A. CT ratio of 200/1A, Accuracy classof 5P15 and a burden of 30 VA.,
CT Secondary Current = 6000/200 = 30A.Setting on phase fault relays = 100%Setting on Earth fault relay = 40%Z = 5+3+5+18.7 = 10 + (3+18.7) Ohms
As the current in the IDMT element rises, relay core gets saturated and IDMT relay burden getsreduced to about 0.4 (3+18.7) = 8.68 Ohms. Z = 10+8.68 = 18.68 Ohms.CT will have to develop IZ = 30x18.68 = 560 V.CT cannot develop 560 V due to saturation and relay will not operate currently.
If the CT ratio is raised to 400/1 A, IZ = 15x18.68 = 280 V. CT will have to develop only280 V which it can and relay will correctly operate.
This is more of a theoretical case and the need to raise HT feeder CT ratio to such ahigh value as 400/1 with 40 % E.F relay setting is seldom required. However, the following haspractical implications. Also refer to an old article by Er. Srinivasaraghavan, Divl. Engineer,reproduced elsewhere in this manual.
Earth fault current = 2500 A.CT ratio = 200/1 (5P15, 30 VA). Phase fault relays set at100%. E.F relay set at 20%.
IZ = 12.5 10+0.4 (75+3) = 515V. Relay will not correctly operate due to core saturation. Theremedy is to raise EF setting to 40%.
Another problem with 20% setting in E.F relay instead of 40% is that in a station withhigh fault level in the LV bus, the earth fault IDMT relay burden will now increase four fold. Inthis case, not only that high burden may cause CT saturation but may also result in over heatingof the relay coil due to excessive burden, resulting in damages to the relay.
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The CTs and relays for TNEB Substations are standardised. So, saturation of C. Tsduring faults is very rare. If at all this occurs it will be in 110 KV station with heavyconcentration of short circuit MVA in the HT busbars and for a close earth fault. If it is foundthat the CT gets saturated, the following suggestions can be considered to avoid saturation.
1. Increase CT ratio.2. Disconnect the instantaneous element in the O.C relay.3. Avoid paralleling of Power Transformers on LV side to reduce the fault current so that eachTransformer will feed certain number of feeders in a Substation.4. Disconnect the instantaneous element in the earth fault relay5. Change the CTs6. Go in for a static E.F. relay
EFFECTIVEEFFECTIVEEFFECTIVEEFFECTIVE SETTINGSETTINGSETTINGSETTING OFOFOFOFEARTHEARTHEARTHEARTH FAULTFAULTFAULTFAULTRELAY:RELAY:RELAY:RELAY:
The IDMT element of the earth fault relays impose a far higher burden on the CTs thanthe phase fault relays because of the lower settings adopted. For instance, a relay with a 20%setting will have an impedance of 25 times that at 100% setting. Not only is the exciting currentof the energizing current Transformer proportionally high due to the large burden of the earthfault relay, but the voltage drop on this relay is impressed on the current transformers of theparallel group, i.e., on the other two phases, whet her they are carrying current or not.
The total exciting current is therefore the product of the loss on one CT and the numberof current transformers in parallel. The summated magnetizing loss can be appreciable incomparison with the operating current of the relay and in extreme cases where the settingcurrent is low or the current transformers are of low performance, may even exceed the outputto the relay. The “effective setting current” in the secondary terms is the sum of relay settingcurrent and the total excitation loss. Strictly speaking, the effective setting current is the Vectorsum of the relay setting current and total exciting current, but, for electro magnetic relays atleast, the arithmetic sum is near enough, because of the similarity of power factors.
The effective setting for a range of setting values of an earth fault relay (1A relay) in theprotection scheme of “3-phase fault relays + an earth fault relay” is calculated and tabulated.
Relay burden: IDMT = 3VA, Highset = 5VA
Knee point voltage of CT = 24OV
Exciting current at Knee point = 150 milli Amps.
93
CHAPTER-VIII----------------------------------------------------------------------------------------------Relay P.S Relay Ohms Voltage Exciting Effective----------- IDMT+H.S. Developed current setting
----------------------------------------% A V I 31 Current %
A(milli Amps)
(1) (2) (1)+(2)--------------------------------------------------------------------------------------------------10 0.10 300+5 30.5 57 161 0.261 2620 0.20 75+5 16.0 30 90 0.29 2940 0.40 18.8+5 9.52 18 54 0.454 45.460 0.60 8.3+5 8.16 15 45 0.645 64.580 0.80 4.7+5 7.8 13.5 40 0.84 84---------------------------------------------------------------------------------------------------
The above excitation characteristic (voltage versus exciting current) is taken from thatof 11kv CT’s in service in a feeder in Trichy metro circle. It may be seen that reducing theearth fault setting to 20% my not serve the purpose as the effective earth fault setting is muchhigher than 20%. On the other hand, reduction of Earth Fault setting to this level brings in itswake the problem due to increased burden as already explained.
In TNEB, the neutral of the Star connected Secondary windings of the PowerTransformer is solidly earthed. As there is no impedance in the neutral to limit the earth faultcurrent, earth fault current due to earth faults closer to the station will be considerably high, andthe relay coil may experience considerable heating during severe earth fault. The lower thesetting, the higher the resistance of the relay coils. So the heating at lower setting tap iscorrespondingly higher. So an earth fault setting of 40% is suitable for the majority ofapplications and should be used unless it is known that service conditions are such that lowersettings are necessary. In territories where the earth resistance is higher and the short circuitMVA in the HT busbars is not enough to deliver sufficient earth fault current for relayoperation, lower earth fault settings could be adopted. This however should be attempted afterensuring that earth faults close to the stations causing maximum earth fault currents will notcause C.T. saturation at the lower setting.
STATICSTATICSTATICSTATIC RELAYSRELAYSRELAYSRELAYS
Static O.C. and E. F relays offer many advantages. The one relevant to the abovediscussions is the very low burden that they impose on the CTs, negligible burden whencompared to that imposed by electro mechanical relays. Static IDMT relays with both 3 sec and1.3 sec and in 1A as well as 5A versions are available. Current setting ranges from 50% to200% in steps of 10% for the O.C relays and 5 to 80% in steps of 5% for E.F relays with TMSof 0.1 to 1.0 sec in steps of 0.01 may be available. High set instantaneous elements offer settingranges of 2 to 30 times rated current in steps of 2 for O.C relays and 0.5 to 8 A in steps of 0.5 Afor E.F relays. The standard relay burdens may be as follows.
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O.C : 1A -- 0.03 VA (max) at rated current at all settings.
5A -- 0.075 VA (max) at rated current at all settings.
E.F : 1A -- 0.2 VA (max) at rated current at all settings.
5A -- 0.5 VA (max) at rated current at all settings.
Because of their very low burdens irrespective of the current settings, the static relaysare CT friendly and CTs with lesser burden and a consequent lesser dimension and cost thanthat of those in service are enough. But the many thousands of electro mechanical relays in thesub stations giving excellent performance cannot be done awa y with because protectivepractices are also economy oriented and it will take some years to phase out the existingelectromechanical ones.
TYPICALTYPICALTYPICALTYPICAL SETTINGS:SETTINGS:SETTINGS:SETTINGS:
Short circuit current set up severe mechanical stresses in the Transformer winding andits structure and produces enormous heat in the winding copper, raising the hot spottemperature. The mechanical stresses as well as the heating are proportional to the square of thecurrent.
A Transformer is designed to withstand the stresses and the heat produced in it when itfeeds short circuit. And yet, over a period of time, heavy short circuits can weaken theTransformer, its strength will be equal only to the strength of the weakest component in acomplex structure. It is therefore necessary to isolate heavy short circuits instantaneouslythrough High set element instead of following the current-time characteristics of the IDMTelement. But a low setting on the High set element can defeat the purpose of the IDMT elementie, to allow time for a light or medium and temporary fault to die out so as to avoid aninterruption of supply. So, in choosing the setting for the High set element, a balance has to bestruck.
The high-set element makes possible a reduction in the tripping time at high fault levelsand improves the over all system grading by allowing the discriminating curves behind it to belowered.
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11KV11KV11KV11KVFEEDERS:FEEDERS:FEEDERS:FEEDERS:
CT ratio : 400-200/1A
Accuracy class : 5P15, Burden = 30 VA
CT ratio adopted : 200/1A
Plug setting on phase fault relays : 100%
Plug setting on Earth fault relay : 40%
High set instantaneous element:
110/11KV SS : Phase fault relay: 8-10A
Earth fault relay: 3-4A
33/11KV SS : Phase fault relay: 4 to 6A in low fault level station6 to 8A in high fault level station.
Earth fault relay : 2 to 3A
LV BREAKERS (CT ratio selected should permit over loading of the powertransformer by atleast 10%)
i) Power Transformer : 110/11KV, 16MVACTs, provided : 1200-600/1A, 5P15, 30VACT ratio adopted : 1200/1APhase fault relay setting : 75%
ii) Power Transformer : 110/11KV, 10MVACTs, provided : 800-400/1A or 1200-600/1A, 5P15, 30VACT ratio adopted : 800/1A or 600/1APhase fault relay Setting : 75%(800/1A) or 100%(600/1A)
110 KV GC BREAKER (CT ratio should permit simultaneous over loading of allpower transformer by atleast 10 %)
CT ratio : 600-300-150-75/1A
Accuracy class : 5P20. Burden:50VA
CT ratio to be adopted :
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2x16MVA Power Transformers : 300/12x10MVA or 1x 16MVA or 1x10MVA = 150/1
Plug setting on phase fault relays : 100% or 75%as the case may be.
Plug setting on Earth fault relays : 40%
High set instantaneous element:
Phase fault relays: A minimum setting of 120% of the through fault current on the 110KVside for the maximum 11KVfault current for a 3-phase fault determined by the 11 KV bus faultlevel, assuming that the Power Transformers are at maximum tap.
Eg.: 110KVCT ratio adopted: 150/1A.
Power Transformer tap limit on the + side 15%
11KVbus fault level: 200MVA
Maximum 11KVfault current: 10500A
Maximum 110KVthrough fault current: 10500x1.15/10 = 1210A
CT Secondary current: 1210/150 = 8A
Minimum setting of High Set Inst.element: 8x1.2 = 9.6 or say 10A.
The operating time of the High set instantaneous element is usually of the order of 20milli seconds. The fault current transient in 11/22/33 KV systems will normally die out withinthis time. However, if a fault occurs when the system voltage wave is passing through zero, thefault current wave will be fully offset. The fault current wave will initially contain a d.ccomponent dacaying rapidly, with the current reaching steady state in about a cycle. Duringsuch times, the High set element in the GCCB may over reach i.e, it may act for the throughfault on the LV side of the Transformer even though the steady state through fault current iswell within the setting on the High set element. Such an occurrence will warrant a highersetting on the High set element.
Earth fault relays: High Set element is not a must. If provided, it’s setting will have nobearing on the maximum earth fault current on the 11KV side for the reason that earth fault onthe LV side is seen as phase to phase fault on the HV side. As the TMS of the IDMT relay willbe set at minimum and as any earth fault in the zone from the 110KV GCCB to the PowerTransformer HV busing will cause a very high value of earth fault current, the IDMT elementwill act in minimum time making the Highset instantantaneous element almost redundant.
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A CT ratio of 75/1 is not to be adopted for the 110 KV GCCB even if the powerTransformer capacity permits this and a minimum CT ratio of 150/1 is to be adopted to limitthe CT secondary current during 110 KV Bus fault, which may otherwise cause severe strain tothe elements in the CT secondary circuit.
OVEROVEROVEROVER CURRENTCURRENTCURRENTCURRENT RELAYRELAYRELAYRELAY CO-ORDINATION:CO-ORDINATION:CO-ORDINATION:CO-ORDINATION:
Over current relay co-ordination between adjacent levels of protection is necessary forselective tripping.
There are two basic rules for correct relay co-ordination which may be generally statedas follows.
i) Whenever possible use relay with the same operating characteristic in serieswith each other.
ii) Make sure that the relay closest to the load has current settings equal to or lessthan or at the most equal to the relays upstream, that is the primary current required to operatethe relay downstream is always equal to or less than the primary current required to operate therelay upstream.
The time interval between the operation of two adjacent relays depends upon three mainfactors.
i) The fault current interrupting time of the circuit breaker.
ii) The relay over shoot time.
iii) Errors
CIRCUITCIRCUITCIRCUITCIRCUITBREAKERBREAKERBREAKERBREAKER INTERRUPTIONINTERRUPTIONINTERRUPTIONINTERRUPTION TIME:TIME:TIME:TIME:
The circuit breaker must have completely interrupted the fault current before thediscriminating relay ceases to be energized.
OVEROVEROVEROVER SHOOTSHOOTSHOOTSHOOT
When the fault is interrupted and the relay deenergized, operation may continue for alittle longer until the stored energy if any is dissipated. In the induction disc relay the kineticenergy of the motion of disc causes this overshoot. Though relay design is directed tominimising and absorbing this energy, some allowance is necessary.
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ERRORSERRORSERRORSERRORS
All measuring devices such as relays and current transformers are subject to somedegree of error. The operating time characteristic of either or both relays involved in thegrading may have positive or negative error and some allowance has to be made.
RELAYRELAYRELAYRELAY GRADINGGRADINGGRADINGGRADINGFORFORFORFOR SELECTIVESELECTIVESELECTIVESELECTIVE TRIPPINGTRIPPINGTRIPPINGTRIPPING
A minimum time interval of 0.3 seconds (0.1 second for each of the above three factors)is allowed between adjacent relays for the maximum fault current, determined by the LV busfault level and also for the fault current determined by the setting on the High set element(primary setting). For 11 KV and 22 KV feeders, a minimum TMS of 0.05 second for the “3second relays” and 0.1 second for the “ 1.3 second relays” may be adopted for both the phasefault and earth fault relays.
Suppose the maximum 11 KV fault current determined by the 11 KV fault level is3000A. and the CT ratio is 200/1A and setting on the high set element is 8A. The Primarysetting of the High Set element is 8x200 = 1600 A. The grading margin is to be maintained for1600A as well as 3000A.
For a fault current on the 11 KV feeder of magnitude higher than the sum of the primarycurrent setting on 11 KV LVCBs, the relays in LVCBs also see the fault and pick up. When thefault current is more than the primary setting of the High set element, the feeder CB getstripped by the operation of the High set element. Till the fault current is fully interrupted, theLVCB relays will continue to have operating torque. Though the High set element of feederrelay operates in about 20 milli seconds, some allowance is necessary for the LVCB relays sothat they will not operate to trip the LV breaker. So a time of 0.3 Sec at the maximum faultcurrent may be allowed between the feeder relay and LVCB relays.
The TMS of the over current relays in the LV breaker/breakers is chosen such that theLV breaker/breakers in parallel, trip atleast 0.3 seconds later if the fault is not cleared by thefeeder breaker with the highest setting. The TMS of the over current relays in the 110 KVGroup control breaker is chosen such that the 110 KV GCCB will trip atleast 0.6 seconds laterif the feeder breaker and LV breaker/breakers do not clear the fault. The time multiplier of theearth fault relay in the 110 KV GCCB can be set at minimum as the earth fault on the LV sideof the transformer is seen as phase to phase fault on the HV side.
The over current relays of 33 KV lines are graded with the relays in the 11 KV feedersof the 33/11 KV SS in a similar way, depending on the number of stages in between. The Earthfault relay in the 33 KV feeders can be set at minimum. When gradation is done for a 110KV –33KV – 11KV system and if maximum stages are involved (11KV Feeder CB, 11KV LVCB,33KV GCCB, 33KV Feeder CB, 33KV LVCB, 110KV GCCB) some sacrifice by way of overlapping of some adjacent protections in the grading process generally at the intermediate levelhave to be made so as not to increase the TMS of the 110KVGCCB to a very high value.
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In stations where both 11 and 33 KV ratios are available, the TM settings of 110 KVGCCB is calculated from the TMS of the 11 KV LVCB and 33 KV LVCB and the higher ofthe two calculated Values is adopted as the TMS for the 110 KV GCCB.
SAMPLESAMPLESAMPLESAMPLE GRADING:GRADING:GRADING:GRADING:
Gradation of IDMT relays in single ratio Sub stations like 110/11 KV SS or 33/11 KVSS is straight forward and simple. In stations with multi ratio say a 110/33-11 KV SS, gradationis a tedious process if not a difficult one. Gradation is required only for over current relays.
Time multiplier settings are calculated by maintaining a grading margin of 0.3 secbetween adjacent breakers both at the primary setting current of the High set element and themaximum fault current. This will ensure the minimum grading margin of 0.3 sec betweenadjacent breakers at all fault currents from the relay pick up level right upto the maximum faultlevel. If grading is done based on the primary setting of highset element only, the relayoperating time differential between adjacent breakers may fall below 0.3 sec at certain othervalues of fault current with the possibility of non selective tripping. A grading margin of 0.4sec will ensure correct discrimination in the latter method i.e single gradation process. As theformer, i.e the double gradation process though tedious, helps comparatively faster clearance offaults through the IDMT element, when the relay current is below the setting on the High setelement, the same is the preferred method.
Consider the 110/33-11 KV Substation [Fig: 7 (c) & 7 (d)]. The fault levels of thebusbars of the 110 KV SS and the two 33 KV substations [Fig: 7 (a) & 7 (b)] fed by the 110KV SS, capacity of the Power Transformers, the maximum tap available in the powerTransformers, the CT ratio adopted in the various breakers are indicated. The TMS of both theover current relays and earth fault relays of all the 11 KV feeders at all the three substations areset at minimum, i.e. at 0.05 see for 3 second relays and at 0.1 see for 1.3 second relays.Similarly the TMS of earth fault relays in the 33 KV feeders and the 110 KV GCCB are set atminimum. The grading of IDMT over current relays is done as follows. Grading is done withthe feeder having the highest primary current setting i.e. the lowest PSM for a given faultcurrent.
In this example, the bus fault levels, breaker configuration, power transformercapacities and CT ratios are taken from the actual values of a 110/33-11 KV and 33/11KVruralsub stations in Tiruchy Region.
I . 33 KV S.S.1 (Refer Fig. 7-A).
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11111111KVKVKVKV FEEDERFEEDERFEEDERFEEDER
C.T ratio : 200/1IDMT relay setting : 100%Relay graph : 3 secHigh set element : 6 ATMS adopted : 0.05 secPSM = 6 x (100/100) = 6Time from graph = 3.85 secOperating time = 3.85 x 0.05 sec = 0.193 sec
33333333KVKVKVKV GCCBGCCBGCCBGCCB
(a) BASED ON HIGHSET ELEMENT OF 11 KV FEEDER:
C.T ratio : 300/1Plug setting : 75%Relay graph : 3 secPrimary setting current = (6x200) x (11/33) x 1.09 = 436 A(The factor 1.09 is related to the maximum tap in the Transformer, +9% in thiscase)PSM = (436/300)x (100/75) = 1.94Time from graph = 10 secTime required = 0.193+0.3 = 0.493 secTMS = 0.493/10 = 0.049 or say 0.05 sec
(b) BASED ON MAXIMUM FAULT CURRENT:
11 KV fault level = 39 MVAMaximum 11 KV fault current = 39000 / (√3x11) = 2047 AHigh set element operates. Operating time = 0.02 sec33 KV through fault current = 2047 x (11/33) x 1.09 =744 APSM = (744/300) x (100/75) = 3.3Time from graph = 5.8 secTime required = 0.02+0.3 = 0.32TMS = 0.32/5.8 = 0.055 or say 0.06Higher of (a) & (b) = 0.06TMS of 33 KV GCCB = 0.06.
(c) High set element :33 KV through fault current = 744 ACT secondary current = 744/300 = 2.48AHighset element has to be set atleast at 3 AMaximum fault current for 33 KV bus fault
= 50000/ (√3x 33) = 875 ACT secondary current = 875/300 = 2.92 A
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So no meaningful setting can be adopted on highset element. High set element to bekept disconnected.
33333333KVKVKVKV FEEDERFEEDERFEEDERFEEDER -I-I-I-I (AT(AT(AT(AT 110110110110KVKVKVKV SS)SS)SS)SS)
(a) BASED ON 11 KV FAULT LEVEL:33 KV through fault current = 744 APSM of 33 KV GCCB at 33 KV SS - 1 = 3.3Time from graph = 5.8 secTMS of 33 KV GCCB = 0.06Relay operating time = 5.8 x 0.06 = 0.35 secGraded time of 33 KV feeder .1= 0.35+0.3 = 0.65 secPSM of 33 KV feeder .1 = (744/300) x (100/100) = 2.48Relay graph of 33 KV feeder .1 = 1.3 secTime from graph = 2.95 secTMS of 33 KV feeder .1 = 0.65/2.95 = 0.22
(b) BASED ON MAXIMUM 33 KV THROUGH FAULT CURRENT:
(for 33 KV bus fault at 33 KV SS-I)33 KV through fault current =875APSM of 33 KV GCCB = (875/300) x (100/75) = 3.9Time from graph = 5.05 secOperating time of 33 KV GCCB = 5.05x0.06 = 0.3 secGraded time of 33 KV feeder .1 = 0.3+0.3 = 0.6 secPSM of 33 KV feeder = (875/300) x (100/100) = 2.92Time from graph = 2.6 secTMS= 0.6/2.6 = 0.23Higher of (a) & (b) = 0.23TMS of 33KVfeeder-1 = 0.23
(c) High set element:
Maximum 33 KV through fault current = 875 ACT secondary current = 875/300 = 2.92 A33 KV bus fault level at 110 KV SS = 218 MVAMaximum 33 KV line fault current = 218000/(√3x33)= 3814 ACT secondary current = 3814/300 = 12.7 AHigh set element may be set at 8 A
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II.II.II.II. 33333333KVKVKVKV SSSSSSSS –––– IIIIIIII (Refer(Refer(Refer(Refer fig.fig.fig.fig. 7-B)7-B)7-B)7-B)
11 KV FEEDER
CT ratio : 300/1Plug setting : 75%Relay graph : 1.3 secHigh set element : 6 ATMS adopted : 0.1 secPSM = 6x(100/75) = 8Time from graph = 1.42 secRelay operating time = 1.42 x 0.1 = 0.142 sec
33 KV FEEDER-2 (AT 110 KV SS)
(a) BASED ON HIGH SET ELEMENT (11 KV feeder)
11 KV fault current = 6x300 = 1800 A33 KV through fault current = 1800 x (11/33) x1.15 = 690 A(The factor 1.15 is related to the Transformer maximum tap of +15%)Relay operating time of 11 KV feeder = 0.142 secGrated time = 0.142 + 0.3 = 0.442 secCT ratio of 33 KV feeder = 200/1Plug setting = 100%PSM = 690/200 =3.45Relay graph = 3 secTime as per graph = 5.5 secTMS = 0.442/5.5 = 0.08
(b) BASED ON 11 KV FAULT LEVEL:
11 KV fault level = 37 MVA11 KV fault current = 37000/ (√3 x 11) = 1942 A33 KV through fault current = 1942 x (11/33)x1.15 = 744 AHigh set element of 11 KV feeder operatesRelay operating time = 0.02Graded time = 0.3 + 0.02 = 0.32 secPSM = (744/200) x (100/100) = 3.72Time as per graph = 5.2TMS = 0.32/5.2 = 0.06Higher of (a) & (b) = 0.08TMS of 33 KV feeder – 2 = 0.08
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(c) High set element :33 KV fault level of 33 KV SS 11 = 49 MVAMaximum 33 KV through fault urrent = 49000/(33x √3) = 857ACT secondary current = 857/300 = 2.86 A33 KV bus fault level at 110 KV SS = 218 MVACT secondary current = 3814/300 = 12.7 AHigh set element may be set at 8 A
III.III.III.III. 110110110110KVKVKVKV SSSSSSSS (GRADING(GRADING(GRADING(GRADINGFROMFROMFROMFROM 33333333KVKVKVKV SIDESIDESIDESIDE )))) (Refer(Refer(Refer(Refer fig.7.c)fig.7.c)fig.7.c)fig.7.c)
33333333KVKVKVKV LVCBSLVCBSLVCBSLVCBS
Graded with 33 KV feeder.1
(a) BASED ON HIGH SET ELEMENT:
Primary setting = 2400 APSM of 33 KV feeder.1 = (2400/300) x (100/75) = 10.7Time from graph : 1.27 secTMS = 0.21Operating time = 1.27 x 0.21 = 0.27 secGraded time of LVCBS = 0.27 + 0.3 = 0.57 secPSM = (2400/2x300) x (100/100) = 4Time from graph = 5 secTMS = 0.57/5 = 0.114 = 0.12
(b) BASED ON MAXIMUM 33 KV FAULT CURRENT:
33 KV fault level = 218 MVA33 KV fault current = 218000 / (√3 x 33) = 3814 APSM of 33 KV feeder-1 = (3814/300) x (100/75) = 16.95Time = 1.07Operating time = 1.07 x 0.21 = 0.22 secGraded time of LVCBS = 0.22 + 0.3 = 0.52 secPSM = (3814/2x300) x (100/100)= 6.36Time = 3.65 secTMS = 0.52/3.65 = 0.142 = 0.15Higher of (a) & (b) = 0.15
TMS of 33 KV LVCBs = 0.15
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110/33-11 kv s.s33 kv SIDE:
110KVGCCB
FIG-7C
2
1
33 KV218 MVA
300/1100%
Pr.TR.216 MVA-5to+15%
200/1100%
300/1100%
33 KVFDR-1300/1
75%
33KVLVCB
33 KVFDR-2
110KV716MVA
300/1100%
Pr. TR. 116 MVA-5to+15%
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CHAPTER-VIII
200/1100%
110 KVGCCB
10 MVA300/1100%
110 KV716MVA
600/1
11 KVLVCB
11 KVfeeder
11KVCB
11 KV109 MVA
Pr.TrGCCB
11 KV SIDEFIG-7D
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CHAPTER-VIII
110110110110KVKVKVKV GCCBGCCBGCCBGCCB
(a) BASED ON H.S ELEMENT OF 33 kv FEEDER.1:
PSM of LVCB = 4Time from graph = 5 secOperating time = 5 x 0.15 = 0.75 secGraded time of 110 KV GCCB = 0.75 + 0.3 = 1.05 secPSM = (2400/300) x (33/110) x 1.15 x (100/100) = 2.76Time from graph = 6.8 secTMS = 1.05 / 6.8 = 0.154 Or say 0.16
(b) BASED ON 33 KV FAULT LEVEL:
PSM of LVCBs = 6.36Time from graph = 3.65 secTMS of LVCBS = 0.15Operating time = 0.548 secGraded time of 110 KV GCCB = .548+0.3 = 0.848PSM = (3814/300) x (33/110) x 1.15 = 4.39Time from graph = 4.6 secTMS = 0.848/4.6 = 0.184 Or say 0.19Higher of (a) & (b) = 0.19TMS of 110 KV GCCB = 0.19
110110110110KVSS:KVSS:KVSS:KVSS: GRADINGGRADINGGRADINGGRADINGFROMFROMFROMFROM 11111111KVKVKVKV SIDESIDESIDESIDE
11111111 KVKVKVKV FEEDERFEEDERFEEDERFEEDER
CT Ratio : 200/1Plug setting : 100%Graph : 3 secHigh set element : 8 ATMS : 0.05 sec11 KV fault level : 109 MVAMaximum 11 KV fault current = (109000 / √3 x 11) = 5721 A
(a) PSM = 8
Time from graph = 3.35 secOperating time = 0.05 x 3.35 = 0.168 sec
(b) PSM = 5721/200 = 28.6
Time from graph = 2.2Operating time = 0.05 x 2.2 = 0.11 sec
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11 KV LVCB
CT ratio : 600/1Plug setting = 100%
(a) PSM = (8x200/600) x (100/100) = 2.67
Time from graph = 7 secGraded time = 0.168 + 0.3 = 0.468 secTMS = 0.468/7 = 0.067 = 0.07
(b) PSM = (5721/600) x (100/100) = 9.54
Time from graph = 3.1Graded time = 0.3 + 0.11 = 0.41 secTMS = 0.41/3.1 = 0.132 Or say 0.14Operating time = 0.14 x 3.1 = 0.434 secHigher of (a) & (b) = 0.14TMS of 11 KV LVCB = 0.14
110110110110KVKVKVKV GCCBGCCBGCCBGCCB
CT ratio = 300/1Plug setting = 100%
(a) PSM = (8x200) x (11/110) x (1.15/300) = 0.61Relay will not pick up.
(b) PSM = 5721 x (11/110) x (1.15/300) = 2.19
Graded time = 0.434 + 0.3 = 0.734Time from graph = 8.9 secTMS = 0.734/8.9 = 0.082 Or say 0.09TMS = 0.09TMS as from 11 KV side = 0.09TMS as from 33 KV side = 0.19Higher of the above two = 0.19TMS of 110 KV GCCB = 0.19
(c) HIGH SETMaximum 11 KV fault current = 5721Maxmum 110 KV through fault current = 657 ACT secondary current = 657/300 = 2.19 AMaximum 33 KV fault current = 3814 AMaximum 110 KV through fault current = 3814x(33/110) x1.15=1316 ACT secondary current = 1316/300 = 4.39 A
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Higher of the above two = 4.39 AMaximum 110 KV bus fault current=(716000/√3x110) = 3758 ACT secondary current = 3758/300 = 12.53AHigh set element may be set at 6 A
As seen under “ Faults and fault current analysis”, the relay settings have beencalculated based on the maximum three phase symmetrical bus fault MVA. This generallygives satisfactory results. However, the fact is that unsymmetrical faults such as “ phase toground” and “phase to phase” faults are the ones that occur more than 90% of the times withthe former being the most common of the faults. So there may be occasions, though rare, whennon-selective tripping occurs. For instance, the GCCB may trip along with the LVCB for aphase to phase fault on the LV side. When such a non-selective tripping occurs, the GCCBrelay settings may have to be revised suitably, in this particular instance based on the maximumphase to phase fault current (to be worked out), instead of the 3-phase fault current, keeping inmind that the phase to phase fault on the L.V. side is seen as a 3-phase fault on the HV sidewith a current distribution of the form 1:2:1 (Ref. Fig. 5) for the“DY” Transformer and that assuch the reflected. Fault current on the H.V. side at maximum tap must be multiplied by thefactor 1.15 (i.e; 2÷√3).
REVISIONREVISIONREVISIONREVISION OFOFOFOFSETTINGS:SETTINGS:SETTINGS:SETTINGS:
The 110 KV symmetric fault level for the grid stations for maximum generationconditions and with all transformation equipments in service is provided by the Head Quartersbranch at periodical intervals from which the MRT Engineer is to calculate the fault level forthe various bus bars of the 110 KV, 66 KV and 33 KV substations. Revised fault levels have tobe determined as and when warranted for changed conditions like addition of Transformercapacity, upgradation of substation etc. Relay settings have to be revised for change in bus faultlevels and as and when there is change in CT ratio and breaker configuration in the substation.
BREAKERBREAKERBREAKERBREAKER RUPTURINGRUPTURINGRUPTURINGRUPTURING CAPACITY:CAPACITY:CAPACITY:CAPACITY:
As and when there is an upward revision of fault levels in the various busbars, the MRTbranch should check and see whet her the short circuit withstanding capacity of the breakers areenough. If not, replacement of the existing breaker with a breaker of higher rupturing capacitymust be recommanded in writing.
ANNUALANNUALANNUALANNUAL TESTS:TESTS:TESTS:TESTS:
Primary injection tests are done during commissioning and as and when required. Theseare not part of the Annual tests. This test in one stroke determines the healthiness of overallprotection.
Secondary injection tests are done on relays during commissioning, annually and as andwhen the need arises i.e., when the relay settings have to be revised, in correct operation ofrelay is observed etc. Relay testing procedure is detailed elsewhere in this manual.
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During annual tests, the CT Secondary circuit should be meggered and the I.R. Valuerecorded. Opening time of the circuit breaker in all poles must be checked and noted. The OpenCircuit D.C.Voltage, the current drawn by the trip coil and the voltage avai lable at the trip coilterminals when current flows through the trip coil should also be measured and recorded.Comparison with the previous values will confirm whet her the trip coil as well as the entireD.C. Circuit from the battery through the D.C. Panel, Control and relay panels down to the tripcircuit are in perfect health. The Trip Coil plunger and tripping mechanism, the breakerauxiliary contacts etc., should be given a thorough examination. The Station battery also needscareful examination and readings should be taken by the MRT branch and recorded. TheStation earth pits should be checked and the earth pit resistances measured and recorded. Acombined value less than 0.1 Ohms may be considered as being very good.
The D.C.Panel also needs inspection and examination. All the alarm and trip circuits ofthe power transformers and common station alarms must all be checked for correct operation.All the D.C. fuses and links must also be checked individually. The Master tripping relay is tobe initiated and tripping of the GC and LV breaker, checked. The tripping Register is to becarefully reviewed.
Any lack of maintenance work on the part of the substation staff that may have anadverse impact on protection of substation equipments must be taken to the knowledge of thesubstation controlling Engineers for corrective steps.
Non selective tripping if any should be carefully studied and analysed. Revision of relaysettings if required should be done.
The MRT branch plays the most vital role in the well being of the distribution circle.The MRT Engineer should shurg off tendencies if any to do annual tests in a routine way andbeing complacent. It is important to keep in mind that the annual tests are not a routine task buta part of the preventive maintenance for keeping the protection system of the sub-station inperfect working order. Mere MRT skill is not enough. The leader at work should keep his eyeswide open and tune his mind to the job on hand and ensure that the technical staff carry out theworks to a good degree of perfection. He must also be on the look out for things that have thepotential to create protection problems in the immediate or near or distant future and shouldone be identified, corrective measures should be taken. Works should be properly planned andhaste should be avoided but speed is important. When power through an equipment is switchedoff for rectification/testing works, the Board loses some revenue during the period of outagebut the worse thing is that a lot many consumers are deprived of electricity, the absence ofwhich puts them to a lot of inconvenience and hardship. The quicker the power supply isresumed the better for the consumer as well as the Board. The abi lity to restore supply with theleast interruption without sacrificing the quality and standard of works is the hall mark of aquality MRT Engineer. An MRT man taking pleasure in doing that kind of work doesn’t expectaccolades from any quarter but does his job with pride and job satisfaction.
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CASECASECASECASE STUDYSTUDYSTUDYSTUDY
1)1)1)1) TRIPPINGTRIPPINGTRIPPINGTRIPPING FORFORFORFORNONONONOFAULT.FAULT.FAULT.FAULT.
One fine morning, an Assistant Engineer from a Rural O&M Section who made a visitto the MRT Office, casually mentioned to the Asst.Executive Engineer/MRT that the 11KVfeeder feeding his area had been tripping frequently on E.F.relay indication and the fault hadnot been located yet. When grilled, he mentioned that the line had been tripping on earth faultrelay indication for the past four days, that the main and spur lines had been thoroughlypatrolled and doubtful insulators, changed and that the line every time was test charged OK buttripped after feeding loads for some time. The weather had been clear, no wind and the dayswere bright. There was still no word yet from the Asst.Engineer of the adjacent section underwhose control the 33/11KVSubstation concerned was in.
By then, the AEE/MRT was fairly certain of what was going on. A couple of hours later,the MRT gang was in the Substation. Primary injection test established that the Secondarycircuit of the blue phase C.T. was open. The CT ratio was 150/1 with 40% earth fault setting.With one CT not delivering secondary current, there was residual current flowing through theE.F. relay under normal load Conditions and no wonder the line tripped on Earth fault relayindication, every time the load current rose above 60A (150x40/100= 60A). Refer fig 8(B). TheAmmeter crack switch in that old Kiosk did not have a provision to read the residual current.
It was one of those old breakers and there were two single phase energy meters in thetwo outer phases for energy measurement by two wattmeter method. The Current leads in theenergy meter on blue phase were found released, separated and taped. The pressure leads werealso found released but the two leads had been shorted and taped. Needless to add that thepressure circuit fuse was found blown.
When enquired, the Asst.Engineer incharge of the S.S. innocently stated that on findingthe energy meter stuck, he had released the leads making through the current connections andisolating the pressure leads, applying insulating tape to the exposed wire ends and that he wasto have sent the defective meter to the MRT Section for rectification. As an Electrical Engineer,the A.E had remembered that the CT Secondary should not be kept open circuited but in hisenthuciasm had mistaken the pressure leads as current leads and vice versa.
The AEE/MRT was tempted to take the A.E./S.S to task for the frequent interruption ofsupply in the feeder for five days. Instead he felt that the better course of action would be tosupport and educate the A.E. for the initiative and interest shown by him though he ended upmaking a mistake.
Years later there was another case similar to that above in a different S.S and theproblem was reported to the MRT branch within a couple of days. Again that was an old kioskand the sub station staff appeared to have dislodged the wire when they replaced the oil in theOCB two days earlier.
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113
CHAPTER-VIII
In both the cases the CTs were found healthy. Such occurrences of CT secondarygetting open circuited are extremely rare. Should a thing like that happen, ratio and secondaryexcitation tests should be conducted and the condition of the CT, ascertained before putting itback in to service.
2)2)2)2)NONONONOTRIPPINGTRIPPINGTRIPPINGTRIPPING FORFORFORFORFAULT.FAULT.FAULT.FAULT.
Here also, a CT is involved but the effect is just the opposite. One evening, the MRTgang while returning from work entered a way side sub station to attend to a minor problem inthe station reported a few days back. As the A.E/MRT was at work, the A.E.E/MRT was goingthrough the tripping Register when he found some thing odd with the trippings in a particularfeeder. All the trippings were through the O.C. relays, there was no tripping through the Earthfault relay for the past six months. Annual relay test was still a good four months away. Actingon a hunch, the A.E.E. got the A.E. to take L.C. on the breaker and megger the CT Secondarycircuit, releasing the earth connection. Energy measurement in that feeder was also by twowattmeter method and the current coil of one of the two meters was found to have got earthed.That was originally a 2.5A rated energy meter, the original current coil had been released atMRT Lab and current coil, rewound with thinner wire for 2.5 times the original number ofturns for converting the meter for 1A operation. The thin leathoroid paper provided over theiron core as insulation had given way earthing the current coil.
With the neutral of the CT Secondary solidly earthed, if a second earth develops, the CTSecondary current during an earth fault on the line, takes the least resistance path by passingthe residual circuit. The E.F. relay will not operate and the fault will be cleared by the o.c. relayconcerned provided the fault current is more than the primary setting of the o.c. relay. Refer fig8(c).
3) This happened more than 10 years ago. A new substation with a single 110/11KV, 10 MVAPower Transformer was comissioned in a neighbouring distribution circle which was formedout of the parent circle in the late seventies. HBB make differential relay was provided forTransformer protection. The compliant was that that differential relay was mal-operating oncein a while. The A.E/SS had mentioned that casually to the AEE/MRT of the parent circle oneday.
The A.E/SS was informed that wrong differential CT/relay connection could triggerdifferential relay operation when the load on the transformer exceeded a certain value and wasadvised to get the connections checked by the territorial MRT branch. An year later, based onthe report that the transformer differential relay at that substation was kept disconnected onaccount of relay defect, the E.E/MRT of the parent circle (No territorial E.E/MRT in theneighboring Circle concerned) was directed by the Head-quarters branch to inspect thesubstation concerned and sort out the problem. The E.E/MRT took his MRT gang with him forthe inspection.
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CHAPTER-VIII
CT secondary circuit of ‘w’ Phase has got earthed @ ‘P’(Load current on feeder neglected)
For an earth fault on the ‘u’-Phase line, the CT secondary current flows as marked, bypassingthe earth fault relay.
Similar will be the current flow, for earth faults on the other phase lines also.
Earth fault relay will not operate for earth fault on any phase.
Fig. : 8-c
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CHAPTER-VIII
It was found that no provision had been made to measure the three differential currentsand provision for measuring only the secondary pilot currents of the HV and LV differentialCTs had been made. The transformer was taken out of service and work was started forproviding three current terminals for measuring the differential currents returning from therelay. In the meanwhile the cables from the bushing CTs were physically traced down to theterminal block in the marshalling box. It did not take more than ten minutes to identify theproblem. The HV yellow phase bushing CT secondary lead was found pitted against the LVblue phase CT Secondary and vice-versa. For that wrong sequence, currents would flowthrough the operating winding of the yellow and blue phases of the differential relay undernormal load conditions and the HBB differential relay would act when the load on thetransformer exceeded 20% of its full load. The wrong connections were corrected, additionalcurrent terminals were provided in the control room for measuring the differential currents, thetransformer was put on short circuit and the nine currents, (3 HV CT Pilots + 3 LV CT pilots +3 differential) were measured and found correct. The transformer was put back into servicewith the differential relay and there were no further differential trippings.
The Asst.Exe.Engineer and Asst.Engineer/MRT of the Distribution Circle concernedwere both men of known sincerity. Though both had been in that MRT branch for some time,that was the first time that they had to commission Transformer differential protection.Obviously, they were not aware of the most vital check in commissioning Transformerdifferential protection viz putting the Transformer on Short circuit and measuring thedifferential currents besides the currents from the HV and LV bushing CTs. This test in a singlestroke can confirm all that are to be confirmed, i.e., correctness of sequence of CT secondaryconnections, correctness of CT polarity and ratio, correctness of the delta formation of the CTsecondary on the star side of the Transformer, correctness of differential relay connections,healthiness of the differential CT/Relay circuitry and the absence of an earth connection in theCT secondary differential relay circuitry except for the earth connection of the neutral point ofthe star connected CTs on the delta side of the Transformer. Perhaps there were none aroundduring commissoining time experienced enough to guide the inexperienced Engineers.
4)4)4)4) 125125125125%%%% CORRECTCORRECTCORRECTCORRECT ::::
When some one is very correct it may be said that that person is one hundred percentcorrect or even 110% correct. But never is it said that one is 125% is correct. In CT terms onecan say 125% is correct. This is just to mean that a C.T. can be continuously operated at 125%rated current. There have been instances when loads were restricted to avoid tripping of feederon overload. To cite a case, due to addition of loads in 11 KV line fed off a 33/11 KV SS, the33KV line at the 110 KV SS which was already loaded to the brim during peak hours wastripping on overload. Load shedding at the 33/11 KV SS was done to prevent the overloadtrippings of the 33 KV line eventhough the Power transformers at either station had margin.The substation Engineer was asked to raise the plug setting of o.c. relays on the 33KVfeeder to125% by the MRT branch as higher ratio was not available in the CTs. The concerned S.S.Controlling Officers were concerned about the well being of the CTs, a needless concern. TheCTs are designed to accept such contingencies. The only problem will be that the Ammeter willbe off scale when the line current goes above 100% during which time the Ammeter crackswitch is to be kept off.
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However, this is not to mean that the plug settings can be raised to 125% and the matterleft at that. Action must be taken to replace the CTs with ones with a higher ratio at the earliestand till then the plug setting will be 125% correct.5)5)5)5)NONONONOTOTOTOTO GASGASGASGASLOCKOUTLOCKOUTLOCKOUTLOCKOUTANDANDANDAND NONONONO TOTOTOTO SSSSSSSS LOCKOUTLOCKOUTLOCKOUTLOCKOUTTOO:TOO:TOO:TOO:
The Annunciator announced SF6 gas lockout condition in the 110 KV Group Controlbreaker at an important 110 KV Substation about 2 hours drive from the MRT Head-quarters.The annunciation came around 7 AM and thanks to the phone with the AEE/MRT’s neighbour,the A.E.E. incharge of the SS could talk to the MRT man within fifteen minutes of theannunciation. The A.E.E. in control of the SS gave the message to the MRT Man and said thathe would get a blink on the 110KV line feeding his SS, open the incoming isolator andsafeguard his equipment to which the MRT Man replied that the right thing to do would be notto do anything and that the substation could continue to be fed till the arrival of the MRT gang.The substation AEE wasn’t too sure and it took some convincing on the part of the MRT manto have the other man accept the proposal. Around 11 AM, the MRT Van drove into the SS andas the MRT man got down, the incoming 110KV isolator kept opened and securely lockedgreeted him. He starred at the station A.E.E. who ducked saying that the boss didn’t want totake chances. So the MRT man thought he would mind his own business which was to find outand set right what was wrong. As it were, there was no SF6 gas leakage, the gas density was allright and the trouble was with the magnetic contactor which was set right. The breaker was putback into service there by freeing the substation from an unnecessary power lockout. Beforeleaving, however, the Station A.E.E. and A.E. were taken aside and told why the station couldhave been kept in service with the incoming breaker in gas lockout condition.
With low gas density, the breaker is not to be operated but then the condition hadalready locked out the breaker. The breaker would not operate but would remain like a simpleswitch in closed position. Power could flow through the breaker with no harm done. The onlything of some relevance would be that the breaker would not offer protection to the transformer.But then what if an incoming breaker like this fails. Don’t we make through the jumpers andfeed load through the station till another breaker is provided which may take a few days. TheTransformer of course will lose local Highspeed protection through the differential relay. OnBuchhloz alarm the incoming line would have to be got tripped through the grid stationoperator or before that the protection at the feeding end might see the fault and trip the gridstation breaker. It would be a calculated risk worth taking and which is an accepted practice inthe Board in an emergency condition.
6)6)6)6) WHICH/WHOWHICH/WHOWHICH/WHOWHICH/WHO ISISISIS ATATATAT FAULT?FAULT?FAULT?FAULT? THETHETHETHE TRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER ORORORORTHETHETHETHE TESTINGTESTINGTESTINGTESTING KIT?KIT?KIT?KIT?THETHETHETHE MRTMRTMRTMRT WINGWINGWINGWING OROROROR THETHETHETHE TRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER REPAIRREPAIRREPAIRREPAIR WING?WING?WING?WING?ANYTHING/ANYONEANYTHING/ANYONEANYTHING/ANYONEANYTHING/ANYONE CANCANCANCAN BE.BE.BE.BE. ITITITIT ALLALLALLALL DEPENDSDEPENDSDEPENDSDEPENDS…………....
The Buckholz relay of one of the two 66/11KV. 5MVA, ‘AEG’ make Transformers in asubstation acted accompanied by the actuation of the E.F. relay of the 66 KV GCCB. The MRTtest results were all satisfactory. But the results of the two tests on the gas collected in theBuchholz chamber were positive. An arcing fault was suspected and the transformer wasdeclared defective. Another 5 MVA was allotted and commissioned in place of the defectiveunit. The transformer was moved out for examination and repair.
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Later it was learnt that the transformer was declared healthy and erected elsewhere. Oncharging, the Buchhloz relay had again acted. Again the transformer was moved to the repairbay and on that occasion the bushing CTs were also examined and one of the HV bushing CTwas found to have arced to the frame at the neck. The defect was attended to and thetransformer successfully commissioned.
So, satisfactory MRT test results alone cannot be taken as being conclusive in declaringa transformer as being healthy when the Buchholz relay acts with gas collection. Adverseresults on gas analysis invariably points to a fault inside the transformer.
A few years earlier to the above occurrence a failed transformer, repaired and servicedat the repair bay was sent to an adjacent distribution circle for erection and commissioning. TheMRT Wing on testing the transformer declared it as being defective. The E.E./Transformer whowas once an MRT man himself won’t buy it. He called for a second test on the transformer andagain the same declaration by the MRT Wing. Again the E.E/Transformer won’t accept it. Heperhaps thought enough was enough and traveled for 300KMs from Madras to see the testingfor himself. He witnessed the test, checked the transformer testing kit declared that thetransformer testing kit was defective and not the transformer and indeed that was the case. Thetransformer was satisfactorily commissioned. So there can be no substitute for experience.
There have been occasions when the MRT Wing was stumped by the results of DCresistance test on the transformer secondary winding. For values being in the milli ohm range,the test has to be done carefully taking precautions. The ideal way to measure this value is byusing a Kelvins bridge. In conducting this test through a wheatstone bridge or by Ohms law,sufficient care must be taken to eliminate contact resistance. Strictly speaking that ofcoursecannot be eliminated altogether but can be brought down from milli level to micro level.Otherwise spurious D.C. resistance values will be indicated.
Whether a defective unit is declared as healthy or a healthy unit is declared as defective,it is the reputation of the MRT Engineer that gets a beating. So one has to be that extra bitcareful in coming to a conclusion. But that doesn’t mean that one could take his own time incoming to a conclusion. A totally involved MRT Engineer devoted to his craft learns fast. Anexperienced, alert and thoughtful one always arrives at right conclusion in quick time.
7.7.7.7. ISISISIS INDEPENDENTINDEPENDENTINDEPENDENTINDEPENDENT POLEPOLEPOLEPOLEOPERATEDOPERATEDOPERATEDOPERATED 110110110110KVKVKVKV BREAKERBREAKERBREAKERBREAKER ININININ AAAA SUB-STATIONSUB-STATIONSUB-STATIONSUB-STATIONWITHWITHWITHWITH 30V30V30V30VDCDCDCDCACCEPTABLE?ACCEPTABLE?ACCEPTABLE?ACCEPTABLE?
During March” 90, the 66/11 KV Karur SS was upgraded to 110/11 KV SS. AnIndependent pole operated “ HBB” make SF6 breaker was erected as 110 KV Group controlbreaker to control one 110/11 KV, 10 MVA Power Transformer initially, with a second 10MVA unit to be erected there after. An “S & S” make 11 KV outdoor type VCB was erected asthe LV breaker. 2 Nos 30 V, 64 AH batteries were erected one set for the 11 KV feeders andanother set for the 110 KV GC and 11 KV LV breakers and Power Transformers. A new D.Cpanel was erected and the dc supply to the 110 KV GCCB was found taken through 4x2.5sq.mm cables with two leads per terminal, i.e., 5 sq mm leads, effectively.
118
CHAPTER-VIII
It was suggested by the MRT wing that the independent pole operated 110 KV GCCBmight be replaced with a gang operated 110 KV breaker to reduce the breaker tripping currentfrom (3x7) Amps (Trip coils rated to draw 7A at 30 V DC) to (1x7) A thereby reducing thedrop in the dc supply cable and at various locations between the battery and breaker. The MRTwing was also concerned over the reliability of 110 KV GC and LV breaker trippings during amaster relay initiation at a future date with the 30 V battery having to deliver 21 Amps (3x7A)to the GC breaker trip coils and 16 A (2x8A) to the two nos 11 KV LV breakers,symultaneously. The matter was taken upto Head Quarters level but in view of the S.S, havingto be upgraded before 31.03.90 and the non availability of a ready 110 KV gang operated 110KV SF6 breaker, instructions were given to go ahead and commission the substation as erected.
During precommissioning tests on the 110 KV GCCB, the following observations weremade.
1. Breaker tripping currents measured by individual energisation.2x2.5 sq.mm cables for DC + and DC -. Battery charger off.----------------------------------------------------------------------------------------------------------------Phase Trip coil No.1 Trip Coil No.2
------------------------------------ -------------------------------------------Open T.C. T.C. Open T.C. T.C.Circuit current voltage Circuit current voltageDC volts DC volts
----------------------------------------------------------------------------------------------------------------R 30 V 5.6 A 21.5 V 30 V 5.5 A 21.0 VY 30 V 6.0 A 20.0 V 30 V 5.9 A 21.0 VB 30 V 5.8 A 20.5 V 30 V 5.9 A 21.0 V
----------------------------------------------------------------------------------------------------------------
Total 3 phase trip coil current measured by symultaneous energisation of trip coils.Open circuit D.C volts : 30 VTotal trip coil current (TC1) : 10.5 A , i.e., 10.5 / 3 = 3.5A per coilTrip coil volts : 15 V each
Values not accepted by MRT wing.
2. The DC supply cables were reinforced by S.S Erection branch and test repeated.DC + : 4x2.5 Sq.mmDC - : 4x2.5 Sq.mmBattery charger “ ON” and in trickle charge.Open circuit D.C volts : 33 VTotal trip coil current (TC1) : 15 A , i.e., 15 / 3 = 5A per coilTripcoil volts : 20 V. each
Values not accepted by MRT wing.
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CHAPTER-VIII
3. The DC supply cables were further reinforced by S.S Erection branch and test repeated.DC + : 8 x 2.5 Sq.mmDC - : 8 x 2.5 Sq.mmBattery charger ‘ON’Open circuit D.C volts : 35 VTotal trip coil current (TC1) : 20 A , i.e., 20/3 = 6.66A per coilTrip coil voltage : 25 V, each
The values were passed by the MRT branch.
The breaker opening time was to be 28 milli sec as per Manufacturers specifications.
In the first case, the opening times were 50 milli seconds in each pole.
In the third case, the opening times were 30 milli seconds in each pole and accepted.
Tests were repeated for TC2 of all poles and results were satisfactory.
The Board has now changed the DC supply norm for 110 KV radial substation from30V, 64AH to 110V, 120AH, so matters as above may not be of concern to the MRT branch.But in old 110 KV stations where 30 V, 64 AH DC supply is in vogue and where suchindependent pole operated 110 KV breaker may be in service, the substation and MRT wingmust give the highest priority to maintaining the battery and the 110 KV GC/11 KV LV breakertrip circuits in perfect working order and there shall be no complacency whatsoever in thematter of protection.
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CHAPTER-VIII
AnnexureAnnexureAnnexureAnnexureSample fault MVA calculation for a 110/11kV substation is provided for guide lines.
110kV
10 MVA10% 11kV
The fault MVA level at the sending end i.e., at the 110kV bus of a nearing 230 kV substation istaken as ……2000MVA and the distance is taken as 10km from 230kV S/S
The source impedance at 110 kV bus on 230/110kV S/S = (KV)²Fault MVA
Source impedance =110 x 110 = 6.05 ohms2000
Impedance of the line= 4.75 ohms/km (ACSR Leopard)For 10 km = 47.5 ohms
Total impedance upto 110 kV bus of 110/11kV S/S = 47.5+6.05= 53.55 ohms
Impedance of the transformer = 10 x kV2
100 MVA
10 x 110 x110100 10
= 121ohms
Total impedance up to transformer = 53.55+121 = 174.55 ohmsTotal impedance converted to11kV side of the Transformer
Z2 = Z1 (kV2²/kV1²)= 174.55 (11²/110²)= 1.746ohms
Fault MVA level at 11kV bus = 11²/1.746 = 69.3MVAFault current =3637 amps
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CHAPTER-CHAPTER-CHAPTER-CHAPTER-IXIXIXIX
DISTANCEDISTANCEDISTANCEDISTANCE RELAYSRELAYSRELAYSRELAYSEr. M. Arunachalam
EE / GRT
The distance relay responds to input quantities as a function of the electrical circuitdistance between the relay location and point of faults. Basically the distance relay comparesthe current and voltage of the power system to determine whet her the fault exists within oroutside its operating zone. The pioneer beam-type distance relay can be used to illustrate theoperating principle. The relay’s zone of operation is a function of only the protected lineimpedance, which is a fixed constant, and is relatively independent of the current and voltagemagnitudes. Thus, the distance relay has a fixed reach, as opposed to over-current units, forwhich reach varies as source conditions change.
LineLineLineLine sectionsectionsectionsectionrepresentationrepresentationrepresentationrepresentation
AAAA linelinelineline sectionsectionsectionsection isisisis representedrepresentedrepresentedrepresented inininin thethethethe powerpowerpowerpower systemsystemsystemsystem asasasas below:below:below:below:
A ZE Bs ZL
Zs source nBalance point or reach Zu source
In the above figure, ZL is the impedance of the line to be protected from the bus A tobus B. Zs is the equivalent source impedance up to bus B, and Zu the equivalent sourceimpedance up to bus B . ZE represents the equivalance of the interconnecting system betweenbuses A and B except for line Z L.
RepresentationRepresentationRepresentationRepresentation ofofofof aaaa linelinelineline sectionsectionsectionsectionandandandand thethethetheR-XR-XR-XR-X diagram.diagram.diagram.diagram.
BBBBn
source Zs
Bus voltage
Blance point
source Zu
AAAAnnnn
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The distance relay is applied to the bus A line terminal. The system can be plotted on anR-X diagram. With O as the origin, the phasor impedance ZL. Of the line is drawn in the firstquadrant.
Either per unit or ohms can be used, although secondary or relay ohms are generallypreferred. The CT secondary formed in star (wye) is connected to distance relay.
Zsec = Zrelay = Zpu*Rc/Rv
Rc and Rv are the ratios of CTs and PTs respectively. Zs is the source impedance, canbe plotted from A in to the third quadrant at B, the source impedance Zu can be extended, bothimpedance at their respective magnitudes and angles. In applications involving several linesections, Zu would be the remote line section beyond bus B; Zs would be the line sectionbehind the A line relay or to the left of bus A(if we assume there were no other lines or sourcesat either bus A or B)
A number of distance relay characteristics plotted on the R-X diagram may be a circle,ie., whenever the phasor ratio of V/I falls inside the circle, the distance unit operates. Bymodifying either the restraint and/or operating quantities, the circle can be shifted as shownbelow:
OffsetMhoZsr
Zu
ZL
B
X
B
R
XLong reach Zs R
Line short reach Zs RZsr=0
Directional unit
NZL
X X nzl
ImpedanceMho
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Load can be represented on these R-X diagrams as an impedance phasor, generallylying near the R axis (depending on the power factor of the load current on the line).The phasorlies to the right(first quadrant of the (R-X diagram) when flowing into the protected line fromthe bus and to the left (third quadrant of R-X diagram) when flowing out of the line to the bus.Load is between 0 and 5 A secondary at or near rated voltage; faults generally produce muchhigher current levels and lower voltages, so that the load phasor usually falls outside thedistance operating circles.
Historically three zones of protection have been used to protect a line section andprovide back up for the remote section. Each of the three zones uses instantaneous operatingdistance relays. Zone-1 is set for 80% of the line impedance. Zone-2 is adjusted for 100% ofthe line, plus 50% of the shortest adjacent line off the remote bus incase adjacent shortestfeeder being a double circuit 50% of any one feeder. Zone-3 is set for 100% of the line, plusapproximately of the adjacent longest line off the remote bus incase adjacent largest feeder is ofdouble circuit 110% of any one of the feeder. If the coverage overlaps because of long linesfollowed by shortlines, time gradation shall be provided. These classical settings define theprotective zones only if there are no infeed effects. In practice, there is almost always an infeedeffect at the buses, which reduces the reach. The settings guidelines are as per the Instructionsin the memo No:
CE/P&C/SE(D)/P&C/EPCII/AEE5/F.Protn/D.34/2k dt 13.11.2k
Since zone-1(Z1) tripping is instantaneous, the zone must not reach the remote bus,hence the 80% settings. The 20% margin provides a safety factor for security,to accommodatedifferences or inaccuracies in relays, current, potential transformers and line impedance. The20% end zone is protected by the z0ne-2 (Z2)
relay, which operates through a timer T2, set with one step of coordination timeintervals for overcurrent relays. Two zones at each terminal are required to protect all of theline section,with 60 to 80% of the line having the simultaneous instantaneous protection. Thisprotection is independent of system changes and loading.
The backup zone-3 also operates through a timer T3 , set as shown to coordinate withthe zone-2 unit of the remote bus. Coordinating distance relays, with their fixed reach and time,is much easier than coordinating the over current relays.
PhasePhasePhasePhase MhoMhoMhoMhoDistanceDistanceDistanceDistance
The reach setting (replica line impedance) is the phase impedance. Steady state characteristic:Circle with a diameter that is equal to the reach setting and passes through the origin at an angleequal to the line characteristic angle, with respect to the resistance line.
R
Ziang
ZrelayR
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CHAPTER-IX
Ground Mho Distance
The reach setting is the loop impedance. The characteristics are the same as the Phase Mhodistance elements.
Dynamic Characteristic
The circle that passes through the replica line impedance and the source impedance.Reactance characteristic
The reactance relay does not vary in the presence of are resistance, because it isdesigned to measure only the reactive component of the line. Any increase in the resistivecomponent of the fault impedance will have no effect upon the relay reach, as the relay willcontinue to measure the same value of the reactance. However, when the fault resistance is ofhigh value that load and fault current magnitudes are of the same order, the reach of the relay ismodified by the value of the load and its power factor and may either over-reach or under-reach.
Ground Quadrilateral Distance
The reach setting is the loop impedance. The resistance element that
extends from the resistance axis at an angle equal to the line characteristic angle.
X
Zsource
Ziang
Zrelay
nZLX
X
RZlang
32QFDirec.elemm
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CHAPTER-IX
COMMISSIONING AND TESTING OFDISTANCE RELAYS
1.1.1.1. INSPECTIONINSPECTIONINSPECTIONINSPECTION ANDANDANDAND INSTALLATION.INSTALLATION.INSTALLATION.INSTALLATION.
A visual checks of the relay to be done for any transport damages at the site. The relayshould be checked for its auxiliary voltage rating as per the data stated and its connection for itscorrect polarity. Check also that all units , possible extra auxi liary relays, etc., are included inthe equipment in accordance with the apparatus list.
2.2.2.2. PROGRAMMINGPROGRAMMINGPROGRAMMINGPROGRAMMINGANDANDANDAND SETTINGS.SETTINGS.SETTINGS.SETTINGS.
The modern relays are having a large number of programming features and are to bedone as per the programming manual of relay. The modern numerical relays will startfunctioning correctly only with proper programming. The relay manufacturers will supply thenecessary software for the programming through computers, which will check up the relaysystem. For programming of the relays of static versions , making of jumpers and positioningof programming switches should be done in each of its printed boards. While doing theprogramming in the static relays, the D.C supply should be switched off.
The distance relay is always set in accordance with the selectivity plan for the network.The positive sequence, zero sequence impedance of the network should be found from data’s ofthe line configuration. In short line applications the possibility to cover enough fault resistancewill be a major consideration. Load encroachments are not so common. Individual setting ofresistive and reactive reach are features which will improve the situation. For lines shorter than8-10 Km, over reaching schemes are more suitable than understanding schemes in most cases.Errors in measuring transformers and line data combined with the influence of load transfermakes an under reaching scheme less suitable. The use of an over reaching scheme willimprove the resistive coverage. In some applications, the ultimate solution is to add adirectional comparison ground-fault relay to the line protection system. In short lineapplications parallel lines are frequent. The likely hood to have fault current reversals in thesystem must thus be considered when selecting settings and communication scheme.
The phase fault relays are based on a unbalance measurement, which gives a cross-polarizedmho characteristic. As with any cross polarized mho relay, the effect of source impedance is tooffset the mho circle to include the origin in case of forward faults. Figure below shows themho characteristic for phase to phase faults with zero source impedance and the effect ofincreasing the source impedance.
Zs-/Zm=5Z3
Z1
Z2
Zs-/Zm=0
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The operating characteristics for phase-ground and 3-phase faults are a compositecharacteristics, may be made by combining mixed polarized mho and quadrilateralcharacteristics operating in a logical arrangement. The two characteristics are selected to ensureboth speed and sensitivity. The mho characteristic will provide a limited resistive reachcompared to the quadrilateral characteristic in short lines applications. On the other handapproximately 4-5 ms in operating time is gained. In long line appl ications the margin to theload impedance will be a major consideration.
Since the phase-phase measuring relays are based an unbalance impedancemeasurements, they do not operate for three phase load or power swing conditions. Therefore,no precautions are necessary to limit the relay settings to avoid load encroachment.
For parallel lines or double circuit lines, the negative and positive sequence mutualimpedance between the different branches will be only 2-3% of the positive sequence and willbe very little effect on measurement. Whereas the zero sequence mutual coupling impedancecan not be ignored, since the value can be 70% of the zero sequence impedance. The mutualimpedance will influence the distance measurement of ground faults, and cause either anextension or a reduction of the reach relative to the set reaches.
The line impedance is converted to the secondary side of the instrument transformerswith the formula
Z sec = CT ratio/ VT ratio x Z prim
Z sec = VT sec x CT prim x Z prim
VT prim CT sec
The impedance actually seen by the relay might differ from the calculated values due toerrors such asa) Errors introduced actually by CTs and VTs, under transient conditions.b) Inaccuracies in line zero sequence impedance data and the effect of zero sequence
compensation setting.c) The effect of infeeds between relay and fault location including influence of different
X0/X1 ratios of the various sources.d) The effect of load transfer between the ends of the protected lines especially when
appreciable fault resistance must be recognized.e) Zero sequence mutual coupling from parallel lines.f) The fact that the phase impedance of untransposed lines is not equal for all fault loops.
The difference between the impedance of different phase-phase loops can be as much as5-10%.
Because of the errors above Zone-1 reach is normally limited to 80% of the calculated linesection impedance.
For the same reason the Zone-2 reach should be set to at least 120% of the calculated linesection impedance to ensure that it will always over reach the line section.
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CHAPTER-IX
Zone-2 reach can be set longer but it should never exceed 80% of either of the followingreaches:1) The reach corresponding to the impedance of the protected line section plus the first zone
reach of the shortest adjacent line section.2) The reach corresponding to the impedance of the protected line plus the impedance of the
maximum number of transformers in parallel on the bus at the remote end of the protectedline.
Zone-3 is mostly used as a back-up zone:i) set to 150-200%of the line section to provide backup forZone1 and Zone2.ii) Set in the reverse direction to provide back up for the bus bar protection.
Zero sequence compensationThe measuring loop at single-phase to ground faults consists of two impedance. Z1 the positivesequence impedance in the phase conductor and Zn the ground return impedance Zn is definedas Z0 – Z1
3The ground return impedance is set by the zero sequence compensation factor Kn and theground return impedance (Zn) angle ϕn.
The performance for single phase to ground faults is of great importance as normally more than70% of the faults on a transmission line are single phase to ground. The fault resistance iscomposed of two components, the arc resistance and the tower footing resistance.
Rarc = 28707 x l(in meter)I¹·4 I actual fault current
1 length of the arc and is approximately equal to 2-3 times the arc foot point spacingDistance relays can not be used to detect very high resistive ground faults as the reach islimited by the load impedance and load transfer. For faults with fault resistance higher thanwhat can be detected with impedance measuring an additional zero sequence ground fault relayhave to be included.
To avoid load encroachment problems and healthy phase relay operation under combinedthree phase load and ground fault a maximum resistive reach in the quadrilateral characteristicshave to be adopted.
POWERPOWERPOWERPOWER SWINGSWINGSWINGSWING BLOCKINGBLOCKINGBLOCKINGBLOCKINGDistance relays which respond to balanced 3 phase changes in impedance will be
affected by system power swings. These swings or oscillations occur following a systemdisturbance such as load change or fault clearance. As the generators attempt to find a stableoperating angle relative to each other, they overshoot the final position and continue oscillatinguntil stability is achieved. The extend of the oscillations depends upon the severity of thedisturbance, and the natural stability of the system. The oscillation rate is determined by theinertia of the system and impedance between different generators. When the generation at eachend of a line protected by distance relays oscillates, the impedance seen by the relays variesalong some locus. It will be seen that this locus can enter the distance relay characteristic, and
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CHAPTER-IX
cause relay operation if steps are not taken to prevent this. The general practise is to block thepower swing in all zones of distance protection. The practise will be modified according tosystem studies.
Power line carrier aided transfer tripping (as enclosed in separate sheet) auto Reclosingand syrichronization.
PowerPowerPowerPower linelinelineline carriercarriercarriercarrier aidedaidedaidedaided InterInterInterInter Tripping:Tripping:Tripping:Tripping:
The zone I coverage of the distance protection will cover only the 80% of the protectedline and will not cover the “ end zones”, about 20% of the protected feeder length. If the faultoccurs at the end zone of the protected line, one side the protection will clear the faultconstantaneously, but other side will face it as zone & fault will clear after 0.4 see.
Faults remaining on the feeder for zone 2, time may cause the system to be comeunstable. The fault will cause permanent lock out of the circuit breaker at each end of the linesection, on usage of auto re closing in the feeder. The general practice is to avoid the autoreclosing if the carriers aided scheme is not adopted.
The unit scheme of protection is to compone the condition at both ends of the feeder.Whenever the fault is internal or external to the protacted section. The simplerr way ofspeeding up fauet clearence at the terminal which clears an end zone fault in zone 2 time is toadopt a direct, accelerated transfortrip. The Direct transfer trip relay, scheme in which 2000 Irelay is used to send a signal to the remove and of the feeder, the receive relay contact iscorrected directly to the trip relay. The disadvantage of this scheme is the possibility ofconsidered tripping by accidented operation or mal operation of signalling equipment.
The scheme is more secure by supervising the receive signal with the impedance zone 2measurement operation before allowing tripping and the scheme is known as permissive underreach transfer trip scheme.
The accelerated transfer trip scheme is similar to Permissine under reach transfer tripscheme. In its principle of operation but it is applicable only to zone suitched distance relayswhich shares the same measuring which for both zone 1 & 2 and.
In the above relays the under reach zone 1 unit is arranged to send a signal to the remoteend of the feeder in addition to tripping the local breaker. The receive relay contact is arrangedto operate the range change relay which extends the reach of the measuring unit from zone 1 tozone 2. Immediately instead of at the end of the zone 2 time delay. This accelerate the faultclearance as the remote end.
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CHAPTER-IX
Permissive under reach scheme general arrangement in distance relay.
Z1 - Zone Trip Contact
Z2M - Zone 2 measuring element contact
Z2T - Zone 2 timer / Contact
Z3M - Zone 3 measuring element contact
Z3T - Zone 3 timer / contact
TR - tripping relay.
Z3M
Z2M
Z3T
Z2T
Z1
Z2T
Z3T
TR
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RR
RR = Receive relay contact in carrier set,
RRX = Receive and relay at Distance relay
ReclosingReclosingReclosingReclosing andandandand synchronizing:synchronizing:synchronizing:synchronizing:
The large majority of the over head line faults are transient and case can be cleared bymomentarily de energising the line. It is therefore, feasible to improve service continuity byautomatically reclosing the breaker after relay operation. The automatic reclosing will improvecontinuity of service and increase the availatility of transmission line, but certain pre cautionsare to be taken.
1. The generator should never be connected to a system on automatic reclosing,time the angle of voltages across the breaker in the vicinity of the generator is an inadequatemeasure of the possible hazard associated with closing the breaker. The sudden change inpower in the generator following closure is however a key indicator.
2. When a transformer is subjected to a substantial through fault severe forces aredeveloped within and between winding, which produce motion. Repetitive motion can producefailure of transformer.
RR
Z3M
Z2M
Z2M RRX
Z3T
Z2T
Z1TR
Z2T
RRX
Z3T
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The desired attributes of a reclosing system vary with user requirements. In an areawith high level of transient fault, (lightning incidences) more transmission time breakers will besuccessfully re closed on the first try. Single short re closing relays those which produce onlyone reclosure until reset are entirely satisfied.
Multiple shot reclosing relays are warrented on disribution circuits with significant freeexposure, where an unsucessful reclosure would generally mean a customer outage.
The speed of tripping is a significant factor in the success of a reclosure on atransmission circuit. The faster the closing, the loss fault damage and/or degree of arcionization, the less the shock to the system on reclosure and greater the likelihood of reenergization with out subsequent tripping. The probability of sucessful reclosing is improved itreclosing occurs only after a high speed pilot trip. The high speed of pilot tripping is achievedwith the help of communication channels like power line carrier communication protectioncouplers. Such a system will eliminate the high of probability of unsuccessful re-closure onnon pilot trips, particularly for end-zone faults in which clearing OCCURS sequentially and thede energized time is short. The general practice of utilization of single shot re-closing is withthe assistance of PLCC network, and on failure of PLCC network the function of re-closing isblocked in the relay.
A sample calculation to be adopted for re-closure for dead time and re-claim time istabulated below. The longer death time is required because of the fact that the two phasesremain energized tend to keep the arc conducting longer.
ASPERASPERASPERASPER GENERALGENERALGENERALGENERAL PRACTICEPRACTICEPRACTICEPRACTICE ONEONEONEONESHOTSHOTSHOTSHOTRECLOSERECLOSERECLOSERECLOSE ISISISIS ADOPTEDADOPTEDADOPTEDADOPTED
DEADDEADDEADDEAD TIMETIMETIMETIME
Dead time should be able to ensure complete deionization of arc
A study of a larger, period on operating experience has formulated the minimum deadtime ast = 10.5 = KV
34.5Where KV is the phase to phase voltaged the system.
Assuming arc deionization time as typical 0.17 sec for a 230 KV system
Recommended dead time setting is as below= 0.17 sec + 0.02 sec. (margin) = 0.19 sec.
Hence, the adopted setting should be more than 0.19 sec
Adopted at 0.25 sec.
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RECLAIMRECLAIMRECLAIMRECLAIM TIMETIMETIMETIME
The reclaim time is the time to be allowed, for the permanent opening of all for pole after oneshot of single pole re-closure, if the fault persists.
Recommended time = CB closing mechanical reset + 5 sec + gas pressure recovery time
Now, CB closing mechanical reset = 60 sec (max – assumed) to be checked withBKR test result
Gas pressure recovery time : 30 sec. (max-assumed) to bechecked with BKR test result.
Re claim time = 60 + 5 + 30 = 95 sec
Note: Reclaim time can be checked with breaker duty cycle and can be modifiedSuitably, if required.
FactorsFactorsFactorsFactors governinggoverninggoverninggoverning applicationapplicationapplicationapplication ofofofofReclosing:Reclosing:Reclosing:Reclosing:
1. For instantaneous reclosing, the protective relay contact must open in less thanthe breaker re-close time.
2. The breaker latch check and when applicable the low pressure switch should beused to avoid operating the breaker if the mechanisms is not prepared to a accept closingenergy or gas pressure is inadequate.
For instantaneous re-closing, arc deionizime time must be considered.
Synchronizing:Synchronizing:Synchronizing:Synchronizing:
Synchronization check has to be made to sense the voltage on the two sides of thebreaker are in exact Synchronism i.e. the angular difference between the two voltages and thefrequency difference is below the present value. The check is required to minimize the shockto the system when breaker closer. The angular difference between the voltages does notdetermine the transient to which the system will be subjected upon closure. Rather, the shockto the system is related to the voltage across the breaker contacts, the phasing voltage is thecritical quantity in determining whet her the breaker is allowed to close.
The system is in Synchronization the single shot reclosing doesnot required theSynchronization. The Synchronization check is an essential system of unattended or attendedlocations for automatic Synchronization or supervision for manual Synchronizing.
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SAMPLE SETTING CALCULATION FOR DIST ANCE RELAY
1.1.1.1. PRIMARYPRIMARYPRIMARYPRIMARYVALUEVALUEVALUEVALUE
The line data which is to be protected comprises of a small length of
Cable on one side , with O/H line in between the feeder is ….LINE LENGTH = 14.877 Km of OHL(GTACSR ,1x 402/phase)
+ 0.5 Km of 900 sq.mm XLPE at one side,+0.5 km of 900sq.mm XLPE at the other end
OHL (Z1) = 0.0901+ j 0.4604 ohms/kmOHL (Z0) = 0.114+ j 0.501 ohms/kmXLPE cable (Z1) 1200 sq.mm = ( 0.02032+j0.2773) Ω/Km
XLPEcable (Z1) 1000 sq.mm = (0.0235+j0.2452)Ω/Km
XLPE cable (Z0) = (0.1984 +j 1.938) Ω / km
TOTAL (Z1L) = (1.3684 + j 7.0895) Ω
= 7.2204 ∠79.075°
TOTAL (Z0L) = (1.8944 + j 9.3914) Ω
Line impedence of adjacent = 7.005 Km of Cable 1200 sq.mmshort line (Z2L)
= (0.1423 +j 1.9425) Ω=1.9477 ∠85.81°
Line impedence of adjacent = 27.440 Km of OHL+0.425KmLongest line (Z3L) 0f1000sq.mm cableAt one end+0.034Km
of 630sq.mm0FC= (2.4818 + j 12.7436 ) Ω
= 12.9830 ∠78.98°
Fr = 0.263 ohm per loop
S = 151 MVA (Maximun Load Transfer)
F = 50Hz
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WhereZ1 = Positive sequence impedance
Z0 = Zero sequence impedance
Fr = Additional fault resistance (arc and towerfooting resistance)
S = Apparent power (maximum power Transferred)
Iprim./sec. = 1200 / 1 A
U prim./U.sec. = 110000 / 110V , 50Hz√3 √3
The relay shall work with following setting
Zone 1 = 80% of the lineZone 2 = 100% of the line + 50% of Adjacent short line
Zone 3 = 100% 0f the line +110% of the adjacent longest line
Transformation Ratio = CT/PT = (1200/1) / (110000/110) = 1.2
STARTER REACH: V²/S = 110²/151 = 80.132 Ohms(primary value)= 80.132*1.2 = 96.16 Ohms
Maximum permissible reach of the start relay Zmax = 0.5*96.16 = 48.08 Ohms
The starter relay setting is determined by the Zone-3 reach and the load impedance. Theradius of the start relay circle is determined by setting the Zone-3 reach by overreaching about 35%.
Z1L (secondary) = Z1L (primary) x Transformation ratio= (1.3684 + j 7.0895) Ω x 1.2 = 1.6421 +j 8.5074 Ω= 8.6644 ∠ 79.08°
Z2L (secondary) = ( 0.1423 +j 1.9425) x 1.2= 0.1488 +j 2.0307 = 2.0362 ∠85.81°
Z3L (secondary) = (2.4818 + j 12.7436) x 1.2= 2.5945 + j 13.3222 = 13.5725 ∠78.98°
Z0L (secondary) = (1.8944+j9.3914 ) x 1.2 = 1.9804 + j 9.8178= 10.0155 ∠84.02 ohm/phase
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2.2.2.2. ZONE-1ZONE-1ZONE-1ZONE-1 SETTING:SETTING:SETTING:SETTING:
Zone 1 impedance = 0.8 Z1L
= 0.8x 8.6644 ∠79.08° ohm/phase= 6.9315 ∠79.08° ohm/phase
In case of numerical relays the value calculated shall be programmed directly In the case ofstatic/ magnetic relays the relay manual shall be referred for setting the calculated values byway of selections
2.2.2.2. ZONE-2ZONE-2ZONE-2ZONE-2 SETTING:SETTING:SETTING:SETTING:
Zone-2 settings =100% of the line + 50%of the adjacent shortest line
= 1.6421 +j 8.5074 + 0.5 x (0.1488 +j 2.0307)= 1.7165 + j 8.7464= 8.9132 ∠79.17°
According to the relay manual the settings are to be adopted for the Zone-2 reach. Similar tothe Zone-1 the numerical relays shall be fed with the value.
3.3.3.3. ZONE-3ZONE-3ZONE-3ZONE-3 SETTING:SETTING:SETTING:SETTING:
The relay can be set with Zone – 3 in reverse looking blocking mode or onforward reach,
Required Zone-3 forward reach = 100 % of Z1L +110% of Z3L= 1.6421 +j 8.5074 + 1.1 x (2.5945 + j 13.3222)= 4.4961 + j 23.1618= 23.5941 ∠79.17° ohm / phase
As per relay manual the relay settings shall be calculated for the selection of relayconstants for the value calculated above. For the numerical relays the value calculated shall beprogrammed directly.
The above setting shall be programmed in case of numerical relays. If the relay is ofstatic type, the availability of reverse zone shall be detected first and setting shall be set as perprocedure given by the manufacturer.
StarterStarterStarterStarter reachreachreachreach ::::= 1.35 x 23.5941 ∠79.17° ohm / phase= 31.8521 ∠79.17° ohm / phase
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5.5.5.5. EARTHEARTHEARTHEARTH FAULTFAULTFAULTFAULT COMPENSATIONCOMPENSATIONCOMPENSATIONCOMPENSATION SETTINGSETTINGSETTINGSETTING
KN = Z0L – Z1L = (1.8944 + j 9.3914) - (1.3684 +j 7.0895)3Z1L 3x (1.3684 +j 7.0895)
= 0.109 ∠-1.9667°
ZNL = KN x Z1L = 0.109 ∠-1.9667° x 8.6644 ∠ 79.08°= 0.9344 ∠77.13°
6.6.6.6. RELAYRELAYRELAYRELAY CHARACTERISTICCHARACTERISTICCHARACTERISTICCHARACTERISTIC ANGLEANGLEANGLEANGLE SETTINGSETTINGSETTINGSETTING
Z1L = 1.6644 ∠ 79.08° ohm , therefore θ PH = 80°
ZNL = 0.9344∠ 72.13° ohm, therefore θΝ = 78°
7.7.7.7. POWERPOWERPOWERPOWER SWINGSWINGSWINGSWING BLOCKINGBLOCKINGBLOCKINGBLOCKING
In normal scheme, where Zone-4 elements will be reverse looking , the Zone-5 forward reachshould be set to the starter forward reach , and the Zone-4 reverse reach , should be set to thereverse reach.
Thus Zone-5 forward reach = 31.8521 ∠79.17° ohm / phaseZone-4 reverse reach = 1.5094 ohm (25% of Zone I )
Proportion of Z0ne-4 reverse reach =
Zone-4 reverse reachZone-5 forward reach + Zone –4 reverse reach
= 1.7329 = 0.6515631.852+1.7329
The reaches are set so thatThe total reach to be set = 1.3 (Z5 forward +Z4 reverse)Set the timer for identifying the fault condition to 40ms
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7.7.7.7. ACCURACYACCURACYACCURACYACCURACY OFOFOFOF IMPEDANCEIMPEDANCEIMPEDANCEIMPEDANCEMEASUREMENTMEASUREMENTMEASUREMENTMEASUREMENT
Zone-1 accuracy is +5% for System Impedance Ratio’s (SIR) of upto 30 and +10% for SIR ofupto 60. If +5% of accuracy of Zone-1 is required, then the operate in voltage for earth faultsand phase faults need to be more than the minimum required voltage of the relays.
Minimum Fault Level at 110KVbus of S/S 8066 = 2237.8 MVAAssuming that the Zero sequence source impedance equals the positive sequence.
ZS1 = ZS0 = 110² = 7.786 ohm2237.8
SequenceSequenceSequenceSequence sourcesourcesourcesource impedanceimpedanceimpedanceimpedance ::::
ZSE = ZS1 + ZS2 + ZS0 = 7.786 ohm3
LineLineLineLine positivepositivepositivepositivesequencesequencesequencesequence impedanceimpedanceimpedanceimpedance totototoZone-1Zone-1Zone-1Zone-1 reachreachreachreach pointpointpointpoint
= 80% of 8.6644 ∠79.08° = 6.9315∠79.08° ohm
Therefore relay voltage for a phase fault
= Z1L x E = 6.9315 x 110 = 51.8 VZS1+Z1L 7.786+6.9315
Line zero sequence impedance to Zone-1 reach point= 80% of 10.0155 ∠84.02 = 8.0124∠81.08 ohm
Line fault loop impedanceZLE = Z1L+Z2L+Z0L = 6.9315+6.9315+8.0124 = 7.2918 ohm
3 3
Therefore relay voltage for an earth fault
ZLE x E = 7.2918 x 110 = 30.71V(ZSE + ZLE )√3 (7.786+7.2918)√3
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8.8.8.8. COMMUNICATIONCOMMUNICATIONCOMMUNICATIONCOMMUNICATION CO-ORDINATIONCO-ORDINATIONCO-ORDINATIONCO-ORDINATION TIMETIMETIMETIME
tp = Signalling channel p/u time + margin
= 20ms (assumed) +20ms= 40ms
td = 20ms – (signalling channel reset time)Assuming signalling channel reset time as 10ms
td = 20ms –10ms = 10ms
9.9.9.9. TIMETIMETIMETIME LAGLAGLAGLAG
It is decided to set T2 = 400ms and T3 = 1000ms
To set on the relayT2 = (32 + 8)10 = 400 msT3 = (32 + 16 ) 20 = 960ms
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TESTINGTESTINGTESTINGTESTING PROCEDURESPROCEDURESPROCEDURESPROCEDURESThe testing engineer should be supplied with all the required settings for the relay.
Some specific information about using the testing kit should be known to understand how toperform the tests using the specified testing kit or other suitable equipment s.
TESTINGTESTINGTESTINGTESTING EQUIPMENTSEQUIPMENTSEQUIPMENTSEQUIPMENTS REQUIRED:REQUIRED:REQUIRED:REQUIRED:
1) ZFB or TURB or TURH or FERAJA or any other make testing kit2) 2 multi meters(20000Ω/V on DC range)3) 1 high impedance digital voltmeter4) 1 variable auto transformer for rated current capacity5) 1 variable resistor 0-2000 for rated current capacity.6) 3 double pole switches7) 1 d.c power supply (if panel supply unavailable)8) Test plugs according to the type of relays9) Any monitoring point box is available for the relay10)1 phase angle meter11)1 electronic insulation tester(if panel wiring is to be checked)
SECONDARYSECONDARYSECONDARYSECONDARY INJECTIONINJECTIONINJECTIONINJECTION TEST:TEST:TEST:TEST:
ISOLATION:-ISOLATION:-ISOLATION:-ISOLATION:-
All the relay contacts can be prevented from operating while the rest of the relay functionsnormally and gives indications. It is however necessary to check the operation of contactsduring commissioning, so alternative trip isolation must be obtained.
INITIALINITIALINITIALINITIAL CHECKS:CHECKS:CHECKS:CHECKS:
DC supplies to the panel should be checked for its polarity and if the panel is notequipped with DC supply, a suitable supply should be connected to the relay terminal/test block.On power up the observations as per the instruction manual of the relay should be checked andthe relay inoperative alarm contact should be in open position.
In the case of numerical relays, on power on , the enable target display illuminated andthe relay contact for power on indication should open. Front panel LED and LCD screen shouldbe checked . The relay should be checked for its self test status and the LCD screen of the relayshould show the status ok display. By using the up and down arrow buttons to view the specificrelay self-tests and should come out from status display.
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CHECKING UP OF VOLTAGE DETECTORS: Each phase to ground input voltage ismonitored and the pick up of the voltage detector is to be fixed., say 44.5V (±10%) Themonitor selection should be selected ( The protection schemes are fully functional when inmonitor options). Apply voltage in turn to each voltage input and determine the pickup anddrop off of each level detector . The pick up will be indicated by an indication and the drop offshould be with in 20% of pickup.
FIXEDFIXEDFIXEDFIXEDCURRENTCURRENTCURRENTCURRENT LEVELLEVELLEVELLEVEL DETECTORS:DETECTORS:DETECTORS:DETECTORS:1. LOW SET: Each phase current is monitored, and the pickup of the level detector isdependant on the setting of the impedance the most sensitive value being 5% of In.The pickup is given by 5 x In amps ±10%
100 x Zphselect monitor option , inject current in turn into each pair of phase terminations and determinethe pick up and drop off of each level detector. The drop off should be with in 20% of thepickup.
2222HIGHHIGHHIGHHIGHSET:SET:SET:SET:Current setting is given by 7.5 xIn amps ±10% select monitor option and
100 x Zph determine the pick up anddrop off value
BIASED CURRENT LEVEL DETECTORS (HIGH and LOW SET)Biasing only comes into action when a minimum phase difference current is exceeded. Theresidual signal is derived by summing the vectors of the voltages in the relay which areproportional to the currents. The operation level when biasing varies directly with the highestphase difference current until a limit is reached. The minimum operate level varies inverselywith Zph. In commissioning it is only necessary to check this level.Low set: The minimum operate current level is given by = 5 x In amps ± 20%
100 x Zphselect monitor option . By injecting current in to each phase input and determine the pickup anddrop off which should be with in 20%of each other.
High set: The minimum operate value is given by :- 16 x In amps ±20%100 x Zph
select monitor option . By injecting current in to each phase input and determine the pickup anddrop off which should be with in 20%of each other.
REACH AND FAULT LOCATION CHECK:
The relay should be connected with three current source and voltage sources and should be inpositive direction. The relay should be provided with trip isolation before commencing the testsbut the operation of the contact should be checked for all measurements.Before starting the testing of the relay the engineer should make himself familiar with therelays programming techniques and the menu if it is a numerical relay
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The testing equipment must be able to supply phase to ground volts and currents in the correctphase relation for a particular type of fault on the selected relay characteristic angle. Thefacility to alter the loop impedance (phase-ground compensation or phase-phase) presented tothe relay is essential, this may be a continuos adjustment or steps of around 1% in the voltageor current.The testing equipment should be connected to the relay terminal through the test block takingcare not to open circuit the CT secondary. Care must be taken to isolate other circuit in seriesconnected to the distance relay like LBB relay by blocking its operation. VT supervisionshould be set “ TO ALLOW TRIP”, if possible giving indication only. It will be more useful ifSTART INDICATION is ENABLED which will speed up the process of determining thereaches.Commence with connections for an R-N fault. Apply an impedance slightly greater than thecalculated first zone reach (or the equivalent voltage and current to the value of impedance withline angle setting in the testing kit) momentarily to the relay will indicate start RN (for theenabled forward zone) DEF start will also be optained if fitted and enabled. Make smalladjustments, say 1% to the impedance and reapply to the relay until the highest impedance,which gives the indication Z1, RN occurs.
Note: If the circuit Breaker open condition is connected through optical isolator input or bysome other means then all faults can appear as SOTF. Appropriate action must be taken toprevent the condition to appear in the relay.
If the relay is provided with fault locator feature also, sufficient time should be given to acceptthe relay indication for calculation of fault location.The measured impedance should be with in 10% of the calculated value assuming the angle ofthe impedance presented is with in 5degrees of the angle set for Ph-Ground. Check theappropriate contacts operated for single or three phase tripping as selected. In particular checkthe trip contact and the block autoreclose contact.Change the direction of the current and ensure that the relay does not operate (check with aclose up fault briefly applied)Repeat the above tests for the other two phases i.e., Y-N and B-N. The test should be done forzone-1, zone-2 and zone-3 reaches.
Carry out the tests as for ground faults for R-Y, Y-B and B-R faults. Under commissioningconditions the measured value should be with in 10% of the calculated values. The test shouldbe repeated for all Zones of measurements.Note: If test kit similar to ZFB is usedThe phase to neutral voltage not involved in the selected fault does not maintain the correctphase relationships and the reach for slightly off angle faults may be affected due to movementof the relay characteristic angle on the impedance plane.Resistive reaches check (If Quadrilateral characteristic is applicable)Checks are done using resistive faults, thus in the forward direction all zones will operate at thesame loop impedance. The checks should be done for all phase to ground faults and resultsshould be with in 15% of the selected settings.Operation time check:
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Applying a fault at 50% (approximately) should check zone-1 operation time of Zone-1 reach.An interval meter should be started when the fault is applied and stopped by a suitable pair ofcontacts.To obtain correct operating times, it is essential to use dynamic tests starting with all phase toneutral voltages above the level detector setting (the test sets when connected for phase faultsdo not have resistors fitted which tie down the neutral point. Check Ph-N voltages with 100%potential setting). If this is not done, filters in the voltage and current circuits will already beswitched in and operation times will be slower by upto 20ms.If the polarizing quantities are not correctly provided by the test set, some slower times may bemeasured. This may be noticed when doing phase-phase faults on the test kits.When test kits connected for phase faults and 110V-phase/f selected with 100% potentialsetting the phase to neutral voltages are not balanced it is only necessary for them to be greaterthan about 45V.Times vary with the point-on-wave of fault application. It is thus suggested that number ofoperations be done for each type of fault and the mean value recorded.Times vary with the type of characteristic, typical times beingShaped Mho 15-30msQuadrilateral 20-35msIf the polarizing quantities are not correct or if the voltage filters are in initially times mayincrease by 10-20ms.The time measurement should be done for all Zones of measurements.
Simulation of power swing in the relayFault loop selected is R-YApply an impedance just outside Zone-2or 3 as appropriate and reduce it with out switching off(say 1% steps) until power swing indication, check that the PSB alarm contact also closes.Apply the fault again in to just inside Zone-2 or 3 as appropriate and then move the fault againto inside zone-1 in less time than the lowest time delay setting. Only the Zones not blocked bythe PSB feature will change to measuring the condition as fault.Voltage transformer supervisionOperation occurs when zero sequence voltage above a set level is detected without any zerosequence current being detected above a set level. The relay is set to block and the blocking cantake place simultaneously. The relays have the facility for self resetting of the VTS contact foralarm and blocking.Switch on to fault conditionThe feature is enabled when all poles have been dead for a specified time.If busbar VTs are used, breaker open input condition should be energizedMemory feature (synchronous polarization)This can only be done with a dynamic type of test equipment. The memory is mainly to dealwith three phase close up faults but is made to run out when any voltage level detector resets orwhen any comparator operates. There is nominally 16 cycles of memory polarizing which isnormally derived from phase volts. We thus have to satisfy the above condition and make therelay behave as though it is seeing a three phase close up fault.
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Signalling channel checkThis test should be applied to any scheme using a signaling channel when the channel inservice is available and in service. An engineer will be required at each end of the protectedline and some form verbal communication is necessary.
During checking up of transfer top scheme, the distance relay test kit should be connected tothe relays at both ends and the communication channel connected to the relay. At one end thezone I reach should be set to the kit and at the other and the zone 2 measurement / starter reachshould be set in the kit. On verbal communication both end testing kits should be instituted andthe relay tripping should be watched simultaneously. The relay at both ends should indicate thetrip signal immediately on initial on of the test kit. The test should be repeated for setting theother end on 2001 and 2042 at receiving end.
Live system checkTrip testTrip isolation should be obtained if breaker operation is not wantedAuto reclose should be blockedFinal setting checkThe checklist should now be referred to, and used in conjunction with that of the setting list. Ifthe VTS is to block tripping check this is set.On load checksWith the line energized check the voltage input to the relay across each pair of phases andbetween each phase and neutral. Check for correct phase rotation with a phase rotation meter.CT/VT phasing check (for numerical relay)To ensure that the corresponding voltage and current go to a given relay element it is necessaryto check the phase angle between them agrees with the known load power factor. If theinformation is available is in terms of import /export MW and MVAR.Directional checkThe test must be carried out with the relay energized from the voltage transformer and currenttransformer with the load current above the minimum sensitivity of the low-set current leveldetectors (20% of In) and preferably lagging power factor in the tripping direction.The relay should be selected for low set current level for its most sensitive settings, the angle tothe minimum value and zone-1 to a straight-line directional characteristic. All contacts will bedisabled and the relay inoperative alarm will close.A check must be performed with the fault in the opposite direction, which is achieved byreversing the current input to the relay, and the relay should give appropriate message.
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COMMISSIONINGCOMMISSIONINGCOMMISSIONINGCOMMISSIONING TESTTESTTESTTEST RESULTRESULTRESULTRESULT SHEETSSHEETSSHEETSSHEETSDISTANCE RELAY TYPE:SERIAL NUMBER:STATION DATECIRCUITSCHEME TYPE
TEST RESULTS
1. PRILIMINARY CHECKS
a) Rating detailsb) CT shorting contactsc) DC supplyd) Power upe) Wiringf) Relay inoperative alarm contact
2. VOLTAGE LEVEL DETECTORS
Level
P
3 PHASE CURRENT LEVEL DETECTORS (LOW SET)
Level
P
HIGH SET
LevelDetectors
Relay TerminalInjected Pick up Volts Drop off Volts
Drop off %Pick up
Phase A
Phase B
Phase C
LevelDetectors
Relay Terminal Pickup currentInjected
Drop offCurrent
Drop off %Pick up
Phase A
Phase B
Phase C
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CHAPTER-IXHIGH SET
Level
P
BIASED LOW SET
Level
P
BIASED HIGH SET
evel
LevelDetectors
Relay TerminalInjected Pick up Current
Drop offCurrent
Drop off %Pick up
Phase A
Phase B
Phase C
LevelDetectors
Relay TerminalInjected Pick up Current
Drop offCurrent
Drop off %Pick up
Phase A
Phase B
Phase C
LevelDetectors
Relay TerminalInjected Pick up Current
Drop offcurrent
Drop off %Pick up
Phase A
Phase B
Phase C
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ZONEZONEZONEZONE REACHREACHREACHREACH MEASUREMENTSMEASUREMENTSMEASUREMENTSMEASUREMENTS (PHASE(PHASE(PHASE(PHASE FAULTS)FAULTS)FAULTS)FAULTS)
FAULT REQUIRED NOMINAL RELAY RELAY EQUIV. % OFTYPE REACH LOOP VOLTS AMPS Z OHMS Error
IMPEDANCEREQUIRED
A-B ZONE 1
B-C
C-A
A-B ZONE 2
B-C
C-A
A-B ZONE 3
B-C
C-A
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ZONEZONEZONEZONE REACHREACHREACHREACH MEASUREMENTSMEASUREMENTSMEASUREMENTSMEASUREMENTS (GROUND(GROUND(GROUND(GROUND FAULTS)FAULTS)FAULTS)FAULTS)
FAULT REQUIRED NOMINAL RELAY RELAY EQUIV. % OFTYPE REACH LOOP VOLTS AMPS Z OHMS Error
IMPEDANCEREQUIRED
A-N ZONE 1
B-N
C-N
A-N ZONE 2
B-N
C-N
A-N ZONE 3
B-N
C-N
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IF θΡΗ and θΝ differ by 5° the vector sum of phase fault and ground fault impedance should befound out to give θ and the basic ground fault loop impedanceFAULT LOCATION (IF FITTED)
Z1 = ------------------------- ZF = ----------------------------LINE LENGTH = -----------------
MUTUAL COMPENSATION ENABLED/DISABLED
Phase Location given for Zone-1 reach Location given for Zone-1 reach% or Km or Miles( No mutual) % or Km or Miles(With mutual)
Expected Actual
A-G
B-G
C-GA-B
B-C
C-A
OPERATION TIME
Zone-4 (RR) Starter ReachPhase Zone-1 (ms) Zone-2 (sec) Zone-3 (sec) Seconds Seconds
A-B
B-C
C-A
A-G
B-G
C-GNote: for switched relay for one measuring court can be taken for time measurement.
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CHAPTER-IXPOWER SWING
Zone Boundary
Required forward loop impedance :
Measured forward loop impedance :
Required Reverse loop impedance :
Measured Reverse loop impedance :
Measured Time :
Simulated Power swing
Blocking and contact check
Zone-1 block
Zone-2 block
Zone-3 block
All zone block
PSB alarm
VOLTAGE SUPERVISION
Operation on zero sequence volts --------------- V
Operation time ---------------- sec
Indication
Instantaneous Operation
IndicationSelf-resetting Enabled/ Disabled
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CHAPTER-IXOperation checkedSWITCH ON TO FAULT
SOTF indication
Trip time
MEMORY FEATURE (SYNCHRONOUS POLARISING)
Zone-1 trip alarm contact dwell time ------------------- ms
PERMISSIVE TRIP
Aided trip check
Signal sends check
TDW timer (if applicable)
Three pole trip
ON LOAD CHECK
CT Burden check
Voltage correctness check
Phase rotation check
CT/VT phasing correct check
Forward directional check
Reverse directional check
NEGATIVE - SEQUENCE DIRECTIONALELEMENT TEST USING SINGLE PHASEVOLTAGE AND CURRENT : (If the relay is with Negative-sequence directionalcharacteristics)
Select output contacts for indicating the operation of Forward unbalanced fault and Reverseunbalanced fault elements.
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The relay-unbalanced element operates based upon the magnitude and angle of negativesequence voltages and currents. The magnitude and angle of negative sequence voltage (V2)and negative sequence current (I2) have to be calculated using the equation below
V2 = 1/3 (VA + a².V B + a. VC )
I2 = 1/3 ( IA + a².IB +Alice )
Using single phase signals simplifies the V2 and I2 calculations.
V B = V C = 0 voltsIB = IC = 0 amps
V 2 = 1/3 . (VA)I2 = 1/3 .( IA )
Assume that you are applying a test voltage VA =18∠180° Volts secondary. The test angle ofA- phase current should be taken from the relay setting angle. The negative sequenceimpedance will be positive when I2 lags V2 by the angle of line impedance and negative if I2
leads V2.Turn on the voltage sourceApply , say., VA =15V∠180° , IA = 0.0∠96°
Slowly increase the magnitude of IA with out varying the phase angle The magnitude of thecurrent is determined by calculating the negative sequence impedance. The negative sequenceimpedance for a forward single line ground fault will result in a negative value of negativesequence impedance and for a reverse fault it will be positive. If the value of the forwardthreshold value of negative sequence impedance is less the fault is in the forward direction andthe relay set to forward unbalanced fault condition.
The relay multiplies the measured +ve sequence current magnitude by a setting, then comparesthe result to the measured magnitude of the –ve sequence current. The magnitude of –vesequence current must be greater than the magnitude of the +ve sequence current multiplied bya setting for the directional element to operate.
When increasing the current at a particular limit the reverse unbalanced fault element willasserts , indicates that the –ve sequence impedance is greater than the reverse thresholdimpedance of the system. If the current is increased beyond that limit the forward unbalancedelement asserts, indicating that the negative seq. Impedance is less than the forward thresholdvalue.
Verify the performance described above by calculating negative sequence impedance with theabove tested quantities.
When performing the test other protection elements may assert , causing the relay to close otheroutput contacts and assert relay targets. This is normal and is not a cause for concern.
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CASECASECASECASE STUDIESSTUDIESSTUDIESSTUDIES
CASE:1CASE:1CASE:1CASE:1
Analysis of the tripping at Sriprumbudur - Koyambedu feeder on10th Feb. 2000.
Koratoor 230 kvs/s
230kv NCTPS fdr.
230kvETPS fdr.Sriperumbudur400 kv s/s Koyambedu230kvs/s
Relay indications.Koyambedu feeder.
Main 1. RAZFETN
Main2. SIEMENS 7SA511BN Z1
Observations at Sriperumbudur
Heavy flash over seen on Koyambedu feeder with jumper cut at line switch. The breaker ofKoyambedu feeder trippedAT Koratoor s/s the NCTPS fdr. And the ETPS feeders are not in service. There was a fault atKTR-SPR feeder A conductor snapped , but the line was not tripped for the fault. The KOYfeeder at SPR was tripped with heavy flash over and with a jumper cut at the SPR end. Therewas no tripping at KOY ,the Koyambedu operator has noticed a supply failure both fromKorattoor and SPR. The known fault at KTR-SPR feeder was not cleared but causes over flowof current in one single path causes the heavy flash over and the operator at SPR has opened theLV breakers of the Auto transformers.The KTR-SPR and SPR-KOY feeders are running parallel up to some point , and the mutualcompensation effect might have caused the over reaching of the setting. So, the tripping ofKTR-SPR feeder might have been delayed and causing the KOY feeder jumper cut . Therelays at KTR and SPR in the feeder of KTR-SPR was verified and the compensation factorwas reduced to 0.7 to have the sufficient reach.
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CHAPTER-IX
CASE:2CASE:2CASE:2CASE:2
Deails of trippings atKortoor, NCTPS ,Sriperumbudur… on 30th Jan 2000SPK
KLPMKDP To TVLM GDDI
MOSR TVLM
TRNI KOYArni KTR ETS MYL NCTPS
SPR TPT
Under line clear
On 30th Jan 2000 the units at NCTPS, ETPS and GMR were tripped resulting in a blackout inChennai area. The ETS-KTR and NCTPS- KTR feeders were on line clear.
There was a line fault in NCTPS-SPR feeder 2 and tripped at both ends on BE Z1 andsubsequently the feeder 1 was also tripped on same indication. At the time tripping the NCTPSunits are generating 630 MW and the following feeders are in service. The NCTPS- MOSUR,NCTPS-GDDI and the NCTPS –TPT feeders. The Mylapore feeder is in radial fromTondiarpetS/S.The GMR Vasavi generating machines and the TCPL unit in parallel with the110 kV bus of Gummidipoondi were tripped.
NCTPS units trippings are
Unit1 on Over voltage
Unit 2 on house load and subsequently on condensor pressure high
Unit 3 on house load and subsequently on Drum level low
ETPS units tripped on
Unit 2 Boiler protection
Unit 1 Under Voltage
Unit 5 RH system protection
GMR Vasavi units were tripped on Under speed.
The TCPL unit tripped on ID fan tripping
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CHAPTER-IX
ANALYSIS:ANALYSIS:ANALYSIS:ANALYSIS:
The tripping of generating units are unwanted for the feeder trippings which is normal. TheNCTPS after tripping of SPR feeders feeding the loads in TPT feeder , MOSUR feeder and theradial load of Gummidipoondi.
The units are to be stable after the actuation of house load condition with the load ofabout300MW in TPT S/S.GDDIS/S and the local loads. On detailed analysis the house leadturning up for the units at NCTPS was checked and found that the valves are not func;tioningproperly. After the studies conducted at Neyveli, the improvement in the terminal units areunder progress. System, which is unwarranted. The feeding arrangements and the loaddistributions are to be studied. There are generating stations on 110kV bus system inter linkingthe 230 kV system, the operation of the system is in low frequency condition of about 48Hz.Due to the operation of the system under low frequency conditions the machines are facingelectromechanical thrust to move the machine to the oscillating condition and causing thetripping. The tripping are unwarranted and are to be avoided. The system has to be studied forits stability.
CASE.3CASE.3CASE.3CASE.3GMR SBM KTR
VYD
CNPT BBGTPS
The 110 kV system links GMR private power project tripping frequently for external feederfaults. The feeders were provided with numerical distance relays of AEG make PD521. Thecause for tripping of the machines on over current was found to be that they have adopted thehigh set value as 2.5 times with instantaneous setting and the same was corrected. For externalfault conditions the feeder were tripping on over current indication. On examination of thedistance relay if the measurement is not done by the relay the relay will actuate through overcurrent if the current exceeds the setting value. The non-measurement of the distance relay waschecked and found to be there is a programming error. During commissioning of the feeders itwas noticed that the polarity of the CTs was wrongly selected, the relay was selected throughprogramming for reversal of polarity. The relay is having a programming for the selection ofphase rotation; it was selected for positive sequence phase rotation, which is anti clockwise.Due to selection of polarity reversal and phase rotation the current was shifted to 180 degreecausing the measurement.
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CHAPTER-IX
CASE.4CASE.4CASE.4CASE.4TTPS PSQ
CKNI MYD TDLRKundah
KYR PGLR
Whenever the under frequency islanding takes place for two blocks seperation of the wholeblock of the system, the feeders at Chekanoorni towards Meyvadi , Pugaloor feeder andthudialoor were tripping with three phase indication. The feeders are protected withTHR3PE18 relays which is having the power swing blocking removal on completion of 3rd
Zone time. The power system on two block will be seperated with TTPS-KUNDAH as oneblock and rest of the system as one block. The TTPS-Kundah block generators are swingingand the swing settles after about 1.7 sec and so the 3rd Zone time was set at 1.7 sec . After thatthe tripping was not there and M/S Easun Reyrole was requested to provide a deblockingfacility for 2 sec. The provision was made in Chekanoorni S/S only. The relay of MM3T alsohaving the same problem but with de blocking time of 1 sec and the relay also requires change.Due to the islanding conditions the electrical center of the system shifted due to outages. TheABB make relays are provided with 2 sec. Deblocking, the system with that relays are holdingthe condition.
156
CHAPTER-XCHAPTER-XCHAPTER-XCHAPTER-X
POWERPOWERPOWERPOWER TRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMERTESTINGTESTINGTESTINGTESTINGANDANDANDAND PROTECTIONPROTECTIONPROTECTIONPROTECTION
Er. M. VaradarajanEE / O&M
CLASSIFICATION:CLASSIFICATION:CLASSIFICATION:CLASSIFICATION:
Transformers in use in T.N.E.B. may be classified into four major groups.
1. Transformers in Radial stations for distribution of power at high tension.:a) 110/33 KV, 110/22 KV and 110/11 KV power transformers,b) 110/66 KV auto transformers, 66/33 KV, 66/22 KV and 66/11 KV power
transformers andc) 33/11 KV power transformers
are in this category.
110 KV power transformers are usually ordered for multi-ratios like 110/33/22 KV,110/22-11 KV and 110/33-11 KV with a minimum rating of 10 MVA. The standard capacitiesare 10, 16 and 25 MVA.
At 33/11 KV line tap substations, transformers of capacity 1, 1.5 and 2 MVA may beavailable. The T.N.E.B. has decided not to have any more new line tap sub-stations in future.
At 33/11 KV substations, transformers of capacity 3, 3.15, 5 and 8 MVA may beavalable. The board is now procuring 8 MVA transformers only in this voltage ratio and thelower capacity transormers will be phased out.
The above step-down transformer except 110/66 KV auto transformers belong to thevector group “Dy11” with secondary neutral solidly earthed.
2. 230/110 KV Auto Transformers in grid stations. Transformers with a rating of50, 75, 80 and 100 MVA may be available. The Board is procuring 100 MVA units only underthis category now.
These auto transformers have their main winding star connected with the neutral solidlyearthed. They also have a 11 KV delta connected tertiary winding with some specific MVArating to connect phase compensating devices like shunt capacitors, static var compensators etc.When not needed, the tertiery is kept idle. However the closed delta connected winding helpssuppression of third harmonic voltages and aids flow of sufficient current for a line to earthfault for the protective device to operate.
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400 KV Stations are under the control of the Power Grid Corporation. AtSriperumbudur and Salem, the 400/230 KV auto trans formers and 400/110 KV Transformerare under T.N.E.B. control. In the other 400 KV stations in Tamil nadu the transformers areunde r power grid control.
3. Step-up Transformers in generating stations.
The generation is generally at 11 KV, phase to phase and is stepped up to 110 KV or 230KV. Here the primary winding (11 KV) is delta connected and the secondary EHV winding,star connected with the neutral, solidly earthed. Where the power rating of the unit is large,3 single-phase units maybe provided and connected externally to form a three-phasetransformer. The transformer MVA rating matches the generator rating.
4. Distribution transformers to feed L.T. distributions with primary rating at 11 KV or 22 KV.These transformers belong to the vector group “ Dy11” with secondary neutral solidly earthed.
I.I.I.I. TESTINGTESTINGTESTINGTESTING
The following Tests are specified in IS:2026 (Part I), specification for powertransformers, Part-I, General:
TYPETYPETYPETYPE TESTS:TESTS:TESTS:TESTS:
(a) Measurement of winding resistance.(b) Measurement of Voltage ratio and check of Voltage Vector relationship.(c) Measurement of impedance voltage/short circuit impedance (principal tapping) and load
loss.(d) Measurement of no load loss and current.(e) Measurement of insulation resistance.(f) Dielectric tests(g) Temperature rise test(h) Tests on ON-LOAD tap-changers, where appropriate
ROUTINEROUTINEROUTINEROUTINE TESTSTESTSTESTSTESTS
(a) Measurement of Winding resistance.(b) Measurement of Voltage ratio and check of voltage vector relationship.(c) Measurement of impedance voltage/short circuit impedance (Principal tapping and load loss)(d) Measurement of no-load loss and current.(e) Measurement of insulation resistance.(f) Dielectric tests(g) Tests on ON-LOAD tap-changers, where appropriate.
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CHAPTER-X
SPECIALSPECIALSPECIALSPECIAL TESTS:TESTS:TESTS:TESTS:
(a) Dielectric tests(b) Measurement of Zero-sequence impedance of three phase transformers.(c) Short circuit test.(d) Measurement of acoustic noise level.(e) Measurement of harmonics of the no-load current.(f) Measurement of the power taken by the fans and oil pumps.
TOLERANCES:TOLERANCES:TOLERANCES:TOLERANCES:
(i) a) Total losses : +10% of the total losses.b) Component losses : +15% of each component loss, provided that the
tolerance for total losses is not exceeded.
(ii) Voltage ratio at : The lower of the following values:no-load on the (a) 0.5% of the declared ratio.Principal tapping (b) A percentage of the declared ratio equal to(rated voltage ratio) 1/10 of the actual percentage impedance
voltage at rated current. (This does notapply to auto ransformer)
(Tolerances at othertappings shall besubject to agreementbetween the manufact-urer and the purchaser)
(iii) Impedance voltage atrated current (Principal tap) :
a) If the principaltapping correspondswith the mean tappingposition or with oneof the two middletapping positions:
1) Two winding : + 10% of the declared impedance voltage for thattransformers tapping.
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CHAPTER-X
2) Multi-winding : + 10% of the declared impedance voltagetransformers for one specified pair of windings.
+ 15% of the declared impedance for a second certifiedpair of windings.
Tolerance to be agreed and stated for Further pairs ofwindings.
b) For tappings other : If necessary, the short-circuit impedances on other taps maythan the principal be specified. If this is done the extremetapping. tapping impedances shall be included. The
tolerances then applicable shall be as follows:
If the principal tapping corresponds with the mean tappingposition or with one of the two middle tapping positions, thetolerances applicable on this principal tapping shall be thosestated above and on other than principal tapping, shall beincreased by a percentage equal to half the difference intapping factor (percentage) between the principal tapping andthe actual tapping.
iv) Short circuit : Note less than as indicated in (iii) aimpedance for any In the other cases the tapping range shalltapping be considered as balanced about the mid-
tapping position and the tolerances shallbe calculated as before but assumingtolerances as above applying to the midtapping position in excess of that above.For a specified tapping range, thesimplest method is to fix according to theabove calculation only the minimum andmaximum values of impedance including the tolerances.
For tapping ranges in excess of an overall 25% of where thetolerances derived may result in unacceptable levels ofimpedance, tolerances shall be subject to agreement betweenthe manufacturer and the purchaser.
v) No-load current : + 30% of the declared no load current.
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CHAPTER-XTESTSTESTSTESTSTESTS ATATATAT THETHETHETHE FACTORY:FACTORY:FACTORY:FACTORY:
Type/Routine/Special tests if any as specified by the TNEB in the P.O. specificationwill be done at the factory by the transformer manufacturer in the presence of the nominatedEngineer of the TNEB. The test results will be authenticated by the Manufacturer’s Engineerand the TNEB Engineer who witnessed the test and sent to the TNEB for acceptance.
Besides the above, Manufacturer’s test certificates in respect of the followingaccessories are also to be furnished to the Board for acceptance.
(a) OLTC(b) Bushings(c) Buchholz relay and surge relay(d) Magnetic Oil level gauge(e) Winding temperature controllers.(f) Oil temperature controllers(g) Radiators(h) Cooling fans (if provided)(i) Pumps (if provided)(j) Transformer oil(k) Pressure relief valve.
TESTSTESTSTESTSTESTS ATATATAT SITE:SITE:SITE:SITE:
A transformer may be tested at site under the following circumstances.
(a) A new or second hand transformer to be commissioned:- Pre-commissioning tests to bedone.
(b) Tests to be conducted to determine the healthiness or other-wise of the transformer thathas been taken out of service on the actuation of Buchholz/Differential relay or on observingsome abnormal occurrence that has placed a question on the healthiness of the transformer.
The following constitutes pre-commissioning tests at site.
(a) Insulation resistance test(b) Ratio test on all taps.(c) Dielectric test and dissolved gas analysis (DGA) on oil which will be the basis for future
DGA.(d) Open circuit test for measurement of magnetizing current.(e) Short circuit test.(f) Operation test on OLTC if provided.(g) Operation test of protection devices and interlocks.(h) Measurement of winding resistance of all windings, at all taps in winding having taps.(i) Determination of Vector group and polarity test.(j) Measurement of capacitance and tan delta of transformer bushings of EHT voltage rating.(k) Core balance test.(l) Tests on bushing CTs if provided.
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CHAPTER-X
To determine the healthiness or otherwise of the transformer that has been in service,the following tests may be done at the service tap without disturbing it.
(a) Insulation resistance test(b) Ratio test(c) Dielectric test on oil(d) Measurement of magnetizing current(e) Short circuit test(f) Measurement of winding resistance.(g) Gas analysis test on gas if any collected in Buchholz chamber in case of Buchholz
relay / differential relay operation.
IMPORTANT:IMPORTANT:IMPORTANT:IMPORTANT:
(1) Ensure that the service tap is not disturbed and conduct tests first at the service tap.
(2) See that gas if any in the Buchholz Chamber is not allowed to escape. Whatevergas is accumulated, must be preserved till the special maintenance wing gets ready for gasanalysis.
(3) The MRT and Special Maintenance Wings must have proper coordination betweenthemselves as not only that the cause that has brought about the outage on the transformer isidentified but also that it is done fast.
If necessary, the tests may then be done at all taps.
GENERALGENERALGENERALGENERAL PRECAUTIONSPRECAUTIONSPRECAUTIONSPRECAUTIONS TOTOTOTO BEBEBEBETAKENTAKENTAKENTAKEN ININININ CONDUCTINGCONDUCTINGCONDUCTINGCONDUCTING TESTS:TESTS:TESTS:TESTS:
For pre-commissioning tests on a transformer, line clear will not be available. Variousagencies like transformer erection, substation erection, special maintenance etc., may be atwork on the transformer or around it. The testing branch shall first of all intimate all the otheragencies at work (Engineer/Foreman incharge of works) that precommissioning tests on thetransformer is going to be conducted that power supply will be available on transformer top aswell as at the testing kit, Power Supply Board etc. on the ground beside the transformer, thateverybody will steer clear of the transformer under test and that after tests the transformer canbe approached only after getting clearance from the Engineer incharge of testing at site.
The transformer and the area beside it needed for conducting the tests shall bebarricaded with rope all round.
Danger boards shall be provided at prominent positions at Test site making clear the testzone to every one around including those who may otherwise happen to trespass the testingareas.
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CHAPTER-X
In addition to taking the above precaution, the MRT Engineer supervising the testingwork should keep an eye on the activities around so that anything that has the potential for anaccident can be spotted and preventive action taken. The Engineer should keep in mind that heis not only to ensure correct testing procedure and high testing standard but also is to see thathis men and instruments are safe guarded. To achieve these, the Engineer should be availableat test site for the entire duration of tests and be vigilant.
In case of existing transformer, the testing Engineer shall avail of line clear from thesub-station operator and see that the transformer is properly isolated on either side and that it isproperly discharged and earthed. After connecting the testing leads to the transformer bushingconnectors and before commencing the tests the earths provided shall all be removed takingcare not to tilt the earth rods being removed towards live parts of adjacent equipment, switches,busbars etc. Test supply is to be switched on after being doubly sure that all the earths havebeen removed and that there is no person on the transformer and after loud cautioning to allaround that supply is being switched on.
The test supply shall be through a robust triple pole switch with proper fuses determinedby the maximum test current that will be drawn. The supply cable from the supply mains to thetriple pole switch board (supply board) shall be physically secured at suitable locations enrouteso that the cable will not get disturbed. After checking the availability of correct supply at theincoming terminals of the supply board, the tests will be started, switching on the supply.
The test will be conducted in fair weather conditions. If there is any symptom ofimminent rain or even a light drizzle, the tests shall be stopped, the test supply, switched off,the supply cable disconnected at the mains and all the testing instruments and kits moved fromthe testing site to shelter. On no account shall any of the instruments/kit be allowed to get wet.As and when conditions permit restarting of the tests it shall be again checked and ensured thatnone of the testing kit/instruments is wet.
The required tests will be conducted one by one, taking the required precautions if anyspecific to the particular test. The procedure for various tests are elaborated below.1) RATIORATIORATIORATIO TEST:TEST:TEST:TEST:
In order to obtain the required accuracy a ratio meter may be used to determine thevoltage ratio of the transformer. The ratio is to be determined at all taps.
The ratio meter is used in a bridge circuit where the voltage of the windings of the transformerunder test are balanced against the voltages developed across the fixed and variable resistors ofthe ratio meter. Adjustment of the variable resistor for zer o deflection is obtained on thegalvanometer then gives the ratio to unity of the transformer windings from the ratio of theresistors. The modern ratio meters incorporate the inductive voltage divider and solid statephase sensitive null detector and ensures high measurement accuracy and operational reliability.In addition to determining the voltage transformation ratio which is the primary objective ofthis test, the polarity between the windings and phase relationship between phases can also beeasily established by the ratio meter in a single operation. Before using the ratio meter, theinstruction manual for operating the ratio meter must be carefully studied and all precautionsnoted therein must be followed. Ratio test through the ratio meter should be attempted onlyafter getting familiarised with the instrument.
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When a ratio meter is not available, the ratio may be determined by energizing the HVwinding of the transformer with 3-Phase LT supply from the mains and measuring the voltageapplied to the H.V. side and the voltage induced in the LV Windings by taking measurement atthe LV terminals, keeping the LV terminals open circuited. This is not an accurate method, asthe instruments used to measure the voltage may not have the required accuracy. The ratio is tobe determined at all the taps. If OLTC is available, the test can be started from one extreme tapand measurement taken for each tap up to the other extreme by operating the OLTC withoutswitching off supply voltage while operating the OLTC. For transformers not provided withOLTC, the supply is to be switched off while operating the OFF LOAD tap switch. Theincrease or decrease in the LV side voltage for each tap should more or less correspond to thepercentage mentioned for that tap in the name-plate. See table (1)
TABLETABLETABLETABLE ---- 1111
110/33-11 KV TIRUCHY S.S.
TEST CONDUCTED ON POWER TRANSFORMER NO. 3, 110/11KV, 16KVA.
RATIO TEST (DATE OF TEST: 20.11.1987)
TAPNO.
PRIMARYVOLTS APPLIED SECONDARY VOLTS OBTAINED
RY YB BR ry yb br rn yn bn1 420 420 416 41.5 41.2 41.4 24.0 23.8 24.02 420 420 416 42.0 41.8 41.8 24.3 24.2 24.23 420 420 418 42.5 42.1 42.5 24.5 24.5 24.64 420 423 419 43.0 42.8 43.0 25.0 24.9 24.95 420 424 424 43.5 43.2 43.4 25.3 25.2 25.26 419 424 424 44.1 43.7 44.0 25.6 25.4 25.47 420 424 424 44.6 44.2 44.5 26.0 25.8 25.88 420 424 424 45.2 44.9 45.2 26.2 26.0 26.09 420 424 424 45.8 45.3 45.6 26.4 26.2 26.310 424 420 416 46.3 45.9 46.0 26.9 26.6 26.611 424 420 416 46.7 46.4 46.8 27.2 27.0 26.912 424 420 416 47.5 47.0 47.4 27.5 27.4 27.313 424 420 416 48.3 47.9 48.2 27.9 27.6 27.714 424 420 416 49.0 48.5 48.9 28.3 28.0 28.015 424 424 420 49.6 49.2 49.5 28.8 28.3 28.316 424 424 420 50.2 49.8 50.2 29.2 28.9 28.917 424 424 420 50.9 50.5 50.8 29.6 29.3 29.3
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PRECAUTIONSPRECAUTIONSPRECAUTIONSPRECAUTIONS
In doing this test, voltage injection should be only on the High voltage side so as tolimit the voltage on the other side (LV side) to a safe, directly readable level. The neutral in thestar side may be kept isolated from ground. Test leads selected should be strong with goodinsulation and the soundness of the leads should be checked before connecting them. colourcodes may be used for the three phases and neutral. The leads used for the HV side and LV sideshould be distinctly identifiable. The leads should be connected solidly to the transformerbushings and firmness of the connections should be checked. The free ends of the leads fromthe HV and LV sides should be brought down separately in two bunches and connected to theappropriate terminals of the testing kit. Free ends of the leads from the LV side should besecurely connected to dummy terminals in a wooden/Hylum Board (Transformer Board) fortaking voltage readings if ratio meter is not used.
Preferably a 3 phase 4 wire board with a sturdy 3 pole iron clad switch may be used(fig-1). By keeping the switch off in the transformer board, the voltage readings can be taken.PVC insulated, 7/16 leads may be used for testing.
For auto-transformers, the ratio between HV and IV (Intermediate voltage) and HVand LV should be noted separately.
In the star side, the phase to neutral reading shall be taken. Phase to phase voltagereadings may also be taken.
The readings should be recorded in the site register along with the date and time of test,mentioning also the instruments used and the range selected in the instrument for reading thevoltages.
SHORTSHORTSHORTSHORTCIRCUITCIRCUITCIRCUITCIRCUIT TESTTESTTESTTEST
Before commencing the test, the short circuit current is to be calculated for theavailable mains voltage from the percentage impedance of the transformer.e.g.: (1) Power transformer, 33/11KV, 5MVA, 87. 5A/262.5A
Z = 6.81% at principal tap, mains voltage : 372V6.81% of 33KV = (33000 x 6.81/100) = 2247.3V2247.3V will deliver rated current of 87.5A on short circuit.372V will deliver a short circuit current of (372 x 87.5 / 2247.3) = 14.48AAt principal tap, short circuit current on HV side = 14.48A.Short circuit current on LV side = (14.48 x 33/11) = 43.45Ae.g. (2): Power transformer: 110/11KV, 10 MVA, 52.5A/525Az = 8.93% at principal tap, Mains voltage = 400V8.93% of 110KV = (11000 x 8.93/100) = 9823 V9823V will deliver 52.5A in short circuit.400V will deliver: (400 x 52.5/9823) = 2.14 AHV Short circuit current at principal tap = 2.14A.LV short-circuit current = 2.14 x 110/11 = 21.4A
165
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166
CHAPTER-X
Based on the calculated short circuit currents for the available mains voltage, the instruments toread the HV and LV currents and the range to be selected can be decided for the short circuittest.
The transformer Board used in the voltage ratio test can be used for the short circuittest by keeping the switch ‘ON’ which short circuits the LV windings and the neutral.
The test can be commenced by keeping the transformer tap at one extreme position. Allprecautions mentioned for the ratio test apply to this test as well. Usually, the HV short circuitcurrent can be read directly through Ammeter/multimeter if the short circuit current atmaximum tap will be less than 10A. Else, a precision CT and Ammeter or a low range fairlyaccurate tong tester may be employed to read the HV short circuit current.
The LV short circuit current is usually read with a Tong tester. This instrument doesnot give accurate readings but a good quality tong tester with the right range will be goodenough for the short circuit test. If, however accurate readings are needed, a precision CT withan accurate Ammeter/multimeter must be used to read the secondary short circuit current.
The spill to the neutral should also be read. To select the instrument for the purpose, theneutral current may be checked with a low range tong tester first. If the spill current is lowerthan 1A which will be the case in almost all the healthy new transformers, when balanced3-phase voltage is available at the mains a 1A Ammeter may be used initially. If the neutralCurrent is found to be below 0.1A, a milli-ammeter/Multimeter in milli-amp range may be usedto read the spill current to the neutral.
For each tap, the applied voltage, H.V. and L.V. short circuit currents and the LV spillcurrent should be noted and recorded. If OLTC is available, the test can be continued withoutswitching off Mains supply and by moving to the next tap by operating the OLTC. Thereadings will be taken for all the taps.
As per the present TNEB specification, the spill current is not to exceed 2% of the shortcircuit current on LV side for step down transformers. If the spill is more than 2% when readwith accurate instruments in testing a new unit, the matter may be referred to the Manufacturer.However this limit cannot of applied to a second hand unit for commissioning.
Results of short circuit test conducted on a Power Transformer are in table – 2 (a) & (b).
167
CHAPTER-XTABLETABLETABLETABLE –––– 2222 (a)(a)(a)(a)
TIRUCHY 110 KV S.S. (110/11 KV. 16MVA)
SHORT CIRCUIT TEST: (DATE OF TEST: 20.11.87). LV WINDINGS AND LVNEUTRAL SHORTED AND VOLTAGE APPLIED TO HV WINDINGS (3 ph. 432 V)
VECTOR GROUP TEST: - (Date of test: 20.11.87)
3 phase, 430v applied to HV windings and one phase voltage to HV windings cut off in turnand secondary voltages measured.Tap at No.1 (-5%)
The Vector group of DY11 is thus established.
TapPrimary current in AmpsIR IY IB
Secondary Currents.======================
Ir Iy Ib
NeutralCurrentIn AMPs
IN
1 2.70 2.70 2.68 28.5 28.0 28.0 0.502 2.80 2.80 2.75 28.7 28.0 28.2 0.523 2.80 2.80 2.75 28.5 28.0 28.2 0.504 2.85 2.85 2.83 28.5 28.0 28.5 0.535 2.90 2.85 2.85 29.0 28.0 28.0 0.506 2.95 2.95 2.90 29.0 29.0 28.5 0.507 3.00 3.00 2.95 29.0 28.0 28.5 0.508 3.05 3.03 3.00 29.0 28.5 28.5 0.539(b) 3.05 3.05 3.05 29.0 28.0 28.5 0.5010 3.10 3.10 3.10 29.0 28.0 28.5 0.5311 3.13 3.13 3.10 28.8 28.0 28.5 0.5012 3.18 3.18 3.20 28.5 28.0 28.5 0.5313 3.22 3.20 3.20 28.5 28.0 28.5 0.4914 3.25 3.25 3.22 28.5 27.5 28.0 0.5215 3.30 3.25 3.25 28.5 27.5 28.0 0.4716 3.30 3.30 3.30 28.0 27.5 28.0 0.5217 3.40 3.40 3.40 28.0 27.5 28.0 0.47
Primaryphasevoltageout in
Secondary Volts measured.
rn yn bn ry yb br
R - ph (V-YB=430) 13 22 7 38 30 6Y - ph (V-BR=430) 4 18 23 16 43 25B - ph (V-RY=430) 23 20 4 43 18 24
168
CHAPTER-X
TABLE – 2 (b)
SHORT CIRCUIT TEST
110 KV MANAPPARAI S.S. (PR.TR.:110/33 KV. 16 MVA)
THEORITICAL SHORT CIRCUIT CURRENT CALCULATION
110 KV MANAPPARAI SS, 110/33 KV. 16 MVA, HHE, 9.93%, 84/280 A.For (110000 x 9.93/100) volts, the s.c. current in Primary will be 84 A at normal Tap.
For 385 V. primary S.C current = (385x100x84)/110000x9.93) = 2.96 AS.C. current in secondary = (2.96 x 100/33) = 9.85 A
The secondary terminals including neutral were short circuited and 3 phase voltagewas supplied to primary terminals.
Instruments used:Primary volts by A.C voltmeter, 0-600 V rangePrimary current by A.C Ammeter, 0-5 ASecondary current by Tong tester, 0-25 A rangeNeutral current by Motwane MultimeterAll currents are in Amps.
TAPNo.
Primary VoltsApplied
VRY VYB VBR
Primary current
IR IY IB
secondary currents
Ir Iy Ib In1 385 385 385 2.59 2.58 2.62 9.0 8.7 9.0 0.062 2.65 2.64 2.68 9.4 9.1 9.2 0.063 2.75 2.70 2.76 9.5 9.4 9.4 0.064 2.83 2.79 2.85 9.7 9.3 9.4 0.065 2.88 2.85 2.90 9.8 9.3 9.6 0.066 2.97 2.93 2.99 9.9 9.5 9.7 0.077 3.04 3.00 3.05 10.0 9.5 9.7 0.078 3.09 3.07 3.14 10.0 10.0 10.0 0.089 3.17 3.13 3.19 10.0 10.0 10.0 0.0810 3.29 3.26 3.30 10.50 10.0 10.20 0.09511 3.38 3.34 3.41 10.75 10.0 10.25 0.1012 3.45 3.43 3.48 11.0 10.0 10.25 0.1013 3.54 3.50 3.56 11.0 10.25 10.25 0.1114 3.62 3.57 3.64 11.0 10.25 10.50 0.1115 3.68 3.62 3.69 11.0 10.75 10.75 0.1116 3.73 3.69 3.74 11.0 10.75 10.75 0.1117 3.78 3.74 3.79 11.0 10.75 10.75 0.105
169
CHAPTER-XTABLETABLETABLETABLE –––– 2(C)2(C)2(C)2(C)
TIRUCHY 110 KV S.S.(110/11 KV, 16 MVA POWER TRANSFORMER)
POLARITY TEST (DATE OF TEST: 23.11.87)
Primary phase – R and secondary phase – b were shorted and 3 phase LT Voltage wasapplied to primary.
The following voltages were measured and compared with the expected values.
Voltage across primary phases = 445 V (applied)Voltage across Secondary phases = 51 V (induced)(Transformer at maximum tap, i.e., + 15 %)
==================================================================Voltage Voltage expected Voltageacross measured
==================================================================V (Y- y) 445 + j 51 = 448 V 450 V
V (B-y) 445 + 51 COS 30 = 489 V 490 VV (B-r) 445 + 51 COS 30 = 489 V 490 V
==================================================================
It is therefore established that the polarities and vector group-Dy11 are correct.
WINDINGWINDINGWINDINGWINDING RESISTANCE:RESISTANCE:RESISTANCE:RESISTANCE:
The DC resistance of HV windings on all taps and the LV windings are to be measured.In case of Auto-transformers, DC resistance of HV, IV and LV windings have to be measured.Winding resistance of all phases has to be measured.
The best instrument of measuring the DC resistance of LV windings that is in fractionof an ohm is the “Kelvins double bridge” as the measurement is not affected by lead resistance.The HV winding resistance, IV Winding resistance in case of auto-transformer and LVWinding resistance of higher value can be measured with a Kelvins bridge or a wheat stonebridge. If one is not very familiar with the instrument, the instruction manual of the instrumentmust be studied before attempting measurement.
Where suitable bridge instrument is not available for measurement, the windingresistance may be measured by connecting it to a battery and reading the voltage applied andthe current drawn and applying ohms law. An automobile battery or a set of released substationbattery cells with adequate strength may be used.
170
CHAPTER-X
For the winding with taps, the winding resistance for all taps has to be measured. ForTransformers with OLTC, the OLTC may be operated starting from one extreme tap and takingmeasurement at each tap without breaking the circuit. For transformers with off load tapchanger the DC supply is to be switched off before moving on to the next tap.
CAUTION:CAUTION:CAUTION:CAUTION:
(1) The transformer winding is highly inductive. When DC supply is switched off, a heavyback emf will be induced which can damage instruments and cause accident to personnelcoming into contact with the back emf. So, sufficient caution should be exercised whilecarrying out this test. Voltmeter/multimeter in the voltage range must be disconnected beforebreaking the circuit to prevent damage to the instrument.
(2) As the windings, particularly the 110KV and 230 KV Windings have a large timeconstant, sufficient time must be allowed for the current to stabilize to get true resistance values .This applies to measurement using bridge instruments also. If it is desired to reduce the currentstabilization time, series resistance may be introduced to reduce the time constant in which casethe voltage should be read at a point beyond the resistor so as not to include the voltage dropacross the resistor in the voltage measurement.
(3) Unless the resistance measurement is made using a Kelvins double bridge, the measuredresistance includes lead resistance also which must be subtracted from the measured value toget true resistance of the windings. Resistances of Windings of the order of Milli ohms like thatof 11KV Windings for instance will be affected by contact resistance. So due care must betaken to eliminating the contact resistance or atleast to reduce them to micro level before takingmeasurement.
The date and time of measurement, weather condition, winding/oil temperature, theinstrument used for measurement must all be recorded. Refer table – 3.
If voltage conditions warrant change of tap in a power transformer with off load tapchanger, in service the dc resistance of the winding after changing the tap must be measured. Inold transformers, long years of service may have caused coating of oil sludge in the tap switchcontact, resulting in some deviation of the d.c. resistance from the expected value. Any hastyconclusion will be ill advised. Instead, the tap switch may be operated a number of times andthen the winding resistance measured at the set tap. This should clear the contact surface givingthe true value of winding resistance. The tap switch should be locked in the new position.
171
TABLETABLETABLETABLE –––– 3333 (A)(A)(A)(A)
MEASUREMENT OF D.C. RESISTANCE: TIRUCHY 110 KV SS
H.V. WINDING: Date of Test: 20.11.1987
BY WHEATSTONE BRIDGE: (including lead resistance of 0.11 ohm) winding temperature40° C.
=====================================================================TAP NO. RY OHMS YB OHMS BR OHMS
=====================================================================1. 4.600 4.613 4.6102 4.511 4.562 4.5543 4.497 4.511 4.5054 4.444 4.456 4.4535 4.393 4.404 4.4026 4.344 4.354 4.3507 4.291 4.302 4.2948 4.239 4.253 4.2449(b) 4.185 4.192 4.19210 4.239 4.250 4.24311 4.290 4.303 4.29512 4.341 4.360 4.34513 4.391 4.411 4.39714 4.441 4.461 4.44815 4.492 4.511 4.49916 4.546 4.561 4.55117 4.596 4.610 4.604
=====================================================================
172
CHAPTER-X
L.V.L.V.L.V.L.V. WINDING:WINDING:WINDING:WINDING: (Date(Date(Date(Date ofofofof Test:Test:Test:Test: 20.11.20.11.20.11.20.11.’’’’87)87)87)87)
(By V/I method. This method was resorted to as the wheatstone Bridge developed some defect.)
=====================================================================PhasePhasePhasePhase VoltsVoltsVoltsVolts CurrentCurrentCurrentCurrent DCDCDCDCOhmsOhmsOhmsOhms DCDCDCDC OhmsOhmsOhmsOhms
DC DC including lead of winding.resistance
=====================================================================rn 0.70 5.1 0.137 0.027yn 0.69 5.1 0.135 0.025bn 0.69 5.1 0.135 0.025ry 0.82 5.0 0.164 0.054yb 0.80 5.0 0.160 0.050br 0.80 5.0 0.160 0.050
=====================================================================
Caculation of lead resistance:
Let ‘R’ be the total lead resistance
R + yn = 0.135 - (1)R + bn = 0.135 - (2)2R + yn + bn = 0.270 - (3) = (1) + (2)R + yb = R + yn + bn = 0.160 - (4)R = 0.270 − 0.160 = 0.110 ohms - (3-4)
WindingWindingWindingWinding temperaturetemperaturetemperaturetemperature :::: 50505050°°°° CCCCOil temperature : 50° C
173
CHAPTER-XTABLETABLETABLETABLE ---- 3333 (b)(b)(b)(b)
110/33-11 KV MANAPPARAI S.S.(PR. TR.: 110/33 KV, 16 MVA, HHE) Date of Test : 20.1.93
DCDCDCDCRESISTANCERESISTANCERESISTANCERESISTANCE
Instruments used : Volts by Philips digital Amps by Meco digitalYard Temperature : 30˚ COil/Winding Temperature : 29° C
(A) PRIMARY SIDE : (OHMS) (Including a lead resistance of 0.1 Ohm)
==================================================================TapTapTapTap DCDCDCDC resistanceresistanceresistanceresistance ininininOhmsOhmsOhmsOhmsNo.No.No.No. ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Ry YB BR==================================================================
1. 4.099 4.106 4.1242. 4.056 4.062 4.0803. 4.005 4.014 4.0334. 3.957 3.967 3.9875. 3.919 3.922 3.9376. 3.860 3.873 3.8937. 3.817 3.825 3.8438. 3.769 3.778 3.7979. (a) 3.722 3.727 3.743
(b) 3.720 3.727 3.743(c) 3.721 3.727 3.747
10. 3.672 3.680 3.70311. 3.625 3.633 3.655\12. 3.580 3.587 3.60413. 3.535 3.533 3.56014. 3.485 3.488 3.51415. 3.440 3.441 3.46416. 3.390 3.391 3.41917. 3.344 3.342 3.364
==================================================================
(B) Secondary side : (OHMS)(Including lead resistance of 0.1 ohm)
ry = 0.3522 rn = 0.2259yb = 0.3482 yn = 0.2239br = 0.3503 bn = 0.2226
174
CHAPTER-XMAGNETIZINGMAGNETIZINGMAGNETIZINGMAGNETIZING CURRENT:CURRENT:CURRENT:CURRENT:
The magnetizing current drawn by the transformer at LT mains supply voltage may bemeasured for both the HV and LV Winding for all phases. For Delta-Star transformers, it isessential to measure the magnetizing currents on the star side. As the middle limb has a lowernett reluctance (as the fluxes traverse a shorter distance), the magnetizing current drawn by themiddle limb Winding will be lower.
IMPORTANT:IMPORTANT:IMPORTANT:IMPORTANT:
When measuring on the starside, the neutral point of the star connected windings should not beconnected to supply neutral and instead should be kept floated, as otherwise third harmoniccurrents on the three phases which will be phase coincident will flow through the neutral backto the supply source thereby giving higher values which will not be a true measure of themagentizing currents.
Abnormal value of magnetizing current can indicate inter turn short in the windings orproblem in the core like core shifting etc., So magnetizing current is a very important parameterto be taken not only for commissioning a new unit but also for comparison with future valuesof the transformer during its life period.
While measuring the magnetizing current, if only one set of readings are taken, thetransformer tap must be kept at minimum to include 100% of the winding irrespective of theside from which measurement is taken. The measurement can as well be made for all the tapsduring precommissioning test.
CAUTION:CAUTION:CAUTION:CAUTION:
When magnetizing current is measured on the LV side at LT mains voltage, the HVinduced voltage will be high. For instance it will be of the order of 4KVacross the phases for a110/11KV Power Transformer. The testing leads from the HV bushings must be removedbefore switching on supply for LV side measurement of magnetizing current.
The magnetizing currents may have different values for different transformers though thevoltage and MVA ratings may be the same, depending upon the individual characteristics of thecore material and construction feature and also depending upon the supply voltage. Howeverthe values will be within a close range for transformers of the same voltage rating and capacity.Typical values of magnetizing current are in Table – 4(a) & (b).
Measuring and recording the magnetizing current with accurate instruments as andwhen opportunity arises and building up a record of values in a transformer’s life time is a verywelcome preposition as review of the values with due allowance given for the voltages atwhich the measurements were taken, can throw light on changes taking place in the transformercore and forewarn a potential trouble brewing in the transformer.
175
TABLETABLETABLETABLE –––– 4(a)4(a)4(a)4(a)
110/33-11 KV MANAPPARI S.S(P.R.TR.: 110/33 KV, 16 MVA, HHE)
MAGNETISINGMAGNETISINGMAGNETISINGMAGNETISING CURRENTCURRENTCURRENTCURRENT (Date(Date(Date(Date ofofofof test:test:test:test: 20:01:93)20:01:93)20:01:93)20:01:93)
(A) HV Side measurement, LV side kept openInstruments: Volts by Phillips Digital multimeter
Current by - do –=====================================================================
Tap Primary volts applied Magnnetizing current in milli ampsNo. -------------------------- ------------------------------------------
VRY VYB VBR IRM IYM IBM===============================================================
1. 396 401.4 400.7 2.87 2.92 3.442. 2.88 2.92 3.443. 2.88 2.92 3.444. 2.87 2.92 3.425. 2.87 2.94 3.416. 2.87 2.94 3.387. 2.87 2.92 3.388. 2.87 2.92 3.389. 2.88 2.92 3.3810. 2.88 2.94 3.3611. 2.87 2.93 3.3412. 2.88 2.92 3.3613. 2.88 2.93 3.3214. 2.87 2.92 3.3415. 2.88 2.93 3.3216. 2.88 2.94 3.3217. 2.87 2.94 3.32
================================================================
(B) LV Side measurement, HV side open.(LV neutral floated)Instruments: Volts by Phillips Digital multimeter
Amps by Motewane Analog multimeter.
===============================================================Tap Seconndary volts applied Magnnetizing current in milli ampsNo. ------------------------------ -------------------------------------------
VRY VYB VBR IRM IYM IBM================================================================
1. 390.8 394.2 394.2 17 14.5 22.0================================================================
CHAPTER-X
176
CHAPTER-XTABLETABLETABLETABLE –––– 4444 (b)(b)(b)(b)
MAGNETIZING CURRENT (TYPICAL VALUES)(Dyll transformers, excited from the LV side, i.e., starside with neutral floated, HV open)
===============================================SL. Exciting current in milliNO. 3PhVoltage amps
Date of Test Sub-station Pr. Tr applied ====================== Remarks(Volts) I2U I2V I2W
===============================================1 26.9.92 33/11KV, THENNUR 33/11KV, 405 76.8 41.2 61.8 New
8MVA, INDO TransformerTECH
2 23.3.91 33/11KV, THENNUR 33/11KV, 373 20.0 14.5 22.0 New ( 1 )5MVA, ANDREWYULE No.1
3 23.3.91 33/11KV, THENNUR 33/11KV, 385 25.0 20.0 27.0 New ( 2 )5MVA, ANDREWYULE No.2
4 17.12.92 33/11KV, MAYANUR 33/11KV, 460 29.3 16.6 29.5 S.H. (1978)3.15 MVAAPEX
5 11.7.89 33/11KV, MAYANUR 33/11KV, 418 95.0 63.8 78.2 S.H.2 MVA
6 ------ 33/11KV, AZAD ROAD 33/11KV, 408 80.0 64.8 80.0 S.H.L.T.S.S., 2 MVA
KIROLOSKAR7 4.9.92 110KV, KARUR 110/11KV, 422 54.2 33.8 67.5 New
10 MVAHHE
8 19.03.90 110KV, KARUR 110/11KV, 370 68.0 59.5 84.0 New10 MVAHHE
9 26.3.91 110KV, TIRUCHY 110/33KV, 380 13.5 13.0 18.5 New16 MVABHEL
10 10.10.90 110KV, AYYERMALAI 110/33KV, 388 25.5 15.5 30.0 In Service16 MVAIMP
11 22.02.89 110KV, AYYERMALAI 110/33KV, 430 27.0 15.0 19.5 New16 MVAIMP
12 04.12.89 110KV, TIRUCHY 110/11KV, 375 82.0 57.0 93.0 New16 MVAHHE
13 15.2.93 110KV, KAMABARA- 110/11KV, 396 81.3 53.2 84.2 NewSAMPETTAI 16 MVA
VOLTAMP==============================================================================================
177
CHAPTER-X
POLARITYPOLARITYPOLARITYPOLARITY ANDANDANDAND VECTORVECTORVECTORVECTOR GROUP:GROUP:GROUP:GROUP:
In the ratio test with a ratio meter, null deflection can be obtained only if the polaritiesare correct. So correctness of polarity can be confirmed by successful completion of the ratiotest with a ratio meter.
When a ratio meter is not available, correctness of polarity and the Vector group can bedetermined in the following way.
The connections made for ratio test by voltage measurement can be used for this test. Theprimary and secondary windings are connected together at one point as indicated in fig –2(a) &(b). 3 Phase L.T. supply is applied to the HV terminals. Voltage measurements are then takenbetween various pairs of terminals as indicated in the diagrams and the readings obtainedshould be the vector sum of the separate voltages of each winding under consideration.
178
CHAPTER-X
179
Primary phase ‘U’ and secondary phase ‘W’ were shorted and 3-phase L.T Voltage wasapplied to HV side.
Voltage applied to HV side 445 (Ph – Ph)Voltage across Secondary : 51 V (Ph – Ph)
The following voltages were measured and compared with the expected values for DY 11Connection
Voltage across Voltages expected for DY 11 Voltages obtained1V – 2V
1W – 2V
1W – 2U
445 + J51 = 448 V
445 + 51 COS 30° = 489V
445 + 51 COS 30° = 489V
450 V
490 V
490 V
CHAPTER-X
180
Fig : 2(b) (b)
Hence vector group and polarities are correct. (See fig 2(b)(b) for vector diagram)
Establishing correctness of polarity and vector group are illustrated throughexamples for power and Auto transformers. Also see fig – 2 (c) and table 2 (a) (ii)for alternative way of establishing the vector group of “ Dy11”.
CHAPTER-X
181
CHAPTER-XCORECORECORECORE (MAGNETIC)(MAGNETIC)(MAGNETIC)(MAGNETIC) BALANCEBALANCEBALANCEBALANCE TEST:TEST:TEST:TEST:
This test is done to find out whet her the magnetic paths of the transformer core arebalanced. Single-phase voltage is applied across one phase and neutral on the star winding andthe voltage developed across the other two phases are read. Ideally for voltage applied to themiddle phase, the voltage in the two outer phases should be equal to half the voltage applied tothe middle winding. However there may be some difference due to variation in the magneticpaths. The measured values may be used as a parameter for future comparison. Results of testconducted on two transformers are furnished below:
(1) 110/11 KV Kamparasampettai SS.110/11KV/6MVA Power Transformer, DY11,Make : Volt Amp.Date tested : 15-2-93Supply given to LV side, HV kept open.
----------------------------------------------------------------------------------------------------------------Sl. No. Voltage applied Voltage obtained
----------------------------------------------------------------------------------------------------------------1. 2U-N: 228.4 V 2V-N: 174.0 V
2W-N: 53.8 V2. 2V-N: 224.3 V 2U-N: 114.2 V
2W-N: 109.3 V3. 2W-N: 223.4 V 2U-N: 55.3 V
2V-N: 169.7 V----------------------------------------------------------------------------------------------------------------
2) Trichy 230/110 KV SS:New Auto Transformer, 100 MVA.
Make: EMCO Transformers Ltd.,Date tested: 23.10.99Single phase Voltage was applied to HV Side.
----------------------------------------------------------------------------------------------------------------Sl. No. Voltage applied Voltage obtained
----------------------------------------------------------------------------------------------------------------1) 1U-N: 228.5 V 1V-N: 154.4 V, 1W-N: 85.5 V2) 1V-N: 230.5 V 1U-N: 138.4 V, 1W-N: 102.0 V3) 1W-N: 228.5 V 1U-N: 83.5 V, 1V-N: 166.0 V
----------------------------------------------------------------------------------------------------------------
Single phase voltage was applied to IV side.----------------------------------------------------------------------------------------------------------------
Sl.No. Voltage applied Voltage obtained----------------------------------------------------------------------------------------------------------------
1. 2U-N: 228.0 V 2V-N: 167.0 V, 2W-N: 69.4 V2. 2V-N: 229.4 V 2U-N: 122.0 V, 2W-N: 113.3 V3. 2W-N: 228.6 V 2U-N: 51.8 V, 2V-N: 189.8 V
----------------------------------------------------------------------------------------------------------------
182
Connect for opencircuit test Remove fuse in Red Phase supply in supply Board. Now,full LT. Ph to ph voltage is available across (1v-1w) only; i.e, middle phase winding for Dy11.So, in Secondary side, V(2V-N) must be the full induced ph to neutral voltage and so on.
Eg: 33/11 KV, MAYANUR SS : APEX, 3.15 MVADate tested : 17:12:92 Tap: Normal
L.T MainsPh-Ph supply 2U-N 2V-N 2W-N 2U-2V 2V-2W 2W-2Vacross1V – 1W 32.2 84.6 52.6 116.5 137.3 21.0440 V1W – 1U 19.5 70.5 84.6 59.3 154.2 100.5440 V1U – 1V 85.1 67.3 19.8 152.1 51.1 103.2
Hence Vector group is Dy 11.Hence Polarities are correct.
CHAPTER-X
183
CHAPTER-X
INSULATIONINSULATIONINSULATIONINSULATION RESISTANCERESISTANCERESISTANCERESISTANCE ANDANDANDAND POLARISATIONPOLARISATIONPOLARISATIONPOLARISATION INDEX:INDEX:INDEX:INDEX:
A 2.5 KV, mains (or motor) operated megger may be used. First, zero correction is to bemade. If the transformer has been under hot oil circulation, the insulation resistance has to bemeasured after the transformer has sufficiently cooled. The transformer neutral is to bedisconnected from ground. It should be ensured that there are no jumpers connected on to thetransformer bushings. The megger may be preferably kept on a flat wooden board or stool.Megger leads should be strong and have a very good insulation. The line lead of the megger isto be connected to the bushing of the winding under test and the earth lead, connected to one ofthe earth terminals of transformer tank. The line lead between the transformer bushingconnection and megger terminal must be kept suspended in the air by holding with asufficiently long and good and flexible insulation tape (glass tape or dry cotton tape forinstance) so that no part of the line lead comes into contact with the earth or transformer body.The one minute insulation value is to be taken and recorded. A minimum IR value of 2 megaohms per KV is expected.
For two winding transformers, HV to earth, LV to earth and HV to LV insulationresistance values are to be taken.
For three winding transformers, HV to Earth, IV to earth, LV to earth, HV to IV, HV toLV and IV to LV values have to be taken.
Along with the IR values, the winding/oil temperatures at the time of test, Date and time,details of the megger used and the weather condition are to be noted.
The polarization index is the ratio of the IR value at the tenth minute to the IR value atfirst minute and may be taken and recorded for all the windings to earth separately and alsoacross the windings. A PI value around 1.5 is good for oil immersed wi ndings like thetransformer. PI value will be an important parameter for future comparison. The Winding/Oiltemperature readings must of course be noted.
CAUTION:CAUTION:CAUTION:CAUTION:
Before commencement of the meggering, all the Engineers and Staff of different wingsaround must be cautioned that the transformer is going to be meggered and none is to come intocontact with the megger leads or any part of the transformer. Release the jumpers from thetransformer if already provided before commencement of meggering.
Refer tables 6(a), (b), (c), (d), (e), (f), (g) & (h) for results of tests conducted on230/110KVAuto transformers.
184
CHAPTER-X
TESTTESTTESTTEST OFOFOFOFTRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER OIL:OIL:OIL:OIL:
The dielectric strength (BDV) of the transformer top oil and bottom oil samples have tobe tested at site before and after circulation. Oil sample taken from the OLTC chamber is alsoto be tested. The acidity of the oil is also to be checked. These tests can be conducted by thespecial maintenance branch.
Besides, tests as per IS 335 for new oil may be got conducted at the Head-quarters R&Dlab and test results obtained and recorded to have bench mark values for future comparison.Refer to Annexure-VII of the proforma for transformer oil test result of the code of technicalinstructions for details.
DISSOLVEDDISSOLVEDDISSOLVEDDISSOLVED GASGASGASGASANALYSIS:ANALYSIS:ANALYSIS:ANALYSIS:
Gases are formed in oil in the transformer due to natural aging and at much greater rateas a result of faults and incipient faults. The type and severity of a fault may often be inferredfrom the composition of the gases and the rate at which they are formed. In the case of anincipient fault, the gases formed remain partly dissolved in the oil and only in special cases willfree gases be formed. Periodical sampling of oil from transformer and analysis of the dissolvedgases assist in the detection of faults at an early stage of development and may enable seriousfuture damage to transformer to be prevented.
The gases involved are hydrogen, some hydrocarbons, carbon oxides and atmosphericgases. Some of each of these gases will be formed during normal operation and these amountsare classified as norm. Fault conditions produce gases in higher quantity and in differentproportions which vary from the norm, the type and energy of the fault altering the carbon tohydrogen ratio of oil molecules in specifically related ways and producing variation in thecarbon oxide ratios when solid insulation is involved.
For details refer to item No. 3.07.03, Analysis of dissolved gases of the “code oftechnical instructions”.
Dissolved gas analysis may be got conducted at the R&D Wing on the Oil samplestaken after filling but before commissioning of new trnasformers to have bench mark valuesand at yearly intervals there after and also as and when there is action of Buchholz relay ortransformer differential relay for a genuine reason to take further action as per the interpretationof the test results.
185
CHAPTER-XCONDENSERCONDENSERCONDENSERCONDENSER BUSINGS:BUSINGS:BUSINGS:BUSINGS:
Bushing of transformers at EHT level are of sealed Condenser type. Beforecommissioning, the capacitance and tan delta values must be got measured by the R&D Wing.During service, it is worthwhile to check the tan delta value at yearly intervals. Any increasingtrend will be an indicator of the development of potentially destructive condition and thebushing must be replaced to avoid failure during service thereby preventing it from being asource of possible harm to the transformer itself. Refer to Annexure-VIII of the code ofTechnical instructions for the limiting tan delta values for different types of Condenserbushings.
OLTC:OLTC:OLTC:OLTC:
The present practice of the Board is to have OLTC for all power and Auto transformers,irrespective of the capacity of the transformer. The OLTC operations must be checked.
Manual operation of OLTC must be first checked. Before switching on supply to OLTCcontrol circuit, the IR value of the entire OLTC circuits must be checked with a 500v meggerfor satisfactory value. Then the OLTC control supply may be switched on and the operation ofthe Motor protection relay must be checked. OLTC operation by “Local electrical control”must be checked for all taps ensuring that the limit switches at both the extremities operatecorrectly. Tap changer mechanical indicator at the Driving mechanism and the electricalindicator at the remote panel at the control room must be checked for correct indication. Thenoperation through “Remote independent control” is to be checked. If the operation and tapindication have been satisfactory this far, then the OLTC control in the remote panel is to belooped to the OLTC control of the existing transformer/transformers if the new unit is asecond/third one to be paralleled with the existing transformer/transformers in the station.Operation of the OLTC of the new unit along with those of the existing units must then bechecked both in “Master” as well as “ Follower” mode for successful operation. “Out of step”condition for the new unit must be simulated and it should be ensured that “Out of step”annunciation with alarm comes. See Annexure-1, Also see section 3.04, ON LOAD TAPCHANGER of “ Code of technical instructions” and under the heading “ On-load tap changer”in section 3.03 maintenance procedures.
BUCHHOLZBUCHHOLZBUCHHOLZBUCHHOLZRELAY:RELAY:RELAY:RELAY:
Correct operation of the buchholz top and bottom floats must be checked. See section3.03.20, Buchholz relay of the “ code of technical Instructions”. Buchholz relay is a veryreliable device for protection of transformers against internal faults and it seldom malfunctions.Actuation of buchholz relay while in service must be taken seriously and the transformer mustbe taken out of service even for top float action. The gas accumulated in the buchholz chambermust be collected and analysed by the special maintenance branch as early as possible.
See instructions under Annexure-IV of the code of technical instructions for testing ofgas accumulated in Buchholz Chamber. A positive result surely indicates problem inside thetransformer. The transformer should be declared as defective even if the MRT results are OKand kept isolated permanently and the transformer erection branch informed for arrangingexamination of the transformer and rectification at site or at the transformer repair bay.
CHAPTER-X
186
ANNEXUREANNEXUREANNEXUREANNEXURE –––– 1111TIRUCHY 110 KV S.S. (PR.TR.: 110/11 KV, 16 MVA)
ON LOAD TAP CHANGER (Date of test: 25-26:11:1987)
(1) Manual operation of OLTC checked for tap raise and lower. OK. Tap indication at Drivingmechanism found OK.
(2) Local electrical operation of OLTC checked for tap raise and lower for all taps. OK.
(3) Tap changing from Remote control panel tried and found OK for both tap raise and taplower, with independent control. Tap position indicator at Remote control panel was foundnot functioning properly. Transformer erection was informed for rectifying or replacing thedefective tap position indicator. Remote tap position indicator since rectified and tested OKon 28.11.87.
(4) OLTC (3) control was looped to the existing OLTC (1) & (2) group, keeping unit (2) as thefirst unit of the group, unit (1) as the second and unit (3) as the last in the group.
Operations of OLTCs of power transformers-1,2 & 3 as a group were checked, keeping thecontrols of OLTC (3) in “ Master” and the rest in “Follower, and OLTC (2) in “ Master” andthe rest in “Follower” and lastly OLTC (1) in “Master” and the other two in “Follower”.All the operations were found satisfactory.
(5) Operation of motor protection relay, checked OK.
(6) Functioning of tap “ raise”, “Lower” limit switches was checked. OK.
(7) Functioning of out of step buzzer checked, OK.
(8) OLTC operation signaling at control panel was checked and found OK.
(9) IR value of all OLTC (3) Circuits to earth = 50 Meg Ohms.
COOLINGCOOLINGCOOLINGCOOLING FANS/OILFANS/OILFANS/OILFANS/OIL PUMPS:PUMPS:PUMPS:PUMPS:
If the transformer is provided with forced air cooling, the fan motor operations must bechecked. First the IR value of all fan control circuits and fan motors must be checked with a500v megger for satisfactory values. Then the operation of the fans must be checked first bymanual control and if OK by the switch in the Winding temperature indicator for auto start/stop.The currents drawn by the individual pump motors must also be measured and recorded. SeeAnnexure-2.(a) (ii)
If the transformer is provided with Oil pump motors, they must also be checked foroperation after meggering the circuits and motors. Operation of the oil pumps must be checkedfirst by manual control and if OK by the switch in the Winding temperature indicator for autostart/stop. The currents drawn by the individual pump motors must also be measured andrecorded.
187
CHAPTER-X
TEMPERATURETEMPERATURETEMPERATURETEMPERATURE INDICATORS:INDICATORS:INDICATORS:INDICATORS:
All Power and auto transformers are provided with oil as well as Winding temperatureindicators. During testing of Transformer/Transformer bushing CTS, the winding temperatureCT is also to be tested for current ratio and passed. Both the Oil and Winding temperaturemeters must be calibrated using a standard thermometer and a heated oil bath. If the radiatorsare provided with fan motors, automatic starting of fan motors at the set winding temperature isto be checked. The temperature setting may be made as per the manufacturersrecommendations. If the temperature setting is not specified, the temperature may be set at 65°C to start the cooling fans. The temperature for fan stopping may be set 5° C below thecorresponding “start” setting.
The oil and winding temperature alarm may be set as suggested under the sub section“Transformer Protection”. If winding temperature trip is provided, the same has also to be setas per the recommendation.
ALARMALARMALARMALARM ANDANDANDAND TRIPTRIPTRIPTRIP CIRCUITS:CIRCUITS:CIRCUITS:CIRCUITS:
Simulate and check the following for flag indication/annunciation with audible alarm.
(1) Conservator low oil level(2) Oil temperature high(3) Winding temperature high(4) Buchholz top float(5) Any other device connected for audible annunciation.
Simulate and check the following for flag indication/Annunciation with master trip.
(1) Buchholz bottom contact.(2) OLTC surge relay contact(3) Differential relay contact if provided(4) Pressure relief valve contact(5) Winding temperature trip if provided.(Ref. Annexure 2(a)(i) )
188
CHAPTER-X
ANNEXUREANNEXUREANNEXUREANNEXURE –––– 2222 (a)(a)(a)(a)TIRUCHY 110/33-11 KV S.S.
(i)(i)(i)(i) POWERPOWERPOWERPOWER TRANFORMERTRANFORMERTRANFORMERTRANFORMERALARMALARMALARMALARM ANDANDANDAND TRIPTRIPTRIPTRIP CIRCUITSCIRCUITSCIRCUITSCIRCUITS (TESTED(TESTED(TESTED(TESTED ONONONON 25.11.25.11.25.11.25.11.’’’’87)87)87)87)
1. 110/11 KV, 16 MVA Power Transformer (3) alarm with flag indication at control room wasconnected up for high winding / oil temperature, Conservator low oil level and Buchholz topfloat action.
The initiating contacts were closed and alarm and flag indications at control roomchecked Ok.
2. Buchholz bottom float contacts, OLTC oil surge relay contacts and differential relaycontacts were connected up for flag indication at control room and Master tripping of theconcerned breakers. The operation of the flag relays and master relay were checked by closingthe circuits. OK.
3. The master relay contacts were connected to trip 110 KV GC OMCB and Pr. Tr. L.V.VCBs (1), (2) & (3). The master relay was initiated and the trippings of these breakers werechecked and found OK. (Done on 29.11.’87) during station total shut down.
4. The alarm and trip circuits were meggered with 500 v megger to earth. IR value = 100 Meg.Ohms.
(ii)(ii)(ii)(ii) POWERPOWERPOWERPOWER TRANFORMERTRANFORMERTRANFORMERTRANFORMER (3)(3)(3)(3) COOLERCOOLERCOOLERCOOLERCONTROLCONTROLCONTROLCONTROL :::: (DONE(DONE(DONE(DONEONONONON 27.1127.1127.1127.11’’’’87)87)87)87)
1. All the three cooling fan motors were meggered with 500 v megger.
IR value of Motor 1 = > 100 M Ohms.- do - Motor 2 = > 100 M Ohms.- do - Motor 3 = > 100 M Ohms.
2. All the fan control and signalling circuits were meggered with 500 v megger. IR value = 50meg ohms.
3. Automatic starting / stopping of fan motors by temperature control was checked and foundOK.
4. Cooler motor starting/stooping signalling at control room was checked. OK.
189
CHAPTER-XBUSHINGBUSHINGBUSHINGBUSHINGCTsCTsCTsCTs ::::
Detailed tests on current transformers mounted in the transformer bushings must becarried out whet her the CTs are to be connected or not. Usually two CT cores, one fordifferential protection and the other for backup over current protection will be provided in eachphase. Class “ PS” CTs will be connected for differential protection and the backup protectioncore will in majority of cases be kept idle as relays for over current protection are usuallyconnected to the CTs in the LV breaker. If the CTs are not required, their secondary terminalsmust be kept shorted and earthed. See elsewhere in this manual for testing of CTs. Also seetable (7) for results of tests conducted on power Transformer bushing CT’s.
LVLVLVLV BREAKER:BREAKER:BREAKER:BREAKER:
Precommissioning tests on the transformer LV breaker, LV CTs and relays have to beconducted as per norms. See elsewhere in this manual for testing of breaker, CTs and relays.The over current relays in the LV breaker have to be graded with the HT feeder relays and theGroup control breaker. Refer Annexure 2(b)
COMMISSIONINGCOMMISSIONINGCOMMISSIONINGCOMMISSIONING CHECKS:CHECKS:CHECKS:CHECKS:
Refer to Annexure – I, checklist for commissioning of power Transformers undersection (3), code of technical instructions for details.
When the transformer is ready for energisation, a final check is to be made to ensurethat all protective devices are “ in” and that DC supply for the transformer is cut in. L.C mustbe returned if not done already. The Operator at the feeding substation is to be informed of theproposed energisation of the transformer and asked not to charge the line feeding the stationwithout concurrence in case it trips. It is every one’s duty to check that all the earth rods havebeen removed from the transformer and its breaker. When the transformer is really ready andsafe for energisation, other transformers in service if any in the station may be cut-off and thenthe new transformer may be energized through the Group Control breaker. If it is a smallstation with no group control breaker, the transformer AB Switch on the HV side may beclosed first and the transformer, energized by closing the station incoming AB Switch.
If everything is normal on energisation, the transformer humming may be carefullyheard. For any abnormal noise from inside the transformer it should be deenergisedimmediately. On satisfactory energisation the transformer is to be kept idly charged for a fewhours. The transformer may be initially stitched on to the HT bus making sure that other units ifany are ‘off’ and OLTC may be operated observing the voltage and voltage change through theHT bus PT or station service transformer. The phase sequence as seen at the Stationtransformer LT main fuses for the existing transformer and as well as the new transformer mustbe the same. After idle charging for a few hours, the new transformer may be directly put onload or paralleled with the other transformers and put on load as the case may be.
The next day the transformer may be switched off, LC availed of and air if anycollected in the Buchholz Chamber may be released. It is quite likely for any trapped air in theoil to have come up and get accumulated in the Buchholz Chamber.
190
CHAPTER-X
Annexure 2(b)Power Transformer (3) L.V. Breaker and relays:
(1) Relay tests: (Date of test: 16.10. ’87).
Relay Details:3 O/L and 1 E/L relays, Easun Reyrolle make.1 A, S1.Nos. HR.822124/822181; Type TJm 11.
(a) 3 O/L Relays.
Tested at a plug setting of 100% and a TLS of 0.2 Secs.The O/L relays are graded with the 11KVfeeder relays and 110 KV GCOMCB relays.All instantaneous elements disconnected.
(b) E/L Relay
Tested at a plug setting of 40% and a TMS of 0.3 seconds.The E/L relay is graded with the feeder. (E/L relay has since been disconnected as perBoard’s revised norms)Instantaneous element disconnected.
(c) IR Value of all relay terminals to frame = 100 Meg ohms (500V megger)
(2) Breaker tests: - (Date of testing : 23.11. ’87)
(a) The 30V tripping and closing coils supplied along with the breaker were released, rewoundfor 110V DC and put back in place.
(b) Breaker opening time checked:
R-Phase -- 0.04 Secs.Y-Phase -- 0.04 Secs.B-Phase -- 0.04 Secs.
(c) Trip Coil current - 3.5A
DC Volts = 122VDip in circuits = 4VMinimum tripping voltage for an O.C.B. opening time of 0.04 Secs = 58V.Corresponding trip coil current: 1.85A.
(d) Power transformerLV bushing CTs (5P20) used for L.V. Breaker relays. CTs mounted in the breaker released.CT ratio adopted = 900/1 Amp.
IR Value of protection CT Secondaries including cable leads and relays = 50 Meg. Ohms.(500V megger)
191
CHAPTER-X
(e) IR Value of DC control, protection and alarm circuits = 100meg ohms. (500Vmegger)
(f) Power transformer (3) put on short circuit and CT secondary currents at relaying pointmeasured.
Power Transformer H.V. current : 3.55A.-do- L.V. current : 30A.
CT Secondary currents.
Phase R = 33 Milli amps.Phase Y = -do-Phase B = -do-Residual = Zero.
(g) LV Breaker closing and tripping operations via Manual control, Local control switch andremote control Switch checked and found O.K.
Tripping through key interlock and relay contacts checked and found O.K.
Signaling at breaker panel and control room and alarm at control room checked and foundO.K.
Trip circuit supervision lamp checked and found O.K.
(h) IR value of breaker ac circuit leads including cable leads with 500V megger: 100 Megohms.Heater operations checked and found OK.
(i) Breaker panel Ammeter calibrated.MF for Ammeter = R X 0.75 (Top scale)
(j) Power transformer HV bushing CTs (Core : 5P20)Were used for current indication at control room.Ratio adopted : 90/1 Amps.Power transformer put on short circuit.Transformer HV Current = 3.55ATransformer LV Current = 30ACT Secondary currents at control room Ammeter measured.Phase R = 38 milli amps.Phase Y = -do-Phase B = -do-Neutral = Zero.
Control room panel Ammeter calibrated. MF for Ammeter= R X 0.9.
IR value of CT Secondary including cable leads and meter by 500V Megger = 50 meg.Ohms.
192
CHAPTER-X
ANNEXUREANNEXUREANNEXUREANNEXURE –––– 4444
TIRUCHY 110/33-11 KV S.S.
CHECKS DURING COMMISSIONING OF POWER TRANSFORMER – 3 ON 30.11.’87.
1. With Power Transformer (3) energised and kept idly charged from the HV side, thecurrent in the following terminals were measured at differential relay. (DTH 31, E.E.)
Current in milli-amps.------------------------------------------------------------------------------------------------------------ph Relay Current ph. Relay current ph Realy currentHV Terminal Diffl. Terminal LV Terminal------------------------------------------------------------------------------------------------------------
R 7 22 R 8 21 R 10 0
Y 11 19 Y 12 18 Y 14 0
E 15 21 B 16 21 B 18 0------------------------------------------------------------------------------------------------------------
(2) Power Transformer-3 alone energised, connected to 11 KV bus and on no load, the L.Tvoltages of the station supply Transformer was checked.
Phase sequence checked, OK.----------------------------------------------------------------------------------------------------------------Tap No Tap % Voltage Tap No Tap % Voltage----------------------------------------------------------------------------------------------------------------
17 + 15% 427 11 + 7.5% 394
16 + 13.75% 421 10 + 6.25% 390
15 + 12.5% 417 7 + 2.5% 376
14 + 11.25% 411 5 Normal 367
13 + 10% 405 3 -2.5% 358
12 + 8.75% 400 1 -5% 352-----------------------------------------------------------------------------------------------------------------
193
CHAPTER-X
3. With Power Transformer-3 alone on load, the currents at the following terminals of thedifferential relay were measured.
a) Power Transformer No. 3 : H.V. Current = 4.05 A |
| Both increasing.- do - : L.V. Current = 338 A |- do - : Tap: 16, + 13.75%
------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------------------
4) Power Transformer-3 and Power Transformer No. –1 were put in parallel and load sharingchecked and found OK.
5) Switching stability check of the differential relay: This is to be done by keeping the LV ofthe new Power Transformer open and charging it from the H.V side several times and thedifferential relay must not operate during this exercise. However, as the differential relay nowprovided in Power Transformer-3 has already been checked for switching stability during theTransformer magnetizing current in rush period during the commissioning of PowerTransformer No-2, this check was dropped.
Ph. Relay Current Ph. Relay Current Ph Relay CurrentHV Terminal Amps Diffl. Terminal Amps LV Terminal Amps
R 7 0.525 R 8 0.101 R 10 0.45Y 11 0.545 Y 12 0.103 Y 14 0.47B 15 0.530 B 16 0.100 B 18 0.46
194
PARALLELPARALLELPARALLELPARALLELOPERATION:OPERATION:OPERATION:OPERATION:The satisfactory parallel operation of transformers is dependent upon the following five
principal characteristics.
(1) The same inherent phase angle difference between the primary and secondary terminals.Same vector group will ensure this.
(2) The same polarity(3) The same phase sequence(4) The same voltage ratio(5) The same percentage impedance.
A very small degree of latitude may be allowed with regard to the fourth characteristicie., percentage impedance. But the first three requirements must be absolutely fulfilled.
Any voltage difference will cause a circulating current to flow between the secondarywindings of the transformers adding to the losses and heating. Hence it is best to have identicalvoltage ratios.
Difference in percentage impedances will cause unequal load sharing with thetransformer having the lower percentage impedance sharing proportionately more load. If thedisparity in outputs of any two transformers exceeds three to one, it may be difficult to producethe correct loading conditions for each individual unit. So, 3:1 in MVA rating is the limit forparallel operation.
When two transformer of unequal percentage impedances are operated in parallel, theload sharing and the maximum load transfer without overloading the transformers may becalculated as follows:
Transformer-1, 16MVA, Z = 10%Transformer-2, 10MVA, Z = 8.93%\
When operated in parallel, transformer-2 having lower percentage impedance will sharea proportionately higher load.
Let ‘P’ be the total load that can be transferred without over loading transformer-2. Letbase MVA be 16.
Let P1 & P2 be load shared by transformers – 1 & 2 so that P = P1 + P2
Z1 = 10Z2 = (16/10) x 8.93 = 14.29P2 = P (Z1/ Z1+Z2) = P (10 / 10 + 14.29)
ie., 10 = 0.412P.Therefore P = 10/0.412 = 24.3 MVA
P1 = P (Z2/ Z1+Z2)= 24.3 X (14.29 / 10+14.29)= 14.2 MVA
(P1 = P - P2 = 24.3 - 10 = 14.3)
195
CHAPTER-X
So a maximum of 24.3 MVA can be transferred without overloading transformer–2 andthe load shared by the transformer-1 will be 14.3 MVA (against 16MVA rated capacity) and bytransformer-2, 10MVA (Full capacity)
Before commissioning, paralleling test must be conducted by paralleling the new unitwith the existing unit on the HV side leaving the LV sides open and applying 3 phase LT mainsvoltage to the HV side. The voltage across like and unlike phases on the LV side may bemeasured for all taps. With both the transformers at the same tap, voltage across like phaseswill be zero or of negligible value and those across unlike phases will be the expected phase tophase LV voltage for that particular tap. For conducting this test, L.C must be availed of on theexisting unit and the usual precautions taken. See table-5.
When one transformer has OLTC and the other, off load taps, it is better to have the twotransformers feed loads independently by splitting the LV bus. If however it is felt that the twotransformers must be operated in parallel for better flexibility of managing the loads, the tap inthe Transformer with off load taps may be chosen and set considering the station voltageprofile and the tap in the transformer with OLTC may be set at the matching tap. If no exactmatching tap is available, one tap in the transformer with OLTC, with voltage ratio closest tothat set in the other transformer may be chosen. The OLTC supply cable must then bedisconnected and the handle for manually operating the OLTC must be removed and kept underlock and key with the AE/SS.
The two transformers can be operated in parallel in the taps chosen as above.
For instance, to parallel a new unit with OLTC having 17 taps (5% to +15%) with anexisting unit with off-load tap changer with 5 taps (-3 to + 9%), the tap in the existing unit maybe set at No.5, ie +9% and that in the new unit set at No.12 ie., + 8.75%. There will becirculating current between the two transformers on the LV side due to the unequal voltageratio which cannot be helped.
CAUTION:CAUTION:CAUTION:CAUTION:
Before energizing the new Transformer and paralleling with the existing unit, it shouldbe physically checked and ensured that the HV and LV dropper connections to the twotransformers from the strung buses are alike. Wrong dropper connections will virtually act as ashort circuit when the transformers are paralleled causing undesirable results. There have beenunfortunate incidents of this kind for want of carrying out this simple and elementary visualcheck.
196
CHAPTER-X
TABLE – 5POWER TRANSFORMER PARALLELING TEST -- DATE OF TEST :08.09.92
110/11 KV KARUR S.S. (PR.TR.:2, 110/11 KV, 10 MVA, HHE, NEW)(PR.TR.:1, ------ do ------, EXISTING)
Both the Transformers were parallelted on HV side and secondary volts were measured.Primary Volts applied: VRY = 430 V; VYB = 428 V; VBR = 428 V; ND means “NoDeflection”
=============================================================================
=============================================================================
===============================================================================
Note: Voltage measurement across like phases with the transformer at different taps isdeliberately done to ensure that ‘No deflection” in the voltage reading instrument, readacross like phases with the transformers of identical taps is genuine and not due to anytemporary defect in the instrument.
Tap No.PowerTr 1
Tap No.Power Tr 2
Vr1r2 Vr1y2 Vr1b2 Vy1r2 Vy1y2 Vy1b2 Vb1r2 Vb1y2 Vb1b2
11 11 ND 49 49 49 ND 49 49 49 ND10 11 0.46 48.5 48.5 48.5 0.47 48.5 48.5 48.5 0.4610 10 ND 48 48 48 ND 48 48 48 ND10 9 0.45 47.5 47.5 47.5 0.44 47.5 47.5 47.5 0.45
9 9 ND 47 47 47 ND 47 47 47 ND8 8 ND 46.5 46.5 46.5 ND 46.2 46.5 46.2 ND7 7 ND 45.8 45.8 45.8 ND 45.6 45.8 45.6 ND6 6 ND 45 45 45 ND 45 45 45 ND5 5 ND 44.5 44.5 44.5 ND 44.2 44.5 44.2 ND4 4 ND 43.8 43.9 43.8 ND 43.6 43.9 43.7 ND3 3 ND 43 43 43 ND 43 43 43 ND2 2 ND 42.5 42.5 42.5 ND 42.3 42.5 42.3 ND1 1 ND 41.5 41.8 41.5 ND 41.5 41.8 41.5 ND1 2 0.34 42 42 42 0.35 42 42 42 0.342 1 0.35 41.8 42 41.8 0.34 41.8 42 41.8 0.35
197
TABLE:TABLE:TABLE:TABLE: 6(6(6(6(a)a)a)a)
TIRUCHY 230/110 KV S.S.Precommissioning test on 100 MVA, Auto Tr.fr.
I. RATIO TEST
Instrument Used : ‘ELTEL’ Transformer Ratio Meter ( MODEL : TRM 200 )
(a) HV/IV Date tested: 5.11.99
TAP PHASE M.F READING % DEVIATION MEASURED EXPECTEDNO. RATIO CENTI RAD. RATIO RATIO1. U
VW
0.20.20.2
11.5011.5011.50
+0.00+0.06+0.10
+0.05+0.07+0.02
2.3002.3012.302
2.3002.3002.300
2. UVW
0.20.20.2
11.3711.3711.37
+0..5+0.10+0.14
+0.05+0.07+0.03
2.1962.1972.198
2.1952.1952.195
3. UVW
0.20.20.2
11.2411.2411.24
+0.00+0.05+0.10
+0.06+0.08+0.03
2.1692.1702.171
2.1692.1692.169
4. UVW
0.20.20.2
11.1111.1111.11
+0.02+0.07+0.11
+0.07+0.07+0.03
2.2102.2122.212
2.2102.2102.210
5. UVW
0.20.20.2
10.9710.9710.97
+0.08+0.07+0.11
+0.05+0.07+0.03
2.1972.1972.197
2.1952.1952.195
6. UVW
0.20.20.2
10.8410.8410.84
+0.10+0.15+0.20
+0.05+0.07+0.07
2.1712.1722.173
2.1692.1692.169
7. UVW
0.20.20.2
10.7110.7110.71
+0.05+0.10+0.15
+0.05+0.09+0.05
2.1442.1452.146
2.1432.1432.143
8. UVW
0.20.20.2
10.5810.5810.58
+0.09+0.12+0.19
+0.05+0.08+0.03
2.1192.1202.121
2.1172.1172.117
9B. UVW
0.20.20.2
10.4510.4510.45
+0.04+0.09+0.14
+0.07+0.09+0.05
2.0922.0932.094
2.0912.0912.091
10. UVW
0.20.20.2
10.3210.3210.32
+0.08+0.12+0.18
+0.07+0.09+0.05
2.0672.0672.069
2.0652.0652.065
11. UVW
0.20.20.2
10.1910.1910.19
+0.02+0.07+0.12
+0.05+0.10+0.05
2.0382.0392.040
2.0382.0382.038
CHAPTER-X
198
CHAPTER-X
(b) HV/LV--------------
12. UVW
0.20.20.2
10.0610.0610.06
+0.06+0.01+0.15
+0.08+0.10+0.05
2.0132.0122.015
2.0122.0122.012
13. UVW
0.20.20.2
9.939.939.93
+0.01+0.04+0.10
+0.07+0.09+0.04
1.9861.9871.988
1.9861.9861.986
14. UVW
0.20.20.2
9.809.809.80
+0.04+0.08+0.12
+0.07+0.09+0.05
1.9611.9621.962
1.9601.9601.960
15. UVW
0.20.20.2
6.676.676.67
+0.01+0.02+0.08
+0.08+0.10+0.05
1.9341.9341.936
1.9341.9341.934
16. UVW
0.20.20.2
9.549.549.54
+0.04+0.06+0.10
+0.08+0.10+0.05
1.9091.9091.910
1.9081.9081.908
17. UVW
0.20.20.2
9.419.419.41
+0.02+0.01+0.06
+0.08+0.10+0.06
1.8821.8821.883
1.8821.8821.882
TAP PHASE M.F READING % DEVIATION MEASURED EXPECTEDNO. RATIO CENTI RAD. RATIO RATIO1. U
VW
1.01.01.0
13.2813.2813.28
+0.18+0.13+0.08
+0.18+0.17+0.16
13.30413.29713.291
13.2813.2813.28
2. UVW
1.01.01.0
13.1313.1313.13
+0.20+1.501+0.10
+0.18+0.17+0.15
13.15613.32713.143
13.1313.1313.13
3. UVW
1.01.01.0
12.9812.9812.98
+0.17+0.10+0.06
+0.18+0.18+0.14
13.00212.99312.988
12.9812.9812.98
4. UVW
1.01.01.0
12.8312.8312.83
+0.20+0.12+0.08
+0.18+0.18+0.15
12.85612.84512.840
12.8312.8312.83
5. UVW
1.01.01.0
12.6812.6812.68
+0.15+0.09+0.04
+0.18+0.18+0.15
12.69912.69112.685
12.6812.6812.68
6. UVW
1.01.01.0
12.5212.5212.52
+0.261+0.18+0.15
+0.18+0.18+0.15
12.55312.54312.539
12.5212.5212.52
7. UVW
1.01.01.0
12.3712.3712.37
+0.221+0.15+0.10
+0.18+0.17+0.16
12.39712.38912.382
12.3712.3712.37
199
CHAPTER-X
8. UVW
1.01.01.0
12.2312.2312.23
+0.18+0.10+0.06
+0.18+0.18+0.15
12.25212.24212.237
12.3212.2312.23
9. UVW
1.01.01.0
12.0712.0712.07
+0.20+0.13+0.10
+0.18+0.18+0.15
12.09412.08612.082
12.0712.0712.07
10. UVW
1.01.01.0
11.9211.9211.92
+0.24+0.16+0.12
+0.18+0.18+0.16
11.94911.93911.934
11.9211.9211.92
11. UVW
1.01.01.0
11.7711.7711.77
+0.20+0.12+0.08
+0.19+0.18+0.15
11.79411.78411.779
11.7711.7711.77
12. UVW
1.01.01.0
11.6111.6111.61
+0.32+0.24+0.20
+0.18+0.18+0.16
11.64711.63811.633
11.6111.6111.61
13. UVW
1.01.01.0
11.4711.4711.47
+0.20+0.10+0.06
+0.19+0.19+0.16
11.49311.48111.477
11.4711.4711.47
14. UVW
1.01.01.0
11.3211.3211.32
+0.22+0.13+0.09
+0.20+0.19+0.16
11.34511.33511.330
11.3211.3211.32
15. UVW
1.01.01.0
11.1611.1611.16
+0.261+0.16+0.14
+0.20+0.19+0.16
11.18911.17811.176
11.1611.1611.16
16. UVW
1.01.01.0
11.0211.0211.02
+0.22+0.12+0.08
+0.20+0.20+0.17
11.04411.03311.029
11.0211.0211.02
17. UVW
1.01.01.0
10.8710.8710.87
+0.18+0.06+0.03
+0.20+0.20+0.16
10.89010.87710.873
10.8710.8710.87
200
CHAPTER-XTABLETABLETABLETABLE –––– 6(B)6(B)6(B)6(B)
II. OPEN CIRCUIT TEST
Instrument Used : ‘METRIX’ Digital Multimeter for Voltage: ‘MOTWANE’ Digital Multimeter for Current
a) Between HV & IV
1. 3 Phase Voltage Applied to HV2. IV & LV kept open
TAPNO
Voltage Applied in volts Voltage measured in volts1U-1V 1V-1W 1W-1U 2U-2V 2V-2W 2W-2U 2U-N 2U-N 2W-N
1 408.4 406.8 404.6 177.5 177.5 177.3 102.5 102.7 102.72 408.1 407.7 408.6 179.6 179.5 179.0 103.6 103.8 103.63 408.0 407.3 408.1 181.9 181.4 181.8 104.7 105.2 105.14 401.7 406.8 407.9 183.2 183.1 183.5 105.9 106.1 106.05 406.2 406.1 406.9 185.5 185.1 185.5 107.0 107.1 107.06 404.5 405.4 405.4 186.7 187.1 187.1 107.9 108.2 108.27 404.7 404.6 404.8 189.0 188.8 189.1 109.0 109.7 109.38 399.0 399.9 399.8 191.4 191.1 191.4 108.7 109.1 109.29a 399.6 399.4 399.7 191.6 191.7 195.5 110.5 110.8 110.69b 400.7 400.3 400.1 191.7 191.5 191.8 110.7 110.9 110.99c 404.9 403.8 405.8 194.0 193.3 194.5 112.2 111.9 112.010 404.7 403.4 404.7 196.0 195.6 196.5 113.3 113.5 113.311 404.9 403.7 404.7 199.0 198.0 199.0 114.7 115.0 115.112 403.8 402.5 403.7 201.0 200.5 200.0 115.8 116.0 116.013 404.0 403.0 403.3 203.7 203.0 203.0 117.4 117.7 117.714 404.4 404.0 404.5 206.5 206.2 206.2 119.2 119.5 119.515 405.3 404.6 405.1 209.3 209.0 209.3 120.9 121.2 121.216 404.8 404.3 405.6 212.5 212.2 212.9 123.0 122.0 123.017 405.1 405.0 405.7 216.3 215.5 216.4 124.6 124.5 124.7
201
CHAPTER-Xb) Between HV & LV
1) 3 Phase voltage applied to HV2) IV & LV kept open
c) Between IV & LV----------------------
1) 3 Phase voltage applied to IV2) HV & LV kept open
TAPNO
Voltage Applied in volts Voltage measured in volts1U-1V 1V-1W 1W-1U 3U-3V 3V-3W 3W-3U
1 423.8 422.8 422.0 18.5 18.5 18.52 423.9 423.1 421.8 18.7 18.7 18.63 424.1 423.7 421.9 19.0 19.0 18.94 424.5 422.6 422.0 19.2 19.2 19.15 423.8 423.2 421.6 19.4 19.3 19.36 424.4 423.2 421.7 19.6 19.6 19.67 424.1 423.5 422.1 19.9 19.9 19.88 423.2 422.6 421.2 20.1 20.2 20.09b 423.7 423.1 421.2 20.3 20.3 20.210 423.6 422.7 421.1 20.5 20.6 20.511 424.3 423.4 421.3 20.8 20.9 20.812 423.1 422.4 421.3 21.1 21.1 21.113 424.6 423.1 421.3 21.4 21.5 21.414 424.1 422.5 421.3 21.6 21.7 21.615 424.1 423.0 421.2 22.0 22.1 21.916 424.2 423.6 421.2 22.2 22.3 22.217 421.7 420.5 419.5 22.4 22.5 22.6
TAPNO
Voltage Applied in volts Voltage measured in volts2U-N 2V-N 2W-N 3U-3V 3V-3W 3W-3U
9b 235.5 235.7 234.5 41.1 40.7 41.1
202
CHAPTER-XTABLETABLETABLETABLE –––– 6(C)6(C)6(C)6(C)
III. SHORT CIRCUIT TEST
Instrument Used : ‘METRIX’ Digital Multimeter for Voltage: ‘MOTWANE’ Digital Multimeter for Current
a) Between HV & IV
1. 3 Phase Voltage Applied to HV2. IV shorted including Neutral3. LV kept on
TAPNO
Voltage Applied in V HV CURRENT in Amps IV CURRENT in Amps.1U-1V 1V-1W 1W-1U 1U 1V 1W 2U 2V 2W N
1 395.0 393.6 392.5 3.567 3.596 3.644 8.228 8.239 8.362 0.162 394.8 393.6 393.5 3.582 3.613 3.658 8.186 8.145 8.290 0.1343 393.6 392.1 392.0 3.595 3.614 3.663 8.087 8.023 8.175 0.1334 393.0 391.5 391.6 3.594 3.625 3.667 8.005 7.995 7.113 0.1635 394.5 393.5 393.4 3.600 3.621 3.678 7.937 7.900 7.036 0.1206 394.4 393.1 393.4 3.606 3.620 3.675 7.838 7.778 7.932 0.1757 394.1 392.8 393.4 3.585 3.624 3.670 7.710 7.715 7.826 0.1608 394.1 392.5 393.0 3.589 3.617 3.580 7.612 7.608 7.724 0.139a 393.6 392.4 393.2 3.575 3.600 3.641 7.501 7.464 7.578 0.129b 393.3 392.2 393.0 3.580 3.597 3.633 7.506 7.479 7.559 0.1339c 393.6 392.0 393.2 3.607 3.589 3.619 7.555 7.445 7.548 0.0510 393.3 391.5 392.5 3.592 3.570 3.606 7.448 7.323 7.422 0.511 393.2 391.5 393.0 3.569 3.551 3.584 7.294 7.193 7.285 0.04212 387.9 387.6 388.0 3.497 3.491 3.418 7.059 6.982 7.089 0.0513 386.7 386.1 386.9 3.472 3.468 3.500 6.919 6.823 6.927 0.04614 386.6 386.0 387.0 3.493 3.502 3.520 6.919 6.832 6.900 0.07215 393.9 393.8 394.1 3.481 3.479 3.498 6.743 6.682 6.750 0.0816 393.6 392.4 393.1 3.448 3.445 3.463 6.608 6.526 6.594 0.0617 395.1 393.6 394.6 3.432 3.420 3.441 6.442 6.381 6.442 0.06
203
CHAPTER-Xb) Between HV & LV
1. 3 Phase voltage applied to HV2. LV shorted3. IV kept open
TAPNO
Voltage Applied in V HV CURRENT inAmps
IV CURRENT in Amps
1U-IV 1V-1W 1W-1U 1U 1V 1W 3U 3V 3W N1 423.5 422.0 420.9 0.600 0.640 0.640 15.46 15.48 16.18 0.1605 417.8 416.9 416.7 0.600 0.650 0.640 15.01 15.10 15.77 0.134
9B 422.9 421.5 420.3 0.650 0.670 0.680 14.97 15.12 15.80 0.13513 421.8 421.9 419.4 0.660 0.700 0.690 14.60 14.68 15.23 0.16317 422.0 422.3 421.0 0.700 0.720 0.700 14.06 14.28 14.61 0.120
204
CHAPTER-XTABLETABLETABLETABLE –––– 6(d)6(d)6(d)6(d)
IV. MAGNETISING CURRENT
Instrument Used: ‘METRIX’ Digital Multimeter for Voltage: ‘MOTWANE’ Digital Multimeter for Current
(a) HV Magnetising Current
1. Voltage applied to HV2. HV & LV kept open3. Neutral floated
TAPNO
Voltage Applied in Volt Current measured in ma1U-1V 1V-1W 1W-1V 1U 1V 1W
1 400.0 397.0 399.0 1.497 1.436 1.8552 399.0 398.6 399.6 1.522 1.450 1.8723 398.3 397.0 398.0 1.552 1.440 1.8864 398.0 396.6 397.5 1.574 1.483 1.9005 398.0 396.6 397.0 1.625 1.456 1.9226 398.0 397.0 397.0 1.660 1.515 1.9377 399.0 397.3 398.0 1.664 1.546 1.9638 398.0 395.5 398.0 1.708 1.500 1.9879b 397.9 395.3 397.5 1.741 1.555 2.01410 396.8 395.0 397.0 1.780 1.563 2.02311 396.1 395.5 387.2 1.832 1.590 2.06412 396.0 395.5 397.3 1.863 1.625 2.08013 396.0 396.0 397.5 1.914 1.638 2.10614 396.0 396.0 397.5 1.967 1.647 2.13415 396.4 396.0 396.5 2.000 1.680 2.16016 396.4 396.0 396.5 2.050 1.725 2.21017 389.7 388.5 390.0 2.100 1.740 2.250
205
CHAPTER-X(b) IV Magnetising Current
1. Voltage applied to IV2. HV 7 LV kept open3. Neutral floated
(c) LV Magnetising Current
1. Voltage applied to LV2. HV & IV kept open
TABLETABLETABLETABLE :::: 6(e)6(e)6(e)6(e)V. DC RESISTANCE :Instrument: ‘ETEL’ Transformer Winding Resistance Meter (Mode): TWRM 5
Applied Current: 5 Amps.1. HV/LV WINDINGS
TAPNO
Voltage Applied in volts Current measured in ma2U-2V 2V-2W 2W-2U 2U 2V 2W
9b 407.0 407.7 407.7 4.41 2.85 3.58
TAPNO
Voltage Applied in Volts Current measured in Amps3U-3V 3V-3W 3W-3U 3U 3V 3W
9b 414.2 414.4 413.9 0.20 0.17 0.130
TAP U V W
NO. 1U-NOhms
2U-NOhms
1V-NOhms
2V-NOhms
1W-NOhms
2W-NOhms
1. 0.694 0.247 0.696 0.249 0.692 0.2482 0.687 0.248 0.687 0.249 0.686 0.2483 0.676 0.248 0.677 0.249 0.676 0.2484 0.668 0.248 0.669 0.249 0.668 0.2485 0.659 0.248 0.660 0.249 0.660 0.2486 0.649 0.248 0.651 0.249 0.651 0.2487 0.642 0.248 0.642 0.249 0.643 0.2488 0.634 0.248 0.634 0.249 0.633 0.2489 0.626 0.248 0.625 0.249 0.626 0.24810 0.635 0.248 0.635 0.249 0.634 0.24811 0.644 0.248 0.643 0.249 0.642 0.24812 0.654 0.248 0.650 0.249 0.651 0.24813 0.663 0.248 0.660 0.249 0.660 0.24814 0.670 0.248 0.669 0.249 0.668 0.24815 0.679 0.248 0.677 0.249 0.677 0.24816 0.687 0.248 0.686 0.249 0.686 0.24817 0.696 0.248 0.696 0.249 0.695 0.248
206
2) LV WINDING
TABLETABLETABLETABLE :::: 6(F)6(F)6(F)6(F)VI. MAGNETIC BALANCE TEST
Instrument Used: : ‘METRIX’ Digital Multimeter (Date of Test : 5.11.99)
1. HV Side
2. IV Side
3. LV Side
TapNo
3U-3Vm ohms
3V-3Wm ohms
3W-3Um ohms
17 14.55 14.55 14.55
VoltageApplied
Voltage1U-N
MeasuredIV-N
In Volts1W-N
1U-N1V-N1W-N
228.5138.483.5
154.4230.5166.0
85.5102.0228.5
VoltageApplied
Voltage1U-N
MeasuredIV-N
In Volts1W-N
2U-N2V-N2W-N
228.0122.051.8
167.0229.4189.8
69.4113.3228.6
VoltageApplied
Voltage1U-N
MeasuredIV-N
In Volts1W-N
3U-3V3V-3W3W-3U
395.0163.150.1
332.0394.0356.4
73.1233.0396.0
CHAPTER-X
207
CHAPTER-XTABLETABLETABLETABLE :::: 6(g)6(g)6(g)6(g)
VII POLARITY AND VECTOR GROUP
Instrument Used: ‘MOTWANE’ Digital Multimeter. (Date of Test : 5.11.99)
a) Between HV & IV (Yyo)
1. 1U & 2U shorted.2. 3 Phase Voltage applied to HV.
Voltage Applied in Volts. Voltage Measured in Volts.------------------------------------------------------------------------------------------------------------
1U--1V = 406.80 2U--2V = 404.701V--1W = 410.10 2V--2W = 188.301W--1U = 410.10 2W--2U = 183.101U—N = 234.40 2U—N = 233.701V—N = 244.10 2V—N = 108.701W—N = 230.70 2W—N = 105.00
1U—2U = 0.321U—2V = 304.001U—2W = 308.001V—2U = 405.401V—2V = 136.501V—2W = 305.901W—2U = 409.601W—2V = 293.701W—2W = 125.30
208
CHAPTER-X
1V – 2V = 1W – 2W136.5 = 125.30
IV – 2V < 1V – 2W>136.5 <305.90
1W – 2W< 1W – 2V125.3 < 293.7
1U,2U
1V1W
2V2W
209
b) Between HV & LV (yd)
1. 1U & 3U shorted2. 3 Phase Voltage applied to HV
Voltage Applied in Volts. Voltage Measured in Volts.
1U—1V = 407.50 3U—3V = 17.901V—1W = 407.90 3V—3W = 17.901W-1U = 409.40 3W—3U = 18.101U—N = 238.30 1U—3U = 0.001V—N = 235.10 1U—3V = 17.80IW—N = 235.20 1U-3W = 17.90
1V-3U = 407.901V-3V = 393.201V-3W = 409.001W-3U = 410.001W-3V = 394.801W-3W = 394.00
1V – 3W > 1W – 3W409 > 394.6
1V – 3W > 1V – 3V409 > 393.2
1U,3U
1V
3V
3W
1W
210
CHAPTER-X
TABLETABLETABLETABLE :::: 6(6(6(6(h)VIII. PI VALUE
InstrumentUsed: 5 KV ‘WACO’ POWEROPERATED IR. TESTER (Date of Test : 27.10.99)
Applied Voltage: 5 KV
TIME IR Value Measured in M Ohms.(Minutes)
HV - E LV – E HV – LV
0.5 1250 1500 20001.0 1300 1900 25002.0 1390 2400 28003.0 1400 2600 30004.0 1450 2800 35005.0 1500 2800 38006.0 1600 2800 40007.0 1700 2800 41008.0 1700 2800 42009.0 1700 2800 45001.0 1700 2800 4500
1) PI Value (HV-E): = 1700------ = 1.301300
2) PI Value (LV-E): = 2800------ = 1.4731900
3) PI Value (HV-LV): = 4500------ = 1.82500
211
CHAPTER-XTABLE:TABLE:TABLE:TABLE: 7777
BUSHING CTSOF POWER TRANSFORMERDate of testing: 22-2-19901) Ratio Test: Instruments used: (HHE Make, New Unit for
Motwane AVO meter (Karur 110/11 KV S. S, 10 MVA)Precision currentTransformer – 1No.
a) HV/ busing CTs (Core –1 – Differential – 60/1A;Core-2 - Backup – 60/1A.
-------------------------------------------------------------------------------------------------------------------Primary Secondary Secondary Secondary current obtainedCurrent Terminals current in Amps.injected expected - - - - - - - - - - - - - - - - - - - -Amps. Amps. IU IV IW-------------------------------------------------------------------------------------------------------------------60 IS1 –IS2 1.0 1.0 1.0 1.030 - do - 0.5 0.5 0.5 0.560 2S1 – 2S2 1.0 1.0 1.0 1.030 - do - 0.5 0.5 0.5 0.5-------------------------------------------------------------------------------------------------------------------(B) LV Bushing Cts.
Core (1) : Differential . . 600-300/0.577A.Core (2) : Back up. . . 600-300/1A
-------------------------------------------------------------------------------------------------------------------Primary Secondary Secondary Secondary current obtainedCurrent Terminals current Amps.Injected expected ----------------------------------------------------------Amps. Amps. 2U 2V 2W.-------------------------------------------------------------------------------------------------------------------600 1S1 – 1S3 0.577 0.58 0.58 0.58300 - do - 0.288 0.29 0.29 0.29300 1S1 – 1S2 0.577 0.58 0.58 0.58150 - do - 0.288 0.29 0.29 0.29600 2S1 – 2S3 1.0 1.0 1.0 1.0300 - do - 0.5 0.5 0.5 0.5300 2S1 – 2S2 1.0 1.0 1.0 1.0150 - do - 0.5 0.5 0.5 0.5-------------------------------------------------------------------------------------------------------------------
(2) Polarity Test:-Instrument used: (1) 6V Battery.
(2) Centre Zero. 0-30/, DC, Voltmeter.
212
CHAPTER-XPolarity, checked and like terminals marked thus below:
(a)(a)(a)(a) HVHVHVHV BushingBushingBushingBushingCTsCTsCTsCTs ....
1U1U1U1U1s1 1s2 2s1 2s2
1W1W1W1W1s1 1s2 2s1 2s2
1s1 1s2 2s1 2s2
1V1V1V1V
213
CHAPTER-X
(b)(b)(b)(b) LVLVLVLV BushingBushingBushingBushingCts:Cts:Cts:Cts:
2N2U
1s21s1 1s32s22s1 2s3
2N2V
1s21s1 1s32s22s1 2s3
2W2N
1s21s1 1s3
2s22s1 2s3
214
CHAPTER-X3) DC resistance:Instrument used: Agronic digital Ohm meter.
(a) HV Windings.
------------------------------------------------------------------------------------------Secondary DC resistance DC resistance obtained in OhmsTerminals. expected in 1U. 1V. 1W.
Ohms.------------------------------------------------------------------------------------------1S1 – 1S2 - - 0.5 0.5 0.52S1 - -2S2 - - 1.2 1.2 1.2------------------------------------------------------------------------------------------
(b) LV WINDINGS
--------------------------------------------------------------------------------------------Secondary DC resistance DC resistance obtained in Ohms.Terminals expected in 2U 2V 2W
Ohms.--------------------------------------------------------------------------------------------1S1 –1S2 - - 1.9 1.9 1.91S1 –1S3 - - 3.6 3.6 3.62S1 – 2S2 - - 2.4 2.4 2.42S1 – 2S3 - - 4.6 4.5 4.5--------------------------------------------------------------------------------------------4) IR Value.
Instrument used: 500V megger.(a) HV CTs--------------------------------------------------------------------------------------------Terminals IR Value in meg. Ohms.
1U 1V 1W--------------------------------------------------------------------------------------------1S1 to Earth 50 50 1002S1 to Earth 50 50 1001S1 to 2S1 50 50 100--------------------------------------------------------------------------------------------(b) LV CTs--------------------------------------------------------------------------------------------Terminals IR Value in meg. Ohms.
1U 1V 1W--------------------------------------------------------------------------------------------1S1 to Earth 100 100 1002S1 to Earth 100 100 1001S1 to 2S1 100 100 100--------------------------------------------------------------------------------------------
215
CHAPTER-X
(5) Secondary excitation.Instruments used: Motwane Avo meter - - 2 No.s‘V’ in volts and ‘I’ in Milli Amps.(A) HV CTs(i) Phase ‘U’ Differential (1S1 – 1S2).Ascending-------------------------------------------------------------------------------------------------------------------V. 10 20 30 35 40 45 50 55 60 75 100-------------------------------------------------------------------------------------------------------------------I. mA 50 70 88 95 110 118 128 140 150 170 240-------------------------------------------------------------------------------------------------------------------V. 120 130 135 140 145 150 155 160 165-------------------------------------------------------------------------------------------------------------------I.mA 310 355 385 420 465 515 620 760 920-------------------------------------------------------------------------------------------------------------------
Knee point voltage (V K ) = 140 V.I mag at VK/4 (35V) = 95 Milli amps.I mag. at 55V. = 140 Milli amps.
Descending.-------------------------------------------------------------------------------------------------------------------V. 160 155 150 145 140 120 100 60 55 20 10-------------------------------------------------------------------------------------------------------------------I mA 600 515 460 420 385 292 230 138 135 50 20-------------------------------------------------------------------------------------------------------------------Phase ‘U’ Backup (2S1 – 2S2).-------------------------------------------------------------------------------------------------------------------V. 10 30 50 75 100 125 150 200 250-------------------------------------------------------------------------------------------------------------------mAI. 30 55 75 100 120 142 165 210 262-------------------------------------------------------------------------------------------------------------------ii) Phase ‘V’, Differential (1S1 – 1S2).Ascending.-------------------------------------------------------------------------------------------------------------------V. 10 20 30 35 40 45 50 55 60 75 90 100-------------------------------------------------------------------------------------------------------------------I mA 35 55 70 80 87 92 100 107 115 135 155 170-------------------------------------------------------------------------------------------------------------------V. 120 130 135 140 145 150 155 160 165 167.5-------------------------------------------------------------------------------------------------------------------I mA 210 235 250 270 305 335 415 560 790 1020-------------------------------------------------------------------------------------------------------------------Knee point voltage (VK) =140V.I mag at VK/4 (35V) =80 Milli amps.I mag at 55V. =107 Milli amps.
216
Descending.CHAPTER-X
-------------------------------------------------------------------------------------------------------------------V. 160 155 150 145 140 120 100 80 60 55 40 20 10-------------------------------------------------------------------------------------------------------------------I. mA 560 380 330 280 250 200 165 135 105 100 75 40 15-------------------------------------------------------------------------------------------------------------------Phase ‘V’ – Backup (2S1-2S2).-------------------------------------------------------------------------------------------------------------------V 10 30 50 75 100 125 150 175 200 225 250-------------------------------------------------------------------------------------------------------------------I.mA 25 50 65 85 100 115 130 145 165 185 210-------------------------------------------------------------------------------------------------------------------iii) Phase ‘W’ Differential (1S1-1S2).Ascending.-------------------------------------------------------------------------------------------------------------------V 10 20 30 40 45 50 55 60 75 90 100 120-------------------------------------------------------------------------------------------------------------------I mA 35 45 72 80 87 95 100 110 128 145 160 180-------------------------------------------------------------------------------------------------------------------V 130 140 145 150 155 160 165 170-------------------------------------------------------------------------------------------------------------------I. mA 215 240 257 280 310 360 465 690-------------------------------------------------------------------------------------------------------------------Knee point voltage (VK) =145V.I mag at VK/4(36V) =77 Milli amps.I mag at 55V. =100 Milli amps.Descending.-------------------------------------------------------------------------------------------------------------------V 165 160 155 150 145 140 120 100 80 60 40 20-------------------------------------------------------------------------------------------------------------------I.mA 400 310 280 255 240 225 185 150 128 100 75 40-------------------------------------------------------------------------------------------------------------------Phase ‘W’ Backup (2S1-2S2).-------------------------------------------------------------------------------------------------------------------V 10 30 50 75 100 125 150 175 200 225 250-------------------------------------------------------------------------------------------------------------------I mA 30 55 75 100 120 142 165 187 210 235 262-------------------------------------------------------------------------------------------------------------------
217
CHAPTER-Xb) LV CTs.i) Phase ‘U’ Differential. 300/0.577A (1S1-1S2).
Ascending. (‘V’ in volts and ‘I’ in milliamps)-------------------------------------------------------------------------------------------------------------------V 10 20 30 40 50 55 60 70 80 90 100 105-------------------------------------------------------------------------------------------------------------------I 5 8 10 12.5 14.5 15 16 18 20.5 23 26 27-------------------------------------------------------------------------------------------------------------------V 110 115 120 125 130 135 140 145 150-------------------------------------------------------------------------------------------------------------------I. 30 33 36 39 43 50 58 70 90-------------------------------------------------------------------------------------------------------------------Knee point voltage (VK) =130 V.I mag at VK/4 (32.5V) =10.6 Milli amps.I mag at 110V =30 Milli amps.
Descending.-------------------------------------------------------------------------------------------------------------------V 145 140 130 120 100 80 60 55 40 20 10-------------------------------------------------------------------------------------------------------------------I 71 48 38 33 25 20 15.5 14.5 12 7.5 4-------------------------------------------------------------------------------------------------------------------Phase ‘U’ Differential. 600/0.577A (1S1-1S2).Ascending.-------------------------------------------------------------------------------------------------------------------V 10 20 30 40 50 55 60 80 100 120 140 160 180-------------------------------------------------------------------------------------------------------------------I. 1 2 3 3.5 4 4.2 4.5 5.5 6.2 7.2 8.2 9.5 10.5-------------------------------------------------------------------------------------------------------------------V. 200 210 220 230 240 250 260 270 275 280 290 300-------------------------------------------------------------------------------------------------------------------I. 12 13.1 14.3 15.2 16.5 18.1 20 23 27 35 41 54-------------------------------------------------------------------------------------------------------------------Knee point voltage (VK) =250.I mag at VK/4(62,5V) =4.6 Milli amps.I mag at 110V. =6.7 Milli amps.
Descending.-------------------------------------------------------------------------------------------------------------------V. 280 275 260 255 250 225 200 175 150 100 50 25-------------------------------------------------------------------------------------------------------------------I. 24 22 19 18 17 14.5 12 10 9 6.5 4 2-------------------------------------------------------------------------------------------------------------------
218
CHAPTER-XPhase ‘U’ Backup, 300/1A (2S1-2S2).---------------------------------------------------------------------------------------V. 50 100 150 200 250 300 330 350 365---------------------------------------------------------------------------------------I. 12 17.5 22.5 27 32 44 56 76 96---------------------------------------------------------------------------------------Phase ‘U’ Backup, 600/1A, (2S1-2S3).----------------------------------------------------------------------------------------V. 50 100 150 200 250 300 350 400 450----------------------------------------------------------------------------------------I. 3 4.5 6 7.5 8.5 9.5 11 12.2 13.5----------------------------------------------------------------------------------------(2) Phase ‘V’ Differential. 300/0.577A (1S1-1S2).Ascending.-------------------------------------------------------------------------------------------------------------------V. 10 20 30 40 50 55 60 75 100 110 120-------------------------------------------------------------------------------------------------------------------I.mA 3 5.2 7 8.5 10 10.5 11.5 13.5 17 19 21.5-------------------------------------------------------------------------------------------------------------------V. 125 130 135 140 145 150 155 160 165 168-------------------------------------------------------------------------------------------------------------------I.mA 23 24.5 26.2 28.5 31.5 35.5 42 50 67 97-------------------------------------------------------------------------------------------------------------------Knee point voltage (VK) = 140V.I mag at VK/4 (35V) = 7.7 Milli amps.I mag at 110V. = 19 Milli amps.
Descending.-------------------------------------------------------------------------------------------------------------------V. 160 155 150 140 130 125 100 75 55 25 10-------------------------------------------------------------------------------------------------------------------I. 41.5 35 31 26 22.5 21.5 17 13.5 10.5 5.5 2-------------------------------------------------------------------------------------------------------------------Phase ‘V’ Differential. 600/0.577A (1S1-1S3).Ascending.-------------------------------------------------------------------------------------------------------------------V. 10 20 30 40 50 55 60 75 100 150 200 225 230-------------------------------------------------------------------------------------------------------------------I. 0.5 1.2 1.5 2.1 2.5 2.7 3 3.7 4.5 6.2 8.2 9.5 10-------------------------------------------------------------------------------------------------------------------V. 235 240 245 250 255 260 265 270 275 280 285 290-------------------------------------------------------------------------------------------------------------------I. 10.2 10.5 10.7 11 12.5 14 14.5 15.5 16.2 17.2 18.5 20-------------------------------------------------------------------------------------------------------------------Knee point voltage (VK) = 250V.I mag at VK/4(62.5V) = 3.1 Milli amps.I mag at 110V = 4.8 Milli amps.
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Descending.-------------------------------------------------------------------------------------------------------------------V. 275 270 265 260 255 250 245 240 200 150 100 50 25-------------------------------------------------------------------------------------------------------------------I. 16.8 11.5 11 10.5 10.2 9.8 9.2 8.5 8 6 4.2 2.5 1.2-------------------------------------------------------------------------------------------------------------------Phase ‘V’ Backup 300/1A (2S1-2S2).----------------------------------------------------------------------------------------V. 50 100 150 200 250 300 325 350 360----------------------------------------------------------------------------------------I. 11.5 17.5 22.5 27.5 32.5 42.5 50 67.5 81----------------------------------------------------------------------------------------
Phase ‘V’ backup. 600/1A (2S1 – 2S3).----------------------------------------------------------------------------------------V. 50 100 150 200 250 300 350 400 450----------------------------------------------------------------------------------------I. 2.5 4.5 6 7.5 8.5 10.5 12 13.5 14.5----------------------------------------------------------------------------------------
(3) Phase ‘W’ . Differential, 300/0.577 (1S1 – 1S2).Ascending.-------------------------------------------------------------------------------------------------------------------V. 10 20 30 40 50 55 60 75 100 110 120-------------------------------------------------------------------------------------------------------------------I. 4 6.5 8.5 10 12 12.5 13.5 16 21.5 22.5 27.5-------------------------------------------------------------------------------------------------------------------V. 125 130 135 140 145 150 155-------------------------------------------------------------------------------------------------------------------I. 29.5 32 35.5 42 48 67.5 100-------------------------------------------------------------------------------------------------------------------Knee point voltage (VK) = 130v.I mag at VK/4(32.5V) = 8.9 milli amps.I mag at 110/. = 22.5 Milli amps.
Descending.-------------------------------------------------------------------------------------------------------------------V. 145 140 135 130 120 100 55 25 10-------------------------------------------------------------------------------------------------------------------I. 43 34.5 30.5 29 25.5 20.5 12 7 2.5-------------------------------------------------------------------------------------------------------------------Phase ‘W’, Differential, 600/0.577 (1S1 – 1S3)
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Ascending.-------------------------------------------------------------------------------------------------------------------V. 10 20 30 40 50 55 60 75 100 150 200 225 230 235-------------------------------------------------------------------------------------------------------------------I. 0.5 1.5 2 2.5 3 3.2 3.5 4.1 5.2 7.5 9.8 11.5 12 10-------------------------------------------------------------------------------------------------------------------V. 240 245 250 255 260 265 270 275 280 290-------------------------------------------------------------------------------------------------------------------I. 10.5 13.1 13.8 16 18.5 21 22.5 26 27.5 29-------------------------------------------------------------------------------------------------------------------
Knee point voltage (VK ) = 230V.I mag at VK/4 (57.5V) = 3.35 milli amps.I mag at 110/. = 5.7 milli amps.
Descending.-------------------------------------------------------------------------------------------------------------------V. 275 270 265 260 250 245 240 200 150 100 50 25-------------------------------------------------------------------------------------------------------------------I. 18 16 15 14 13.2 13 12 9.5 7.2 5 3 1-------------------------------------------------------------------------------------------------------------------
Phase ‘W’ Backup. 300/1A (2S1-2S2).----------------------------------------------------------------------------------V. 50 100 150 200 250 300 325 350----------------------------------------------------------------------------------I.mA 11.5 17.2 22 27.5 32.5 44 55 80----------------------------------------------------------------------------------
Phase ‘W’ Backup. 600/1A (2S1-2S3).-----------------------------------------------------------------------------------------V. 50 100 150 200 250 300 350 400 445-----------------------------------------------------------------------------------------ImA. 2.5 4.5 6.2 7.5 8.5 10 11.2 12.5 13.5-----------------------------------------------------------------------------------------
Winding temperature CT (Date of test: 13.03.90)-------------------------------------------------------------------------------------------------------------------
Primary current by Tong tester.Secondary current by motwane multimeter.
-------------------------------------------------------------------------------------------------------------------py. Amps 30 40 50 60 70 80 90 100 150 175-------------------------------------------------------------------------------------------------------------------sy. Amps 0.32 0.43 0.54 0.64 0.76 0.86 0.98 1.07 1.60 1.85-------------------------------------------------------------------------------------------------------------------
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II.II.II.II. PROTECTIONPROTECTIONPROTECTIONPROTECTION
A. External causes:
All transformers have to be protected against external causes that are sources ofabnormal stress to the transformer namely.
(a) Over load(b) Short circuits(c) High Voltage, high frequency disturbances.
Transformers of 400 KV rating are also protected against over fluxing caused by overvoltage/reduced system frequency.
(a) Over load causes increased Copper loss and a consequent temperature rise. Overloads canbe carried for limited periods depending on the initial temperature and the coolingconditions. The rating of a transformer is based on the temperature rise above an assumedmaximum ambient temperature under which condition no sustained overload is usuallypermissible. At a lower ambient temperature some degree of overload can be safelyapplied. Short period over loads are also permissible to some extent depending on theprevious loading conditions. No precise ruling applicable to all conditions is availableconcerning the magnitude and duration of safe overload. But the most important aspect isthat the winding must not be allowed to overheat, a temperature of about 95 C may beconsidered as the normal maximum working value beyond which further rise intemperature if allowed will have an adverse impact on the life of the transformer. Even thisupper limit of temperature is very much on the higher side for sustained operation and theoperating personnel must be cautioned of the high temperature of the winding at a muchlower level. This is the basis on which the high temperature annunciation is set. The typeof cooling also plays a part on the temperature settings. Refer to Section 3.02 (3.02.01,3.02.02, 3.02.03, 3.02.04) on classification of transformers according to cooling methodand permissible temperature rise, code of technical instructions.
In TNEB generally the following methods of cooling and setting are adopted fortransformers:-
(I) Power and Auto transformers in substations:Unless there is specific recommendation from the manufacturers, the following settingscan be generally adopted upto and excluding 16 MVA: Oil natural cooling throughradiators. Oil temperature alarm may be set at 70°C. Winding temperature alarm to beset at 80°C. Winding temperature trip is not provided.
(II) Power transformers 16 MVA and above and Auto transformers upto 50 MVA: Forcedair cooling through radiators with a set of cooling fans provided which can be switchedon manually as well through winding temperature meter.
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Oil temperature alarm : 70°C
Winding temperature alarm : 80°
Winding temperature trip : 90°
Cooling fans set to start at a winding temperature of 65°C and set to stop at windingtemperature of 60°C.
(III) 230/110KVAuto transformers, above 50MVA. Forced air cooling through radiators andforced oil circulation.
Oil temperature alarm : 75°C.
Winding temperature alarm : 85°C.
Winding temperature trip = 95°C.
Cooling fans set to start at 70°C of winding temperature.
Cooling fans set to stop at 65°C ------- do ------
Oil pump motor set to start at 75°C of ------- do ------
Oil pump motor set to stop at 70°C of ------- do ------
(b)(b)(b)(b) SHORTSHORTSHORTSHORTCIRCUITS:CIRCUITS:CIRCUITS:CIRCUITS:
Power transformers of lower capacity i.e., below 5 MVA, 33/11 KV are protectedagainst external short circuits by Horn gap fuses on the HV side and the feeder protection. Thefuses will blow off for internal faults also but by that time the fault may get magnified.Transformers of rating 5 MVA and above are protected against external faults by the feederprotection and the over- current relays in the LV breakers protect the transformer against LVbus faults. Over current relays in the group control breaker on the HV side of the transformeralso provides cover against heavy faults on the LV side. The earth fault and over current relaysin the group control breaker by the way may also give protection against heavy internal faults.
(c)(c)(c)(c) HIGHHIGHHIGHHIGHVOLTAGE,VOLTAGE,VOLTAGE,VOLTAGE, HIGHHIGHHIGHHIGHFREQUENCYFREQUENCYFREQUENCYFREQUENCYDISTURBANCES:DISTURBANCES:DISTURBANCES:DISTURBANCES:
A high voltage transformer connected to an overhead transmission system is likely to besubjected to steep fronted impulse voltages due to atmospheric disturbances or switchingoperation. A line surge which may be of several times the rated system voltage willconcentrate on the end turns of the winding because of the high equivalent frequency of thesurge front. The surges can breakdown the internal insulation producing extensive damage tothe transformer windings, if not taken care of. The effects of these surges may be minimizedby designing the windings to withstand the application of a specified surge test voltage andthen ensuring that this test value is not exceeded in service by the provision of a suitable surgearrester mounted adjacent to the transformer terminals.
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Modern practice of surge protection of transformers is aimed at preventing excessivevoltage surges from reaching the transformer as a unit, that is, not only the HV and LVwindings but also the bushings, where flash over and insulation breakdown will result inserious damage and system disconnection. The required surge protection is given bycoordinating rod gaps in the bushings and the surge arresters. In TNEB, transformers below 50MVA capacity are provided with an independent lightning arrester on the LV side and by acommon arrester on the HV side. 230/110KV Auto transformers are provided withindependent arresters both on the HV as well as LV side for surge protection.
B)B)B)B) PROTECTIONPROTECTIONPROTECTIONPROTECTION AGAINSTAGAINSTAGAINSTAGAINST INTERNALINTERNALINTERNALINTERNAL FAULTS:-FAULTS:-FAULTS:-FAULTS:-
(a) BuchholzBuchholzBuchholzBuchholzrelay:-relay:-relay:-relay:-
This is a gas operated device fitted to transformers having conservator tanks and is installedin the pipe line between the transformer and its conservator tank. This device consists of anoil-tight container fitted with two internal elements one below the other which operate mercuryswitches connected to external alarm and trip circuits. Normally this device is full of oil andthe elements due to their buoyancy can rotate on their supports. An incipient fault within thetransformer generates small bubbles of gas which in passing upwards towards the conservator,get trapped in the buchholz relay there by causing the oil level to fall as a result of which theupper element rotates and when sufficient oil has been displaced the mercury switch contactsclose thus completing the external circuit which is connected to audible alarm. In the event of aserious fault within the transformer, the gas generation is more violent and the oil displaced bythe gas bubbles flows through the connecting pipe to the conservator. This abnormal flow ofoil causes the lower element to be rotated thus actuating the contacts of the second (bottom)mercury switch thereby completing the external circuit which is connected to trip the circuitbreaker/breakers to isolate the transformer.
Some of the faults against which the buchholz relay will give protection are(i) Top contact (alarm):-Acts for minor faults.
Core-bolt insulation failure.Short-circuited core laminations.Bad electrical contacts/faulty joints.Inter turn faults or other winding faults involving only lower power infeedresulting in local over heating,Loss of oil due to leakage,Ingress of air into the oil system.
(ii) Bottom contact (trip). Acts for serious faults.Short circuit between phases,Winding earth fault,Winding short circuit,Puncture of bushings.
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The buchholz relay is an invaluable and most reliable device for protection oftransformer against internal faults, whet her required as a main protection or as a supplement toother protection schemes and it seldom malfunctions.
Its action on a live transformer calls for immediate attention and action on the part ofthe substation/MRT and special maintenance Officers and Staff.
On actuation of the relay, gas within the device can be collected from a small valve atthe top of the device for analysis and from the results obtained a rough diagnosis of the troubleinside the transformer can be made. Refer to Annexure-IV, instructions for testing of gasaccumulated in Buchholz relays and item No. 3.03.20, Buchholz relay – Examination of gas ofSection-3, Code of technical instructions.
(b)(b)(b)(b) OLTCOLTCOLTCOLTC SURGESURGESURGESURGERELAY:RELAY:RELAY:RELAY:
The Diverter switch forming part of the on load tap changer is housed in a separate oiltank the oil of which does not communicate with the oil in the main tank. The diverter chamberhas its own oil conservator. A protective surge relay is provided in between the diverter switchoil tank and its conservator. Faults in the diverter causes an oil surge which causes the surgerelay contacts (that is connected to trip the circuit breaker/breakers) to close and isolate thetransformer. Refer to subsection 3.04, on-load tap changer of the code of technical instructions.
DIFFERENTIALDIFFERENTIALDIFFERENTIALDIFFERENTIAL RELAY:RELAY:RELAY:RELAY:
This protection covers the complete transformer. This is basically a circulating currentsystem formed with carefully selected CTs on the primary and secondary sides of thetransformer. The single line diagram in fig.3(a) shows the principle of transformer differentialprotection in its simplest form. Assuming the transformer at principal tap and with correctlymatched CTs on either side, no current will flow through the differential path for normal loadconditions or through faults and the relay does not operate. During an internal fault the currentbalance is upset and the difference of the two currents flow through the differential pathcausing relay operation.
However to apply this principle to the usual three phase transformer, a number ofconditions are to be fulfilled.
(a) Transformer ratio:
The rated currents of the transformer on the primary and secondary sides differ ininverse ratio to the corresponding voltages. The CTs should therefore have primary ratings tomatch the rated currents of the transformer windings to which they are applied.
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CHAPTER-X(b) Transformer connections:
If the transformer is connected delta-star, balanced three phase through current suffers aphase shift of 30°C which should be corrected in the CT Secondary leads by appropriateconnection of the CT secondary windings.
Zero sequence current flowing on the star side of the power transformer will notproduce current outside the delta on the other side. The zero sequence component on the starside must hence be prevented from entering the differential relay by connecting the Currenttransformers in delta.
The above two requirements are met in a Delta-Star transformer by connecting the CTson the Delta side of the transformer in Star and on the star side of the transformer in delta. Ifthe transformer is star-star, the CTs on both the sides are connected in delta. When the CTs areconnected in delta, their secondary ratings must be reduced to 1/√3 times (0.577) the secondaryrating of the star connected CTs so that the currents outside the delta may balance with thesecondary currents of the star connected CTs.
(c) Tap changing facility:
The current transformers are selected to balance at the principal tap. Operation at a tapdifferent from the principal one will create an unbalance proportional to the ratio change. Atmaximum through fault current, the spill in to the differential path may be substantial.Differential protection is therefore provided with sufficient bias to restrain relay operationagainst through faults at the maximum tap. refer to fig. 3 (b), (c) & (d).
(d) Magnetizing In-Rush
When a transformer is charged, there is a magnetizing current in-rush. There is nocurrent on the other-side, the entire Secondary current of CT located on the side from which thetransformer was charged, flows through the differential path. The relay will see this as aninternal fault and operate unless the condition is identified as magnetizing inrush and additionalrestraint provided to block relay operation. A typical magnetizing inrush current waveform isshown in fig.4. This contains considerable second harmonic component, which may beanything from 20% to 60% of the fundamental depending on the point in the voltage waveformat which the transformer was energized. The second harmonic component generated may bemaximum when the transformer is energized when the voltage wave is passing through zero.The second harmonic component is filtered from the current entering the differential path andused as additional bias to restrain relay operation. Relay operation is usually blocked when thesecond harmonic content exceeds 18 to 20%of the fundamental component.
For auto transformers, if the tertiery is not connected to any load, the transformer istreated as a two winding transformer for differential protection ignoring the tertiery winding.The protection will however act for faults in the tertiery winding as well.
However if the third winding is connected to a load or supply, it cannot be ignored.CTs should be provided for the third winding also and suitably connected in the differentialprotection scheme – Single line diagram illustrating this is given in fig.3 (b) & (c).
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Restraint through current in multiples of rated current
(When the differential current exceeds a certain percentage of the through current, relayoperates. This percentage is settable in the relay. Hence this relay is called percentagedifferential relay)
PERCENTAGEPERCENTAGEPERCENTAGEPERCENTAGEDIFFERENTIALDIFFERENTIALDIFFERENTIALDIFFERENTIAL RELAY:RELAY:RELAY:RELAY:
Fig : 3 (d)
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The differential relays are provided with a high set instantaneous element for high speedprotection against terminal faults in the transformers. Such faults involve very high faultcurrents and if this causes the CTs to go into partial saturation, the resulting harmonies mayslow down relay operation. To take care of such a contingency, the differential relay isprovided with an unrestrained high set element.
Static differential relays of different make are in service in TNEB. The relays usuallyhave a basic setting and a pick-up of 15 or 20% of relay rated current is adopted. The biassetting may have certain specific values from 15% and 50% depending on the make of the relay.Suitable bias setting based on the max transformer tap in percent has to b adopted. The
available setting in the High set instantaneous element may be some specific value from 8 to 20times relay rated current. The relay operating time may be 30 to 50 milli seconds for restrainedoperation and 10 to 20 milli seconds for unrestrained operation. For each make, relayinstruction manual gives features of the relay, settings available, recommended settings, testingprocedure etc., Generally the following tests have to be done.
a) Pick up check
b) Bias check
c) Second harmonic check
d) High set element check
For relay testing procedure see elsewhere on testing of differential relays in this manual.
Class “ PS” CTs are used in differential protection and the CTs are usually provided inthe transformer bushing themselves with the required ratio based on the power transformervoltage and power rating. The CT secondaries and relays have 1 Amphere rating as per thepresent standard practice. As per standardisation the bushing CTs available in the powertransformerws can be used for differential protection without the need for any interposingauxiliary CTs. Where differential CTs are not available in the power transformer bushings,external CTs may be provided (with suitable auxiliary interposing CTs if required) fordifferential protection. Interposing CTs may be needed when a 5A CT Secondary is to be usedfor a 1 Amp relay and to reduce the pilot current to the relay by 1/√3 when 1A rated CTs areconnected in delta.
230/110 KV auto transformers have their own lightning arresters on the HV and LVsides. To bring the LAs within the zone of protection, external CTs on either side of thetransformer are provided for differential protection though differential CTs are available in thetransformer bushings. If CTs are kept idle their secondaries must be permanently shorted.
The differential protection will correctly act only if the CT ratio, CT polarity and CT-relay connections are correct. During precommissioning tests, these aspects must be carefullychecked. During precommissioning tests, the CTs must be tested for
Typical Transformer
Magnetizing inrush current wave
( High second harmonic content )
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CHAPTER-XRatio,Polarity,
Knee point voltage,Magnetizing current,
Secondary winding d.c. resistance andInsulation resistance of secondary winding (with 500V meggar only)
Refer to chapter on testing of current transformers else-where in this manual.Finally and as the last item of check, short circuit test on the transformer at LT mains
voltage is to be done. Along with the short circuit currents on the HV and LV side of thetransformer, the HV CT pilot currents on the three phases, LV CT pilot currents on the threephases and the differential currents on the three phases must be measured and checked whet herthe values are as expected. The test may be done at the principal tap and at the maximum tap.The expected spill current must be available in the differential paths at maximum tap and Zeroor negligible current in the differential paths at principal tap. To facilitate measurement ofthese nine values of currents which will be in milli amps, the leads from the CT to thedifferential relay must be routed through suitable current terminals with links that can beopened for current measurement and kept closed normally. See figure – 5. Two importantpoints have to be noted. The neutral of the star connected CTs must be earthed at only onelocation and as close to the CTs as possible. The marshaling box in the transformer tank is anacceptable location for this purpose. The star point of the differential relay must be on the CTside of the current terminals to facilitate measurement of the differential currents on the threephases. Check and ensure that except for the above star, there is no other star point in thedifferential relay panel or anywhere in the differential relay circuit including the relay.
The above checks through transformer short circuit test is the most important item ofprecommissioning test on transformer differential protection and must be carried out carefullyand properly. Otherwise the differential relay may trip under normal load conditions or for athrough fault. There have been many instances of nuisance trippings of the Transformerdifferential relay due to improper conducting of this check and in most cases the reason wasthat this check was not at all done or was done in an improper way. Once this check has beensatisfactorily completed no further work should be done on the CTs or relays or in the CT-relaycircuitry. Refer Annexure-3, checking correctness of differential CT-relay connectionsequence.
Also see the following figures for current flow in the differential relay for normalconditions, internal fault conditions and external fault conditions;
Power transformer: Fig – 6 (a), (b), (c), (d), (e) & (f)
Auto transformer : Fig – 7 (a), (b), (c), (d) and (e)
Also, refer to “Practical guide to differential protective scheme to Power Transformer”by Er. A.S. Kandaswamy, CE/Transmission/Chennai.
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ANNEXUREANNEXUREANNEXUREANNEXURE –––– 3333CHECKING CORRECTNESS OF DIFFERENTIAL C.T. CONNECTION SEQUENCE
Tiruchy 110 KV SS. (Date of testing: 23-24/11/1987)With the Power Transformer-3 (110/11 KV, 16 MVA) differential C. T. Secondary
connections and differential relay connections completed, with the differential relay inserted inthe relay casing in position, the power transformer was put on short circuit. That is, the Powertransformer L.V. Winding and neutral terminals were shorted and 3 phase LT Voltage wasapplied to the H.V. terminals. The currents in the differential H.V. and L.V. CT secondarypilots and in the relay differential path were measured.Power Transformer tap at No. 17 (+15%)
-do- HV Current : 3.55 A-do- LV Current : 30 A
Differential CT Secondary currents obtained (milli amps)Relay: DTH 31, EE Make.
------------------------------------------------------------------------------------------------------------H.V. CT Pilots Differential L.V. CT Pilots
------------------------------------- ------------------------ ----------------------------Relay Phase Current 1. 2. 3. 1. 2. 3.Terminal
1. 2. 3.------------------------------------------------------------------------------------------------------------
7 R 39 8 R 6 10 R 3311 Y 39 12 Y 6 14 Y 3315 B 39 16 B 6 18 B 33
------------------------------------------------------------------------------------------------------------Power Transformer tap brought to normal and the above currents measured:------------------------------------------------------------------------------------------------------------
7 R 32 8 R 0.6 10 R 3211 Y 32 12 Y 0.7 14 Y 3215 B 32 16 B 0.7 18 B 32
------------------------------------------------------------------------------------------------------------It is therefore confirmed that the differential CT and relay connection sequences are
correct.(6) IR VALUES: - (Date of test 24.11.”87)
Checked with 500V Megger.
(a) IR Values of differential CTSecondaries including cable leads and relay : 50 meg Ohms
(b) IR Values of D.C. circuits of differentialRelay including cable leads. : 50 meg Ohms
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CHAPTER-XWHENWHENWHENWHEN DIFFERENTIALDIFFERENTIALDIFFERENTIALDIFFERENTIAL RELAYRELAYRELAYRELAY ACTS:ACTS:ACTS:ACTS:
A differential relay is expected to act only for a fault inside the transformer and forfaults anywhere in the differential protection zone. But in the last 20 years, action of thedifferential relay for a wrong cause has been predominant in the substations. In fact in wellover 90% of the cases of action of differential relay connected to power transformer, the actionhas been for wrong reasons like lack of through fault stability in the relay, lack of stability formagnetizing in-rush, defects arising in the CT circuits and wrong CT-relay connections. Whenthe differential relay acts, the transformer is isolated and the MRT/Special maintenance wingsare to be informed. If relay action is accompanied by buchholz relay action, analysis of the gascollected in the buchholz chamber will confirm whet her the tripping is for a fault in thetransformer or not. Even if the buchholz relay has not acted, the buchholz chamber has to beexamined for gas collection and gas analysed if collected. If the differential relay has acted notaccompanied by gas collection, then the MRT branch has to carefully and accurately determinethe reason for differential relay action.
Short circuit test may be conducted on the transformer and the differential CT pilotcurrents and differential currents measured. This check will confirm whet her there is any defectin the CT-relay connections including wrong connection or not and action is to be takenaccordingly.
If the connections are healthy and correct and if the differential relay action was duringa through fault and there is no gas collection, the relay would have acted due to lack of throughfault stability. If the relay has acted during charging of the transformer and if there is no gasaccumulation in the buchholz chamber, the relay would have acted for lack of magnetizing inrush stability. Defects in the relay could also be the reason in the above two cases. Carefultesting of the relay will confirm whet her it is defective or not and action is to be takenaccordingly.
If the transformer is found healthy, the differential relay is tested OK and if the CT-relay connections are healthy and correct and if no specific cause could be attributed todifferential relay action, then the relay may be interchanged with that in the adjacenttransformer to study the future behavior of the relay. If there is no adjacent unit forinterchanging the relays, the relay may be retained in the transformer. However if there isrepeated action of the particular differential relay without any apparent cause the relay may bereplaced and the released relay, referred to the manufacturer.
As stated earlier, action of differential relays in power transformers of TNEB has beenfor the wrong reasons in well over 90% of the cases in the last 20 years. So it will be illadvised to keep a healthy transformer out of service just because the differential relay has acted.When a transformer is kept out of service for any length of time forcing load restrictions, the
Board loses revenue and a large number of consumers stand of Suffer. The onus is on the MRTEngineer to give a clear verdict. For this one must be confident and decisive. Confidence andtaking correct decisions come from a good knowledge of the transformer and a thoroughunderstanding of the various aspects of differential protection and being meticulous andmethodical in executing protection works and having the ability to put the knowledge gainedfrom experience in to practice. In short the MRT Engineer must know his job well.
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245
The following may be taken as general guidelines on the action to be taken againstaction of the transformer differential relay.
CASECASECASECASE (a)(i)(a)(i)(a)(i)(a)(i)
Differential relay operates when a new power transformer is energized. Buchholz relaymay or may not have acted. Gas collection in Buchholz Chamber is present.
Test the gas. If result is positive, declare transformer as defective. If gas test result isnegative, test the transformer. If results are satisfactory, declare transformer as being OK. Testthe differential relay particularly the high set element. If results are not satisfactory, disconnectand remove the differential relay. Install a healthy relay if readily available after testing it.Proceed to energize the transformer again. If a differential relay is not readily available, thetransformer may be charged with buchholz protection. If the differential relay test results aresatisfactory, the transformer may be charged with the same differential relay. If it acts againand the transformer is declared OK, discard the differential relay. If the transformer is chargedOK on the second occasion with the same differential relay, keep the differential relay in forfuture observation. If similar behavior is observed in any of the future energisation of thetransformer, the relay can be considered as not possessing magnetizing inrush stability whenconditions at the instant or charging cause maximum inrush current. Relay can then be replacedand the released relay, referred to manufacturer.
CASECASECASECASE (a)(ii)(a)(ii)(a)(ii)(a)(ii)
Same operation as in (a.i) except that the transformer is an existing one that has been inservice in that station for some length of time.
If gas is present in buchholz chamber, test the gas. If result is positive declaretransformer as faulty. If result is negative, or no gas has accumulated and if there have beenprevious operations of the differential relay during transformer energization, consider that thedifferential relay does not possess magnetizing in rush stability. Transformer can be consideredas healthy and put back into service. Differential relay may be got replaced at the firstopportunity. If differential relay operation is first occurrence, test the transformer. If OKdisconnect the differential relay and charge the transformer. Then turn attention to thedifferential relay. Test it. If not OK, replace it. If OK, put the differential relay back into serviceand watch its future performance.
CASECASECASECASE (b)(b)(b)(b)Differential relay operates during a through fault.
If the tripping during through fault is the first occurrence for the differential relay, Ifthere is gas collection, test the gas and act accordingly. Even if there is no gas collectionsuspect the transformer as well as the relay. Test the transformer. Check the CT pilot anddifferential currents, conducting Transformer short circuit test. If OK, test the relay. If relay isdefective, replace the relay. If relay is also OK put the transformer and relay back into serviceand watch the relay’s future behavior. If transformer is OK and relay is OK but CT/differentialcurrents measured during transformer short circuit test are not OK, check and find out whet her
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246
any of the CTs is defective and act accordingly. If CTs are OK, check the CT-relay circuits,locate the problem, attend to it, repeat the short circuit test, confirm that everything is OK andput the transformer and relay back into service.
(i) If the differential relay has a history of previous operations during through fault, and ifthere is no gas collection, consider that the differential relay lacks through fault stability. Putthe transformer back into service. Test the relay. If not OK, replace it. If OK, decide whet her toput the relay back into service or not depending on the number of previous such operationsduring through fault. Generally avoid keeping relays with such misbehavior in service andinstead replace the relay with a healthy one.
CASECASECASECASE (c)(c)(c)(c)
Differential relay acts under normal conditions. When the transformer is in service. Nothrough fault.
If there is gas collection, act accordingly. Even if there is no gas collection, suspect thetransformer, relay, CTs and connections. Concentrate on the transformer first and test it. Duringshort circuit test check the differential CT Pilot/differential currents. Determine whet her thetransformer or CTs or circuits is defective. If one is defective, act accordingly. If the results areOK, then test the relay. If not OK, release it, put the transformer back into service. Replace therelay with a healthy one. If the relay is OK and no cause could be determined, transfer thedifferential relay in the adjacent transformer to the transformer in question and vice-versa. Actaccording to future observations. If this is not possible, if the differential relay action for noapparent cause is the first occurrence, give the relay another chance. If there is a secondoccurrence replace the relay.
The above are to be treated as general guidelines only and not as something to befollowed to the hilt. The idea is that if the differential relay action is not due to any defect in thetransformer or bushing CTs, but due to other reasons the transformer is to be brought intoservice at the quickest possible time. To that extent, the above aim of not keeping a healthytransformer off line for more than the minimum time required the above guide lines are meantto help the engineer to achieve the above to clear it.
400400400400KVKVKVKV TRANSFORMERS:TRANSFORMERS:TRANSFORMERS:TRANSFORMERS:
The following protections provided for 230/11KV Auto transformers are provided for400/230 KV Auto transformers and 400/110 KV Power Transformers also.
a) Buchcholz Protectionb) Differential protectionc) OLTC surge relayd) Thermal, overload protection (Winding temperature trip)e) Over current protection in breakers on either side.
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The following additional protections may also be provided in view of the importanceand very high cost of the transformer.
f) Differential protection based on high impedance.g) Under impedance relayh) Overfluxing relay
Power frequency over voltage causes both an increase in stress on the insulation and aproportionate increase in the working flux of the transformer. Increased flux causes an increasein the iron loss and a disproportionately great increase in magnetizing current. The spurt iniron loss can overheat the core. Flux is diverted from the core structure into steel structuralparts. Under over excited core condition, the core bolts which normally carry little flux may besubjected to a large component of flux diverted from the highly saturated and constricted regionof core alongside the core bolt. Under these conditions of operation, the core bolts can get overheated rapidly with an adverse effect on their own insulation. If the conditions are allowed tocontinue the coil insulation may get affected.
Reduction of frequency has an effect on the flux density similar to that of over voltage.An over voltage accompanied by lower frequency will be the worst operating condition for atransformer with regard to over fluxing.
The basic principle involved in over fluxing relay is to monitor V/F and the relay has atime delay characteristic related to V/F as instantaneous tripping for over fluxing condition isnot required.
CASECASECASECASE STUDY:STUDY:STUDY:STUDY:
1. Defective bushing CTs:
During precommissioning tests on the new power transformer bushing CTs forupgradation of 66 kv Ayyermalai SS to 110 KV, certain defects were noticed. Report from theMRT branch to the Distn. Circle S.E is produced below.
Sub: 110 kv Upgradation of Ayyermalai SS – New IMP make 110/33-11 kvPower transformer under erection – Bushing CTs – Test results – defectsnoticed – Reg.
* * * *
The bushing CTs of the 110/33-11 kv, 16 MVA, “IMP” make PowerTransformer supplied against Chief Engineer/Transmission P.O.No.854, dt: 18.09.87 and nowunder erection at the 66 kv Ayyermalai sub-station were tested by the MRT branch on 10-14:02:89. Certain defects and deviation from the P.O specification observed are reportedhereunder.
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i). H.V.CTs
A) Backup Protection core
Tested and found satisfactory.
B) Differential protection core, Class “PS”
The CTs were tested and found satisfactory except for the following deviationfrom the P.O specification.
As per the P.O specification, the magnetizing current at VK/4 (VK = knee point voltage)should be less than 50 milli amps. The actual values obtained are furnished hereunder.
Phase VK measured VK / 4 Magnetizing current at VK/4 inMilli amps actually measured
U 80 V 20 V 69V 80 V 20 V 62W 80 V 20 V 70
ii) L.V. CTS
c) Differential protection CTs (class “PS) CT Ratio : 300/0.577 A (For use with 110/33 kvratio of Power Transformer)
As per the P.O specification, the minimum knee point voltage shall be as under.
Vk = 40 I (RCT + RL) where,I = Relay rated current (1 Amp in this case)RL = Lead resistance (1 ohm in this case)*RCT =CT secondary winding resistance.
The test results indicate that the actual knee point voltages are less than theminimum values expected as furnished here under.
Phase RCT I RL Min. Vk Vk obtainedIn ohms in amps in ohms expected actually.
U 1.555 1 A 1 102 V 83 VV 1.542 1 A 1 102 V 80 VW 1.556 1 A 1 102 V 93 V
The CTs are otherwise tested and found satisfactory.
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C) Backup protection CTs (class 5P20)
Initially the ratio test results and DC resistance of Phase “V” CT were notsatisfactory while that of phases “U” and “ W” were satisfactory.
Later, during the secondary excitation tests, all the three phase CTs
behaved erratically. Even at low voltages the exciting current was jumping, varying whenthe voltage was kept steady and shooting up beyond 1A. This wild behavior of these CTsgenerally indicates that the inner layer winding insulation of the CTs has given way. All thethree CTs are hence declared defective.
The matter may please be arranged to be taken up with the supplier for replacement ofthe defective CTs.
NoteNoteNoteNote::::In response to the above, the differential CTs were replaced by the firm, tested and
found satisfactory in all respects. One of the LV backup CTs was rectified at site and the restwere replaced by the firm, tested and found satisfactory in all respects.
∗ RL is 2 ohms as per present norms.
2) During the late nineteen seventies 110KV, 10MVA power transformers in service wereprovided with static differential relays. Twelve such relays were provided in PowerTransformers in the then composite Trichy Elecy. System. In the early nineteen eighties someof these relays were acting for magnetizing inrush condition once in a while. The High setelements in these relays had a setting of 10A. On testing, the High set elements were foundacting for 5 to 6 Amps. The problem was well beyond the guarantee period. However as anumber of relays were involved, the problem was referred to the manufacturer. Themanufacturer’s Engineer, after examination of the relays at site changed a few resistances in therelays and the relays were tested and found OK. The suspected resistances in other relays forwhich no problem was reported were also changed. The defect in all these cases was that theoriginal ohmic value of some of the resistances have got changed during service. It was laterlearnt that poor quality control in the firm which supplied the resistances to the relaymanufacturing company was the reason behind the ohmic shift in the resistances after just afew years of service. Since rectification, there had been no further operation of the differentialrelays during transformer charging.
In the above cases the relays would have acted whenever the maximum amplitude of thetransient current during the magnetizing inrush period was of very high level. Various factors,the prime being the point in the voltage waveform at which the transformer was changed wouldhave determined the maximum transient current amplitude.
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3) One day in the mid eighties, the differential relay of the 11OKV, 10MVA, PowerTransformer No. 1 at the 110/11 KV Thiruverumbur SS had acted under normal loadconditions. The transformer, differential relay, differential CT and connections were checkedand found satisfactory. There was no apparent cause for the relay operation. The relay inquestion and the identical relay in the identical transformer No-2 were interchanged. About amonth later, the same differential relay then in transformer No.2 again acted for no apparentreason. Definitely there was a hidden problem in the relay, which could not be identifieddespite the MRT Wings ’ brain raking session with the relay. The relay was referred to themanufacturer who wanted it at their works at Chennai for examination. A week later the relaywas returned with the remarks that some defective component in the relay had been replacedand certifying that the relay was OK and could be put back into service. The relay wasrecommissioned in transformer No.2, after testing it and finding it OK. Some twenty days afterit’s recommissioning, the relay acted again under normal load conditions and again there wasno apparent reason. The usual tests on the relay and CT circuits revealed nothing adverse. Thecommon factor in the three relay operations was that the relay had acted one to two hours pastnoon when the ambient temperatures were about maximum for the day and the season wassummer. The differential relays of both the transformers were housed in a metal box beside thetransformer in the yard. So were the identical relays in ten other transformers in differentsubstations.
The relay was again sent to manufacturer stating in very clear terms the above commonfactor involved in the three maloperations. The relay was returned by the manufacturer giving aclean chit to it. Obviously they could not locate the hidden cause. The relay was put back intoservice in transformer No.1.
About two weeks later, it acted again for the fourth time. Needless to mention that the relayoperation was during normal conditions, about an hour and a half past noon when the yardtemperature was at its maximum for the day. The time for further trials was over and there wasno better option to the MRT Wing than discarding the relay.
The cause for the maloperation of the relay remained a mystery. The MRT Wing wasdisappointed that they couldn’t unravel it. But then, the relay manufacturer couldn’t either andthat was some consolation. One thing was certain. The higher yard temperature past noon thatsummer was the trigger, affecting some component in the relay. The static relays are supposedto perform best in airconditioned environment but then no Electrical Utility in India can affordto aircondition the control room of a 110KVSS. Whether the relay would not have maloperatedhad it been installed in the control room where the ambient temperature would be a few gooddegrees lower was a moot point. But the important observation is that all the twelve relayssupplied to Trichy Elecy system were all installed in the yard only and were all in service undersimilar conditions without any such misbehavior and some of the relays are still in service now.There is also no denying the fact that performance wise installation of such static relays in thecontrol room instead of the yard will be a better choice, despite the slight increase in the burdendue to lengthy cables.
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GENERATORGENERATORGENERATORGENERATOR PROTECTIONPROTECTIONPROTECTIONPROTECTIONEr.K. Mounagurusamy
CE / P&C
1.1.1.1. NatureNatureNatureNature ofofofof faultsfaultsfaultsfaults andandandand meansmeansmeansmeans ofofofof productionproductionproductionproduction::::
1.1 Voltage Surges:
Systems over voltages caused by direct lighting strokes on transmission lines can reachthe generator through the transformer as voltage surges. Station type lightning arrestors andsurge capacitors are provided at the output terminals of the generators for the protection againstthese voltage surges.
1.2: Over currents
Due to
– External faults in the system
– Overloading continuously to meet demand
– Unbalanced loading due to unbalanced loads or due to systemproblems.
Simple over current relays with normal inverse characteristics can be used – Normalpick up value is 1.5 times full load current. Time delay is set to match the thermal capability(Curve being supplied by generator manufactures) of the generator.
Voltage restraint over current relays which can be regarded equivalent to impedancerelays are better in the sense that the relay will operate more or less independently of currentdecrement and act quicker for faults causing reduction of Generator terminal voltage. Voltagecontrolled over current relays have two pick up setting – one for normal voltage and the second,a low pick up with a changed pick up and characteristic when voltage goes below say 40%.These relays are most suitable when excitation is derived from the output of the generator itself,since the excitation will itself will get reduced when generator terminal voltage is going down,the effect being cumulative.
Generally, this protection is connected to trip the generator breaker only, withoutshutting down the Unit.
If this relay is connected in the neutral side, it acts also as a back protection for thegenerator itself.
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Continuous overloading to meet system demands is monitored by thermal relays or byspecially connected over current relays shown as below:
RTD (Resistance temperature detector embedded in stator core)
O/C SetterRelayCoil
I2 IR I1
Normally, I1 I2
110 V IR OPT
Normally, no current is flowing through the relay coil. When the resistance of RTDincrease due to increase of RTD increase due to increased stator temperature, an unbalancedcurrent is developed through the relay coil to pick it up. The relay has inverse characteristic.
Any contact resistance in relay input finger contacts, wiring terminals could maloperatethe relay.
Suggested to connect for alarm in manned Power Houses.
1.3: Unbalanced Protection:
Unbalance loading could be due to
– Opening of one pole of the generator breaker.
– Open circuit of one line in transmission systems
This will lead to negative sequence currents in the stator thereby leading to armaturefield, which rotates in the opposite direction of the rotor. Hence, double frequency eddycurrents will be induced in the rotor causing temperature rise.
Setting based on the formulae I22 t = K Where k - a constant depending upon the
heating characteristic of the machine
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t – time in seconds
I2 – negative sequence current expressed inper unit stator current.
Generally,
K = 30 for turbine generator, synch condensers= 40 for hydraulic generator
If I2 exceeds 0.25 per unit, alarm acts
If I2 exceeds 1 per unit, trips the generator
The protective systems consists of a negative sequence current filter feeding a currentrelay of I2 t =K characteristic.
In some cases like Sholayar, an ammeter is provided in series with the over currentrelay showing the value of unbalance current for continuous monitoring by the Operators.
Phase to phase faults and phase to ground faults will also be detected by this relay butother protection will be faster than this relay.
The reason for the more time delay usually adopted is since the source of unbalanced isin the system and with generators in the vicinity these should not be disconnected unless thecondition remains uncorrected for such a time that there is the danger of damaging thegenerator.
The validity of the equation I22 t = K is based on the assumption that all energy
generated by the negative sequence current, is transmitted in the form of heat to the rotorwithout any losses to surroundings. In reality, a certain portion of this heat is transferred to thestator. If the negative sequence current is of continuous nature a thermal balance will beobtained.
In the case of salient pole generator, the eddy currents occur to a greater extent indamper windings. On hydro units, these damper windings are in general ably dimensioned andhence such generators will be able to withstand much higher negative sequence currents thanturbo generators of similar ratings.
Modern, direct cooled turbo generators and salient pole generators without damperwindings can be damaged and must therefore be tripped if the negative sequence current forany lengthy period exceeds 5% of the rating of the machine.
For some hydro units, the time can be as high as 60 seconds.
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1.4 Over Voltage Protection:
Sustained over voltage on a machine might be caused by
- faulty voltage regulator
- sudden load changes in the machine withmanual voltage control. Even system frequencychange could vary the generator output voltage.
Sudden loss load in a hydro generator due to any isolation could lead to 180% over speeddue to slow operating governor and turbine gates. This can cause very dangerous voltage rise ifthe AVR is not there. If good AVR is available, the voltage rise could be limited to 1.5% evenfor such over speeds.
Protections is by– Armature attracted type with definite time delay (OR)
– Inverse voltage relay with pick up around 120%– Instantaneous elements are also used with high
pick up value upto 140%1.5 Earthing and earth fault protection:
Earth faults normally occur in the armature slots. They are more likely to happen whenthere are voltage surges or sustained over voltage at the generator terminals as explained in 1.1and 1.4. Maintaining the AVR in good working condition can save many stator windings fromdamage.
The damage at the point of fault in the core is directly related to the selected currentrating of the neutral earthing impedance i.e. to the earth fault current quantity. With faultcurrents less than 20 A negligible burning of the iron core will result if the machine is trippedwithin some seconds. See Fig. 1. The repair work then amounts to replace the defective coilonly without restacking the laminations.
If, however, the fault current is more, severe burning of the core will be the result,NECESSITATING RESTACKING OF LAMINATIONS, a much more price. Even when ahigh-speed earth fault differential protection is used, severe damage may be caused, owing tothe large time constant of the field circuit and the relatively long time required to completelysuppress the field flux.
Some of the grounding methods are discussed below:a) Ungrounded systems – Not in practice in T.N.E.B.
b) Resistance grounding system – Used in old stationslike Singara and Moyar. Protection is by over-currentrelays in the neutral.
c) Neutraliser ground systems OR Peterson coil:
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The total systems capacitance to ground is cancelled by an equal tuned inductanceconnected in the neutral in which case the current in the fault point is zero but there will becurrent through the neutral inductance to enable to have a protection relay (Voltage relay)across the inductance.
d) P. T. earthed System
A voltage relay across the P.T. secondary gives the earth fault protection.
e) Distribution transformer grounding:
This is mostly used. A distribution transformer is introduced between neutral point andground. The secondary is shunted by a resistor. This is in fact a high resistance groundedsystem. The resister is to prevent the production of high transient voltages in the event of arcingearth fault, which it does by discharging the bound charge in the circuit capacitance. For thisreason, the equivalent resistance in testator circuit should not exceed the impedance of the totalsummated capacitance of the three phases. In other words, the resistive component of the faultcurrent should not be less than the residual capacitance current.
Earth fault protection can be obtained by applying a relay to measure the transformersecondary current OR by connecting a voltage measuring relay in parallel with the loadingresistor.
Typical examples:
XC = Total capacitance per phase of generator windingsurge protection capacitor, lighting arrestergenerator connections, Generator transformer (LV)
= 0.227 F
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Total residual capacitance = 3 x C = 3 x 0.227 F106 106
Total residual capacitive impedance = =3ωC 314 x 0.681
= 4680
Value of effective resistance needed in the neutral is 4680
[250]2Hence, value of R =4680 x ------- = 0.9 Ω
[18000]2
This is the total resistance required, the total transformer winding resistance andgenerator winding resistance, expressed in terms of the secondary circuit, should be deducted toobtain the value of loading resistor.
Third harmonics present a problem and the relay design should take care of this.
90 to 95% of the stator can be covered by this protection.
It is better to grade the relays with the fuses of Generator line P.Ts.
If frequency dependent relays are used, the coverage at low frequencies during startingwill be reduced.
1.6 100% Earth fault protection:–
In cases of large machines of 200 M.W. and above, a 100 percent stator earth faultprotection is advisable. The reason for this kind of protection is due to the mechanical damagesresulting from the insulation fatique, creepage of the conductor bars and bolts coming loosenear the neutral point, vibrations of the conductors OR other fittings of the cooling systemswhich have been thought to have been responsible for the earth faults near the neural point.There are other forms of earth fault protections which work on the basis of artificialdisplacement of neutral point OR measuring third harmonic content in the generator voltage.Yet another dependable 100% earth fault protection scheme monitors the whole stator windingby means of a coded signal current continuously injected in the generator winding by acorresponding coupling transformer. This scheme provides protection in any mode of operation– standstill, running up OR down and normal operations covering 100% of the windingeffectively.
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CHAPTER-XI1.7 Phase Faults:–
Since the insulation in a slot between coils of different phases is atleast twice as large asthe insulation between one coil and the iron core, normally phase faults are rare. If occurs, largecurrents flow and enormous heat will be developed leading to fire some times. Modernmachines are normally equipped with cast-resin OR similar non-flammable insulating materialsand the use of CO2 is hence not required in such machines. Phase faults normally occur on theoverhanging end portion of stator coils. If they occur in a slots of two coils, the faults willinvolve earth in a very short time. If they occur in end portion, fault currents will not flow viathe core and the laminations will not be damaged. The repair work may therefore be limited toaffected coils.
Differential relay is the one used to protect against phase faults. It does not protect themachine against earth faults in the case of high resistance or distribution transformer or P.T.grounding of neutrals where the fault currents are limited and may not reach the pick up valueof differential relay. This relay will not protect turn to turn faults also, which will be dealt withlater.
Various kinds of the differential relays area) High impedance voltage differential relay:
The relays are connected between the phase and neutral leads of the paralleled CTs. Forexternal faults, the voltage across the relay will be low, as the current circulates between thetwo sets of CTs and no current flowing through the relay. For internal faults the fault currentsmust pass through each CTs exciting branch and the high-impedance, voltage relay, so that theCTs are saturated for most faults, producing high voltage to operate the relay. During periodswhen CTs are saturated by D.C. component of fault current, the AC input produces no furtherflux change and there is no output. Under these conditions, the inductance of the windingdisappears and the winding appears as a resistance equal to the copper resistance only.
It follows that it is the maximum voltage required to operate the relay rather than itscurrent setting which determines the stability level which will be attained with given CTs. It isseen that saturation of current transformers is permissible and correct reproduction of primarycurrent is unnecessary provided a satisfactory voltage setting is adopted for the relay.High-speed relay operation is achieved by the use of CTs with saturation voltages of not lessthan twice relay setting voltage.
b) Biased Schemes:
In this arrangement, the relay is fitted with two coils comprising one operating coil anda restraint coil carrying a current proportional to any current flowing through the protected zoneproducing a restraint on the relay.
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During through fault conditions, the relay receives a restraint not present in the case ofan unbiased relay and consequently proportionately more current can be permitted in theoperating coil without the risk of relay operation.
APPLICATION TECHNIQUE OF DIFFERENT RELAYS:
a) Identical current transformers shall be used at both ends to minimise mismatch.
b) It is preferable not to connect any other equipment in the differential circuit.
c) It can be seen from theoretical considerations that one of the largest factors affecting overallperformance is the C.T. lead burden. This should be kept at a minimum by keeping thecable route to the minimum, avoiding of two many terminal connections and links.Paralleling of CTs in the scheme can be done nearer to the switchgear if possible and onlythe leads of the operating circuit taken to relay panel.
d) The same neutral side CTs can be used for overall Generator transformers differentialprotection in case there are no constraints.
e) Pick up at as low as 2% and a slope of 10% with 4 cycles time are normally recommendedwith identical CTs in biased scheme. For higher rated machine, pick up at 1% with onecycle operating time are recommended.
1.8: Generator – Transformer Overall Differential Protection:
This is normally fed from CTs on the generator neutral side and on the H.V. side of theset-up transformers. Also, if a stepdown station service transformer is connected to thegenerator terminals this may be included in the overall protection by using CTs on the L.V. sideif unit size is small as the machine is tripped one way or another via governor oil low pressureon the loss of station transformer.
This relay must have a restraining feature which can prevent maloperation duringmagnetising in rush surges. There are opinions that harmonic restraint for these relays are onlyoptional as the voltage on the transformer is slowly built up. But, inrushes will also occur whena nearby fault occurs on an adjacent feeder. During the time of fault, the terminal voltage of thetransformer fault is practically zero and at the instant of feeder fault clearance, i.e. when the CBof the faulty feeder open, the transformer terminal voltage quickly rise causing severemagnetising inrush currents.
These relays should always have biased schemes.
Earth fault protection of the generator may cover the transformer primary.
Bigger transformers of 50 MVA and above, have REF protection also for high voltagewinding.
Detailed description of transformer protection mentioned under transformer protectionare applicable to generator transformer also.
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1.9: Interturn faults and Split-phase differential relay:
This protection senses turn to turn faults. It will also detect lamination failures as thereluctance is altered and the unbalanced current between windings increases. It may alsorespond to rotor shorts.
The generator differential protection described in the previous paras does not detectinter-turn faults. Even if there is an inter-turn fault in one phase winding, there will becirculating current inside the shorted turns path but the current at both ends of the phasewindings will be same and there will not be differential current.
There are several kinds of other inter turn protections which is not in the scope of thismanual.
1.10: ROTOR earth fault:
A single earth fault in the rotor is not very serious. Development of another fault isserious. Hence only alarm provision for this relay is generally provided.
The conductivity of the bearing oil film and the capacitance of the filed winding are themain aspects to be cared for. A grounded carbon brush can be provided to ride on the shaft tocombat the oil film resistance.
1.11: Some of the other protections are:
a) Loss of prime mover power:–
Reverse power relays are must for turbogenerators. In Francis hydro turbines, this relayis needed to avoid churning of water.
b) Pole slip protection:
Normally provided in bigger turbo generators for protection against out of stepoperation or pole slipping.c) Over-speed – Mechanical devices are more dependable.
d) Under voltage protection is normally used in induction generators.1.12: Loss of excitation:
When the excitation to a generator is lost suddenly, the flux does not immediately reduce tozero since the machine is a highly inductive one. The reduction of the flux causes the rotor tomove to a larger angle so that the machine can put out the turbine kilowatt input and at thesame time, the decreased flux causes a reduction in the VAR output till it reaches zero and thenincreases negatively. The terminal voltage drops rather slowly reaching a value of 70% in 5seconds.
Fig. 2 shows the results of a test done in a machine with the use of a digital computer in1954.
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The rotor moves further to a larger angle and the synchronous machine finally slips pastthe first pole, there is an abrupt acceleration of the rotor and power output decreases abruptly.Due to this acceleration, there is an oscillation in the real and reactive power flow. Increase inspeed makes the governor to lower the input of primemover. The machine approach the actionof an induction generation but it will never reach the condition same as the induction generatorbecause the quadrature and direct axes sub-transient and transient paths are different. If thesystem is large comparing with that of the machine, the system voltage will not decrease toomuch and the excitation can be restored to the machine in trouble. If the system voltage hasdecreased excessively, the machine must be tripped.
Continued operation of a generator without excitation will cause damage to the rotor,the end fingers of stator, stator winding, all by excessive heating. The pull out limits of othermachines also get reduced. Round rotors in generators without amortisseur windings get moreover heated.
A generator can run safely above synchronous speed with zero excitation for about 2 to3 minutes. In this time, the operator can detect a loss of field from panel meters and takecorrective action. But, it is preferable to have a protection.
Relays which operate at a specific value of field current do not give a full coveragethrough under current relays which are used in some places.
The most selective type of loss of excitation relay is a directional distance typeoperating from A.C. voltage and current at the main generator terminals. When excitation islost, the equivalent generator impedance traces a path from the first quadrant into a region ofthe fourth quadrant. By encompassing this region within the relay characteristic, the protectionis accomplished.
Impedance relay in combination with a directional element can be used. Offset MHOtype is largely used. Fig.3 shows the operating characteristic on a R-X diagram. The offset O.C.is approximately equal to half the direct axis transient reactance of the generator and O.D. isequal approximately to the direct axis synchronous reactance. The offset O.C. is necessary toprevent the operation of the relay for power swings.
Fig. 4 shows the terminal impedance locus. Ref: An article “Loss of field protectionfor generators” By Sri. K. Srinivasaraghavan, superintending Engineer and Sri. E.S. Narayanan,Assistant Engineer – published in TNEB Journal June 1960.
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PROTECTIONPROTECTIONPROTECTIONPROTECTION OFOFOFOF SYNCHRONOUSSYNCHRONOUSSYNCHRONOUSSYNCHRONOUS CONDENSERSCONDENSERSCONDENSERSCONDENSERS
These units usually operate as an unloaded motor to supply capacitive reactance to thesystem. Protection is similar to Generators. The loss of field excitation relay settings should beset with its operating circle to enclose an impedance seen at the terminals with zero excitation.
Operation to supply capacitive reactance will operate the distance unit, but tripping issupervised by the voltage unit. No protection exists for inductive reactance in to the system(over excited) as the directional – sensing unit is open and the distance unit may or may not beoperated.
Ref: Protective relaying byJ. Lewis Blackburn.
PROTECTIONPROTECTIONPROTECTIONPROTECTION OFOFOFOFMOTORS:MOTORS:MOTORS:MOTORS:
Motors must be protected against overload, unbalance supply voltage, electricalwinding faults bearing fail.
SMALLSMALLSMALLSMALL MOTORS:MOTORS:MOTORS:MOTORS:
Single phasing cannot be detected by a set of voltage relays connected across lines.Since, even when one supply phase is dead, the motor maintains substantial back emf on itsfaulted phase terminal to prevent dropping - off the voltage relay.
Comprehensive protection for overloading, single phasing and unbalanced supplyvoltage are available in one single relay of certain companies.
3.3:3.3:3.3:3.3: LARGELARGELARGELARGEMOTORS:MOTORS:MOTORS:MOTORS:
3.3.13.3.13.3.13.3.1BEARINGSBEARINGSBEARINGSBEARINGS
Practically there is not good protection for Ball/roller bearing failures. O/L relay,temperature relay, vibration detectors etc. cannot give foolproof protection.
Thermal detection devices work well with sleeve bearings.
OVERHEATINGOVERHEATINGOVERHEATINGOVERHEATING OFOFOFOFWINDINGS:WINDINGS:WINDINGS:WINDINGS:
A rough estimate shows that insulation life is halved for each 8°C rise in continousoperating temperature – Negative sequence currents produce as much as three times the heatingproduced by equal positive sequence current. Even 5% negative sequence voltage can produce30% negative sequence current.
Overload relays cannot detect single phasing since line current under a single-phasecondition is 87% of 3 phase stall condition. Negative sequence relays can easily detect singlephasing.
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- Relays should employ “Heat Sink” principle which can produce a thermal replica ofthe motor accurate thermal protection assumes increase importance.
- Split phase protection can detect inter turn faults.
- Phase faults protection can be by differential.
- Ground fault of winding can be protected by differential protection, ground fault relayresidually connected CTs or by core balance C.T.
OTHEROTHEROTHEROTHER PROTECTIONSPROTECTIONSPROTECTIONSPROTECTIONS BEINGBEINGBEINGBEING ININININ PRACTICEPRACTICEPRACTICEPRACTICE ARE:ARE:ARE:ARE:
- Protection against reverse rotation
- Pull out protection for synch motors
- Damper winding thermal protection
- Protection against sudden restoration of supply to avoid the possibility of the supplybeing restored out of phase with motor generated voltage.
- Under power and reverse power protection
- O/V and U/F protection
- Rotor winding protection.
Ref: 1. GEC measurements
2. Some notes on squirrel cage induction motor protection for abnormal conditions by Mr.J.R.S. WILKIE, English Electric, Canada.
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UNDERFREQUENCYUNDERFREQUENCYUNDERFREQUENCYUNDERFREQUENCYRELAYINGRELAYINGRELAYINGRELAYINGANDANDANDANDLOADLOADLOADLOADSHEDDINGSHEDDINGSHEDDINGSHEDDING
Er.K. MounagurusamyCE / P&C
- Load shedding is essential in emergencies to keep the system in tact.
- Effect of under frequency operation of system- Boiler outputs reduce due to reduction of draft fan speed.
- 10% reduction in speed of feed pumps reduces output by 30% and hencereduction of turbine generator output.
- Cooling effects of generators get reduced and hence affects the thermallimits.
- Stator voltage is proportional to speed of generator and hence MVARoutput decreases, desinged output is not feasible.
- 10% reduction in frequency reduces turbine capacity by 0.9%. Lowfrequency operation may result in vibration and probable resonance of lowpressure blades leading to blade fatique.
- Pull out torque of induction motors is inversely propertional to squre offrequency.
- 10% reduction in frequency will increase the operating time of protectionrelays by 10%
- Instrument errors increase
- Accuracy of energy meters adversely affected- Transformer core losses increase
- 10% reduction of frequency 10%reduction of KVAR output of capacitors.- reactive power consumption increases in ballest lamps- 10% of frequency reduction increases 16% of consumption of reactive
power in air conditioners and 63%in T.V.Sets.
POWERPOWERPOWERPOWER SYSTEMSYSTEMSYSTEMSYSTEM PROTECTIONPROTECTIONPROTECTIONPROTECTION DURINGDURINGDURINGDURING DECLININGDECLININGDECLININGDECLINING FREQUENCY:FREQUENCY:FREQUENCY:FREQUENCY:
When there is a sudden loss of generation due to any tripping of large generator,the system frequency immediately drops. If the tripped unit is compartively small, thesystem is not affected.
If the tripped generator or loss of generation power is large, effect is serious. Ifthere is sufficient reserve spinning governors take up the problem.
If there is not sufficient spinning power, the frequency will go down depending onhow much generation was lost and how much was system demand.
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If the frequency declines much, some other generators provided with underfrequency protection to protect their machine also trip and the effect is cummulative andthe system may go black out.
If some load shedding is done when the frequency declines sufficient to keep thefrequency in limits, the system will survive. This kind of load shedding is automaticallydone by the use of under frequency relays.
Soft ware package are available now-a-days to exactly arrive at the settings ofthese relays in stages and if properly set and put into effect without manipulations, thesystem stability will be well within the safety.
If the automatic load shedding is not effected properly, the stability of the systemwill certainly be under question.
Normally the under frequency tripping scheme control wrests with the localoperating people. If trip links are provided in this system, there are possibilities ofkeeping the trip link open due to the known reasons but the implications of such an actionwill now be understood clearly, it is hoped.
Ref: “Philosophy of under frequency relaying”Article by Er. R. Venkataraman,
Assistant Engineer,Office of the S.E/T/E.
Published in TNEB Engineers Association bulletin
U/FU/FU/FU/F SYSTEMSYSTEMSYSTEMSYSTEM PROTECTIONPROTECTIONPROTECTIONPROTECTION ININININ TNEBTNEBTNEBTNEB ASASASAS ONONONONAPRILAPRILAPRILAPRIL 2001200120012001
To get separated from Southern grid during disturbance the following inter-statefeeders are tripped with RPF and Under Frequency relay combination.
1) 400KVSriperumbudur – cuddapah will trip at 100MW (Export to cuddapah)when frequency is at 48 Hz with time delay of 0.5 sec.
2) 400KVSalem – Bangalore will trip at 300MW (Export to Bangalore) Whenfrequency is at 48Hz with time delay of 1.0 sec.
When these 400KV feeders get tripped the TNEB with Kerala systemgets separated from Andera Pradesh and Karnataka.
II If frequency is not improving due to Generation – Load mismatch, Loadrelease through Under frequency relays set at 47.8 Hz/Inst is obtained. Selected 110 KVfeeders would trip on Under Frequency relay to effect a load relief of about 650 MW.
III On further decline of frequency persisting sub – islanding schemes to getfollowing block – islanding will be effected.
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a)a)a)a) ETPSETPSETPSETPS (combined(combined(combined(combinedwithwithwithwithBBGTPS)BBGTPS)BBGTPS)BBGTPS) BlockBlockBlockBlock::::
Under this block two conditions viz.. with or without Generation inBBGTPS are envisaged. The feeder in this block would be tripped at47.6 Hz/ 0.75sec. When there is no Generation at BBGTPS additional relief of Padi SS &Sembium SS is added. Operator on duty at ETPS act depending on availability ofGeneration at ETPS to match the load in the block.
b)b)b)b) GMRGMRGMRGMRVasaviVasaviVasaviVasavi DieselDieselDieselDiesel GenerationGenerationGenerationGeneration PlantPlantPlantPlant BlockBlockBlockBlock::::
This block would get separated at 47.6 Hz/0.75 sec. In this block –islanding also, two conditions ie.. for 180 MW and 100 MW generation level atM/S GMR plant are envisaged. When Generation drops to 100 MW, additionallyat chindaripet would be tripped.
c)c)c)c) NCPTSNCPTSNCPTSNCPTS (Combined(Combined(Combined(Combinedwithwithwithwith TCPLTCPLTCPLTCPL Generation)Generation)Generation)Generation) BlockBlockBlockBlock::::
At 7.6 Hz/2 sec, the NCTPS (Plus TCPL) will go with base loadsaccording to Generation in two stages viz.. i) When generation at NCTPS is lessthan 450 MW with TCPL Generation. This block will have Korattur, Koyambedu,Kadaperi., Tharamani, Mosur loads according to the two conditions ofGeneration level.
House load operation of two units at 47.5 Hz/3 sec. Is restored. Also oneunit will go on H/L at 52 Hz/1 sec.
d)d)d)d) NeyveliNeyveliNeyveliNeyveli ThermalThermalThermalThermal PowerPowerPowerPower StationStationStationStation BlockBlockBlockBlock::::
(Generation 1700 MW load 664 MW). This islanding scheme operates at47.6 Hz/2 sec with Generation @ TS1 & TS2 and selective 110 KV & 230 KVfeeders of Cuddalore, Perambalur, Deviakurichi, Villupuram 230 KV, Villupuram110 KV and Eachengadu Substations for base load. All the 400 KV feeders atTS2 will be connected to under Frequency trip at 47.6 Hz/2 sec. The excessiveGeneration in this block will be reduced by running selected units on H/L. Thescheme will be supervised by Neyveli Authorities.
e)e)e)e) MetturMetturMetturMettur ThermalThermalThermalThermal PowerPowerPowerPower StationStationStationStationBlockBlockBlockBlock::::
(Generation 800 MW Load 612 MW) this block too gets islanded at47.6Hz/ 2 Sec. This block will have Salem, Mettur, Singarapet, Hosur,Thiruvannamalai and Erode loads as base loads.
House load operation is not possible for these units due to design problems.
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f)f)f)f) TTPSTTPSTTPSTTPS ––––HydroHydroHydroHydro BlockBlockBlockBlock ::::
This block gets islanded at 47.6 Hz/2 Sec. Under three conditions viz., i) 5machines availability @ TTPS plus Hydro area Generation ii) 4 machinesavailability @ TTPS plus Hydro area Generation iii) 3 machines availability @TTPS plus Hydro area Generation. Depending on load Generation study thefeeders that are tripped at 47.6 Hz/2 Sec. Separately for the above three conditionsare communicated.
Apart from this certain other feeders at 47.6 Hz/3 sec. Are tripped to offsetadditional load within the islanded zone.
Under Frequency relay on Aliyar Power House to automatically changethe machines from condenser mode to Generator mode at 47.6 Hz/0.5 sec. Isinstalled.
House load operation of machines 4 & 5 in TTPS is set at 47 Hz/5 secs.
iv) Since MAPS will go on H/L at 47.78 Hz at 4 sec. Itself separateislanding is not provided for these machines.
Kalpakkam units are connected for H/L. In stage I unit auxiliary loads of24 MVA will be transferred to Generator at 47.78 Hz/1 Sec. At 47.78 Hz/4 secthe unit will go on H/L.
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CHAPTER-XIIICHAPTER-XIIICHAPTER-XIIICHAPTER-XIIIPOWER-LINEPOWER-LINEPOWER-LINEPOWER-LINE CARRIERCARRIERCARRIERCARRIERCOMMUNICATIONCOMMUNICATIONCOMMUNICATIONCOMMUNICATION
Er. M. ArunachalamEE / GRT
INTRODUCTION:INTRODUCTION:INTRODUCTION:INTRODUCTION:
The Power Line Carrier Communication terminals are created and commissionedat various substations. The values for the required characteristic input and outputquantities for the system are to be followed as per 1) IEC Recommendation 495-1974 andas per Indian Standard IS 9482-1980. The tests on the terminals are to be done as per themethod indicated in Indian Standard IS 10706-1983 of latest versions.
Units and levels & Measurement methods:
The units are in Decifal, and terms used in the system are Attunation, compositloss and Return loss. The PLCC systems is functioning in the range of 30 KHE-500 withmaximum power lost in line. The receiving equipments has little effect on transmittingend the losses are expressed db-attenuationPower Line: Xdb = 10 log P1/P2Absolute power level Xdbm = 10 log P/1mw
Relative power level Xdbr = 10 log P/P ref.Voltage level Xdb = 20 log V1/V2
Current level Xdb = 20 long I1/I2(When the scalar ratios of currents or voltages are the square roots of the correspondingpower ratios.).1 Mw in 600 ohm
= 0.775V= 1.291ma.
COMPOSITCOMPOSITCOMPOSITCOMPOSIT LOSS:LOSS:LOSS:LOSS:
The input of stem having impedence Z is fed by a source with internal impedence Z1 ,the composit loss in Decibel is given by 10 times log 10 Ratio of power PO – meet thesource would give upto an impedence Z1, to the power P it sends through the system toits terminating impedence Z2.
Composit loss = 10 log10 P0/P dB.Insertion loss:
10 log10 P1/P2 dB.
Where P1 is the power available to the system without the insertion of a network.P2 is the power at the output with insertion of network.
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CHAPTER–XIIIMISMATCHMISMATCHMISMATCHMISMATCH LOSS:LOSS:LOSS:LOSS:
10 log P0/P dB
Number of decimals by which the power in the load in the matched conditions wouldexceed the power actually flowing in the load.
RETURNRETURNRETURNRETURN LOSS:LOSS:LOSS:LOSS:
10 log10 Po/Pr dB.
Number of decibels by which the power in the load in the matched condition wouldexceed the reflected (Return) power with connection to be actual load.
INTERINTERINTERINTER MODULATION:MODULATION:MODULATION:MODULATION:
In a non-linear Network to which two or more sinusoidal signals are appliedsimultaneously, a series of additional sinusoidal signal will arise, there are all Harmonicsand inter modulation produces of the applied signals.
Among the inter modulation produces of two signals = m1 t1 + m2t2, the oldorder products, the two 3 order products frequencies (2 f1+f2) and (2f2-f1) are harmful,being closes to f1+f2.
Measurement of Impedence.
V1/V2 = R+1x1/R ; V1/V2 = 10 P1-P2/201x1 = R. 10 P1-P2/20 – R
Ex: h = 0dB. P2 = -43.5 dBR = 1r1x1 = 10 43.5/20 = 150r.
Insulation level of Line Trap:
Residential voltage by nominal discharge0.5mH 31.5 5.4
Front-of-wave Impulse
Sparkover voltage of the arrester
P1 dB
V1
O
O
V
1 X 1P1 dB
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Peal : 26 KVInsulation levels of Tuning device and Line Trap.
Typical factory impulse voltage: 90 KV
Impulse Test voltage of L.T. 75 KVFront of wave impulse spark over voltage of arrester .. 62 KV
The performance of Line Trap can be assessed in terms of its EFFECTIVERESISTANCE.
Tappling loss of a line trap is a measure of the loss of power sustained by carrierfrequency signal due to the finite blocking ability of the line trap. It is defined in terms ofthe ratio of the signal voltages across an impedence equal to the characteristic impedenceof the line with and without shunt connection of the line trap. It is expressed in decibels(db). Rating of the Tapping Loss::
The value of the tapping loss as determined by the shunt connection of the resistancecomponent only of the line trap impedence. (Tapping loss based on blocking resistance).Tapping Loss::
Due to R+jx = 10 log (1+0.25+N)/N2+P2 db
Where N = R/Z & P = 1 x 1 /2.
Due to R only 20 log ( 1 + 1 /2N) db
Due to 1x1 only 10 log (1+0.25/P2) db
Band width of line trap
That frequency band V f1
Within which the blocking impedance does not fall short of a specified value.
OR
That frequency band V f2 within which the tapping loss does not exceed a specified value .
Rated band width:
Bandwidth expressed in terms of
Rated blocking impedance or rated tapping loss
V f1N or V f2N.
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V f1N Band width expressed in terms of rated blocking impedence.V f2N Carrier frequency band within which the ratedtapping loss does not exceed a specified value.
BLOCKINGBLOCKINGBLOCKINGBLOCKING REQUIREMENTS:REQUIREMENTS:REQUIREMENTS:REQUIREMENTS:
Permissible variation of the blocking impedence and tapping loss quantitiesshould be within the band width of the line trap.
A maximum loss of 2.6 db for both tapping loss and rated tapping loss thiscorresponds to Line trap blocking resistance 1-41 times the characterisitc impedence ofthe transmission line.
TYPICALTYPICALTYPICALTYPICAL CASE:CASE:CASE:CASE:
Line trap blocking resistance: 570 ohms.Transmission line characterestic impedence of a single conductor phase to earthimpedence – 400
TESTTESTTESTTEST ONONONONLINELINELINELINE TRAPS:TRAPS:TRAPS:TRAPS:
Type Tests
1) Measurement of inductance of the main civil.
2) Measurement of Temperature Rise
3) Insulation tests.
4) Short time current tests
Routine tests
Measurement of blocking impedence
Measurement of tapping loss.
Measurement blocking impedence
2b
By means of a bridge method from which Resistance and Resistive and Reactivecomponents may be read off.
Measurement circuit.Measurement of Tapping Loss(A7)
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2L I
V 0
At = 20 log (V1/V2) dB
Z are resistors equal to characteristic impedance of the line.
V1 = VO/2 V2 = V
Coupling capacitor of coupling Device coupling capacitor and compiling device from acarrier frequency filter for efficient and connection of CF currents to high voltage line.High frequency characteristic of coupling capacitor.
Equivalent series resistance 40 r
Stray capacitance of Low for CCvoltage terminal 200 pf and for CVT 300+0.05 Capacitance
Stray conductance of low 20 pvs for CCvoltage terminal 50 pvs for CVT
High frequency current – to with stand atleast 1A ( )
value of current equivalto a power of 400 w for a terminal resistance 4400 ohm.
ROUTINEROUTINEROUTINEROUTINE TESTS:TESTS:TESTS:TESTS:1. Capacitance at power frequency
a) in the standard tem. range for testing.b) at rated power frequencyc) at sufficient low voltage to ensure No internal breakdown.
2. Voltage testsa) Duration 1 min.b) Test voltage between high voltage and earth terminals.c) Low voltage terminal shall be earthed.
3. A.C. test voltageValue corresponding to insulation level.
4. D.C. test voltageValue twice the RMS value of the AC test voltage.
3
4
LT
2LG V
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5. Test between the low voltage and earth terminals.AC voltage of 10 KV RMs.
Duration 1 Minute
6. Capacitance and tangent of the loss angle after the voltage tests.
a) at Rated voltageb) at Rated frequency.
Measured capacitance shall not differ from the rated value bymore than – 5% + 10%
Tangent of the loss angle.
Limits of permissible variation subject to agreement.
The purpose of measurement is to check uniformity of production.
Typical value less than 0.5 x 10-3
Coupling Device :
Coupling Device is connected together with coupling capacitor The turning of thecoupling capacitor is to component of the coupling capacitor.
Impedence; in order to promote the efficient transmission of carrier frequentsignals.
Turing device:
It matches the impedence between the power line carrier frequency connection.
TRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER
Galvanic Isolation between primary and secondary terminals of the coupling device todrain to earth of the power frequency current devived by the coupling capacitor.
DRAINDRAINDRAINDRAIN COIL:COIL:COIL:COIL:
If limits the volt ge surges coming from the power line at the terminals of thecoupling device.
LIGHTINGLIGHTINGLIGHTINGLIGHTING ARRESTORS:ARRESTORS:ARRESTORS:ARRESTORS:
Direct and efficient earthing of the system when necessary of the primary terminals of thecoupling device.
Carrier freq. requirements.
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composite lost : not more than 2 dB
Return loss : preferably not less than 12dB
Nominal line 200-400 ohmside impedence phase to earth coupling
400-700 ohm phase-phase coupling
Nominal equipment 75 ohm (unbalance)sideimpedence 150 ohm (Balanced)
Destoration and Inter modulation Atleast 80 dB Below peak envelop power
INSULATIONINSULATIONINSULATIONINSULATION REQUIREMENTREQUIREMENTREQUIREMENTREQUIREMENT
Power freq. Level 5 Kvrms 1 min. isolation Transformers
Impulse level To with stand 1.2/50 impulse voltage 10 KV (peak)(Peak value equal to twice the value of the impulse sparkovervalue of the main Arrestor.
TESTSTESTSTESTSTESTS ONONONONCOUPLINGCOUPLINGCOUPLINGCOUPLING DEVICEDEVICEDEVICEDEVICE (ROUTINE/ACCEPTANCE)(ROUTINE/ACCEPTANCE)(ROUTINE/ACCEPTANCE)(ROUTINE/ACCEPTANCE)1. Composit loss2. Return loss3. Power Freq. voltage test
MEASUREMENTMEASUREMENTMEASUREMENTMEASUREMENTOFOFOFOF COMPOSITCOMPOSITCOMPOSITCOMPOSIT LOSS.LOSS.LOSS.LOSS.
Z2
21N V0V
CFGenerator.
Loss = 20 Log 10 V0/2v √2 ½ dB.
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MEASUREMENTMEASUREMENTMEASUREMENTMEASUREMENTRETURNRETURNRETURNRETURN LOSS.LOSS.LOSS.LOSS.
CF Generator
Return loss: 20 log (V1/V11) dBV1 is the voltage measured by the Web meter (V) with switch closed.
V11 is the voltage measured by the voltmeter (V) with switch
The line boide and equipment side return loss shall preperably he not less than 12dB.
In certain cases values less than 12 dB may require to be accepted.
DISTORTIONDISTORTIONDISTORTIONDISTORTION ANDANDANDAND INTERINTERINTERINTER MODULATIONMODULATIONMODULATIONMODULATION TESTTESTTESTTEST
Apply to the secondary terminals of the coupling device, two generator, set on twodifferent frequencies conveniently located within the available bandwidth of the couplingdevice, Measure across an impedence equal to the line side impedence connected to theprimary side by means of test capacitor, two signals are obtained, whose power is equalto one generator of the nominal peak envelop power. Power frequency test of Isolatingtransformers.
Power fre. voltage of 5 KVrms for one min.
CJ
Z1
22G V0
V
TC f Generator 21G GF1 F1
Select ive c freceiver
279
CHAPTER–XIIITESTTESTTESTTEST ONONONONDRAINDRAINDRAINDRAIN COIL:COIL:COIL:COIL:
Measurement of Impedence at power frequency.
Impedence at power frequency between the primary terminal and the earthterminal as low as possible and in no case in excess of 20 ohm.
The frequency bandwidth, within which the composite loss does not exceed andthe return loss does not fall short of the specified values.
For coupling devices ICE REC 495 (1974) mentions for line side and equipmentside Impedence. A return loss greater than 12 dB Referred to the normal values, butimpractice this figure may be difficult to achieve.
For PLC terminals IEC REC 495 (1974) specified a Return loss greater than 10dB referred to the nominal value of carrier frequency impedance.
C.F.C.F.C.F.C.F. CONNECTINGCONNECTINGCONNECTINGCONNECTING CABLE:CABLE:CABLE:CABLE:
150 ohm balanced
Electrical characteristicResistance Max 23.4 ohms
Insulation Resistance Min. 10,000 M. ohm/km
Test voltage 50 H 2 min.
wire-wire – 500 VRMS
wire-shiled – 4000 V RMS
Mutual capacitor – 31 n /km
Earthing at equipment end
Eliminates power freq. current circulation.
May cause high voltage across the wdgs of the coupling transformer which will need tobe designed for this duty. Maintenance personnel will need to take precaution against thepossibility of potential differences during faults, between cable screen and thelocal earth.
B) Coupling device ad carrier terminal not part of same earthmesh.
Earthing at earth potential differences may be high in the case of a fault and thecirculating currents in the screen may be dangerous.
Earthing at equipment end only the common practices to earth only the one side to thescreen at the carrier equipment end. By use of Balanced cables some of the aboveproblems can be avoided.
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APPLICATIONAPPLICATIONAPPLICATIONAPPLICATION OFOFOFOF PLCCPLCCPLCCPLCC SYSTEMSYSTEMSYSTEMSYSTEM
Analogue signals of frequency variation type.
SpeechSignalsTeleprotectionTelecontrolTeleprintingand Telefax.
As per IEC 495, IS 492, CC, TT Dissortion per 1 H droft in FSK Channel N 0.5 at 200Bd.
Possible utilisation 4KH
Speech 300-2400 H
Pilot 2400-2700 V
Signals - 2700 H – 3660 H
V.F. Band 0.3 - 3.7 KH
Speech 0.3 - 2.4 KH
Dial tF6 2.58 KH
Signals 2.76 – 37
IF Freq. 16.45 KH
IF Band 12.7 – 16.15 KH
As approved by a national Authority the carrier frequency range
40 KH – 500 KH
Basic carrier frequency Bandfor a single one way channel 2.5 KH, 4 KH
Nominal CF Band.
Band for a particulars one way PLCC channel.
e .g. 2.5, 2, 7.5, 10 kh4, 8, 12, 16 KH
Nominal Impedence 75 r unbalancedAt CF output 150 r balanced
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RETURNRETURNRETURNRETURN LOSSLOSSLOSSLOSS
10 dB R/2 = 1.925
Nominal C.F. Power is the permissible Emission power for which the equipment isdesigned comparable with the requirements for superiors emissions available at CFoutput acc resistance load equal to nominal load impedance. Mean CF Power averagedover a time sufficiently long compared with the cycle time of the lowest modulating freq.During which average power assures its highest value.
Ratio between PEP and manpower depends all factors in multiple signal. Speechlevel, with or without compressor. No type and level of signals, may be assumed to bebetween 8.5 & 10 ds. under normal service condition speech levels (Relatine)
Four wireTransmit ReceineeRange of 0.60-17 dBr. 3.5 to + 8 dBr.Suggestion-3.5 dBr – 3.5 dBr.
-14 dbr + 4 dbr
Two RecommendationTransmit 0 dbrReceive -7 dbr.
Balanced Normal Impedence 600 RReturn loss
Not less 14 db
Group delay distortion:Suggested limits300 – 3400 HZ CCITT M - 10 20300 – 2400 HZ
Group delay distortion of a pair of transmitting and Receiving PLC Terminus for dataTransmission where speech channel is used for data transmission.
For 300 –3400 HZ
Starts 500 HZ - 3ms600 HZ - 1.5ms
1000 HZ to 2600 HZ - 0.5ms2800 HZ - 3ms
For 300 – 2400 HZ500 HZ - 3ms600 HZ - 1.5ms
1000 to 1900 HZ –0.5ms2100 HZ - 3.0ms
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AUTOMATICAUTOMATICAUTOMATICAUTOMATIC GAINGAINGAINGAINCONTROLCONTROLCONTROLCONTROL ::::
For a variation of CF input signal level of 30 db, the U.F receive levelspeech/signalvaries of db.
LINEARITYLINEARITYLINEARITYLINEARITY ::::
As a function of UF input level over all loss of the speech circuts not differ bymore than + 0.3 dbr from overall loss at 0 dbmu.
For any input level between –10 dbm & 0 dbmu
Example 800 HZ- 3.5 dbm - -3.5 dbm )(- 5.5 dbm - -5.5 dbm )( ± 0.3db- 8.5 dBm - -8.5 dbm )(- 11.5 dBm - -11.5 dbm )( +0.3Db- 13.5 dBm - -13.5 dbm )(
Limiter action :-
Increase in VF signal level of +15 dBm. Increase in CF output level must be +3dBm.
Noise generated within the terminal weighted Telephone noise not be exceed 60dBm op.Noise generated within the terminals has limited significance, as underoperational conditions , the corona noise is dominant, in the order of –40 dBm opunder operational conditions a more realistic value is –55 dBm op.
CROSSCROSSCROSSCROSS TALK:TALK:TALK:TALK:
Due to signal channels, either individually or collectively the system shall notgive rise to a weighted disturbance power in the speech circuit of more than –60 dBm op.
Signalling input and output , the pulse distortion should exceed 5ms.
VOLTAGEVOLTAGEVOLTAGEVOLTAGE REQUIREMENTS:REQUIREMENTS:REQUIREMENTS:REQUIREMENTS:
Power supply : DC; 500V DC 1 mohm(both terminal connected together and earth )1000V 1.2 /5 pulse for terminal not isolated from earth.
AC 2000V ms power frequency 1 min both terminals connectedtogether and earth .
CF input and output terminals ; terminals isolated from earth, 2000V ms power frequency1 min. Both terminals connected together and earth Terminals not isolated from earth
3000N 1.2 /50 pulse
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V.F Signalling and AlarmFree from earth. 500V DC 1 min.
VFT channels its frequency and Tolerences :-
Channel NumberCCITT Recommendation R35 R37 R38 ANominal Modulation Rate 50 100 200 Bd.
Capacity of Homogenous 24 12 6VFT channels in a standardCarrier system with 4 KHZ spacing ;Lowest mean frequency 420 480 600 HZ
Higher mean frequency 3180 3120 3000 HZ
Permissible deviation from theFrequency at sending end ±2 ±3 ±4 HZ
Difference between two characteristicFrequency in the same channel 60 120 240 HZ
Maximum in PLC system :- ±3 ±4 ±6
Noise in PLC system :-Mainly caused by the power system operation..
Two main type of Noise : Substained white – moisse – like voltages (Random noise).Irregular discharges across insulators and conductors. (Carona and brush discharge)
Impulse type noise:-Shortsparks and bursts of high amplitude caused by,1. Operation of Isolators.2. Operation of breakers.3. Short circuits.4. Flash over5. Atmospheric discharges.Interference caused in PLC system due to HVDC system.
Other PLC system :
Sources external to power systemsMaritime Aeronautical systemBroad casting service.System operating in MF and IF bands.
Reuse of me PLC frequencies:
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Reuse at a geographically spaced distance which ensures a level difference of preferably60db between the useful signal and disturbing signal.
dB, dBm, dBu10 log p1/p2 dB20 log v1/v2 dB
Abritute Levels1mw = 0 dBmU = 0.7751 = 0 dBu
40 dBm 10W 600 ohm 77.5V + 40 dBu+40 dBm 10W 150 ohm 38.7V + 34.0+40 dBm 10W 75 ohm 27.4V + 31.0 dBu
Standard Limits for transmission quality of Data transmission. One of the most importantfactor affecting the data transmission quality is the distortion in time of the significantinstances (known as telegraph distortion).
The degree of signal distortion must be kept within certain limits, the ultimateobjective being that the degree of distortion on received signals should be complaiablewith the merging of the receiving equipment.
The distortion limits,
600 Bands – leased circuits - 20 - 30%1200 Bands – leased circuits - 25 - 35%
Degree of tolerable distortion (%)
Modulation rate 50 Bd 100 Bd 200 BdChannel spacing 120 HZ 240 HZ 480 HZ
Inherent inochronumdistortion with normalreception level 5 % 5 % 5%
Incase of slow level variationof +8.7 dB to 17.4 dB withrespect to normal receptionlevel 7% 7% 7%
Inpresence of interfrenceby a single wave freq.equal to either of twocharacteristics frequencieswith a end of 20 dB belowthe signal level of thetest channel. 12 12 10
With introduction of afrequency of thesignals. 5 5 5
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Distortion in a data channel causes Loss / Frequency distortion group delay distortion
Variation with time in over all lossRandom circuit NoisePhase filterSingle tone interferenceFrequency errorHarmonic DistortionText distortion due to white NoiseVFT FM 240 100 BdChannel level –17.5 dBmFor a Noise level of –24 dB.
For 50 Bd distortion is 12.5%100 Bd distortion is 20%
Text distortion due to frequency distortion.
48 HZ – 13.5%-8 HZ – 13.5%
Distortion in series connected VFT channel for 120 – 50 Bd.For 4 Nos. of Series connected VFT channel,For the normal level distortion will be 7%If the level is above normal, the distortion varies minimum for 4 Nos 8%Where as for a reception level below normal about 17.4 dB.4 Nos. of Series connectedVFT channels, distortion becomes 12%Distortion in FSK channel due to frequency change of 1 HZ
For 120 50 Bd 2.08 %240 100 Bd 1.04 %480 200 Bd 0.52 %600 600 Bd 0.31 %
Limits for maintenance of Telephone type circuits for Data transmission Telegraphdistortion limits.
Leased Switched300 Bd 20 – 25 20 – 25 %600 Bd 20 – 30 25 – 30 %
1200 Bd 25 – 35 30 – 35 %
Bit error rate (max) Leased Switched300 Bd 5 – 10-5 10-4600 Bd 5 - 10-5 10-3
1200 Bd 5 –10-5 10-3
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PERIODPERIODPERIODPERIOD OFOFOFOF MEASUREMENTMEASUREMENTMEASUREMENTMEASUREMENT ISISISIS 15151515MINMINMINMIN
Block Error Rate:
Example: Period of measurement = 15 minNo. of Bits transmitted = 1080000Length of sequence = 511 Bits.No. sequences transmitted = 2113.
Maximum Permissible line loss:Total loss planningValue as per IEC 5 dB.
Dielectric loss in capacitance, loss in coupling devices, loss in CF cable, loss incarrier sets operating in parallel. (0.5 – 1.0 dB (IEC)).
PEP = 1010 =40 dBm
Coupling loss at Max. Permissible Min.Permissible S/N NoiseOne line end line loss line loss Ratio level
Min. of 2 HZ132 KV 5 dB 43 dB - 8 dBm 25 - 33dBm
220 KV 5 dB 33 dB - 2 dB 25 - 23dBm
400 KV 5 dB 23 dB + 12 dB 25 - 13dB
Power alocation in a multi purpose PLCC system is determined by the followingproperties of the sub channels.
Noise band width.Required signal to Noise Ratio.Method of modulation.Assumption.
Sum of voltages of individual sub channels at carrier frequency is equal to the voltagescorresponding to the PEP. of the transmitter. The speech limits rise is 0 dB. For is usedfor all signal channels. operating range for all sub channels should be the same.
S/N ratio for speech 25 dBfor signalling channel 15 dB.
Noise power in a sub channel is proportional to its Noise Band Width.
Allocation of power in various sub channels of PLC terminals for speech plus signalswithout teleprotection.
Criteria: Power proportional to Noise band width in AM channels, (Speech andPilot) power in FM signalling channel 6 dB lower than in equal Band width AM
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channels.
Sub channel Noise Band Power Voltage Level relativeWidth HZ Ratio Ratio to speech
Speech 2100 2.5 10 0 dBnPilot dial 80 1 2 - 14 dBnFor 120 (50Bd) 80 ¼ 1 - 20 dBnFor 240 (100Bd) 160 2/4 1.5 - 17 dBnFor 480 (200Bd) 320 4/4 2 - 14 dBn
Calculation of Required Level In Speech Channel.
Level in speech+
Sum of all sub channel, equ. Channel mn= dBm (max) – 20 Log - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - -
Equ. channel No. for speech
dBu (max) = Voltage level corresponding to PEP of transmitted.
PLc terminal level: 10 WATT PEP40 dBm PEP34 dBm / 150 n
Example of calculationSub channel Eq. channel No.
Speech 10Pilot 2
-------12
-------Speech level = 34 – 20 log 12/10
= 32 – 4 dB/150 nLevel Pilot = -14 dBr to speech
= 18.4 dB/150 n
NOTE:
Channel No. Channel specimen Type of medulatorAmplifier Frequency
001 – 024 120151 – 165 170301 – 308 360
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Power Allocation:
Pr = PPEP – 20 log (nsi √Bsi/Br + √BZS/Br + √Brc/Br + √A.Bs/Br)Pr = Signal level of Reference Channel dBm.PPEP = Peak envelope power – dBm.B = Noise Band width CHz.Fs = Tel. Sig. Channel.Rl = Reduced carrier.A = 10 without compander.
1 with compander.R = Reference channel.
Example:PEP = + 40 dBm
Operation mod : Speech onlySuppressed carrier 300 – 2400 Hz.
Pr = 40 –20 log (√80/80 + √10 x 2100/80= 15 dBm
with reduced carrier
Pr = 40 – 20 log (√80/80 + √200/80 + √10 x 2100/80)= 14.52 dBm.
Example:
PEP = 40 dBmOperation mode : Speech + Data
300 to 2400 Hz1-Sub channel 200 Bd2-Sub channel 100 Bd earth
Suppressed Carrier.Pr = 40 – 20 log (√80/80 + √320/80 + 2 √160/80 + √10 x 2100/80)
= 13.14 dBmReduced carrier
Pr = 40–20 log (√80/80 + √320/80 + 2 √160/80 + √200/80 + √10x 2100/80)= 12.54 dBm
Line Alternation:
Several modes of carrier signal propagation take place simultaneously on a multiconductor line.
Main Characteristics of Natural Modes:Each mode has its own specified propagation loss, Velocity and characteristic
impedance.The modes are independent of each other. The phase voltage at any location is thesector sum of the phase mode voltages at that location, similarly the phase currentis the vector sum of the mode currents.
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NUMBERNUMBERNUMBERNUMBEROFOFOFOFMODES:MODES:MODES:MODES:
3 modes in the case of single circuit line with 2 earth wires grounded at eachtower.
7 modes in the case of double circuit line with one insulated earth wire.Coupling arrangements should be chosen that the above transmitting power of
lower loss mode.For practical coupling arrangements, such as phase to earth, phase to phase or
inter circuit coupling, the transmitting power is generally injected in the form of a modemixture, part of it much high loss (ground) ground mode, this resulting in a certain modelconversion loss.
Line Alternation line+ = L11 + 2 ac + aadd
aadd : Additional loss caused by discontinuities e.g., Couplingcircuit, transposition etc
L1 : alternation constent of lower loss mode
√f= 0.07 ---------- + 10.7 dB / pam
√dC n
f = Frequency in KHZde = Diameter of phase conductor (nm)
n = Number of phase conductor in bundle.Approx. + 10 % Upto 300 KHZ : + 20 % Upto 500 KHZ
Line Voltages above 150 KVEarth resiotivity around 100 – 300 rm.
Additional alternation due fault distance.
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HVHVHVHV ACACACAC TESTTESTTESTTESTBy R&D
SOMESOMESOMESOMEDETAILSDETAILSDETAILSDETAILS ONONONONDIELECTRICDIELECTRICDIELECTRICDIELECTRIC TESTS:-TESTS:-TESTS:-TESTS:-
The dielectrics break down due to several factors like increased voltageapplication, temperature, the age of dielectric materials, presence of moisture and othercontaminants.
When an arc is struck through an insulation, say of generator, it punches a pinholethrough the material. The result of the pinhole may not be felt immediately and an arcmay continue without causing damage for some time. Internal damages which take placein voids in the dielectric erode electrical insulating materials causing serious damage. Atsometime minor faults can cause a short circuit causing considerable damage and may beleading to major shut downs.
The following are some tests used for assessing insulation properties:
a) IR value measurement with meggers, P-I value tests (10 min to 1 minvalue)
b) Hipot tests (D.C and A.C):
RECOMMENDEDRECOMMENDEDRECOMMENDEDRECOMMENDEDTEXTTEXTTEXTTEXT VALUESVALUESVALUESVALUES ARE:ARE:ARE:ARE:
I.I.I.I. GENERATORS:GENERATORS:GENERATORS:GENERATORS: (1(1(1(1MIN.MIN.MIN.MIN. TESTS)TESTS)TESTS)TESTS)
a) A.C tests for new winding or coil - 2E + 1Subsequent test - 80% of first test.Old machines - 0.6 (2E + 1)
Where 0.6 is the derating factor.
b) D.C. testsA.C to D.C Conversion factor of 1.4 may be used.i.e 11 KV A.C = 11 x 1.4 KV D.C.
c) Example I: 11 KV Old m/c: A.C Hipot value = (2x11)+1x0.6 = 13.8KV
d) Example: 11 KV old Gen. D.C hipot testValue = (2x11)+1x0.6x1.4
=19 KV
e) Cables. (1 min)
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A.CA.CA.CA.C TESTS.TESTS.TESTS.TESTS.
New Cables – 2.5 x Uo Where Uo is the phase to neutral KV rating of cable.If the Cable is 11/6.35 KV
test value = 2.5 x 6.35If the cable is 11/11 KV (normally used in generators)
test value = 2.5 x 11 = 27.5 KV
D.CD.CD.CD.C TEST:-TEST:-TEST:-TEST:-
A.C to D.C conversion factor of 1.4 may be used. An abstract of CIGRE report28.8.1988 given below will be interesting to go through.
The necessity for such a A.C voltage test level is since the m/c phase to Neutralvoltage may reach (1.2 x 11 KV) When a m/c is separated from grid due to some validreason the m/c voltage may reach 1.2 times the ratio voltage. If an earth fault occur in onephase of cable the voltage in other phase of the Gen. may go to 11 KV to neutral in highimpedance earthed generators. The gen should withstand this value.
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C) Tan delta and Capacitance tests on generators
For a good insulation the Capacitance is almost constant at all voltages, but forinsulation containing voids, the capacitance value increases with increase in voltage dueto discharge in void. Tan delta test is a sensitive test for delection of moisture content,voids, crack and deterioration etc. Any steep value in the tan delta indicates someabnormal condition. Absolute values are not useful generally. Comparison with previoustest results help.
There is a correction between increase in loss tangent (tan delta) and capacitancewith voltage and the energy dissipated in discharging voids.
D) The other tests available are partial discharge test and 0.1 HZ test.
SCOPE:SCOPE:SCOPE:SCOPE:
This covers the high voltage AC test conducted on equipments at site to measurethe leakage current.
APPLICATION:APPLICATION:APPLICATION:APPLICATION:
This test is done on the stacks of 110 KV & 230 lightning Arresters, at ratedvoltage.
PERIODICITYPERIODICITYPERIODICITYPERIODICITY:
The test is done at the time of commissioning, thereafter yearly.
TESTTESTTESTTEST PROCEDURE:PROCEDURE:PROCEDURE:PROCEDURE:
TESTTESTTESTTEST CIRCUIT:CIRCUIT:CIRCUIT:CIRCUIT:
VA
L
NVariacce
Voltmeter
HV TestingTransformer
SpecimenUnder test
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Test equipments
HV Testing Transformer 220V/60 KV, 600 VA
Ammeter 0-10 mA with resolution of 0.1 mA
Voltmeter 0-250 V AC
Variac 230 V/0-260, 5A.
The Lightning Arrester to be tested is completely isolated both from supply end
and from ground.
The connections are given as shown in the circuit diagram. The voltage is appliedgradually on the LA under test using the variac, keeping an eye on the ammeter &voltmeter readings. The leakage current readings are noted at say 30%, 60% & 100% ofthe MCOV rating of the Arrestor. Care should be taken not to exceed the MCOV. TheVoltage should be reduced as soon as MCOV is reached. Normally the test is done oneach stack separately.
Precautions:
The IR value of the LA is to be tested before conducting the HV AC test.
While testing individual stacks of a LA, it should be ensured that the stack is notkept on the ground while testing.
The test voltage should not exceed the MCOV values for any stack. The HV leadsfrom the HV testing Transformer should not be very close to conducting surfaces andadequate clearance shall be maintained.
Significance of the Test:
A surge arrestor normally acts as an insulator to normal system conditions, hencethis insulation property is, as in any insulation system, subject to certain deterioration.
Hence a power frequency leakage current test at the rated voltage of the Arrestoris a practical field test to determine the condition of arrestors in service.
Results and Analysis:
The leakage current values have to be interpreted on a comparative basis,emphasis is on variation from earlier recorded values than on absolute values. However alimit value of 3 mA is taken as a criteria. Also, the leakage current value at rated voltageshould not exceed the minimum level recommended by the supplier. The readings are tobe used more as trend analysis for detecting deterioration/degradation in the Arrestercomponents.
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Reference:
TNEB Code of Technical Institution/1990.
HV DC Test:
Scope:
This covers the high voltage DC test conducted on equipment at site to check thevoltage withstand capability and the leakage current.
Application:
The test is done on equipments, in which HV AC test cannot be effectively donedue to high capacitance and consequent power requirement of the testing apparatus.
Typical applications include test on Generator Stator Coils, H.T. motors, Cables,Busbars etc.
Periodicity:
Normally the test is done after overhaul, recommissioning as per field
requirements.
Test Procedure:
Test Circuit:
HV TestingTransformer
HVDiode To
Speciment
Variacce
A
L
N
R
C
Ammeter
Diode
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CHAPTER–XIVTest equipments:
HV Testing Transformer - 220 V/60 KV, 600 VA
Diodes - HV Rectifier Diodes
Ammeter - 1 mA – 10 mA Range
Variac - 1 phase, 5A
If the test specimen is a HT motor, the 3 phases of the stator winding terminals
may be shorted together and the High Voltage lead should be connected to it. If test can
be done on separate phases, the same may also be done. The HVDC is to be applied
gradually, preventing any overshoot of the ammeter. The leakage current may be
measured at the rated voltage after about one minute.
In the case of cables, while conducting the test on one phase, the other two phases
in a 3 core cable should be earthed.
Precaution:
The HV DC test must be done only after conducting the IR value test (with a 5
KV megger) and only if the IR value is found satisfactory.
As the capacitance of the specimen, would be normally high especially in the case
of cables, proper care should be taken to sufficiently discharge the specimen after the test.
Results and Analysis:
The normal leakage current values would be in the range of 0.05mA - 0.5mA.
Dissolved Gas Analysis test:
Scope:
This covers DGA test of Transformer oil samples using Gas chromatography
technique to detect and quantify dissolved gases in the oil.
Application:
The test is applied in case of HV Transformers mainly to detect incipient faults that maydevelop inside the Transformers and generally to diagnose the condition of theTransformers in service and to suggest future action.
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Description:
The Transformer in service is subject to electrical & thermal stresses resulting inliberation of gases from the hydrocarbon mineral oil used in the Transformers. Cellulose(paper insulation) also is involved in the formation of gases, which are dissolved in theoil. Gases may be formed, due to natural aging and also as a result of faults. Basically,the mechanism of gas formation in oil includes oxidation, vapourisation, insulationdecomposition, oil breakdown etc. An assessment of these gases, that are dissolved in theoil, would help in diagnosing the internal condition of the Transformer. Operation with afault may seriously damage the equipment and it is useful to detect the fault at a veryearly stage of development.
In the case of fault, its type & severity may be inferred from the composition ofthe gases and the rate of gas formation. In the case of incipient faults, the gases formedare partly dissolved in the oil, hence periodic analysis of oil samples for the amount andcomposition of dissolved gases forms a means of detecting faults.
DGA involves the following steps:
(a) Sampling of oil
(b) Extraction of gases from the oil
(c) Analysis of the extracted gases using gas chromatograph.
(d) Calculation of concentration of gases in PPM.
(e) Interpretation of results.
Periodicity:
The DGA is done on all power/auto transformer of 110KV class & above on
yearly basis and on special occasions warranted by service conditions. In the case of new
Transformers the test is recommended one month after commissioning and thereafter
yearly. A DGA test one month before expiry of the guarantee period of the Transformer
is also recommended.
TESTTESTTESTTEST PROCEDURE:PROCEDURE:PROCEDURE:PROCEDURE:
Equipment used:
(a) The Gas extraction plant consisting of magnetic stirrer, vacuum pump, mercury
reservior, degassing system.
(b) Gas Chromotograph.
(c) Output unit namely Integrator and PC
The Gas – Chromatographic system consists of a carrier gas stream supplied by agas cylinder, a sample inlet /injection port, a chromatographic column, detectors, and anoutput recorder.
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The carrier Gas Nitrogen obtained from cylinder is passed through flow regulatorto the column. The carrier gas passes through the sample inlet system where it picks upthe sample to be analysed. The carrier gas sweeps the sample being injected into itsstream and enters into the column where the separation takes place.
Absorption columns are used for the separation of gaseous mixtures. Molecularsieves Poropak Q type absorbents are used to separate CO, CO2, H2 gases. Silica gel typeabsorbents are used to separate hydrocarbon gases.
Detectors (Flame Ionisation and Thermal conductivity detectors) are used indetecting the Gases and works on the principle of thermal conductivity (TCD) of thegases and the electrical conductivity of gases which have been partially ionised The FIDis used for hydrocarbons and the TCD for atmospheric gases like CO, CO2, & Hydrogen.
The Gas extraction plant is first evacuated with the help of the rotary vacuumpump. When sufficient vacuum is achieved, oil is let into the degassing vessel and stirredtill complete degassing is achieved. Using the mercury column, the evolved gases arecompressed to the known volume.
The Gases are drawn by means of airtight syringes and injected into the GasChromatograph, after the Gas Chromatograph is properly set up with carrier Gas etc. Thedetection and quantification of gases take place in the Chromatograph. TheChromatograph is calibrated by means of a standard gas mixture containing a suitableknown amount of each of the gas components to be analysed to establish the calibrationcurve and retention time. An Integrator connected to the output of the Chromatographgives the proportional area in units for different gases. The method of calibration involvesmeasuring the area of each peak and retention time, identifying the gases correspondingto each peak by comparison with the chromatogram obtained by calibration & obtainingthe gas values in PPM. The PPM values of the gases are calculated by comparing withstandard gas values and the quantity of dissolved gases in PPM is than calculated for eachgas.
Precaution:
The samples must be collected, labeled, stored, Transported and tested withproper sampling, storing and testing procedures to obtain accurate results.Analysis & Interpretation:
There are several methods for interpreting the results of the DGA test. Firstly acheck is made by comparing the concentration levels with levels that are permissible in ahealthy Transformer depending upon the service age of the Transformer. Thesepermissible concentration levels for gases are tabulated, for reference.
Then, in case of higher gas levels, than the permissible levels, or in cases wheregas levels show abnormal increasing trend from previous recorded values, the Roger’smethod of diagnosis or the 3 ratio method prescribed in IS 10593 may be used forinterpretation.
Reference:IS 1866, IS 9434, IS 10593, CPRI Publications.
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LIMITINGLIMITINGLIMITINGLIMITING VALUESVALUESVALUESVALUESISISISIS 1866186618661866 –––– 1983198319831983
------------------------------------------------------------------------------------------------------------TEST EQU. VOLTAGE METHOD LIMIT------------------------------------------------------------------------------------------------------------ELECTRIC STRENGTH, Min ≥ 145 KV IS : 6792 50KV < 145≥ 72.5 KV 40
< 72.5 KV 30
WATER CONTENT ≥ 145 KV IS : 335 25PPM, Max < 145 KV 35
SPECIFIC RESISTANCE ALL V IS : 6103 0.1@ 90, 10 E 12 Ohm-Cm Min
TAN DELTA ≥ 145 KV IS : 6262 0.2@ 90, Max < 145 KV 1.0
ACIDITY ALL V IS : 1448 0.5Mg KOH/g, Max
I F T, N/m, Min ALL V IS : 6104 0.015
FLASH POINT Min ALL V IS : 1448 125 orDeg C, Min Max. decrease of 15
SEDIMENT AND/OR ALL V IS 1866 NILPRECIPITABLE SLUDGE
PERMISSIBLE GAS CONCENTRATIONSSSS
GAS <4 YEARS 4-10 YEARS >10 YEARS1 HYDROGEN 100/150 200/300 200/3002 METHANE 50/70 100/150 200/3003 ACETYLENE 20/30 30/50 200/1504 ETHYLENE 100/150 150/200 200/4005 ETHANE 30/50 100/150 800/10006 CARBON MONOXIDE 200/300 400/500 600/7007 CARBON DI OXIDE 3000/3500 4000/5000 9000/12000
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Furan Analysis Test:Introduction:
Paper is the major solid insulant in Transformers. While there are a number oftests to monitor the condition of the oil in the Transformer, till recently there was nopractical technique available for condition assessment of the solid insulation in theTransformers.
A new testing method has emerged in which condition of solid insulation isassessed by analysing the degradation of products of cellulose paper called furaniccompounds using High Performance Liquid Chromatography (HPLC) or any othersuitable equipment.
Application:The test is specially applicable to Transformers that have put in more than 10
years of service life and also in cases where the involvement of cellulose is suspected infaults that have been detected irrespective of service age of Transformers.
Furan compounds:Furanic compounds commonly referred to as furans, are products of degradation of
cellulosic materials and are dissolved in the oil. The furanic compounds that are detected.quantified and analysed are2 – Furfural dehyde5 – Hydroxy methyl – 2 furfural2 – Acetyl furan5 – Methyl – 2 – furfural2 – Furfural alcoholof these 2 – furfural dehyde is found to be the most commonly monitored furancompound.
Periodicity:The periodicity for this has not been established but it is suggested that a
reference test value for all Transformer in the 10th year of service and yearly testing fromthe 15th year onwards may be adopted presently.Test Procedure:
Equipments:Equipments such as High Performance Liquid Chromatograph, visible rangespectrometer are used in Furan Analysis. However the HPLC is the standard equipmentused.
Method:(a) Furanic compounds in the oil samples are extracted from a known volume
of test specimen.
(b) A portion of the extract is introduced into an HPLC system equipped witha suitable analytical column & UV detector.
(c) Furanic Compounds in the test specimen are identified and quantified bycomparison to standards of known concentration.
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Result and Analysis:
The furan compounds are analysed on a trend basis. The concentration levels arecompared with previous values and the assessment of solid insulation as healthy, initialstage of degradation, failure levels etc are made and appropriate action taken.
Reference
IEC 1198/1993ASTM D 5837-95CPRI Publications.
Transformer oil tests:
(a) Electric Strength (BDV)
Scope:
This covers test on oil samples of Transformers, which are inservice and useuninhibited insulation oils and complying with the requirements of IS 335 when fillednew.
Definition:
The voltage at which the oil breaks down when subjected to an ac electric fieldwith a continuously increasing voltage contained in a specified apparatus. The voltage isexpressed in KV.
Application:
The test is applicable to Transformers of any rating and switch gears.
Periodicity:
The test is done on an annual basis along with all other oil characteristic tests andmore frequently if condition of the oil/equipment warrants. However the BDV of oilsamples from Transformer of all voltage class & from OLTC shall be tested on aquarterly periodicity, separately with locally available test kits.
Test procedure:
The test is done with a test cell, made by glass or plastic, which shall betransparent and non-absorbent, with an effective volume of 300 to 500 ml and preferablya closed one. The electrodes are mounted on a horizontal axis and shall be 2.5 mm apart.
The test procedure is begun by adjusting the sphere gap of the electrodesaccurately by the use of 2.5 mm gauge (supplied with the kit).
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Initially some of the oil from the sampling container is poured out to clean the tipof the sample container. The test cell shall be cleaned by rinsing with the test oil twicebefore filling the test oil for the test. The oil, then, should be poured gradually, avoidingformation of air bubbles.
The oil is filled to a height of 40 mm from the axis of electrodes. The test cellwith oil is then placed in the testing unit. A period of 5 minutes is allowed for the oil tosettle. Then voltage is applied at the rate of rise of 2 KV/second. The voltage is thusincreased to a value where the oil breaks down and the corresponding voltage is noted.The test is carried out six times on the same oil sample filling with intervals of 2 minutes.The Arithmetic mean value of the six readings is taken as the BDV of the oil sample.
Precaution:
The sample must not be exposed to atmosphere and should be as near to the actualoil in the Transformer as possible, in all aspects..
The sample container may be shaken upside down to get a homogenous samplefor test.
The container electrodes etc may be rinsed thoroughly with test sample, prior tothe commencement of the test.
Results and Analysis:
The test values are interpreted as per IS 335 for new oil and as per IS 1866 for oilin service.
For oil in service the limit values are as follows:
Equipment voltage Limit (Minimum)
145 KV and above 50 KVBetween 72.5 KV and 145 KV 40 KVLess than 72.5 KVA 30 KV
Reference:
IS 335, IS 1866, IS 6792
(b) Flash Point:
Scope:
This covers test on oil samples of Transformers, which are inservice and useuninhibited insulating oils and complying with the requirements of IS 335 when fillednew.
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CHAPTER–XIVDefinition:
It is the temperature at which the oil gives off so much vapour that this vapour,when mixed with air, forms an ignitable mixture and gives a momentary flash onapplication of a small pilot flame under the prescribed conditions.
Application:
The test is applicable to Transformer of all ratings.
Periodicity:
The test is done on an annual basis along with all other oil characteristic tests andmore frequently if condition of the oil/equipment warrants.
Test procedure:
The test equipments used are pensky-martin closed cup apparatus, thermometersand variac.
The cup is cleaned well by rinsing twice with the test oil. Oil is filled upto themarking provided and is placed in the test apparatus. The oil is heated and from about100’C onwards, a small pilot flame is used to ignite the mixture and the temperature atwhich this mixture gets ignited is noted and recorded as the Flash-Point.
Results and Analysis:
Minimum limit is 125’C or maximum decrease of 15’C for all voltage class.
Reference:
IS 335. IS 1866, IS 1448
(c) Neutralisation Value (Acidity)
Scope:
This covers test on oil samples of Transformers, which are inservice and useuninhibited insulating oils and complying with the requirements of IS 335 when fillednew.
Definition:
It is the measure of free organic and inorganic acids present in the oil. It isexpressed in terms of the number of milligrams of potassium hydroxide required toneutralize the total free acids in one gram of the oil
Application:
The test is applicable to Transformers of all rating.
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Periodicity:
The test is done on an annual basis along with all other oil characteristic tests andmore frequently if condition of the oil/equipment warrants.
Test Procedure:
The materials used for the test are indicator bottle containing universal indicatorwith PH value of 4 & 11, clean, dry glass test tubes and a color chart calibrated withneutralisation number values.
The test procedure is, 1.1 ml. of sampling oil to be tested is accurately pipettedinto a clean dry test tube. To this 1 ml of Isoprophyl, alcohol. 1.0 ml of 0.0085 N SodiumCarbonate solution are added. Then, to this five drops of the universal indicator are addedand gently shaked.
0.0085 N of Sodium Carbonate solution is prepared by dissolving 0.085 N ofSodium Carbonate in 10ml of distilled water to get 0.0085 N of sodium carbonatesolution.
The resulting mixture develops a color depending on the PH value of the mixture.This color is compared with the standard chart, which gives the approximateneutralisation value ranging from 0 to 1.0.
Results and Analysis:
Maximum limit for all voltage clause is 0.5.
Reference:
IS 335, IS 1866,
(d) Specific Resistance (Resistivity)
Scope:
This covers test on oil samples of Transformers, which are in service and useuninhibited insulating oils and complying with the requirements of IS 335 when fillednew.
Definition:
It is the ratio of the dc potential gradient in volts per centimeter paralleling thecurrent flow within the specimens to the current density in amperes per squarecentimeters at a given instant of time and under prescribed conditions. This isnumerically equal to the resistance between opposite faces of a centimeter cube of theliquid. It is expressed in Ohm-centimeter.
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Application:
The test is applicable to Transformers of all ratings.
Periodicity:
The test is done on an annual basis along with all other oil characteristic tests andmore frequently if condition of the oil/equipment warrants.
Test procedure
The equipments needed for the test are million megohm meter, oil cell, oil cell heater.
The oil is heated upto 90’C and 500 V d.c. applied, and after one minute themegohm indicated is noted and the Resistivity value is calculated with appropriatemultiplication factors and cell constant.
Results & Analysis
Minimum limit is 0.1x10^12 Ohm-cm at 90’C for all voltages.
Reference:
IS 335, IS 1866, IS 6103.
(e) Dielectric Dissipation Factor (Tan delta)
Scope:
This covers test on oil samples of Transformers, which are in service and useuninhibited insulating oils and complying with the requirements of IS 335 when fillednew.
Definition:
It is the Tangent of the angle (delta) by which the phase difference betweenapplied voltage and resulting current deviates from 1/2 radian when the dielectric of thecapacitor consists exclusively of the insulating oil.
Application:
The test is applicable to Transformers of all ratings.
Periodicity:
The test is done on an annual basis along with all other oil characteristic tests andmore frequently if condition of the oil/equipment warrants.
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Test procedure:
The equipments required are Dielectric constant test kit, oil cell, oil cell heater.
The oil cell is thoroughly rinsed with the sample oil to be tested and about 35 mlof oil is taken in the cell and heated to 90'C. Then 500V AC is applied to the terminals ofthe oil cell. The Tan delta bridge is balanced by adjusting the potentiometers to get nulldeflection. The Tan delta value obtained is recorded.
Results & Analysis:
The maximum limit for Tan delta at 90'C is 0.2 for voltages of 145 Kv & aboveand 1.0 for voltages below 145 KV.
Reference:
IS 335, IS 1866, IS 6262.
(f) Interfacial Tension:
Scope:
This covers test on oil samples of Transformers, which are in service and useuninhibited insulating oils and complying with the requirements of IS 335 when fillednew.
Definition:
It is the force necessary to detach a planar ring of platinum wire from the surfaceof the liquid of higher surface tension that is upward from the water-oil surface. It isexpressed in dynes/cm. or N/m.
Application:
The test is applicable to Transformers of all ratings.
Periodicity:
The test is done on an annual basis along with all other oil characteristic tests andmore frequently if condition of the oil/equipment warrants.
Test procedure:
The apparatus required are tensiometer, fine platinum ring, glass beakers.
Before starting the test, all glass beakers are cleaned with isoprophyl alcohol andacetone. The platinum ring is also cleaned with isoprophyl alcohol & acetone. Thetensiometer is placed in a horizontal plane.
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About 20-25 ml. of distilled water is taken in the sample container and is placedon the adjustable platform of the tensiometer. The platinum ring is suspended from thetensiometer. The adjusting platform is raised till the platinum ring is immersed in thewater to a depth not exceeding 6 mm and at the centre of the glass beaker.
Now gradually, the platform is lowered, increasing the torque of the ring systemby maintaining the tension arm in the zero position. As the film of water adhering to thering approaches the breaking point, slow adjustment is made to ensure that the movingsystem is in the zero position when rupture occurs. The surface tension of the water isnoted. The value is normally 71 to 72 dynes/cm.
Now the tensiometer scale is brought to zero and the adjustable platform is raiseduntil the ring is immersed to a depth of about 5 mm in the distilled water. The sample oilto be tested is poured slowly along the walls of the beaker over the distilled water. Theplatform is slowly lowered, increasing the tension of the ring system. The IFT is the scalereading at which the ring breaks free from the interface.
Results & Analysis:
The minimum limit for all voltage is 15 dynes/cm.
Reference:
IS 335, IS 1866, IS 6104
(q) Water Content:
Scope:
This covers test on oil samples of Transformers, which are in service and useuninhibited insulating oils and complying with the requirements of IS 335 when fillednew.
Description:
This test is for the determination of water content usually in the range of 0-75ppm in the oil.
The Karl-fisher method is used. The method is based on the reaction of water withIodine and Sulphur-di-oxide in Pyridine/methonol solution.
Application:
The test is applicable to Transformers of all ratings.
Periodicity:
The test is done on an annual basis along with all other oil characteristic tests andmore frequently if condition of the oil/equipment warrants.
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Test Procedure:
The materials required for the test are methanol with less than 0.02% watercontent, Karl-fisher Reagent, Titration vessel.
The titration vessel is made moisture free.The Karl fisher Reagent and the methanol are taken in the two sides of the burette
to levels. A certain quantity of methanol is allowed in the test vessel. The pointer willshow end point as water. The electro magnetic stirrer should rotate at a speed of 150-300rpm. Karl Fisher Reagent is allowed into the vessel to neutralise the water. When all thewater is separted, the pointer will show Karl Fisher Reagent-O'. A known quantity ofwater say 20µl is introduced with a syringe. The pointer will once again show waterindication. Steadily and gradually the Karl Fischer Reagent is added continuously so as tobring the pointer to Karl Fisher 'O' position. The initial and final readings are noted. Thedifference is the volume of Karl fisher required to neutralise 20µl of water. The sameprocedure is repeated with sample oil and the water content present in the oil is calculatedusing the formula (20 X K.F. required to neutralise the Oil X 103 ) / ( 25 X 0.88 X K.F.required to neutralise water).
Results & Analysis:
The minimum limit for Transformers of voltage class 145 KV & above is 25 PPMand for voltages below 145 KV is 35 ppm.
Reference:
IS 335, IS 1866, IS 2362
(h) Sludge Test:
Scope:
This covers test on oil samples of Transformers, which are in service and useuninhibited insulating oils and complying with the requirements of IS 335 when fillednew.
Description:
This test is conducted to determine the presence of sediments and perceptiblesludge in the oil.
Application:
The test is applicable to Transformers of all ratings.
Periodicity:
The sludge test is carried out when the IFT value of oil is very low say below 13Dynes / cm.
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CHAPTER–XIVTest procedure:
11 ml of the test sample oil is pipetted in a clean conical flask. 100 ml. of Hexaneor N-heptane is added to this oil. The mixture is shaken well and is kept in a dark placefor 24 hours. At the end of 24 hour, it is checked for any precipitation in the oil. If anyprecipitation is observed, the sample oil contains sludge.
Results & Analysis:
For all voltage class sludge should be NIL.
Reference:
IS 335, IS 1866.
Note:
All Indian standards referred versions are the latest versions revised/amendedfrom time to time.
TestTestTestTest procedureprocedureprocedureprocedure forforforformeasurementmeasurementmeasurementmeasurement ofofofof TanTanTanTan deltadeltadeltadeltaandandandand CapacitanceCapacitanceCapacitanceCapacitance ofofofof equipments.equipments.equipments.equipments.
1. Scope: This covers the method of measuring the dielectric loss properties of theinsulation system of equipments by measuring the Tan delta and Capacitance values.
2. Definition: Tan delta is the tangent of the dielectric loss angle of an insulationsystem. It is also referred to as dissipation factor or dielectric loss factor.
3. Significance of Tan delta value in insulation systems:
In an insulation system, the dielectric loss is given by V2 WC tan delta watts. Ifthe dielectric power loss is more, the dielectric strength of the insulation would bereduced. The Tan delta is affected by moisture, voids and ionization in the Insulation.Hence it is indicative of the quality of insulation.
4. Principle of Tan delta and Capacitance measurement for HV equipments.
4.1 The High Voltage electrical equipments have conductors HV and LV separated byan insulating medium. It can also be a conductor or winding with an HT terminal and theLV terminal connected to ground. These systems can be represented as two and threeterminal capacitors. An example of a two terminal capacitor is the bushing of anequipment. The central conductor is one terminal and the mounting flange (ground) is theother terminal. An example for a three terminal capacitor is a bushing with a Tan deltatest tap. In this case the central conductor is one terminal, the test tap is the secondterminal and the mounting flange is the third terminal. Likewise most of the HVequipments can be visualised as capacitors with simple and complex insulation systemsand these can be measured with a test set that can measure both grounded andungrounded specimens.
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In the ideal case, the capacitance current leads the voltage by 90'. But in practice,in all insulation systems, there exists a loss current Ir which is small in magnitude but inphase with the voltage, as shown above. The total current I, therefore leads the voltage byan angle which is less than 90°. The angle by which it is less than 90° is known as theloss angle delta and in all practical cases, the magnitude of Ic and I are same as Ir is verysmall and the power factor and dissipation factor tend to be the same.
In the above diagram Dissipation factor = tan delta; As the importantcharacteristic of a capacitor is its dissipation factor, it is measured and monitored as adiagnostic test of insulation systems.
5. Application:
The test is conducted on the following:
(1) Power and Auto Transformer Bushings(2) Power and Auto Transformer Windings(3) Generator stator coils(4) Current and Potential Transformers.(5) CVTs(6) Any other HV equipment where insulating condition is to be tested.
6. Periodicity:
The test is done at the time of commissioning and thereafter yearly and on actualrequirement depending on the conditions of the equipment.
4.2 The Vector Relationship:
Q
S
IC
VIr
I
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Test procedure:
There are two basic versions of testing (i.e.) Grounded specimen test andungrounded specimen test. The circuit diagram are shown below:
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The circuit connections are given as shown above depending on whet her thespecimen is grounded or floating. The Input voltage is raised gradually through a variactill the desired HV Voltage is reached for the specimen. The bridge circuit consists of adifferential transformer, R-C network, known standard capacitor (Cn) and the unknownspecimen (Cx) under test. The same HV voltage is applied to both the known andspecimen capacitors. The currents through the two capacitors pass through the differentialTransformer, which is balanced by means of adjustment of the bridge capacitors, whichare provided with multiplication selectors. Once the bridge is balanced for thecapacitance value the capacitance selected is read directly from the multipliers. The tandelta is then adjusted to get the balanced horizontal position in the Oscilloscope. Thevalue of Tan delta is also directly read from the bridge Tan delta selector with appropriatedecimals.
Precautions:
(1) It is always preferable to conduct the Tan delta test after the IR value test has beendone and found satisfactory.
(2) The test voltage should not exceed the rated voltage of the equipment, under test.
(3) Adequate safety precautions are to be taken when the test is on, Inadvertent entryto testing area must be prevented by proper measures.
(4) Bushings etc. should be well cleaned and the test must be carried out in dryweather condition.
(5) Make sure the input voltage variac is in the 'O' position before the start of the test.
(6) Interference from neighbouring live lines should be minimum. Modern kits withinterference suppression circuits are preferred while testing in yards etc.
(7) For Generator windings and higher capacitance specimen's the variac and thetesting Transformer should be of higher rating to carry the increased charging current.
Test value Interpretation:
In the case of Bushings the ISS prescribes a maximum value of 0.007 for oilimpregnanted condensor bushings and 0.020 for noncondenser bushings. These arevalues for new bushings and for bushings, windings and other equipments that areinservice trend monitoring is the best suggested course for proper analysis of the testresults.
Reference:
1. MWBTan delta and Capacitance kit operating manual.2. IS2099-1973.
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CHAPTER-XVCHAPTER-XVCHAPTER-XVCHAPTER-XV
MAINTENANCEMAINTENANCEMAINTENANCEMAINTENANCEOFOFOFOF PROTECTIONPROTECTIONPROTECTIONPROTECTIONRELAYSRELAYSRELAYSRELAYS
Er.K. MounagurusamyCE / P&C
9.1 SITE VISITS:
During the site visits, the following inspection works may be done in the protectionand control rooms and arrangements may be made to coordinate with other
departments for necessary works:1. The room should be tidy and clean2. Sufficient lighting should be there3. There should not be any leakage of water4. Sun rays should not fall directly on panels.5. The panels should be vermin proof.6. The inside of the panels should be free from cobwebs, dust, hanging loose wires etc.7. The room temperature should be with in limits.8. The outside of the panels should be clean.9. All the relay covers should be tightened and clean.10. Fault recorders should be in working condition.11. All the relay catalogues and drawings should be well maintained and be available in
easily traceable location. A list of these items may be readily available.12. General condition of the batteries should be checked and reported to the concerned if
any improvement is required.
9.2. MAINTENANCE TESTING OF RELAYS:
All the protective relays have to be tested ONCE in a year and calibrated.
The procedures for testing should be well studied and understood. Latest digitalrelays have self test facilities and these relays need testing once in 5 years only as perthe manufacturers. Otherwise periodic testing is extremely important, as almost allthe protective equipments are passive for most of the time. They are called upon toact only when abnormal conditions occur.
9.3. GENERAL PRECAUTIONS ON TESTING AND HANDLING OF RELAYS:
- Examine relay coils like current coil, voltage coil, flag coil, D.C. auxiliary coil,timer coil etc. for continuity.
- Check for burns on contacts, sticking up of moving parts, meeting surface and fixedcontacts.
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Experience shows that moving parts normally stick to the mechanical back stop.In armature attracted relays, there is remanence magnetic sticking up also. The starters inL3WYS distance relays have this problem. Contacts sticking up with backstop have beenexperienced frequently in EE relays. These should be cleaned each time without fail withtrichloroethylene (good to clean oil and grease), CTC (good to remove carbon), or whitepetrol (good to clean disc jewel bearings).
9.4 HANDLING OF ELECTRONIC EQUIPMENT:
a) A person’s normal movements can easily generate electrostatic potentials ofseveral thousand volts. Discharge of these voltages into semiconductor devicesparticularly chips when handling electronic circuits can cause serious damage, whichoften may not be immediately apparent but the reliability of the circuit will have beenreduced.
b) Do not remove the modules unnecessarily. However, if it becomes necessary towithdraw a module, the following precautions should be taken to preserve the highreliability and long life for which the equipment has been designed and manufactured
- ensure that you are at the same electrostatic potential as the equipment bytouching the case.
- Handle the module by its front plate, frame or edges of the PCB. Avoidtouching the electronic components, PCB track or connectors.
- Do not pass the module to any person without first ensuring that you areboth at the same electrostatic potential. Shaking hands achievesequipotential.
- Place the module on an antistatic surface or on a conducting surface whichis at the same potential as yourself.
- Store or transport the module in a conductive bag.
- If you are making measurements on the internal electronic circuitry of anequipment in service, it is preferable that you are earthed to the case with aconductive wrist strap.
- Wrist straps should have a resistance to ground between 500 K – 10 mOhms.
- If a wrist strap is not available, you should maintain regular contact withthe case to prevent the build up of static.
- Instruments used should be earthed to the case whenever possible.
- Re-soldering may affect the capacitance of the circuitry.
9.5 Take precautions to avail line clear on the equipment to be tested. Place greenflags in the panel under test.
9.6 Ensure that P.T voltages are not available to the relay under test. P.Ts ingenerators should be kept isolated : otherwise back feeding of high-voltage to theGen. is possible.
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9.7. Mark down the existing physical position of potentiometer, time dial pointers etc.with a pencil. This will help restore in case of inadvertent changes duringhandling.
9.8. Actuation of certain relays like Generator differential or split phase relay mayrelease CO2 in generators. Hence, proper isolations of CO2 circuits should beensured.
9.9. Actuation of certain relays could operate LBB schemes. Precautions should betaken, while testing LBB and BB relays, extra care should be taken to isolate theTRIPPING Circuits. In some cases, BB relays and other relays may be in samecore of C.T. Unless care is taken, the ENTIRE SUB STATION may go BLACKOUT.
9.10. There may be necessity to change some settings during testing. Original settingsshould be restored by making entries in site register.
9.11. Some wiring may need removal for testing. They should be entered in register andbefore closing the job the wiring should be restored promptly. Any removal of TB.links should be treated similarly. If ferrules are not available in the removed leads,temporary ferruling should necessarily be done before removing.
9.12. The fuses removed should be entered in the site register to enable putting backwithout fail.
9.13. Cartridge type fuses should not be checked with higher range in multimeters orfor continuity buzzer. It should give zero ohms in an accurate low rangemultimeter since failed fuses also give continuity in high ranges.
9.14. Current can be injected to the relay without removing them C.T leads. Removal isnot a must but this should be judiciously done. Refer to 9.9 above.
9.15. Earth fault selection relays in some distance relays need shorting during testing toavoid overloading.
9.16. Temporary wedges placed should be removed back.
9.17. The relay coils and the auxiliary switching relays are not continuous rated. Hencethey should not be engaged continuously.
9.18. Some operations like test closing of breakers could lead to L.T. supplychangeovers unwantedly and even they may back charge the machine.Precautions have to be taken.
9.19. Once L.C. is availed, any operation is the responsibility of the engineer who hasavailed the L.C. but it shall be done with information to operator concerned.
9.20. The maintenance engineers should also witness the relay tests to the extentpossible since they are the owners of the relays.
9.21. While test tripping the breakers through the relays, the manually picked up relaysshould not be released until the breaker has tripped since the relay contacts are notdesigned to break the trip coil current. When the breaker trips, the trip coil currentwill be broken by the breaker auxiliary contact.
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9.22. After normalising, the availability of D.C. voltage, P.T. voltage at the relay inputsshould be confirmed. The load current passing through the C.T. should beconfirmed by measuring the voltage burden between the current coil terminals,noting down the load current also in the register.
9.23. Do not try to do any modification to the wiring or change in settings withoutanalysing fully and without having consultation with superiors unless other wisesituation warrants, in which case ratification should be later obtained.
9.24. Do not assume that the scheme drawings are always correct. Some modificationscould have been done and not marked. Always have a suspecting eye.
9.25. Any modification done should be communicated to all concerned who shouldincorporate them in the drawings in their offices without fail.
9.26. History of settings and trouble shooting should be entered in permanent registers.
9.27. Faulty operations or LED indications should be checked.
9.28. Wherever master relays are available, all the connected relays should be testoperated to ensure the picking up of master relay. Test tripping of breaker can bechecked through master relay.
9.29. All alarm/ annunciator points should be checked without fail.
9.30. P.T. voltage availability, D.C. aux. supply availability across all the relaysterminals should be confirmed.
9.31. Voltage burden at the relay current terminals after normalising the equipmentshould be measured and recorded in the test report also noting down the loadcurrent at the time of burden measurement.
9.32. It is preferable to note down in the glass cover of the relays the date of last testdone.
9.33. LOAD ON C.Ts
The peak load on the lines, feeders and substation transformers may be reviewedfor any possible overloading of C.Ts beyond the limits once in 3 months andentered in a separate permanent register called “Peak Load on C.Ts”. The C.Tscan be overloaded by 20% continuously.
9.34. RECORDS:
An official test circuit diary for each type of relay shall be maintained in hand,containing the test procedure, precautions to be taken, isolation to be done, modeltest result, settings adopted etc. Relay catalogues should invariably be on hand.
All the testing works and results should be first recorded at site in a permanent register/note books with printed page numbers to avoid tampering of details later. The test resultsshall be authenticated by the engineer present. Names of the testers should be entered.The test results may then be entered in the specified form and sent to higher officers.Standardised specimen test report form is enclosed in Annexure.2 B/A means beforeadjustment and A/A means after adjustment. Changes may be done in the form ifnecessary to suit local conditions. Any abnormality noticed during the testing may berecorded under the column “ Remarks” in the test report.
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The test schedule with tests done date and tests due date shall be displayed conspicuouslyin the office room in a Fixograph or in a board so as to review them frequently.
The details of the tests done may also be recorded in a permanent register with pagevarallocation for each relay. A few pages together may be allocated for each relay or set ofrelays in the case of 3O/L. One register may be put up for each substation or for moresubstations combined.
A specimen of one page of the register for a relay is given below:------------------------------------------------------------------------------------------------------------
Feeder/Line/Transformer : S/S :Relay details : (Make, Type, Model, Sl.No., rating,
D.C.aux. voltage etc.)Settings Range available :Settings adopted :C.T.Ratio available :C.T.Ratio adopted :V.T.Ratio adopted :Date of Commissioning :
------------------------------------------------------------------------------------------------------------Sl. Date of Date of Remarks Signature SignatureNo. Last Next of of
test test Protection Reviewingdone. Due. Engineer. Officer.
------------------------------------------------------------------------------------------------------------1) Deails of
settings changedwith referenceletters no.
2) Details of anydefects.
3) Details ofmodification
4) Details of“ Obsoletion”Communicatedby thesuppliers.
-------------------------------------------------------------------------------------------------
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T E S T R E P O R T1. Name of S/S. :2. Name of Feeder/Line :3. (a) Rela y : (Ex. Dista nce Rela y Main 1/Main 2)
(b) Make : (ABB)(c) Type : (Ex. RAZOA)(d) Sl.No. :
4. Nature of Test : Specia l/Routine (State reason if itis specia l)
5. Date of last testing :6. Date of this testing :7. Page No.of Test record (site) Book : (Including Volume No.)8. Testing instruments used : (Ex: TURH KIT, WICO megger ,
5A ammeter, 150 V Volmeter)9. Test Results:
(a) Rela y (Ex: For O/C relay)----------------------------------------------------------------------------------------------------------Test Time Time Obtained RemarksCurrent Exp.
R O Y O B O
B A A A B A A A B A A A----------------------------------------------------------------------------------------------------------P.U. 2 Amp. 2.1 2.1 2.1 -- 2.0 --
4 A 1 Sec. 1.4 1.0 1.1 -- 1.0 -- Time diaadjusted
8 A 0.7 Sec. 0.9 0.71 0.75 -- 0.65 -- in Rphase
20 A 0.3 Sec. 0.5 0.31 0.31 -- 0.28 -- relay.----------------------------------------------------------------------------------------------------------
(b) Checking of Flag or LED (indica tions of relays) and the annunciator points.
(c) Megger ing
C.T.Sec. to Earth
(d) C.T.Burden (VOLTAGE MEASURING IN THE C.T.SECONDARY CIRCUTT ATREIAY TERMINALS)
R-N = V : Y-N = V : B-N =V
Load Current:
(e) P.T.Voltage
R-Y = R-N =
Y-B = Y-N =
B-R = B-N =
(f) Trip Circuit testing (test tripping the breakers through relay)
(g) Remarks:
1) Checking of all fuses
(Sd) TESTER ASST.ENGINEER ASST.EXE.ENGINEER.
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CHAPTER-XVICHAPTER-XVICHAPTER-XVICHAPTER-XVI
GASGASGASGAS INSULATEDINSULATEDINSULATEDINSULATED SUB-STATIONSSUB-STATIONSSUB-STATIONSSUB-STATIONSEr.K. Mounagurusamy
CE / P&C
The informations given be low are abstracted from several ASEA GIS equipmentbooklets.
Gas insulated Sub-station of certain types takes up only about 10% of the area ofconventional Sub-stations.
Figure-1 shows below the comparison, for a volt level upto 170 KV.
HISTORY:HISTORY:HISTORY:HISTORY: Use of SF-6 gas for breakers was started in mid sixties.
GIS programmes were launched in seventies. In early 1977, first GIS wascommissioned by ASEA in Sweden upto 420 KV. Now GIS of several thousand KV areavailable.
At lower levels of voltage three phase systems are used.At UHV levels single phase systems are used.
ADVANTAGES:ADVANTAGES:ADVANTAGES:ADVANTAGES:
1) The area required is very much less2) Quicker and simpler erection3) Easier maintenance4) Insensitive to influences of surroundings
GASGASGASGASPRESSURE:PRESSURE:PRESSURE:PRESSURE:
The higher the gas pressure (density), the higher will be the insulation strength ofthe gas and smaller the dimensions of the enclosure. Normal pressure is 7 bars.
Figure-1
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In some designs, the equipment can withstand the rated voltage also when the gaspressure decreases to atmopheric pressure provided no switching is done.
COMPONENTS:COMPONENTS:COMPONENTS:COMPONENTS:
- Conductors- Insulators- Enclosures- Gas- Spacers
SPACERS: - forms a solid insulation, in parallel with gas, between the conductor in thecentre and the surrounding earthed enclosure. The earthed enclosure is in the form ofmetallic tube. In the centre of this there is the conductor which is supported and held inplace by insulating cones called spacers. The space between conductor and enclosure isfilled with SF 6 gas at overpressure. See Figure 2 to 5.
324
CHAPTER–XVIFIGURE - 2
FIGURE - 3
FIGURE - 4
325
CHAPTER–XVIFIGURE - 5
FIGURE - 6
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327
CHAPTER–XVIFIGURE - 6
FIGURE - 8
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The spacers have to withstand mechanical forces from gravity, apparatus function,pressure differences between gas sections, earthquakes and short circuit currents. Disctype spares are also used.
CONDUCTORS:CONDUCTORS:CONDUCTORS:CONDUCTORS:
Consists of aluminum tubes with joining contacts at the ends. Current is transmitted viathe spring loaded contact member to the copper parts and against which the contactmember rests. These are later welded to the aluminium parts.
JOINTS:JOINTS:JOINTS:JOINTS:
There are angled joints and T-Joints
EXPANSIONEXPANSIONEXPANSIONEXPANSION JOINTS:JOINTS:JOINTS:JOINTS:
Expansion joints are provided partly to compensate for the tolerance during manufactureand partly to allow for thermal expansion.
OTHEROTHEROTHEROTHER COMPONENTS:COMPONENTS:COMPONENTS:COMPONENTS: Like disconnectors, CTs, VTs etc. are shown in figurebelow:
FIGURE-9Disconnector straight
1. Fixed contact2. Moving contact3. Operating devise
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CHAPTER–XVI1. FIGURE-10
Angled and T disconnectors
Disconnectors can be operated by Motor devices.
`
T-disconector
Fig - 10
330
CHAPTER–XVI
- Shows continuous position indication- Possibility of using the earthing switches as a test probe for measuring contact
resistance and polarity of instrument transformers- Can be located in the same housing as disconnectors but also elsewhere.- Can be operated either manually or Motor operated- There are two types such as fast operating and slow operating
FIGURE – 12VOLTAGE TRANSFORMERS
- Voltage transformers can be set up where it is required i.e. on bus bars and outgoingcircuits.
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Figure – 13
CURRENTCURRENTCURRENTCURRENT TRANSFORMERTRANSFORMERTRANSFORMERTRANSFORMER
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The bushing can be adopted to any existing oil filled or PEX cable
- Also used for High potential testing of GIS bus bars etc.
EXTENSION:The GIS can be extended usually by lengthening the bus bars and adding more
breaker groups provided necessary space is provided in the building. Erection sequencemust be checked in detail. Another question to investigate is the procedure of testing afterinstallation of the new parts.SAFETY:
The probability of anybody being injured in a GIS will 0.000025 per year or onceper 1300 years. GIS is said to be 40 times safer than conventional sub-stationsTESTING OF GIS:
1) Testing of Gas:Non return valves are provided to fix the gas density switches. After removing the
switch assembly, external gas hoses can be connected and gas filling, draining, testingcan be done.
2) Breaker testings:
Since the poles are inside the gas tank, approach to do the timing tests, primaryinjection through CTs were difficult. For one end, the earth switch end which is insulatedbefore the earth connection can be used. For the other end the earth switch cannot be usedsince all the three phases are looped inside the SF-6 chamber and only the neutral isbrought out. Hence, the cable ends which was at a distance of 100 meters from S.S. wereused for the above tests. The layout of cable system is shown in Figure-17. This was alsoused for hipot testing the cables. D.C. hipot testing of GIS has to be avoided.
FIGURE – 16: SF-6 AIR BUSHING
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CHAPTER-XVIICHAPTER-XVIICHAPTER-XVIICHAPTER-XVII
REVIEWREVIEWREVIEWREVIEWANDANDANDANDANALYSISANALYSISANALYSISANALYSIS OFOFOFOF TRIPPINGSTRIPPINGSTRIPPINGSTRIPPINGSEr.K. Mounagurusamy
CE / P&C
ALLALLALLALL THETHETHETHE TRIPPINGSTRIPPINGSTRIPPINGSTRIPPINGS SHOULDSHOULDSHOULDSHOULDBEBEBEBEREVIEWED.REVIEWED.REVIEWED.REVIEWED.
Analysis of the operation of protective relays or the scheme is very important for aprotection engineer.
The following types of operations need analysis:-
- Maloperation i.e False tripping in the absence of primary fault.- Incorrect operation or unwanted operation during a primary fault.- Failure to operate.
The protection engineer may carry out the analysis in the above lines and do the needfulfor improvements. The action taken may be reported to the head office for scrutiny. Thereare always possibilities for human error in the protection works and hence a scrutiny byanother agency is an Absolute Necessity.
All the trippings of transmission and sub-transmission level lines and transformers atSubstations should be reported by T.M. to the concerned head office in the form givenbelow:
TransmissionTransmissionTransmissionTransmission linelinelineline fults:fults:fults:fults:
A line fault is a condition where electric current follows an abnormal path due tofailure or the removal of insulation which normally confines it to the conductor.
Insulation is usually either air or high resisting material which may also be usedas a mechanical support. Air insulation can be accidentally short circuited by birds,rodents, snakes, monkeys tree limbs, unintentional grounding by maintenance crew etc.,or broken down by over voltage due to lighting or weakened by ionisation due to fire.Organic insulation can deteriorate due to heat or ageing or can b broken down by overvoltage due to lighting, switching surges or faults at other locations.
Porcelain insulators can be bridged by moisture with dirt salt or industrialpollution or can develop a crack due to mechanical forces. In such cases the initiallowering of resistance causes a small current to bee diverted which hastens thedeterioration or ionisation causing this current further to increase in a progressive manneruntil a flash over occurs.
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Overhead transmission lines are most vulnerable for lighting strokes. More than50% of electrical faults of overhead lines are known to be caused by lightning. As perVan C. Warrington, all faults occur within 40 degrees before voltage maximum at linesover 100KV. The shield wires intercept most direct strokes and allow them to beconducted harmlessly to ground. Some time, they could reach the conductors below theshield wire. In such cases, the lightning surge will bee distributed in all directions of thelines connected, depending upon the point of incidence. For example, a lighting strikepenetrating the shielding system and terminating on a phase conductor would generatetraveling waves of the same magnitude and polarity propagating in opposite directions.
Some times, these waves may attenuate and die without any problems. Most ofthe times, they keep on propagating on the line. Of all the line insulators are in healthycondition, the surges reach the terminal substations and be bypassed to the groundthrough lighting arresters. In this case, protection needs to operate and line will remainhealthy since surge current is by passed within micro seconds.
If any of the lines insulators re weak, it can undergo flash over due to the surge.“The possibility of even the direct stroke causing a flash over near voltage zero isminimised by the fact that the lighting stroke lasts only one or two microseconds and, ifthe line voltage were near zero at the moment, there would be nothing to sustain the flowof power after the stroke. Although the stroke current may be upto 100,000A there is lessthen a coulomb in a stroke, so there would be no cloud of ionised air maintaining a lowresistance path until the voltage built up” (Van C. Warrington : vol 2). Once a flash overoccurs, there will be system frequency follow current depending upon the fault level andthe arc will not extinguish till the system voltage is interrupted by the protection. Thismeans that both end relays of a tied line should operate and isolate the line. A single endtripping will not suffice. Many a times, the flash over does not damage the insulator andthe line can be recharged. This is called a “passing faults”. Short circulating the lineinsulator by snakes, birds etc., as discussed before, will also come under this category.
But, if the insulator gets damaged by the flashover, it will not withstand the powersystem voltage if reenergized and the protection will again operate. This is a kind“permanent fault”. There are different types of permanent faults which are not discussedhere.
The flashover may occur in more than one towers due the lighting surge wave. Ifone such flashover leads to a permanent damage in the second zone of a distance relaysand another flashover causes a temporary flashover in its first zone coverage, both endrelays will trip on first zone and may cause confusion when analysing by the protectionengineer.
Single end trappings should be treated in a special manner. From the discussionsso far made, at will be clear that there can not be single end trippings at all! But, they dooccur. A tall tree ay swing and touch a conductor in the second zone but may withdrawbefore the second zone time of the relay. In this case, only the other end will trip on firstzone. A jumper may get open and fall on the tower arm in one side and the tripping willbe single en only. A conductor may snap and tall to ground in only one side of the linesand the result will be single end tripping. Hence, the protection engineer shall not takegranted any single end tripping which is very rare. If the cause is not established clearly,the protection system should be checked thoroughly in the case of single end trippings.
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Lighting need not even come in direct contact with power lines to cause problems,since induced charges can be introduced into the system from nearby lighting strokes toground. Although the cloud and earth charges are neutralised through the establishedcloud – to – ground path, a charge will be trapped on the line. The magnitude of thistrapped charge depends on the initial cloud to earth gradient and proximity of the stroketo the line. Voltage induced on the line from the remote stroke will propagate along theline causing similar problems as that of direct stroke.
When a lightning directly strike a tower or the earth conductor the tower has tocarry huge transient currents. If the tower footing resistance is considerable, then thepotential of the tower would rise steeply with respect to the line and consequently theinsulator string would flash over. This is known a “BACKFLASHOVER”. It is clearthat too many trippings on temporary faults may also indicate more tower footingresistance, needing improvements.
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TMTMTMTM
From ToThe Superintending Engineer
Asst.Exe.Engineer/Shift Copy to the Exe. Engineer/O110 KV/line tripping Copy to the EE/GRT (MRT)message Copy to the AEE/GRT (MRT)
1. Name of Sub-Station :2. Name of line :3. Time & Date of tripping :4. Relay indications )
at both End. )5. Is the line radial or )
Tied at both ends )6. Load on the line prior )
to tripping MW, MVAR, )AMPS. )
7. Bus voltages recorded )before tripping – at )the time of tripping - )after tripping. )
8. Special observations )like grunt in generators,flickering of lamps )oscillations in panel )meters. )
9. Any other simultaneous )trippings of 132 KV )lines or distribution )lines. )
10. Climate :11. Time and date of )
normalisation )12. Remarks :
Asst. Exe. Engineer / Shift.
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1) Every grid and upstream radial feeders tripping shall be reviewed monthly.
2) Even correct trippings of grid feeders and upstream radial feeders should also be
reviewed and classified as “ IN ORDER” and reported to higher office. A correct
tripping in the view of one engineer (may be inexperienced) may be a wrong one.
There are instances that single end tripping of grid feeders have been classified as IN
ORDER in some cases without analysis. Correct single end trippings of grid lines are
also possible but extremely remote – a line getting open and conductor making
ground fault in only one side.
3) Review of transformers and generators shall be reviewed then and there. Our old
practice is that the review should be made within 24 hours. It is felt that this is even
now very essential. Maloperation of any equipment i.e. radial lines, tie lines,
Transformers, Generators shall be analysed within 24 Hours.
4) Correct operations shall be classified as due to
- Weather
- Lightning
- External incidents
- Failure of line or equipments
- Overload
- System disturbance
- Cause not known.
5. Incorrect relay operations shall be classified as due to
- Design limitations
- Inadequate or Incorrect settings
- Construction defect
- Maintenance defect
- Failure of relay component
- Caused by pilot channel
- Personnel errors
- Incorrect application of relays
- Unexplained.
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6. Relay tripping registers shall be maintained by protection wing as well as substations
O&M wing.
7. Protection engineers should be knowing how to calculate the fault level at any point
in the system. Fault level of local substations should be calculated by them and
exhibited in the premises conspicuously.
8. Some of the interesting review and analysis are discussed below:
I.I.I.I. WRONGWRONGWRONGWRONG CONNECTIONCONNECTIONCONNECTIONCONNECTION OFOFOFOF GENERATORGENERATORGENERATORGENERATOR –––– ROTORROTORROTORROTOR EARTHEARTHEARTHEARTH FAULTFAULTFAULTFAULTRELAYSRELAYSRELAYSRELAYS ATATATAT ALIYARALIYARALIYARALIYAR POWERPOWERPOWERPOWER HOUSEHOUSEHOUSEHOUSE ANDANDANDAND SHOLAYARSHOLAYARSHOLAYARSHOLAYAR POWERPOWERPOWERPOWER HOUSE.I.HOUSE.I.HOUSE.I.HOUSE.I.
The Generator rotor earth fault relays were with wrong connections at Aliyar
Power House and Sholayar Power House.2 since their commissioning. The relays were
not operating during normal conditions though there was an earth fault existing in the
rotor and were operating “ Correctly” for a short moment during shutdown sequences.
The circumstances which warranted the tracing of the fault and action taken to rectify the
defect are narrated in the following lines:-
On 23.12.79, 27.7.80 and 1.9.80 the rotor earth fault relay of the 60 M.W. Hydro
generator at Aliyar Power House acted for a short-while during normal shutdown
sequences soon after the shutdown impulse was given.
Every time the relay was tested and found to be normal. The details of the I.R.
value of the rotor circuits meggered on 23.12.79 are not available and the I.R. value of
the rotor circuits meggered subsequent to the operation of the relay on 27.7.80 and 1.9.80
were low and was of the order of 0.2 to 0.3 M. Ohms.
No serious thought was given for the relay operation on 23.12.79 considering it as
freakish. Only after a recurrence on 27.7.80 the matter was studied in detail.
The relay was acting just for a moment during the shutdown sequence and it was
not acting during normal running of the machine or during shutdown time and this
required a deep study of the subject.
While going through the original schematic drawing of the Generator on 30.9.80
it was observed that the rotor earth fault relay was given wrong connection.
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The scheme as per the given drawing is shown below :
In this connection scheme, the rectifiers in the bridges of the relay will permitflow of current when the circuit is closed by earthing the point ‘A’. This current would bedue to the D.C. source voltage available at the terminals 9 & 10 of the relay. It could beseen that the D.C. voltage on t he rotor is in “subtractive series” connections with the D.C.source voltage of the relay. Hence, if the earthing point is slowly moved from point Atowards point B, the resultant voltage across the relay coil would be V9-10 – V A F. Aslong as V9-10 is greater than VA-F, there would be a flow of current through the relayelement R. When VAF becomes greater than V 9-10, the resultant voltage would not beable to drive any current through the circuit since there are the rectifiers in the bridge ofthe relay which will not permit any flow of current when they are supplied with a voltageof reverse polarity. This means that only a very small zone of the motor from the point Atowards B was under protection of the relay so far. (It was confirmed later that the relaycurrent was zero even when the point B was earthed solidly.)
In the first look, it seemed that the problem has further confused since it wasoperating during a particulars period of shutdown sequence, though it was connected in a“non-operating way”. On further analysis, the “wrong connection” was found to be thecause for the momentary operation of the relay during the shutdown sequence alone asexplained below.
The Generator at Aliyar has “ de-excitation scheme” during shutdown sequence i.e.as soon as the shutdown impulse is given, the main exciter voltage is reversed rapidly tocause “de-excitation of the rotor” before the tripping of the field breaker. When the mainexciter output voltage is reversed, it comes in “ additive series” with the D.C. supplyvoltage of the relay i.e. the relay gets “ correct connection” accidently for a moment and ifa rotor earth fault is persisting it measures and indicates and this a what had occurred onall the three occassions. This was got proved on 5.9.80. Necessary modification in the
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scheme was down on 5.9.80 by interchanging the internal wiring leads in the terminal 9& 10 of the relay, after getting oral approval of the Divisional Engineer/GRT/Thudiyalur.The machine was running and when the relay was put back in service after modification,the relay acted immediately. A persisting rotor earth fault was suspected. On earthing t herotor through a 5 K resistor, there was measured a leakage current of 0.75 m.amps. So farit was not detected by the relay and after modification it has detected.
Even with the original wrong connection, the relay should have detected the earthfault when the machine has come to rest i.e when the rotor voltage has come to zero. Thiswas not there and it could be explained as below with an example.
Let the D.C. source voltage of the relay be 55 V The setting current required forthe relay element to pickup is 1.1 m.amps.
Therefore I.R. value detected by the relay55
= = 50000 Ohms.1.1 ma
This much of low I.R. value will be detected by the relay if the fault is in anyportion of the rotor when the machine is shutdown.
Let the rotor voltage be 55 Volts.
Assuming that the connections are O.K, and a fault of 100000 Ohms occurs atpoint B when the machine is running.
Total voltage available for the )relay element ) = 55 + 55 = 110 V
Therefore the leakage current or )the operating current through ) 110the relay element ) = - - - - - - - = 1.1 ma
) 100000
Hence the relay could operate i.e a fault of 100000 ohms at point B could bedetected by the relay only when the machine is in service and the same fault would goundetected when the machine is shutdown since the relay current in the case would beonly 55/100000 = 0.55 ma i.e. the “aid” voltage of the rotor is not available now.
The relay available at Aliyar Power House is of English Electric make type VME.The same type relay was available at Sholayar Power House 2 also. When the studieswere going on at Aliyar Power House, the scheme at Sholayar Power House.2 waschecked for comparison. It was found that the very same defect was there also. That relaywas also operating for a moment several times when the machine was tripping on faultssince 1971. The relay has not picked up during normal shutdowns as was operating in thecase of Aliyar Power House due to the fact that the de-excitation scheme comes intooperation only during fault trippings of the machine at Sholayar Power House.2 and isnot coming during normal shutdowns. The modification was also carried out at SholayarPower House 2 afterwards.
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Such defects with similar type of rotor earth fault relays could be detected only bytest-earthing both ends of the rotor while the machine is running. Any testing by earthingthe rotor when the machine is not in service or by earthing any one end of the rotor whenthe machine is in service is not the complete one and will not reveal such defects.
II.II.II.II. ROTORROTORROTORROTOR LIFTLIFTLIFTLIFT PROTECTIONPROTECTIONPROTECTIONPROTECTION ATATATAT KADAMPARAIKADAMPARAIKADAMPARAIKADAMPARAI POWERPOWERPOWERPOWER HOUSE:HOUSE:HOUSE:HOUSE:
Top beam
SettingElectrical Contact
Gap = 1.2 m.m
Rotor bracket beam
During over-speeds or any unbalance problems, the rotors of the generators mayget lifted up in the case of vertical machines. At Kadamparai, rotor lift protection is givento trip the machine. When the rotor bracket beam lifts up by 1.2 mm (Original setting),the protection will operate.
The machine was tripping frequently from 11.4.91. It was tripping.
a) before synchronism
b) after synchronism
c) When the load was changed
d) Even when the machine was running smoothly.
After struggling continuously for 8 days, the reason was found to be rather funny.Whenever the side doors of the generator was opened for some reason or other, the entiretop platform with the beam bent and moved down by 1.2 mm due to downward suction ofair caused by all blower fans.
Prior to 11.4.91, all the blower fans could not be switched on due to problems insome fans.
III.III.III.III. TRIPPINGSTRIPPINGSTRIPPINGSTRIPPINGS OFOFOFOF GENERATORGENERATORGENERATORGENERATOR 2222 atatatat KUNDAHKUNDAHKUNDAHKUNDAH POWERPOWERPOWERPOWER HOUSE.HOUSE.HOUSE.HOUSE. 3333 ONONONONBUCHHOLZBUCHHOLZBUCHHOLZBUCHHOLZ INDICATION:INDICATION:INDICATION:INDICATION:
Generator No. 2 at Kundah Power House 3 tripped on transformer buchholzindication and Generator O/V relay indication. There was no air or gas in the buchholzrelay and the machine was put back in service. Though the machine was running OK, themachine was shutdown to probe further for the tripping.
The cable coming from the transformer was found damaged. Thinking that thiscould be the reason, the machine was re-serviced. The machine tripped again after oneday with the same relay indication.
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Staff who checked the Buchholz relay by dismantling it said that the diaphragmwas weak and that could be the cause.
But, it was approached from another angle. Why the Generator O/V relay hasacted? Had the Buchholz relay first acted, the machine field breaker would have trippedimmediately along with the main breaker and there could not be any reason for themachine voltage to rise.
It was decided to test the O/V relay. It was operating even for normal voltage of11.2 KV on the machine. And, when the O/V relay acted, Buchholz trip alarm came.
There were two culprits:
1) Wrong calibration of O/V relay2) Wrong connection of annunciator.
IV.IV.IV.IV. PERSONNELPERSONNELPERSONNELPERSONNEL ERROR:ERROR:ERROR:ERROR:
The generator at one Power House was reported one day to have tripped withoutany relay indication except master relay operation.
After thorough checking of Generator, transformer, Cables, Protection systemnothing could be found out. Everyone was hesitant to restart the machine but theconcerned operator said the machine can be restarted. Here was the clue:
On further interrogation with the operator, Switch Board Attendant and other staff,the truth came out. When the operator had observed some oscillations of some meters, hethought that something was wrong with the machine and operated the emergency push-button.
V.V.V.V. ANOTHERANOTHERANOTHERANOTHER PERSONNELPERSONNELPERSONNELPERSONNEL ERROR:ERROR:ERROR:ERROR:
Machine. 1 at one Power House was reported to have tripped on Generatordifferential relay. When the operator on duty was contacted over phone, he said that whenhe wanted to shut down unit.1, he just put his hand on the L.T. breaker switch of machine.1 and at that instant the machine had tripped.
Not a deliberate, but an upset boss shouted at the operator over phone :
“Are you playing? How can it trip when you just touch it? Do you think that I am afool? Do you think that I do not know what happened?”
Immediately, the operator surrendered and accepted that he had done a wrongoperation by paralleling the L.T. system of machine 1 and machine.3 after tripping hemain breaker of machine.1.
Shouting helps some times for analysis:
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VI.VI.VI.VI. MALOPERATIONMALOPERATIONMALOPERATIONMALOPERATION OFOFOFOFTRANFORMERTRANFORMERTRANFORMERTRANFORMER DIFFERENTIALDIFFERENTIALDIFFERENTIALDIFFERENTIAL RELAY:RELAY:RELAY:RELAY:
At one Sub-Station, both the transformers were tripping one differential relayfrequently for through faults i.e for known fault on downstream radial feeders. This washappening for many years and several testes on transformer and relays were in vain.
The ultimate reason was very simple. The differential relay p.u. setting was 15% butthe transformer had tap range upto 17.5% with OLTC. When the tap moves to extreme,position, the mismatch current was sufficient to operate the relay.
VII.VII.VII.VII. MALOPERATIONMALOPERATIONMALOPERATIONMALOPERATION OFOFOFOF DISTANCEDISTANCEDISTANCEDISTANCE RELAYS:RELAYS:RELAYS:RELAYS:
When the author joined at Saudi Arabia, the first assignment was the analysis ofthe frequent tripping of a double circuit feeder outgoing from a Power House for reversefaults, Er. Arunachalam who has contributed some chapters in this Manual was theprotection incharge. Though the problem could not be identified by them so far, it wasnot at all a problem for both of us.
Attacked the first point and found that the C.T. connection were opposite.
The problem was set right without availing a shutdown and also withoutsuccumbing to the threat from the local boss that both of us would be sent to fail ifanything wrong happened.
This particular analysis is so simple that it does not deserve inclusion in thismanual but this is included to show the capability and standard of the protectionengineers in our board on comparison. The problem had caused several black outs to thesystem there but was not given due though for several years.
The author wishes to mention on more things – purely personal:
In one committee meeting held to finalise the procedures to commission a newsubstation, 10 out 12 people were from India and nine out of the ten were from TamilNadu.
VIII.VIII.VIII.VIII. DOWNDOWNDOWNDOWN TOTOTOTO THETHETHETHE EARTHEARTHEARTHEARTH PROBLEMPROBLEMPROBLEMPROBLEM
During a pre-commissioning test in a Sub-Station, a transformer differential relaytype MBCH, a static relay, was not behaving properly.
When the relay was tested by another engineer next day, the relay behavedcorrectly.
The reason was:
The first engineer tested the relay keeping it outside the case. That was his usualmethod.
The second engineer did by his method by keeping it inside the case.
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Later, on enquiry from an engineer from the relay manufacturing company, thereason given was that the static relay will misbehave if its chassis is not earthed properly.Proper earthing is provided in- side the case and when the relay is racked out, the earth islost.
IX.IX.IX.IX. BLINDBLINDBLINDBLINDAPPROACH:APPROACH:APPROACH:APPROACH:
For the known fault on a distribution feeder from Sub-station in Saudi Arabia,several feeders were tripping simultaneously even in other substations very far away.
How to approach?
One of the author’s Colleagues, a distribution engineer, hailing from our board,came up with suggestion one day. He was telling that one particular feeder which had avery high pick up setting had never tripped on similar occasion. On that basis, hesuggested to revise the settings of all other feeders.
The suggestion looked very childish. Comparing with the peak load the settingswere more than sufficient in all feeders.
However, the subject was digged further.
A phenomenon called “COLD RUSH” was explained in an article appeared in thelectures at PSTI, Bangalore. There was not much explanation but it gave a starting point.
On further searching, it was found that the “Cold-Rush” is a very big problemwhere loads are predominant with Air-conditioners, even in United States. Several blackout have occurred.
What is a “ Cold Rush”?
When a fault occurs at a particular location in a system, the system voltage drops.When the voltage drops to 70% and below, the A.C. units stall. Even if the voltage isrestored immediately, they take a very high current of 5 times the full load current till thebleeding of pressure system completes.
This takes more than a minute and hence the load on the healthy feeders suddenlyshoot up to several times the full load, causing the tripping.
The problem was solved temporarily by increasing the P.U. settings as suggestedby our colleague, though by layman approach.
The correct solution for this problem is to provide U/V tripping in all the airconditioners.
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X.X.X.X. DISTRIBUTIONDISTRIBUTIONDISTRIBUTIONDISTRIBUTION OFOFOFOFEARTHEARTHEARTHEARTH CURRENTSCURRENTSCURRENTSCURRENTS ININININ HIGHHIGHHIGHHIGH VOLTAGEVOLTAGEVOLTAGEVOLTAGE SYSTEM:SYSTEM:SYSTEM:SYSTEM:
The theory of this subject is dealt in several books including GEC measurementsbook and Russian books. Chances are very remote for the protection engineer to go into itdeeply but one of our former engineers, Er. Srinivasaraghavan, Disvisional Engineer(Generation) has produced a very good article on this subject in MSEB. Journal datedJune 1952. A reproduction of the full article (since not even one word is extrawritten)will certainly help to guide our engineers.
ELECTRICITY DEPARTMENT JOURNAL
IT IS THE GENERAL practice to earthed the neutral in high voltage transmissionsystems, at one voltage transmission systems, at one point only, that is at the sending end.In case of earth fault in one of the phases, the earth current flows from the fault to theearthed neutral through earth and actuates the earth fault relay and trips the breakers, thusisolating the fault. There have been instances where star/star transformers with tertiarydelta have been connected at the end of transmission system, the neutral point on the H.V.side of these transformers being brought out and connected to earth. Thus the neutral isearthed also at a point, other than at the sending end. In such cases, earth fault.Current flows not only from the fault to the sending end neutral but also from the neutralpoint of the star/star transformer, though this is beyond the fault. The distribution of thefault current is as shown in diagram I.
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In this diagram G is the generator feeding into a transmission line through adelta/star step up transformer T1, T2 is a step down transformer connected to the end ofthe transmission line, the connections of the windings being star/star with tertiary deltaand the neutral point on the H.V. side being connected to earth.
The effect of the current flowing into the fault not only through the faulty phase,but also through the healthy phases from beyond the fault on the operation of protectiveequipments is interesting. A few examples that have actually occurred some years blackin the Department’s E.H.T. net work are mentioned here:
(i) Coimbatore –Madurai-Koilpatti 66 KV line – (Diagram 2).--The neutral pointsof the star connected auto-transformers at Coimbatore were solidly connected to earth: inaddition, the neutral pint of the star/star transformers with tertiary delta at Koilpatti endwas earthed. For earth faults in the lines between Coimbatore and Madurai, the 66 KVOCB on the outgoing line to Koilpatti a Madurai end used to trip out: the 66 KV fuses onthe transformers at Koilpatti end also used to blow out on certain occasions. The remedywas either to isolated the neutral at Koilpatti or raise the setting of the earth fault relay onthe Koilpatti line at Madurai end sufficiently high to prevent its operating under suchfault condition. The former course was adopted.
(ii) Coimbatore-Prianaickenpalayam – Nellitharai 11 KV line. Mettupalayamwas original fed from Nellitharai S.S. by stopping down the 66 KV voltage to 11 KVthrough delta/star transforms, When Nellitharai sub-station was abolished after changingover to feed from Coimbatore. The 66 KV/11 KV transformers were left at Nellitharai forsome time and this used to be kept energised at 11 KV from Coimbatore end and isolatedon the 66 KV side. Under such conditions, there have been cases when the 11 KV OCBat Nellitharai tripped for a fault on the line between Coimbatore and Nellitharai (vidediagram 3).
In both these instances the operation of the OCBs beyond the point of the fault areevidently due to flow of earth fault current from the neutral of the transformer at theremote end in these case at Koilpatti and Nellitharai.
XI.XI.XI.XI. PROTECTIONPROTECTIONPROTECTIONPROTECTION ENGINEERSENGINEERSENGINEERSENGINEERS’’’’ PROBLEMS:PROBLEMS:PROBLEMS:PROBLEMS:
Another good article written by Er.G.A. VISVANANTHAN, in MSEB. Journal(date not known) is also reproduced since this is also very illustrative:
IT IS NOT very uncommon to have certain unexplainable operation of relays in spite ofvery careful selection of relay settings. In many such cases definite faults were found toexist outside the sphere normally scrutinized by the protection engineer. It is, therefore,necessary that the engineer should proceed with tan open mind to investigate suchapparent maloperations. The following occurrence is an example:-
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At Tiruvarur in the Mettur Electricity System, a 11 K.V. feeder is taken for abouta mile from the Government sub-station to the South Madras Electric Supply licensee’spower house from where a number of feeders are taken out to the licensees; variousstations. At the Government sub-station the feeder is protected with 2 overload and oneearth leakage relay and at the licensees’ Power House, the incoming and the outgoingfeeders have also 2 overload and one earth leakage relay; some four years backcomplaints were being received from that station that for earth faults on any of thelicensees’ feeders, the relay at the Government sub-station end only would trip, thuscausing supply failure to the licensee’s entire area.
The testing of relays and O.C.Bs. in the Government sub-station and gradation ofsettings of relays at both the ends of the feeder and those on the out-feeders at thelicensee Power House did not stop this occurrence. Finally it was decide to check up theconnections of and test the relays and O.C. Bs. at the licensees’ Power House.
On examinations, it was found that on each feeder, the connexions were as shown inthe sketch below with an earth connection at “a”
This explains the non-operations of the earth leakage relays at he licensees’ end foran outside fault, while tripping the relay at the Sub-station end. This earth connexion wasremoved and the relays and O.C.Bs. were tested. From then on wards the relays operatedsatisfactorily.
G. A. VISVANATHAN.
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EXPERIENCESEXPERIENCESEXPERIENCESEXPERIENCES ININININ PROTECTIONPROTECTIONPROTECTIONPROTECTION FIELDFIELDFIELDFIELDEr.K. Mounagurusamy
CE / P&CFEEDERFEEDERFEEDERFEEDER TRIPPINGSTRIPPINGSTRIPPINGSTRIPPINGS DUEDUEDUEDUETOTOTOTO SINGLESINGLESINGLESINGLEPHASEPHASEPHASEPHASE FUSEFUSEFUSEFUSE BLOW-OUT:BLOW-OUT:BLOW-OUT:BLOW-OUT:(Arti cle by: Sri. S. Raghunatha Rao B.E; D.E(E) & Sri. P. Narayanan B.E; D.E(E)
The blow-out of the H.G. fuse on the H.V. side on one phase of the Delta/StarPower Transformer at a Sub-station may cause feeder trippings on L.V. side.
There was recently an occurrence of this nature at Poonamallee Sub-station, whenthe 33 K.V. H.G. fuse on the yellow phase of single 3-MVA: 33/11 K.V. Transformer inservice at the time below off. Of the four numbers 11 K.V. feeders taking off the station,three tripped on over-load blue phase while the fourth feeder was standing.
A review has indicated that the fuse blow out should have preceded the feedertrippings, the blow out being caused by mere over-load over a period of time during thepeak period. (Two strands of 21 SWG timed copper wire were used for the fuses in theabsence of OCB control on the H.V. side.)
The trippings of the 11 KV. Feeders are analysed with the help of vector diagramsgiven below : --
With the blowing out of the H.V. fuse on the yellow phase the voltage vectors ofphases R and Y on the primary and r and y on the secondary side collapses, Y becomingY’ and r and y moving to r’ and y’. This results in only half the normal voltage beingimpressed across the windings R and Y of the primary and a single phase secondarysupply with normal voltage between the blue phase and neutral and half the normalvoltage between the red and yellow phases and neutral. Consequent upon the fullsecondary voltage being available only between the blue phase and neutral there shouldhave been a disproportionately heavier drawal of power on the blue phase. The three 11K.V. feeders, which were already fairly loaded at the time of occurrence all tripped onoverload blue phase, the heavier drawal on this phase, resulting in load currentsexceeding the overload settings. The fourth feeder, which was also in service at that time,is understood to have had practically negligible load and the fact of this feeder nottripping is perhaps explained by the failure of the load on the blue phase of this feeder toreach the plug setting value, notwithstanding the heavier drawal of power on this phase.
EARTHEARTHEARTHEARTH FAULTFAULTFAULTFAULT RELAY:RELAY:RELAY:RELAY:
There is a big article on this subject by ER.K.S. DORAISWAMY, DivisionalEngineer on this heading published in December 49 of MSEB. Journal. The conclusionis given below:
The current flow in a residually connected earth fault relay in series with 2 O/Lrelays, is only a fraction of the unbalanced current. The true replica of earth fault currentwill not be flowing through the E/L relay particularly when it setting is very low.
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Number of tests were done in the MRT. Lab at Coimbatore and results andtabulated. The readings show that with the E/L relay plug setting at 20% the E/L relaysets only 40% of current in the faulty phase and the balance current flows through theother phase relays. At 70%P.U. setting, the current sharing is 79%.
BREAKERBREAKERBREAKERBREAKER MECHANISMMECHANISMMECHANISMMECHANISM FAULT:FAULT:FAULT:FAULT:
For a fault on Aliyar – Sholayar feeder.2 in 1980, all the 110 KV feedersemanating from Aliyar tripped at remote ends. The relay had operated in Aliyar-Sholayarfeeder.2 also and the breaker had also tripped.
The system was normalised without too much digging out.
On deeper investigation next day, the relay contacts of Sholayar feeder.2 at ALRend had burnt and damaged.
Why the contacts should burn?
Suspected the breaker and the timings were measured. Much increased. This wasdue to heavy friction in the mechanism.
In cricket, the match is not over till the last ball is bowled, Kapil says. Inprotection, the investigation is not over till the cause is traced out.
CONCLUSION:CONCLUSION:CONCLUSION:CONCLUSION:
It should be clearly understood that only maticulous, strict adherence to rigidtesting standards and indepth knowledge of tripping analysis go a long way in ensuringthe correct operation of protective gear and elimination of unwanted operation or minormishaps which often prove very costly. In spite of everything, only 80% of the faults arestill cleared correctly by the protection systems as per experts. This is why – protectionis an ART where perfection is impossible.
SOMESOMESOMESOMEEXPERIENCESEXPERIENCESEXPERIENCESEXPERIENCES ININININ THETHETHETHE FIELDFIELDFIELDFIELD WORKS:WORKS:WORKS:WORKS:
To start with, item 1 is reproduced from our old MSEB (Now TNEB) JournalJune 1960 – an article “ Operation and Maintenance Problems” written byEr. S. Mohammed Ali, then Divisional Electrical Engineer.
1) “ Know what you are doing”
In many of our potential transformers, the secondary yellow phase is connected toearth and the neutral left insulated. A section officer look out the P.T. for routineoverhaul. While reconnecting the wires, he did his job all right but finding the neutralwas without a connection, he attached an earth wire to it as is done on any distributiontransformer. In a few minutes after energising it, the P.T. was found burnt out. Thismistake can be attributed to (i) ignorance and (ii) not marking each terminal whiledisconnecting. It is a good practice that while disconnecting wires in any terminal board,each terminal is clearly tagged.
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It is equally good practice to record the order of parts dismantled when handlingany mechanical equipment. What is dismantled in a few seconds may take hours to refitif you have lost sight of the order of things.
2) Earthing of P.T. secondary at Moyar
Originally, the P.T. secondary Yellow phase was connected to earth and theneutral left insulated when Moyar was commissioned in 1952.
After all the distance relays and synchronising scheme were completely replacedand modified in the years 1992/93, the Yellow phase earth remained in Yellow phase. Asper the manufacturers of the new distance relays provided, the P.T. neutral needs earthed.This was corrected in 1997. The implications can be set aside but the overlooked isoverlooked.
3) P.T. failure at Maravakandy:
When the commissioning tests were done on 14-6-92 at Maravakandy MiniHydro Power House (1 x 750 KW) in Nilgiris, at the time of building the machinevoltage to its rated value of 3.3 KV one of the two PTs of V-connected machine PT gotburnt out.
A spare P.T. was erected on 26.2.92 and it also got burnt out when energised.
When the contractor brought replacement P.T. on 20-7-92, he informed that theyhave supplied 3.3 KV / √3 110 / √3 P.T. so far instead of 3.3 KV / 110 V PTs with thename plate of 3.3 KV / 110 V ratings.
Any site done with station L.T. supply will not reveal the defect.
4) Mixing of P.T. wiring with C.T. wiring:
When the P.T. secondary circuits were meggered on 25-3-1978 in the station L.T.supply circuit of one of the generators at Sholayar PH I (Commissioned in 1971), thecircuit was giving zero IR value. The reason was found to be the wiring mixing betweenP.T. and C.T. circuits. One C.T. was actually feeding the potential coil of an energymeter. The Polarity connections of the CTs were also opposite.
5) Mixing of A.C. supply with D.C. circuit at Sandynallah S.S.
When the routine meggering of D.C. circuits was done in 1971 at 110 KVSandinallah S.S. in Nilgiris it was found that there was wiring mixing between station LTsupply and station DC supply. If annual meggering was done effectively, this could havebeen identified early.
6) Loss of P.T. supply at Moyar PH
The layout of the 110KV buses at Moyar Power House existed in service in 1997is given in Figure 12.1.
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Normal operational procedures are:
- Keep 189 A – PT and 189 B – PT isolators closed energising the 110 KV feederBus PT and taking PT loads on this P.T.
- Keep transformer bus dead
- Keep the 189 A and 189 B isolators of the generators which are running and keepthem open in idle generators.
- When LC is needed in 110 KV feeder bus P.T. close any one of the isolator oftransformer bus of running generators and avail the relay loads on Transformerbus P.T. De-energise the feeder bus P.T. by opening both its isolators. Such L.Cswere being avai led monthly for maintenance works.
Let us assume that all the three machines are running. But P.T. is on L.C.Transformer bus P.T. is fed from machine 1.
Suppose, machine 1 trips on fault. Its OCB trips and machine 1 voltage goes tozero thereby the bus P.T. looses its supply. All the distance relays will trip on loss of PTsupply, causing black out at Moyar.
The same black out will happen if the operator shuts down machine 1 and opensthe 189 A and 189 B without knowing the implications.
It was told that there were many cases of all feeders tripping simultaneouslybefore at Moyar end only.
Another problem is the non-existence of a true bus coupler isolator. Anyinadvertent penning of one of the isolators in all the generators and PT, there is thepossibility of separation of the two buses. If Bus PT is Bus A in such an eventuality,faults on Singera feeder 2 and Gobi feeder 2 will not be sensed by the P.T. in serviceleading to possible non operation of protection.
By connecting both bus P.Ts to both buses and introducing a bus coupler 189AB – BC as shown in figure 12.2 solved all the above problems.
Even now 189 A isolators of the generators are useless since the 110 KV lightningarrestors of transformers are connected through 189 B isolators only.
Action is being taken to remove the copper tubular bus bars of transformer buscompletely.
In the authors opinion, the design of the bus arrangement is non-standard. With50% of the bus structure materials, a simpler bus with the same facility could have beendesigned and erected. Even now, a comprehensive operation with one bus is not possiblesince the feeders do not have bus selection facility. Selection arrangement can be madebut very laborious. This can be done if MUSHEP comes.
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7. Emergency operation with one P.T. of less V.A capacity:
When one of the 110 KV P.T. failed at Udumalpet in 1991/1992, a smaller V.A.capacity was temporarily used till the correct capacity P.T. was arranged. All themetering circuits were kept switched off to keep the P.T. load under capacity and the S.S.was operated with calculated risk.
8. Emergency operation with one transformer of less capacity at Aliyar Power House:
When one single phase transformer of 24 MVA capacity failed, a transformer of12 MVA was connected in the bank with other phase transformers of 24 MVA and theAliyar machine was operated for some days till the correct size transformer was arranged.The load and the generator was limited to the capacity of the small size transformer. Themachine had negative sequence relay and it was kept in service without any problem.
9. Need to test C.T. at rated current:
Due to the non-availability of suitable loading transformer one 800 A.C.T. wastested O.K. with 400 A and put in service but the ratio did not keep up when the loadwent beyond 400 A. This shows that, the CTs should be invariably tested for its ratedcurrent.
At Kadambarai, the generator ring CTs are rated 8000 A. Loading transformerwas available to inject only 1000 A. Hence, 8 turns of current injecting lead weretoroidally would through the C.T. and the tests were done for 8000 A. Such torodialwinding may not be possible in sub-station C.Ts but their maximum rating is 1200 A onlyand hence no problem exists.
10. Tripping of generator differential relays at sholayar PH-1
There were frequently maloperation of generator differential relays of bothmachines at Sholayar PH 1 for through faults on 110 KV feeders since commissioning in1971. Suspecting the metrosils connected across the CT secondaries they were removedon 12-11-79 and thereafter there was not even a single such wrong tripping.
11. Negative sequence relay operation at Kadamparai
Unbalance current (1000 A, 1000 A, 1800 A) was noticed in machine 4 on29.8.90. The observation was ignored assuming that the transducers would have beenfaulty. When the load picked upto 70 MW on 30.8.90, the machine tripped on negativesequence relay.
Many tests like measurement of D.C. resistance of generator circuit, measurementof generator impedance primary injection by injecting current just after 230 KV CTs inthe yard – in vain.
Primary injection was done after the 230 KV breaker in the yard. CT secondarycurrents were less than expected in R and Y phases.
Reached the location. Y Phase limb of the 230 KV ABCB was showing 500Ω inclosed condition.
Lesson: Don’t make assumptions.
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12. Tandem rod problem in 110 KV OMCB:
During routine maintenance works on a 110 KV OMCB (BHEL) at 230 KV/110KV S.S. at Udumalpet, the timing was incorrect in one of the limbs. The reason was theloosening of bolts in the tandem rod.
13. Problem with core balance CTs in Cables:
In one of the sub-stations where core balance CT was used for earth faultprotection in the outgoing cable of a distribution line, the earth fault relay did not operatefor a known earth fault in the cable.
It was found that the earthing of cable sheath was not made properly.
The earth fault current has gone through the C.T. and also returned through theC.T. getting cancelled each other in the C.T. Hence no out put from C.T.
Correct sheathing is shown in figure. Current first goes through the cable core,returns through sheath and again returns through the sheath. The sheath currents throughthe CT gets cancelled and the cable core current remains.
14. Protection tripping through ‘Local’ control of breaker:
In a section of a system with 8 No. grid feeder breakers commissioned under onecontract, a fault occurred in one of the lines.
The protection operated O.K. and isolated the fault. The Operator went to the yardfor inspection and tried to test charge the line through local control from the breakermechanism box. All the incoming breakers to that S.S. tripped at the remote ends. Thedistance relay in the above faulty line operated but the breaker did not trip.
On investigation, the protection scheme was so designed that the protectiontripping was not effective when the breaker control was on ‘LOCAL’.
We have already said that the protection tripping should be effective irrespectiveof the position of the local-remote control switch of the breaker.
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15. A Terrific Experience:
While test charging after a fault tripping the operator at 230 KV S.S. Udumalpetone day observed that there was no current in one phase of a 230 KV feeder going to thenearby S.S. at Myvadi. The protection did not operate will not operate if it was on openjumper.
LC was availed and a through inspection of the line was done by lines wing andeverything was O.K.
Test charged the feeder. The current was still missing.
Shut down the feeder. 400 Volts 3 phase voltage was injected from 230 KVUdumalpet S.S. and bulbs connected at Myvadi a end of the line were burning O.K. in allthe 3 phase.
The protection wing was again moving in the yard for further probing. Suddenly,one person shouted and alerted others to sit down. A vertical live 230 KV jumper fromthe bus going to the isolator got unclamped at the top end and was hanging down just atthe safe clearance over the head of the inspecting persons.
16. Operation during L.C.
This happened when Kundah PH I was a dead end. A double circuit 110 KV linewas there between Kundah PH-2 and Kundah PH-1. All the machines were shut down atKundah PH-1.
A shutdown was needed in line No. 1 shut down was issued and LC was availedin line 1 at both ends. Line work was taken up and LC returned and everythingnormalised.
But the SBA at Kundah PH I found that the 110 KV bus RVM was not recordingfor so many hours. On deeper investigation, it was found that the operator had trippedline 2 at Kundah PH-1 while issuing the L.C.
How much negligence?
Clear instructions over the step by step operations before issuing a line clear onequipment should be available in every SS/PH at the operators table.
Sub-log book should be essentially maintained. The author has heard a story ofattending repair works in the cooler of a healthy generator when the cooler was defectivein other unit.
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17. Primary injection and Bus bard stability problem:
The above figure shows the portion of a 33 KV GIS system. When the B/B CTwas tested for ratio by inserting the current cable through the available external holemarked as “ C”, the CT behaved accurately.
When it was tried to do the primary injection by injection current in between Aand B through conductor, the CT behaved erratically.
THE PROBLEM could not be solved for many months inspite of the visits ofexpert from the country where it was manufactured.
The foreign company finally brought a flux Camera which can take photo ofmagnetic flux. It was seen that there was flux linking between points D and E through F.This was found to be due to missing of an insulating washer provided in one of the fixingbolts of flange F. Actually, there should not have been electric conductivity between Gand H but the defect was the existence of continuity due to the missing washer as wasconcluded by the company engineers.
18. Real life is like that:
I. After the tripping of a generator, the hydraulic operator in a power house wasshouting to the electrical operator:
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“Hey – the machine has tripped – but the shaft is still rotating”
II. No rains – No problem:-
Load dispatch engineer asked to put one Generator on bars immediately.
Operator replied that the rotor is outside.
Load dispatcher advised that since there were no rains, the rotor could well beoutside and asked to put the machine first.
III. Deserving appreciation:
The rewinding works of an induction motor was going on. One big engineercommented to the electrician, “ what you are doing is wrong. There should be only 4 leadscoming out. How come there are six leads?”
Finally, after successful completion of the work, the big engineer recommendedhimself for appreciation and got it too.
IV. Yet to design:
This is in sixties. A proposal was sent through the hierarchical ladder to theCanadian Company who erected Kundah system to provide a transformer in a circuit tosolve a problem. The company replied:
“We are yet to design a D.C. transformer”.
V. More careful:
One engineer was more careful that he wanted to get approval from the foreigncompany who had supplied the 250 V.D.C. generator equipment as to whet her varnishingcould be done to improve its I.R. value.
VI. How is it?
Boss: Which fool gave you the degree?
Subordinate engineer: The same fool who gave it to you.
VII. Betting by the author:
Primary injection was going on in the Bus bar protection C.T. in a sub-station.One young engineer was doing the test. The author was witnessing. The testing guyfound it very difficult to drive current in the loading transformer when he tested oneparticular phase. He said to his assistant to check whet her any secondary of the C.T. wasopen.
The author intercepted and asked? “ How is it? You are sending current onlythrough the C.T. primary and a big bus bar jumper of about 5 meters. How can the C.T.open circuit can impede the current in the loading transformer?”
The testing guy was very sure. The author was very adamant. The author offeredto make a bet and the testing guy immediately accepted. Supplying Pepsi to all presentwas the bet.
The author had to supply Pepsi to all finally.
Experience always speaks.
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VIII. Protection Mind:
One engineer saw a chicken in his dream inside the Kadamparai PH. (How can achicken get into the under ground Power House?) He was telling about this dream to hisnearest people.
Within two or three days, there was the fire accident at Kadamparai. It was sug-gested by somebody in presence of the then Chairman to send down through a basket –pulley – rope system a chicken through the vertical tunnel upto the Power House locationto ensure that fire had extinguished completely. These are also protection thinking anddreaming.
IX. Getting shouted gives un-forgetting pleasure:
The top brass from Madras who is famous for shouting is in site to witness thescheduled commissioning of a big equipment. One small protection engineer could not beavailable for the commissioning. He gets the nod from his local boss to be awa y on theday of commissioning on an unavoidable family function. The news reached the shoutingboss. He shouts, “ what? What do you mean? nothing doing. No commissioning tomorrow.We will wait for you. Go and finish your job and join us.” This shouting is unforgettable.Only the protection engineer can get so much of importance – every one of you know.
X. Masters:
The author has innumerable number of masters in this world. Leaking rain waterwas dripping over a villager silting in a bus. He was not at all caring. He neither botherednor enjoyed. He was as calm as a baby in its mothers’ arms. He is also a master of theauthor. The author thinks of him whenever he faces such a situation now and then andasks himself how the villager in bus would have acted under this circumstance?
Like wise many masters. The author is blessed always with very good bossesanywhere in the world.
Most of the bosses like Er. K. Narayanasamy, Er. B. Ranganathan and Er. K.R.Syed Abdul Subhan are his masters in many ways. When the author makes an analysis oftripping or when he drafts a letter or when he faces a labour union, he asks himself, “HowEngineer …… will analyse this tripping?” The author gets some more depth. His mastershas “ assessed” the author as “GIVES IMMEDIATE SOLUTIONS IN THE FIELD” and“CAPABLE OF TACKLING ANY PROTECTION PROBLEM”
- Million dollars boosts indeed.
The author has started thinking confidently after getting these assessments that hecould give himself a solution to any problem in life also.
The 26 year old protection engineer of electrical equipment has understood nowthe way to protect himself from any hazards in life and his own I.R. value is > --------.
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UNDERUNDERUNDERUNDERGROUNDGROUNDGROUNDGROUNDCABLESCABLESCABLESCABLESEr. M. Arunachalam
EE / GRT
A.3.1. 11KV& 33KVPOWERCABLES.
A.3.2. 110KVOIL FILLEDPOWER CABLES.
A.3.3. 110KVXLPE POWERCABLES.
A.3.4. 230 KV XLPE POWERCABLES.
A.3.5. PILOT CABLES.
A.3.6. LV CABLES.
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A.3.2.A.3.2.A.3.2.A.3.2. 110110110110KVKVKVKV OILOILOILOIL FILLEDFILLEDFILLEDFILLED POWERPOWERPOWERPOWER CABLES.CABLES.CABLES.CABLES.
Test No. Test Description Standard Ref. Remarks1. Sheath Insulation &
continuity Test. IEC-52ISI-
IR value forsheath>100 megohms, And for cableconductor>500 megohms
2. Insulation test forcable core.
3. Phasing test4. H.V. test
Test No. Test Description Standard Ref. Remarks
1. Oil flow test IEC-141-1
ISI-
IR value moreThan 100 Meg ohms.
Test at 245KVDC for 15Minutes.
2. Impregnation Test
3. ConductorResistance test.
4. Capacitance test
5. Sheath insulation by5KVmegger.
6. Cross bonding test.
7. Tightness of links inJunction boxes
8. Test for SVL by2.5KVMegger.
9. High Voltage Test.
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A.3.4A.3.4A.3.4A.3.4 230230230230KVKVKVKV XLPEXLPEXLPEXLPE POWERPOWERPOWERPOWER CABLES.CABLES.CABLES.CABLES.
Test No. Test Description Standard Ref. Remarks
1. Insulation Test IEC-8402. Conductor
Resistance,capacitance &inductance test.
ISI-
3. Sheath insulationTest.
4. Cross bonding Test.5. Link box tightness
check6. SVL test by 2.5 KV
meggerTest at 185 KVDC for 15minutes.
7. H. V. Test
Test No. Test Description Standard Ref. Remarks
1. Insulation Test
2. ConductorResistance,capacitance &inductance test.
IEC – 840ISI-
3. Sheath insulationTest.
4. Cross bonding Test.
5. Link box tightnesscheck
Test at 385 KV DCfor 15 minutes.
6. SVL test by 2.5 KVmegger
7. H.V.Test
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A.3.6.A.3.6.A.3.6.A.3.6. LVLVLVLV CABLES.CABLES.CABLES.CABLES.
Note: Annual DL H.V. test on cables in generalings station should be dispensed with andthe DL H.V test should be conducted after ratification of fault conditions.
Test No. Test Description Standard Ref. Remarks
1. Insulation Test by5KVMegger
IR value>100 Megohm
2 Loop ResistanceTest.
3. Cross talk test &coupling Test.
4. Noise levelmeasurement
Test No. Test Description Standard Ref. Remarks
1. Phasing &continuity check.
IEC- 227-2IR value More than100 Meg Ohms.2. 2KVinsulation test.
3. Visual inspection,size & ratingsconfirmation.
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BATTERIESBATTERIESBATTERIESBATTERIESChecking of Value Regulated Lead-Acid Batteries in conjunction with thecommissioning of plant.
1.1.1.1. GENERALGENERALGENERALGENERAL
This is a general guideline for bringing Valve regulated lead acid (VRLA)batteries into serviceTest Record 1 WAT 910037-006 is to be used during testing.For commissioning of freely vented lead acid batteries, please see provision 1WAT 910034-007.
The installation, commissioning and maintenance instructions given by eachmanufacturer shall always be complied and should be read at the same timesas this guideline.
2.2.2.2. RFERENCERFERENCERFERENCERFERENCE DOCUMENTS.DOCUMENTS.DOCUMENTS.DOCUMENTS.
- Installation drawings and instructions from the manufacture providedtogether with the battery, regarding storage, erection, initial charging etc.
- Commissioning instruction for rectifies 1 WAT 910034-005- Manufacturers manual for rectifier.
3.3.3.3. TESTTESTTESTTEST EQUIPMENTEQUIPMENTEQUIPMENTEQUIPMENT
Multimeter class 1.5Test leadsVoltmeter for DC class 0.2 (Digital multimeter)ThermometerRubber gloves, goggles, eyecup, cold water and saline solution in squeezebottle for eye wash.
4.4.4.4. SAFETYSAFETYSAFETYSAFETY PRECAUTIONSPRECAUTIONSPRECAUTIONSPRECAUTIONS
4.14.14.14.1 HydrogenHydrogenHydrogenHydrogengas.gas.gas.gas.
When lead acid batteries are being charged, oxihydrogen gas is liberated. Tominimise the risk of explosion, the following precautions must be taken:
- Ensure that the space around the battery is adequately ventilated. Ensureventilation according to local standards. Use Swedish standard SS 408 0110 if no local standard is available.
- Smoking is to be prohibited
- Prior to touching the call caps, remove any static electricity by placingthe hand on the edge or the side of the respective battery cases.
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4.24.24.24.2 ChemicalChemicalChemicalChemical stuff.stuff.stuff.stuff.
The valves of the battery must not be blocked or opened. Filling of cells isnot possible, since the electrolyte is immobilized and the battery alreadyfilled when delivered.Severe damages on the battery container might cause acid to leak. Thereforethe same safety precautions as the vented batteries are necessary:
- Use protective goggles.- Washing facilities are to be available close to the battery.
- Electrolyte on the skin, must be washed with plenty of soap and water.- If electrolyte gets into the eyes wash with plenty of clean water and get
immediate medical attention.Lead compounds are poisonous. Always wash your hands after working withthe battery.
4.34.34.34.3 ElectricalElectricalElectricalElectrical currentcurrentcurrentcurrent
Valve regulated batteries are always electrically alive and the risk of shortcircuit (and electrical sparks, see 4.1) must be prevented.
- Use insulated tools only to make connections to the battery, taking carenot to over tighten beyond manufacturer’s recommended torque value.
- Check the circuit and make sure it is safe before making a connection tothe battery.
- Before working on the battery, always remove personal metal effects,such as rings, watches, bracelets, necklaces etc.
4.44.44.44.4 Temperature.Temperature.Temperature.Temperature.
For lead acid batteries in general and especially for valve regulated batteriesit is of utmost important to keep the temperature at a steady level of 20 C°(See fig. 1).
5.5.5.5. PREREQUISITES.PREREQUISITES.PREREQUISITES.PREREQUISITES.
Chargers which are connected to the battery shall already been commissionedpreviously.
6.6.6.6. VALVEVALVEVALVEVALVE REGULATEDREGULATEDREGULATEDREGULATED BATTERIES.GENERALBATTERIES.GENERALBATTERIES.GENERALBATTERIES.GENERAL INFORMATIONINFORMATIONINFORMATIONINFORMATION
6.16.16.16.1 DescriptionDescriptionDescriptionDescription ofofofof basicbasicbasicbasic technologytechnologytechnologytechnology
Over the past years VRLA batteries have been introduced as an alternative tothe conventional lead acid and nickel cadmium batteries. This new type isadvertised as “sealed” or “maintenance free”. The correct designation is“ valve regulated” according to IEC 896-2 (draft).
In a VRLA cell the net water consumption is strongly reduced by means of arecombination of the oxygen at the negative electrode and by preventing thehydrogen from being generated.
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However, the oxygen recombination does not work at 100% efficiency.Some oxygen escapes from the electrochemical system. Furthermore,evolution of hydrogen cannot be fully suppressed. This means that water losswill take place already during normal conditions and particularly duringcharging with high currents and high temperatures. These water losses arenot possible to replace.
The valve, which must open at high pressure, is a very important detail. Ifthe valve sticks open (or is removed for any reason), this will lead to oxygeningress with resultant discharge of the cells and ultimately total dry out. If itsticks, internal pressure build-up will create a severe bulge of the cellcontainer leading to eventual fracture. In the extreme case it may rise to anexplosion.
NOTE:NOTE:NOTE:NOTE:
Valve regulated batteries are not sealed.
6.26.26.26.2 TwoTwoTwoTwo VRLAVRLAVRLAVRLA designsdesignsdesignsdesigns
The VRLA batteries are divided into two main groups depending on the waythe gas recombination is achieved:
- Absorbed (starved) electrolyte- Gelled electrolyte
Absorbed electrolyte cells are built up of pasted plates with microporousglass fibre as separators.
The electrolyte is absorbed by the pores of the electrode active materials andthe separator. The separator is not saturated with acid and the acid free poresare used for transferring the oxygen from the positive to the negativeelectrode.
The gel electrolyte is immobilised by the addition of silicon dioxide to thesulfuric acid. The oxygen is transported through micro cracks in the gel.The plates can be designed as for FVLA with pasted or tubular plates. Theseparators are normally made of microporous plastic.
6.36.36.36.3 FloatFloatFloatFloat chargechargechargecharge
Due to the limited acid volume and consequently the need for high aciddensity in the absorbed cells (1.29-1.30 kg/I), the float charge voltage will besomewhat higher than for other lead acid batteries. For this reason theabsorbed VRLA cells must be charged with a higher float charge level of2.27 V/cell with given tolerances.
The gelled type has the same density as the FVLA type i.e. 1.24-1.26 kg/Iand accordingly has the same float charge level of 2.23-2.25 V/cell.
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This discrepancy must of course be considered when calculating the numberof cells so that the upper limit is not exceeded.
Absorbed GelledDensity 1.29-1.30 kg/I 1.24 kg/IFloat charge 2.27 V/c 2.23 V/c
The manufacturer must give detailed information of recommended floatcharge voltage.
6.46.46.46.4 HighHighHighHighraterateraterate chargechargechargecharge (boost(boost(boost(boostcharge,charge,charge,charge, equalizingequalizingequalizingequalizing charge)charge)charge)charge)
In order to avoid gas development and risk of dry-out, all manufacturersadvise limitations for voltage, current and time when recharging VRLA cells.It is therefore of importance to follow the instructions from the manufacturer.
6.56.56.56.5 AmbientAmbientAmbientAmbient temperaturetemperaturetemperaturetemperature
The higher ambient temperature, the higher float current at a given voltagelevel.
High float current causes high internal temperature and escape of gas, whichwill dramatically decrease the lifetime of the battery.
This is valid for all lead acid batteries. See fig 1.
100 %
Fig 1.50 %
0 10 20 30 40
Due to the exothermal oxygen recombination reactions, VRLA batteriesdevelop much more heat inside the cell than the conventional cells.Furthermore, as there is no free acid, the heat dissipation is not supported byconvection.
Under extreme conditions, the battery can be subject to successive increaseof float current and temperature until it is destroyed. This phenomenon iscalled “thermal runaway”.
Life Time
Temperature
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A temperature compensated charger can be installed in the DC system.This charger can decrease the float charge level at high temperatures andtherefore marginally improve the situation but not restore the lifetime due tohigh temperatures. See typical values fig 2.
Fig 2.
0 5 10 15 20 25 30 35 40
In general, the gelled batteries have a larger electrolyte volume than theabsorbed type and are more resistant to a drying out. This is a generalguideline and differences between different makes may change this picture.
6.66.66.66.6 RippleRippleRippleRipple
There is no difference between valve regulated batteries and conventionallead acid batteries regarding the acceptance of ripple current. The ripplecurrent must be limited to a value recommended by the manufacturer(Normally 5A/100Ah). Otherwise the corrosion on the positive grid and theinternal temperature will increase.
6.76.76.76.7 DischargeDischargeDischargeDischargeperformanceperformanceperformanceperformance
The absorbed type has a very good high rated discharge current performance.Therefore this technology is highly suitable for UPS systems, diesel enginestarting and DC systems where large current peaks are required after a longdischarge period.
For the gel type, the peak loads might increase the nominal battery capacityand consequently the cost. Gel-technology is worth its price for applicationswith low discharge current without extreme peak loads at the end of thedischarge period.
240
235
230
225
220
215
Plant voltage Per Coil (V)
Temperature C’
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6.86.86.86.8 ClassificationClassificationClassificationClassificationandandandand LifetimeLifetimeLifetimeLifetime
EUROBAT has classified the VRLA batteries into 4 groups with particularreference to – Performance- Safety- Design Life*10 + year – High integrity
Telecommunications, nuclear and conventional power plants, oil andpetrochemical industry and other applications where the highest security isrequired.
*10 year – High performance
In general terms, this group of batteries have comparable design lifeperformance as in the 10 + year – High integrity group. However,requirements for performance and safety are not as severe. The requirementfor capacity is 95% at first cycle and 100 % at 10:th cycle.
*5-8 year – General purpose.
Safety requirements and design life related tests are not as stringent.
*3-5 year – Standard commercial.
This group of batteries are at the consumers end and are popular in smallemergency equipment.
There are some gelled batteries on the market today which cannot reach100% after first cycle and shall be classed in the 10 year – Higherperformance group.
The difference in lifetime expectancy between the two VRLA types at 20degrees C is;* Absorbed technology – appr. 10 years for the 10+ and 10 year groups.* Gel technology – appr. 12-15 years
7. RECEIVING,RECEIVING,RECEIVING,RECEIVING, UNPACKINGUNPACKINGUNPACKINGUNPACKING ANDANDANDAND STORAGE.STORAGE.STORAGE.STORAGE.
Inspect the battery upon arrival and check that the goods delivered arecomplete and that all cells/blocks are undamaged.
Under no circumstances shall the cell/blocks be lifted by their terminal pillars.
There is no need to remove the terminal covers before the erection of thebattery set.
If the battery cannot be installed immediately, store all parts in a clean anddry room.
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It is advisable to check the voltage for each cell/block after the unpacking.This can be done without removing the terminal cover (for most of themakes). The recommended lowest voltage is given by the manufacturer.(appr. 2-10 V/cell)
In order to ensure that the batteries can be charged easily after a long periodof storage, it is recommended that the batteries should not be stored morethan the following periods without recharging (typical values);
6 months at 20 °C4 months at 30 °C2 months at 40 °C
For this reason it is very important that the design office is informed aboutany delays at an early stage so that the delivery of the batteries can becoordinated with the start of commissioning.
8.8.8.8. INSTALLATIONINSTALLATIONINSTALLATIONINSTALLATION
The installation section of the battery manual and the installation drawing forthe special project must be complied completely.
Care for space between cells/blocks and for good ventilation in the roomwhere the battery is accommodated.
9999 .... COMMISSIONINGCOMMISSIONINGCOMMISSIONINGCOMMISSIONING CHARGECHARGECHARGECHARGE
NOTE! It is very important to follow the instruction from each manufacturerregarding;
- applied float voltage and high rate voltage (if recommended).- current limit- time period for charging- temperature when charging
Some manufactures make a distinction between initial charge forimmediately load connection and initial charge for site acceptance test.
Generally, the absorbed typed are more sensitive to high voltages and largecurrent. For this reason batteries require most time to be initially charged,especially when the battery is subject for site acceptance test (up to 6dayscharging for some manufactures).
The voltage applied to the battery set is calculated according to: nextrecommended charging voltage (n = number of cells)
If a temperature compensated charger is installed, the float charge voltageshall be adjusted according to recommendation from the manufacture oraccording to fig 2. In this case the alarm level for under/over float chargevoltage is set to 2-3% of the set float value.
377
CHAPTER–XX
The charging current (1 charging) is expressed as % of Ah capacity 0.1 xC10 means that the current shall be limited to a value of 10 % of the nominal10 h capacity.
For a 100 Ah nominal capacity it is 10 A. Before initial charge it might benecessary to derate the current limit of the charger (1 set) so that the currentis limited to the recommended value; I set = I charging
When the station load is connected it is advisable to set the current limit inaccordance with actual configuration in the power station (substation) and therecommended value given from the design office; I set = I charging + I load
10101010 .... SITESITESITESITE ACCEPTANCEACCEPTANCEACCEPTANCEACCEPTANCE TESTTESTTESTTEST (CAPACITY(CAPACITY(CAPACITY(CAPACITY TEST)TEST)TEST)TEST)
The site acceptance test must be carried out in the period between completionof the commissioning charge and the introduction of an operating load on thesystem.
The capacity test is normally performed during 5 hours, 10 hours or thebattery duty period. The following instruction will apply to the 5 and 10hours discharge.
- Read the ambient temperature.
- The charger shall be connected to the battery until the start of thedischarge. It is recommended to check the voltage for each cell/bloc aftercompletion of the initial charge but before disconnection the charger andstart of the testing.
- If nothing else is specified the discharge current is given in themanufactures catalogue at an end voltage of 1.80 volt/cell for 5 hour or 10hours discharge.
- The battery load until shall be connected to suitable terminals where thestation loads and rectifier are disconnected and where the battery load unitconnections are protected by fuses/circuit breakers. See fig 3
378
- If possible, makes a rough current setting on the battery load unit before isconnection to the battery.
- Connect the battery load unit and make a final adjustment of the current. Itis very important to that the discharge current is supervised and kept at anaccurate level of +/-1 % throughout the test
- Make a note in the test sheet at what time the test is started and at whattime the test is finished.
- The battery voltage is to be measured 6 times during the discharge period.
- Battery terminal voltage is to be measured the first 3 times and individualcell voltage is to be measured the last 3 times (at 80-90-100% discharge).
If the battery terminal voltage is measured at the load bank, the voltage dropin the cables between battery and load bank has to be considered
- Voltage drop between the battery terminals and the cell connections shallbe checked during an early stage of the discharge. All cells are checkedand the voltage must not exceed 5 mV. Connections where the voltagedrop is larger must be investigated and carefully adjusted.
Successively as the test is performed, enter the test results in Test Record 1WAT 910037 – 006.
379
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The acceptance test must be supervised to prevent deep discharges and therecharging must be commenced immediately after the discharge with avoltage, current and time equal to the method for putting the batteries intoservice without test.
1.1.1.1. ACCEPTANCEACCEPTANCEACCEPTANCEACCEPTANCE CRITERIACRITERIACRITERIACRITERIA FORFORFORFORCOMMISSIONINGCOMMISSIONINGCOMMISSIONINGCOMMISSIONING TESTTESTTESTTEST
Two criteria must be regarded for acceptance of the site test.-cell/bloc voltage deviation-capacity
The cell/bloc voltage deviation has a very wide range for new VR batteries. Itis recommended to check the voltage for each cell/bloc after completion of theinitial charge but before disconnecting the charger and start of the testing. Inthis stage the deviation can reach a level of +0,2/-0,1 V/cell for gelled cellsbut less for absorbed type.
At the end of a site test the cell/bloc voltage deviation shall not vary morethan +/-0.06 V from mean value and the battery voltage shall not be bellowthe predestinated end voltage (normally the number of cells multiplies with1.80 V/cell).
The capacity test shall be interrupted when the battery voltage has reached theend voltage.If the happens for instance at the 4,5 hour reading for a 5 hour test, it indicatesthat the capacity is only 90 % (4,5/5).
For adsorbed type in*10+ year – High integrity group not less than 100 %capacity is accepted.
For gelled type which is in the 10 year – High performance group 95 %capacity at first cycle is accepted.
Temperature correction for other temperatures than 20° C must be done asfollows:
K(t°) = capacity at temperature t° = time for discharge x discharge current.
K(20°) = capacity at 20° = K(t°) / f
f = correction factor given by the manufacture. If nothing is specified thisfactor can be calculated as; 1+0,006 x (t-20)
380
CHAPTER–XX
ABB Substations Inspection and test record Record form No:1 WAT 910037-006
Descript ion:Batteries valv requlated lead acid
Order No.: Sheet1
With capacity test Drawing No.: Cont2
Customer.: Customer ref.:Erection site.: Ref.:
A. neral Data and Information
Battery type…………………………… .Manufacturer:………………………… .Nominal Voltage:………………………Nubmer of cells:……………………… .Temperature compensated charger ___
B. Initia l charging:
Charging coltage:……………………… VCharging current. (current limit of the charger):…………………… . A
Charging time:………………………… .h
C. Cell voltage after initia l charging:
Float voltage:………… .V Time between initia l charging and capacity test….hAmbient temperature:…………………. °C
Cell. Volt Cell Volt Cell. Volt Cell. Volt Cell. Volt Cell. VoltNo. age No. age No. age No. age No. age No. age1 21 41 61 81 1012 22 42 62 82 1023 23 43 63 83 1034 24 44 64 84 1045 25 45 65 85 1056 26 46 66 86 1067 27 47 67 87 1078 28 48 68 88 1089 29 49 69 89 10910 30 50 70 90 11011 31 51 71 91 11112 32 52 72 92 11213 33 53 73 93 11314 34 54 74 94 11415 35 55 75 95 11516 36 56 76 96 11617 37 57 77 97 11718 38 58 78 98 11819 39 59 79 99 11920 40 60 80 100 120
Test carried outDate. Sign.:
Customers approva lDate. Sign.:
381
ABB Substations Inspection and test record Record form No:1 WAT 910037-006
DescriptionBatteries vlav regulated lead acid
Order No.: Sheet.:2
With capacity test Drawing No.: Cont.:3
Customer.: Customer ’s ref.:
Erection sale.: Ref.:
D. Capacity test.5 hours test:___ 10 hours test:___ ..........hours test:____End voltage/cell 1.80 V/cell_____ Other end voltage/cell.......V/cell
Time between initial charging and capacity test.......h
Ambient temperature............................... °C
Discharge current according to datasheet.........................A
Calculated capacity (discharge current x time)........................Ah
The discharge was started at...............stopped at..................
Individua l cell voltage
5 hours test 10 hours test …….hoursTime V Time Time hours(h) (h) V (h) V0 0
1.00 1.002.30 5.00
4.00 (80%) Sh.4 8.00 (80%) Sh.4 (80%) Sh.44.30(90%) Sh.5 9.00 (90%) Sh.5 (90%) Sh.5
Compl. Compl. Compl.test (100%) Sh.6 test (100%) Sh.6 test (100%) Sh.6
NOTE:NOTE:NOTE:NOTE:Individual cell voltages are noted on sheet 4-6. One sheet for each voltmeter reading at80-90-100% dischargeAt 0 hours the load bank is not yet connected and the voltage indicates the open circuitvoltage of each cell.
The capacity test is to be completed when the battery voltage has reached the endvoltage.
Contact resistance between terminals and cell connectors checked (after 1 hour):______Test carried out
Date. Sign.:
Customers approval
Date. Sign.:
CHAPTER–XX
382
ABB Substations Inspection and test record Record form No:1 WAT 910037-006
DescriptionBatteries vlav regulated lead acid
Order No.: Sheet.:3
With capacity test Drawing No.: Cont.:4
Customer.: Customer ’s ref.:
Erection sale.: Ref.:
E. Evaluation of results after completed test.
1.Cellvoltage deviation after initial charge with the rectifier still connected at floatcharge mode (section C. page 1)
Mean value...........V/cellMax. value............V/cellMin. value.............V/cell
2. Cellvoltage deviation after completed test (section D, page 2)
Mean value...........V/cellMax. value............V/cellMin. value.............V/cell
3. Extracted capacity.
Extracted capacity after compleated test = discharge current x discharge time:................................................................................................Ah.Calculated capacity according to section A:...............Ah.Correction with other temperatures than 20°C; Capacity (20°C) = Capacity
(t°C)/correction factor:................................................................................................Ah.
F. Recharging after completed test
Charging voltage...................VCharging current....................ACharging time.....................…h
References to used instruments:
Type:__________________________Identit y:_________________________________Type:__________________________Identit y:_________________________________Type:__________________________Identit y:_________________________________Type:__________________________Identit y:_________________________________
Test carried out Customers approval
Date, Sign.: Date, Sign.:
CHAPTER–XX
383
ABB Substations Inspection and test record Record form No:1 WAT 910037-006
Cell voltage after 80% discharge
DescriptionBatteries vlav regulated lead acid
Order No.: Sheet.:4
With capacity testDrawing No.: Cont.:
5Customer.: Customer ’s ref.:
Erection sale.: Ref.:
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
1 21 41 61 81 1012 22 42 62 82 1023 23 43 63 83 1034 24 44 64 84 1045 25 45 65 85 1056 26 46 66 86 1067 27 47 67 87 1078 28 48 68 88 1089 29 49 69 89 10910 30 50 70 90 11011 31 51 71 91 11112 32 52 72 92 11213 33 53 73 93 11314 34 54 74 94 11415 35 55 75 95 11516 36 56 76 96 11617 37 57 77 97 11718 38 58 78 98 11819 39 59 79 99 11920 40 60 80 100 120
Test carried out Customers approvalDate, Sign.: Date, Sign.:
CHAPTER–XX
384
ABB Substations Inspection and test record Record form No:1 WAT 910037-006
Cell voltage after 90% discharge
DescriptionBatteries vlav regulated lead acid
Order No.: Sheet.:5
With capacity test Drawing No.: Cont.:6
Customer.: Customer ’s ref.:
Erection sale.:Ref.:
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
1 21 41 61 81 1012 22 42 62 82 1023 23 43 63 83 1034 24 44 64 84 1045 25 45 65 85 1056 26 46 66 86 1067 27 47 67 87 1078 28 48 68 88 1089 29 49 69 89 10910 30 50 70 90 11011 31 51 71 91 11112 32 52 72 92 11213 33 53 73 93 11314 34 54 74 94 11415 35 55 75 95 11516 36 56 76 96 11617 37 57 77 97 11718 38 58 78 98 11819 39 59 79 99 11920 40 60 80 100 120
Test carried out Customers approval
Date, Sign.: Date, Sign.:
CHAPTER–XX
385
ABB Substations Inspection and test record Record form No:1 WAT 910037-006
CellCellCellCell voltagevoltagevoltagevoltage afterafterafterafter 100%100%100%100% dischargedischargedischargedischarge
DescriptionBatteries vlav regulated lead acid
Order No.: Sheet.:5
With capacity test Drawing No.: Cont.:6
Customer.: Customer ’s ref.:
Erection sale.: Ref.:
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
CellNo.
Voltage
1 21 41 61 81 1012 22 42 62 82 1023 23 43 63 83 1034 24 44 64 84 1045 25 45 65 85 1056 26 46 66 86 1067 27 47 67 87 1078 28 48 68 88 1089 29 49 69 89 109
10 30 50 70 90 11011 31 51 71 91 11112 32 52 72 92 11213 33 53 73 93 11314 34 54 74 94 11415 35 55 75 95 11516 36 56 76 96 11617 37 57 77 97 11718 38 58 78 98 11819 39 59 79 99 11920 40 60 80 100 120
Test carried out Customers approval
Date, Sign.: Date, Sign.:
CHAPTER–XX
386
ContributorsContributorsContributorsContributors ofofofof thisthisthisthis ManualManualManualManual
1.1.1.1. Er.Er.Er.Er. A.S.A.S.A.S.A.S. KandasamyKandasamyKandasamyKandasamyM.E.,MI.EEE(USA)M.E.,MI.EEE(USA)M.E.,MI.EEE(USA)M.E.,MI.EEE(USA) CE/TransmissionCE/TransmissionCE/TransmissionCE/Transmission
Contributed a lot of papers on Distribution protection and Metering system.
2.2.2.2. Er.Er.Er.Er. K.K.K.K. Mounagurusamy.Mounagurusamy.Mounagurusamy.Mounagurusamy. B.E.,B.E.,B.E.,B.E.,
Chief Engineer/Protection & communication. The experiences in the generation andtransmission network with contributions to the development of the system.
3333.... Er.Er.Er.Er. M.M.M.M. Varadharajan,Varadharajan,Varadharajan,Varadharajan, B.E,B.E,B.E,B.E,
Executive Engineer/O&M /Orathanadu
Experiences in generating station protections and distribution protection contributed tothe value information.
4.4.4.4. Er.Er.Er.Er. P.P.P.P. Ponnambalam,Ponnambalam,Ponnambalam,Ponnambalam, B.Sc.,B.Sc.,B.Sc.,B.Sc., B.E.,B.E.,B.E.,B.E.,
Executive Engineer/Sub-Station Erection / Chennai
The experience in the field of erection and testing of equipment contributed to the manual .5.5.5.5. Er.Er.Er.Er. M.M.M.M. Arunachalam,Arunachalam,Arunachalam,Arunachalam, M.E.,M.E.,M.E.,M.E.,
Executive Engineer/Grid relay Test/Chennai
The experiences on transmission protection are shared much on this manual.
The contributions are worthy in nature and confined to the transmissions.
387
“There occurs a fault;
Then the current should halt;
Otherwise the fault current would increase;
And the service continuity decrease.
But the relay acts quick;
And the circuit breaker trips;
The faulty part is disconnected;
And the power system is protected.
Thank you Mr Switchgear;
Because of you there is a little fear”.
- By somebody
290
APPENDIXAPPENDIXAPPENDIXAPPENDIX 1111TABLETABLETABLETABLE 1111
TESTTESTTESTTEST SPECIFICATIONSPECIFICATIONSPECIFICATIONSPECIFICATION REFERENCESREFERENCESREFERENCESREFERENCES ANDANDANDAND TESTTESTTESTTEST REQUIREMENTSREQUIREMENTSREQUIREMENTSREQUIREMENTS
Ref. Country Organization Voltage Uo/U Specification in use Test requirements(kv/kv) for new cables
d.c. timevoltage (min.)
1 ITALY Cable 36/60 - IEC 502 exrapolation 4Uo 15Maker - CIGRE recommondations
2 Cable 63/110 to CIGRE recommondations on customerMaker 86/150 agreement 4UO1 15
3 Cable 76/132 IEC 502 extrapolation on customer 3Uo 15Maker agreement 4Uo 15
4 GERMANY BEWAG 63/110 BEWAG specif ication 1984 3.1Uo 155 THE 30/50 KEMA specif ication S 10 for 50, 3Uo 15
NETHERLANDS KEMA 64/110,9 2/150 110 and 150 KV cables, KEMA S107th April 1984.
6 SWITZERLAND Cable 35/60 to - IEC 502 4Uo 15Maker 127/220 - SWISS SEV 3437
7 SWEDEN Cable 17.3/30 SWEDISH SS 424 1417 4Uo2 15Maker to - 1979 1.73Uo/50Hz
127/220 5or
Uo/50Hz 24hours
8 EIRE ESB 63/110 ESB Specification 4Uo 15949T May 1979
9 FRANCE EDF 36/63 Under consideration52/90 “ - -130/225 “
10 UK ESI 38/66 to ESI standard 09-16 4Uo 1576/132 Issue 1 August 1983
11 AUSTRALIA ETSA 38/66 SWEDISH SS 242 14 17 4Uo 15- 1979
12 SECV 38/66 Australian Electricity 3,46Uo 15Supply UtilitySpecifications
13 ACTEA 76/132 ESI Standard 09-16 4Uo 15Issue 1 August 1983
14 PCC 38/66 Australian Electricity 3,94Uo 15Supply Utility Specificiations 3,33Uo 15
15 USA NEMA16 JAPAN JIEE 38/66 National Technical 4Uo 10
to Standard for Electric89/154 Installations 2.6Uo 10
17 INTERNATIONAL l EC up to 98/170 draft IEC Specification 3Uo 15
1 - Sometimes limited to 3Uo if SF6 insulation involved.2 – Used on special customer requirement for 132KV XLPEcable.
291
APPENDIXAPPENDIXAPPENDIXAPPENDIX 2222TABLETABLETABLETABLE 2222
RESULTS OF SITETESTS
Ref Country Organ. In it ial Accessories In it ial Site Test ServiceSite Test Resu lts failures
Description(kV) (Min)
(kV) Termin. Joint Type
1 ITALY Cable 4Uo 15 36/60 Slip-on Slip-on EPR Newinstallation –Maker EPR Taped EPR, on- nobreakdown
VulcanizedTaped ERP
Vulcanized2 Cable 4Uo 15 63/110 Slip-on Taped EPR, Three new installa- One early
Maker EPR Slip-on Vulcanized t ions(2 installa- breakdownEPR tions63/110 kV) - (63/110 kv
No breakdown cable).3 Cable 3Uo 15 63/110 Slip-on Taped XLPE Newinstalltion -3 joint fai-
Maker EPR vulcan ized -1 joint failure lures with in(voids on cable 3 days (Largeinsulat ionpencil- voids onling) insulat ion
pencilling)4Uo 15 76/132 Slip-on Taped XLPE Newinstallation - 9 joint fail-
vulcan ized - 18 joint failures lures with in(11 joints had ob- 4 days (voidsv ious defects; 7 pencilling orjointswere appa- similar).rently soundbutlailed v ia thetopof the pencilling).-2 cable failures(cable damage)
Uo 24 hr 76/132 Slip-on Taped XLPE Newinstallation - 3 joint fai-(a.c.) EPR vulcan ized - 9 joint failures lures with in
(defects in joints) 1 month(defect injoints).
4 GERMANY BEWAG 3.1 Uo 15 63/110 Slip-on Taped EPDM un- No failures inSilicon vulcan ized d.c. test ingRubbed
5 The PGEM 4Uo 15 30/50 No. failures inNETHERL. 64/110 d.c. test ing
92/1506 SWITZERL. Cable 4Uo 15 35/60 Slip-on Taped EPR No failures in
Maker to Silicon Silicon Vulcanized d.c. test ing127/ Rubber Rubber
220Cable 4Uo 15 86/150 d° d°Maker (220
appr.)7 SWEDEN Cable 3.84Uo 17.3/ Slip-on Taped EPDM un- 1000 km of80-240kV
30 vulcan ized Cable tested to16 ss 424 unlog
a.c. or d.c. test.
127/ Slip-on Taped XLPE kV cable.vulcan ized reportedon
initial site testat (a.c.)/ 24 hr.
4Uo 15 76/132 Taped XLPE Special orderofvulcan ized 132 Kv cable with
lead sheath.B-12joint failed 4Uo/15min test (no ob-v ious reason for
(100) (600) failure).
292
APPENDIXAPPENDIXAPPENDIXAPPENDIX 2222 (Continued)(Continued)(Continued)(Continued)TABLETABLETABLETABLE 2222
RESULTS OF SITETESTS
Ref Country Organ. In it ial Accessories In it ial Site Test ServiceSite Test Resu lts failures
Description(kV) (Min)
(kV) Termin. Joint Type
8 EIRE ESB 4Uo 15 64/110 Slip-on Taped EPR All 4Uo/15 min d.r.vulcan ized test satisfactory
9 FRANCE EDF 3Uo 30 36/63 Slip-on Taped LDPE on No site Lest donebefore HDPE Underconsiderat ion19772Uo 15 52/90 Slip-on Taped Un- “(a.c.) vulcan ized
130/225
10 UK Cable 4Uo 15 38/66 Slip-on Taped Un- No failure in d.c.vulcan ized test ing.
Marker 76/432 (93) Taped Vulcanized (Note4Uo/15 min(3) test also carried
outas part ofTypeApprovalTest onCable loopwithjoints).
3.5Uo 15 38/66 Slip-on Taped Un- No failures invulcan ized d.c. test ing.
76/132 (24) Taped Vulcanized(24)
4.5Uo 15 38/66 Slip-on Taped Un- No failure in(6) (4) vulcan ized d.c. test ing
4Uo 15 38/66 Slip-on Taped Un- No failures invulcan ized d.c. test ing.
76/132 CSP
11 AUSTRALIA ESTA 3.67Uo 15 38/66 Slip-on No No failures injoints d.c. test ing
12 SECV 3.46Uo 15 38/66 No No failures injoints d.c. test ing
14 PCC 3.94Uo 15 38/66 No failures ind.c. test ing
3.3Uo 15 76/132
15 JAPAN JIEE 4Uo 10 38/66 EPR Taped EPR 6 accessory failu-vulcan ized res in 3700 km cir-
u it (moisture ininterface betweenpremoulded st ressconeand cable in 2accessories, pre-moulded st ress coneposit ioned incor-rectly in 1 acces-sory)
2.6Uo 10 89/154 EPR Moulded XLPE No failures in3 km circu it.
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80